With Gas So Cheap and Well Drilling Down, Why Is Gas Production So High?
Posted by Euan Mearns on January 26, 2012 - 9:20am
This is a guest post by David Hughes, a geoscientist, president of a consultancy dedicated to research on energy and sustainability issues, and a fellow of Post Carbon Institute, on whose website this article first appeared.
Natural gas prices have declined to below $3.00/mcf, levels not seen for years, yet the EIA posted the highest gas production ever in October, 2011. U.S. gas production is growing despite annual well completion rates that are half that at the peak of the drilling boom in 2008, when gas price topped $12.00/mcf. Proponents of shale gas as a “game changer” suggest that, despite the well-known high decline rates of shale gas wells, their productivity is sufficient to grow production with far fewer wells at historically low prices. Others, such as Arthur Berman, claim that shale gas plays require much higher prices to be economic. The answer may lie in the gas produced in association with oil drilling, which is near all time historical highs.
Figure 1 illustrates the annual number of gas wells and gas production documented by the EIA. Although drilling is still well above 1990’s levels, it is only half that of the all time record drilling levels reached in 2008.
Natural Gas Production versus Annual Drilling Rates, 1990-2011
U.S. natural gas production has reached production levels of 4.6 percent above the previous 1973 peak, and nearly 16% above the recent 2001 peak. While some of this increase is likely due to delayed tie-ins from the 2008 drilling boom, and some due to the high initial productivities of shale gas wells, these are not likely the whole story.
Hydraulic fracturing has certainly changed the game with respect to gas production from shales and tight rocks, albeit with widely reported collateral damage including methane leakage into groundwater, pollution from produced frackwater disposal on the surface, induced earthquakes from frackwater injection into disposal wells and the environmental footprint of industrialized landscapes. Equally important is the game changing nature of applying hydraulic fracturing to producing oil from shales.
Figure 2 illustrates annualized crude oil production versus well drilling rates. Drilling rates are near all time highs, more than double the rates of the 1990’s, and have succeeded in increasing production to levels not seen since late 2003 (yet down 42% from 1971). Production has grown by 0.65 million barrels per day above the all time low in U.S. oil production in May, 2008, causing some pundits to declare a new era of “American energy independence”.
Crude Oil Production versus Annual Drilling Rates, 1990-2011
Large amounts of natural gas are produced in conjunction with the production of hydraulically fractured shale oil and in association with conventional oil drilling. Given the price differential between oil and gas at present many companies have changed their focus to shale oil or liquids rich shale gas to enhance economic returns. Although much associated gas in the production of shale oil is simply flared, as in the Bakken play in North Dakota, much is also produced into the market even at current low prices. Thus the apparent “too- good-to-be-true” statistics showing growing gas production with declining drilling are simply that – too- good-to-be-true. The record drilling for oil, and its contribution to gas production, is masking the high drilling rates required to grow gas production in the EIA statistics (which classify a well as either “oil” or “gas” depending on its principal product).
Drill baby drill – Recent drilling rates are near all time highs
Production decline rates in both shale gas and shale oil wells are very high – first year declines in Barnett shale gas wells are in the order of 65% and are higher in Haynesville wells. Similar decline rates are observed in shale oil plays. Thus new wells must continually be drilled to offset depletion in existing wells. Figure 3 illustrates the aggregate footage drilled for oil and gas in the U.S. and the average depth of the wells.
Annual Footage Drilled versus Average Well Depth 1990-2011
It can be seen that the footage drilled is near all time historical highs. And it can be argued that a hydraulically fractured foot, drilled in 2012, required much higher inputs of energy and capital investment than a foot drilled in 1980, as the deposits targeted are so much more challenging (or marginal, depending on your perspective). In addition, the average depth of a well is 40 percent deeper than it was in 1990. This reflects the declining EROEI associated with domestic U.S. oil and gas production, which can only be expected to decline further going forward.
So, despite vocal industry proponents to the contrary, there is no such thing as a free lunch. Growing, or even maintaining, U.S. oil and gas production will require an increasing level of inputs in terms of the number of wells drilled, the footage drilled, the capital investments required, and likely, the large amounts of collateral environmental damage incurred.
Editor's note: This post spawned a vigorous debate among the editors that has delayed publication by about a week. This debate revolved around the contribution made by shale gas and shale oil plays to overall US gas production, the impact of delayed hook ups to production figures and the veracity of EIA data. These issues are open for debate in the comments.
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David Hughes makes many valuable and interesting points about U.S. gas production from shale plays but does not present data to support his premise that associated gas from more oil-prone plays is the cause of present over-supply . Our research suggests that the Eagle Ford, Bakken and Granite Wash oil-prone plays currently contribute about 9% of the total gas produced by shale plays based on June 2011 HPDI data, and that gas volume from other oil-prone plays is trivial.
Exhibit 1 shows historical production from all U.S. shale plays from January 2008 through June 2011. This exhibit indicates that while most gas production comes from Haynesville, Barnett, Fayetteville, Marcellus, and Woodford shale gas sources, the combined Granite Wash, Eagle Ford and Bakken contribution is notable also.
Exhibit 1. Natural Gas Contribution of U.S. Shale Plays. Source: HPDI.
Exhibit 2 shows the daily volumes from each U.S. shale play and the respective contribution of each to total shale gas production.
Exhibit 2. Natural Gas Contribution of U.S. Shale Plays and Percent of Gas. Source: HPDI.
Exhibit 3 compares the daily volumes and percentage of total gas production from gas-dominated shale plays and associated gas from oil-dominated shale plays.
Exhibit 3. Natural Gas Contribution of U.S. Shale Plays & Associated Shale Gas Plays. Source: HPDI.
These exhibits suggest that associated gas from oil-prone shale plays is a factor in U.S. gas production as David Hughes contends.
A factor perhaps, but you seem to demonstrate conclusively that it isn't much of one.
Bruce,
I agree but, in an over-supplied market, 9% of additional supply is notable and contributes to the ongoing surplus of natural gas.
Art
Years ago, a pipeline guy told me that the difference between a glut and a shortage in the North American natural gas market is 2% of supply. And of course, the relatively warm winter so far has contributed to weak demand.
However, on the supply side I suspect that a big contributor is the proven reserves treadmill that you documented--where shale players can book proven and proven undeveloped reserves on a BOE basis using a six to one ratio between gas and oil. I suspect that on a cash flow basis we could be looking at something like a sixty to one ratio this summer. Once companies get on the treadmill, it's very difficult to get off, and many companies may be drilling wells that make little economic sense, in order to maintain their proven and proven undeveloped reserve base.
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Stack enough older wells which have relatively flat, albeit very low production, and a lot less high producing fast declining new wells need to be brought on line yearly to keep production flat. The shape of the long tail describing the mature shale well's life cycle would dictate just the amount of new gas needed to keep production flat (or going up or down at any given rate). That holds as long as new wells' production and life cycles averaged out about the same as that of the wells drilled during the initial shale gas drilling surge. That might be a part of the explanation to why reduced drilling efforts in gas fields and increased gas production are happening simultaneously.
Of course low gas prices would tend to discourage even that amount of drilling so in the end there is a very, very high likelihood that it is the public company booking of reserves treadmill that keeps the drilling effort going at its current level.
I was just about to say the exact same thing. I recently spoke with some commodity traders that, long ago, bought natural gas, put it in storage, and sold futures against it. Now their gas is being "forced out" because of "storage rotation." Basically, producers are willing to pay more (or appear to be better long term customers) thus the storage operator is forcing the speculators out. The speculators, in turn, have to sell their gas "at any price".
Good for merchant power producers who weren't hedged.
Scott Hanold, a Minneapolis-based analyst for RBC Capital Markets says, "Gas produced from oil wells probably accounts for about 10 percent of the roughly 75 billion cubic feet per day produced from onshore U.S. wells outside of Alaska". http://fuelfix.com/blog/2012/01/24/chesapeake-stalls-slide-in-gas-prices...
If that's true, it's hard to believe 9% is coming from shale oil wells.
Just a thought...
Though the 'dry' shale gas drillers may slow down the number of wells they complete (I think that's the right term) because of the price disincentive, the shale oil drillers have lots of incentive to increase the number of wells drilled. The increased drilling, or steady state, in the shale oil plays may slow the declines of the gas volumes which will extend the glut.
Exactly. They're squeezing the rocks for the more profitable liquids. The extra gas is more a competition killer than a profit maker right now. I'd bet they're looking long term for profits from the gas -- exports, products, transportation.
Climate impacts on these unconventionally accessed fuels will be pretty terrible. But this does give the US an economic advantage over the next 10+ years. A pessimist would say that we make the same mistake we did with oil -- become over-dependent on nat gas for everything and deplete the new resources at a very rapid pace. For my part, I hope we use the time the gas/liquids buy to speed the transition to renewables.
What would be best, in my opinion, is to add an 'energy independence' feed in tariff on all fossil fuels produced within the US as well as oil imports. The tariff would then go to direct investments to produce and incentives to purchase renewable energy systems. In combination, the time bought by new oil and gas supplies and a rapid development renewable energy program fueled by feed-in tariffs, US energy independence becomes a visibly achievable goal and puts us at an amazing advantage in the energy markets.
ND produced about 0.5 bcfd in November and sold perhaps 0.35 bcfd. That works out to about 0.8 % of US total.
EIA figures reflect 'dry gas' production(actually sales). As far as I know, the EIA estimates production based on voluntary reports from selected operators. That may be the source of some error.
Bakken associated gas is bringing about $7/mmcf in some cases because of ngl's. These operators get a 'netback' on ngl's.
Here is the EIA annual dry natural gas production chart (looks like 2011 will be close to 23 TCF):
Two key differences between 1973 and 2011: (1) Vast increase in the number of gas wells now versus 1973 and (2) Most of the new wells in 2011 have very high decline rates, versus the 1973 decline rates. So, the net energy per well is much lower now, versus 1973, and most of the new wells have a much higher annual production to reserves ratio, versus 1973.
For example, in 1972 Texas gas wells produced 7.5 TCF, from 23,000 gas wells (893 MCFGPD per well), and in 2010, Texas produced 6.4 TCF, from 102,000 gas wells (172 MCFGPD per well).
So, the average gas well in Texas in 2010 produced one-fifth of what the average gas well in Texas produced in 1972.
I can't lay hands on production v. time at the moment, but isn't that true only in the first year or so, but thereafter decline rates for shale gas are less than traditional vertical wells?
Some of the case histories I have looked at, e.g., the DFW Airport Lease, actually show accelerating rates of decline with time (although my last production data were through May, 2011).
Do you measure decline in percent?
Usually percent per year, e.g., the rate of increase in average annual US dry natural gas production was 1.00%/year from 2000 to 2010 (and 2.3%/year from 2004 to 2010):
http://www.eia.gov/dnav/ng/hist/n9070us2a.htm
I have a pet theory about natural gas production. I call it the flat tire phenomenon.
Farmers sometimes put fluid in tractor tires to increase weight and thereby gain added traction. These tires seldom go flat and if they do it takes a long time as it is fluid that is leaked mostly. In contrast air filled tires can go flat over night.
In the case of oil wells, oil often leaks out of the rock slowly and the remaining rock acts as a dam to prevent more distant oil from coming to the well. The fluid has a hard time getting through the rock to the well.
But gas is different. Like air in the tire under pressure it tends to leak out easily and faster if there is any leak at all. And as pressure is released from production gas tends to equalize the underground pressure faster because it has an easier time passing though rock, just like the air filled tire tends to go flat faster than the fluid filled tire.
Not only that, the rapid drop in gas pressure near the well tends to collapse the surrounding rock like a flat tire collapses. This underground movement releases yet more gas since gas can pass more easily through rock than fluid. This explains reports of earthquakes near fracked gas wells in Ohio and elsewhere.
It also explains why gas production can continue as a relatively high level even as oil production stalls out. The leaking fluid filled tire will still be up in the morning while the leaking air filled tire is flat.
Dude has discovered viscosity !
With pressure drop, fractures close and constrict flow relatively. If we are lucky, the nanodarcyosphere (rock matrix) will give up gas and maintain pressure(somewhat).
I would like to add that the there has been a large leftward shift in demand due to the relatively warm winter and "softness" in the power market.
Interesting perspective. In general it's good to not forget the time lag involved especially with offshore fields. Sometime investment decisions are made years before the actually price of oil/NG can be estimated confidently. Maybe I missed it but I didn't notice one very significant factor explaining the increase in domestic NG production: the Deep Water Independence Hub in the GOM . From RigZone: "Natural gas production through the Hub began on July 19, 2007, from the first of 15 subsea wells located in 10 anchor fields. The producers expect to ramp up production toward the Hub's capacity of 1 billion cubic feet of natural gas per day (Bcf/d) by late 2007. " Literally in a month's time US NG production increase 1 bcf/day. During the second quarter of 2011 the IH surpassed a milestone of more than 900 bcf of cumulative NG transported.
Not coincidentally this is when the EIA chart begins to show a significant ramping up in rate. That's the good news. The bad news is that DW wells are optimized for rate and not URR. Most DW fields deplete in less than 7 years. The additional good news is that now that the IH is in place as well as other pipeline systems, smaller fields may become economic to develop. Unfortunately current NG prices could delay many if not most of those new projects. OTOH just last month Anadarko announced the discovery of Cheyenne East field close to the IH. They anticipate first production later this year.
"And it can be argued that a hydraulically fractured foot, drilled in 2012, required much higher inputs of energy and capital investment than a foot drilled in 1980,...". Perhaps a bit of an understatement in some cases. Spoke to an engineer yesterday about a great new Marcellus well in PA. Great but at an expense: an 8,000' lateral with 20 separate frac stages. He said the completion, including the frac job, cost 3X as much as drilling the well. OTOH we've been putting big fracs in vertical wells for decades. In 1978 I pumped a 500,000# on a vertical well in Lavaca Co. Texas. In west Texas they've been frac'ng vertical wells since the 50's. Shale wells have been drilled/frac'd for a long time including a period of big time horizontal drilling in Texas...the Austin Chalk. Except for longer laterals and more frac stages nothing new is going on today. What drove these plays prior to 2008 was the expectation of higher NG prices...they briefly bounced off $13/mcf. And then came the price crash that crippled Chesapeake, Devon et al. As NG prices stabilized the public companies discovered they could not replace their reserve base from conventional plays: not enough prospects to go around. In that sense the shale plays saved their hides: even if the profit potential was that great there were tens of thousands of potential wells to drill that could used to increase the reserve bases of pubcos and thus keep Wall Street happy with them. But with NG prices falling it's difficult to expect this trend to carry on in those non-oily trends. Chesapeake just announce they were cutting their drilling budget by 8%.
"In addition, the average depth of a well is 40 percent deeper than it was in 1990." That's been driven more by conventional NG drilling. Below a certain depth/temperature finding oil is very unlikely. Eventually as the shallow prospects are drilled there's nothing left but the deep wells which will predominantly be targeting conventional NG. These are the wells I'm drilling today. But instead of drilling 12,000' wells testing 1,500 acre targets as I did in 1980, I'm drilling 16,000'+ wells testing targets that are often less than 100 acres. Due to deteriorating NG prices we've just cancelled half our wells for this year, That represents a total cut in drilling of over $80 million. And we're a very small company.
Rockman:
Do you hedge forward your production? One theory I have seen for the glut is that many wells are backed by financial investors. To minimize risk and/or lock in profits they hedge forward the production for up to 2 years.
Now that the price is down it will take 12-24 months to wean the hedged production out of the market so don't expect a major reduction in production anytime soon.
Hedging varies greatly from company to company. CHK didn't have much at all of their 2012 gas production hedged (17%) while others did have quite a bit hedged.
I can't speak for gas producers but the large coal producers are hedged ~90% one year out, 50% two years out, and <10% three years out. If they're publicly traded you can find it in their 10Ks.
I fail to see why publication of this report was delayed a week but I also see why some of the data thrown up would merit debate the most obvious being how much gas is produced by gas wells and how much by oil wells. What I didn't see was data totaling up the breakdown of frac wells vs non frac wells and their associated production. Also in a related question what % of existing wells are frac, both oil &/or gas and what % of new are?
hugho - No we don't. We sell directly into the market. My owner has other commodity hedging operations...all paper trades. In fact, it's those ops that fund my drilling programs...he's very good at it. For one thing, hedging isn't free. And there th obvious risk of betting the wrong way. Also, the biz plan is to put $X amount of oil/NG reseves in the ground and flip it down the road. Having production hedged makes that more difficult: you're asking the buyer to take the risk on a bet you made.
The reason why gas is so cheap is because production is so high. The Law Of Supply And Demand is still alive and well. The reason production remains high, even though many gas wells today are presently uneconomic is because, the operators HAVE to keep bringing new wells on line in order to keep their leases. It's cheaper in the long run to operate new wells at a loss, than to lose the land leases the uneconomic wells are located on.
The reason the "well count" is going down is because gas operators are switching to Liquids (Oil and NGL's) instead, because it's more profitable. The Oil and NGL well counts are going up, up, and up. When you consider that the Eagle Ford, Woodford, Granite Wash, plus the Bakken are all now morphed into Liquids plays, you've got enough gas produced as a cheap by-product of Liquids production to push the gas price way, way, way down. This by-product effect also results in greater Oil and NGL production, because now the more marginal Liquids plays have also become even more economical. The reason these marginal Liquids plays are/were so marginal is because of....their high gas content. Get it? The Liquids are the cake, the gas is just the frosting on the cake.
This article, like so many other articles at TOD, is barking up the wrong tree. You will NEVER, EVER get the complex energy equations right, unless or until, you also factor in "The Dismal Science." The best way to do this is to access all your information from the companies on the ground doing the work. However, none of the information you will get from these companies will ever support any Peak Oil theories. Sorry. Next step is to try to understand, exactly why this is. But, don't bother barking up any more of the wrong trees.
I'm sure that producing regions don't peak on Fantasy Island, but here in the real world, one doesn't have to look very hard for examples of production peaks, e.g., Texas & the North Sea, two regions developed by private companies, using the best available technology, with virtually no restrictions on drilling. Combined, they accounted for about 9% of cumulative global production through 2005.
1972 Texas peak (in black) lined up with absolute 1999 North Sea peak (different vertical scales, C+C):
It's interesting to see how production responded to rapid increases in oil prices. Texas & North Sea production on horizontal axes, versus annual oil prices on vertical axes:
http://i1095.photobucket.com/albums/i475/westexas/Slide2-2.jpg
Curiously, the combined efforts of the global oil industry have been unable to cause a material increase in global crude oil production since 2005, in contrast the rapid increase in production from 2002 to 2005.
Although global production (in black) and the North Sea had different rates of increase leading up to their respective plateaus, the two plateaus have, so far at least, been remarkably similar (different vertical scales, C+C):
Note that the annual Brent crude oil price doubled from 2005 to 2011, from $55 to $111.
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Circumstantial evidence? No hard evidence?
I showed two "No excuses" production peaks, with both declines corresponding to rapid increases in oil prices. I then showed the post-2005 global crude oil production plateau, which corresponded to a doubling in global crude oil prices. And then we have what our data suggests will be an ongoing--and accelerating--rate of decline in the supply of Global Net Exports (GNE) available to importers other than China & India.
Ironically, the current slow rate of increase in US crude oil production* is primarily due to high global crude oil prices, resulting from flat global crude oil production and the ongoing decline in GNE.
*Monthly EIA data through October show a 2011 production rate of about 5.6 mbpd, versus the pre-hurricane rate of 5.4 mbpd and versus 5.5 mbpd in 2010 (C+C). I estimate that there were 1,000 rigs drilling for oil in the US in 2011, resulting in a net increase of about 100 BOPD per rig per year in 2011.
Rig count data:
http://www.wtrg.com/rotaryrigs.html
Annual US crude oil production through 2010:
You really need to make the scales comparable. If the North Sea is going to be on scale that represents 67% of the top of the scale, then global production should be too: i.e., the global scale should start at about 25. A note that the scales are different doesn't really help.
As noted in my comment, the rates of change in production for 2005 to 2011 globally and for 1996 to 2002 for the North Sea are quite similar.
FOR ALL
I suspect westexas chose the scales to make the chart more visually dramatic. Regardless of the scales if you know how to read a chart it doesn't matter what scales he uses IMHO. The data tells the same story. But the similarity of the curves points to a fact that many don't realize: Mother Earth loves log-normal distribution. Go to any mature oil/NG trend and plot reservoir URR. There are a very small number of big fields and many smaller fields. Plot that curve on a log-normal scale and it's truly amazing: in many cases it plots a near perfect straight line. IOW the reservoir size distribution is anything but random. And it doesn't matter if the largest fields are 100's of millions of bbls of oil or just a few million. I suspect this is the main reason why the two curves seem so similar despite being on different scales. While economic and political factors affect the development of different trends/basins, once enough wells have been drilled the log-normal distribution will usually dominate the stats. I suspect if wt's data were plotted log-normal it would show two straight and parallel lines.
the two curves seem so similar despite being on different scales.
They only look similar because they're on mismatched scales.
if wt's data were plotted log-normal it would show two straight and parallel lines.
They wouldn't. The percentage growth rates are very different, and a log-normal chart would show that nicely.
Part of the problem here is that global production is going to behave very differently from the production of a single field.
One big reason: in the past if a single field declined world prices didn't rise, while global production affects prices. As you've said many times, horizontal wells and fracking aren't new, but high prices have changed how they're used.
Nick,
"Part of the problem here is that global production is going to behave very differently from the production of a single field."
This is Peak Oil blasphemy! But, you are entirely right! The whole concept that Peak Oil is built upon is that, the whole world is just like one big oil field. And, as time has proved over and over again, it ain't. Because prices will always rise high enough to ensure a greater supply, or demand will slacken so much, there is no need for more supply.
Thanks.
Regarding your 2nd paragraph...that seems a bit strong.
I suspect we're on "peak-lite", where liquid fuel supply will grow slowly for a while, while prices stay below $125/bbl, and that we'll then see a plateau for a while.
For me, the fascinating question is when EVs will expand to the point where they gain serious economies of scale, and suddenly liquid fuel demand starts to drop sharply.
no doubt if the world oil production acted like the the North Sea's we'd be in a world of hurt real soon. But it is very hard to argue with WebHubbleTelescopes cumulative discovery plotting
his oil shock model gives this as the production curve--remember this is a crude oil production curve not all liquids--and I don't believe Canadian tar sand production is included either but if Web is out there he might correct me.
Lots of people harassed Web to put his crude oil production prediction on the table (often bringing out the worst of Web,s abrasive qualities) but few said booo, when he finally posted it.
I'm not too fond of westexas mismatching the scales to compare a single oil field to world producion either. Smacks of talk radio tactics.
WHT often points out that his model produces a much fatter "tail" than does a simple symmetric normal-type curve.
Even so, there's a few problems with this model:
1) it back dates reserve increases to the time of initial discovery. Now, the Bakken seems to have 200-400B barrels of oil in place. The official estimate just a few years ago was that the URR was very small - N. Dakota production peaked long ago. Then it rose to just under 4B barrels a couple of years ago, and now it looks reasonably likely to be, what, 15B?
Similarly, US lower-48 reserves have stayed roughly the same for 40 years - about 10 years production!
Is it really valid to backdate increases like that? How do you work that kind of increase into the model above?
2) So far, there's no sign of the 2008 peak shown in this model.
3) crude is a useful thing to model, but all liquids are what matter.
2) So far, there's no sign of the 2008 peak shown in this model.
What are the world crude numbers since 2008--do you have them parsed out somewhere?
Of course crude isn't the whole picture, but it is still a huge part of it--especially the price part of the picture.
Since Web back dated reserves for the whole period charted it likely isn't that big an issue going forward--the whole picture would just flatten out a little moving the peak to the right some if he plotted the reserve increases as new discoveries.
Are the Bakken additions much different proportionally than reserve additions the mega fields we've nearly drained encountered?
Similarly, US reserves have stayed roughly the same for 40 years - about 10 years production
please put the numbers up (and source). I'm not disputing the statement but I've no ready recollection of the number and it certainly helps to see it once in a while
the whole picture would just flatten out a little moving the peak to the right some if he plotted the reserve increases as new discoveries.
Well, the whole model would look completely different if all reserve additions were not backdated - that's meaningful. It's not at all clear if new reserve increases are going to be small - look at Kurdistan and elsewhere in Iraq. And, there's Canada's recent increase - now, that was tar sands, but that goes to the other point: other liquids may not change the peak a lot, but they'll make a real difference to decline rates.
I think the Bakken additions are indeed higher than usual. OTOH, tight/shale oil exists in a lot of other places - we've known about that, but ignored it, just as we did the Bakken. Finally, we don't have good evidence that existing fields won't see additional increases.
I'll look for those other numbers.
the whole model would look completely different if all reserve additions were not backdated
Completely is likely a big overstatement.
Reserves like the Bakken can grow as much as they want--if the extraction rate hits a wall of about 1mbpd or less they will just thicken the long tail a tad. The effort it takes to develop such fields does make me wonder if regions with far less infrastructure and industrial capability would be able to make other shale plays pay.
Will long tailed plays like the Bakken balance out all the deep water plays where production falls off even faster than in the North Sea? We suck oil out of all fields a heck of lot faster now than back when US production peaked in 1970...and crude production is barely more than treading water
Completely is likely a big overstatement.
Well, I was talking about redoing the original chart without any backdating of reserve additions. IIRC, most of these cumulative reserve numbers came not from the original time of discovery, but later in stages. So, a redone chart without backdating will look completely different.
That's not to say that the original chart with backdating is completely invalid, but it does have it's limitations. Perhaps it's biggest limitation is that it's based on the behavior of fields and regions, and global production has price feedback that will change the dynamics of things.
make me wonder if regions with far less infrastructure and industrial capability would be able to make other shale plays pay.
Yes, lack of infrastructure will slow things down. OTOH, the potential returns are enormous. Heck, they can truck the oil out for a few dollars, and they will.
crude production is barely more than treading water
Yeah, that's the crucial thing - for the first time in roughly 100 years, for about the last 7 years supply has truly been limited. My best guess is that crude will increase very slightly for several years and that all liquids will increase a little faster for a little longer, then we'll have a moderately long plateau.
"Predicting is very hard, especially when it's about the future." - Neils Bohr?
Yes, lack of infrastructure will slow things down. OTOH, the potential returns are enormous. Heck, they can truck the oil out for a few dollars, and they will.
it's not just moving the oil-it is also moving tremendous amounts of equipment, pipe, diesel, fracking fluid and the list goes on--if we are really lucky there won't be a need to go after tight oil in the least accessible areas.
Some folks are talking up a bit of storm about going after shale oil on the North Slope. Shipping costs, permafrost (and sometimes great distances to gravel pits), water access (the Great Bear crowd seems to think they will be able to utilize the saline stuff they will be drilling through for the fracking) and a host of other items will make the effort a real challenge--and maybe we should mention winters are a fair piece tougher and longer on the North Slope than in North Dakota, Eastern Montana and Southern Alberta/Saskatchewan.
Drilling was supposed to start in November, nothing on the web yet-I might have to ask around.
Anyway this is in region with a massive developed, though aging, crude oil delivery system, very promising geology, and high construction and operations costs. What comes of Great Bear's project should tell a bit more about the limits current crude prices impose upon possible tight shale oil production efforts.
Well we have wandered pretty far from the key post--though we are now talking the North Slope and it has somewhere between 30 and 130 trillion feet of natural gas stranded under it. We will know the world natural gas market is hungry when/if that stuff finally gets piped to market.
I learn something every day. Today, I learned that there is only one oil field in the North Sea. I yield to the collective wisdom of my critics, and I apologize for my mistake in thinking that there is more than one oil field in the North Sea. Perhaps readers should evaluate the quality of the critics' comments based on the critics' level of understanding of global production.
In any case, as I pointed out several times, the key similarity is the rate of change in production for the North Sea, from 1996 to 2002, versus the rate of change in global production from 2005 to 2011. Would anyone like to do a post comparing those numbers? Anyone? Anyone?
However, there is one other similarity. Based on the HL plots, the North Sea was about 50% depleted in 1999, and global conventional production was about 50% depleted in 2005.
Today, I learned that there is only one oil field in the North Sea.
Field...region...play...that's arguing with a detail, and suggesting that it discredits the whole argument. It combines two fallacies: arguing with a detail (I forget the technical name of the fallacy), and arguing by ridicule. Neither feels good to the audience, or convinces anyone who didn't already agree.
the key similarity is the rate of change in production for the North Sea, from 1996 to 2002, versus the rate of change in global production from 2005 to 2011.
Great. Then in the future, just chart those two periods, and use matched scales. We can argue, or agree, about what that chart tells us.
I think that your comment speaks for itself.
I wish it did - what are you saying, that the mistaken word really does invalidate that the chart is wrong?
Incidentally, I didn't even originally quote you. It was one of the other experts in global production, one who could not differentiate between between an oil field and a producing region. Incidentally, if there is little difference between an oil field and a producing region, why is there so much controversy over comparing a producing region to the world? But I digress.
Regarding your assertion that the chart is wrong: Are the vertical or horizontal scales wrong? Are the production numbers wrong? Are the time periods wrong? Did I not state that the rates of increase leading to the respective plateaus were different? And did I not point out that the vertical scales were different?
I didn't even originally quote you.
I know - I just didn't want the discussion to get sidetracked.
, why is there so much controversy over comparing a producing region to the world
The point remains the same - the comparison needs to be presented properly. The secondary point, that a region's production may behave differently from the world, is still valid.
Are the vertical or horizontal scales wrong?
The vertical scales are wrong: if the N Sea production is charted over 2-6B, that's 2/3 of the total. The world production needs to be on the same scale: roughly 25B - 75B.
Did I not state that the rates of increase leading to the respective plateaus were different? And did I not point out that the vertical scales were different?
Yes, but we can't see it in the chart. Visual arguments are much more powerful - the scale needs to be right so people can visually compare things properly.
Sorry. As the Rock noted, there is nothing wrong with the chart. There does seem to be something wrong with your interpretation. Why don't you just put a piece of paper over the graph, and worry about something more important.
Ask anyone who does this kind of analysis and presentation professionally (as I do), and they'll tell you the same thing. You've noticed that three different people have objected to it, just in this thread?
As I repeatedly noted up the thread, the graph shows what I intended it to show--similar production plateaus, incidentally at comparable stages of depletion based on HL plots. And I noted the different rates of increase leading to the plateaus and the different vertical scales. It's a mystery to me why you guys are so obsessed over a simple graph that shows exactly what I intended it to show.
"It's a mystery to me why you guys are so obsessed over a simple graph that shows exactly what I intended it to show."
---------------------
The reason is simple: they want to shut you up. If they're successful, they will have eliminated one of the few people in the Oil Industry willing to speak the truth about Peak Oil. We can't have that, can we?
No, bmiller, I don't think so. I also object to westexas' mixed use of scales. However, I don't want him to shut up; just fix the chart :)
Hi bmiller. I fixed the chart. See response to ROCKMAN's request to Nick for an alternative chart.
the graph shows what I intended it to show
But you don't really want to mislead, right?
It's a mystery to me why you guys are so obsessed
I'd say you care about this exactly as much as we do - otherwise, why argue about it? And you and we are both right to put energy into it - it's important.
I noted the different rates of increase leading to the plateaus and the different vertical scales.
Visual evidence is much more powerful than words. A footnote won't do: the chart needs to be correct.
I learned that there is only one oil field in the North Sea
you got me there--I was being careless--I just looked the North Sea plots a few weeks ago and I should have caught myself-I just lazily used terms bantered around by a couple other posters
Thought the talk radio comment might get a reply ?- ) It was a bit unfair. I'll lay out the scaling difference below--I figured the rundown would have a bit more hitting power if I actually got you to chime in ?- ).
sure the rate of change on the flat top is comparable but it is the run up (and in the case of the North Sea the run back down) rate of change that holds the eye.
Just a tad different rate of change there (very rough 'edge of envelope' numbers garnered from your charts used in below calculations)
global 2002-2005 about 10% increase (67-74mpbd)
North Sea 1993-1996 about 32% increase (4.3-5.7mpbd)
The way you place the two different scaled graphs suggest the run up is comparable and leaves it to the reader to infer the rundown will be comparable as well. North Sea drops about 21% in seven years from [edit: I fat fingered 2001 originally] 2002-2009. So the eye would extrapolate world production dropping about 7% from 2013-2020 to around 69 mbpd . That might or might not be all that unreasonable a prediction-time will tell. Certainly a shut down of the Straits of Hormuz would throw a heck of monkey wrench into the prediction business.
The same objections to that chart have been mentioned repeatedly over the months. Since you have the real numbers instead of the crude ones I grabbed a simple paragraph under chart mentioning the all the relative change rates on your graph would eliminate any reasonable objections to your scaling method. But then maybe letting the reader handle that is just your teaching style...that method won't work on everyone but what does?
The chart covers a much longer period than that. A chart that compares two things with different relative scales isn't presenting the material accurately.
Nick - Can you point me to one bit of data on the chart that isn't accurate? Thanks in advance.
Yes, the scales. They need to match. Part of what is being shown in that chart is how the two curves look very similar....and if they were presented properly they wouldn't.
Nick - So the data presented on the chart don't represent the actual production vs. time? Please post the correct info so we can all see the errors.
Or how about this: take wt's data and post it in a chart with whatever scales you like. Then whenever wt posts his chart you can just post yours and we can save a lot of chatter. Everyone here can then chose to study your chart or his. Simple solution.
the data presented on the chart don't represent the actual production vs. time?
Not really. If a chart makes growth look 10x as large as it is, that's misleading. If it makes two dissimilar curves look alike, that's misleading. If it implies that global production is about to decline just like N. Sea production, that's misleading.
: take wt's data and post it in a chart with whatever scales you like.
Sure, we could have dueling charts. Still, better just to do it right.
OK, I made this chart eyeballing numbers every 4 years from westexas' chart and plotting them as a percentage of the peak. The last number for North Sea is extrapolated (wes's chart only goes to 26 years). To me, this is a very different (and more representational) picture than the original.
As I have noted once or twice up the thread, my point was that global conventional crude oil production in 2005 was at about the same stage of depletion that the North Sea was at in 1999 (based on HL plots), and that global crude oil production was showing the same type of plateau that the North Sea showed around its absolute peak in 1999, despite the fact that the North Sea showed a more rapid increase in production leading up to the plateau, and a more rapid decline than what we will see globally.
But here is what the EIA shows for the 5 year rate of change in North Sea production from 1996 to 2001: +0.06%/year.
And here is what the EIA shows for the 5 year rate of change in global crude oil production from 2005 to 2010: +0.08%/year.
My chart shows the similarities between the two production plateaus (at roughly the same stages of conventional depletion). The point being that sometimes we see a very well defined peak, e.g., Texas and sometimes we see more of a production plateau around a peak. And in any case, despite a doubling in global crude oil prices from 2005 to 2011, the combined efforts of--and billions of dollars spent by--the global oil industry have, so far at least, been unable to show a material increase in global crude oil production, as we see an ongoing decline in Global Net Exports.
As noted up the thread, it remains a mystery to me why you guys are having fits about the North Sea rates of change before and after the plateau (and I noted the differences in the rates of increase and in the vertical scales in my original post).
In any case, since this appears to be a topic on which some of us will have to agree to disagree, I suggest that we drop it.
The essential point that they are missing is that, although the scales are different, the mathematics of the curves are the same. Only the parameters generating the curves are different.
It's some kind of bell-shaped curve, and I haven't done enough analysis to determine which bell-shaped curve. The people who have analysed it came to different conclusions, from which I conclude the analysis is not easy. It could be Gaussian, it could be the first derivative of the logistics curve, I don't know exactly what it is.
However, the important point to note is that world oil production is going to follow a bell-shaped curve. Which kind of bell-shaped curve is the real issue.
I tried simulating it using a computer and what I know about the world oil industry, and using any kind of reasonable assumptions, it comes out as some kind of bell curve. There's material here for masters and doctoral theses, but since I'm not working on an M.S. or Ph.D. I'll leave it to someone else to develop the math.
From my POV, I've determined that it's a bell-curve of some sort, so my real questions are 1) when is the peak? and, 2) how fast is the decline? The practical purpose is to avoid being blindsided by the events which follow. Many people have been blindsided already, and I'm hoping to avoid becoming a casualty in future.
the mathematics of the curves are the same.
Westexas just got finished saying that they aren't.
The two curves will look very different: the growth rates up to the plateau are very different, and there's a very good chance that global production will show a very long plateau and then a very fat tail. WebHubbleTelescope would tell us very firmly that will be the case.
US lower-48 production doesn't look very much like a bell curve. KSA and Russian production look nothing like a bell curve.
Yes, the N. Sea is an example of a plateau: that's evidence that such a thing can happen. But, we knew that already.
The N Sea curve tells us very little about the global curve.
Westexas just got finished saying that they aren't.
No he didn't. Try reading what he says for a change.
What I am saying is that the curves are based on the same mathematical principles. For instance, if it is a Gaussian function then the underlying equation is:
and the curve can look like any of the following:
If you vary the scale of the graph, you can make the curves match, which indicates they are actually the same function. I'm not sure it is really a Gaussian curve, but some experts believe it is. It could be one of the other bell-shaped curves that are common in statistics and other mathematical fields.
I used to design software to do oil production forecasting for oil companies, and I discovered that if I fed any kind of reasonable assumptions about how an oil field was going to be developed, I ended up with a bell-shaped curve. If I took all the fields in a particular region, e.g. the US Lower 48, ordered them by discovery date, and summed them, I got a bigger bell-shaped curve. If you take all the regions in the world and sum them, you will get a huge bell-shaped curve.
Mind you, I can come up with all kinds of exceptions, e.g. the Canadian oil sands, but these fall into the category of "exceptions that prove the rule". The Canadian oil sands won't add enough to global production to modify the shape of the curve, although it may stretch out the tail somewhat.
Westexas just got finished saying that they aren't. - No he didn't. Try reading what he says for a change.
You're talking about something slightly different. My point: if the curve is flatter, then it's not comparable. The original chart suggests to the viewer that global supply will very soon start to decline, and do so sharply, just as N. Sea did. Both takeaways are misleading.
If you vary the scale of the graph, you can make the curves match, which indicates they are actually the same function.
We can't say that yet about global production (which is where we started, and which is the whole point here): we don't have the data yet.
If I took all the fields in a particular region, e.g. the US Lower 48, ordered them by discovery date, and summed them, I got a bigger bell-shaped curve. If
What do you mean, "ordered them by discovery date"? US production didn't look very bell like even before it started growing again. N Dakota is an obvious exception: it had a peak some years ago, and now is growing again.
If you take all the regions in the world and sum them, you will get a huge bell-shaped curve.
If you select only the regions that have already clearly peaked, and move the curves so that they all start at the same time, then maybe. But, of course, those curves didn't start at the same time, which makes all the difference. After all, the global production chart is all of the regions of the world summed up, right?
And how do Russia and KSA look bell-curved??
Finally, most of the curves you're thinking of were generated during the low-price era before 2004. A global production peak creates a price feedback which doesn't exist for regions: Texas has stabilized, N Dakota is growing - things change when prices rise.
A bell-shaped curve is a bell-shaped curve of whatever type. They're ubiquitous in statistics and other fields such as biology, physics, finance, and communications. It would hardly be unusual for them to pop up in petroleum production as well. It could be a Gaussian function, it could be the first derivative of the logistic function. Another possibility, as Rockman suggested, is a log-normal distribution. Determining which one is material for a University thesis.
Log-normal distributions
And how do Russia and KSA look bell-curved??
Those are two of the production curves that prove the rule, as the saying goes. Russia's curve is actually a bimodal distribution - two bell curves superimposed on each other, one a Communist bell curve and the other a Capitalist bell curve, which is interesting from the standpoint of economic theory. Saudi Arabia's production curve is completely arbitrary because KSA has been acting as swing producer for the world and going the opposite direction from everybody else to stabilize prices - again interesting from an economic perspective.
Bimodal Distribution (note similarity to Russian production)
You really need to take a course in this stuff because it has numerous applications in many different fields.
A bell-shaped curve is a bell-shaped curve of whatever type.
You're focusing too much on the technical details. I'm focusing on broad questions, like whether the N. Sea curve (or that of any region, for that matter) is useful in forecasting the shape of the global curve. As you agreed downthread, it's not.
Russia's curve is actually a bimodal distribution - two bell curves superimposed on each other
Exactly two (roughly) bell curves displaced in time don't add up to a single bell curve.
Saudi Arabia's production curve is completely arbitrary because KSA has been acting as swing producer for the world and going the opposite direction from everybody else to stabilize prices - again interesting from an economic perspective.
Exactly - one of the top 2 or three producers that help shape the global curve isn't bell shaped at all.
You really need to take a course in this stuff because it has numerous applications in many different fields.
You shouldn't make assumptions - FWIW I've been doing this kind of analysis as long as you, with a wide variety of analytical tools: stochastic and deterministic; top-down models and ground-up simulations (ground-up doesn't sound good does it....). For what it's worth...which isn't much: what matters here isn't our authority, it's the evidence and logic we present.
Finally, most of the curves you're thinking of were generated during the low-price era before 2004. A global production peak creates a price feedback which doesn't exist for regions: Texas has stabilized, N Dakota is growing - things change when prices rise.
We were through this before in the 1970s, and I'm old enough to remember it. The price of oil quadrupled, they put the Alaska North Slope on production, everybody thought the problem was fixed, and - it was only temporary. The ANS discoveries just put a minor blip in the bell curve and then we were on the downslope again. North Dakota's potential is nowhere near the size of the Alaska's Prudhoe Bay, which was the biggest oil field ever found in the US, so I don't expect much more than another blip.
Alaska is in steep decline, California is in decline, and the Gulf of Mexico deepwater fields should start to decline soon, so I don't hold out much hope for North Dakota bailing out the entire US. Rockman can tell you more about Texas' potential since he's drilling there, but I don't see him raving about having saved America from oil shortages, either.
Rocky,
"North Dakota's potential is nowhere near the size of the Alaska's Prudhoe Bay,"
As, Prudhoe Bay's EUR is 13-14 billion, and the Bakken's EUR is presently 24 billion, it looks to me like you've got it backwards. It might help your understanding of this issue if you plugged some numbers into your own equation. No one even knows what your reference points are.
"so I don't hold out much hope for North Dakota bailing out the entire US."
Neither do I, nor anyone else in the oil industry. Gee maybe, that's why all the dozen or so other Bakken like tight oil plays in the U.S. are also being developed. I live in Denmark. What country do you live in?
that's why all the dozen or so other Bakken like tight oil plays in the U.S. are also being developed. I live in Denmark. What country do you live in?
I live in Canada, and we have our own share of the Bakken Formation in Saskatchewan. It extends across the international border.
It's a nice play, and has helped make Saskatchewan rich, but it's not a game-changer. We also have a similar play in the Cardium Formation in Alberta, but that's only two big oil plays where hydraulic fracturing makes a major difference, and they are nothing compared to the Canadian oil sands.
24 billion barrels is an awfully wild-eyed estimate of the Bakken potential. The USGS estimated the "technically recoverable" reserves at 3.0 to 4.3 billion barrels, but the USGS has a long track record of being overoptimistic. The state of North Dakota estimated the recoverable oil at 2.1 billion barrels, and that's probably more realistic.
There are not, "a dozen or so other Bakken-like tight oil plays in the U.S." There are the Bakken in ND, the Eagle Ford in TX, and that's about it. The Eagle Ford is a wet gas play rather than an oil play. There are other, smaller plays, but they are in fact, smaller.
I would guess that North Dakota production will peak around 2013-2014 at something under 1 million bpd and then decline steeply from there. It's a crap shoot, so nobody knows until it happens. However, it always happens, and then ND will be on the same downslope as AK, CA, and probably TX again by that time.
To say there are only two is completely disingenuous. I can name 12 "liquids rich" plays in the US that have major changes from hydraulic fracturing.
Niobrara
Third Frontier
Spraberry
Wolfcamp
Wolfbone
Avalon Shale
Third Bone Springs
Cana Woodford
Mississippian
Granite Wash
Cotton Valley
South Western Marcellus
Utica
Cr*p. Now I have 13 new plays to investigate, and I'm probably too late to get into any of them.
Rocky,
If you live in Canada and want to understand the U.S. Bakken, (where most of the action is) then you will just have to study the oil production of a country you don't presently live in...just like me.
Like yourself, I also haven't learned anything at all about U.S. oil production by staying focused on the oil production of the country I'm presently living in.
When you multiply 48,000 wells times an average EUR per well of 500,000 BOE, you get 24 billion BOE. Where is the "wild-eyedness of this estimate? The USGS survey was in 2008, with a cutoff date from June 2007. It is not used anymore by the American oil industry as it is considered to be hopelessly out of date. Ditto the 2.1 estimate as it's from the same time period.
As, another reader has shown you a very short list of shale formations, there is no point in me pointing out all the rest. The Eagle Ford has an oil window, too. Why else do you think that many Bakken oil companies also own extensive acreage in the EF, not to mention all the other oil shales? In the oil business, it's not the size that matters, unless you are refering to the size of the profits they get from both large and small oil formations.
Odd, that the Bakken Oil industry insists on disagreeing with you, when you know so much about it, as the general understanding is 1 millions barrels by 2015. There are presently plans for 1.3 million in take away infrastructure. Present daily production is about 510,000/day. May I suggest you take a winter's vacation down to warm and sunny North Dakota, and have a look around for yourself? I can't make it, as I'm presently very busy studying ND oil production on this new fangled invention called the Internet. I've been told that you can actually find all the latest up to date information on the Bakken just by going to the right websites.
Do you believe in Peak Oil or something? You do seem to have about the same grasp of all the relevant facts, as most of the true believers do. I've heard that faith can move mountains, but have never seen it actually happen. By the way North Dakota is located somewhere to the south of Canada, and probably somewhere near South Dakota. I hope you can find it.
When you multiply 48,000 wells times an average EUR per well of 500,000 BOE, you get 24 billion BOE. Where is the "wild-eyedness of this estimate?
Well, the wildness is involved in the 48,000 wells with 500,000 BOE each. I can believe that you might be able to drill some wells and recover 500,000 BOE from them, but I have serious doubts whether you can drill 48,000 wells and recover 500,000 BOE from each and every one. We'll see, but it sounds unlikely. It involves drilling two wells per square mile in an area the size of West Virginia. At a rate of 2000 wells per year, it would take 24 years to do it.
Do you believe in Peak Oil or something? You do seem to have about the same grasp of all the relevant facts, as most of the true believers do.
It's not a matter of faith, it's a matter of geology and mathematics. It's mathematically provable that if there is a finite amount of oil in the ground, and you use oil every year, eventually you will use it all up. If consumption increases on an exponential curve, then eventually it will hit a point where you are not able to find oil as fast as as you are consuming it, and a peak will occur. After that, production will decline because most of the oil has been found and there are fewer places left to look for it. Most likely you will not run out of oil all at once, but production will approach zero asymptotically.
If you generate a production curve for this, it will most likely be bell-shaped, and in my experience most oil fields follow a bell-shaped production curve. It is highly likely that global production will follow the same type of curve.
People who think oil can last forever at exponentially increasing rates of consumption are naive. It's mathematically impossible.
By the way North Dakota is located somewhere to the south of Canada, and probably somewhere near South Dakota. I hope you can find it.
I can probably find it, I have relatives living there. It's much like Southern Saskatchewan, except drier, and with fewer people.
The Bakken Formation is in the Western part where it's really dry and empty. I've been in an awful lot of places that are just like it and also have oil. I've paid my dues and I'm not going to go there just for a vacation.
North Dakota - Tourism
I'm sorry, I don't make these things up, I just copy and paste them.
Rocky,
"It involves drilling two wells per square mile in an area the size of West Virginia."
[edit]
The state of West Virginia has a surface area of 24,231 square miles. If you put two wells per square mile, then yes, you would have about 48,000 wells. Good comparison. But, why bring West Virginia into the argument? Why not use the same area of the Bakken, that the estimate originally comes from? The area of the Bakken that this 24 billion BOE estimate is based upon is only 14,671 square miles, which is also less than 7.5% of the total Bakken area of 200,000 square miles. It involves drilling a total of 8 wells per spacing unit of two 1 square mile sections, in two different zones of the Bakken. I don't know how many times that information has been posted on this thread so far, but I'm sure getting tired of posting it. And, other people are also posting it.
Your skill in math just might be able to help you come to the conclusion, that there must be 7,335 spacing units with 8 wells per unit, which would then mean 58,680 possible wells for this area, producing on average 500,000 BOE, or a total of 29,340,000,000 BOE. But the estimate says only 24 billion BOE. Why? Because not all of this area has been 100% de-risked. This has also been extensively discussed on this very thread. As about 4,000 wells have already been drilled, there is just 44,000 more wells to go. It will take as long as it takes. All estimates were based upon the going well production data at that time, which indicated an average EUR per well of 500,000 BOE.
Since that time Oct.12th, 2010, the average EUR per well has gone UP to 603,000 BOE, a 20.6% increase. Why? A better understanding of geology, and better fracking techniques. Ever hear of Super Fracking? You really are quite the expert in modern day oil production, aren't you. And you are really quite up to date with the going Bakken EUR rates aren't you. You really do know a lot about the Bakken, don't you. So, you brilliantly doubt the possibility of 48,000 wells being able to produce an average of 500,000 BOE per well, when they are already outdoing that rate, by 20.6%, but you offer no data at all for your BELIEF. Why don't you just educate yourself instead, and just leave your FAITH out of your equations? It is not at all unusual to have Bakken wells with 900,000 EUR's, these days.
Everything is finite on this planet, including the planet itself, and you think you need to prove this mathematically? Oil in the year 2012 means All Liquids, a very mixed bag of some very curious items. Peak Oil implies imminent Peak Oil, or else we wouldn't even be talking about it. What is the exact date of this imminent Peak Oil, that you say is not a matter of faith? If it is indeed a matter of geology and math, then go ahead, make my day and present your case. By knowing the geology and the math, that means that you can very accuratly figure out the exact date of this imminent Peak Oil event. And, if you can't do this, then don't bother speaking all that Peak Oil garbage to me.
What is the basis for your average Bakken EUR?
Parshall and Sanish Field may recover 500 mbo/section. This is the sweetest of sweet spots. Parshall peaked in 2008 and Sanish peaked 11-'10.
To put this into perspective, Sanish and Parshall combined have recovered about 0.118 Gb.
ND's 2011 Bakken production is estimated at 0.117 Gb.
Cumulative Bakken production for all the ND Bakken is 0.335 Gb.
Operators have a long haul to get to 1.0 Gb. So it is early to say the Bakken will recover the USGS estimate, let alone A Pie-in-the-sky.
ND's 2011 Bakken production is estimated at 0.117 Gb.
average daily production per ND:
11 Jan 343,196
Feb 349,218
Mar 360,097
April 351,228
May 363,548
June 384,811
July 424,992
August 446,397
September 463,888
October 487,726
November 509,754
December (est) 509,754
total .151919 GB
You are quoting total ND production. The NDIC quoted November Bakken production at 443,000 bpd. 2011 prodution for the Bakken will be available here about March, 2012.
https://www.dmr.nd.gov/oilgas/stats/2010Formation.pdf
Still a long haul to 1 Gb, an epic voyage to 4 Gb and a moon shot to 24 Gb.
Hamm arrived at his number by multiplying one WAG times another WAG to arrive at an unrestrained WAG. A Hammsays away from reality, imo.
The North Dakota Geological Survey doesn't seem to have made up it's mind:
"Price also states that 50% of this oil is recoverable (on average, 200 billion barrels of oil). The model as presented by Price in this paper appears solid. Considerable input was given to this paper by North Dakota Geological Survey geologists concerning the geology of the overall geology of the Williston Basin and specifically the Bakken Formation. In addition to samples collected for analysis from the ND Geological Survey Core and Sample Library, Price used the well files from the Oil and Gas Division extensively. This data and the considerable input from staff geologists adds to the credibility of the geological portion of the model."
https://www.dmr.nd.gov/ndgs/bakken/bakkenthree.asp
The big question is not only how much was generated, but how much remains in the Bakken. Price seems to have wanted all the oil that happened in the Bakken to stay in the Bakken. Price used two very doubtful assumptions 1) that the fractures in the bakken are horizontally oriented and 2) that faults are rare in the Williston Basin.
1) Fractures, natural and hydraulically induced, are oriented perpendicular to the plane of least principal stress. Except in areas of compressional stress and in very shallow reservoirs, least principal stress will be vertical and fractures will be vertically oriented. Areas subject to compressional stress are rare in the Williston basin, the WB is a failed rift- predominately extentional not compressional.
2) I have no idea how price arrived at that conclusion. The intersection of a vertical fault with a vertical well are rare. One consequence of all the horizontal drilling is that the laterals cut many, many vertically oriented faults. An entirely different picture is unfolding.
The cartoons presented by Continental Resourse showing radial fractures is bogus. I believe that cartoon was originated by Brigham exploration and borrowed from Brigham by Continental.
Estimates of recoverable oil from oil in place are essentially meaningless in the Bakken. Natural fractures account for nearly all the movable oil in place and a small fraction of reservoir volume. The nanodarcy permeability matrix rock contains most of the oil in place and very little moveable oil. The estimate or 500 mbo are based on volumetric calculations, not on performance.
Still a long haul to 1 Gb, an epic voyage to 4 Gb a moon shot to 24 Gb and a Mars shot to 100 Gb (or whatever).
Notice that Hammsays is usually delivered from behind the curtain of boilerplate thick disclaimer. I wonder how Hamm gets away with quoting his figures, in an interview for example, without first issuing that disclaimer. Hamm is probably in violation of SEC regulations.
Banned,
"The estimate or 500 mbo are based on volumetric calculations, not on performance."
Here is the most recent average well performance for some of the biggest players in the Bakken. These are all EUR figures. Company names are left out per request of TOD. As this is recent, the data has obviously been collected AFTER the date of the original estimate, and thereby cannot be used as evidence against your assertion, but is intended to provide readers with at least a look into what is going on in the Bakken right now. Some of this data,(probably some of the lowest EUR's)come from areas outside of the estimate area, (I think.) One company's data was left out, as the wording of it's EUR's could have been misconstrued as an average EUR of the whole Bakken.
Readers must then somehow extrapolate this information backwards to October, 2010, in any attempt to use it in the original estimate of 500,000 BOE. Extrapolations of data are well known to be extremely untrustworthy. Be careful out there.
Dunn County leasehold: 800-900 Mboe
Koala (NE McKenzie County): 800-900 Mboe
Smokey (South of Koala): 750-850 Mboe
Polar (SE Williams County): 800-900 Mboe
Grizzly (SW McKenzie County): 350-450 Mboe
Hector/Ajax (NE Dunn): 498 Mboe
Aenaes/Myrmidon (SW Mountrail/NW McLean): 577 Mboe
Indian Hills (North to NE McKenzie County): 787 Mboe
Hebron (Richland County): 600 Mboe
Red Bank (West Williams County): 450 Mboe
South Cottonwood (West Mountrail): 675 Mboe
North Cottonwood (SW Burke): 500 Mboe
St. Croix (West Burke): 400 Mboe
Rough Rider: 700 Mbo
NE Dunn/SW Mountrail/SE McKenzie counties: 725 Mboe
South Divide County: 440 Mboe
Fort Berthold (SW Mountrail): 900 Mboe
SW Williams to N McKenzie: 550-300 Mboe
Mountrail County: 250-500 Mbo
Richland County: 250-400 Mbo
Fort Berthold (NE McKenzie/N Dunn): 600-800 Mboe
Sanish Bay (SW Mountrail): 500 Mboe
Westberg (NE McKenzie): 500 Mboe
Average throughout play of 603 Mboe
Lewis and Clark (SW McKenzie): 300-500 Mboe
Sanish-Bakken (Mountrail): 950 Mboe
Sanish-Three Forks (Mountrail): 400 Mboe
Hidden Bench (North McKenzie): 600 Mboe
Tarpon (NE McKenzie): 900+ Mboe
Cassandra (SE Williams): 900+ Mboe
North Fork/Nesson (E McKenzie): 500 Mboe
North Stockyard (South Williams): 400 Mboe
Roosevelt Bakken (Roosevelt County): 300 Mboe
Roosevelt Three Forks (Roosevelt County): 200 Mboe
NW Williams County: 350-500 Mboe
E Richland/E Roosevelt counties: 350-500 Mboe
Mountrail County: 400-600 Mboe
Parshall Bakken: 816 Mboe
Lewis and Clark Three Forks: 500 Mboe
Billings Nose (Elm Coulee/S McKenzie): 200-250 Mboe
Bakken: 500 Mboe
E Divide and W Burke counties: 350 Mboe
Don't you mean forecast ? Do you have cumulative performance for the wells in your list ?
banned,
Yes, you are correct of course. This was the most recent EUR per well FORECAST, based upon all the most recent well PERFORMANCE. Some orientation: this information is pulled out of a recent article from a recent series of articles regarding the relationship between Bakken EUR rates and IP rates to try to determine the level of risk involved for investors, who perhaps foolishly only rely on high IP rates. I can't copy any company specific information here at TOD, so you need to be careful to not misinterpret anything. It is possible that this is being presented out of context, but it is not intentional on my part. I don't know about the cumlative performance, but I can check. The small group I am working with now is trying to better pin down EUR rates. The author only works off of company information, and trys to leave his own predictions out of the story. Here is some more from that article, so the following are not my words, so I am not responsible for them, and I usually do not source such information from mere individuals:
"This article covers estimated ultimate recovery or EURs. This is the amount of oil and gas expected to be economically recovered from a reservoir by the end of its producing life. Take these numbers with a grain of salt, as EURs can vary significantly based on operator and the analyst modeling."
"Here are different estimates compiled by oil producers in the Bakken. Remember these estimates differ in location, and some estimates are for the upper Three Forks which is a little deeper than the middle Bakken. These estimates are garnered from a combination of the geology in the area, plus the producers' ability to extract the resource. Estimated Ultimate Recovery or EURs are produced through initial production rates and show how much oil equivalent that should come from each location."
"IP rates are used to find EURs. The total number of days a well is in production is important. A well that is choked back more will produce less in the first 24 hours. After 90 days of production the rates generated from both wells level off. Longer term production rates reduce the level of error, and are more appropriate in determining estimated ultimate recovery. The only way to be sure as to the accuracy of EURs, is to study each company's results to get a baseline. The area of these wells is also important, as various geological differences could affect longer term numbers. Drilling and completion techniques can also change IP rates. Length of laterals, number of stages, and amount of sand and/or proppant can all effect estimated ultimate recoveries. Realize that a poor outcome in an area does not mean the whole field will underperform, it may just be due to a producer's learning curve."
Here is an excerpt from some analysis I did a few months ago. I don't believe the Bakken will average more than 250 kb/well eur. Also consider that the best sweetspots are being drilled now, and that the actual producible area is a small fraction of the total geographic area. 48,000 wells is very unlikely. even 1/2 that is probably unlikely. Optimistically youyr 24 Gb might be 6 Gb.
Bakken published data vs modelled EUr shoes major inconsistencies.
Brigham’s average production of 1800 b/d for the first week, 1100 b/d for the first 30 days, and 830 b/d for the first 60 days falls on a smooth curve that includes CLR’s 450 b/d for the first 90 days. This curve implies a production rate of 90 b/d at the end of the first year, only 5% of the first week’s average production rate.
If we take a production rate at the end of the first year of 100 b/d, declining to zero at the end of the 10th year, we have 165 kb for those 10 years. Add in the 75 kb from the first year and we have 240 kb EUR. This is a long way from the 300 to 400 kb EUR projected by CLR in their EUR vs frac stages chart. Their median EUR projection seems to be about 360 kb which is still high vs the decline curve, but much lower than the 518 kb they have modeled. Very strange.
I have tried curves using the 30, 60, and 90 day average rates as end of period rates, or as average for each of the first, second, and third 30 day periods instead. Thus I have a range of EURs from 240 to 410 kb, with a middle value about 340 kb. However the low end is the one consistent with both companies’ real wording. The safest EUR number to use is probably 250 kb/well.
Do you have any idea whether the North Dakota Geological Survey has addressed any of that?
I'd be curious to know what you think of their language in that report?
banned,
"Hamm arrived at his number by multiplying one WAG times another WAG to arrive at an unrestrained WAG. A Hammsays away from reality, imo."
I have presented you with Hamms methodology. It is up to you to disprove him, or agree to it. Instead you are attacking him pesonally, because you know you can't disprove his methodology. You are thereby admitting defeat in this matter.
From Wikipedia, " if you can attribute a bad trait to your opponent, others will tend to doubt the quality of their arguments, even if the bad trait is irrelevant to the arguments."
Well data is not considered to be Wild Ass Guessing.
How about if you prove 500,000 barrels X 48,000 locations is not WAG X WAG ?
banned,
Glad you answered. This post got misplaced by me, but let's just take it from here. My first reaction is, this is a little like proving the sun is shining, when it is. Sometimes that can be difficult, but it also depends on who you are trying to prove this to. So, I could say, just open your eyes, then you have all the proof you need. I think the burden of proof is on you. That is, I think you need to either disprove this, or accept it. I think I have explained this formular many times over at this thread. But here is an edited explanation from a still unpublished article I have written.
"In North Dakota the surface area of the Bakken is broken down into sections of one square mile each, or 640 acres. Under the leases they have signed, oil companies can then hold (by production) two sections at a time typically on a North-South axis, which are then called, "spacing units" of 1280 acres each. This can be done by drilling just one horizontal well, that traverses both these sections, (one spacing unit) in either of the Middle Bakken or Upper Three Forks zones. Secondary to holding the acreage under lease, is that in exploratory areas, this practice is also known as de-risking. Later, when more time is available, oil companies can come back and drill the remaining wells in a de-risked area, which then ups that area's classification to fully developed. That means drilling a total of 8 wells, (4 in each zone), to fully develop each spacing unit. This means, that each section undergoes a three step transformation process from unexplored, to de-risked, to fully developed."
"What determines the number of wells drilled in any given zone is the nature of the oil saturated rock in that particular geological formation. It is believed that,(in most cases) the optimum spacing for the most effective draining of the oil in place, will be best achieved by spacing the 10,000 foot laterals 1320 feet apart, hence the planned 4 wells per zone, per spacing unit, which results in a final spacing of 320 acres per well for each zone. The most effective way to drain both these two zones is to drill a north south oriented Middle Bakken well, and then step over to about 660 feet east or west and drill an Upper Three Forks well in the same orientation, and then step over another 660 feet and drill the next Middle Bakken well, working your way out across the whole play. This original 4 wells per zone plan, however, now needs to be understood within the greater context of the recent discovery of multiple zones of oil saturated rock in the Lower Three Forks Formation. The more zones discovered, obviously the more wells will be needed to eventually fully develop each SURFACE spacing unit. As, companies plan to access all these lower formations with the same 10,000 foot laterals staggered at 660 feet apart throughout each zone, it's quite obvious that they have had this Bakken play pretty well figured out all along."
The rest is not from my article, but just out of my own head. Therefore, I can not be so sure that everything is 100% true.
The 500,000 EUR number is derived from all available well data from that time. This number is arrived at by comparing various average rates of oil production from as many wells as possible, over various time lengths. Typically 30,60,90 day rates for newer wells, and up to several years for the older wells. There aren't very many old wells in the Bakken. These are then compared to oil well results from various other plays, that are considered to likely give the same type of results, as the Bakken is expected to give. In other words short term Bakken well production, is then modelled after whatever long term (30 year) production model fits it best.
If for example, Bakken wells suddenly started declining much more than their model did, then that model would have to be thrown out, and a different 30 year model would have to be used, which showed a decline rate more similar to the suddenly declining Bakken rate. This of course would lower the EUR. But, the opposite, in theory anyway, could also happen, where the EUR model would be exchanged for one that was higher, if Bakken wells did NOT decline as fast as their models did. This would result in a higher EUR. This all comes under the heading of methodology, and you'll find it in all resource extraction plays.
But, it gets tricky because not all these wells are the same. The biggest wild card is the number of fracs, because that will always be low for the older wells, and high for the newer ones, as the companies move up the learning curve. The results from the two separate zones are also modeled on two different models, but the results are then mixed together and averaged, proportionally. There are more than a few other minor twists to all this, but I believe that this gives you the main picture.
It is obviously not an exact science, and no one can really prove, or disprove, the results. These are after all, only estimates. But, you can take issue with the whole process, the methodology, if you like. The only purpose of this whole EUR exercise is to signal to all the other related industries, like pipelines, how much pipeline will likely be needed, and when. It is not meant to prove or disprove Peak Oil theory, but that's probably how you see it.
I might have some more on this, tomorrow, and you are welcome to respond to this part already, but I've got to go. Just keep hanging in there. We will reach the end someday.
November Bakken per NDIC was 510k bbl per day.
https://www.dmr.nd.gov/oilgas/stats/historicaloilprodstats.pdf
You are quoting ND total production which includes all 28 'pools'. The NDIC reported November Bakken production at 443,000 bpd by press release. 2011 annual prodution for the Bakken and 27 other pools will be available here about March, 2012.
https://www.dmr.nd.gov/oilgas/stats/2010Formation
westexas,
I think the NS vs. Global graph needs another line - the price/barrel to show that the cost of continuing the plateau the black line is on - that would bring it home for those who can't imagine the incredible cost of continuing our oil-induced dream world.
Think of the billions of dollars spent by the global oil industry globally for 2006 to 2011 inclusive, with no material increase in global crude oil production, and with a measurable and ongoing decline in Global Net Exports.
The best technology may well be available but that does not mean it necessarily gets used when it produces more expensive product than the cheap oil pulled out of the Middle East, especially when Middle East production could be increased rapidly at will to swamp demand. The Middle East no longer appears capable of swamping an ~85 mbbl/day demand with cheaper oil than can be produced in the US.
Also, you're seeing this in the last couple of years?
Curiously enough, the Texas RRC shows significantly lower numbers for annual Texas production, less than one mbpd in 2010, in much the same way that the EIA is showing higher numbers for Saudi production than what other sources show. And note that the absolute production peak in Texas was about 3.5 mbpd in 1972.
Having said that, Mid-continent US crude oil production has clearly rebounded, but the fact that oil companies can and will make money by putting new fields on line and by increasing the recovery in existing fields does not necessarily mean that they can make a material difference. And if we look at total US crude oil production, it looks like the net increase in 2011 will be about 100,000 bpd, with about 1,000 drilling rigs drilling for oil, or a net increase of about 100 BOPD per year per rig. I call this making an incremental difference versus a material difference. A case in point is the North Sea, where new fields put on line in 1999 or later had a production peak of about one mbpd in 2005, but the new fields only served to slow the overall rate of decline in total production.
Incidentally, I would also note the decline in oil production per well in Texas, versus the early Seventies (from 21 BOPD per well in 1972 to 6 BOPD per well in 2010), which is the same pattern that we see in natural gas.
And the following post has a longer term look at total US crude oil production:
http://www.theoildrum.com/node/8859#comment-867458
But the key point is that what is driving the Lower 48 renaissance--and the approximate 100 BOPD per year net increase in US oil production per rig--is a happy confluence of higher oil prices and improved technology. The higher prices are due to flat global crude oil production since 2005, along with an ongoing, and I suspect, accelerating rate of decline in Global Net Exports (GNE) of oil. I suspect that the average volumetric decline in Available Net Exports (GNE less Chindia's net imports) could accelerate from the one mbpd per year decline that we have recently seen to around two mbpd per year from 2010 to 2020.
So, yes selected areas are showing increasing production, e.g. the Mid-continent area in the US
But, when we look at the net US increase, it was about 100,000 bpd in 2011 (through October, 2011).
This slow rate of increase in US production helped, but global crude oil production has been flat since 2005*.
Meanwhile, GNE (total petroleum liquids) have fallen at about 1.3%/year since 2005
And ANE have fallen at about 2.8%/year since 2005.
So, producers who are able to maintain and increase their production are doing great, but the bottom line is that global crude oil prices have doubled since 2005, from $55 in 2005 to $111 in 2011. If you are a consumer, what numbers should you focus on, rising Mid-continent production or the recent doubling in global crude oil prices?
My guesstimate, and Art Berman concurs, is that at least 90% of the shale wells currently producing oil will be plugged and abandoned or down to 10 BOPD or less by 2020. If you guys prefer to believe the industry story line that wells like this will make a material difference to consumers, all I can say is that you were warned.
*Total liquids, inclusive of low net energy biofuels, did show a material, but quite small, rate of increase of 0.5%/year from 2005 to 2010 (EIA).
westexas,
"My guesstimate, and Art Berman concurs, is that at least 90% of the shale wells currently producing oil will be plugged and abandoned or down to 10 BOPD or less by 2020."
The average Bakken well with a 500,000 BOE EUR is expected to produce for about 30 years. This results in a daily average of only about 46 BOE per day per well. But, average Bakken EUR's are always going upward as new wells with better technologies come on line. CLR presently uses 603,000 BOE for all their estimates. That pushes the number of years upward toward 35 years. Many other companies use even higher EUR's. CLR is actually VERY conservative in all their estimates, which is also why I almost exclusively refer to them. There is no pie in the sky in their numbers, believe me.
Why don't you access your information from the companies on the ground doing the work, like I do? Then you don't have to "guestimate" at all.
About 200 wells are getting drilled there a month these days, so don't forget to factor them in as well. As, the daily oil production also increases by about 15-20,000 barrels a month, because of all the drilling, it hardly even matters what the fate of the currently producing wells actually is, so I have no idea of why you even bother to mention it.
[ed]
Many other companies use even higher EUR's. CLR is actually VERY conservative in all their estimates, which is also why I almost exclusively refer to them. There is no pie in the sky in their numbers, believe me.
This may come as a total shock to you, but companies have been known to fudge the numbers. In fact, I have worked for such companies and been involved in the number-fudging process. It can be quite subtle because in reality you never have all the facts and reserve estimates are a judgement call. Usually a queasy feeling in the pit of your stomach is your first indication that things are going south. By the time the bad news becomes official, the insiders have already dumped their stock and your stock options are underwater.
But back to the oil company estimates - I'd prefer to look at the raw geological and production data, and have an independent consulting company check the calculations. And even then you're never sure.
As for the Bakken - I suspect the decline rate on the new wells is going to be rather steep, but I'd prefer to wait a few years to commit myself to a long-term trend.
RockyMtnGuy,
Yes, the "E" in EUR, stands for estimate, not exact. It cannot be otherwise because of the length of time the wells are EXPECTED to produce, versus the length of time they have ACTUALLY produced.
The decline rates of bakken wells are not, "going to be steep." THEY ALREADY ARE STEEP! And, are likely to remain steep, although some progress has been made flattening them out. The decline curves are the hole in the doughnut. When you turn them upside down you get the cumlative curve, which is the doughnut. Why is everyone on this site so obsessed with doughnut holes, when the only real issue here is the size of the doughnut (The total amount of oil production per day). The bigger the doughnut,(when scaled up) the bigger the doughnut hole. End of story.
I, too look mostly at the raw geological and technical data. And, the most important statistic out there to watch is the average daily rate of production per Bakken/Three Forks well, as this takes into account ALL the ongoing decline rates of ALL the Bakken/Three Forks wells. It is presently (from November, 2011) 142 barrels of oil per day. In comparison just seven years ago, (November, 2004) production was only 9 barrels of oil per day. A 500,000 EUR Bakken well is expected to produce for 30 years at a rate of 46 barrels of oil per day. See if you can figure out what is really going on. Decline rates are obviously not a problem. Anyway, no one in the industry is complaining! Only Peak Oilers. Go figure. Why worry? Be happy.
A 500,000 EUR Bakken well is expected to produce for 30 years at a rate of 46 barrels of oil per day. See if you can figure out what is really going on. Decline rates are obviously not a problem.
Decline rates are THE problem. If you have a well with an initial production rate of 1,000 bpd and a decline rate of 80% per year, after 1 year it will be producing 200 bpd, after 2 years it will be producing 40 bpd, after 3 years it will be producing 8 bpd, after 4 years it will be producing 1.6 bpd, and after 5 years it will be producing 1/3 bpd. (Assuming an exponential decline curve, which is typical).
It will not produce 46 bpd for 30 years.
Of course you can refracture the well and boost production to say, 200 bpd, but then you are back on the exponential decline curve (40 bpd; 8 bpd; 1.6 bdd). You can refracture it again, but you will restart at a lower point on the decline curve. Eventually it will be uneconomic to refracture it, so you will run it as a stripper well until it no longer pays its costs, and then you will abandon it.
That is why Westexas says, "At least 90% of the shale wells currently producing oil will be plugged and abandoned or down to 10 BOPD or less by 2020."
At this point the well has recovered nowhere near its hypothetical 500,000 barrels of oil, so you have to drill an infill well near the first, frac it, and start over - but then you are back on the decline curve again.
So, imagine you have thousands of these wells, all of them in steep decline. You have to drill thousands more to increase production. Soon, you have tens of thousands of wells in steep decline, so you have to drill tens of thousands more to increase production. At some point in time you just can't find enough money to drill enough wells to increase production, and then you find yourself on downslope of the classic Hubbert bell-shaped production curve, which, unbeknownst to you, you have been following up until that point.
Now, keep in mind, this is not totally hypothetical. I used to design computer software for an oil company to predict future oil production. We had a $1 billion budget to play with, and it was a depressing experience when we hit the downslope of the bell curve, because by that time we had tens of thousands of employees, and most of them eventually found themselves out on the street looking for employment elsewhere. The company was taken over by a bigger multinational which was still on the upslope of the Hubbert curve, but I think it has pretty much reached the top, too, and is now in trouble.
An EUR of 500,000 divided by 30 years = 16,666.66. 16,666.66 divided by 365.25 days = 45.63, rounded up = 46 bpd
apparently you missed Rocky's point--he is claiming the 500,000 is a bogus number--not that what you calculated from it is wrong. Another decade of production and we will have a much better handle on what the real EUR is, it isn't worth arguing about now. Let's just hope the Bakken can reach and hold 1 mbpd production in the next few years. I haven't seen any plans for trying to deliver more than that any time in the next decade. The North Slope is fast approaching the 1/2 mpbd mark--down from the 1.8 mpbd it held at for several years--long way to go before Dakota/Montana make up that decline.
We will see what sort of effort it takes to maintain 1mbpd when it gets there--at least there is the potential for it to be maintained for quite a long time--flat production for thirty years at that level would be a very good thing. Who knows, the source rock on the North Slope could prove a Bakken style money maker with oil prices north of $100/barrel. Lots of ifs. Of course if things get out of hand and Hormuz shuts down...well strategic petroleum reserves won't last that long...like I said lots of ifs.
Luke H,
If Rocky is "claiming the 500,000 is a bogus number," then he forgot to include the data that backs up his claim. So, how am I supposed to know what his point even is? No, it's not worth arguing about now. Why doesn't everyone just do their research instead? Then we can all agree on such matters. Everyone just has to AGREE to do the research, first. Can you figure out where the problem actually is, and how to solve it?
granted there was no data but the reasoning was clear
At this point the well has recovered nowhere near its hypothetical 500,000 barrels of oil, so you have to drill an infill well near the first, frac it, and start over - but then you are back on the decline curve again
If the well has recovered nowhere near its hypothetical 500,000 barrels of oil before a new infill well had to be drilled, the original prediction, the hypothetical 500,000 barrel EUR was bogus. Remember, Rocky had mentioned the unreliability of EUR numbers in a post upthread earlier.
Many of us here don't take the EUR numbers bantered about by stock selling companies and many other entities at face value. I'm not going to invest in ND so I'd rather take the slightly longer view and wait for a decade or a dozen years high production numbers to be on the books before I decide whose numbers are most accurate. I'm a bit risk averse by temperment...which is why I have time to sit and type this out right now. You of course are free to do your own analysis and 'publish' your conclusions on these boards, but we are equally free to question the reliability of the numbers being pitched to start with--we can doubt a general class of numbers bantered about because of our experience with similar type numbers in our past. We call that bringing 'the school of hard knocks' point of view to the discussion--or at least we used to, that phrase might have gone out of use. Glad this discussion got down to a slightly more civil tone anyway. I'm as guilty as any for letting my blood get up some...fortunately I've generally had time to quickly civilize my post before someone locks it in with a reply.
I read your posts thus far, which means so far I do value your point of view...good enough for public boards in my opinion...which like yours and that of many other posters here is not exactly a a humble one...
Luke H,
Rocky's reasoning on just about any subject is usually not at all clear to me. Therefore, I do have to do a lot of guessing, and make a lot of assumptions. I'm still trying to crack Rocky's code of understanding, but don't really feel that I've made any progress. I have experienced the same with several other members. I know what's behind it all, but don't choose to broach the subject.
"At this point the well has recovered nowhere near its hypothetical 500,000 barrels of oil, so you have to drill an infill well near the first, frac it, and start over - but then you are back on the decline curve again"
"If the well has recovered nowhere near its hypothetical 500,000 barrels of oil before a new infill well had to be drilled, the original prediction, the hypothetical 500,000 barrel EUR was bogus. Remember, Rocky had mentioned the unreliability of EUR numbers in a post upthread earlier."
I'm sorry, but I have no idea what any of this is about, or where it comes from, or what it is related to. So, I cannot comment on it.
Almost all data I quote is company data. You only have to go to these same company websites to verify their data. The only problem here is that most people don't access company data, and thereby don't verify it either. They just deny it, because that is much easier for them to do. So, it's actually not a disagreement going on here at TOD. Apparently, no one at this site is even informed enough to disagree with me, because no one else even uses the same company data, that I do.
So, it's really just an ongoing exchange of words between someone who is informed, and various others that are not. It's a classic knowledge (knowing) versus ignorance (not knowing) struggle. That's why I keep telling everyone to educate themselves. When that occurs, all arguing will stop, as every reasonably minded person will then be in agreement with me. Then true learning can begin.
It is impossible for the human mind to learn anything when it operates in a condition known as bias. It will only seek confirmation of it's own bias, in order to strengthen it. This is based upon a psychological state of mind known as deep insecurity. Victims are then sought to overwhelm with aggresive bullying tactics, so the insecure one will then feel superior, and thereby secure. It's all grounded in feelings of low self worth, a lack of proper identity, and fear of truly knowing one's own self, or others.
If you doubt any of this, then why not take a look at all the exchanges between myself and those who do not even use their real name, compared to my exchanges with those that do. Then, you might become flabbergasted about how easy it is to understand, what is actually going on at TOD, these days. Coffee anyone?
I'm still trying to crack Rocky's code of understanding, but don't really feel that I've made any progress. I have experienced the same with several other members.
There's a lot of inside knowledge in what I say on this site, and if you don't have the oil industry background, you won't understand it. It's not in oil company financial statements. There are a lot of personal opinions in what I say, but they're based on years of experience, and not all of the experiences have been good - especially for other people.
If you doubt any of this, then why not take a look at all the exchanges between myself and those who do not even use their real name, compared to my exchanges with those that do.
I don't use my real name because, first, I don't want people calling me up and trying to pick my brains. I'm not in the consulting business since I retired and can't charge them for it any more. Second, if they knew exactly who I was they could figure out where I was getting my information from, and I don't want them to know that, either. Third, I'm not really trying to prove anything, I'm just trying to make sure innocent people don't get blindsided by events. If people don't believe me, they can go ahead and believe whatever they want. I just don't want them to mislead other people
Carl Martin
Actually precious few people use their real names on boards like these. To me that indicates the individuals posses a certain amount of good judgment and common sense. Others may have valid reasons for using their own names here--their life's business model may even make that prudent. I wouldn't read too much into that item.
I think that this shows that you have very little experience with estimation of reserves and production decline profiles of unconventional resources. Without going into a terrible amount of detail, I can provide two general maxims for understanding decline profiles. First of all, because shale production is coming from a heterogeneous reservoir with very low permeability, rather than an exponential curve, it is actually the summation of a number of exponential curves of various permeability. The end result is a rate equation generally of the form: q/q0=(1+b(t)*di*t)^(-1/b(t)) where b(t) can range from 0.5 to 4 and is time-dependent and directly related to the deliverability of the induced hydraulic fracture. The annual decline percentage is also time dependent. It would be extremely naive to think that annual decline percentage is constant, especially when wells demonstrate hyperbolic decline profiles. Based on the longest performance of Barnett shale wells, it is empirically known that gas shales follow hyperbolic declines with variable b(t) factors.
Secondly, based on simulator work, wells follow hyperbolic decline profiles where the decline of the well can be thought of as a transient portion with b > 0.5 and a decline into a steady state decline approaching b of 0.5 as t -> infinity.
I left determining what kind of decline curve to use up to the reservoir engineers because that was what we were paying them for. They could plug any kind of decline curve into their projects that they wanted. However a straightforward exponential decline was the default.
In most cases, the reservoir engineers didn't care because the wells were on their way to abandonment and they only estimated declines to humor the Securities and Exchange Commission.
I used exponential decline as a simplifying assumption when I was playing around. It didn't really matter much which decline curve I used for individual wells because the results were very similar. At the end of it all, it was a bell shaped curve for the field.
If they put in an enhanced recovery program, the field would end up with a bimodal production curve (the "Maidenform" curve), which was quite common because they often did EOR to extend the life of fields, but a bimodal curve is just two bell curves superimposed on each other, so it didn't change the overall picture much - it just created a long tail on the overall bell curve. We might see this for global production. At the end of it all it might be a right-skewed bell curve rather than a symmetric one.
The distribution for any naturally occurring resource whether oil/gas/coal/uranium will follow a log-normal curve. This is always the case for any multiplicative process (seal, trap, hydrocarbon, etc.). This can be demonstrated through the use of a monte-carlo simulation with any number of variables.
Keeping in mind that price will affect the shape of the tail. For any single price point for hydrocarbon resources, there is a corresponding log-normal curve. However, with increasing price, the shape of the tail will change. The manner in which the tail changes has not been examined in the same exhaustive fashion that individual field studies have been made.
As an excercise, you may take the hubbert-linearization of a particular field or collection of fields such as Barnett shale gas and you will see that in 2004-2008 there is a massive shift in the slope of the decline implying that the total amount of reserves changed dramatically (over an order of magnitude). This shows that price and technology do have a gigantic change on global reserves.
This goes to show that economics of shale gas is still profitable. While public company valuations may be determined by production and reserve growth, privately held E&P companies are able to generate strong cash flow regardless of sharp declines. However, there is a huge component of PDP that has tremendous residual value despite the fact that at the time of the well being drilled, the value is nearly negligible because of valuation using PV10-PV15.
Pitts,
"Keeping in mind that price will affect the shape of the tail. For any single price point for hydrocarbon resources, there is a corresponding log-normal curve. However, with increasing price, the shape of the tail will change."
I certainly agree, but this is classic Peak Oil Blasphemy!
Peak Oil has NOTHING to do with the effects of above ground factors. It only has to do with below ground geological restraints. So, you MUST ignore the effect of prices on Peak Oil graphs, or else they won't work.
Thanks for making my point for me which I mentioned elsewhere to Westtex. The silly thing just does whatever you tell it to, depending on when you tell it. It makes Yergin's point much better than a peak oilers.
I don't think the method really works for gas reservoirs, and in any case, I don't recall any HL proponents using it for gas.
As we discussed, I think that it provides a useful, and relatively objective method for evaluating producing regions and global (crude oil) production.
And as previously noted, wasn't it quite a coincidence that global crude oil production stopped growing at precisely the point in time that Deffeyes picked, using HL, as the most likely year for a global conventional crude oil peak?
wasn't it quite a coincidence that global crude oil production stopped growing at precisely the point in time that Deffeyes picked, using HL, as the most likely year for a global conventional crude oil peak?
Not really. Deffeyes guessed in 2003 that peak had already happened in 2001, and predicted that production would fall in the coming years. If that had turned out to be the case, he could have claimed credit for a good "pick". But, it didn't happen, so he went on to choose later years as the peak. If you keep on making new predictions until it happens, you aren't really predicting.
And, of course, it's worth noting that he predicted a peak, not a plateau (which could be fairly long).
This is a common thing: humans have a built-in vulnerability to seeing patterns of cause and effect that aren't really there. An example is Jeanne Dixon: in the 1950's she made dozens of predictions each year, all wrong. Finally, in 1963 she made a prediction that could be interpreted to predict Kennedy's assassination, and she found fame.
Another example of a selective data choice: Hubbert did well with domestic oil. OTOH, he tried to make a similar prediction in the late 70's that nat gas would fall off a cliff in the 80's. That didn't happen, so the prediction was forgotten. On the other hand, the oil prediction succeeded, so that was remembered.
Hubbert also called peak natural gas for the US in the early 70's. It is not considered polite to know (or mention) facts contradictory to the website message however.
Bruce, do you happen to have a link for that, for future reference?
Hubbert also coincidently managed to get a rate/time prediction correct. Once I believe. It would seem to me that any method upon which we predicate the fate of the human race should work just a WEE bit more often.
While Pitt did make an interesting post which gave me a lot to think about, it didn't change the fact that there is a peak in the curve. We are just discussing what the shape of the tail on the curve is. If in fact the curve has a fat tail, that is favorable for the consumers of the world since it means production will decline a lot slower than otherwise.
However, it doesn't change the issue that there is a peak and a steep decline shortly thereafter. It just makes for a much softer landing at the end. The Doomsters will be disappointed by this, but nobody else.
And economics has a great deal of effect on the curve, it's just that the economic assumptions are unstated in the usual discussion. In fact, the economics ensure that demand will always equal supply in the equations, regardless of how low supply is. There will be not a case in which there is not "enough" supply to meet demand, unless governments intervene and try to make the system do something that is impossible.
Rocky,
Are you a TRUE BELIEVER in Peak OIL or not??? Peak Oil has NOTHING to do with economy, Nothing, ABSOLUTELY NOTHING! It only has to do with below ground geological restraints. You can't have it both ways, so you might as well give up trying.
Another important maxim: Forecasting based on decline curve analysis is only valid if the reservoir mechanism in the history phase continues in the future.
Bakken oil is a volatile oil.
Recovery of a good part of the oil will probably depend upon an ability to effeciently pump this gassy crude. These wells are not easy to pump, owing to the depth, temperature, occasional sand production and the 'horizontal' lateral.
Many wells, on pump, are reporting a small amount of gas flared or vented each month. The operators are 'unloading' these lateral by opening the casing to the atmosphere. It appears the operators are able to 'surge' oil and water from the undulating lateral.
And I have more shocking news ! The producing mechanism at Parshall and Sanish is gravity dominated.
I have heard of 1000bpd wells coming on-line -- those would have been "good" 20 years ago, and are very good today. Companies I hear say they will be there 20 years, when looking for office space investments and such.
All anecdotal, but some of these wells are pretty good. Give it a few years and the picture will be a lot clearer, though.
westexas: Discussing Peak Oil at the Oil Drum is like preaching to the choir. I suppose it's not without some beneficial effect since the news media probably reads the Oil Drum but evidently the message still hasn't gotten through. I would recommend speaking at colleges and universities to broaden the audience, but Peak Oil is such a dismal, bad news story I doubt people will be receptive to the message. In the final analysis nothing short of survival will motivate people to deal with Peak Oil. Of course, at that point it will that much harder to address but life is never simple.
It's not so dismal.
We don't need oil - we need to kick the FF/oil habit ASAP.
Maybe that "kicking" hasn't happened much yet - despite high prices - because in actual practice it's often easier said than done?
Actually, it's happened many times before.
• 130 years ago, kerosene was needed for illumination, and then electric lighting made it obsolete. The whole oil industry was in trouble for a little while, until someone (Benz) came up the infernal combustion engine-powered horseless carriage. EVs were still better than these noisy, dirty contraptions, which were difficult and dangerous to start. Sadly, someone came up with the first step towards electrifying the ICE vehicle, the electric starter, and that managed to temporarily kill the EV.
Now, of course, oil has become more expensive than it's worth, what with it's various kinds of pollution, and it's enormous security and supply problems.
• 40 years ago oil was 20% of US electrical generation, and now it's less than .8%.
• 40 years ago many homes in the US were heated with heating oil - the number has fallen by 75% since then.
• US vehicles reduced their fuel consumption per mile by 50% from about 1978 to about 1990.
• 50% of oil consumption is for personal transportation - this could be reduced by 60% by moving from the average US vehicle to something Prius-like. It could be reduced by 90% by going to something Volt-like. It could be reduced 100% by going to something Leaf-like. These are all cost effective, scalable, and here right now.
I personally prefer bikes and electric trains. But, hybrids, EREVs and EVs are cost effective, quickly scalable, and usable by almost everyone.
• As Alan Drake has shown, freight transportation can kick the oil-addiction habit relatively easily.
We don't need oil (or FF), and we should kick our addiction to it ASAP.
The only reason we haven't yet is the desperate resistance from the minority of workers and investors who would lose careers and investments if we made oil and other FFs obsolete.
(1) I meant this time around, not 30, 40, or 130 years ago. Past performance does not guarantee future performance.
(2) properly street-legal hybrids may be cost-effective for some people, but that "effective" cost is high and largely front-loaded; this is not well-matched to an uncertain economy. EVs may be cost effective, with the same limitations, but only as secondary vehicles for shorter trips, since charging-station infrastructure mostly isn't out there. But in today's economy many people are already having more than enough with their primary vehicles.
(3) bikes have uses, but much of the USA experiences something called "winter", which involves substances such as "snow", and, worse, "glare ice" and "black ice". Few people are or will be willing to use bikes in "winter". Indeed, come to the Berkeley of the Midwest right now and you can have the considerable bike infrastructure almost to yourself even though the snow has been minimal this year (but you can't have the bike-share, which is shut down until spring) - it simply doesn't substitute for year-round modes.
(4) bikes are hazardous, and that is a strong deterrent - rough quote, "what possesses you to ride that bike when you have your children to think about?" When they are e-bikes, there will be no offsetting exercise benefits, since those are really just another genus of motorcycle, aka suicycle, and are likely to be driven as such. This will repeat the pattern already set by mopeds, which used to have those silly vestigial pedals - how many years ago did the last person to do so actually pedal one?
(5) electric passenger trains will arrive at useful frequency almost exclusively in areas wall-to-wall with people - for which read: fantastically expensive areas or highly dangerous ones. I wouldn't look for more than very modest expansion in today's bad economy.
(6) all it would take to electrify the freight railroads is money. Lots and lots of money, front loaded. Not only for tens of thousands of miles of catenary and on the order of a million support towers, but north of 20,000 locomotives as well. And all that catenary would have to be maintained, forever - with major outages and stoppages every time there's an ice storm, or even merely, as in England, "the wrong kind of snow". See EVs and the economy.
(7) the glib argument that all we need to do to remove "the only reason" we haven't attained utopia, is to frog-march some notional 1% - more precisely in this case a "minority of workers and investors" - into oblivion, seems, to put it as kindly as possible, overly simplistic, almost verging on tinfoil. See (1) through (5), and "we" will need to overcome other barriers as well. Change is usually far from cost-free. In addition, change that is experienced as being for the worse (e.g. walking and waiting a long time in the broiling sun or freezing cold for a bus or train to arrive, in lieu of going right away and door-to-door in a nice, comfortable, 24/7-available car) will be resisted.
In sum: wand-waving or wishful thinking aren't likely to get 'er done.
The average daily distance traveled in Australia, the USA, and Europe is about 40mi/60km. You can do this with half a bootful of PBa, and even less of NiMH or Lithium. The charging infrastructure for this daily commutes-worth of power is the household GPO.
Given the choice between an EV they only have to 'refuel' each night or two by plugging it into the wall, and an ICEV they have to regularly stop at a petrol station to fill up, I expect most people would choose the EV as their primary car, and use an ICEV or Hybrid as the secondary car.
Or maybe not. We all know what a time-consuming effort it is to charge up our mobile phones every day or two.
Past performance does not guarantee future performance.
Of course. OTOH, if you're interviewing a new hire, what else is more important?
properly street-legal hybrids may be cost-effective for some people, but that "effective" cost is high
What do you mean by high?? The average 2011 new car sold in the US for over $30k. The standard Prius, on the other hand, runs about $25, and the Prius C starts below $20k, with 50MPG.
EVs may be cost effective, with the same limitations, but only as secondary vehicles for shorter trips, since charging-station infrastructure mostly isn't out there.
Sure. Of course most households have 2 or more cars, and extended range EVs and plug-in hybrids will work for the rest.
Few people are or will be willing to use bikes in "winter"
Sure. That was just a personal preference.
come to the Berkeley of the Midwest
You mean Ann Arbor? Great place. Are you a student there?
electric passenger trains will arrive at useful frequency almost exclusively in areas wall-to-wall with people
Sure. OTOH, they work extremely well for commuter trains and for travel from city center to city center.
all it would take to electrify the freight railroads is money.
Sure. It's not our top priority, given the railroads are at least 3x more fuel efficient than trucking. OTOH, have you read Alan Drakes analysis? It looks cost effective to me.
the glib argument that all we need to do to remove "the only reason" we haven't attained utopia, is to frog-march some notional 1%
Not glib at all. I've arrived at it after decades of sad experience.
"Poor Exxon. They used to be the oil company that everybody loved to hate. This spawn of the Standard Oil breakup had it all: Obscene profits, the Exxon Valdez, a mean CEO who sneered at clean energy, blatant funding for climate deniers.
But now, the new ExxonMobil is just not that special anymore.
It turns out that all the big oil companies are buying elections, paying front-groups to spread lies about climate change and dumping their tiny investments in clean energy while continuing to put out soft-focus ads touting how green and socially responsible they are. And they just don’t seem to care that much about preventing oil spills either.
In these days of peak greed, you have to drill pretty deep in the oil patch to find the worst of the worst.
A real gusher
Well, after coming up with a bunch of dry holes, the environmental and government-reform movements seem to have found the activist equivalent of Old Spindletop: Charles and David Koch."
See http://transitionvoice.com/2011/02/more-reasons-to-hate-the-koch-brothers/
Most people can't afford a new car, hybrid or otherwise. A new Prius costs about as much as the median American worker makes in a full year. Also, one cost-benefit factor often ignored by those with comfortable incomes is the hedging value of buying a (lower priced) vehicle which gets poorer gas mileage. If you lose your job or the price of gas rises you can drive less to lower expenses, but you still have to make the finance payment even if the car isn't driven at all.
Most people can't afford a new car, hybrid or otherwise.
Sure, they can. Many choose not to do so, like me.
A new Prius costs about as much as the median American worker makes in a full year.
I believe the median US worker makes substantially more than $20k per year (the starting price of a Prius C).
the hedging value of buying a (lower priced) vehicle which gets poorer gas mileage.
A 7 year old used standard Prius can be bought for $14k, slightly more than the average 7 year old vehicle. A used Corolla (highway MPG 40) can be bought for $5k.
The median American makes just about $26K/yr pre-tax. If he's silly enough to buy a new car for $26K and finances for 72 months, no down and 0% interest, that's $361/mo, plus higher tags and insurance than he'd pay for a used car. That's more than a sixth of pre-tax income. Half of Americans make even less than that.
If he buys a vehicle that gets 50mpg instead of 25mpg, and drives 12000 miles a year, he will save about $80/mo on gas at $4/gallon, $60 at 40 mpg, $40 at 33mpg, etc.
The median American makes just about $26K/yr pre-tax. If he's silly enough to buy a new car for $26K/i>
Well, the average new car goes for over $30k. I agree that most people should think about buying a use cars (that's what I did for my last purchase).
If he buys a vehicle that gets 50mpg instead of 25mpg, and drives 12000 miles a year
The average new car is driven about 15k miles per year, and the average overall is 13k.
he will save about $80/mo on gas at $4/gallon
That's $10k over 10 years. Overwhelmingly worth it.
What you're missing is that the average American cannot afford a new car, therefore his vehicle preferences are largely irrelevant to what new vehicles are produced. Folks who do buy new cars are relatively price insensitive, which makes economy less of a factor in their purchase decisions. Used vehicles are a fixed pool. Prices are based on demand. Fuel prices affect demand for certain used vehicles. If fuel economy and purchase price were the only variables, folks wouldn't be able to save much money by buying a more efficient car, since the price of the used car would reflect the potential savings. (There are obviously other factors in play, like the relative utility of certain vehicles for certain tasks, which is what the roller skate comment was about). Anyway, individual savings is largely irrelevant, since the used vehicle pool is roughly fixed, society doesn't save anything except to the extent that those who drive more have the more efficient cars. You recognize that not everyone can drive the most efficient car in the pool, however, you refuse to consider the implication that this means average Americans will end up basically forced to drive less efficient vehicles. We can't all carpool with the guy with the most efficient car in the pool.
My original point was that as a society, we can kick the oil habit. That's happening right now, albeit too slowly, by raising CAFE regs. CARB is getting in the act, by requiring 15% of all cars sold in CA to be at least partially electric, by 2025.
Another important factor: the US has way more light vehicles than are needed, and they're essentially thrown away after 12 years. The pool of high MPG vehicles could be used much more heavily during the transition.
Finally, if you carpool with someone driving the average 22MPG vehicle you get 44MPG. Three carpoolers get 66MPG. If the three pile into a Corolla at 35MPG, they're getting 105. Not bad.
We agree that dramatically lower dependence on petroleum is possible and feasible, even with quasi-BAU, and that CAFE is potentially an important tool in combination with many others. We disagree about the pain of this on the average American, who will not do well during this transition unless additional policies are put in place to help make that happen. Higher gas taxes with a per capita rebate would be one step in that direction.
Note that motor gasoline for use in light vehicles represents only ~45% of U.S. consumption of petroleum. I would like to see more policy efforts to reduce the other 55%.
I think we're very close to agreement.
I'd say that the average American could get through this transition pretty easily if they weren't misled by a media environment controlled by the allies of FF industries. I can't tell you how many low income people I've interviewed who were driving gas hogs, and had been fooled into thinking this made sense. For the same price they could have gotten something far more cost effective...
OTOH, I absolutely agree that lower income folks will be in for some real stress, and could use some help.
I think higher gas taxes with a per capita rebate are an excellent idea, though it must be pointed out that it would hurt high-mileage, low income folks. I'd say that they need assistance with low-cost credit for replacing their vehicles.
Liquid fuel consumption has fallen enough that light vehicles now account for about 50%. For better or worse, commercial consumers are much more responsive to price signals.
So I guess where we differ is that I think average Americans will see a lot (more) pain absent some policy improvements, but you think the pain will be confined to lower income folks. At what level of personal income would you expect this transition to be relatively painless? I strongly suspect two-thirds of Americans fall below the level you may be thinking of as low-income. 30% of adults lived in 'doubled up' households in 2011.
On credit-yes, it's a bit off topic for here but major overhaul of banking and credit is necessary. Bankruptcy law reform, cost-of-service-based banking fee limitations, and interest rate caps are needed. Credit union enrollment and direct deposit should be automatic with employment. Used car financing, check cashing, payday loans, title loans, pawn shops, etc should be strictly regulated.
The median American makes just about $26K/yr pre-tax.
And the average new car sells for more than $30k. I don't know why people are willing to do that, but they clearly are...
drives 12000 miles a year
The average new car is driven 15k, and the average overall is 13k.
he will save about $80/mo on gas at $4/gallon
Which is very roughly $10k over the life of the car, adjusting for time value of money. Overwhelmingly worth it.
Not everybody can buy a used Prius or used Corolla, the supply is fixed and the price is controlled by demand. Incidentally I drive a 4-cylinder 14 y.o. used Camry on which the odometer will roll over 300K miles this year, I bought it 5.75 years ago at 100,000 miles.
Not everybody can buy a used Prius or used Corolla
Right now they can. Maybe that will change - I hope so. If so, we'd have a temporary problem. Some people might need to carpool (the horror).
10+ million a year in the US certainly can. A new Prius costs LESS than the median new car price in America, which means more than half of the total purchases can be a Prius and SAVE money over their expected other choice. Although with the increasing again fuel production around the world, a decent 40mpg gasoline powered compact, like say the Chevy Sonic or Mazda 3 Skyactive system is quite n attractive alternative.
There are over 300 million people in the U.S. and about 80% of them are driving age but new vehicle sales are under 14million. If fuel economy and initial purchase price were the only differences between vehicles, everyone would use roller skates.
True. E-bikes work nicely for some things.
But, I'm not sure what your point is...
His point is rabblerabblerabblerabblerabble. ;)
Regarding bikes, winter, and safety.
People in this country don't ride bikes in the winter. This is probably cultural, since people in other countries (wealthy countries) with comparable winters ride bikes in the winter. Ice can be sanded and salted (just like it is for cars) and/or you can install studded tires on your bicycle. I commute, by bicycle, in the Boston area, and the local path is only plowed, not salted, so at times it can be very icy, and I have traversed miles of ice-covered pavement without falling down. Other people do just fine without snow tires by sticking to salted+sanded routes. The two weather "events" that are really annoying are rain, which soaks in and splashes, and very hot+humid weather, since you can only remove so much clothing. Snow by itself is no big deal, though obviously the cars still on the road are dangerous because of (their) reduced visibility and control. This is an issue for a lot of the Southern US, agreed, though the heat problem can be somewhat mitigated by traveling more slowly (speaking as someone who grew up on the Gulf Coast and bicycle-commuted one summer in Houston). My brother commutes by bicycle in Florida year-round; clearly it is possible.
The safety stats for bicycles are flawed in several ways. First, bad demographics. In this country, bicycle riders are disproportionately children, and we have no organized safety training for them. Beyond that, the non-children cyclists are disproportionately male, which does not help either, especially in the young-adult demographic. Second, bad infrastructure; the roads in this country are generally not designed for safe cycling, and even our cycling-specific accommodations are often dubious. Third, even given all of that, they're not that bad -- the one per-hour estimate I have seen (and it is old, and the work supporting it is no longer available, but the source was reputable) rates bicycles and automobiles as about the same.
One thing you overlook is that the exercise benefits are not just offsetting; they are overwhelming. Danish studies (large study populations, over many years, correcting for other risk factors) find a 28% LOWER overall mortality rate for bicycle commuters, and an expected lifespan extension of 2-5 years. However, this is not as vivid as crash risk, and so people tend to ignore it, both in their aversion to cycling, and their willingness (as you note) to forgo exercise and elect for an electric "assist" that ultimately turns out to be the main means of propulsion.
Nonetheless, there is some elasticity in all of this; bicycle commuting seems to be on a slow uptick in the Boston area. It got a real kick in the pants from the 2008 oil price spike. Note that we're also conflating facts and perception; there are people who will ride a scooter, but who will not ride a bicycle, because they perceive that not keeping up with (urban-ish) traffic is risky. They *should* ride a bicycle, but they *will* ride a scooter, and both choices consume far less energy than driving a car.
I'm not myself a big fan of electric trains, for the reasons that you describe. What I would expect to see in the next ten years is some combination of carpooling and ultimately robot-cars for mini-mass transit. There's companies out there now (Avego is one I know of) attempting to use a combination of smart phones and social media to facilitate carpooling; I expect that this will only increase, and get easier as the apps improve and smart phones are more widely deployed, and eventually reach a critical mass that causes it to really take off. Somewhat further out, if/when robot cars get better, I expect that you would just order a ride at a specific time, and it would just show up, like a cab, only with a few other people in the mini-van or car.
The assumption here is that bicycling (not with electric assist) and dial-a-van would be complementary; for sufficiently short trips, there will always be some wait for transit, so better to just hop on a bike, but for longer trips it will be net faster to wait for a robo-van-pool. One issue with all of this is that if the road allocation remains unchanged, we'll end up in a situation where everyone wants their neighbors to take the RVP, leaving more room on the road for ME to DRIVE (and more spaces for parking, too). Changing road allocations will be problematic, even though it really is the proper role of government to moderate individual impulses to promote the greater good.
I don't believe I said the world doesn't "need" Oil. My position has been and continues to be oil consumption should be restrained through taxes and secondarily by more fuel-efficient vehicles.
I get a kick how the Oil Industry thinks of itself as the progenitor of Oil. Why don't you tell all of us just how the Oil Industry created Oil?
I don't believe I said the world doesn't "need" Oil.
No, that's my contribution to the conversation.
My position has been and continues to be oil consumption should be restrained through taxes and secondarily by more fuel-efficient vehicles.
I agree. Heck, let's take it a step further, and just move to HEV/PHEV/EREV/Evs.
Over what time period? 12 months? EIA shows a US production increase of 213K bpd Oct 2010 to Oct 2011, and an increase of 1250K bpd from the lowest October of 2005 (27%). And as you say there is further increase in other liquids.
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=MCRFPUS2&f=M
Falstaff,
At this site it is the lowest possible oil production statistic available, that is inevitably posted, because no one wants to look reality in the eyes. Hubbert's curve has developed a very nasty upward going curve in it, and it's getting worse just about every single day. And, Peak Oil theories are all based upon the idea that what happens/happened in the U.S, will then inevitably happen in the rest of the world. Whoops!
Where possible, I try to use average annual production numbers, which tends to smooth out both anomalously high monthly values and anomalously low monthly values. For the same reasons, I prefer to focus on average annual crude oil prices.
Good point!
James Hamilton graphs the historical peaking of production in almost every one of the US oil producing states. See:
Oil Prices, Exhaustible Resources, and Economic Growth*
He points out the ongoing/increased production came from expanding to new areas, with little from new technology in existing regions.
Of course, over most of that history oil prices were low.
Peaking of a region is very different from global peaking. When Pennsylvania peaked, they just moved on to Oklahoma, then Texas, etc, etc. Oil was oversupplied for about 100 years - the TRRC regulated supply for about 40 years before 1973, and KSA for about 30 years after.
We're in a bit of different era now, as you know. Global PO causes prices to rise, and this feedback will cause different production dynamics. I suspect we'll be basically on a plateau for quite a while.
This idea that natural gas producers must keep producing on a well that is losing money makes no sense.
I am not understanding how parties on either side of such a contract could be stupid enough to sign it.
dnpvd0111, It is because the leases were signed many years earlier, and neither side could accurately see the future, because no one can see the future with any degree of accuracy. That's where risk comes into the game, and why investors with money (to lose) are needed. Capitalism certainly has a lot of quirks and faults, but so does every other economic system. Maybe, it's because quirky and faulty people are always involved in economic systems.
Is natural gas actually being produced at a loss?
This makes no sense.
Now perhaps the idea is that the leasee has only so long on the well so they must develop the well in the hope of future profit.
Can a producer with a lease with potentially (for the sake of argument) a hundred well potential, hold onto the lease by producing a single well at a loss? It would be rational to lose a small amount of money today, to keep your future lottery ticket alive.
But why should a lease be written in such an absurd manner?
Leases are written in an attempt to serve both the interests of the land owner and of the producer. If leases weren't written in a matter that in some way compelled the producer to drill, then the producer would simply lock up large swaths of land and "sit" on them until conditions were optimum for production. The fact that there are multiple producers competing over land facilitates language that protects the interests of the land owner to some degree.
Won't the lessor make more money on the gas when gas is at higher prices?
dnpvd0111,
Yes, but the lessor also makes money on an uneconomic well, while the owners of the well, (gas companies and/or investors)are losing money...but, they still "own" their lease and will eventually make money if the economics improve. GreenPlease answered your other questions quite well.
Here is what oil companies are doing in the Bakken in regards to leases, which might also apply to certain gas plays. They first make one exploration well typically over two, one mile square sections, with a 10,000 foot lateral, that traverses both sections. The two sections are then classified as de-risked, and investors will then be much more willing to invest. The production from that one well with an a typical Bakken EUR of 500,000 BOE will last for 30 years at a daily average rate of only 46 BOE per day. That is deemed to be enough production to hold that lease for 30 years.
Later, when the oil companies have more time, they come back and drill 7 more wells (There are two separate formations in the Bakken) 3 in one zone and 4 in the other. Then that 2 square mile area is considered to be completely developed, and the money starts really rolling in to the lessor. There are at present multible unexplored and undeveloped oil zones beneath the upper two, so up to 20 wells might eventually be drilled every 2 square miles in the 10,000 square mile thermally mature area of the Bakken. Hope that helps.
Every piece of information i have laid eyes on, not just what promoters have said, shows that the bakken and three forks are in pressure communication, meaning wells completed in the two zones are competing for the same reserves. Many of these dual wells are also communicated through hydraulically induced, propped frac's.
An evaluation of Sanish field, with an average of about 3 wells per 1280, demonstrates that some of these wells are also competing for the same reserves. How in the world are they going to drill 5 more ?
[edit]
bannedonsomewebsites,
[edit] I don't see the point of your comment. I'm also a bit unsure of what your true intentions are, and what your real understanding of these issues actually is. I have never heard of the expression "propped frac's" before, therefore I do not know for sure what you are trying to say. I also do not know who, or what you mean by promoters, or why you (apparently) don't accept their viewpoints. You have also not revealed the sources of this other information you have laid eyes on, but it doesn't seem to come from the companies doing the actual work. [edit]
But, some of the wells in the Sanish field are vertical wells that intentionally source oil from both formations, as the layer of separating rock is very thin there, and because it is also just plain cheaper to do so. The Sanish "field" is really only a sand like formation on top of the upper three forks formation, and is generally considered to be part of the Three Forks formation. It covers a very limited, but very lucrative area. It is also possible that you cannot properly distinguish between the two main formations that I have referred to, and are instead referring to communication between the Sanish field and the upper Three Forks formation, of which the Sanish is merely a subset of. Yes, there possibly is well communication in that limited area, but I don't know for sure. But, there are presently no reports of any well communication between the two main formations, the Middle Bakken and the upper Three Forks. Therefore they are still considered to be two separate oil bearing formations.
How about some better clarification from your side?
Please see this pdf: Mathistad Communications Testing
http://www.nd.gov/ndic/ogrp/info/g-018-039-df.pdf
This testing was done in '09. Based on production to date, it is questionable if the number 1 and 2 combined will recover 400 MBO(400,000 BO).
Current Well Name: MATHISTAD 1-35H
Pool: BAKKEN Cum Oil: 168177 Cum MCF Gas: 202017
Current Well Name: MATHISTAD 2-35H
Pool: BAKKEN Cum Oil: 114185 Cum MCF Gas: 169902
bannedonsomewebsites,
Thanks for the link. I am familiar with the test as it was very big news at the time. Here are some very relevant words from CLR:
"During the fracture-stimulation of the Mathistad 2-35H, pressure spikes were detected below, in the horizontal well bore of the Mathistad 1-35H. "This was not surprising, given our placement of the Mathistad 2-35H horizontal only 50 feet above the lower TFS well, the pressure depletion in the TFS well bore area, and the high pressures involved in frac-stimulation," Mr. Hamm said. "We set up 'worst case' conditions, with unrealistically tight spacing and aggressive pressures, to see if we could frac through the intervening shale layer into the lower horizontal well bore. Once the Mathistad 2-35's frac pressure subsided and it began flowing back, we clearly had production from untapped rock. We saw insignificant communication with the lower TFS well."
You see, when you look deeper into matters, it turns out that in this test they tried to FORCE communication between two very dissimilar wells, as #1 was much older and therefore de-pressurized, and the distance between the wells was also a very unnatural 50 feet. They at least partially succeeded to force the issue, as minor communication between the wells was achieved. But the test proved that the two oil formations are NOT in contact with each other. Today CLR's laterals of Bakken wells are spaced at 1320 feet intervals per oil zone. But, the lower zone laterals (Three Forks) are staggered laterals, which means they are in between the Bakken laterals(and lower down) at a distance of 660+ feet from the Bakken laterals. This pattern is expected to continue as they develop all the multible underlying oil zones.
This leaves me wondering why you chose to argue with me using results from a test well, rather than actual wells in production. To me it just looks like classic Peak Oil cherry picking of information in order to distort the truth. But, do you have any other examples, or do you wish to concede defeat in this issue, here and now?
The Mathistad No. 1 and 2 are actual wells in production. I posted the cummulatives. CLR's Model shows 900 mbo, reality indicates < 400 mbo.
Banned,
Obviously, the two wells are in production. What would be the point of capping two producing wells? You are avoiding the fact that these two wells were both used as TEST wells to determine whether there was well interference between the two formations. There wasn't! But, you still think there was. So, I'm still waiting for you to produce some proof of your claim.
What does the real or imagined production data have to do with the issue we are discussing? The TEST is over! Try to stay focused on the central issue, and stop dragging red herrings into this discussion. It will only lead other people to believe that you are losing.
You need better sources of information on the topic.
Carl Martin,
There are reports of communication between the bakken and three forks. The Bicentennial-Elkhorn Ranch trend of the bakken shows depletion in the three forks by production in horizontal and vertical bakken wells going back to 1980.
Whiting has reported pressure depletion in the three forks in the Bicentennial area. That is at least one report. The claim.... 'there are presently no reports of any well communication between the two main formations, the Middle Bakken and the upper Three Forks.'..... is clearly mistaken.
The three forks formation represents a tremendous amount of additional oil in place. The question is, imo, how much of it is recoverable and how to optimize recovery with well placement.
I doubt 8 wells per 1280 is optimal.
The described placement is 4 wells in Three Forks and 4 wells in Bakken amounting to a total of 8 wells per 1280 only in the sections where the Three Forks and Bakken are both present and very thick. Based on the Matthistad press release available on Continental's website, they claim that a staggered arrangement of well bored prevents hydraulic fracture stimulation treatments from inducing interference between the two formations.
Not sure if you knew 100% of this information, but it is not clear from your post.
Cheers
Pitts,
Not sure if this was meant for me, or not, but yeah, you got it exactly right. What Banned doesn't seem to get is that this well placement is the direct result of the test, and in fact the whole reason for the test. The NDIC wouldn't allow this well placement UNLESS the two Mathistad wells passed the test by proving there was no well interference. Further more the NDIC also agreed to allow fence to fence placement of the wells, in order to utilize the full 1320 foot distance between the laterals, as measured in each zone. Otherwise, oil companies can only squeeze in three wells per zone, because they have to have a 200 foot setback from the property lines. That's why the EUR of the whole Bakken suddenly jumped by 25% in just one day. Greater efficiency in well placement was now made legal, by allowing 8 wells per zone for each 1280 spacing unit. I've actually written an article on this subject, but still don't have it published.
Towards the area of the SW Middle Bakken pinchout, that Banned is referring to, but in the Three Forks zone, there is too much uncertainty in the well data, so this area is underexplored and therefore not derisked. No one believes that 8 wells per spacing section is possible here. This is why the 24 billion BOE is so LOW. Only 70 % of the inner thermally mature area of the Three Forks was considered to be de-risked. If the entire area considered was de-risked, then the EUR estimate would have been 29.34 Billion BOE, because there would be room enough for 58,680 wells producing at 500,000 average EUR per well, instead of just 48,000 wells. All this is ancient history for investors in Bakken oil companies. The Bakken oil play has never been adaquately covered by this website. Therefore, you have to source your all your Bakken information elsewhere, as I have done.
The numerous wells that have been filled up with frac sand from offset(both vertical and horizontal) frac jobs discredits Hamms claim.
In one case a well being drilled in the Bakken lost a mud motor, mwd and drill pipe stuck during a frac job 1/2 mile away. That well was eventually plugged back and sidetracked.
Banned,
If, you wish to assert that, "There are reports of communication between the bakken and three forks," then it is up to you to provide the rest of us with proof of such. As you offer none, I can only assume that you don't have any proof, and wish to turn this discussion into a shouting match, instead.
You mention a Whiting report. Fine. Please provide this report to us all. You can't expect anyone to just take your word on it. Meanwhile, my claim remains correct until proven wrong. Perhaps, it is indeed wrong, and I just don't know that, because no one has managed to ever prove it wrong.
Why do you, "doubt 8 wells per 1280 is optimal." I don't know for sure whether it's optimal, or not. I only know that CLR says it's optimal, and they have already invested millions/billions? in this plan, so I can only assume that they know what they are doing. It is, by the way, 4 wells per 1280 PER ZONE, so the actual spacing is 1320 feet per lateral for each zone. The lower zone laterals are then staggered by 660 feet, so the closest two wells in different zones can possibly be is 660+ feet. That's why there is no well communication reported. Why don't you go to contres.com, look up their latest investor presentation, "Third Quarter 2011 Update" from 01/05/2012, page 11, and educate yourself on these matters instead of using your time arguing with me?
By the way, do you concede defeat in this discussion, or not?
P.S. On page 10 you can also see a map, that shows how the Middle Bakken pinches out NW of the area you are referring to in your first paragragh. I believe what happened is that oil companies were actually drilling into the Three Forks, but mistakingly thought it was the Middle Bakken instead, because the Three Forks was not known to be a separate oil producing zone at that time. In that area CLR only has plans to drill 4 wells total per 1280 spacing unit, because they can only locate one oil producing zone there, presently identified as the Three Forks. That's why this area is known as the Middle Bakken pinchout. Do you get it?
I will locate Whiting's presentation even though you apparently didn't read the Mathistad Communication Testing I posted above. It may take some time to locate, but I am 100% certain Whiting acknowledged depletion in the three forks from production from the upper bakken shale.
Assume what you like.
edit:
http://www.whiting.com/investor-relations/press-releases/
You will have to look for the 2-23-11 press release titled: Whiting Petroleum Corporation Announces Forth Quarter and Full Year 2010 Financial and Operating Results
end edit>
Continental also tried the three forks in this Bicentennial area. No pressure data is presented, but production data points to a depleted reservoir just as Whiting found and acknowledged.
Marathon's acerage is developed with 2 wells per 1280. Are you suggesting that Marathon doesn't know what they are doing ? Hamm is a shameless self promoter. Hamm stated a few years ago that eur for a bakken well was 1000 times the 7 day ip rate. How did that turn out ?
The Mathistad Communication Testing study ,which I take it you didn't read, was done by CLR with funding from the NDIC. These are CLR's wells, their model produced seriously bogus realizations, e.g. 900 mbo eur from the two wells that will struggle to produce 400 mbo, the incremental mbo they claim for the second well. Do you get it ?
These geologists aren't incompetent, many wells drill out of zone. The usual remedy is to plug back and side track the hole.
I've been educating myself on this subject since 1984, when I was first assigned the area. One of my first projects resulted in a recommendation to recomplete a vertical well in the upper bakken shale. Interested in knowing how that turned out ?
banned,
[edit] I have read the NDIC reports, not just once, but many times. I don't see what your issue is with them. As, the NDIC has agreed with CLR, that the MB and 3F's are two entirely separate formations, this report does not support your case that there is well interference going on. Sorry!
As to the information in the second box, (Whiting completed...) It sounds to me like this information is not actually coming from Whiting, but rather from another company working in the same area. Can you give me the link to this source of information?
I have followed your links to Whiting's website, but came up with nothing of any relevance. So, the onus is still upon you to come up with some solid proof for your assertions.
Not that it is proof of anything, but I chose to share your thoughts with a certain Michael Filloon, who is the most prolific writer about the Bakken that I know of. Here is his answer: "To my knowledge this has never happened. I have heard rumblings about it, but no one has made a clear argument that it is true." As, Michael knows far more about the Bakken than I do, I will hereby publically accept his answer as definitive, until it is proved to be wrong...by you.
I don't choose to respond to any of your other ramblings, as it all seems to be part of the same unproved package you are so desperately trying to deliever to me. Your deep seated bias towards Harold Hamm is now well known to all, and is (apparently) what drives you to say the things you do. (Anything, just to get that man!) So, your credibility still remains extremely low with me.
No, I am not interested in knowing about a vertical well that "you" completed, because it is not relevant to the issue at hand, and I don't want to waste further amounts of my time and energy trying to separate fact from fiction. I repeat, your credibility still remains extremely low with me.
Have you tried this ?
I posted the text and you apparently don't believe the text and can't find the text from the link and instrustions. You have to follow the link and folllow the instructions.
That is probably a good idea. 'When you find yourself in a hole - stop digging'. Author unknown.
You should direct Filloon to the the link I provided. Educate Filloon !
There are dozens of formations in the Williston Basin and many more local names for members. The NDIC classifies the zone from 50' above the upper bakken shale to 50' below the lower bakken shale as one pool, the Bakken Pool.
Banned,
Okay, I'm on the same page as you now. I don't know what to make of this item, "Based on Whiting's evaluations, we believe there has been partial pressure depletion from Upper Bakken Shale wells drilled in this area in the 1980s and 1990s" It does not explain much of anything to me, but I consider it VERY mysterious, and perhaps ominous. But, it doesn't even explain which zone this pressure depletion is taking place in, nor does it specifically mention any well communication, or well interference. So, I don't see how it can be proof of anything you are claiming. The words well communication or well interference MUST be there to prove your point. But I will run all this by Michael, again. I got to go, for now!
The text speaks for itself. The well was completed in the three forks. The three forks was found to be partially depleted by production from 80's - 90's upper bakken shale production.
"The lower Lodgepole limestone, above the Bakken Formation, and the upper Three Forks Shale, below the Bakken Formation, make up the rest of the Bakken Source System, as defined by Price and Lefever (1992)."
2.04 Bakken Source System
http://www.undeerc.org/price/TextVersion.pdf
Quoting from your link:
I recommend you go to meetings where this information is discussed, if you aren't actively involved in drilling, producing, evaluating or quantifying these types of problems professionally. I would recommend you start here.
https://www.wbpcnd.org/
Bruce_S,
That was a link to a future event, which may or may not be beneficial to my PRESENT understanding of the Bakken. Your post did not answer my question, "Why do you think I need better sources of information?" [edit]
I think you need better sources of information because it didn't take 5 minutes at a meeting similar to the one I referenced to find people quantifying the amount of interference between Bakken and Three Forks wells. If you don't want to go to the area specific information meetings, you can also go to the larger national conferences. Pay attention to the talks and you can find the experts there as well.
http://www.aapg.org/longbeach2012/
Bruce_S,
Where do these people get their data on, "quantifying the amount of interference between Bakken and Three Forks wells."? The oil companies? If this is at all true, then you/they have a major story on your hands. I accept that you can't easily prove this, which of course does not mean, that it is not true. But, it would be nice if there was a written version of this somewhere on the net. Otherwise, I can't use this information for much, as for me, it can only be hearsay, or readsay, if you like.
Incorrect. As Banned has already referenced, this information is already available.
Bruce_S,
In other words the people talking are only talking about this one small area of the Bakken, where there has been some pressure depletion previously reported. I'm still missing confirmation from either you or Banned, on whether there is on record any well communication/interference between two separate wells, at the same time, in two different formations, where it can be determined that the one well is actually stealing another well's intended production, or that oil companies are somehow misrepresenting this happening. There so far doesn't seem to be much of a story at all. That was also what Michael Fillon has said. This all seems to be a case of too much nothing.
http://shale.typepad.com/bakkenshale/mathistad-1-35h/
This link may be of interest to you. I can't find the actual investor presentation, but there have been multiple pilot programs in the Bakken in order to assess the ultimate field spacing. Companies have well arrangements that will ultimately allow 8 wells per 1280 section with 4 Three Forks wells and 4 Bakken wells in the best areas of the play.
Cheers
Try rephrasing your statement. ...people are only talking about this one small area of the Bakken, one of the few if not the only where people have tested the idea that interference takes place and discovered that it does.....
Bruce_S,
Now, I'm losing you. There are in fact two places under discussion. The test wells, and a report from a company talking about pressure depletion in a whole different area. I believe you were refering to the second. Were you? There were no well tests there, that I know of. Only in the first area.
While interfering wells have already been documented, and interfering formations are in the process of being documented, and while you might consider this effect only in small areas, I will bet you dollars to donuts that it will happen elsewhere. Call it a hunch.
dn - Let's put you in the driver's seat. You own 2,000 acres of minerals under you cattle ranch. Oil/NG prices are low. Not much drilling going on. None of your neighbors have been approached for a lease in over 5 years. Your loan on those expensive breeder steers you bought is coming due. Cattle prices are half of what you expected by this time. Your older girl has decided to become a vet and wants to go to Texas A&M: "Daddy...I need some money".
Now my broker shows up at your door and offers you $200/acre. But I also have some very tough lease terms. My broker hands you a draft for $400,000 and a lease agreement to sign. What do you do? Well...do you feel lucky, punk? (as Dirty Harry might say). Do you turn the deal down hoping I'll come back with a better trade for you? Or maybe I don't come back because I have more prospects to drill than money to drill them all so I only lease the ones where I get the best trade.
Well...feel lucky, punk...do you? LOL.
This is the real world I'm describing for both operators and mineral owners. Today, in plays like the Eagle Ford, many mineral owners are sticking it to the oil companies big time. But that's how it should be. It's called capitalism. No one forces a company or a landowner to make a tough trade. And no one is obligated to give either a better trade than they need to. Just like buying a house these days. Just because you paid twice for your home than what it's worth to me today doesn't mean I should pay you more. Granted it's a bitter pill to swallow. OTOH how would like to be forced to pay more for a house than what you think it's worth?
eos et al - Yes..it can and has happened. But typically with older leases. Today many mineral owners have gotten smarter. But it's still a negotiable issue. If leasing is way down and the mineral owner needs cash he'll back off demands. OTOH if he's in a hot play (like the Eagle Ford) the mineral owner will call most of the shots. We're trying to put together leases for a deep NG well in Texas and part of the acreage is HBP (Held By Production). The entire 6,000 acre field was "unitized": the field consists of almost 100 different mineral leases/owners but are consolidated into one legal entity. Over 270 wells were drilled initially and produced over 40 million bbls of oil. But today there are only two wells left producing making 73 bopd with a 98% water cut. All the mineral owners share proportionally the royalty from that little bit of oil. I doubt each mineral owner gets more than a few $'s per month. But because it's a HBP unit we can't take the leases for our well. Have to negotiate with the unit operator for a sublease...not easy to do. But the mineral owners have no option. They signed leases that allowed this to happen: contract law...be careful what you agree to.
As to the question of why an operator will continue to produce if losing money: depends on how they are losing money. If they made a bad hedge bet they either keep delivering physical NG or they have to buy it at market price to satisfy the hedge. Will always be better to produce what NG you can vs. buying make-up NG. But an operator may continue to produce a well even if there's a net operational loss hoping for additional activity on the lease. They may being trying to generate another drilling project on the lease or hoping another company might do so. Another factor is the P&A cost: they might be losing $500/month but it might cost $15,000 to plug the well. So they'll hang on hoping for more activity or someone like me will buy the well and take over the P&A obligation. And a public company might hang on to a large acreage position waiting for a more advantageous time to take the write down that would occur if they let the leases go.
Huh ???? Is the 'Unitized Formation' everything from the surface to the center of the earth ? I've never seen it.
ban - It depends on the original lease terms. The field was unitized in several formations. But the leases can be held at all depths with any production. These are very old leases. I know of another field were all rights to all depths are being held by less than 20 bopd...all 7,500 acres. Unitization has its good/bad points. And the good/bad changes over time depending on production rates and prices.
La. can be even more frustrating. I can drill a well on acreage I own 100%. But after I make a discovery another company can call for a unit hearing. If they can prove to the commission that some of the oil/NG my well is producing is coming from their acreage the state will force me to give them a percentage of the well I risked my money to drill. They have to reimburse me for that share but they didn't risk any money to begin with. I once saw a company lose 40% of a well this way...a well making $2.5 million a month.
La. has some other unique laws: You buy (not lease) the mineral rights under a 10,000 acre tract of land. If you don't develop that oil/NG in 10 years and have it producing the mineral rights revert to the surface owner. That's one reason many mineral owners make what look like bad trades: if they didn't make any trade they would lose their rights so a bad trade was better than no trade at all.
depends on how they are losing money
How often are they actually losing money on day-to-day operations? Doesn't production pay for day-to-day operations almost all of the time, even with NG prices this low?
Nick - Good point. I think folks get confused when talking about a well's "profitability". Overall a well might not recover the monies spent to drill it. But the LOE (Lease Operating Expense) can be low enough to make a nice profit on net cash flow. Thousands of wells that never recovered their investment have produced significant volumes of oil/NG.
Additionally I've completed a number of wells I knew weren't going to recover the ENTIRE investment: drilling cost = $8 million. Completion cost = $2 million. I estimate the net income from production = $6 million. So I complete it because I make 3:1 on my money ($6 mill vs. $2 mill). But overall I've lost $4 million: ($8 + $2) - $6. I'm sure you and most understand the concept of "sunk costs". It doesn't leave a good taste in your mouth but you do it.
ROCKMAN,
Yup, it always costs money to make money, and it always costs even more money to lose money. Life in the oil and gas fields sure hasn't changed much over the years, and I don't think it ever will. Too bad, that most people aren't aware of this very simple fact of life.
Carl - All good points. And I'll add my usual rant about the other big factor,IMHO, as to why we see some operators developing reserves that don't offer a very attract return. Those operators being pulic companies who MUST meet Wall Street demand for an ever increasing reserve base regardless of profitability. A few months ago Petrohawk, one of the big early players in the Eagle Ford, sold the company for #12 billion. they had little production and mostly undeveloped EF acreage. I just found out last week that Petrohawk had already begun droping many of the EF leases they felt were too marginal to drill. Those shareholder couldn't care less how profitable the wells will be: they've alread captured their profit and walked away.
Back when my landman kept bringing me EF deals after I told him that our private company couldn't justify drilling I devised a way to prove my point. I made the same offer to 5 different EF players who wanted to sell me their acreage: I would pay them their asking price. BUT I wouldn't deliver the cash to them...I would use that money to pay for a porion of every well (with me paying for the rest) and assign them owneship in the production. IOW I would pay for their share of the wells 100%. And guess what? Not one of them took my offer (fortunately because I would have withdrawn it). None of them wanted to own a piece of an EF well even if someone else was paying for it. They just wanted their cash and go to the house. And remember these were the players who were in the Ef from the beginning and understood the play better than anyone.
Rockman, I think you have to look at many different companies to get the full picture about what is going on. I was/am not very familiar with Petrohawk, but I always viewed it as a gas play that never managed to make the switch over to Liquids. I only follow oil companies, that are successful, and thereby got out of gas years ago, because they could see all this coming down the pipeline. [Edit]
And, I don't understand why the people at this site insist upon always finding one bad example, then applying it to the whole group. That's just cherry picking. Surely you must know that one bad apple doesn't spoil the whole barrel. Or, if we are to talk about doughnuts, why keep mentioning doughnut holes? It's not about how much oil isn't produced. It's about how much oil is produced, and why.
I was in Pecos and Ward county today. Chasing sand. Helluva job looking for sand in West Texas.
Had conversation with two different people working for two different producers. They both said the words that have chilled me to the bone. I survived 1986
Those words, " This is not the old oilfield. This time it is different"
It ain't different. We are in a bubble right now. There is too much stupid money chasing stupid projects being promoted by people that don't know come here from sicum.
This is NOT going to end well. There is going to be a lot of money from people that should know better that will evaporate. All those issues of too many people in NoDak will be resolved.
This is why I'm pushing my company from gas to liquids as fast as I can. Oil is going to stay high. Gas will drop, and then cycle up. It'll be a great time to have a CNG vehicle or an LNG compression business, though!
I suspect the numbers in the graphs are low on NGLs, and the odd classification of wells as oil vs gas in some locales, but I don't really know.
I am quite sure, though, that production of gas wells is not decreasing quite as quickly as expected due to improving enhancements. Even if a well would not pay to drill now, if it exists now it may pay to workover for plunger lift or such to deal with liquid-forced declines. This added gas is low cost and depresses the market too.
In order to answer the question of how much natural gas is generated from oil wells I went to the EIA Natural Gas Gross Withdrawals and Production dataset. This dataset has gross withdrawals broken down by well type. From that data (and another US Natural Gas Prices dataset) I created the following graph:
The first thing one should notice is that this dataset is imperfect. Missing data are well marked with 'NA' in most of this spreadsheet. But the values of '0.0' for shale and coalbed wells in 2010 are clearly wrong.
With no data from 2010 for shale and coalbed wells, it is impossible to say how much they contributed in the last two years. By all accounts, gas from shale wells has grown geometrically and currently accounts for a large fraction of US natural gas production.
What I found interesting was that production from conventional wells declined during 2008 and 2009 and then jumped up in 2010 while production from oil wells was entirely flat during this period.
This dataset, if the data are to be believed, tells some interesting stories and I would be very interested in hearing peoples' theories as to what events might explain the details of this chart.
Regards,
Jon
It looks like they just stopped splitting shale out and lumped it in with gas in 2010. Thats why one suddenly drops down and the other suddenly jumps up.
I concur. I don't see any other way to justify the huge increase in flow rates from "gas wells" as there haven't been any conventional gas plays discovered/developed in the last ten years large enough to produce that sort of a jump.
Great chart Jon, It seems clear that the jump in "gas wells" is linked to lumping in coal bed and shale wells - why change the reporting standard? I find it strange that oil associated gas is so flat with oil production in decline. Also interesting (suspicious) structure to oil associated gas data. Also strange is the flat dry gas production which suddenly goes into decline late naughties. And why is this data so noisy - and seem to lack annual cyclic structure that I know is present in N Sea! Winter demand and hence production, is normally much higher.
Can you sum the categories to produce a total? This doesn't look real to me. How do the numbers stack against the likes of BP?
Here ya go:
I reckon the 'gas plays' are lumped in with oil wells that are 'blowing the head' in the final dying days. Of course the other side of this coin is that we are witnessing the silent death of many oil wells.
Marco.
I heard a large gas company guy say "we're an oil company now", yet all their wells were still 'gas' wells. He specifically said there were tax benefits for them to classify wells as gas wells, so your data may be meaningless without a matching figure for "oil produced from gas wells".
He said Marcellus would crash, but EF would continue, and Utica would take off, on the wetter side anyway.
We'll see.......
I SUSPECT THGERE WERE A LOT OF WELLS DRILLED IN 2008 BUT NOT PRODUCED UNTIL A PIPELINE BACAME AVAILABLE IN 2010.
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Best to all!
Kate
[Edit - sorry, thought my e-mail was posted - should be now - is katerwriter@gmail.com]
One point ignored here is that natural gas is now driving the price for coal down. So the question is not only whether nat gas can be produced at these cheap prices but can coal be produced at these price levels.
Power companies in the midwest are retiring plants because they are making the call that they will be generating electricity from natural gas. That is a business decision which will be effecting both the price of natural gas in the future and that of coal for some time to come. I believe the estimates for replacing the electricity from those plants will require 15% of the natural gas produced in the entire country. That should soak up the oversupply from the shale revolution, and then some!
Go local and it's free. Can't compete with free.
http://www.chinapost.com.tw/taiwan/local/hualien/2009/07/31/218504/Two-H...
"Wells were drilled in China as long ago as 3000 B.C., using strings of bamboo rods much like modern cable tools. The gas discovered by these wells was distributed through bamboo pipes."
https://www.dmr.nd.gov/ndgs/Publication_List/pdf/50th%20Anniversary%20of...
The use-it-or-lose-it approach to gas seems short sighted. It might be a good thing to have plenty in reserve decades from now. Assuming we don't want burn too much coal for electricity we have
Path A: limited nuclear, major gas fired electricity, expensive gas mid century
Path B: more nuclear, limited gas fired electricity, cheaper gas mid century.
If future gas prices were known under either scenario it would be possible to do a cost-benefit analysis. Who knows Path B might turn out better. While I understand there are immediate incentives to drill gas/oil plays perhaps the regulations could be changed in gas prospects. A gas well could be capped for say 20 years for a nominal fee. Investors could sit pretty until gas prices are restored.
If none of that makes sense consider the possibility of a Strategic Gas Reserve for tough times ahead. This already exists for helium but academics have considered the possibility for NG. It's as though we learned nothing from Peak Oil with gas as the major remaining versatile hydrocarbon fuel.
Boof - "A gas well could be capped for say 20 years for a nominal fee." And how would you feel if you were the mineral owner that would get the royalty from that gas and your about to lose your ranch because you can't make the mortgage payment? Or maybe you were just hoping to retire now instead of when you're too old to enjoy it. Or what if you are an investor in that well and have put you life savings in it. And now you don't get any money back for 20 years??? And if your the operator who borrowed the money to drill that well...how do you pay the loan back? Most operators can't afford to cut back their NG production today even a little let alone shut a well in completely...there are bills that have to be paid.
A SGR could make sense. But there are already many in existance....called NG storage facilities. These are privately owned. During the high demand months of the winter the existing wells typically can't produce fast enough to meet demand and they thus draw from storage. But the prority of these ops is profit...not national security. If the pulic wants to fund an SGR system I'm all for it. Besides providing some national security it would help dry up some of the glut we have now and generate some higher prices for the oil patch. But NG storage is very expensive to set up. But China still has a lot of money left the could loan us I suppose.
In fact up the road a ways from me the Chinese have bought a working nickel mine and put it on care and maintenance until the nickel price comes back. They have deep pockets, I guess in part due to being an agency of the Chinese government, not a private company.
The perceived gas glut could be why an Australian offshore gas project is on hold
http://www.theaustralian.com.au/business/mining-energy/woodside-kicks-of...
I'm sure we'll want that gas soon enough the way we are using up the resource. Thus a mothballed gas project is kind of saving some for later.
The gas glut is strange because there are plenty of places that don't have enough gas such as Asia, western Europe and even south eastern Australia. These places would grateful just for the gas which is flared in gas rich regions.
Yair...Boof or anyone. Can you provide any insight or links to info on the coalseam gas kerfuffle that is going on in Qld.
I would imagine the characteristics of the fields and individual wells would be different to shale plays...and is it a different gas? I would have thought it was methane.
What are it's characteristics and uses. Is there any info on depletion rates of individual wells?
Cheers.
Speak of the devil
http://www.theaustralian.com.au/business/mining-energy/chinese-likely-to...
The Chinese evidently believe any gas glut is temporary.
SP my understanding is that coal seam gas is ~98% methane so it is cleaner than most natgas which often contains CO2, H2S, ethane, butane and so on. Thus the unburnt gas sometimes needs to be scrubbed of CO2 using zeolite sieves as will be done by Chevron at Barrow Island, Western Australia.
To me shale gas sounds like it comes from marine sediments based on plankton. I guess natgas is the same but usually trapped in pockets. Coal seam gas would appear to be derived from freshwater swamp deposits, subsequently buried. Oil persons should confirm this.
Boof - Tough to make generalizations. But methane is methane regardless of it's source. That's what eventually burned and the combustion products are identical. How it exists in the ground and when produced is another matter. Compostion of components beyond methane ranges widely: high NGL's, sulfur, N2, water, etc. As your point out the flow is scrubbed to remove the unwanted. Sometimes the unwanted (NGL and sulfur) can be valuable.
Reservoir dynamics. The NG produced from shale gas wells exists in the fractures or cracks in the rock. Little if none typically comes from the rock matrix itself...permeability is just too low. The fractures flow the NG at very high rates but repesent a relatively low volume...thus the usual high decline rate. Think of a small air tank with a big valve. CBM (coal bed methane) is a very different animal. Think of a bigger tank with a smaller valve. I don't know a lot about CBL but here are some of the basics. The initial problem is water production. Most CBM reservoirs have a lot of water in them...fortunately usually fresh water. A CBM well may have to produce many tens of thousands of bbls of water before it begins producing a significant amount of NG. That can be beneficial in dry areas...farmers/ranchers like this. But it can be a problem. In some areas of WY there's a high concnetration of sodium...not sodium chloride...salt. The problem at the time was there was no standard established as to limits. Otherwise some folks in the arid section were looking forward to all that free water.
As I undertand it most if not all of the NG from CBM reservoirs is molecularly bound to the organic material. The water production reduces the reservoir pressure and thus induces a destablization and the releases the NG. But once the process is established production can remain flat for many years/decades...but often at just several 100 mcf/day. In that sense CBM and shale gas are polar opposites. CBM comes on very slowly as it's dewatered but then establishes a relatively slow decine rate. SG, OTOH, comes on at a very high rate (thousands of mcf/day) and the typically declines very quickly in just a few years. You can imagine the economic models of the two plays are radically different.
Roger that. I'll link to this explanation if it comes up again.
Rockman - Above you wrote, "The NG produced from shale gas wells exists in the fractures or cracks in the rock. Little if none typically comes from the rock matrix itself...permeability is just too low. The fractures flow the NG at very high rates but repesent a relatively low volume...thus the usual high decline rate."
In case you haven't heard of him, I came across Terry Engelder a few weeks ago and it looks like he's been into gas shale since the 70's when he was at the NRC looking into earthquakes and nuke plants.
"It was nuclear energy that first got me into gas shales. I worked for the Nuclear Regulatory Commission in the 1970s, which was concerned with mitigating earthquakes that could affect reactors in the Eastern US.
"I looked at fractures in gas shales. The connection is straightforward, remains the same to this day: earth stress controls the orientation of hydraulic fracturing for gas shales as well as natural fractures. The physics of the process is identical."
That's part of this short interview with him. http://thebreakthrough.org/blog/2012/01/terry_engelder_on_the_federal.shtml Thought you might be interested in his work if you haven't come across him.
Also, for those who are interested, he's going to be debating David Hughes, the author of the article that started this thread, in Tulsa on February 7. The debate is on hydraulic fracturing. Looks to be invitation only, but maybe it's not too late to get invited for those in the business. And not too far from Tulsa. Here's the link - http://www.utulsa.edu/academics/colleges/college-of-law/Centers%20and%20...
You really need to read the references provided contradicting this particular claim Rock, prior to spreading yet more bad information on the topic.
Paragraph 2. A nice old reference, because people have known otherwise for a LONG time.
"Devonian shale gas reservoirs typically are characterized by a low storage, high flow capacity natural fracture system FED BY HIGH STORAGE, LOW FLOW CAPACITY MATRIX ROCK"
http://www.pe.tamu.edu/wattenbarger/public_html/Selected_papers/--Shale%...
Banned: I just want to say one word to you. Just one word.
Rockman: Yes, sir.
Banned: Are you listening?
Rockman: Yes, I am.
Banned: Viscosity.
Bruce - You need to educate yourself about the difference between some of those Devonian shales and the other fractured shale plays. I suspect I've read more reports about the desorbtion of methane from those organic compounds in some Devonian shales than you probably know exist. Most of the hot new shale plays have no significant desorbtion of methane. I've drilled the New Albany Shale in KY and have recently posted about it. Guess you missed my explanation of how such formation can produce for 20 to 40 years with virtually no decline thanks to desorbtion. When you find the report highlighting the desorption of significant amounts of methane from the Eagle Ford please post.
Your original statement on the production from shales was general in nature. You should not generalize when such a statement is not true in Devonian plays at the least. And as I am sure you know, the Antrim and Marcellus fall into the Devonian as well. We aren't talking about just some old nitro-shot Ohio shale stuff here.
I suspect not all of us were stocking grocery shelves during the down years. I have no problem with desorption data from shales or using a Langmuir isotherm during any in-place calculations, but to state as fact that shales only involve fracture drainage is patently false. So is pretending that the only matrix storage is sorbed gas. You can satisfy yourself of this by simply examining the equations of decline in modern software or the reservoir equations behind Fetkovitch decline curve matching, or even the basics of dual permeability systems and how we build the simulators to account for such behavior. In some cases the sand face pressure isn't even reduced enough to activate a Langmuir dominated decline. Shallow stuff like the New Albany certainly might operate at low enough pressures to have a significant desorbtion component, in which case why would you spend all your time generalizing that there isn't at least ONE other storage mechanism in gas shales? Let alone the TWO others we account for when building reservoir and simulating matching programs?
I like your coherent style, Bruce_S. It's pretty difficult to come up with any kind of argument against all that. I think everyone has to just accept your explanation.
Unlikely.
So if I understand this correctly. This is a terrible time to be a dry shale gas driller. The prices for natural gas are very low and will go lower if people keep drilling. And even if dry shale gas drillers slow down, the price of natural gas will probably remain low due to all the by-product natural gas obtained by people drilling for (extremely valuable) liquid oil in tight shale deposits.
However, one good thing going for them is that many of the oil plays in shale are in the middle of no-where such that there are no nearby natural gas pipelines . . . thus the natural gas is just flared off.
BTW, flaring natural gas should be illegal IMHO. Given that all hydrocarbons are finite, it seems incredibly wasteful to just flare them.
Speculawyer,
I certainly agree with your first paragragh.
But, the natural gas flare off in U.S: oil fields is only temporary. When it is economical to capture all the gas, the oil companies will eventually do so. It's always the economy that ultimately drives everything in energy production.
spec - "This is a terrible time to be a dry shale gas driller." FWIW you can take this as a metric: as I've said before we don't drill the shale plays because we were making better profits from our conventional deep NG drilling. Now were cutting many of those projects from our budget. In anticipation of futher declines in NG prices we're in the process of modifying our biz plan and could eliminate almost or all of our NG drlling. Like I've said before: my owner is in this just to make a profit. We have no stock to hype or investors to skin. We just take his family's money and try to make a better return than he can get elsewhere. My emphasis is now turning to EOR from shallow Texas oil fields (most of which have been abandoned) by utilizing horizontal well bores. Fortunately I developed these skills long ago in the offshore GOM. OTOH my exploration cohorts are getting a tad nervous. My owner has great respect and affection for these guys. But that won't stop him from firing all of them. Just as the oil patch ain't the public's momma, he ain't my cohorts' momma either. Nothing personal...just business. LOL.
I have been looking for a softening of the completion market space, given the very public downturn in Marcellus, but so far there has been none, at least for us. Eagle Ford is still going gangbusters, and other wet plays are as well.
International remains strong, across the board, and the US is very strong for oil.
I think your plan of EOR is a good one, and we're seeing similar desires for source rock limestone and sandstone, for oil and oily gas.
There is very strong desire for production enhancement to reduce lifecycle decline curves and get more production from existing wells. This is still paying even for many dry gas wells. Companies are seeking to delay workover points and slide the cost picture away from major capital investment and toward keeping a field profitable and the gathering network going.
To me, this says they believe the drop is temporary, but I fear it could last a year or two at least, because there is a lot of gas coming along with the oil, and even the minor enhancements make a significant difference. Probably until we get a cold winter?
paleo - "To me, this says they believe the drop is temporary". I hope they're right but I'm not betting on it. IMHO this bubble began building back in '06 or so. As you know it takes a long time for volumes (reserves and rate) to change significantly. I had thought a drop in NG demand was a factor but when I pulled the numbers we're burning about as much NG as we ever have. It's all about oversupply these days IMHO. Between the pubcos drilling to keep their stock prices up and all those new LNG trains sitting on top of many TCF coming online around globe it's difficult for me to be optimstic. Some very cold weather up north might offer us some relief but longer term I think we're stuck with relatively low NG prices for a few years...at a minimum.
I think you may be right. I told my wife I thought we should put off getting a higher-eff HVAC unit and get a CNG vehicle instead. Might as well play the arbitrage the best we can, as electricity is not going to go up a lot while NG is cheap.
I continue to wonder if high oil will be sustained. So far the economy seems like it can handle $100 oil, but if that turns out not be true even the oil plays may falter. I think it's a pretty safe bet that there will be money to be made drilling hydrocarbons for the rest of my career in any case, though there may be a few hard years here and there.
I personally don't think the existing NG wells are going to drop as quickly as the first few frac fields did. Better understanding of the formations, coupled with ready deliquification, is likely to keep wells flowing at least a little better. We're seeing plunger and gas lift all over the place, to extract both water and oil fairly economically. Had one customer go from a -17% to a +2% YOY decline curve on his field, with fairly modest investment in EOR and no new drilling. I'm sure it won't hold, but every bump like that adds gas to the glut. Whether URR changes much is another question entirely, of course.
paleo - "I personally don't think the existing NG wells are going to drop as quickly...". Nor do I. The shale wells still have steep declines even with better techniques. But they still produce something. A new well might start at 6,000 mcf/day and decline 80%+ the first few years. But you can still end up with 20 such wells making 300 mcf/day each with a low DR. That's the same as one well making that 6,000 mcf/day but lasting a lot longer. There are many wells in the oldest NG in KY (a fractured shale play BTW: New Albany Shale) that produced their low rates with no decline for 25+ years. All those new fractured shale wells will establish a base load that will be rather stable. That's one reason I never gave serious consideration to concerns about US NG production "falling off a cliff". With NG prices drill rig count may be on the verge of falling off that cliff though. The last NG price plunge (late '08) crippled many shale gas players (Chesapeake, Devon) and put many others out of business.
BTW: an engineer just told me about a sweet spot an operator found in the Marcellus in PA. IP 36,000 mcf/day. I could live with an 80% decline rate on such a well. OTOH it wasn't cheap: 8,000' lateral and the 20 stage frac cost 3X what it did to drill the well. But still...
Rockman
Thanks for frank comments on the challenges and issues.
Do you have any suggestions on where I could find data on the production/running length of wells with liners for the peak (or average) oil or heavy oil compared with gas or shale gas? - and what type of distribution that shows?
I have heard a rule of thumb of about 1 bbl/day per m in oil sands. i.e. ten horizontal wells each 1000 m long on a well pad producing 10,000 bbl/day. I think that is at peak production.
David - No...no easy source for that data in general. You could put it together from various sources in a particular play but you would seldom get enough details (especially reservoir specifics). And every trend like the Eagle Ford and Marcellus there are sweet spots and not so sweet spots. Thus wells drilled exactly alike could vary greatly in two areas of the same trend. Then add the fact that not all operators are as good at getting the job done right.
Any rule of thumb will often be misleadng. First any generalization will vary greatly with the reservoir type: fracture shale, tight sandstone, porous limestone, porous sandstone. Take a fractured shale: productivity will ofetn be a function of the number of natural fractures penetrated more than any other factor. A 3,000' lateral might cut twice as many fractures as a 6,000' lateral just a mile away and produce 3X the volume of the longer well. In a conventional reservoir a 3,000' lateral in one reservoir might flow at twice the rate of a 6,000' lateral but not because the longer well couldn't flow at a higher rate. It wouldn't because the lateral in the longer well sits closer to the oil water interface and to avoid coning the water (pulling up water production prematurely) the operator intentionally produces the longer well at a lower rate.
Also be aware that anoperator may put out a big press release on a well with a great flow rate but isn't obligated to do so on less impressive wells.
ROCK, got any numbers on just what percentage of gas production is coming from older lower producing shale gas wells?
A new well might start at 6,000 mcf/day and decline 80%+ the first few years. But you can still end up with 20 such wells making 300 mcf/day each with a low DR. That's the same as one well making that 6,000 mcf/day but lasting a lot longer
This was the point I tried to make in my first comment days ago way up thread but I didn't state it near as clearly. Well it hit -50F at the airport this morning maybe my thoughts are flowing slower--kind of like gelled diesel ?- )
Luke - I've been trying to pull together such data for the Eagle Ford for the last couple of weeks but work keeps getting in the way. LOL. I also owe it to westexas and others. Over 600 wells have been completed in the last 6 years or so. But many won't have much production history beyond couple of years. But it should at least give some flavor to the situation.
I was hoping you were still trying to get that posted. Looking forward to seeing it. Just as soon as the thermometer budges upward a bit I've a bit of work to get moving on myself. Been darned cold up here since Christmas.
ARC Energy posts: Who is Eating at the Petroleum Club? - January 16, 2012
I think what's missing in that assessment (cheap vs expensive), and this is just hand waiving, is that it doesn't take into account the miss rate or dry holes. As I understand it, one effect of lateral and frac is that they rarely miss anymore, as compared to traditional verticals. So an operator might well find that the high well count per unit production drilling expense, today, is just as affordable as the lower count per unit production, plus dry holes, from years ago.
A problem like this one was once solved by the Texas Railroad Commission. What are the prospects for regulatory control of the natural gas sector, in an effort to stabilize production and prices?
Socialist!
I really don't think you could get away with that kind of market control today. There is a hardcore free-market ideology soaking up mindshare these days that I just can't see anything like that happening in the current political climate.
spec - The Texas Rail Road Commision still has authority to set production limits. They meet once a month to set proration rate. Since the early 70's every month they've set the rate at 100% of a well'ss capability. If for what ever reason they decided to cut Texas oil production in half all they need do is set the proration at 50%. Needless to say the political ramifications would be huge. But every oil producer in Texas would comply with the order until some higher authority brought legal action against the TRRC and imposed a court order. If an oil company violated proration orders it wouldn't be the first time Texas Rangers showed up in a company's office and hauled someone away in cuffs. I saw such first hand once long ago. When they say "Don't mess with Texas" what they are really saying don't mess with the TRRC. LOL.
Are we still importing natural gas from Canada?
http://205.254.135.24/dnav/ng/ng_sum_lsum_dcu_nus_a.htm
Yes. US monthly net imports (Oct) were ~168 bcf over total US consumption of 1741 bcf, or ~10% net imports. The largest share of that comes from Canada.
The US is still importing nearly 4 trillion cubic feet of gas per year, the vast majority of it from Canada. Canadian production NG is falling, but not very fast, and new US production is more than making up for the decline.
Before you read too much into the Canadian production decline, it's worth noting that Canada has vast amounts of shale gas, but at current depressed prices it's unlikely many wells will be drilled. Canadian shale gas development has been somewhat more rational than that of the US, where a lot of the shale gas is being produced at a loss these days.
The US has also started exporting a lot of natural gas recently. Most of this goes to Canada and Mexico. Canada has started diverting its own natural gas into its oil sands plants and burning US natural gas in its homes and powerplants instead.
Yes, down from an import peak of 4.5 tcf/year in 2007, while at the same time exporting over 1 tcf/year as you point out at the bottom, and rising.
http://www.eia.gov/naturalgas/importsexport/annual/index.cfm
Imports from Canada would have declined in any case because gas production in Alberta (the main source) peaked around 2000 and has been declining ever since. Alberta has been in the process of curtailing removals from the province and exports to the US, while diverting the remaining gas to domestic consumers.
It's a good thing that the US has a recent surplus of shale gas production because otherwise the US government might have noticed they were being curtailed and gotten upset. As it is, it looks like Eastern Canada is making up for its reduced supply of NG from Alberta by importing cheap NG from the US. Smiles all around.
It looks kind of rosy from the US perspective, until you realize the US gas is being exported at very low prices, often below replacement cost. Meanwhile the US is importing oil at 4 or 5 times the cost of the exported NG on an energy-equivalent basis. It's the "buy high, sell low" approach to going broke.
In a more rational country the government would raise gasoline and diesel fuel taxes to high levels, while subsidizing the conversion of home heating and transportation to NG, but US tax and energy policy hasn't been rational for a long time.
the US gas is being exported at very low prices, often below replacement cost.
How are Canadian gas exports to the US priced?
Canadian gas exports to the US are priced at US market price FOB some delivery point in the US. The Canadian price at the wellhead is the US price less transportation costs and overhead. That is why Alberta natural gas is selling for $2.12 at the moment, whereas US gas is about $2.75.
$2.12. Ouch! Nobody can make money on it at that price.
(I'm fudging the comparison somewhat because Canadian measurement units and dollars are somewhat different, but close enough for illustrative purposes).
What are the transportation costs for Natural gas?
Coal is selling on the NYMEX for $61/TON for 1200BTU/lb coal. So this comes to $2.66 per million BTU. This seems very cheap to me--A truckload of coal costing 13-1400 dollars. If it moved by truck the freight costs could quickly become higher than the value of the cargo if it had to move any distance.
It doesn't cost very much to move gas by pipeline. If the price is $2.12 per 1000 cu. ft. at the AECO hub in Alberta and $2.75 at the Henry hub in Louisiana, you can assume it costs 63 cents to move 1000 cu. ft. of gas from Alberta to Louisiana, it being a competitive market and all. 1000 cu. ft. has about 1 million BTU of heat content, so it's about 63 cents per million BTU to move natural gas across the entire US north to south.
That's just a ballpark estimate. In reality it is very complicated to figure out the price.
As you can see, it's a lot cheaper to move natural gas long distances than coal. That's the main economic problem with coal - it's very expensive to transport long distances except by sea.
For natural gas, I think the guideline is that you would have to transport it at least 3000 miles by pipeline before it would be cheaper to ship it by sea as LNG.
With New Super-Fracking Advances, The Shale Revolution Might Be Just Getting Started
http://www.dailymarkets.com/economy/2012/01/22/with-new-super-fracking-a...
Even if all the things that people just have to sign up to tell us here were true, all they really show is just how desperate we're becoming. The easy stuff is gone and we're going after what's left at much higher prices and levels of difficulty.
"Super-Fracking"? Is that anything like the massive hydraulic fracturing techniques we used to use on our wells decades ago?
One way you can tell the amateurs from the professionals is that they use the spelling, "frack" instead of "frac". In the oil patch, we never heard the word "frack!" used except on the Battlestar Galactica when the Cylons were bearing down on them. I think the MSM invented it to sound like they knew something.
Rocky,
Not quite true. The spelling change originally came from the environmentalists, who changed the spelling to emphasise the "derogatory" nature of frac'ing. Then the media picked up on it. Now, it's gone mainstream. I used to fight it many years ago, but soon realized it wasn't worth it. So, I spell it fracking too, just because everyone else does, except for most of the oil industry.
Professional does not mean expert or even informed, it just means you are paid for what you do, as in a professional burger flipper. Amateurs do not get paid for what they do, but they might be experts in what they do, or very well informed.
Now that you have read the article, what do you think about the new "Super-Fracking" technologies?
Gee, I wonder if it's the evolution in fracking technologies, that is behind the ever increasing average EUR per Bakken well, or if it's only just someone's imagination, that's causing all these well documented wells to increase their output by so much.
Now that you have read the article, what do you think about the new "Super-Fracking" technologies?
It sounds a lot like what we used to do, only the techniques have become more refined. However, the author doesn't really know what he is talking about, so it's hard to be sure.
The big advance was horizontal drilling. Frac'ing we always did, but the horizontal drilling techniques have made a major difference in the amount of oil that can be recovered from one well.
Gee, I wonder if it's the evolution in fracking technologies, that is behind the ever increasing average EUR per Bakken well, or if it's only just someone's imagination, that's causing all these well documented wells to increase their output by so much.
It's a combination of high prices, improved technology, and cost control. They've known the Bakken Formation was there since the 1930's, but the price of oil was not high enough nor the technology sufficiently cheap to make exploiting it worthwhile.
Now, exploiting it is worthwhile, but it's not really a new oil field. It doesn't change the production peak, it just puts a fatter tail on the downside of the production curve.
Face it, the US has already produced most of its oil, and the objective now is to suck the last remaining oil out of the ground as efficiently as possible, and hopefully make money while doing so.
US production overall is rising. It's not rising dramatically fast, but it is rising - that's not a fat tail, it's something different.
I think what you see, and I think someone else mentioned this, is that unlike previous region-by-region Hubbert curves that took place in a world where there was some other place cheap to drill, now we are seeing somewhat steadier high prices, and that makes previously unprofitable fields profitable, either again, or for the first time. So rather than a thin tail, you'd expect to see a fat tail (in this case, a fattening tail!), but with higher prices. No doubt someone with better information will contradict me.
As to WTF is going on, my explanations would be all hand-waving. You'd expect that cheap oil running short of demand would force prices up, which would in turn open up previously unprofitable fields, but why not everywhere, why is the increase in production not enough to knock the price back down? Demand growing too fast? Easier/cheaper to deploy the new fancy techniques closer to home? Not optimistic about entering into a partnership with Putin or Chavez? Saudis happy to let prices float high?
Rocky,
Yes, the author is actually not very informed. I am familiar with him. He is a bit of a parrot, but he might be correct in whatever it is he is parroting. He does try to sensationalize everything. The article was actually not very up to date, or that informative. It was just an introduction to the subject.
Can you explain how high prices and cost control increase EUR per well? Improved technology, yes. But, not the other two.
"It doesn't change the production peak,"
As U.S. oil production has been going up, how does that not change the "production peak."
"Face it, the US has already produced most of its oil,"
Nope, it's not over until it's over, and YOU sure don't determine when it's over, but apparently you actually think that you do. I think you are way overdue for a reality check. You really don't determine much of anything on this planet. Sorry.
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I like to use the politically correct term of "induced hydraulic fracture". That way nobody throws paint on me!
Anthropogenically induced hydraulic fracture (AIHF) is probably more accurate since an hydraulic fracture can be naturally or anthropogenically induced !
Wandered over to gregor.us, and noticed a perhaps-relevant post on the low price of natural gas in the US.
http://gregor.us/americas/for-a-million-btu/
Once pipelines to the rest of the world market are complete, drilling for NG will be a more attractive investment.
And whoever is losing money now probably figures that will happen soon enough, when compared to the cost of shutting down a drilled well and restarting it later.