This post was originally posted at my blog “Fractional Flow”.
In this post I present an update to my previous posts over at The Oil Drum (The Red Queen series) on developments in tight oil production from the Bakken formation in North Dakota with some additional estimates, mainly presented in charts. The expansion is much about the differences between wells capable of producing, actual producing wells and idle wells (here defined as the difference between the number of wells capable of producing and the number of actual producing wells).
There is still noticeable growth in tight oil production from an accelerated additions of producing wells.
- For October 2013 North Dakota Industrial Commission (NDIC) reported a production of 877 kb/d from Bakken/Three Forks.
- In October 2013YTD production from Bakken/Three Forks (ND) was 775 kb/d.
(It is now expected that average daily production for all 2013 from Bakken (ND) will become around 800 kb/d. - The cash flow analysis now suggests less use of debt for manufacturing wells for 2013.
Major funding for new wells now appears to come mainly from from net cash flows.
kb; kilo barrels = 1,000 barrels
MODELLED VERSUS ACTUAL PRODUCTION
![Figure 02: The colored bands show total production [production profile for the “2011 average/reference” well multiplied by the net number of producing wells added during the month] added by month and its projected development (lh scale). The white circles show net added producing wells by month (rh scale). The thick black line reported production from Bakken (North Dakota) by NDIC (lh scale). The chart also shows forecast developments for total oil production with respectively 1,500 (red dotted line) and 1,800 (light green dotted line) reference wells added annually through 2013 and 2014. The model was calibrated to start simulations as from January 2010. NOTE: The chart shows the models forecast towards 2025 from the population of producing wells as of October 2013. Producing wells will continue to be added, thus actual future production will be higher.](http://fractionalflow.files.wordpress.com/2013/12/02-modelled-versus-actual-oct-13.png)
The chart also shows forecast developments for total oil production with respectively 1,500 (red dotted line) and 1,800 (light green dotted line) reference wells added annually through 2013 and 2014.
The model was calibrated to start simulations as from January 2010.
NOTE: The chart shows the models forecast towards 2025 from the population of producing wells as of October 2013. Producing wells will continue to be added, thus actual future production will be higher.
The forecasts with 1,500 and 1,800 “2011 reference” wells added through 2013 and 2014 (with baselines of Janaury 2013) also serves as additional references that may be indicative of directional changes in average well productivity.
If the model over time develops a growing deficit against actual reported production, this could suggest that newer wells have an improved well productivity relative to the reference well and vice versa.
The chart shows a deficit between modelled and actual production during 2010 which also demonstrates higher average well productivity in 2010.
The model estimated a decline in total production from the wells capable of producing in October to November to around 40 kb/d and that it now takes the net additions of 120 – 125 reference wells per month for the next few months to sustain the October production level. This is exclusive of any seasonal effects of increase in the number of wells shut in (idled) due to weather related causes.
For what it is worth the model estimated that total production from the producing wells (Bakken (ND)) as of October 2013 to October 2014 (year over year) would decline by 318 kb/d or 37%.
POSSIBLE EXPLANATIONS FOR DEVIATIONS BETWEEN MODELLED AND ACTUAL PRODUCTION
To smoothen any seasonal swings from seasonally (temporarily) shut in wells a 12 Month Moving Average (12 MMA) has been added (dark red line).
How to read the chart: If modelled total production is higher (above 100%) than actual, this may suggest that newer wells added on average has a “poorer” productivity than the “2011 reference” well and vice versa.
A likely explanation for the recent deviations is that during winter a relatively higher number of wells get shut in and are not brought back to flow before the spring. The model does not recognize these events and continues to add flow from these wells wherever they were expected to be on their flow curve. This may cause wells added during winter to appear as slightly poorer than they really are as the model sees less flow from the added wells relative to the reference well. Conversely as the situation allows (coming out of winter), the shut in wells are gradually brought back to flow, the model will not recognize this, and new wells added may therefore look somewhat better than the reference well.
Wells in conventional oil reservoirs tend to flow somewhat better for some time when started up after being shut in (rested) for some time. Wells in tight oil formations should be expected to exhibit a similar behavior and thus have temporarily improved flows (gush) when restarted.
It is difficult to predict at what point in a well’s productive life it becomes temporarily shut in, when this happens and how long the shut in will last. It is possible to use actual data to make an approximate model that describes the distribution of wells in time and durations and thus get an estimate of how this affects total production.
Winter, due to accessibility issues, appears to cause an increase in the number of wells shut in and shut in periods could be as long as 3 to 4 months. This winter 4 – 500 wells are expected to become subject to seasonal shut ins. With time and as the total number of wells capable of producing grows, it should be expected that a higher number of wells may be subject to seasonal shut ins, ref also the section “IDLE WELLS” below.
From GrandForksHerald:
“It’s pretty significant when you think about 400 or 500 wells being shut off for three to four months,” Helms said.
Other effects may be that in some months the average for the added wells are somewhat better than the reference well, and other months somewhat poorer. However if a trend in any direction develops over several months, this may suggest a change in well productivities relative to the reference well used for the model.
ESTIMATES ON NET CASH FLOWS FROM WELL ACTIVITIES
The assumptions for the chart are WTI oil price (realized price), average well costs starting at $8 Million in January 2009 and growing to $10 Million as of January 2011 and $9 Million as of January 2013. All costs assumed incurred as the wells were reported starting to flow (this creates some backlog for cumulative costs as costs in reality are incurred continuously as the wells are manufactured) and the estimates do not include costs for completed non- flowing and dry wells.
Economic assumptions; royalties of 15%, production tax of 5%, an extraction tax of 6.5%, OPEX at $4/Bbl, transport (from wellhead to refinery) $12/Bbl and interest of 5% on debt (before any corporate tax effects).
Estimates do not include any effects of hedging, dividend payouts, retained earnings and income from natural gas/NGPL sales (which now and on average grosses around $3/Bbl).
Estimates do not include investments in processing/transport facilities and other externalities like road upkeep etc.
The purpose with the estimates presented in the chart is to get an approximation of net cash flows and development of total debt used.
The chart suggests that so far in 2013 capital expenditures (CAPEX) for added producing wells has mainly been financed from the net cash flows from the existing population of producing wells. Use of debt appears to have noticeably slowed. As these estimates are for all added wells in the Bakken (ND) it should be expected that there are differences between the operating companies.
In 2013 an estimated $20 Billion may be used for manufacturing tight oil wells and construction of associated facilities in North Dakota.
THE 4 COUNTIES WITH THE BIGGEST PRODUCTION
Here follows a closer look at tight oil production developments from Dunn, McKenzie, Mountrail and Williams which now are the 4 counties in North Dakota with the biggest tight oil production. NDIC is now reporting oil production from 17 counties and the 4 counties with the biggest production now has around 85% of the total oil production in North Dakota.
- As from 2008 and through 2012 Mountrail was the county that provided the biggest portion of the production from Bakken (ND).
McKenzie is now the county with the biggest production portion from Bakken (ND), refer also figures 05 and 06. - The major portion of growth in tight oil production from the Bakken is now expected to come from McKenzie county as the other counties now have slower growth, refer also figures 05 and 07.
- Mountrail with prolific fields/pools as Alger (refer also figure 09), Parshall, Reunion Bay, Sanish (refer also figure 10) and Van Hook appears to have a slow down in production or are in decline.
- Mountrail took over from McKenzie as the county with the highest well density in mid 2010 and still keeps this position, refer also figure 15.
- McKenzie now provides for around half of the annualized production growth from these 4 counties.
Figure 06 shows that the growth in oil production from Williams and Mountrail has slowed down while there is good growth in oil production in Dunn and McKenzie.
To better visualize the underlying trends for oil production from these 4 counties the developments described by 12 MMA (annualized) was applied as shown in figure 07 below.
By using 12 MMA it becomes clearer that growth in production in Williams and Mountrail is slowing, while growth is lead by McKenzie followed by Dunn.
THE OTHER COUNTIES IN NORTH DAKOTA
For the other counties in North Dakota three counties, Divide, Stark and Burke saw some growth in oil production starting back in 2010. Recently only Divide continues to show growth.
DEVELOPMENTS FOR 2 POOLS IN MOUNTRAIL
In figures 6 and 7 it is shown that in recent years Mountrail was the county that lead the growth in oil production starting back in 2008. Note the decline in production following the collapse of the oil price in 2008. More recently the growth in production in Mountrail has slowed down. Mountrail is where prolific pools like Alger, Parshall, Reunion Bay, Sanish and Van Hook are found.
NOTE: The chart does not include wells and production from wells on confidential list.
During the last year and despite a high number of wells added, production in Alger has been in decline.
NOTE: The chart does not include wells and production from wells on confidential list.
A FEW NOTES ABOUT WELLS
The monthly statistics in the public domain from NDIC on changes in the total number of producing wells does not distinguish between flows from wells flowing for the first time (“virgin” wells) and wells that were capable of flowing and for some reason and duration was idle and brought back to flow.
- North Dakota Industrial Commission (NDIC) reports show that the number of net added producing wells in the Bakken, Sanish, Three Forks and Bakken/Three Forks pools increased by 195 from September to October.
- NDIC reports show that the number of wells actually producing increased by 199 in North Dakota from September to October of which 154 was in the 4 counties with the biggest production.
- NDIC reports show that the number of wells capable of producing increased by 161 in North Dakota from September to October, of which 122 was in the 4 counties with the biggest production.
- NDIC reports show that at anytime 9 – 10% of wells capable of producing are idle.
Idle wells are here meant to describe the difference between wells capable of producing and wells actually producing. - McKenzie now has around one third of the rigs drilling in Bakken (North Dakota) and provides more than half of the growth in tight oil production for the 4 counties with the biggest production, refer also figures 06 and 07.
The numbers of wells capable and actually producing includes wells on confidential list.
How many new (“virgin”) wells were brought in during October 2013?
WELLS CAPABLE OF PRODUCING
In the chart above note the recent acceleration in wells additions for McKenzie.
In Williams there is a decline in added wells capable of producing, this is also reflected by slower growth in production as shown in figures 06 and 07.
Dunn and Mountrail see a relatively constant addition of wells reflecting a slower growth in production.
Mckenzie has good growth in wells capable of producing which is also reflected by growth in actual production.
WELLS ACTUALLY PRODUCING
Data from NDIC for McKenzie shows that in September 2013 was an increase of 32 actual producing wells and an increase of 60 wells capable of producing.
How should the difference between the increase in the numbers of actual producing and capable of producing be interpreted?
WELL DENSITY (Wells capable of producing)
For what it is worth a chart showing the development of well density for the 4 counties with the biggest production has been included.
1 square mile = 640 acres
Highest well density is now in Mountrail followed by McKenzie which appears to catch up. McKenzie had the highest well density until Mountrail took over in mid 2010 and Mountrail still has the highest well density despite the lowered drilling activity.
All the areas in the 4 counties with the biggest tight oil production should not be expected to have an ubiquitous productivity. There will also be a limit to how close the wells may be drilled without causing interference.
Promoters of the oil industry who claim that production in the Bakken region will continue to increase for many years to come appear to assume that the area outside of the 4 main counties (Dunn, McKenzie, Mountrail and Williams) will be as productive as within these 4.
IDLE WELLS
Idle wells are here defined as the difference between wells capable of producing and wells actually producing. At any time a number of wells capable of producing will be shut in for some reason, ref above the discussion about deviations between modeled and actual production.
As the total number of wells with time increases it could be expected that an increasing number of wells will become subject to seasonal effects, making it more demanding to bring these back to flow as condition permits.
Mckenzie has the highest number and biggest portions of idle wells, and as of October – 13 around 11% of the wells were idle. McKenzie has been and is the county with the highest portion of idle wells which may be a seasonal accessibility issue.
Effects from wells temporarily shut in (idled) will reduce cash flows and returns.
—-
Red Queen posts on The Oil Drum:
Is Shale Oil Production from Bakken Headed for a Run with “The Red Queen”? (Sep 25 2012)
Reposted (Jan 01 2013)
Is the Typical NDIC Bakken Tight Oil Well a Sales Pitch? (Apr 29 2013)
Maugeri Misses Bakken ”Red Queen” (Aug 05 2013)
When an oil driller is said to be ‘operating from cash flow’ or not borrowing against its own account it means it is borrowing against its customers’ accounts, instead.
The customers are borrowing from their bosses’ customers’ banks, whose customers are borrowing in turn from other customers’ banks … whose bosses are doing the same thing. This is our economy: interconnected daisy chains of loans, most of which are unsecured. From the standpoint of the driller, all funds are borrowed, the issue is the effect of the drillers’ costs on the customers ongoing ability to borrow.
With the world price of oil @ $110 more or less, the effects are profound … as the more costly oil does not produce any more goods or services than did the cheaper fuels of twenty years ago. We pay more and the costs bankrupt us an inch at a time.
Hello Steve,
If the boundaries for the analysis (and thus the post) were expanded I would agree with your observation.
I covered this issue in a recent post; http://fractionalflow.com/2013/12/14/a-closer-look-into-the-drivers-of-the-norwegian-economys-recent-growth-success/
From the post linked above:
Presently many oil companies have bet their financial future on consumers’ abilities to continue to go deeper into debt in order to buy the more expensive oil (from more exotic areas like the Arctic) which will allow the oil companies to retire the debts acquired for the developments of these sources.
Hi Rune,
If you look at the history of the four big counties (McKenzie, Mountrail, Dunn, and Williams) you will see that not all of the wells are Bakken/Three Forks wells.
https://www.dmr.nd.gov/oilgas/stats/McKenzie.pdf
McKenzie had about 600 producing wells in 2005.
https://www.dmr.nd.gov/oilgas/stats/Mountrail.pdf
Mountrail about 50 producing wells in 2005
https://www.dmr.nd.gov/oilgas/stats/Dunn.pdf
Dunn had roughly 100 producing wells in 2005.
https://www.dmr.nd.gov/oilgas/stats/Williams.pdf
Williams had about 400 producing wells in 2005.
The total wells was about 1100 to 1200 producing wells in 2005, but there were only about 190 producing wells in the Bakken in Jan 2005. So the number of wells in these counties that are “Bakken/Three Forks wells is not clear cut. In other words not all wells in these four counties have been drilled into the Bakken or Three Forks formations. Mckenzie in particular and Williams to a smaller degree have a lot of older wells that are likely marginal. These may be some of the wells that are “capable of producing”, but have been shut in. When these well are producing, they probably produce less than 10 barrels/day.
I checked the numbers at https://www.dmr.nd.gov/oilgas/mpr/2005_01.pdf see page 2.
Jan 2005 Dunn- 99, McKenzie-656, Mountrail-53, and Williams-343 producing wells for a total of 1151 wells, according to https://www.dmr.nd.gov/oilgas/stats/historicalbakkenoilstats.pdf there were 188 producing wells in the Bakken /Three Forks in Jan 2005 so 963 of the wells in these four counties were not Bakken/Three Forks wells in Jan 2005, about 2/3 of these wells may have been McKenzie wells and most of these would have been 20 years old in 2005 and close to 30 years old today (look closely at the chart for Mckenzie county).
DC
Hello Dennis,
The charts (as from “The 4 Counties with the biggest Production”, figure 05) does not say that all the wells are in the Bakken/Three Forks formations for the 4 counties presented. Most of the wells in these 4 counties are believed to be producing from the Bakken/Three Forks formations and a major portion of the production comes from the mentioned formations.
Directors cut for December 2013 says that more than 95% of the wells drilled are targeting the Bakken/Three Forks formations.
That chart for McKenzie County clearly spells out the influence from the newer wells.
– Rune
Hi Rune,
I was mostly looking for a possible explanation of the difference between the percentage of idle wells in McKenzie vs. the other 3 counties which you focused on. Note that figure 17 is labelled “Bakken Developments …”, and there is a noticeable difference in McKenzie County vs the other 3, of the 2200 wells producing in McKenzie County, it is possible that 600 of these are not Bakken wells. As far as figure 17 we really don’t know what percentage of the idle wells are Bakken/Three Forks and which are in other formations. It seems likely that the older wells from before 1993 (and that are now 20 years old or more) may be a large proportion of the idle wells in McKenzie and Williams counties.
I don’t have access to drilling info which might break down Bakken/Three Forks wells from wells in other formations in the various counties.
There is also the possibility that some “idle wells” may be capable of producing but are waiting on fracking services, Lynn Helms suggests this number may be about 450 wells.
Also note that the 95 % of drilling being in the Bakken, that applies to new wells and ahs probably been the case since about 2009. Note that before the Bakken took off there were about 3000 wells producing from areas of North Dakota besides the Bakken/Three Forks in Jan 2005, and that number remains about the same today. My contention is that a large proportion of idle wells may come from this non-Bakken group of wells.
DC
Hello Dennis and thanks.
Figure 17 has a mislabeling in the header and should read North Dakota and NOT Bakken.
Only sure way to find the split between idle wells in Bakken/Three Forks and others is by going through the monthly records for each well (which is very time consuming).
For some of the wells I have followed the life of in Bakken/Three Forks I observed that some wells became shut in soon after they were started. Other wells had water and natural gas production reported for some months, but no oil production. Why, I do not know.
So apart from the split on idle wells in Bakken and others it has value to get estimates on how much (total) production has been shut in.
A well capable of producing is capable even if it is not fracked. Therein lays the possibility that the effect from the actual backlog may be less than perceived.
– Rune
Hi Rune,
Do you have access to drilling info? I thought the info might be found there. Tou are correct that going through the monthly reports for individual wells would be way too much work, its too bad that the NDIC does not put their monthly report in Excel format, then it would be easy to sort this info out. I suppose someone could convert the PDF to an excel format, but I don’t know how to do that.
On the well density chart, if we assume that 600 of the 2200 wells in McKenzie county are not Bakken/Three Forks wells, then the well density in the Bakken/Three Forks would be 0.65 wells per square mile in McKenzie County, so there may be room for another 800 wells in McKenzie before it levels off the way Mountrail has (assuming a similar density will work as well in McKenzie). If we assume 50 wells per month or 600 wells per year are added in the Bakken/Three Forks of McKenzie County, then output may level off in 16 months in that county.
I definitely agree that the areas outside of the sweet spots are likely to be less productive (lower average well EUR). In addition, the closer spacing that Continental Resources is experimenting with is also likely to reduce the average well productivity (EUR30). My guess is that we will see the average well EUR30 in the Bakken decrease by June 2015 (possibly earlier).
DC
DC,
NDIC lists regularly active rigs with well ID and county. From what I have seen of public NDIC data, only way to find number of wells by formation and (approximate) start of flow is by going through the monthly production reports.
Hi Dennis – I think I can convert PDF to to excel, if send me the file.
That model of forecast and production reminded me of one of my favourite movies of my youth. Jaws.
How many straws will fit into that 4 county shake? Very thorough analysis. Thanks.
Paulo
Paulo thanks,
The idea behind showing development in well density, ref figure 15 was in an effort to illustrate that somehow there are (area) limits to how many wells may be drilled into the ground. How this will translate into well spacing for Bakken I note there is a discussion about, and further it could be expected that all areas do not have equal productivity.
– Rune
Rune, I’ve seen many graphs showing tight oil production entering a steep decline for a few years followed by a multiyear or multidecade tail where the production declines very slowly. Any idea what drive mechanism keeps the oil flowing during all these years? Is it simply oil leaking into the wells from the overlying oil bearing strata by gravity?
And are the oil extractors going to use water flooding or other pressure maintenance techniques, or maybe even artificial lift, at some point in the well life? Just curious on what will happen once all the sweet spots are drilled out.
There may be a combination of drive mechanisms like gravity and geological overpressure. How fast oil flows to the wells will be related to natural phenomena (porosity and permeability), moveable oil and how differential pressure develops with time. Liquids/gases will flow towards the point with the lowest pressure. I note there are discussions going on about the dominant factors influencing future flows.
Using flooding for tight oil formations (keeping in mind porosity and permeability) appears to me to be a very challenging (and expensive) undertaking. One of the reasons is how to control the flood (injection fluid), irrespective of drive medium, which acts like a piston pushing the petroleum liquids towards the well.
Using a pump is one way to lower well pressure to increase/maintain a “low” well pressure to assist oil farther away (the well) to flow into the well and be “pumped” out.
– Rune
An interesting question. Ten years after initial production, a lot of models confidently show this or that amount of oil flowing — but do we have any hard data for what happens in actual Bakken shale wells 10 years after IP?
As far as I know extensive drilling for light tight oil with horizontals and multistage fracking is something that really took off as from 2008.
So as of now there are few wells that have a production history of 10 years or more from formations like Bakken and Eagle Ford.
Hi Watcher,
Current LTO production in the Bakken uses 2 mile laterals and 30 fracking stages, this method has only been in use since 2009 (or maybe 2010), so we only have data on a few wells (maybe 200 or so) since 2010, anything beyond these 3 to 4 years is only a guess as far as the shape of the well profile. Some of the estimates use a hyperbolic profile with b exponents of as much as 1.4 and ERR30 of about 450 kb, others suggest a thinner tail with ERR30 of 280 kb, my guess is that the average well profile will be somewhere in the middle with an ERR30 around 360 kb. Nobody knows the answer, time will answer it. Note that ERR30 is the 30 year estimated ultimate recovery.
DC
Aren’t tight oil wells already being capped, just a few years after coming online? Or are these just temporary shut in because of weather issues? But of course you’re right, it may very well take years to find out if those long tails on the graphs are real or not.
Hi frugal,
There may be a few wells that are shut in after just a few years, my guess would be that it is a low %, Rune has looked at the data much more closely than me. I have noticed that some wells produce only Nat gas, with low prices these are more likely to be shut down and may be a part of the idle well count. Again the numbers are a low %, probably on the order of 1%.
DC
Bingo. That non zero tail on the long term well production models may be bogus, and with huge well count those levels DO matter for production growth in the somewhat near term.
Meaning, if you have 1000 wells producing 100 bpd, that’s 10% of the total. I think truck trips to load up oil from tanks are not free. They don’t cost $10,000 / day (100 X $100), but we might very well see cap and abandon at 30 bpd. And that makes those tails go to zero, not a gentle low level asymptote.
Hi Watcher,
If you look at the NDIC stats for the Bakken and compare it with all of North Dakota you will find that there are about 3200 wells that are not drilled into the Bakken or Three Forks formations. These wells produce only about 66 kb/d collectively or on average about 20 barrels per day, so in North Dakota in general, a well can go pretty low (my guess would be 5 b/d) before being shut in. The same rules may not apply to horizontal multifracked wells, we really don’t know, but some of the older shale gas plays may give some clues as Jeff Brown has pointed out once or twice 😉
DC
Resilience had this in a roundup…
Wyoming May Act to Plug Abandoned Wells as Natural Gas Boom Ends
DAN FROSCH, NY Times, Published: December 24, 2013
State Senator John J. Hines, a Republican who represents mineral-rich Campbell and Converse Counties, said it was vital for lawmakers to take up the issue swiftly, because natural gas was so important to Wyoming’s economy.
“All of this just came to a head at once,” said Mr. Hines, who heads the Senate’s minerals committee.
Last spring, Mr. Hines was told by Patriot that the hum of gas drilling activity on his own sprawling cattle ranch would soon grow quiet.
Soon after, the company, which leased parcels of Mr. Hines’s land, disappeared completely — leaving behind more than 40 coal-bed methane wells and a jumble of pipes and pumps.
“They informed me that they were shutting down because they were short of funds,” Mr. Hines said. “All of it, in my opinion, needs to be cleaned up.”
Those who have fun at other’s expense aren’t likely to stick around and clean up after the party’s over.
Googling around I found The Stripper Well Consortium, so there may be future life for those wells:
The SWC is an industry-driven consortium that is focused on the development, demonstration, and deployment of new technologies needed to improve the production performance of natural gas and petroleum stripper wells. SWC is comprised of natural gas and petroleum producers, service companies, industry consultants, universities, and industrial trade organizations.
http://www.energy.psu.edu/swc/aboutswc.html
According to the DOE’s Energy Lab:
“Stripper well” is a term used to describe wells that produce natural gas or oil at very low rates—less than 10 barrels per day of oil or less than 60 thousand cubic feet per day of gas.
Despite their small output, stripper oil and gas wells make a significant contribution to the Nation’s energy supply—and they are the lifeblood of thousands of small, independent oil and gas operating companies.
About 80 percent of the roughly 500,000 producing oil wells in the United States are classified as stripper wells. Despite their small volumes, they add up. The >400,000 stripper oil wells in the United States produce, in aggregate, nearly 1 million barrels per day of oil, which represents almost 19% of domestic oil production.
In 2002, the number of domestic stripper gas wells in the United States grew for the eighth straight year, to nearly 246,000. These wells account for 1.4 trillion cubic feet of natural gas production per year, or roughly 10% of all onshore production in the Lower 48 states. Overall, stripper wells are quickly becoming a critical element in meeting near-term increases in gas demand: increased stripper well production accounted for 43% of the overall rise in domestic production during 2001-2002.
Given their low production rates, stripper wells typically are marginally economic properties. And with each passing year, the economics continue to degrade. In particular, proper disposal of increasing volumes of produced water adds significant cost burdens to the well. Eventually, the well ceases to be profitable and is plugged and abandoned. In 2002, operators abandoned 3,870 gas wells, even though most of these wells were still producing some gas. Once these wells are abandoned, the remaining gas resources typically are lost forever.
http://www.netl.doe.gov/technologies/oil-gas/swc/stripperwell.html
Perhaps there is still money to be made on the last drops and gasps of a dying well.
Now if we could only find out find how many of these stripper wells are from shale plays.
I also found this – Department of Energy to Sell Naval Petroleum Reserve Number 3 (NPR3).
Casper, WY.
– The Secretary of Energy reported to Congress the Department’s intent to sell all
right, title and interest in NPR3 through a public competitive bid process on the open market.
NPR3, run by RMOTC, is the last U.S. Government-owned operating oil field and is more
commonly known as the Teapot Dome.
http://www.rmotc.doe.gov/PDFs/20130715_RMOTC_PressRelease_DispositionandSale.pdf
An interesting read.
http://www.rmotc.doe.gov/PDFs/EXEC-2013-000936%20signed-dated%20ltrs%20and%20Report.pdf
Thanks, Rune, for this detailed account. When I consider this and other articles, by yourself, Dennis, Art Berman & others, both here and back @ TOD, I cannot help but wonder at all the attention (here in the PO blogosphere, at least) given to a an oil field – the Bakken – whose production amounts to only about 1mbd, somewhere between 1-2% of the global total. The attention here and the hype & excitement out in MSM land to such a bit player overall seems clear evidence of PO to me…
The Bakken tight oil developments have been truly amazing to follow, and in many ways we should be grateful for its contributions to global supplies.
What appears to be poorly understood is that this is expensive oil like several of the recent developments in the North Sea (on a full cycle basis) and that the high oil price does not automatically translate into high (financial) returns.
Another thing to ponder is that a portion of these new supplies comes from sources that are sensitive to the oil price and that a moderate decline in the oil price would as an effect slow down capital expenditures for new wells/developments and thus make it harder to sustain present supply levels.
Light Tight Oil (LTO) has an API gravity of 36 – 44 which also translates into lower volumetric energy content. How refined LTO yields marketable products like gasoline etc. I have so far not seen any figures of.
– Rune
One of the comment threads here on this site quotes an article noting the outright scarcity of diesel and kerosene fractions in Bakken output (compared to Bonny Light) , and almost no diesel and kerosene fractions (5% vs Nigeria’s 23%) in Eagleford “oil”.
No search here: It’s http://peakoilbarrel.com/u-s-monthly-energy-review/#comments
Scroll to toolpush comment starting with “Exception #4”. The article itself is behind a registration firewall.
Hello,
The above is an interesting observation.
I am just theorizing on the above observation. If there is an increase of LTO in the feed for the refineries resulting in the use of less heavier crude oil, this should also show up in the distribution of end products like gasoline, distillates and kerosene (to keep it simple).
A higher portion of LTO would yield more gasoline and less distillates and kerosene. If so, this should also become reflected in the relative price developments between those three end products.
If the industry thus pushes for exports of LTO, this may be one of the reasons for it.
– Rune
That means pricier food and maybe pricier everything, given that trucks run on diesel.
Hi Rune,
There was speculation by Toolpush that as the sweet spots get crowded out that a greater proportion of production is condensate instead of crude.
Any sense on your part if that may be something to be expected?
I have not been aware of such considerations.
Only reason I can think about has to do with molecule sizes and permeability and porosity.
Rune,
The point I was trying to make, that AWS is referring, is the Bakken as a basin, is very large and gives the impression that an “unlimited” number of wells could be drilled, well a very large number if unlimited is too much. But we find that it is really only 4 counties that are making up the main supply of oil. Now we have a very much more limited area to drill. Each of these counties are approx 2000 sq miles. Now you are saying that there is really only one county to watch. So if McKenzie county is 100% Bakken sweet spot, then at 320 acre spacing gives 4000 wells. At the rate Bakken wells are being drilled, this number can achieved in a couple of years.
Of course they may go to closer spacing, over lap with Three Forks, etc, but also not all McKenzie county maybe not be a sweet spot either.
It will be interesting to see how it all pans out, but one thing for sure, not too many wells will be fracced today with the low temperatures North Dakota are suffering this week.
The point I was trying to make in the post was that in recent months most of the drilling and added wells were in McKenzie county, which thus had the biggest portion of the production growth. Going forward it looks like McKenzie will continue to be the county that sees most of the drilling and growth in production.
– Rune
In my view, the fact that drillers are increasingly financing their activities out of cash flow rather than debt is a red flag. Borrowing money, especially at today’s attractive rates, is the preferred method for any business — it provides leverage that enhances profits without watering down equity. And if things go really bad, you just default on the loan.
Financing out of cash flow, on the other hand, reduces retained earnings and reduces returns to investors. There is only one reason I can think of why they would be financing out of cash flow — because they have no good alternative. I’m suggesting that the lenders are taking a cautious view of the ability of these companies to repay their loans and, as a result, tightening up on their loans through increased interest rates, shorter terms, and higher collateral requirements. Perhaps the lenders are reading Art Berman’s articles.
But, longer term, cash flow will not be sufficient to fund the continually increasing need for new wells to grow (or just maintain) production — unless oil prices go a whole lot higher, which will create its own set of problems. Either the drillers get more loans or raise money in the capital markets (both of which seem increasingly challenging) or they have to scale back activities.
First, the estimates shown in the figure 04 should be taken as a guidance as a more detailed analysis would have required studying all the companies’ balance sheets, and even then there would be room for some interpretations as it is difficult to establish the companies exact cash flows (when are bills paid, payments received, taxes/royalties paid etc.)
Further in figure 04 there are no estimates on retained earnings and dividend payouts, if adjusted for such posts the debts taking on and accounted for should be expected to be somewhat higher than what is depicted in figure 04.
Taking on more debts requires lenders that are willing to lend and also what remaining debt carrying capacities companies have.
When financial profits grow, debt may be used as a growth enhancer (steroid). If financial profits are in a general decline this has serious consequences on the companies’ abilities to both service a high debt load and maintain capital expenditures (CAPEX) for new wells.
– Rune
Rune,
Great Analysis on the 4 county Bakken production profile. Now that you have a good sense of the data coming from these 4 counties, do you have any indication when you believe overall peak could occur in the Bakken?
Of course there are variables that are out of one’s control such as Oil Price, Interest Rates & etc, but with all that you now know about the Bakken, what when do you believe peak will occur?
steve
Hello Steve and thanks.
You know what they say about predictions and the future etc.? 😉
Anyhow I can venture, call it some informed guesses.
If oil prices remain at present levels I would expect continued growth in LTO production from Bakken albeit at a slower rate for the next 2 – 3 years.
If oil prices sees a slight decline, to say $80/bbl, and remains there for some time I would expect this to curtail drilling which bears with it a probable peak in 2014 (annual figures).
As you point out there are several variables to watch out for in this equation; oil price, quality of remaining area to be drilled, companies’ debt capacities, companies’ strategies (some companies’ now apparently favor a plateau production development [taking the number of operating rigs down] others may be motivated by pushing their stock price [several objectives here] through increased drilling and production growth, availability to skilled manpower and infrastructure [transport, housing, roads etc.] to handle more drilling and production, changes to federal and state regulations just to mention a few.
– Rune
Rune,
Thanks for your “informed guesses.” Your peak time-frame seems to correspond with Art Berman & David Hughes assessment. Of course, this depends on many variables.
However, I was quite surprised to see that the EIA forecasted the Eagle Ford daily Legacy decline rate to fall from 83,000 bd in Dec to 91,000 bd in Jan. While this is a forecasted figure, it still is a big jump in one month.
thanks again,
steve
Hi Steve,
I think the budget cuts are wrecking havoc on the EIA, I would not rely too much on there forecasts. Their data lately for Texas oil production has simply been a 50 kb/d increase each month since March, do you really think their DPR is backed by much data, they are guessing based on a model they came up with last March and are just plugging in numbers at this point. They essentially are flying blind in the fog.
DC
I just ran across this link which will be new to some people in this forum:
http://www.youtube.com/watch?v=P8JFFf9nnDA&feature=youtu.be
We’re familiar with the grave shortcomings of his argument that lot production will soon reach close to five million barrels per day of course but he does acknowledge the necessity of continuous ever expanding drilling just to maintain lto production in this interview.
He also says that fracking and horizontal drilling techniques are adding substantially to the recovery of additional oil from older fields that are otherwise nearing exhaustion. This is a subject that I haven’t heard much about and I’m hoping some of the pros here will have something to say about it.
We should all remember that Harvard is a huge university and that the Mageuri report is associated with the Kennedy School of Government rather than a university department having to with hard sciences such as mathematics or geology.
I doubt that any mathematician or geologist on the Harvard faculty would touch the Mageuri report with a ten foot pole if doing so could be avoided.
He does acknowledge the necessity of continuous ever expanding drilling just to maintain lto production in this interview.
People without jobs and incomes won’t be able to fund the intensity of the drilling activity he is talking about. Daily Job Cuts tells the story everyday. My anecdotal evidence from watching local foreclosures, property sales, government borrowing, and the ever growing number of empty and boarded up businesses and homes tells the story.
Come every Spring, in accordance with Wisconsin State Law, WE Energies begins to shut off services to those who didn’t pay over the Winter – the list grows longer every year. With the very cold weather this Winter – the list will be very long come April and more people will be thrown out of their homes and forced to live together due to circumstances.
Jobless workers enter free fall – “If it comes down to it, I’ll have to sell the house,” says Botta, who bought the place in Bend, Ore., just months before he suddenly lost his job, which netted him as much as $60,000 in a good year. Having already raided his retirement savings, Botta thinks he’ll need to take three or four part-time jobs, working 60 to 70 hours a week just to get by without the unemployment checks.
“I don’t know how people make it on minimum wage,” says Botta. Having applied for nearly 100 jobs without luck—including cashier’s positions at Home Depot and Lowe’s—Botta expects he’ll be pumping gas if he’s lucky.
http://www.msnbc.com/all/jobless-workers-enter-free-fall
Having been in the job market myself – in SouthEast Wisconsin – I don’t even know where he thinks those part-time jobs exist. And he will have even more problems because of his age and time being unemployed. The jobless rate is now irrelevant – it is the labor participation rate that is important – and it says that the game is almost over.
If 5m/bbl of lto is ever achieved – it will have to be sold to the Chinese because locals won’t be able to afford it.
Rune:
I’m new to this area of the Internet, but have been reading up like crazy on shale and peak oil for the last few days. I read your SEP2012 Red Queen post and the followups, and the comments. And the Filloon posts and their comments. And even many other site’s (e.g. Slate, other blogs) that discussed the Red Queen.
Maybe I’m not reading it right, but it seems that you originally said production would peak at 650,000+/-50,000 bpd. But just a few months later (according to ND govt stats), we were over 700,000. And just over a year later (nov2013), we were actually over 900,000. Even just a few months ago, estimates were being made for 1,000,000 bpd to be achieved soon by state and national departments.
I just wonder (this will sound like a callout, but I don’t know how else to say it): did you get the prediction wrong (am I reading the numbers right)? And I saw some followups, but didn’t really see a clear post where you said “I got it wrong”. Actually saw continued touting of the Red Queen (like the Italian guy not taking it into account).
I’m also wondering if you have some analysis of why you got it wrong (like your model is not representative, wells changing over time, becoming better fracced, higher well addition, depletion rate assumptions too harsh, etc.)
Finally, I think you should just base your predictions off of the futures price for crude (rather than something different). That way you are not confounding something else in (low price) along with your guesses on depletion rates, sweet spots, downspacing communication, etc.
P.s. I know this is going to come across as provocative, but I really am trying to grapple with this stuff and understand it and articulating questions helps me do that. I’m a mechanical engineer and a chemist and have a micro-economic bent.
Nony,
Excuse me for jumping right in here between you and the author, but you have mentioned some very salient points, that “someone” needs to address to put the record straight, and I can do just that for you.
In regards to, ” Did Rune get his prediction wrong?” How about also asking if a Norwegian bear shits in the woods? Surely you know the answers to these two very simple questions. So does Rune. So does everyone else who has ever read his Red Queen article. There is nothing wrong with your thinking. In fact, there is everything right about your thinking, because you are skeptical, ask questions, and don’t mind challenging the accepted point of view. Rune isn’t owning up to the truth about his whole Red Queen thesis, and this is typical behavior for a hard core believer in peak oil. It is called denial, and is a very serious psychological problem, that should be dealt with as soon as possible, or else all his hard earned credibility will be lost.
His model was grossly flawed to start with because he cherry picked the well data to support his theory. At the same time he was using “average” EUR’s of 290,000, while the most representative Bakken Company with about 15% of all wells drilled in the Bakken, Continental Resources (CLR), was using 603,000, which is more than twice as much. While it could be said, that that was better than average, CLR is the clear trend setter in the Bakken, and economics eventually drives all companies to adopt the best practices. Several smaller companies with smaller, but excellent land positions like Kodiac (KOG) and Oasis (OAS) were using EUR’s of 700-800,000 at this time. By using such low EUR’s, that also raised his break even point to very unrealistic levels, as the industry leaders were using a break even point as low as $40-45. He simply halved the prevailing EUR’s at the time, and doubled the break even points. Very convenient moves for a true believer in peak oil!
Since then there have been huge leaps of improvement in well design and fracking procedures leading to vastly increasing well densities, that are all contributing to ever more oil being produced, and higher EUR’s right across the board. More and more oil is also becoming accessible with the discovery of, and ongoing further delineation of the lower three levels of the Three Forks. Long before that, CLR did go public with their contention that 24 billion barrels of oil were recoverable in the thermally mature and marginally mature portion of the Bakken alone, (basically the four ND counties and Montana) and that this could be achieved by drilling 48,000 wells with average EUR’s of 500,000.
I do hope that Rune realizes that considerably less than one billion barrels (about 4% of the whole) have been recovered so far, and that it would require a rate of production of about 2.75 million barrels/day just to achieve a yearly production of one billion barrels, which could then go on for 24 more years (in theory).
Yet because of the vast improvements in recovery and added discoveries of new oil in the lower levels, industry now believes that there is at least 900 billion barrels of OOIP in this before mentioned huge “sweet spot”. Now, the only question is how much can be gotten out, and it’s best to not dream about anything higher than 10%, or 90 billion barrels, but certainly 5%, or 45 billion barrels is easily doable.
Using 500,000 EUR’s, 90,000 new wells will need to be drilled, and at a higher rate than present, say 2000/ year, it will take 45 years just to drill that many wells. And you people are talking about the Bakken peaking any minute now???
Try going to …contres.com …, click on “For Investors” at the top, then click on “March 2014 Presentation” on the lower right, if you want some honest insights into what’s really going on in the Bakken, instead of listening to all this peak oil nonsense. This website will only share the same fate as TOD, if they don’t start publishing the truth about the Bakken.
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