Reverse Engineering the North Dakota Bakken Data

Notice: The data I thought would be out today: EIA Crude Oil Production by State will not be out until Thursday, Feb. 27th. However I will have another post coming out later today anyway.

This is a guest post by Ovi Colavincenzo

There is considerable discussion on this site regarding when the North Dakota portion of the Bakken will peak.  Having looked at the monthly Bakken data that the State publishes, it raised the question of whether it was possible to do a reverse analysis of the data and then use it to develop a model that would replicate the ND Bakken production, exactly.   The objective being to provide further insight on what is happening in the ND Bakken.

In order to do this, the following conditions and information were required:

  • A monotonically increasing number of new producing wells
  • A typical/average decline curve for the ND Bakken field
  • Not too many wells being shut/reworked each month

The last bullet is a preferred condition because if a number of low producing wells are shut and replaced by newer high producing wells, then the estimated flow rate of the new wells will be on the high side.

From 1999 to mid 2005, approximately 200 wells were in production in every month.  The addition of an increasing number of new wells began to occur in mid-2005, so start date for the analysis was set at the beginning of 2008 to address the first bullet point above.

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Figure 1: Source:  The Shale Revolution” by J.D. Hughes

For the decline curves, two were used and are shown in Figures 1 and 2.  One came from “The Shale Revolution” by J.D. Hughes, November 19, 2013 shown in Figure 1.  The other came from North Dakota’s Directors cut, “Tribal Leader Summit” 09 05 12 (PDF), Figure 2.

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Figure 2: Source: North Dakota Director’s Cut “Tribal Leader Summit”

Note that the ND data is yearly and the Hughes data is monthly.  While the Hughes data represents the average decline rate for a number of wells, it is not clear what data was used to derive the “Typical Bakken Well Production” curve shown in Figure 2.  Note the significant difference in the initial production rates, 904 b/d vs 580 b/d.  Also a post in “The Oil Drum #9954”, by Rune Likvern, raises questions of how typical it is.

Since it is not clear from the monthly ND data, whether wells are being closed, either temporarily for maintenance/re-fracking or permanently, the ND production and wells data were averaged using a three month moving average prior to being used in the development of the model.  The intent of using the moving average was to minimize the effects of closing and reopening wells.  There is some indication that the opening and closing of wells does impact the variability in the results and is shown below in a comparative chart.

To conduct this analysis, a normalized Bakken decline curve was required.  The decline curves shown above were normalized for this analysis.  Two curves were used in order to assess the impact on the results from using two different curves.  The two normalized decline curves are shown in Figure 3.  The major difference between the two occurs in the first two years.  After the first year, the Hughes decline curve is down by 71% vs. 53% for the ND Director.

Note that there are only four years of original Hughes data.  Beyond four years, the data is extrapolated and parallels the ND Director data.  The original North Dakota Director’s Cut data was yearly and the monthly data was interpolated from the yearly data using a sliding quadratic function.

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Figure 3: Normalized Bakken decline curves

To assess the affects of the differences in the two data sets, the cumulative production associated with each decline curve was compared.  The curves in Figure 4 show how the production rate increases due to drilling one identical well each year in the first month of each successive year.  Looking at the Hughes curve, after drilling 1 well each year for 7 years, the production rate from the 7 wells is only 1.9 bbls/day in 72th month.  After 7 years of production, adding one new well at the beginning of the 8th year only increases the production rate of the field by 0.07 bbls/d, to 1.97 b/d, i.e., 7% of the initial production rate of the new well.  The Red Queen has shown up.

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Figure 4: Cumulative yearly production from adding one well each year

While the ND Bakken data published monthly shows the overall increase in the field’s production, it does not provide information on the productivity of the new wells completed in that month.  As indicated above, the objective of this analysis is to calculate the amount of additional new production required each month to use in a model that would exactly match the ND Bakken production data, after accounting for depletion from all previous months.  Below are three charts that summarize the results of the analysis and the model’s output.

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Figure 5: Monthly new production

 Figure 5 shows the amount of production added by the new wells each month to match the ND Bakken data that was averaged over three months.

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Figure 6:  Monthly addition of new wells

In Figure 5 note the dramatic increase in additional production from roughly 30 kb/d to 60 kb/d in mid 2011.  This sharp increase is related to the sharp monthly increase in new well completions from 70/Mth to 130/Mth during the same period shown in Figure 6.  The trend in new crude production parallels the number of new well completions to the beginning of 2013 and into 2014.  What is surprising is the drop in the average number of new well completions beginning in mid 2013.  Is this a sign of things to come?

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Figure 7:  Comparison of Hughes and ND Director initial production rate

The average initial production rate of the new wells added each month is shown in Figure 7.  One can see a roughly constant production from the new wells beginning in mid 2008 up to 2013 for both curves, except for the two spikes.  Looking at the Hughes data, the new wells from mid 2008 to the beginning of 2013 were averaging 500 b/d, increasing to approximately 650 b/d at the end of 2013.  A similar trend appears in the ND Director’s Cut graph but the growth in 2013 is less pronounced.  This raises the question of whether the increasing well production rates reflect the increasing length of the new wells being drilled or are they being drilled in sweeter areas.  I have read that some wells are now 2 miles long and think that initial production would be proportional to the length of the well.

The dip in well production in early 2009 is associated with the dip in total ND Bakken production.  The sharp increase in Q1-10, I believe is associated with the temporary closing of older, low production wells, which are then brought back on line after maintenance a few months later when the average well production settles into a more typical stable range.

The decline rate that the new wells must offset to keep production increasing is shown in Figure 8 below.  It appears that the decline rate at the end of 2013 is somewhere between 55,000 b/d/Mth and 75,000 b/d/Mth.  If the new wells are supplying approximately 500 b/d and the average decline rate is around 65,000 b/d, then a minimum 130 wells/month are required to offset the decline.

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Figure 8: Total monthly decline rate from all of the previous months’ wells

It was noted earlier that the original ND Bakken data showed high variability in the number of wells drilled and this had a significant impact on the results when analysing the original data set.

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Figure 9:  Original data set of monthly new well completions

To provide the readers with an idea of the variation in the original data, the original monthly well data is shown in Figure 9 and its impact on the initial production rate is given in Figure 10.  Compare the variability in Figure 9 with Figure 6 and Figure 10 with Figure 7.  One can see how the monthly variation in well completions affects the variation in the initial production rates shown in Figure 10.  However note that the four month moving average is similar to the Hughes curve in Figure 7.

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Figure 10: Impact of high variation in original wells data on initial production rate

In Figure 10, even though only 40 wells were completed in December 2013 (Figure 9), the initial production rate of the wells was still the same as in November and December, close to 800 b/d, based on the original data.  In other words the drop in the production rate from November to December, from 911,292 b/d to 862,987 b/d was due primarily to the low number of well completions.

This model is capable of projecting future production rates or scenarios by providing production estimates/guesstimates for future months.  However, I believe the model’s greater value is in showing/evaluating how the growth in production in the ND Bakken has increased through a combination of the addition of new wells and drilling wells that have a higher initial production rate.  By continuing to track the initial production rate, we should see either a drop in number of wells or a drop in the initial production rate or both as we approach the peak.  This behaviour should manifest itself in both decline curves.

I will keep these charts updated on a timely basis or when something significant occurs.

 

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138 Responses to Reverse Engineering the North Dakota Bakken Data

  1. Nony says:

    Thanks for the work. I agree that keeping an eye on average IP (is it slipping) and number of wells dug is essentially the key to monitoring the play. Who know what the 10-20 year type curve really is like and at a certain point, who cares. In any case, new drilling is required and when it lessens (or new wells are less nice), then the play will peak almost immediately.

    1. Give me your feedback on the USGS study. Good methodology? Do you think their numbers are low, high, or about right?

    http://pubs.usgs.gov/of/2013/1109/

    2. Yeah, I figured it had to be completions causing such a radical drop. (and the table they report the months stuff has the number of new wells and number of barrels in columns) Perhaps over time we get to the effect of too much downspacing and/or lack of sweet spots (essentially geology factors). But for now, it does kind of look like it really was weather in December.

    3. What do you think of the report by Cosima Theloy on geology and technology factors (Google it, not sure how to hyperlink to a pdf).

    4. How do the TF and Bakken compare in output? Seems like a fair amount of TF wells have been done so we ought to be able to compare.

    5. I watch the daily rig counts at Million Dollar Way.

    http://themilliondollarway.blogspot.com/2014/02/friday-february-21-2014.html (example, scroll down)

    Seems interesting that in general, we have exactly the same number of rigs in 2014 as 2o13, but moderately down from 2012. This has been pattern for last month. Even though new wells are being drilled a little more efficiently (with more pad drilling), it would still seem to imply some cooling of interest (after all, rigs are available, why not keep the amount from 2012…or even ramp up higher and higher…just for the financial draw). but then the 2014 is same as 2013…so still significant investment worthwhile and not declining more. I just don’t know how to read it. Takeaway bottleneck? Fracking bottleneck?

  2. Nony says:

    6. This is just something of interest to me, but what is the “best” Bakken well?

    • Enno says:

      As far as I can see, that should be
      USA 2D-3-1H from Petrohunt, which since Jan 1 2007 has produced 1345995 barrels of oil, for a daily average since the start of an astonishing 527.6 b/d (only counting oil). I think they revived that well in Feb 2008, as it had a high peak in that month (1000 b/d).
      The median well (counting all single reported wells in ND since 2007) has so far only produced around 67K barrels.

      From my point of view, the graphs from Hughes seem closer to the truth than what ND has come up with. Especially figure 2 is absolutely rubbish. The average 2010+ well produced just over 200 b/d on average in the first year, which dropped to just below an average of 100 b/d in the 2nd year.
      2008 and 2009 wells produce on average less than 30 b/d in their 5th year.

      • Nony says:

        Yeah, the 900 seems way high. I looked at the presentation it is coming from and that looks kind of cobbled together, not very serious. So I wouldn’t read much into that type curve as an official prediction. I don’t like Hughes, but his curve seems more serious.

        I think a lot of the peaker community hooting about “but you’re ignoring the decline curve” is very, very silly. All these companies know that they are intensely drilling (Hamm calls it more like mining coal than drilling oil). Once the sweet spots run out, that is more the issue. But who really cares about the 5+ year output of the wells. It’s not what is driving investment or output.

        • David Hughes says:

          Nony,
          “I don’t like Hughes”.
          Why?
          Frankly I don’t like people that would say something like this without substantiation as to what the problem is. Please advise. Thx.

      • Ovi says:

        Looking at an average initial production rate in 2010 of about 450 b/d for the Hughes curve (Fig. 7) and a 71% drop in the first year, gives an average yearly production of about 290 b/d. Doing the same calculation for ND Director, 350 b/d initial and 53% drop, gives an average production of 260 b/d. Could you provide me with a reference where you obtained the 200+ number for 2010.

        • Enno says:

          Please have a look at my comment in
          http://peakoilbarrel.com/north-dakota-bakkenthree-forks-scenarios/comment-page-1/#comments
          where I posted a graph from which you can deduce this, with reference. A linear approximation for this curve is somewhat optimistic.

          • Ovi says:

            Thanx for the reference Enno. Since you have the data, could you possibly normalize those yearly decline curves and post them here. It would be interesting to see how they would look normalized and how they would compare with the normalized Hughes and ND Director curves.

            Since the model requires a normalized decline curve, it would be useful to know which one is closer to reality, Hughes, ND Director. Also if there is a big difference between the years, I could try to incorporate a few additional curves into the model that would span a few years. Thanks for your efforts.

            • Dennis Coyne says:

              Hi Ovi,

              output in barrels per month for average 2010-2013 well from first to 47th month of output below for Bakken/three Forks (NDIC data):

              9586
              11091
              8710
              7786
              7080
              6423
              5921
              5431
              5097
              4783
              4494
              4306
              4150
              3969
              3820
              3659
              3520
              3383
              3278
              3069
              3014
              2998
              2955
              2940
              2877
              2771
              2730
              2691
              2615
              2592
              2530
              2486
              2405
              2364
              2289
              2235
              2212
              2203
              2241
              2177
              2152
              2161
              2240
              2158
              2323
              2319
              2315
              1746

              I think you can copy and paste into Excel to normalize, data courtesy of Enno. First year average output is 233 b/d. Data based on 5900 wells in month 1 and the number of wells gradually decreases to 482 in month 40, and 33 wells in month 47. I believe data beyond month 40 should be thrown out (too few wells), not sure what Enno’s take is on this. Perhaps he will comment.

      • Nony says:

        Maybe it wasn’t being revived, but being put on the pump? BTW, thanks for the note on that well. Reminds me of the publishing executive who told his editor, “let’s just buy bestsellers”. 😉

  3. Enno says:

    > 2008 and 2009 wells produce on average less than 30 b/d in their 5th year.
    Correction, that should be 48 b/d in their 5th year. I was looking at a subset before. Still quite lower than 88 (or 66 depending on what year 0 means) shown in that figure.

  4. Enno says:

    Part of the difference may be caused that also gas is counted, which I didn’t, although it can’t even explain half of the gap.
    I’m thinking of starting a business selling barrels of oil, or at least the “equivalent”, and fill them up with NG (of course providing 5.8 barrels for each barrel promised). Even after the recent rise of NG, that should still be highly profitable, even more so than drilling the shales!

    • Dennis Coyne says:

      Hi Enno,

      Does your data set give any indication of the difference between Bakken and Three Forks average well productivity (EUR)? Also does your monthly data for 2013 show the rise in well productivity over the last half of 2013 suggested by Ovi’s analysis? Thanks for sharing.

      • Enno says:

        Hi Dennis,
        Based on the free reports it’s not that easy to distinguish between Bakken & TF, as least I didn’t find an easy rule. Under the headers Three Fork I didn’t find too many wells up to now, so I don’t think that analysis will be very useful.
        Regarding IP, I must say I am not so interested in what a well produces in the first day(s), I am much more interested what it does in the first year(s), and will keep following that trend.

        • Nony says:

          Agreed. Choke can have a big effect on first day. I have read that the timing of change to pump is an effect also. That decline should really be considered more from first year to second year, etc. note, this is probably a reasonable enough division in terms of economics.

    • Dennis Coyne says:

      Hi Enno,

      You have the best access to the well data and have been very willing to share that data with me. Thank you. The data set is so large that it is not feasible to share all of it, so I have more questions. If you look at 2013 data month be month do you see the increase in well output from May through December that Ovi’s analysis points to. Also we do see a 5 % increase in 11 month output in 2013 relative to the 2011 average well, but if we saw a shift in a hyperbolic well profile that had a first month production of 500 b/d, a 5 % increase would be 525 b/month. I am just attempting to reconcile your data with Ovi’s analysis.

  5. Old farmer mac says:

    What are the some of the possible reasons that Hughes consistently comes up with higher numbers than North Dakota personnel, anybody ?

    Thanks in advance as usual.

    Another question:
    Maybe I am interpreting the scales wrong but figure two for instance seems to read that the average well produces 900 barrels initially dropping to 427 barrels at about the year two point.

    These numbers seem extraordinarily high in comparison to the numbers I remember seeing here and in other places .

    What gives?

    • Jeffrey J. Brown says:

      As pointed out in the article, we need to differentiate between monthly and average annual production. For example, given a steady decline in production, December will be lower than the average annual production (and given rising production from a play, December production would be higher than average annual).

      In any case, a key point that the Cornucopians are missing is that as our our production increases, and as an increasing percentage of total oil production comes from tight/shale plays, the annual volume of oil production lost to declines from existing wells is increasing faster than the overall increase in production.

      For example, the US produced 5.0 mbpd in 2008 and about 7.5 mbpd in 2013 (average annual C+C). Let’s assume that the decline rate from existing (total US) production in 2008 was about 5%/year and let’s assume that the decline rate from existing production in 2013 was about 10%/year. Based on those assumptions, we needed 0.25 mbpd of new production in 2006 to offset declines from existing wells, but in 2014 we would need 0.75 mbpd of new production to offset declines from existing wells. So, a 50% increase in C+C production would correspond to a three fold increase in the annual volumetric decline from existing wells. Annual US production showed a 8%/year (exponential) rate of increase from 2008 to 2013, but the estimated volumetric loss of production from existing wells (based on above assumptions) would have increased at 22%/year.

      If we use a (conservative IMO) estimate of 10%/year for the annual decline rate from existing US oil wells, in order to maintain 7.5 mbpd for 10 years, we would have to replace 100% of current C+C production in 10 years. In 10 years, we would have to replace the productive equivalent of every oil field in the US–from the Gulf to the Eagle Ford, to the Permian, to the Bakken, to Alaska.

      This is why Peaks Happen. It’s a mathematical certainty that with time, the output from new wells can no longer offset the declines from existing wells.

      • Doug Leighton says:

        Jeff, I really don’t think anyone should be allowed to express a view about Peak Oil until they’ve produced a note from their parents (or doctor) testifying they’ve read AND UNDERSTOOD your (this) explanation of oil extraction reality.

      • Ovi says:

        I think that Jeff’s last sentence needs some clarification. I inserted Fig 4 to clarify the implications of the decline curve. As shown in Fig 4, if one were to drill one identical well each year, total production continues to increase every year, except at a slower pace. As noted in the post for the Hughes curve, “After 7 years of production, adding one new well at the beginning of the 8th year only increases the production rate of the field by 0.07 bbls/d, to 1.97 b/d, i.e., 7% of the initial production rate of the new well.”

        Consider this mathematical example where a well has a decline rate of 50% each year and the initial production rate is 100 b/d. Assuming one identical well is drilled each year, after an infinite number of years, the maximum production rate would be 200 b/d. It is simply the sum of the infinite series 100, 50, 25, 12.5, 6.25, etc. The sum of this series is simply 100/0.5. If the decline rate were 75% per annum, the maximum rate would be 133.33 b/d, i.e. 100/0.75.

        The high decline rate means you have to keep drilling, forever, hence the Red Queen. The peak arises when the number of wells drilled start to decline or the productivity of the new wells decreases.

      • canabuck says:

        Agreed. But we also have to look at the past data (2003 – 2013), and we can surmise that approximately 5 Mb/d was discovered and put into production in the U.S.
        If this happened in the past decade, then it may very well happen in the next decade.
        The ‘decline game’ is not the only game in town. The ‘explore and produce’ game is very much alive and well.

        • Jeffrey J. Brown says:

          Re: canabuck

          I think you illustrated the point I was making about Cornucopians not understanding–or choosing not to understand–the impact of rising decline rates as production increases.

          The net increase in US C+C production from 2005 to 2013 was about 2.5 mbpd (5.0 to 7.5 mbpd). I’m assuming that the decline rate from existing production rose from about 5%/year in 2005 to 10%/year in 2013 (as an increasing percentage of production comes from high decline rate tight/shale plays).

          Let’s assume that we see another 2.5 mbpd increase in net production by 2018 (to 10.0 mbpd in 2018), and let’s work backwards from there. Let’s assume that the decline rate from existing production continues to increase at 1%/year per year, hitting 15%/year in 2018.

          So the projected volumetric declines would look like this:

          2013: 7.5 x o.1 = 0.75
          2014: 8.0 x 0.11 = 0.88
          2015: 8.5 x 0.12 = 1.02
          2016: 9.0 x 0.13 = 1.17
          2017: 9.5 x 0.14 = 1.33
          2018: 10.0 x 0.15 = 1.50

          So, in round numbers and based on the above assumptions*, we would need about 7 mbpd of new production from 2013 to 2018, just to offset declines from existing wells. And we also need new production to show the net increase from 7.5 to 10.0 mbpd.

          For example, the assumption is that we would need 0.75 mbpd from 2013 to 2014, to offset declines, plus another 0.25 for new production, for a required gross increase in production of about 1.0 mbpd from 2013 to 2014, to show a net increase of 0.25 mbpd.

          So, based on all of the foregoing, in order to show a net increase of 2.5 mbpd from 2013 to 2018, I estimate that we would need on the order of 9.5 mbpd of new gross production through the end of 2018. Or, based on the foregoing, in five years we would need to basically do what it took the US oil industry decades to do, as we approached our 1970 peak rate of 9.6 mbpd.

          Incidentally, based on the foregoing, a gross increase in production of 5 mbpd in five years would result in a net production decline. I suspect that an exercise something like this is why the EIA, in effect, recently asserted that Hubbert was right about an absolute US crude oil peak in in the 1968 to 1973 time frame.

          *I think that we would all agree that a higher percentage of US natural gas production comes from tight/shale plays, versus the current percentage of crude oil production that comes from tight/shale plays. I frequently reference the 2013 Citi Research report which put the estimated 2013 decline rate from existing US natural gas production at about 24%/year.

          • Jeffrey J. Brown says:

            Correction: US production increased from 5.0 mbpd in 2008 to 7.5 mbpd in 2013. I’m assuming a 5%/year decline rate from existing production in 2008 and 10%/year in 2013.

          • canabuck says:

            Is it not because of LTO that decline rates are rising? If all of the new production was conventional oil, then the decline rates would stay the same.
            For the record, I would not call myself a Cornucopian. OTOH, I also do not see our society falling off a production cliff in the near future.

            In 2013, if production increased by about 1.0 mbpd net, that means about 1.75 mbpd of gross new production was added in the US. That is a significant figure. The fact that increasing gross production increases cannot be maintained long term, especially with lower capex, cannot be denied.

            • Jeffrey J. Brown says:

              Our premise is that as oil from tight/shale plays makes up an increasing percentage of total production, the decline rate is increasing. However, note that the 2005 to 2012 rate of decline in conventional crude oil production from Alaska was 7%/year (EIA). Note that this is the net decline rate, after new wells were put on line.

              This is one reason I think that a 10%/year overall rate of decline in crude oil production from existing wells is a conservative estimate.

              In any case, even if the decline rate from existing wells does not increase beyond 10%/year, we would need 7.5 mbpd of new production in 10 years, just to maintain current production. Therefore, to return to your original premise that we might see a gross production increase of 5 mbpd in 10 years, a 5 mbpd gross increase–based on a 10%/year decline rate–would result in a significant net production decline.

              • canabuck says:

                We both know that ‘past behavior is no predictor of future events’, yet it is also one point of view that should be considered as a baseline. What was the actual gross oil production added in the last 10 years in the US.? I don’t know, but it was likely more than 5 mbpd. So, we can expect perhaps a net decline of 1.0 mbpd in US oil production over the next 10 years. This doesn’t seem anything to get very excited about. New markets and new technology can handle such a transition.

                Another question is how the investment markets now, can affect US production in 3-4 years from now. It is hard to understand how it all works together, but one can take it by faith that capital markets work for the best of all involved, and that there will be enough oil to go around in the coming decades, and at a fair price.

                • but one can take it by faith that capital markets work for the best of all involved, and that there will be enough oil to go around in the coming decades, and at a fair price.

                  You have far more faith than I. For starters capital markets do not always work for the best for all involved. People and companies often go bankrupt when working capital markets.

                  And whatever gave you the idea that there will be enough oil, at a fair price, for all, for decades? Good Lord man, what do you think peak oil is all about. It appears that you think peak oil is all poppycock.

                • canabuck says:

                  Ron, In the face of rising oil output, maybe it is easier to keep the “faith” that all will be well in the future, rather than holding onto the alternate “faith” that oil production will collapse in the near future. Facts are facts, after all.
                  The truth is likely somewhere in the middle, as we muddle along with a production near-plateau. Will the plateau start to give way to the “slow decline” in the next 2-5 years? No one knows, but it may be possible to extend it out for 20, 30 or 50 years.

                • Jeffrey J. Brown says:

                  But then we have the net export situation, and we have seen a material post-2005 decline in Global Net Exports of oil (GNE*), with developing countries, led by China, (so far at least) consuming an increasing share of a post-2005 declining volume of GNE.

                  Furthermore, I estimate that we burned through about one-fifth of total post-2005 Global Cumulative Net Exports in just seven years (through 2012). For more info, you can search for: Export Capacity Index.

                  Following is my GNE/CNI graph, which shows the 2002 to 2012 ratio of GNE to Chindia’s Net Imports (CNI).

                  *GNE = Combined net exports from top 33 net exporters in 2005, total petroleum liquids + other liquids, EIA

                • Jeffrey J. Brown says:

                  Incidentally, I estimate that the year over year rate of depletion in remaining post-2005 Global Cumulative Net Exports (CNE) accelerated from 3%/year for 2005 to 2006 to 3.8%/year for 2011 to 2012. And this is without taking into account the “Chindia Factor.”

                  In effect, I think that we are maintaining something resembling Business As Usual as a result of an accelerating rate of depletion in the remaining volume of Global Net Exports of oil. It’s as if you were maintaing your lifestyle by consuming your remaining savings at an accelerating rate of depletion.

                • KC says:

                  Canabuck, what planet are you from? Oil at a fair price for all, forever? Have faith in capital markets working for the best of all involved? Excuse me? Have you never heard of Wall Street? Michael Milken? Gordon Gekko? Greed is Good? Bear Sterns? Lehman Brothers? Foreclosure Fraud? Market Timing? Structured Products? LIBOR Manipulation? Money Laundering? All of these frauds and much more have been committed in the name of “business as usual” banking in US capital markets.

                  Dude, you’re a bit late to the party. If you think this is all a fairy tale and happy days are here to stay, I’m sorry to burst your bubble. I’ve been on the inside at many of the world’s largest tier-1 banks and insurers, and I can tell you with absolute certainty that they know what is going on, they know what they are doing, and they are in business to serve themselves. A business remains in business for the benefit of itself, not for the good of the people. A business that has no profits eventually fails and pulls out of the market. Lehman and Bear Sterns are only two of the best examples, not to mention so many of the grand Ponzi schemes out there, a la Madoff, Social Security, whatever you can imagine, it is out there.

                  That you believe any of the crap put out there by the banks and funny numbers from federal agencies or any others, and apparently haven’t done your own research to see reality for what it is – suggests that yes, in fact, you ARE a cornucopian, despite whatever malarkey bs you might suggest otherwise.

                • Nony says:

                  Gordon Gecko? That’s a movie character!

                • KC says:

                  Nony: yes, Gordon Gecko is a movie character, meant illustrate the vagaries of the dark underbelly of the behemoth called investment banking; but he is much more than that – he is the fictional representation of Michael Milken, putting a face upon the evil travails and trespasses of Wall Street.

    • Ovi says:

      That’s how I interpreted the NDIC numbers. What is not clear is whether the 904 is the average for the first month or the actual production during the first 24 hours. In other words what is the time frame associated with “zero”. I assumed that the 904 b/d was the average for the month, as currently reported in the NDIC’s monthly report.

  6. Old farmer mac says:

    I suppose that every body here knows that the way this blog is set up by the company that runs the service that there is no way to separate different subjects into different threads which is why I -and every body else must just jump in and change the subject abruptly if we have something to add that is useful but on a different topic.

    Here is a link to a good article in the NYT about new and proposed regulations about transporting oil by rail.There is an interesting tid bit in it involving an extra fee Canadian railroads are charging to the users of the older tank cars that throws some light on what it costs to move oil by rail.

    The NYT allows you free access to ten articles per month but I have never been able to figure out how they define a month. At any rate most of the regulars here can probably read this article.

    http://www.nytimes.com/2014/02/22/business/energy-environment/to-make-shipping-oil-safer-railroads-agree-to-8-measures.html?hpw&rref=science&_r=0

  7. Old farmer mac says:

    Here’s a link to a piece that has a few little fibs in it in my personal opinion but be that as it may there is still some real red meat in it.

    It is impossible to fault the author on his talking points.

    But he is following the industry script to a ”T” when it comes to misleading the public about the environmental dangers associated with the industry both long term and short. This guy in particular is worse than most in this respect.

    But the implied lies aside, it is the things that such people never say that are the the most important things of all.

    In this case the things not said involve the fast depletion rates of these new unconventional sources of oil and gas.His flower garden is going to die in a drought within a decade.

    Now I am not one to denigrate the immense gift of another decade of plentiful domestic oil but instead of leading the all too gullible public into believing happy motoring is back forever the message should be to make good use of that decade getting ready for the most expensive oil ever.

    Recent research ( sorry I did not save the link ) indicates that the memory of the public is limited to about two years or maybe three at the most when it comes to high gas prices , hard times , and the purchase of a new vehicle.

    Most new vehicles are financed for at least three years and four and five year vehicle loans are commonplace.

    My own personal guess is that gasoline and diesel fuel prices will double in real terms within a decade meaning that it may cost almost as much to gas up a vehicle driven four or five hundred miles a week at that time as it did to make the payment it when it was new if it is a gas hog.

    Twenty gallon a weed at eight bucks adds up to over six hundred and forty bucks a month.

    I am painfully aware of this cost since it costs me more to drive my old Chevy 4×4 truck almost two hundred bucks just for gasoline to use it steadily for a week. Fortunately I seldom need it for more than a few hours at any given time.

    The people buying trucks and cars that are bigger than needed are going to regret it a few years down the road when it is time to trade because the trade in values are going to be depressed in inverse ratio to the vehicle’s appetite for fuel.

    There are all sorts of considerations a thinking person should make in considering the oil situation. A house close in to town and the jobs in town is going to be worth more than one farther out although I do not buy too much into the early death of suburbia theory.( My take is that once tshtf we will be able to buy micro min i cars that get an effective hundred mpg plus because the safety and pollution regulations that prevent them from being built now will be relaxed pronto and that the owners of suburbia will gladly buy them and drive them rather than give up their mcmansions. This opinion is for the near and medium term meaning the next two or three decades.Things may be far different in the longer term but I am confident that bev cars will eventually be cheap enough to save suburbia if business as usual lasts long enough..)

    http://www.forbes.com/sites/davidblackmon/2014/02/20/oil-gas-boom-2014-jobs-economic-growth-and-security/

  8. Not to worry about the steep decline in shale oil, science and technology will fix that problem.

    ConocoPhillips CEO: Skeptics’ warnings of shale bubble are unfounded

    Question: Rapid declines: Shale well depletion raises questions over US oil boom?

    But Lance, speaking at Rice’s Geopolitics of Natural Gas conference, adamantly disagreed, arguing that the industry’s technology advances could compensate for any projected production declines.

    Okay, got that? Shale oil wells are declining at about 6% per month but advances in technology is likely to fix that problem. That is if a fracked well produces 400 barrels per day the first month, just apply technology to that well and it will never decline from that level of production, well not for the next 50 years or so anyway.

    Hey, we got technology dude, so stop worrying about decline rates.

  9. Jeffrey J. Brown says:

    ” . . . industry’s technology advances could compensate for any projected production declines.”

    Of course, the implied message is that we will never show a production peak.

  10. Nony says:

    Ovi:

    See figure 5 of this post. Interesting to see IP over time graphed like this. I’m not 100% sure what to make of it as the companies can move around or just have different development strategies, but the blog author attempts a little analysis. My general impression (from other reading) is that acreage is more the differentiator of companies than technology and presumably the companies have significant differences in where their holdings are within the play. This is not to say that technology is not important (to develop the play at all, or to develop it most effectively), but that it seems to get shared pretty quickly. Not really sure what to make of the IPs staying so steady, is it some effect of finding more sweet spots with time? Some counterbalancing factors? One would expect the best areas to be developed first.

    http://info.drillinginfo.com/5-top-bakken-shale/

  11. Mason Inman says:

    The state of North Dakota makes a lot more information available if you pay a relatively small fee. For the $50 “basic services”, they say you can get access to individual well records that include initial production. For the $175 “premium services,” you can get a lot more. See the left sidebar at: https://www.dmr.nd.gov/oilgas/

    I’ve been thinking of paying the fee, but haven’t yet. I’ve been digging into details on the Marcellus, using the (free) individual well data from the state of Pennsylvania. If anyone’s interested, I’ve got a few posts up here:
    https://medium.com/@masoninman

  12. Nony says:

    I definitely hope that D Coyne, Rune, etc. are paying the 50 or 175 fee. It’s not that much (not like some proprietary database for tens or hundreds of thousands). Given the amount of time they spend on the modeling (and considering the value of that time), might as well get insights from the most data.

    • Dennis Coyne says:

      Hi Nony,

      I am pretty cheap, so I am not paying any fees. Enno has figured out a way to pull a lot of the data from the free website, he has been a huge help getting better well data. Prior to that I used data shared with me by Mr. Likvern. I may look into the $50 service, but I am not sure it would be more useful than data provided by Enno.

  13. Coolreit says:

    BaysideDave888 posts on SA and indicates that he is an “Engineer and Geoscientist, forty years in oil and gas upstream. Over thirty years as investor in oil and gas and independent Operator in most US basins. Forty-five years as investor.”

    His comment below is from this article:

    22 Feb, 2014

    “Value Digger: I appreciate the time you have put into this article and to the breadth of the areas covered. However, as a many-decade owner and operator of natural gas wells, I must disagree with your conclusions that nat gas prices will decrease (or increase no further) in the intermediate time frame – two to five years.

    Other responders, each with very apparent industry experience, have pointed out that the resource plays are indeed demonstrating what I (and a few other old-timers, to be fair) predicted 5 years ago – that these “resource plays” would be just like past hot oil and gas plays in that only about 15% of the wells drilled would be successful. I define success in the long term sense – from the first dollar in geological cost to the last dollar in plugging expense and including all financing and missed opportunity costs. The increase in production from these plays has come about because of a truly massive capital injection, and in total, this capital will never be recovered.

    Again, others have said this but it bears repeating – the rapid declines in per-well production necessitate continued drilling at present rates, FOREVER, in order just to keep production at present rates. I have met many bankers in the past few months who are no longer willing to provide this capital. It might come from public shareholders, but historically, that has been insufficient.

    Beware the EIA. Our (private) studies have shown a NEGATIVE correlation between important EIA predictions and intermediate-term realities.

    I can tell you that, short term (a few months), I think you might be right. I have hedged some nat gas for a few months and we are pulling some wells a little harder to get a short-term cash boost, and others are doing the same. This may temporarily decrease prices, but more production today means less in a couple of years. Remember though, we are hedgers, with much different objectives than all you speculators.

    I have publicly predicted that nat gas production will peak this year, and will decline thereafter until we get at least 9 months of continuous realized prices in excess of $6.00 per MMBTU, inflation adjusted. This would mean about $6.75 in 2017.

    Lastly, continued use of the 5 year average storage numbers is problematic, since natural gas consumption continues to increase every year. The important number should be the percent of storage versus consumption. Also, just an unconfirmed suspicion, but below normal temps may be only part of the picture, low storage may also represent declining production, or at least declining production of gas not dedicated long term.

    http://seekingalpha.com/article/2039803-beware-buyers-12-reasons-why-the-current-sky-high-natural-gas-price-isnt-here-to-stay?v=1393097655&source=tracking

    his other posts –

    http://seekingalpha.com/user/4990081/comments

    Source: http://www.investorvillage.com/smbd.asp?mb=4288&mn=133221&pt=msg&mid=13578655
    ————-

    • Doug Leighton says:

      Coolreit,

      An interesting and valuable contribution to the discussion. I liked his comment: “Beware the EIA. Our (private) studies have shown a NEGATIVE correlation between important EIA predictions and intermediate-term realities.”

      Good eye man!

    • Nony says:

      Even if decline becomes slower instead of faster, you still have to drill forever to continue same volume. Who cares? Mining coal…

    • Calhoun says:

      The money quote: “I have met many bankers in the past few months who are no longer willing to provide this capital. It might come from public shareholders, but historically, that has been insufficient.”

      This gets to an important point in the Kopits’ presentation discussed recently. The oil companies are generating negative free cash flow, which means they are eating themselves alive. They need much higher prices, according to Kopits, to regain positive free cash flow. If the bankers are getting cold feet it won’t take Wall Street long to catch on. And then the ability to “mine” LTO like coal will gone — at least until the price of oil goes much higher.

      Should be an interesting year.

      • Nony says:

        The tight oil companies are fine. They are just rolling over earnings. Very fast payout. and the equity markets and debt markets have no issue investing in them.

        Gas companies is another issue. But still, there is a slew of gas out there that can be profitably produced at 5$.

  14. Old farmer mac says:

    This one takes the cake folks.

    I haven’t seen anything else to match this piece except paradise and virgins (and presumably eternal youth so the virgins will be an asset rather than otherwise.

    Maybe there is as much recoverable natural gas down there as the cornucopians think but I have a hard time believing it myself and even if it is there in the quantities envisioned I don’t think it will stay cheap once the export facilities are up and running.

    Who is blogging credibly about natural gas?

    Ron is doing a super job on oil here but there’s not a lot about natural gas at this site.

    There’s no way I can put across the absolutely giddy natural gas outlook , at least as it appears to the author of this piece. It must be read to be appreciated.

    The scary part is that there are tens of millions of people who want to believe this sort of stuff and therefore they will believe it no matter how greatly exaggerated it may be.

    http://www.foxnews.com/us/2014/02/20/gulf-coast-set-for-bakken-like-boom-with-liquefied-natural-gas/

  15. Ken Barrows says:

    If it takes about 120 additional wells to keep production level and each well costs an average of $6 M, that’s $720 million for no increase in production. I find it difficult to see how, without the alchemy of finance, that this is a profitable venture with current oil prices or even with prices substantially higher.

    I know that’s macro and I hear that the marginal barrel costs less than the current oil price. Is there a detailed analysis of this assertion?

    • Nony says:

      1. Is this really so hard to understand? Each well is designed to pay for itself (as an investment decision). The profit (or NPV) is the same whether the gas is replacing new depletion or going to new customers or whatever. As long as price is the same.

      2. NEWS FLASH! There was decline and a “need to drill forever” even before shale gas. Conventional resources have decline also. It’s not like you drill a conventional well and come back 20 years later and it’s production has stayed the same.

      • SRSrocco says:

        Nony,

        By the way… how old are you?

        And for your reply about ITS EASY TO UNDERSTAND… the reason why the U.S. Shale Gas Industry is still ALIVE today has to due more with the Fed manipulating interest rates to ZERO as well as Wall Street wheeling and dealing rather than companies making money producing natural gas — because they are not.

        Without those two factors, The U.S. Gas Industry would have collapsed a few years ago.

        Is that so hard to understand?

        steve

      • TechGuy says:

        “There was decline and a “need to drill forever” even before shale gas. Conventional resources have decline also”

        You hit the nail on the head, but you didn’t notice. Oil majors invested 3.5 Trillion to maintain flat conventional oil production. Conventional Oil is still and will be the backbone of global production as Unconventional drilling has bottlenecks that cap production. At a some point (rapid depletion, trucks, rigs, roads, etc) will eventual prevent further production growth of unconventional oil. Because there is so much infrastruture needed to drill and begin oil to market, it will prevent production from scaling up.
        In the meantime, conventional production either declines or become to expensive for market prices. Even if the Sweet spots for LTO is endless, it will plateau because of bottlenecks. Conventional production will decline as CapEx rises above the markets ablity to absorb higher prices. Global production will fall.

        That said, I think the era of further LTO expansion is about to be end now that bankers are no longer willing to provide the capital to expand production. Even if geology wasn’t a factor, credit is. Without cheap and easy credit LTO plays will come to an end. The only shot in the dark is if the gov’t enters the game by providing Federal loan guarantees or the Federal reserve starts investing in LTO debt (freeing up capital and permitting banks to off-load risks).

        As far as Kolpits presentation, I think we may not see the pull back in conventional production for a few years as the CapEx cuts will effect future production. Usually CapEx investments take 3 to 5 years before a project begins delivering oil to the market. So if they cut this year, its going to effect production in a few years, not necessarily this year or the next.

        • Nony says:

          Capital, time, and ingenuity can reduce most bottlenecks. For instance if labor is an issue, you train people. There are some bottlenecks sure (NIMBY for instance) that are less tractable.

          This idea that billions are being poured into the Bakken just as some sort of mistake and will eventually be stopped…is just ignorant. You find me a fresh Bakken and I will find you PLENTY of capital to exploit it. The problem is more that the other plays have not had the same results (and yeah, that’s why they have 50 wells dug instead of 5000). But find an exact duplicate Bakken? Money would flooooow!

          One other thing to consider on the declines, exploration, etc. is the number of dry holes in conventional exploration as opposed to unconventional. Yeah, the Bakken wells have high declines, but they are also 98-99% not dry in sweet spots and 85-90% not dry in “unsweet spots”.

          • Calhoun says:

            Yeah, just find me a fresh Bakken. Just do that. OK?

            • Nony says:

              There may not be another one. I mean, after EF, which is already known and being exploited. Maybe the Permian…donno. The other shales around the country have not worked out to be oily yet. For example Utica was supposed to be the oily counterpart to the Marcellus, but it has not delivered crude (has gas). Even Hamm’s SCOOP has turned out to be more gassy than first touted. Bakken may be a rare beast with how oily it is.

          • Yeah, the Bakken wells have high declines, but they are also 98-99% not dry in sweet spots and 85-90% not dry in “unsweet spots”.

            Nony, could you post the link where you found this information. I have been looking for the “percent of Bakken wells that are dry holes” for a couple of years. Now it looks like you have found it.

            Thanks in advance for posting this link.

            • Nony says:

              I’m not sure if you are really being nice or sarcastic. It’s OK if latter though.

              See the USGS fact sheet, table 1: http://pubs.usgs.gov/fs/2013/3013/fs2013-3013.pdf

              Here’s some commentary from Lynn Helms:

              http://www.northdakotaoilcan.com/news/News173/

              • Actually I was having it both ways. I wanted to be nice if you actually had a link but sarcastic if you had no link. And it turned out to be the latter.

                But you came close with the Helms link: Dry holes in the Bakken are rare… 99.9% of the wells are producers, and 80% are profitable.

                That was posted over a year ago from data that is a bit older than that. And he is correct, totally dry holes are extremely rare in the Bakken, almost every well produces some oil. But an awful lot of them produce only a tiny amount of oil.

                Chesapeake Drills Unsuccessful Wells in Southwest ND
                Chesapeake’s attempt to find the southern edge of the Bakken, is being described as the largest failure in drilling in the state since the 1980’s.

                There are a few well sites in western North Dakota that look more like ghost towns than multi-million dollar holes…

                The state only allows a non paying well to stay on the landscape for a year.

                I guess by “non paying” they mean no royalty taxes paid. But the point is most all wells produce some oil but the percentage of wells that do not produce enough oil to pay expenses was 80 percent in 2012. But I would bet that figure has risen considerably since.

              • Dennis Coyne says:

                Hi Ron,

                The USGS link is more interesting and confirms some of what Nony said. One thing I think he got wrong was the size of the sweet spots, in a few of the areas the USGS analyzed they are significant, in many of the assessment units (AU) the sweet spots are not very large.

                So while it is correct to say that the area of the Bakken/Three Forks is large, it is not correct to assume that the sweet spots are also large.

            • Nony says:

              Here’s some discussion (note the different blog entries):

              http://themilliondollarway.blogspot.com/search?q=dry+hole

              P.s. I think the Lynn commentary before is interesting. It looks like as long as you are in the general Bakken region (not south of it), you’re OK. It’s a large area. Rockman may say it’s not a single field, but it might as well be in some ways given the lack of dry holes. Also she mentions finding oil regulary in the Bakken “and below”. I wonder if that means the TF is also as “regular”. (Although my impression is that the TF is not as high a producer, don’t have data, just my impression.)

              She also mentions the Tyler. That’s actually a formation ABOVE the Bakken. It extends further south (into South Dakota). Potentially it is a play for companies that lack acreage in the classic Bakken 4 counties. But so far, it has not paid off (i.e. Tyler holes were dry). Cheseapeake tried some acrage in the southern ND, but it did not work.

      • Ken Barrows says:

        My basic point is that the Bakken data suggests $1B in additional wells per month for about 1 M additional barrels. Sure, price will attract drillers. Seems that price should be multiples higher than currently.

        Data is inconsistent. Some of the reported numbers are right, some are way off. If it really costs $1 B for 1 M additional barrels, the bust will happen soon.

        • Anonymous says:

          1. Do you really think billions of dollars are being invested for something which is so simply calculated to not have a good return?

          2. Those wells have simple payback on the order of 16 months. Calculated as $80 wellhead price, 16 months to cum of 100,000 barrels (from Enno’s curves), 8 million well* cost. Yes, there’s more expenses but also there’s gas realized along with everything after 16 months being gravy. Those wells are NOT money losers. There’s a reason why CLR, etc. can keep plowing back earnings into new wells…because they are generating earnings!

          *This is the newer figure from CLR, documented in official presentations, SEC filings, etc. But even if you go with 10 million/well, big deal. It just extends the simple payback a few months further.

          • Dennis Coyne says:

            Transport costs are $12/barrel, OPEX is $4/barrel but is offset by NG and NGL sales, royalties and taxes are 26.5 % of the wellhead revenue. There is not a lot of gravy after reaching 100 kb because the rate slows down quite a bit, firms do not look at simple payback they use NPV. So lets take $80/barrel and deduct taxes and royalties (I’ll use 25 % to make the math easy) we are left with $60/barrel and we will assume the coastal refineries will pay $92/barrel at the refinery gate to cover transport costs. So we need 8 million divided by 60 or 133 kb for simple payback which is reached in 2.5 years which works out to be profitable as long as prices don’t decrease and the sweet spots don’t run out of room for more wells. I think when we get to 10,000 wells (possibly sooner) we will start to see a decrease in new well EUR, at some point (2 or 3 years) new wells will no longer be profitable and the decline will begin. At present drilling rates of about 1800 wells per year we get to 10,400 Bakken/Three Forks wells in Dec 2015, when we get to Dec 2016 we would be at 12,200 wells (assuming current rates of drilling and fracking) and decline will likely be apparent.

            • Nony says:

              Do you have any info on the average well spacing? Average well spacing in the sweet spots (maybe using assumed USGS sweet spot amounts and some prediction of existing wells being already preferentially in the sweet spots).

              What I’m getting at is some idea of “when we run out of sweet spots”. The average well staying at same productivity for last 5 years is very strange. I think when the average starts going down, the peak is not far behind, because the rate of drilling will go down to avoid the average well getting below a level that is not financially sound.

              Here’s a couple interesting links on downspacing limits in the Bakken. (Note some limited communication of the wells is probably desirable to extract most resource, but obviously this is a trade-off given the added cost.)

              http://www.slideshare.net/drillinginfo/technical-paperwellspacing

              http://info.drillinginfo.com/well-spacing-bakken-shale-oil/

  16. Watcher says:

    From the previous post, there is a pipeline briefer who quoted over 2000 individual truck trips (of apparently about 15 miles) to drill/frack and haul oil from a single brand new well in its first year. 37% of those are after the well starts to flow. It’s hauling output oil. 63% haul pipes and proppant and water. That is the quote from a pipeline guy, who should WANT them to lay pipeline, but knows that they can’t.

    The Marcellus, funded by NGLs, not nat gas, presumably has the same truck count and trip count. Liquids are liquids. You haul by truck. And Nony, the reason it is different in shale vs conventional is again, the trucks. The shale wells die fast — so fast that you don’t put a pipeline to each well. It will be dead by the time it is ready. So you use trucks. With conventional wells, you can install a pipeline for the flow.

    I am suspicious of all these models based on historical data. Only the last year’s worth of data is probably solid because the frack stage count and techniques perhaps as far back as just a few years ago were inferior.

    And lastly, again, the trucks. The well count is growing fast. The road system isn’t. There is careful scrutiny of drill rig count (when clearly drilled but not completed wells are growing in inventory — drill rigs are not the decisive parameter, frack equipment and material is), but there is no scrutiny that I have heard of regarding truck count, road miles on which to fit these increasing truck trip totals, and sheer hauling weight capability. THAT is probably the decisive parameter for predicting peak, but we have no data on it.

    • Calhoun says:

      Excellent point. There are any number of pressure points that could put a non-geological limit on LTO production. Will it be too few trucks? Too few roads? Bankers with cold feet? Cash flow problems? Manpower shortage?

      • Doug Leighton says:

        Or perhaps all five. One (the only) engineer I know orchestrating an oil play in North Dakota told me his main problem at the moment involves trucks on iffy roads. He also said that his neighbors were facing a variety of different issues, including money (as in lack of it).

    • Dennis Coyne says:

      Hi Watcher,

      I think fracking is the main bottleneck, I am pretty sure that roads and trucks are not the problem, but I could be wrong 🙂

      As far as historical data, since 2010 there has been very little change in well profile, based on NDIC well data shared by Enno.

      A big jump from 2007 to 2008 and then a small increase from 2009 to 2010, then pretty steady from 2010 to 2013. See chart below

      • I think fracking is the main bottleneck, I am pretty sure that roads and trucks are not the problem, but I could be wrong.

        Dennis, fracking is roads and trucks. This is about gas but the same is true for oil. (Bold theirs)

        What goes in and out of Hydraulic Fracturing
        Each gas well requires an average of 400 tanker trucks to carry water and supplies to and from the site.

        It takes 1-8 million gallons of water to complete each fracturing job.

        • Watcher says:

          Trucks are trucks, regardless of what they carry. 2000 trips in year 1. 37% carrying oil. 63% carrying pipes and fracking stuff. They get in the same traffic jams the oil carrying trucks will get in.

          The well sites are not along paved roads. Some of this is dirt roads. This is not Boston. There hasn’t been 350 years of road building. 2000 truck trips on dirt roads in year 1. Fracking time is over 100 days. Three months, and some of that could be traffic jams on dirt roads.

          Further, the well count grows. The 2 year old wells producing 100 bpd have to be oil loaded onto a truck every 2 or three days. That truck can get in the way of a fracking truck. Only so many miles of roads for more and more and more truck trips — because the well count grows. You don’t even need snow to obstruct all this. A rainy month (I recall April or May last year Helms talked about muddy roads) will obstruct.

          It occurs to me the pipeline limit is not just well flow rate decline. There are just so many of these wells that owner permissions for pipeline routing becomes a significant obstacle — because the owners will be educated about rapid well death and will want the costs of pipeline removal included in all deals.

        • Watcher says:

          As buried somewhere above, Ron, it occurs to me that the water separator you found on well sites . . . for a multi well pad . . . maybe that water is useable for the next well on the pad.

          Or not. Monterrey talk says only fresh water can be used. Salt water can’t be. Maybe what comes up with oil isn’t fresh enough. Dunno.

          Hmmm even for a 10% oil 90% water cut, that’s still only hmm 400 barrels X 9 = 3600 barrels X 42 gallons = 151,200 gallons of water per day. I have seen no photos suggesting tanks that big. That water must just be sent back underground, not mixed for fracking, though 90 days X 151K is about the water total you quoted as required.

          • TechGuy says:

            “Or not. Monterrey talk says only fresh water can be used. Salt water can’t be. Maybe what comes up with oil isn’t fresh enough. Dunno.”

            Probably because Salt water is corrosive and they must inject the water under very high pressure.

      • Watcher says:

        Dunno what you’re saying. The short 2013 line is clearly above the others. How can that be if technology was static and the sweet spots already drilled.

        • Watcher, the magic word here is cumulative.

        • Dennis Coyne says:

          Watcher,

          You are correct, the 2013 line is above the 2011 line by 5 % or so after 11 months. Compared to increases before 2010 it is not a big change.

          Look closely at the chart, output increases slightly from 2010 to 2011, then drops in 2012 and then increases again in 2013, so the story of smoothly increasing well output due to improved fracking methods and longer laterals etc does not really ring true. There is some randomness in the well output results, and there is no doubt some improvement in fracking methods, but judging by the small changes since 2010 compared with 2007 to 2010 it looks to me that we are approaching diminishing returns on the technological improvement. It is also possible that the technological improvements may be running up against no more room in the sweet spots it is pretty hard to tell.

          In my previous comment:
          I did not say the technology was static, the point is that the technology is increasing well output by very little overall since 2010, I also did not say anything about sweet spots being fully drilled, though this will happen at some point, I have no idea how soon it will be.

          • Nony says:

            Some of the evolution seems to be cost reduction. Some of this is technology (pads, reclamation, etc.). Others could be economies of scale, shortages (of talent, machines) being filled.

            Since the output is staying the same, the simplest explanation would be static technology as far as production optimization and sweet spots still having room. Could be evolution in terms of cost reduction going on. Also, could be some evolution in geological understanding (i.e. finding more sweet spots). It is fascinating though that the output has stayed so constant for 5 years now and for 5000 wells drilled.

          • Watcher says:

            Well, wait a minute. Technology has more to overcome than simply a desired/expected appearance of substantial gains over wells drilled 3 years ago. It has to overcome the exhaustion of sweetspots, too.

            So the 5% increase is a fairly huge technology increase if there is also a sweetspot loss burden tied around its neck. Orrrrr . . . if there is also increasing traffic jam burden tied around its neck.

            We probably do need to keep in mind that “boom” is defined by how many truck driver jobs, and waitress jobs and yes, oil worker jobs there are. Even if oil output is in decline, but more jobs are created to try to slow that decline, it will still be a “boom”.

          • Watcher says:

            BTW just went back to the director’s cut. There were 113 new well completions in December. That’s 113 X (call it) 400 bpd = 45,200 bpd of brand spanking new production.

            But . . . the field was down 48K bpd for the month. Lots of wells were shut in with a net decrease of 27 wells producing, so 113 + 27 says 140 wells were shut down.

            But with 45200 bpd of new production coming online for the month, from completed fracking, but a crash in overall production — clearly the loss of production from already existing wells is how that happened, yes?

            • Watcher says:

              Hmm taking issue with myself. 45200 bpd + 48K decline = 93200 bpd the loss of which would need to be explained by 140 wells shut in. 93K / 140 = 664 bpd lost per well.

              This is too big a number for old wells. They don’t flow that much. So we had loss from wells not 100% shut in, too, which does make sense in snow.

              • Dennis Coyne says:

                Hi Watcher,

                If we just focus on the Bakken, there was an increase in wells producing of 40 wells, if we assume all 113 completions were in the Bakken then 73 wells were shut in (likely due to weather) in the Bakken. I also don’t know what a well completion means, does it mean the well is drilled and tested, but waiting on fracking services? I think the 40 well increase in producing Bakken wells is the number to focus on. If that is correct it would suggest a legacy decline of 64k per month if initial production is 400 b/d per well.

                • If we just focus on the Bakken, there was an increase in wells producing of 40 wells, if we assume all 113 completions were in the Bakken then 73 wells were shut in (likely due to weather) in the Bakken.

                  I don’t think so. Wells shut in are wells shut down, not just shut in because of the weather. Wells that might be shut down for a few days, or even weeks, because of the weather are still counted as producing wells. Wells age, stop producing more than a few barrels per day, and are shut down and capped because they are no longer economical.

                  Anyway the North Dakota statistics give us the numbers. The Bakken had an increase of 40 wells while all North Dakota had a decrease of 62 wells. That means at least 102 wells somewhere in North Dakota had to be shut down.

                  Wells   Bakken  All ND  Wells Outside the Bakken
                  Nov-13	6,784	9,718	2,934
                  Dec-13	6,824	9,656	2,832
                  	   40	  -62	 -102
                  

                  Well completions is wells completed. That means totally completed, fracked and on line.
                  Days from spud to initial production increased 18 days to 132.
                  Well completions means those who have reached that point, and it took an average of 132 days for all wells completed in December.

            • Helms data in his Director’s Cut, unless he specifies otherwise, is for all North Dakota, not just the Bakken. North Dakota production in December was down 53,226 barrels per day.

              Something I found interesting:
              862,978 barrels per day or 93% from Bakken and Three Forks
              60,249 barrels per day or 7% from legacy conventional pools
              6,803 Wells or 68% are unconventional Bakken-Three Forks wells
              3,212 wells or 32% produce from legacy conventional pools

              68% of the wells are producing 93% of the oil. 32% of the wells are producing 7% of the oil. I would guess this is because that all the conventional wells have been there for many years and are mostly stripper wells.

              The Bakken-Three Forks wells are producing 126.85 bp/d
              The conventional wells are producing 18.76 bp/d

              • Watcher says:

                “Well completions is wells completed. That means totally completed, fracked and on line.”

                THAT is the number to focus on. THAT is the source of brand spanking new production. That production was offset, in total, plus an additional 48-53K loss, due to loss of output from ALREADY producing wells.

                More than 90K bpd was lost in the month from already producing wells.

                To throw a further moneky wrench in . . . some of those ALREADY producing wells may have been some of the newly completed wells. Completed first week of December. Output interrupted in 2nd and 3rd week. haha

                • Dennis Coyne says:

                  Hi Watcher,

                  There were 113 completions, lets guess 100 of these were in the Bakken/Three Forks. You are assuming that all 100 of these wells started producing in December and when NDIC also says the number of producing wells increased by 40, that 60 wells in the Bakken Three Forks were shut in. Is that correct?

                  I was looking through Enno’s data on wells that have been shut in in North Dakota since the end of 2007. I separated out Bakken from non-Bakken wells and since Jan 2008 only 42 of 6378 Bakken wells have been shut in (less than 1 %) during 2012 and 2013 and about 84 wells over the 2008 to 2013 period. That is about 1.2 wells per month over the entire period and an increase to 1.75 wells per month over the most recent 24 months. That is quite a large jump in wells shut down in December 2013, from a 2 wells/month average to 60 wells per month, does that seem plausible?

  17. Old farmer mac says:

    Given the amount of money at stake and the apparent profitability of the wells even though they don’t produce much after the first few years it won’t be any problem building enough new roads to service the Bakken.

    The land is mostly flat and it appears that most of the roads needed can be built at the rate of a mile or more a day with a bulldozer, a motor grader and a dozen dump trucks hauling gravel. I am referring to roads that are exclusively for the use of oil companies here, the roads that will not be maintained by the state or local highway department.Given that the truck trip count per well is well over a thousand trips and maybe closer to two thousand , a hundred or even two or three hundred more truck trips won’t matter much. Gravel is cheap and all you need to drive even the biggest trucks at low speeds is a foot of crushed stone laid down wide enough to make the curves.The cure for muddy spots is a few more loads of stone and a few minutes with the motor grader.Remember these are privately owned roads closed to everybody but oil company contractors and most likely no permitting or engineering work or anything of that sort is needed to build one beyond the engineer specifying the route on a plat.

    According to the article I linked to in Scientific American a couple of days ago two thousand five hundred miles of pipeline were laid in North Dakota last year. I have looked for pictures of these pipes and almost all of them are small diameter of about a foot or less.This leads me to think they are mostly being laid from the rail terminals back toward the actual oil wells to spots where enough trucks can reach the outer end to make good use of the pipelines. Most of them are probably pretty short I will guess less no longer than fifty miles max.

    Such small diameter lines are not that expensive and probably extremely easy to permit and build in North Dakota and it wouldn’t take long at all to save enough in trucking costs to pay for one.It commonly costs about eighty to ninety dollars an hour here in the sleepy depressed south these days to hire a dump truck and both driver’s and mechanics wages are dirt cheap compared to ND.I wouldn’t be surprised if the costs are over double there.

    A twelve inch pipe laid along side a road for twenty miles would be ample to take all the trucks hauling crude to a terminal and deadheading back to the wells of that twenty miles.

    Having said all this the things I had to say recently about getting a lot of extra trucks up there for a few weeks work still apply.

    Now as to how the state and localities are dealing with maintaining the public roads given the oil related traffic I don’t know but most rural paved roads won’t last a week under a steady stream of fully loaded trucks and rural highways aren’t going to last a year without needing a new layer of asphalt.

    But you just keep that old motor grader handy along with the phone number of the closest gravel quarry when you own the road and when the ruts get deep enough to slow down the trucks you run the grader. When that no longer suffices you buy more gravel for the trouble spots and the trucks never stop rolling.

    I misspent a couple of the years of my youth around really big construction jobs driving fifty ton Cat dump trucks and other construction machinery and know whereof I speak.Fifty ton trucks were the big ones back in those days and they are still the standard for most heavy construction work but the trucks used in mines nowadays make a fifty look like a golf cart.

    • Nony says:

      I haven’t read much about the Bakken roads, but in the Eagle Ford, have heard that they are just reverting to gravel until the boom is over.

  18. Old farmer mac says:

    This seems likely to be the solution to the problem of rural roads in the Bakken too. Local folks who aren’t making any money out of the oil are probably few in number compared to the ones who are making out financially and there just aren’t that many people in rural ND anyway.
    The oil companies will manage to buy and bribe their way past the road issue.

  19. Old farmer mac says:

    Tight oil and gas are already in production in Florida and a boom in the industry there seems to be in the making.

    Whether it can happen or not is real question given that Florida is a state with a huge population and huge tourism industry.

    There are a hell of a lot of rich nature lovers in Florida as well as millions of people who make their money out of businesses that might be negatively impacted by oil extraction.

    I think the oil wannabe’s in Florida are going to have a long hard fight on their hands but in the end they will probably win it because Florida like every place else has money troubles that will get worse as time passes and eventually the tax revenue argument will trump the nature preservation and tourism arguments.YMMV.

    http://articles.sun-sentinel.com/2014-02-21/news/fl-oil-boom-expands-everglades-20140220_1_oil-drilling-drilling-plans-david-mica

  20. Old farmer mac says:

    These quotes are from a current Telegraph article about the connection between the Scottish independence issue and the future of the North Sea oil and gas industry.

    ” Mr Cameron suggested that central government resources would be essential in future to develop the potential for drilling new oil and gas wells in the North Sea.

    ”Government sources in London added that Scotland alone could not afford the billions of pounds in tax breaks being provided to decommission old platforms in the North Sea and develop new gas fields without resources from Westminster.”

    “This week I will take the Cabinet to Scotland where we will set out how the UK Government can maximise the benefit of North Sea oil and gas to the UK economy for decades into the future, giving a vital boost to local communities and families across Scotland,” he said.

    ”One Westminster source said: “You might argue Scotland couldn’t afford it on its own.”

    Now reading between the lines the message that comes thru loud and clear is that North Sea oil and gas production is in or will be a matter for the history books within the next decade or two and that the costs of getting North Sea oil and gas to market is already so high that it cannot be accomplished without subsidies in the form of outright cost sharing and cutting tax rates for the oil companies to the bone.

    The North Sea is way past peak and given the high cost of deep water oil and gas I doubt it will last much longer as a major play.

    • Doug Leighton says:

      Mac, “…costs of getting North Sea oil and gas to market is already so high that it cannot be accomplished without subsidies in the form of outright cost sharing and cutting tax rates for the oil companies to the bone.”

      This could just as easily be a quote referring to Alaska’s North Slope oil play.

  21. KC says:

    CNBC right now has a report about the Bakken — “Boom or Bust?”

    • KC says:

      The Williston [mayor] at the end of the show said, basically, if the EPA will just get out of the way, “then I think we’re just at the beginning of a 25-year cycle.”

      Umm. Yea.

  22. Thanks for the heads up KC, but it is over now. However I found it online here:
    America’s Oil Rush: Bust or Boom

    • SRSrocco says:

      Ron,

      Thanks for the link. I have to say… after watching the Grand BS Show by the MSM, Wall Street, Federal Reserve, Member Banks and U.S. Energy Industry, I wonder if we really have any chance in making it through the next BIG ONE — the economic depression and collapse that will make the 1930’s look like a cakewalk.

      It is amazing to see the amount of intelligence in these individuals while at the same time, the ability for them to make seriously flawed assumptions and forecasts.

      Nissam Taleb who wrote the Black Swan correctly states, “societies and economies need a certain amount of “redundancy & inefficiency” built in the system to survive.” We have done quite the opposite by making everything “overly efficient.”

      In the county (western U.S.) I now live in (left the suburbs 6 years ago), had 40 small milk dairies back in the 1960’s. Today there are only four. One mega-dairy, one medium sized and two small. The mega-dairy was taken over by the bank in 2009 after the collapse in milk prices. The bank still runs the dairy today.

      Same thing has happened to several other Mega-dairies in the adjacent counties — taken over by the bank. What happens when the SHTF? Back in the 1960’s, we could lose say 3-5 of the small milk dairies and it wouldn’t have been a problem. Why? Because they were small and mostly without debt.

      However, today… when the Mega-dairies go under when the financial system finally crashes? What then?

      The whole system is highly leveraged to debt. I just gave an example of the local dairy industry, because it is one of the major industries in this area.

      The more I look at Gail Tverberg’s forecast for future oil production… the more I realize that it will probably end up being more optimistic than what unfolds.

      steve

      • Doug Leighton says:

        Steve, I think you’re just a bloody defeatist pessimist man. Think about how happy Mother Earth will be, not being turned into a desert wasteland – as quickly!

        • Doug, man do you have it wrong. When things collapse we will all be so hungry we will eat the songbirds out of the trees. And those trees will all be cut down for firewood. The decline of oil and the collapse will be the very thing that turns the planet into a desert wasteland – and quickly!

          • Doug Leighton says:

            I’ll be dammed! Sort of thought that way too but was just trying to put a positive spin on things. Think I’m just going to read Patrick’s comments from now on.

          • canabuck says:

            To give one example: The people of Ethiopia have cut down 94% of the forests in the country since 1950.
            And we in North America have done a good job of cutting the forests on the central plains.
            As long as we have a fairly good life, do many people really care how the next generation will live?

  23. Patrick R says:

    All very convincing except that Gail has been producing that chart for years with the shark fin always just a year ahead…somehow the forces of momentum seem to keep pushing on through the gravity of systemic collapse. What are we to conclude? The shape is right but her timing is too pessimistic? Or could it be that she is too gloomy on both counts?

    If she is wrong, or at least not completely right, could it be that under duress human society does prove to be more adaptive than she conceives?

    Respect to Gail and others who put their money down and make predictions; I ain’t doin’ it! Suffice to say that I expect more surprises in every direction, as my only firm view is that we live in an age of discontinuities; tomorrow will be the same but not as this.

    Steve you are right to mention the Great Depression, Richard Florida is very good on how our times are an echo of this period (The Great Reset). But remember history rhymes rather than repeats. And also that countries, economies, and communities, are like individuals. If they resist change they provoke crisis…. The longer we try to keep the cork in the bottle the bigger the pop. So maybe Gail’s shark fin will swim into view next year, or the next, or the next…. Meantime:

    http://www.theguardian.com/environment/2014/feb/17/amory-lovins-renewable-energy

    • SRSrocco says:

      Doug,

      Maybe you are right….LOL. My extended family never invites me to parties anymore. Ya wonder why? By the way, even if we had a sudden economic collapse, it would not be good for the global warming problem. Why? Because the sudden drop in aerosols that are burned during our modern economy would have an impact of +1.8 degree C increase in global warming. It looks like scientists found out that aerosols such as sulfur dioxide in the atmosphere have been actually keeping the climate cooler…. who would have thunk… huh?

      Patrick,

      I am with you on the “Forecasts.” I have no idea when the PHAT LADY WILL SING, but when she does… I will bet my bottom silver dollar that it will be THE BIG ONE as Sanford always said on the show “Sanford & Son.”

      Lastly, the darling Chesapeake will release its Q4 2013 results on Wed, Feb 26th. They already announced the following earlier this month:

      Chesapeake Energy Corporation Announces 2014 Absolute Production Growth Target of 2 – 4% on Planned Capital Expenditure Decrease of 20%

      · Expected total capital expenditures to range from $5.2 – $5.6 billion
      · Projected production growth of 8 – 10%, adjusted for asset sales
      · Estimated per-unit production and G&A expenses to decline 10% and 25%, respectively, year over year
      —————–
      So, the say there are going to increase “Absolute Production” 2-4% while they cut CAPEX by 20%… that is going to be interesting to see.

      steve

      • TechGuy says:

        “THE BIG ONE as Sanford always said on the show “Sanford & Son.””
        Funny you mentioned that, since Fred would say: Elizabeth, I am coming to join you!” If you recall Queen Elizabeth was referred to as the “Red Queen”!

        Steve, I am total agreement. If by some miracle that an Oil crunch does not hit us. it will be the economic crunch that follows up with the knockout punch. We can’t print our way out of the debt crisis, and the politicians have spend everything nailed down. Too many promises made to too many people. They’ve sold our entire civilization for trinkets.

        “So, the say there are going to increase “Absolute Production” 2-4% while they cut CAPEX by 20%”

        Perhaps this is not too difficult. Consider if they cut CapEx for future projects that do not produce 2 to 5 years in the future. They could easily achieve short term increases while cutting costs. However, its the future production that will suffer since they cut or stopped developing future projects. For instance I can cut my fuel costs for about a week by not refueling my car. Eventually I will deplete my gas tank, but for a short period I managed to get by without spending on fuel.

        “Why? Because the sudden drop in aerosols that are burned during our modern economy”

        I believe you saw the NOVA episode about jet contrails and pollutants servicing as water vapor nucleation to increase cloud formation. As Jet travel declines it will effectively increase the amount of sunlight reaching the surface. http://www.pbs.org/wgbh/nova/earth/understanding-global-dimming.html

        RonP Wrote:
        “When things collapse we will all be so hungry we will eat the songbirds out of the trees. ”

        Ron, I am beginning to have some doubts about this type of end. I think when the collapse happens we will see a large number of nuclear plant meltdowns and spent pool fires before people have a chance to get to that point. Considering the damage done by a single plant Fukushima, that is partially contained, I can’t imagine surviving the loss of a hundred or more nuclear plants. I think every industrialized nation has unknownly built themselves a doomsday machine. Like the Doomsday machine in the Dr Stranglelove movie, It can’t be turned off, but, unlike in the movie, this doomsday machine does not require a nuclear war to trigger it.

        The only way to avoid triggering the doomsday machine is to forever prevent a war with any nation that has nuclear power plants, prevent an industrialized world economic collapse, or any natural disasters in regions with many plants.

    • Watcher says:

      You’re right about this. Those charts from the peak oil folks come out every year with the same shape moved one year to the right.

      • You’re wrong about this. There is no such person as “peak oil folks”. Every peak oiler has a different opinion as to when world oil production will peak or peaked. To lump them all together and to say they all make the same prediction is nothing more than willful ignorance.

  24. Old farmer mac says:

    So, the say there are going to increase “Absolute Production” 2-4% while they cut CAPEX by 20%… that is going to be interesting to see.

    They might actually be able to pull a that rabbit out of the hat this year coming up due to the nature of the business but if they do the impact on next years and the year after that’s bottom line will be ghastly.

    The way this could happen is first step that they put some of the CAPEX (The infernal spell checker will not allow me to type capex in small letters until just now after three or four tries!!) money into souping up production from existing wells and or finishing up some wells on the schedule for the next year ahead of schedule.

    Second step suppose the books looked like this ( these numbers are imaginary!) :

    capex 1,000,000,000 currently. Cut that to 800,000000. Spend some of the 200,000,000 on new wells a little ahead of schedule bringing them on line before the year is out and upgrading production at existing wells.

    (This might hurt future production at old wells according to what I have read somewhere. Apparently oil wells are like the goose that laid the golden eggs. You are supposed to get more oil in the end by going slow than by goosing a well for a short term gain in production.)

    Production will be up, expenditures will be down, profits will rise sharply and the managers keep their jobs another year.

    Investors who know enough to understand what is going on have a great opportunity to get out at a profit while the business press waxes eloquent about how well the company is doing.

  25. marmico says:

    Is Schlumberger’s Broadband Sequence fracking technique cornucopian?

    • The word “cornucopian” refers to a person with a pollyannaish world view, not a process.

      • marmico says:

        Hardly, the issue on this thread seems to be that technological innovation in the LTO basins will not offset fewer “sweet spots”.

        There are over 600 wells in the Bakken to be fracked. That’s why your prediction of a 2014 peak is premature and will be confined to the dustbin of history. Less fracking time, less fracking cost, more production per new (or reworked legacy) well.

        Coyne’s 1.2 mb/d model will be the closest. Earlier, I don’t recall which post, CERA (IHS) [the monster Yergin’s firm] projected that 2013 Bakken new well efficiency was up 5% year on year. Exactly, what Ovi’s chart says.

        Meanwhile, back on old farmer mac’s farm, McClendon (former Chesapeake CEO) has a $5 billion startup in the Utica LTO basin.

        • That’s why your prediction of a 2014 peak is premature and will be confined to the dustbin of history.

          Hardly, because I never made any such prediction. Please do not ever again say I made a prediction that I never made. That is a cheap trick that really pisses me off.

          And what I wrote above is true and hardly deserves your comment of “hardly”. A cornucopian does refer to a person with a pollyannaish world view. To say a process can be cornucopian is really quite absurd. Cornucopian refers to the opinion or opinions of a person. A process cannot possibly have an opinion. You are just being silly. Or perhaps you are not just being silly. Perhaps you really don’t know any better.

          • Dennis Coyne says:

            Hi Ron,

            You posted this a few months ago:

            “I am betting that North Dakota production will peak at about 1.1 to 1.2 million barrels per day sometime late 2014 or early 2015.”

            I think Marmico may have remembered the quote above , which does not say 2014, it says late 2014 to early 2015. But 2014 is not very far from what you actually predicted, if one interpreted that quote as Dec 2014 +/- 6 months which does not seem an unreasonable interpretation. Bottom line nobody knows when the peak will arrive in the Bakken, 2015- 2017 seems reasonable to me. Time will tell.

            See http://peakoilbarrel.com/bakken-update-production-slowing/comment-page-3/#comment-2921

            • robert wilson says:

              Consider the expression “I am betting…” Is that a true prediction or a suggestion that the odds are better than 50/50?

              • Correct, “I am betting” is totally different from “I predict”. I am still betting that the peak will be somewhere in that vicinity but it could easily be a year later.

                To say “I am betting” is an acknowledgement that the date is uncertain, that it could be by then or it could be later. But I am betting it will be somewhere near that time frame.

                • Dennis Coyne says:

                  Hmm. I guess we would have to ask if the bet is for a nickel or $100, to get a feel for if the bet is that the peak will happen in the future or it will happen between year x and year y. There are very few statements about the future that can be made with certainty, unless the conversation is limited to basic physics, and even then there is that uncertainty principle.

                • One thing that could change the trajectory is the terrible months of December 2012, January and February 2014. All three are going to be very bad production months for the Bakken. What effect will that have on the timing of the peak? Will it push it out three months or make it sooner?

                • Nony says:

                  It will push it out. After all, it’s delayed production.

                  However, we could also have an abnormally mild winter next year (and less of a seasonal dropoff) leading to a sooner peak.

                • Dennis Coyne says:

                  Good point Ron. And I think Nony’s guess that it will delay the peak is correct, if we assume all else is equal. Of course that is usually not the case, but it is pretty hard to forecast future events so assuming that things won’t change a lot in the near term is probably as good a guess as any.

        • Dennis Coyne says:

          Hi Marmico,

          Technology can help offset the lack of room to drill in the sweet spots, at some point the reduced productivity associated with non-sweet spots can no longer be offset with improved technology.

          If you look at the April 2013 USGS Study and calculate the number of wells that can be drilled profitably (I assume we need an average EUR per well of more than 220 kb) the areas assumed by the USGS lead to about 25000 wells at most in the North Dakota Bakken/Three Forks.

          Down spacing might work in the sweet spots and allow an extra 5000 wells, but it is hard to predict how much the EUR will decrease when the wells are spaced more tightly. Well costs might come down a little more as well, but eventually they will get to the point where they can be reduced no further. Technology helps, but there are no magic bullets.

        • Calhoun says:

          Marmico, “dustbin of history”? Come on, this thread hardly deserves that kind of polemic cliche. Will anyone give a damn about predictions once the decline kicks in? They’ll have way more important things on their minds, and that’s a prediction I’ll stand by. Ron offers informed (really informed) opinions on what he expects — he shouldn’t be criticized for that.

          • Hey, I am just proud to go down in history even if it is in the dustbin. 😉

            • Watcher says:

              Just went thru the Schlumberger presentation of their broadband technique. Looks like mostly marketing silliness. There is a particular mention that they have already used it in 500 different wells all over the place, Bakken, Eagleford, Haynsesomething and I guess some other gas plays.

              500 is a lot. If this were magical it would have already been embraced pretty widely. Their proprietary content has zero chance of staying secret and would already be known.

              I declare it a non event.

              • Nony says:

                It looks pretty cool though. Have you found an explanation of the rationale for the different size/shape/objects? I would like it spelled out what they are trying to do, a little more.

                Agreed, there needs to be more statistical evidence of production. Just one case study tells little.

                Interesting that the pitch seems to be cost/time reduction rather than production increase.

  26. KC says:

    Marmico meet Canabuck. You guys are made for each other!

  27. Ronald Walter says:

    Commercial development of the Williston Basin began ca. 1951. Oil was discovered near Williston in the year 1929 from a news source in an edition of a local newspaper dated in the year 1929. The Iverson No. 1 was what started it all.

    The Bakken Formation is going to produce a lot more oil in the future. The Bakken didn’t have its name until 1958 or so when a well was drilled on Henry Bakken’s farm.

    To gain the knowledge of its potential, a must read of the study is required.

    The Bakken has already been engineered, reverse engineering is helpful, but the real work has been done.

    http://www.undeerc.org/News-Publications/Leigh-Price-Paper/pdf/TextVersion.pdf

    The price says it all.

    • Anonymous says:

      Ron, The following material about the UK’s North Sea may be of interest; it seems well balanced. I edited it for brevity. http://www.bbc.co.uk/news/uk-scotland-scotland-business-26337438

      OIL AND GAS INDUSTRY FACES ‘BIGGEST CHALLENGE IN 50 YEARS’ 25 Feb. 2014 by Douglas Fraser BBC Business and economy editor, Scotland.

      “…Industry body Oil and Gas UK said only 15 wells were drilled last year despite strong levels of investment, reaching a record last year and sustained this year. Exploration drilling was down from 44 wells six years ago, only sufficient to recover a fraction of the estimated oil and gas remaining offshore. Britain’s waters contain an abundance of oil and gas yet to be found and it is critical we find the means to turn the current state of exploration around”

      Investment is scheduled to fall by nearly half within three years… Following the rapid decline in oil and gas production from UK waters in recent years, the rate of fall slowed during 2013, down by 8% to 1.43m barrels of oil per day, or its gas equivalent. Output is expected to rise during this year, as 25 new fields come on stream.

      Malcolm Webb, chief executive of Oil and Gas UK, said the results showed the contradictions at play between high investment but worrying trends in drilling, output and costs. He goes on: “Even if currently planned wells proceed, the rate of drilling is still too low to recover even a fraction of the estimated six to nine billion barrels yet to be found. Britain’s waters contain an abundance of oil and gas yet to be found and it is critical we find the means to turn the current state of exploration around. Rig availability and access to capital are the two main barriers noted by our members.”

      In addition to exploration wells, the industry last year drilled 120 development wells, a similar level to 2012. Much of the activity was in existing offshore oil and gas reserves, known as brownfield sites. ..”

      • Anonymous says:

        Ron,

        I’m not hiding the above behind “Anonymous”. It just came up that way.

        Doug

        • Doug, thanks for the link and comments. On the anonymous thing. You should get a box requesting your name and email address. Unless you fill in both your post will come up “Anonymous”. Your email address will not appear in or above your post, only your name.

  28. Mark_BC says:

    Sorry if I have missed this somewhere else, but could someone let me know what the typical lifetime production rates are for these wells? Their drilling costs are around $9 million, so how does this compare to the cash flow the companies get from the resulting production?

Comments are closed.