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Mark Anthony, is an IT professional and who had a scientific research background before joining the information revolution. Visit his blog: Stockology (http://stockology.blogspot.com/)
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  • Case Study Of Another Bakken Shale Oil Well

    After my last case study on a Bakken shale well, I decide to study another long history Bakken shale oil well, with no re-fracing done, to see how the classical Arps type curve, and my modified version works in projecting the long term productivity of the well.

    I want to demonstrate that the classical Arps formula, which the shale industry loves to use to project the EURs (Estimated Ultimate Recovery), tend to result in unrealistically high EURs, and that the long term productivity of the shale wells generally fall way below the industry's projections. A well that wasn't re-stimulated during its history will adequately reflect how the well's productivity declines naturally over time.

    The classical Arps Type Curve vs. Modified Arps Type Curve

    Let's re-cap about the classical Arps formula and how I modified it:

    (click to enlarge)

    Geologists Arthur Berman often criticized the industry for using the classical Arps formula which exhibit a hyperbolic decline with the long term decline rate approaching zero. In reality, shale wells exhibit a non-zero terminal decline, so they fall far behind the projections of the Arps formula in the long term. I agree with Berman. I proposed to add a exponential decaying factor to account for the terminal decline. See the chart above.

    This decay rate beta is small, so in the short term it makes little difference, but in the long term, it makes a huge difference. Let me use real production data to find out which one is right.

    The Whiting Federal 14-24H Bakken Shale Well

    The Bakken well I study is Federal 14-24H, well No. 15776. The link contains data on that well. The well was developed by Whiting Petroleum Corp. (NYSE:WLL). Production started on Sep. 22, 2005. So it has seven years of production. That's longer than the XTO Energy operated Sveen 34X-14 that I discussed in my last article. XTO is now part of Exxon Mobil (NYSE:XOM).

    See the monthly production data below. All the monthly days of production are full months, suggesting that production was never interrupted by any re-fracing operations or shut-downs.

    click to enlarge)

    This well is the kind of best performing shale wells that the industry would love to pitch to investors. When it started, it was one of the highest producing well at the time. The well decline was also one of the slowest. First year production decline was only 55%. Compare that to the 80%-85% first year decline in the latest Bakken wells!

    Modeling The Production Using Arps and Modified Arps Formula

    I found the following parameters to fit the actual production using both the classical and modified Arps formula:

    • IP = 400 BOE/Day for both formulas
    • B-Factor = 1.50 for both formulas
    • D = 0.00467/Day for the classical Arps formula
    • D = 0.00333/Day for my modified Arps formula
    • Decay factor Beta = 0.000333/Day for modified Arps
    • EUR from classical Arps is 640 MBOE (in 500 months)
    • EUR from modified Arps is 288 MBOE (<20 BPD in 110 months)

    Note that the long term decay factor Beta=0.000333/day is higher than the 0.0002/day I found for the Sveen 34X-14 well. So although the initial decline of the older wells flatten out faster, its longer term decline is actually steeper. The shale producers just can not gain.

    Here are projections from each formula compared to actual data:

    click to enlarge)

    Although both the classical Arps and my modified Arps fit the data nicely for the first three years, I can not find the right parameters to make the classical Arps curve fit the data in longer term. The Arps curve continues to flatten out while the actual production continued to decline beyond three years. On the other hand, my modified Arps curve still fits perfectly in the long term.

    This deviation is what Arthur Berman has been criticizing about. The data agrees with Arthur Berman and me in exhibiting continued decline beyond three years. The industry's classical Arps formula fails to follow the long trend.

    We can see the deviation more clearly when we plot the graph in logarithm scale, as shown below:

    click to enlarge)

    The logarithm scale plot above shows that the real production data continued to decline following almost a straight line, as suggested by my modified Arps curve. The classical Arps curve continued to flatten out to a horizontal line. Once again, the data clearly agrees with the modified Arps curve I proposed, not with the classical Arps.

    As a result, the cumulative production also follows the projection of the modified Arps. It deviates from the classical Arps curve:

    click to enlarge)

    The deviation of cumulative production is more clear when we plot the longer term trend as below:

    click to enlarge)

    As shown in the above graph. The classical Arps formula projects an EUR of 640 MBOE in 500 months (41.67 years). But modified Arps projects an EUR of not much more than 300 MBOE. If we cut off the well as it falls to below 20 BOE/day production level, which happens after 110 months (9.17 years) then the EUR will be 288 MBOE.

    The Well Data Disagrees with EUR from Classical Arps Formula

    As of today, the well has produced for 7 years. The accumulative production is 257 MBOE. How much more can it produce?

    According to North Dakota DMR data, well No. 15776, the well we discuss here, produced 569 barrels of oil and 1626 MCF of gas in 30 days in September 2012, or total of 849.3 BOE, or 28.3 BOE/day.

    This is not much higher than the 20 BOE/day cut off threshold.

    My modified Arps formula projects a production rate of 30.84 BOE/Day here. It seems to agree with the data pretty well. The model projects a current decline of roughly 0.000583/Day, or 19% decline annually!

    If this decline rate continues and we continue to produce until the production rate is almost zero, the remaining production will be 30.84 BPD / 0.000583 = 53 MBOE. If we cut off at a threshold:

    • If we cut off at 20 BPD, then 18.6 MBOE remains.
    • If we cut off at 15 BPD, then 27.2 MBOE remains.
    • If we cut off at 10 BPD, then 35.8 MBOE remains.

    I think the ultimate production of this well will be 280 MBOE, or roughly 44% of the EUR calculated from classical Arps formula.

    Investment Implications

    There are mounting indisputable evidences that critics like Arthur Berman are right. The shale industry has systematically exaggerated EUR projects of shale wells by more than a double. More over, they systematically under-calculated the armortization of the capital expenditures as the wells deplete much faster than they expected.

    Is there a Ponzi Scheme going on in the shale oil and gas industry? I will let others do the finger pointing. But as an independent investor, I have repeatedly warned people that they should NOT take the rosy pitches from shale development companies at face value. They should always take the projections with a grain of salt, and do their one data analysis to find out the truth. I encourage people to follow my math analysis to find out the reality.

    I keep urging people to get out the shale oil and gas sector, and get into the coal sector. People wrongly believe this meme that:

    "Coal is dead. Cheap and abundant natural gas is replacing coal"

    Just think about how big an investment opportunity it will be when people find out the truth, and shift their investment money from shale gas to coal. Currently there is a huge disparity that for every $75 people spend investing in the shale oil and gas sector, only $1 is invested in the US coal sector. I expect the ratio to be reversed to the other way, for every $1 people invest in the shale sector, there will be $10 invested in coal instead.

    Disclosure: I am long JRCC, ANR, ACI, BTU.

    Dec 17 8:53 AM | Link | 2 Comments
  • Case Study Of Production Of A Bakken Shale Well

    I repeatedly warned people that shale oil and gas producers tend to exaggerate the EURs (estimated ultimate recovery) of their wells and then under-estimate the fair armortization costs in order to show better financial results. I analyzed one most productive well owned by Continental Resources (NYSE:CLR) and showed why the EUR calculated by CLR was way too high. CLR claimed that the Charlotte 2-22H well will produce 561 MBOE. I estimated an EUR of 200 MBOE.

    How to Calculate a Reasonable EUR Estimate

    To re-cap, I proposed to modify the Arps Type Curve formula by introducing a decay factor of roughly 7% annually, or 0.0002/Day, so as to reflect a reasonable terminal decline of the wells. I also proposed a rule of thumb to estimate the EUR quickly:

    Wait 60 days or 90 days after production started, so that the production rate PR stabilizes. Take that production rate PR and multiply by 500 days to estimate how much more will be produce, add the volume already produced to get the EUR.

    How accurate does my method project? To find out, I need to test my method on a well with long production history to study. I found one such well to study. It started production on Sep 19, 2006.

    The Sveen 34x-14 Bakken Well Owned By XTO Energy

    The Sveen 34X-14 well was developed by XTO Energy Inc., which is now part of Exxon Mobil (NYSE:XOM). Here is a link to data on that well. There is a 230 pages comprehensive document on that well. The production started on Sep. 20, 2006. So there's six years of history.

    Here are the monthly productions of that well, in BOEs:

    (click to enlarge)

    Cumulative production of the well is 280 MBOE after six years.

    Modeling the Production of the Sveen 34X-14 Well

    I selected these parameters to model the well's historic production:

    • IP = 900 BPD (Same as in my last article)
    • D = 0.02/Day (a bit less than 0.027/Day in my last article)
    • B-Factor = 1.55 (a bit higher than 1.465 in my last article)
    • Decay factor Beta = 0.0002/Day (Same as last article)

    Here is how my projection compares with the actual production:

    (click to enlarge)

    My projection seems to match pretty well. XTO conducted a re-fracing operation on the well in August 2009, which seems to have boosted the production rate for a while. But the production rate has since then fallen back to my projection curve.

    I used the same IP = 900 BPD and same long term decay factor of Beta = 0.0002/Day as used in my last article. But I had to make two adjustments to make the curve fit:

    1. The initial decline D is reduced from 0.027/Day to 0.020/Day. This means the wells six years ago probably declined a bit slower. The newer wells today, due to closer fracing stages, may decline faster.

    2. The B-factor is increased a bit from 1.465 to 1.550. This means the decline flatten out a little bit sooner in the old wells. The newer wells takes a little bit longer for the decline to flatten out.

    Both of the above changes would result in a slightly higher EURs. So I am not surprised that the EUR will be higher than 200 MBOE. The accumulated production so far is 280 MBOE.

    Since the initial decline D is slower, the production rate stabilize quicker in the old wells. So I will use 60 days after the production start, instead of 90 days, to use my rule of thumb to estimate EUR:

    • At 60 days, the projected IP is 451.4 BPD, the projected cumulative production is 36.78 MBOE.
    • EUR = 451.4 BPD * 500 days + 36.78 MBOE = 263 MBOE.

    My result of EUR = 263 MBOE is close to cumulative production of 280 MBOE, but is still a bit lower than the actual production. This is mainly due to the re-fracing done in August 2009 which did boosted the production rate. But it appears to me that the EUR gain from re-fracing is very limited.

    How much more will this well produce?

    As of Sep. 2012, the well produces 40 BPD. The projected decline rate is 0.0005/Day. Assuming this decline rate holds, the remaining production volume is approximately 40 BPD / 0.0005 = 80 MBOE. If we cut the well off at 20 BPD level, then 40 MBOE will be produced.

    So this well's ultimate production will likely be 280 MBOE + 40 MBOE, or 320 MBOE. Compared with my estimate of 263 MBOE, the well has gained 60 MBOE of extra production due to re-fracing treatment.

    How Much Does Re-Fracing Help?

    Producers pitch re-fracturing the wells as being effective in boosting EURs and extend a well's life span. I am skeptical to the claim. As shown in the above chart, the re-fracing done in August 2009 only marginally boosted the production rate. However the production boosting effect diminished quickly. In three years, it's almost gone.

    In SPE 154669, Mark Craig of Devon Energy (NYSE:DVN) claimed that a cash study of 13 re-stimulated (re-fracing) Barnett wells show that re-fracing, at a cost of $0.9M per well, can boost EUR by 0.8 BCF.

    Such claim is ridiculous. The average accumulative production of all Barnett shale wells is no more than 0.67 BCF per well. It is absurd to claim that re-fracing can more than double a well's EUR. As a matter of fact, paying $0.9M cost to gain 0.8 BCF extra production. That's a production cost of only $1.13/mmBtu. If it is a such a great deal, producers should rush back to Barnett to re-stimulate all the wells. But they don't. So the claim cannot stand the test of water.

    Craig Cooper estimated that re-fracing costs $0.095M per stage. If a well contains 25 stages, one re-fracing operation will cost $2.4M. As the re-fracing only boost production marginally and it lasts less than three years, it seems to me that re-fracing is wasting money.

    In a presentation (page 16), XTO showed the production rate before and after the Sveen 34x-14 was re-stimulated:

    (click to enlarge)

    It looks to me they did manage to boost water production a lot, as all the injected water comes right back out. But the oil and gas production gain was much less impressive.

    Based on my calculation, re-fracing contributed to 60 MBOE extra production. At $65/BOE value, it contributed to $3.90M revenue. As XTO carried out multiple re-fracing operations on the well's six year history so far, I believe the economic benefit of re-fracing is zero.

    Discussions and Investment Implications

    Geologist Arthur Berman and others have been sounding the alarm for a long time that the US NG industry is engaged in efforts to pitch overly-optimistic projections in the shale well revolution. The money spent on shale development far out-weight the economic return. The capital spending of shale producers routinely out-pace revenue stream by several times. Despite of the gloomy reality, producers continue reckless money spending in aggressive well drillings, thanks to generous money from banks and investors.

    This is an non-sustainable bubble. I see a looming debt crisis in the shale industry, which has accumulated more than half a trillion dollars in debts thanks to their shale revolution adventure. The NG industry will collapse once bank lending is cut off, leading to collapse of US natural gas supply. As a result it will send natural gas and coal price skyrocketing. It will happen soon.

    The biggest beneficiary to the looming crisis in the NG sector, is the US coal sector. That's where I put my money in. You should, too!

    The coal sector was wrongfully punished by the wide-spread meme:

    "Coal is dead. Cheap and abundant natural gas is replacing coal"

    Nothing is further from the truth!

    I made the efforts to do the calculation and modeling to find the truth behind the rosy pitches of NG companies. I am convinced that the real data says I was right and the industry experts were wrong.

    I ask you to follow my math and do your own analysis. If you agree with me, pull your money out of the shale industry and into the US coal sector. The coal story is the biggest investment opportunity in more than a decade. I am holding my coal stocks firm.

    Disclosure: I am long JRCC, ANR, ACI, BTU.

    Dec 14 10:10 AM | Link | 2 Comments
  • The Real Economy Of Bakken Shale Wells Of Continental Resources

    I have repeatedly made the point that shale oil and gas producers tend to exaggerate the EURs (Estimated Ultimate Recovery) of their shale wells and then under-estimate the armortization costs, in order to show more pleasant financial results to the shareholders.

    The Charlotte 2-22H Well of the Continental Resources

    Let me do a case study on one particular Bakken shale well owned by Continental Resources Inc (NYSE:CLR), the Charlotte 2-22H well. CLR pitched this well in its 10/09/2012 investor presentation (page 63). It must be one of the best performing CLR wells.

    Fellow SA writer Richard Zeits quoted CLR describing this well:

    The Charlotte 2-22H tested at an initial one-day rate of 1,396 Boe/d and is assigned a EUR of 561 MBoe; the well had cumulative production of 87 MBoe in the first 9.8 months, or just under 300 Boe/d average.

    The well might had a peak 24 hours production of 1396 BOE. But it was an unstable and non-representative production volume to be used for EUR projection. I find a reference of the production in the first 35 days. During the first 5 days, oil produced was 3434 barrels and gas produced was 3449 MCF. Using 5.8 MCF of gas equivalent to one barrel of oil, the total production in 5 days was 4029 BOE. That's averaging roughly 806 BOE per day.

    Modeling Shale Well Decline Using Modified Arps Formula

    I discussed the Arps Empirical Formula in the past. The industry uses the Arps Type Curve formula to project a well's future productions. The problems with using the original Arps formula are:

    • For the initial few months of production, almost any parameter will be able to fit with the production data. So the industry tends to fit the curves using a very high b-factor, in order to project a lower long term decline rate and a higher EUR.
    • The Arps formula itself is divergent when a b-factor higher than 1.0 is used, resulting in a cumulative production that approaches infinity when integrated over long time.
    • The Arps formula has a long term decline rate that approaches zero. In reality, terminal decline rate is roughly 7% or higher. The terminal decline rate does not approach zero in long term.
    • The long term productivity of shale wells routinely come up far short of what's being projected using the Arps formula, as the production declines faster than the formula predicts.

    To adjust for problems above, I adopt a modified Arps formula to model shale well declines. The adjustment is simply multiply the original formula by an additional slow decaying factor Exp(-Beta*T).

    (click to enlarge)

    The original Arps formula, and my modification is explained above.

    Modeling the Charlotte 2-22H Bakken Shale Well

    Using proper parameters, I can model the well's actual production with a perfect match, see my modeling curve as superimposed on the original chart taken from CLR's presentation:

    (click to enlarge)

    My model used the following parameters:

    • IP = 903 BOE per day.
    • D = 0.027 / Day.
    • B-Factor = 1.465 (typical value used)
    • The decay factor Beta = 0.0002 / Day.

    Note that the IP I used is pretty close to the first 5 day average of 806 BOE per day, as mentioned above. My model is validated by matching the actual production in the first 10 months.

    Based on my calculation, my spread sheet gave these projections:

    • First year cum. production is 96.949 MBOE. PR=129.62 BPD
    • Two year cum. production is 132.88 MBOE. PR=76.78 BPD
    • Five year cum. production is 187.45 MBOE. PR=33.46 BPD
    • Ten year cum. production is 227.787 MBOE. PR=14.54 BPD
    • First year production rate decline is -85.65%.

    The EUR estimate can be estimated in two ways:

    1. Use 20 BPD daily production rate as the cut-off. I project that the well drops to below the cut-off production in 2880 days or 7.89 years. The cumulative production will be 214.5 MBOE.
    2. Use my 500 days of IP production rule. But since the initial production drops too fast, let's apply this rule after the first 90 days. By the end of 60 days, the cumulative production is 44.166 MBOE and the production rate is 314.8 BPD. So 500 days at 314.8 BPD will produce another 157.4 MBOE. The total is an EUR = 202 MBOE. Only 5.8% lower than above estimate.

    CLR projected a much higher EUR of 561 MBOE. I do not think their projection is supported by actual data. The original Arps formula would project EUR = 474 MBOE in 15000 days or 41 years.

    The Economy of This Bakken Shale Well

    What's the profitability outlook of this Bakken shale well?

    Based on most recent CLR quarterly report, I estimate that direct well drilling cost is $11.65 per well. Figuring in overhead and production maintenance costs, I think a lifetime cost of $13M per well is a very conservative estimate. Let me do the calculation using $13M and $15M cost per well. Realized revenue was $65 per BOE.

    Just for comparison, let's say CLR borrows $13M from millionaire Joe at a moderate 5% interest. Joe will be earning 5% interest from day one. CLR will be paying the interest and principal from the oil and gas revenue. Let's see how they perform over time.

    (click to enlarge)

    The above chart shows the relative financial performances. The two thick lines represent the accumulative production, with the scale on the right side. The thin lines represents the financial performances.

    I did the calculation using both the original Arps formula, and the modifies formula. The blue lines represent the original Arps formula, which tend to over-estimate. The pink lines use modified formula.

    The red line shows interest and principal accumulated if the money is lent out at 5% interest rate. The horizontal axis is in days.

    As can be seen, CLR would pay off the loan after 3280 days. That's the break even point after a full NINE years. After that point, any revenue earned less the production and maintenance cost would be the profit that gets into CLR's pocket. However, by then, there is not much profit to be made at all: The well will be producing 16.9 BOE per day. That's already below the 20 BPD production threshold I used above for the end of the well's useful lifespan.

    CLR is definitely not making a profit if my calculation is right. I said $13M per well lifetime cost was conservative. Let's see what happens if the cost is $15M per well instead:

    (click to enlarge)

    The above is the same calculation, but done assuming the lifetime well cost is $15M instead of $13M.

    The result is even gloomier for CLR. They are still under water at the far right edge of the chart, which is for 5000 days or 13.69 years.

    By the end of 5000 days, CLR still owes the bank $2.837M debt. Mean while the millionaire Joe who loaned out the $15M have happily earned compounded interest of $14.264M during the same time.

    Discussion and Investment Implication

    After the above discussions, if you have $13M or $15M of cash, do you think you get a better deal simply saving the money in a bank account earning 5% interest, or is it a better deal to invest the money in a shale company to drill a Bakken oil shale well?

    I think the answer is obvious. Bakken shale wells are simply non-economical at current oil price and at current well productivity.

    Why do investors continue to pile on Bakken shale companies like CLR and EOG Resources (NYSE:EOG)? Why the investment community dedicates 75 times more capital money in the shale development sector, than in the US coal mining sector? I believe this is the biggest investment mistake in the history of energy investment! It creates an excellent investment opportunity in the coal sector.

    I stated that the US natural gas industry and coal industry each produces an equal amount of fossil energy. There is no reason why the coal sector deserves only 1/75th of the investment capital of the NG sector, especially when current coal price is at or nearly the profitable level, while the NG price is deeply non-profitable.

    My statement is based on that:

    • US produces roughly 1 billion tons of coal per year. Each ton contains 20 MMBTU of energy. Total is 20 quadrillion BTU.
    • US produces roughly 24 TCF of natural gas per year. Each MCF contains 1 MMBTU of energy. Total is 24 quadrillion BTU.

    But since most of the NG industry has given up on conventional gas and concentrated their effort on shale development, it is fair to compare coal with just the shale gas industry:

    • US produces 9.25 TCF of shale gas and 360M barrels of shale oil, which is equivalent to 5.8 MCF per barrel. The total is 11.34 TCFE of gas. Total energy is 11.34 quadrillion BTU.

    So the disparity is even more extreme. The entire US coal industry produces TWICE as much energy as the shale oil and gas industry. Yet the investment community dedicates only 1/75th of capital in the US coal sector while wasting 75 times money in shale players.

    My advice: Get out of shale plays and get into the coal plays.

    Disclosure: I am long JRCC, ANR, ACI, BTU.

    Dec 12 2:54 AM | Link | 18 Comments
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