how arthur berman could be very wrong…

8/14/2019 How Arthur Berman Could Be Very Wrong

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How Arthur Berman Could Be Very Wrong

Allen Gilmer, Ramona Hovey, and Jason Simmons, Drilling Info, Inc. Energy StrategyPartners

It was with great interest that we read Arthur Bermans commentary Lessonsfrom the Barnett Shale suggest caution in other shale plays in World OilsAugust 2009 edition. From examining production data, Mr. Berman makes avariety of declaratory statements about the Barnett Shale, and thus Gas Shalesin general, which are superficially real, yet disintegrate as predictive factors uponfurther examination. Whereas we typically do not respond to the claims ormethodologies of E&P analysts and pundits, and reserve our expertise for ourclients benefit, Mr. Bermans conclusions need to be examined and responded towhere necessary. The cost of superficial analysis has very real consequences interms of energy policy today like never before.

The thrust of Mr. Bermans article is that the Barnett is an uneconomic play ingeneral, that various technologies dont provide a return on investment, and thatthe play itself is unpredictable, thus all other shale plays are unpredictable. Mr.Bermans major claims are that 1) core areas do not have appreciably higheraverage EURs than the play, overall, 2) there is little correlation between IPrates and EURs, 3) horizontal wells do not produce substantively more thanvertical wells 4) the volumes of commercially recoverable reserves are greatlyover-estimated, 5) average well performance has decreased consistently since2003 for horizontal wells, and 6) hyperbolic predictions overestimate reserves.Left entirely unaddressed in his analysis is the entire concept of a marginalproducer, the statistical effect poor producers have on raw data, and whether it is

proper to analyze un-normalized data, since many factors can be quantified toalter production tremendously, such as corrections for lateral length, number offrac stages, and the results of simulfracs, among others.

CORE AREAS DO NOT HAVE APPRECIABLY HIGHER AVERAGE EURSTHAN THE PLAY OVERALL- In making this statement, Mr. Berman analyzedhorizontal wells in Tarrant and Johnson Counties. Analysts used the very broadbrush of Core, Tier 1, Tier 2, and Non-Core early on when describing thepotential productivity of the Barnett Shale. This broad brush approach is not anappropriate discriminator for potential production because it isnt related toanything other than a non-robust early estimate of Barnett thickness combined

with a very poorly sampled grid representing potential thermal maturity. A morerobust method to define potential productivity is necessary; one that actuallypredicts potential on a well by well basis. For instance, we use Net Feet ofBarnett Shale combined with a Cooking Index, which is derived from GOR thatwe call Graded Potential of Acreage (GPA), and that is updated periodically fromnew results. From our analysis, Tarrant County itself, which is considered Coreusing the broad brush approach actually contains 8 of 10 grades of potentiallyproductive shale by our more localized approach. Choosing Tarrant County by


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itself thus does not represent a natural high grading of acreage, rather it is arandom grab bag of various quality acreage. Comparing the production quality ofwells from several non-discriminated grades of acreage is a bad start. ShouldMr. Berman choose to look at production responses from a more meaningfulsubset of acreage, such as our methodology, he would see substantive

differentiation in raw productivity between acreage grades.

Figure 1. Note the strong correlation of production responses to GPA (Graded Potentialof Acreage) which uses Net Barnett Thickness and a cooking index derived from theGOR of Barnett producers. Sample size is all Barnett Horizontal Wells in the FWB.


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Figure 2. Note the correlation of average cumulative production to GPA. Thesecumulative are raw, actual numbers. In order to derive PREDICTIVE POTENTIAL

productivity, production would need to be normalized for operator learning effects,horizontal lateral length, and Best Practices operations.

THERE IS LITTLE CORRELATION BETWEEN IP RATES AND EURs - Mr.Berman is correct in this statement if he means test AOF IP data, the leastpredictive of IP measurments. However, the correlation between IP data andEUR begins to tighten up significantly if one were to use 2nd Month actualproduction as IP, and even more (90% correlation coefficient) using MaximumMonthly production rate as IP. The reason for this effect is because it oftentakes several months for a well to clean up after initial stimulation. Also, usingthis methodology, maximum monthly rate correlates closely to 6, 12, 24, and 60

month cumulatives production amounts, and is thus an excellent proxy for EUR.


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Figure 1. Although Reported AOF IP doesnt correlate strongly to EUR (cc=46%),Maximum Monthly Production Rate does (cc=86%). This is due to the fact that it often

takes months for the production stream to clean up after stimulation (sample size is allBarnett wells in the FWB since 2002).


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Figure 2. This relationship is demonstrably true throughout every producing grade ofacreage in the Barnett, with correlation coefficient exceeding 90% in several cases

(sample size is all Barnett Wells in FWB since 2002).

HORIZONTAL WELLS DO NOT HAVE APPRECIABLY HIGHER EURS THANVERTICAL WELLS- This statement left us a bit puzzled. The charts belowillustrate both the raw and normalized maximum monthly production rates that wecan definitely tie to EUR. The only thing we can conjecture is that Mr. Berman islooking at the exceptional response of multiple frac stages over time in verticalwells and comparing these to horizontals. By the way, the frac response postinitial frac can be statistically modeled as well, and evidence is emerging thathorizontal wells can exhibit the same behavior.


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Figure 3. As we previously saw, there is a strong correlation between maximummonthly production rates and EUR. Here we see average raw maximum monthly rates

for horizontal wells exceeding vertical wells by a factor of 2 or more depending uponacreage grade. All Barnett wells drilled since 2002.


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Figure 4. The maximum monthly production rates after being corrected for operatorlearning curve. Note that this is a BIG correction. As shown in Figure 6, it typically

takes operators a year or more to maximize their production. Wells drilled at the top ofthe curve typically produce more than twice those drilled at the bottom. The averageboost across all grades of horizontals is a 94% improvement in maximum monthly

production rates when corrected for learning curve and 77% improvement in verticalwellbores.


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Figure 5. Same figure as above but after normalizing for operator learning effect AND a3000 lateral length. This corrects an average of 4% across all grades, but can be as

high 10% depending on acreage grade.


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Figure 6. Basin wide Learning Curve. To normalize for predictive analysis, we adjustwells drilled early in the learning stage to perform as well as wells late in the learning

stage. If production declines later on, this is taken as an indication of drainage and notthat the operator is getting worse. This is calculated for each of the top 20 operatorsand the basin-wide average applied to all other operators.

MARGINAL PRODUCER- Unlike conventional reservoirs, the economics ofshale plays highly favor operators that invest in engineering and ongoingexperimentation in optimizing their drilling, completion, and stimulation practices.The saying One Mans Gold is another Mans Garbage is especially true forthese plays. For an equivalent grade of acreage, the best operators statisticallyproduce 40% or more than the average operator, and up to 4 or 5 times morethan a inefficient operator. Learning curves and operator comparisons are real

and quantifiable throughout. As acreage expires, and the land rush acreagesare released, the optimal operators will successfully step into another mansgarbage.


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Figure 7. In this actual example of the GPA type curves from two different operators,both would appear to be essentially equal. Company A is considered, and is indeed, a

good operator. Company B, with substantively lower GPA acreage, has extracted thesame amount of production from much lower grade acreage.


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Figure 8. Now lets compare the same production type curves from company A tocompany B for similar quality acreage (same GPA). Company B is achieving nearly

50% more gas from the same quality acreage as Company A.

HORIZONTAL WELLS ARE NOT ALL THE SAME- There is a strong correlationbetween lateral lengths and production rates, especially at higher acreagegrades. These need to be normalized before meaningful analysis of horizontalwell performance can be made.


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properly allocated to their proper GPA, normalized for lateral length, normalizedfor operator learning curve, that effect disappears.

Figure 10. Note the steady decrease in acreage quality drilled by horizontalwells since mid 2003, bottoming out in mid 2007, and increasing slightly sincethen.

HYPERBOLIC PREDICTIONS OVERESTIMATE RESERVES - Mr. Berman isabsolutely correct here. This is also usually the case for conventional reserves.Hyperbolic predictions typically provide a ceiling estimate.

CONCLUSIONS - As we discovered when we began analyzing the Barnett,

analyzing shale plays is like peeling onions. Once a layer is exposed, anotherpresents itself. Many factors need to be normalized to really address theeconomics and behaviors of these plays in a predictive sense. Good acreagegrade alone is not a recipe for success. Decent acreage grade needs to becombined with strong, holistic drilling, completion, and stimulation practices thatare constantly tested for optimization to create a real repeatable recipe forsuccess and large economic reserve accumulation. Great operations equate to


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better recoverable resources/reserves for these plays, not more operators oreven more wells.

Raw data combines good operations with bad, early parts of the learning curveresults with later, and good acreage with bad. Making forward-looking

predictions of behavior from this soup assumes that every bad habit ispropagated forward, and that no operator is better than another. Expanding thatconclusion to other plays based on this assumption misses the big picture. Whatthe Barnett is capable of producing is different from what it is producing now.How it can be optimized can only be determined by identifying who is optimizingit and by how much. It is ironic that we are concerned about profitability anddeliverability since it was only a few years ago when we were told that HubbertsPeak was close at hand for US natural gas. Yes, there will be a lot of deadproducers when all is said and done, but for those that invest in operationalexcellence, the Barnett Field and other unconventional plays will go on makingtens or hundreds or thousands of people very wealthy, and providing much

needed domestic hydrocarbons for years to come.

For more information, check out -http://www.info.drillinginfo.com/demos/flashDemos/fwbasin/index.htm
http://www.info.drillinginfo.com/demos/flashDemos/fwbasin/index.htmhttp://www.info.drillinginfo.com/demos/flashDemos/fwbasin/index.htm

how arthur berman could be very wrong…

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