Why The Debate Over The Fracking Fallacy Is A Big Deal

The debate about “The Fracking Fallacy” is a big deal because EPA’s* plan to regulate coal out of existence is based on EIA’s* forecast of abundant and cheap shale gas for decades.   If U.S. natural gas production is in decline by the early 2020s as described in the Nature article, there won’t be enough electric power supply without more, rather than less, coal. And power will cost more. In addition, DOE’s* approvals for natural gas export to Asia, Europe and Mexico may now become truly awful and misinformed decisions.

The magazine Nature published “Natural gas: The fracking fallacy” on December 3, 2014.  The article’s author Mason Inman described how the expectation of decades of abundant natural gas in the United States might be wishful thinking. He compared the Bureau of Economic Geology (BEG) and EIA gas supply forecasts in the nearby figure.   The BEG forecast has U.S. gas production peaking in about 2020 and then, declining sharply.  The EIA prediction is for gas supply to continue increasing into the mid-2020s and then, to remain strong into the 2030s.

Source:  Bureau of Economic Geology (click the figure to enlarge)

Both the EIA and BEG wrote letters to Nature last week stating that Inman’s article was misleading and biased.  More importantly, both letters emphasized that there really isn’t any disagreement between the two forecasts but that there are many differing scenarios that each group has developed because of the many variables and uncertainties involved with supply forecasting.

The Nature article has succeeded in casting doubt for the first time on the beautiful dream that fracking shale reservoirs can restore youth to an ageing American energy industry.  For years, a few industry insiders like me have urged caution about the jubilant projections for U.S. shale gas abundance coming out of EIA, the research departments of investment banks, and industry consultancies.  Things that sound too good to be true often are.

Why did the EIA and BEG jump into the fray when they might have chosen to say nothing and assume that this too would pass as, for instance, the New York Times “Drilling Down” series did in 2011? 

First, because the BEG is recognized as a major force in institutional and academic research with close ties to the oil and gas industry.  The BEG evaluated the performance of every individual well in all of the major U.S. shale gas plays.  Their work is the authoritative standard in my view.

And second, because of timing:  EPA air quality regulations go into effect in April 2015 that will greatly reduce the role of coal in electric power generation as shown in the nearby figure.  Resulting retirement of more than 60 coal-fired plants in 2015 would increase demand for natural gas as the substitute fuel.  Coal plant retirements will continue though 2025 and have been ongoing for several years already in anticipation of the new regulations. 

Source:  GAO (click the figure to enlarge)

EIA’s gas supply and price forecast formed the technical basis that justified EPA’s regulations that did not require congressional approval.  If BEG’s forecast is correct, U.S. gas supply will have peaked before the last coal plants are retired and after the majority have been shuttered.  What will the U.S. do for electric power if gas production is in serious decline?  The only options are to revert to more coal, quickly build nuclear power plants or somehow greatly accelerate development of wind and solar installations (but what to do about the necessary natural gas backup generators?).

Moreover, EPA regulations have relied on EIA gas price projections to further justify coal plant retirements.  These price forecasts say that gas will continue to be inexpensive for decades because of the abundant supply.  If that supply begins to decline, the price will increase meaning higher costs for U.S. homes and businesses.

To make matters worse, DOE has already given approval for natural gas exports by pipeline to Mexico and in the form of liquefied natural gas (LNG) to Asia and Europe.  

Source:  SENER and EIA  (click the figure to enlarge)

These contracts were also approved based on EIA supply and price projections.  Many industry advocates have stridently opposed these approvals arguing that gas export will increase their costs and diminish competitive advantage over foreign manufacturers.

Add it all up and it’s potentially a huge mess.  Interestingly, EIA Administrator Adam Sieminski did not sign the EIA letter to Nature.  We can only speculate why.

*EPA:  United States Environmental Protection Agency

*EIA:  Energy Information Administration, part of the U.S. Department of Energy.

*DOE:  United States Department of Energy

Nature Responds To EIA and BEG Denial Letters

Today, Nature responded to letters earlier this week from the EIA (Energy Information Administration) and BEG (Bureau of Economic Geology, University of Texas at Austin) claiming that Mason Inman's article "The Fracking Fallacy" published on December 4, 2014 was flawed.

The EIA Denial Letter

The BEG Denial Letter

Nature stands by Inman's article and, interestingly, revealed that EIA was asked some questions by Inman while he was working on the article but they did not reply.

It is also interesting that the EIA denial letter was not signed by the EIA Administrator Adam Sieminski but by Deputy Administrator Howard Gruenspecht.

Let's get a few things straight as people attempt to sort through this bit of energy theater.

First, Allen Brooks has documented the events and facts of this story in two issues of Musings From The Oil Patch:

Could The U.S. LNG Market Be Derailed Before It Starts?

Debate Grows Over Illusion of 100-Year Gas Supply Scenario

Allen showed many of BEG Director Scott Tinker's slides that set off the debate in the first of these articles but the key chart in my view is the following:

(Click The Figure To Enlarge)

Despite denial of any differences by both the EIA and BEG, the obvious truth is that the BEG Sloan studies of the major shale gas plays in the United States forecast lower EUR (estimated ultimate recovery), a shorter life-cycle, an earlier and steeper decline and a lower contribution to total gas supply than does the EIA.

Period.

Denying that there is any discrepancy between EIA and BEG is false.  This difference does not disappear by accusing Inman and Nature of misrepresentation and bias.  Attempts by both agencies to discredit Tad Patzek or minimize his role in the BEG studies--more about that a bit later in my comments--are factually incorrect and shameful.

The BEG studies confirm what many "shale gas skeptics" (including me) have said for many years:  The shale gas phenomenon is real, it has contributed a significant volume of gas that nobody thought was available, and there is a lot less of it than some people believe.  I add that it also costs more than represented to produce although that is not part of the immediate debate among EIA, BEG and Nature.

The EIA published 2013 proven reserves of shale gas earlier this month.  Shale gas will provide about 6 years of supply at present consumption.  We can debate about the various classes of reserves and speculate about resources from now until we run out of gas but the plain and simple truth is what Inman and the BEG studies concluded:  there is less gas than many people thought and certainly less than EIA has represented in its natural gas forecasts (do the EIA people who do the gas forecasts talk to the people who do the reserve accounting?).

(Click The Figure To Enlarge)

Much of the EIA's position stated in Gruenspecht's letter (and interpreted by me)  is that uncertainty exists and the EIA represents multiple scenarios and should not be held to account for one or, in fact, any of them.  That sounds good but, as someone pointed out to me, applications for LNG export to the Department of Energy are based on the EIA base case.

Tad Patzek was quoted often in the Nature article and was shamelessly "thrown under the bus" by the EIA and BEG in both denial letters.  

Tad is Professor and Chairman of the Petroleum Eng. & Geosystems Department at the University of Texas at Austin and a lead researcher in the BEG Sloan studies on U.S. shale gas plays.

Despite comments in both letters saying that Tad's role was relatively minor in those studies, I dispute those statements as distortions of fact.  The work done by Tad and his engineering team addressed the determination of individual well EUR which, in my view, is the core of the studies.  

I believe that the BEG Sloan studies represent a monumental achievement and demonstrate an unparalleled level of comprehensive and integrated analysis on the important subject of shale gas. I fully support the technical analysis and Tad Patzek and his team provided the credible core of that work.


Please see the papers following for proof of this.

------------------------------------------------------

1.     Patzek, T.W. Male, F., and Marder, M.,“A simple model of gas production from hydrofractured horizontal wells in shales,” AAPG Bulletin, v. 98, no. 12 (December 2014), pp. 2507–2529.

2.     Patzek, T. W., Male, F. and Marder, M. "Gas production in the Barnett Shale obeys a simple scaling theory,"  PNAS, doi:10.1073/pnas.1313380110, November 18, 2013. Awarded with the Cozzarelli Prize by the National Academy of Sciences for the best paper in engineering in 2013.

3.      Patzek, T. W., Male, F. and Marder, M. "Supporting Materials to: Gas production in the Barnett Shale obeys a simple scaling theory,"  PNAS, doi:10.1073/pnas.1313380110, November 18, 2013.

4.     John Browning, Katie Smye, Scott W. Tinker, Susan Horvath, Svetlana Ikonnikova, Tad Patzek Gürcan Gülen, , Frank Male, Eric Potter, Forrest Roberts , and Qilong Fu, “Study develops Fayetteville shale reserves, production forecast, OGJ, 01/06/2014.

5.     John Browning, Scott W. Tinker, Svetlana Ikonnikova, Gürcan Gülen, Eric Potter, Qilong Fu, Susan Horvath, Tad Patzek, Frank Male, William Fisher, Forrest Roberts and Ken Medlock, III, "BARNETT SHALE MODEL-2 (Conclusion): Barnett study determines full-field reserves, production forecast," OGJ, September 9, 2013.

6.     John Browning, Scott W. Tinker, Svetlana Ikonnikova, Gürcan Gülen, Eric Potter, Qilong Fu, Susan Horvath, Tad Patzek, Frank Male, William Fisher, Forrest Roberts and Ken Medlock, III, "BARNETT SHALE MODEL-1: Barnett study determines full-field reserves, production forecast," OGJ, p. 62, August 5, 2013.

7.     Frank Male, Akand W. Islam, Tad W. Patzek, Michael P. Marder, Paper SPE168993-MS: "Analysis of Gas Production From Hydraulically Fractured Wells In The Haynesville Shale Using Scaling Methods," presented at the SPE Unconventional Resources Conference – USA, held in The Woodlands, Texas, USA, 1-3 April 2014.

8.     Frank Male, Akand W. Islam, Tad W. Patzek, Svetlana Ikonnikova, John Browning and Michael P. Marder,  "Analysis of gas production from hydraulically fractured wells in the Haynesville shale using scaling methods," submitted to the Journal of Unconventional Oil and Gas Resources, 2014 (now in revision to be send back to the editor).

Peak Oil Demand: Near or Far?

An article from yesterday's Washington Post "Is peak oil demand just around the corner?" is, in part, a summary of an article that appeared recently in The Economist ("Yesterday's Fuel").

Citi recently predicted that world oil demand may peak by 2013 because of increased transport efficiency among other factors.

The Washington Post piece features a discussion with Stanford's Adam Brandt who is skeptical about predictions of oil demand peak.

Brandt thinks the demand story is more complex because of the rise in unconventional sources for transport fuel including natural gas, biofuels and oil from tar sands, not to mention electric vehicles.

Brandt doubts that auto fuel efficiency will continue to increase has it has in the recent past and sees a potential explosion of transport demand from Asia.  

He further invokes Jevon's Paradox to suggest that easier and more pleasant driving from Google autonmous vehicles and driving errand outsourcing may in fact increase transport fuel demand.  The past is not necessarily the key to the future.

Wood Mackenzie Says Bakken & Eagle Ford Will Produce More than the Two Largest Fields in North America Combined

Wood Mackenzie reported on July 30, 2013 that U.S. shale plays will produce 5 million barrels of oil per day by 2019, at least half coming from the Eagle Ford and Bakken shale plays.  Naturally, most people believe this without asking the obvious question, "How does this huge volume of oil compare with present U.S. production or the largest fields in the world?"

The U.S. produced 7.3 million barrels of crude oil per day in May, 2013 and reached peak production of just over 10 million barrels of oil in 1970.  WoodMac would have us believe that U.S. oil production will exceed peak production by about 2 million barrels per day, and will increase present production by almost 70%.  That would be awesome but seems highly unlikely based on the history of oil production decline in countries and basins around the world.

This is like telling the average American whose life expectancy is 79 that, by some miracle, we can all now expect to live to be 115 years old.  Never mind that only one person is known to have lived to be this old, it's still reasonable that everybody will live this long! Hmm.

Back to oil production, Ghawar, by far the largest oil field in the world with 74 billion barrels of reserves, produces 5 million barrels of oil per day and never produced more than 5.7 million barrels.  We are, however, supposed to believe that shale plays--the Bakken and Eagle Ford, in particular--will equal Ghawar.

Cantarell, the largest oil field in North America with 19 billion barrels of reserves, produced 2.1 million barrels of oil per day at its peak.

Prudhoe Bay, the largest oil field in the United States with 13 billion barrels of reserves, produced 1.5 million barrels of oil per day at its peak.

WoodMac would have us believe that the Bakken and Eagle Ford will almost equal production from the two largest oil fields in North America combined.  I certainly hope that they are right but history and facts suggest that this estimate is at best highly optimistic and, at worst, exaggerated.

As far as I know, the WoodMac report is not publicly available so I cannot comment on how they arrived at the numbers.  How could they be wrong?  I would first look at the per-well reserves and decline rates used in this estimate because these have been unrealisticallly optimistic for all shale plays so far.  Second, I would look at the size of the commercially productive area they assume for these plays because these have also been unrealistic for other shale plays.

Everybody likes good news but we all hate disappointments.  In a world of dwindling oil resource opportunities (that's why we are drilling shale, after all!), it is time to start changing our behavior and using less oil.  Reports like this give people the message that there is no reason to change our wasteful practices.  Don't worry, be happy!

Shale Plays Not Working For Big Oil

Recent revelations and write-downs of shale assets in North America by Shell, ExxonMobil and Chevron support our research that big companies cannot make money on low rate-low volume shale wells.

The majors exited North America in the 1980s because they could not support the operating costs associated with managing this kind of production even though the wells were profitable.  They went to the overseas arena where things worked for a few decades as deep water plays emerged.

In the last 5 years, international opportunities have been exhuasted and national oil companies hold all the cards.  This means that remaining international opportunities carry onerous production-sharing agreements or other difficult contractual obligations (note the deals that Shell, etc. have entered in Iraq where they must spend $billions to get a $2/barrel payment for incremental added production--these deals are being re-considered.

So, the majors jumped back into North America with the lure of large reserves from shale.  This trend began when ExxonMobil acquired XTO Energy in early 2010.  At the time, this was viewed as a validation of shale plays and their economic viability.  I refer you to my comments about this acquisition in February 2010:

"The mainstream belief that shale plays have ensured North America an abundant supply of inexpensive natural gas is not supported by facts or results to date. The supply is real but it will come at higher cost and greater risk than is commonly assumed. The arrival of ExxonMobil and other major oil companies on the shale gas scene is positive because they will not follow the manufacturing approach, and will do the necessary science that should make shale plays more commercial. This does not, however, ensure success.

"ExxonMobil has come late to the domestic shale party. They may have overvalued XTO's existing wells without fully taking high production decline rates into account. It is also possible that XTO has already drilled the best areas in more mature shale plays, while the potential of newer plays has not yet been established. It is unclear how ExxonMobil’s enormous overhead structure and its associated cost will fit with operating thousands of relatively low-rate gas wells."

Now that the shale plays are not working at least for the major oil companies, what next?

I believe that we are seeing the slow liquidation of these organizations but they cannot let the investment public know that this is what is occurring, hence the cornucopian rhetoric about the shale revolution and North American beoming the next Saudi Arabia--pure poppycock, of course.  Will the recent write-downs and announcements affect investors?  Probably not for now.

British Geological Survey Bowland Shale Gas Assessment

(The original post appeared on The Oil Drum, July 19, 2013)

The latest exuberant shale gas news comes from a report by the British Geological Survey estimating enormous new shale gas resources in the central UK. On June 27, 2013, the British Geological Survey (BGS) released a natural gas resource assessment for the Bowland Shale in the United Kingdom stating that approximately 40 trillion cubic metres (1,300 trillion cubic feet (Tcf)) of shale gas exist in 11 counties in northern England. The BGS report, unfortunately, only addresses gas-in-place (total resources) and not extractable resources (technically recoverable resources) much less reserves (commercial supply). The most-likely reserve potential of the Bowland Shale is only about 42 Tcf (3% of gas-in-place) after applying methods used by the U.S. Energy Information Administration (EIA) and Potential Gas Committee (PGC).

The potential for misunderstanding of shale resource estimates is great. Various organizations have published resource estimates for shale gas plays in the U.S. and around the world. These reports are commonly misinterpreted as representing commercially producible volumes of gas.

Resources are the volume of natural gas in a particular formation, also known as gas‐in‐place. This has no relation to what is physically or technically producible much less commercially viable. The technically recoverable portion of total resources--Technically Recoverable Resources (TRR)--is that volume that can be produced using present technology. It similarly does not include commercial factors. This is the gas volume most often publicized and confused with reserves, the economically producible subset of technically recoverable resources. The EIA states that TRR represents approximately 25% of gas-in-place for most shale formations.

Technically recoverable resources are generally divided into three categories based on uncertainty. According to the PGC, probable technically recoverable resources are those gas volumes that are currently being produced in gas fields such as, for example, the Barnett or Marcellus shale plays. Although the history of production is only a few years to perhaps ten years, there is some degree of confidence in projecting ultimate recovery from early producing rates. Possible resources are thought to exist based on new field discoveries. In this category, there is little production history and large areas of potential gas development must be inferred. Speculative resources are gas volumes that are thought to exist but that have not yet been drilled. These clearly have great uncertainty. Reserves are the volume of technically recoverable gas resources that can be produced at a profit based on present assumptions about cost and price. Supply is the much smaller portion of reserves that has been developed and connected to infrastructure so that it is available on demand to consumers.

I first applied the EIA guideline of 25% Gas-In-Place to determine TRR for the BGS low, high and most-likely gas resource cases for the Bowland Shale. Next, I used the relative percentages of probable (32%), possible (43%) and speculative (25%) TRR taken from the PGC's latest assessment of the U.S. technically recoverable resource base. Finally, I assumed that 50% of the Speculative TRR would be commercially producible, since there is no production from the Bowland Shale, and used this value as the potential reserve estimate.

This approach suggests that the most-likely reserve for the Bowland Shale is approximately 42 Tcf. While this is a substantial volume of gas (roughly equivalent to the Barnett Shale accumulation in the U.S. based on a recent evaluation by the Texas Bureau of Economic Geology in press), it is hardly the amount of gas reported by the mainstream media based incorrectly on the total resources reported by the BGS.

The larger problem for the U.K. and all developed countries is energy for transport fuel and natural gas will not solve that in anything less than decades at best. I want to dispell the mistaken notion that energy sources can be freely substituted. Just because there is another 14 years of potential gas supply for the U.K. because of the Bowland Shale, how hopeful is that in the long-term view of many decades before other energy sources may constitute a meaningful percentage of total energy demand? Also, why do we have to use supply as fast as we can?

Then there are the obvious issues that will challenge development of this resource like public opposition to the physcial footprint of development--based on well productivity from the Barnett Shale, it will take approximately 30,000 wells to fully develop the Bowland Shale potential reserves--and the lack of incentives for landowners (the state owns oil and gas mineral rights in the U.K.) to participate since there is no commecial benefit for them. Also, there is no guarantee that this play will work geologically or be commercial.

While the Bowland Shale is the same geological age as the Barnett and Fayetteville shales in the U.S. and is known to be an oil source rock like the U.S.shales, there is no evidence to suggest that U.S. shale production is an analogue for Bowland gas-producing potential. Among the most important factors in shale gas play performance are high organic content, high thermal maturity and high silica or limestone content. These produce brittle shale reservoirs with large volumes of available gas. High organic content also results in creation of important porosity where kerogen is converted to gas because of a volume change.

So far, there is little geochemical data for the Bowland Shale and, while some of the data appears to be in a similar range as for the Barnett Shale, lack of comprehensive data is a risk factor in assessing the potential of the play. Each shale gas play is different and, until industry knowledge is greater, must be viewed as a “one‐off” opportunity with a considerable learning curve, unanticipated costs and commercial risk.

A Few Words About Peak Oil

(Note:  This post originally appeared in The AAPG Explorer, Februrary, 2013)

Steve Trammel of IHS stated in the January EXPLORER (“Surprise! North America Grabbed the Spotlight”), “The Peak Oil guys are pretty quiet now, thanks to the creativity and innovation of the industry,” as he discussed the tight oil additions to oil production in the United States and Canada.

I am on the board of directors of the Association for the Study of Peak Oil (ASPO USA), and I can assure you that we are not quiet nor do these additions change our concern about the growing cost of oil and its effect on our economy.

In the past month alone, we held a major conference in Austin co-sponsored by the University of Texas, a great advocate for the oil and gas business (Texas leads the United States in both oil and gas production). Right after the conference in Austin, a group of our members presented a panel discussion at the fall American Geophysical Union meeting in San Francisco.

In the same month, we were invited to spend two hours with Adam Sieminski, the new Administrator of the U.S. Energy Information Agency (EIA), and all of his top line staff. On the same day, we met with the new chairman of the Senate Natural Resources Committee, and with a former senior senator who is now among the leading energy lobbyists in Washington.

Some people take us very seriously because they understand that “peak oil” does not mean we are running out of oil. It means that we have run out of the cheap oil on which the global economy is predicated. That is serious business.

We also applaud the creativity and innovation of the industry that has increased U.S. production over the past few years. It is, however, very expensive oil. Tight oil requires at least $80 per barrel for operators to break even because of the cost of horizontal drilling and hydraulic fracturing, not to mention the unprecedented leasing costs that the shale revolution has brought to our industry.

The high price of oil is among the key underlying reasons that the United States and most of the developed world cannot get out this recession. Gross domestic product (GDP) and oil consumption correlate because the economy runs on energy, and oil and its refined products are the largest component of primary energy consumption.

Because of the high price of oil, consumption in the United States has fallen 1.5 percent per year since 2005, and GDP has followed suit. Pre-2005 normal growth for the U.S. economy was 1.8 percent per year. With an annual 1.5 percent decline built in, it is not hard to see the problem with resuming growth.*

The IHS tight oil study Trammel quotes is confusing because it combines Canada and the United States. Canada has been energy self-sufficient for decades and is the leading oil exporter to the United States – any production additions from Canada are still imported oil for the United States.

The EIA estimates that U.S. crude oil production will increase to nearly eight million barrels per day by 2020 and then decline. Present consumption is almost 15.5 million barrels per day. If EIA is correct, the United States will still have to import about seven million barrels per day allowing for demand decline, and that does not look like energy independence to me.

Most of the exuberant reports about energy self-sufficiency from domestic production lump crude oil, natural gas liquids, refinery processing gain and biofuels as “liquids.” That is fine, but we must bear in mind that what we import is crude oil and today, we cannot use other liquids for transport – the main use of crude oil – without massive equipment and infrastructure changes that will cost trillions of dollars and take decades.

These same optimistic reports almost never consider cost, price or profit margins.

The new production we are finding from tight oil is both important and exciting, and it will help make the United States less dependent on foreign crude oil. It will not, however, make us energy independent.

Peak Oil guys like me are hoping that at least people in the oil and gas business will realize that we have a problem that is not going away.

(*All data in this section from Douglas-Westwood.)

(Editor’s note: Berman, an AAPG member, is with Labyrinth Consulting Services in Sugar Land, Texas.)