Petroleum Truth Report

U.S. Shale Gas: Less Abundance, Higher Cost

2011-07-31T13:30:00.000-07:00

SEE THE FULL POST ON THE OIL DRUM:

http://www.theoildrum.com/node/8212

Arthur E. Berman and Lynn F. Pittinger

Lynn Pittinger is a consultant in petroleum engineering with 30 years of industry experience. He managed economic and engineering evaluations for Unocal and Occidental Oil & Gas, and has been an independent consultant since 2008. He has collaborated with Berman on all shale play evaluation projects since 2009.

Introduction

Shale gas has become an important and permanent feature of U.S. energy supply. Daily production has increased from less than 1 billion cubic feet of gas per day (bcfd) in 2003, when the first modern horizontal drilling and fracture stimulation was used, to almost 20 bcfd by mid-2011.

There are, however, two major concerns at the center of the shale gas revolution:

• Despite impressive production growth, it is not yet clear that these plays are commercial at current prices because of the high capital costs of land and drilling and completion.

• Reserves and economics depend on estimated ultimate recoveries based on hyperbolic, or increasingly flattening, decline profiles that predict decades of commercial production. With only a few years of production history in most of these plays, this model has not been shown to be correct, and may be overly optimistic.

These are not purely technical topics for debate among petroleum professionals. The marketing of the shale gas phenomenon has been so effective that important policy and strategic decisions are being made based on as yet unproven assumptions about the abundance and low cost of these plays. The “Pickens Plan” seeks to get congressional approval for natural gas subsidies that might eventually lead to conversion of large parts of our vehicle fleet to run on natural gas. Similarly, companies have gotten permits from the government to transform liquefied natural gas import terminals into export facilities that would commit the U.S. to decades of large, fixed export volumes. This might commit the U.S. to decades of natural gas exports at fixed prices in the face of scarcity and increasing prices in the domestic market. If reserves are less and cost is more than many assume, these could be disastrous decisions.

Executive Summary

Our analysis indicates that industry reserves are over-stated by at least 100 percent based on detailed review of both individual well and group decline profiles for the Barnett, Fayetteville and Haynesville shale plays. The contraction of extensive geographic play regions into relatively small core areas greatly reduces the commercially recoverable reserves of the plays that we have studied.

The Barnett and Fayetteville shale plays have the most complete history of production and thus provide the best available analogues for shale gas plays with less complete histories. We recognize that all shale plays are different but, until more production history is available, the best assumption is that newer plays will develop along similar lines to these older plays. There is now far too much data in Barnett and Fayetteville to continue use of strong hyperbolic flattening decline models with b coefficients greater than 1.0.

Type curves that are commonly used to support strong hyperbolic flattening are misleading because they incorporate survivorship bias and rate increases from re-stimulations that require additional capital investment. Comparison of individual and group decline-curve analysis indicates that group or type-curve methods substantially over-estimate recoverable reserves.

Results to date in the Haynesville Shale play are disappointing, and will substantially underperform industry claims. In fact, it is difficult to understand how companies justify 125 rigs drilling in a play that has not yet demonstrated commercial viability at present reserve projections until gas prices exceed $8.68 per mmBu.

SEE THE FULL POST ON THE OIL DRUM:

http://www.theoildrum.com/node/8212

Interview on Platts Energy Week TV

2011-07-24T16:36:00.000-07:00

Arthur Berman, Houston-based Geoscientist, discusses a recent story featured in the NY Times that called into question whether the shale boom was akin to a ponzi scheme.
http://www.plattsenergyweektv.com/video/default.aspx#/Platts+Energy+Week%2DAlt/07.24.11+Latest+Controversy+Over+Shale+Exploration/78974462001/748923961001/1070933193001

National Legal and Policy Center Lacks Courtesy to Respond

2011-07-17T08:36:00.000-07:00

On July 7, 2011, The National Legal and Policy Center's (NLPC) Chairman Kenneth Boehm published untrue and unsubstantiated statements about me. On July 12, I responded with demands for corrections that were published on this blog: http://petroleumtruthreport.blogspot.com/2011/07/smear-campaign-continues.html.

A week later, the NLPC has not shown the professional courtesy to respond to my request. I leave it to my readers to decide what this means about the NLPC.

The Smear Campaign Continues

2011-07-12T19:24:00.000-07:00

Today, Mr. Kenneth Boehm, Chairman of the National Legal and Policy Center, wrote an e-mail to Arthur Brisbane,The New York Times Public Editor, in which he made false and unsubstantiated statements about my professional work and conduct:

http://nlpc.org/stories/2011/07/07/ny-times-asked-investigate-shale-gas-bubble-series

Mr. Boehm,

I demand a public correction and apology for the unethical, un-researched and un-investigated statements that you made about my professional activities and positions in your e-mail to Arthur Brisbane, Public Editor of The New York Times, and that are now reproduced on the NLPC website.

"Arthur Berman makes his living providing investment advice based upon his own position as a shale gas critic."

Your reference is to a news report on a technical talk that I gave pro bono two years ago that in no way supports your claim that I make my living providing investment advice.

In fact, I do not.

I am a petroleum geologist and have spent all of my thirty-three year career making maps, interpreting subsurface data, evaluating drilling prospects and advising clients on the technical risks of petroleum systems. I am a licensed geoscientist in the State of Texas and have held numerous unpaid positions as an officer in professional geological societies.

I have no experience as a financial advisor and have never given any client investment advice as you claim.

I have no position as a shale gas critic. I evaluate a broad spectrum of oil and gas opportunities in my work and have no bias toward any of them. If the petroleum system risk, reserve, rates and economics of a prospect or play do not meet threshold criteria, I provide this interpretation.

The fact that shale gas plays fail to meet these standard criteria does not make me a shale gas critic but, rather, an honest broker of objective data.

"The truth is that Mr. Berman is a very lonely proponent of this view. As much as he has tried for over three years, he has garnered virtually no scientific support."

Your reference is to a technical report that I published in World Oil, a respected industry journal (re-printed on my blog) that it no way supports your comments.

I suggest that you poll the thousands of technical professionals in the oil and gas business who have filled my invited pro bono technical presentations at professional societies all over the country for many years. Any rudimentary research would reveal that my publications and public lectures cover a spectrum of petroleum subjects of which shale gas is only part. Perhaps you should poll my many clients about the degree to which they find scientific merit in my work.

"In these emails, Mr. Berman appears to be corresponding with, among others, investors who missed out on the boom in shale gas and stand to gain, financially, from a devaluation of the natural gas industry."

You provide no reference for this ridiculous statement so it is obviously nothing more than unethical conjecture to support a bias that you appear eager to forward.

"Mr. Berman offers his views regularly to media outlets which service the investment community, consistently espousing views supportive of short sellers."

Your reference is to a blog by someone who I have never heard of who apparently heard a presentation that I made and summarized my conclusions. I never gave this person an interview and have no idea about his business. Your reference does not support your specious speculation.

I have no interest in or knowledge of short sellers. My business is geology not finance. I have never taken a short position and, frankly, would have to ask how to do it.

I called you today to discuss these and other matters but, since you did not give me the courtesy of a return call, I must write my comments.

Your written comments to Mr. Brisbane are in direct violation of the NLPC's stated purpose:

"NLPC promotes ethics in public life through research, investigation, education and legal action."

Your statements reflect a profound lack of ethics, research or investigation.

I have no interest in defending or otherwise taking the side of The New York Times about its article on shale gas. I do have deep interest in preventing people from making false and damaging statements about me while pursuing some agenda also outside of my interest.

I look forward to a swift rectification of your incorrect and unsubstantiated statements.

Sincerely,

Arthur E. Berman

The Smear Campaign to Distract From the Truth That Shale Plays Are Commercial Failures

2011-07-09T05:43:00.000-07:00

There is a carefully organized smear campaign orchestrated by powerful corporate interests (http://nlpc.org/stories/2011/07/07/ny-times-asked-investigate-shale-gas-bubble-series) to distract from my central argument that the shale gas plays are commercial failures.

I have a clean conscience about all of this and am willing to discuss it with anyone.

I told no one beyond my closest circle of family and friends about the upcoming New York Times article and I did not make any investments, nor did any of my clients or friends, make any investments that I know about based on the timing of its publication.

I was not shown any advance versions of the article and read it for the first time late Saturday, June 25 when it was published online.

I have no active investments in stock and have not for several months. Most of my investments are in REITs, bonds, or commodity funds.

Anyone who thinks that e-mails are confidential only needs to pay attention to the international news (WikiLeaks or any number of discovery cases) to realize that everyone should be careful about what is put in e-mail communications. I am not pleased about how the New York Times published e-mails that supposedly came through me, but I also think that those who believe that this kind of communication is secret and confidential must wake up to the real world.

I will fight the claims of wrong doing to the extent that this is productive, and believe that my record speaks for itself.

The real issue here is the truth about the economics and conduct of shale plays by the independent E&P companies.

All of the media innuendo is calculated to distract from the truth that the shale plays to date are non-commercial and that the companies involved have not been truthful about this.

Jon Entine forced to re-write his post, "Natural Gas "Bubble" Report: Market Tinkering or Shoddy Reporting?"

2011-07-06T19:31:00.000-07:00

Because of my objections, RealClear Politics forced Jon Entine to "update" his post, "Natural Gas "Bubble" Report: Market Tinkering or Shoddy Reporting?"

http://www.realclearpolitics.com/articles/2011/07/01/natural_gas_bubble_report_market_tinkering_or_shoddy_reporting.html

Entine's post remains objectionable because it relies on unsubstantiated speculation rather than evidence or data.

It is indeed curious and ironic that one of Entine's recent articles is titled, "When Science is Unfavorable, Attack the Scientist."

What do you think that you just did, Jon?

Letter to George Mason University re: Jon Entine's post-Natural Gas "Bubble" Report: Market Tinkering or Shoddy Reporting?

2011-07-04T11:40:00.000-07:00

Dear Sir or Madam,

Jon Entine has posted an article called "Natural Gas "Bubble" Report: Market Tinkering or Shoddy Reporting?"(http://www.realclearpolitics.com/articles/2011/07/01/natural_gas_bubble_report_market_tinkering_or_shoddy_reporting.html) in which he represents himself as a staff member and representative of George Mason University. At the end of his post he identifies himself as "directing the Genetic Literacy Project and as a senior fellow at STATS and the Center for Health and Risk Communications at George Mason University."

His post contains errors, exaggerations and untrue statements that cannot be substantiated, and thereby jeopardize George Mason University's legal position and reputation as an honest broker of information.

I demand that Mr. Entine post public corrections to the many incorrect and unsubstantiated claims that he makes in this post. I further request that he write to me directly acknowledging that his post contained the many incorrect and undocumented claims that I specify below. He never contacted me or my clients to verify these claims and, apparently, did no research to document his many specious allegations.

My work with Indiana Gasification (IG) as an expert witness is a common and legitimate role for experienced oil and gas experts. I demand that he state in his correction that there is nothing unusual about my relationship as a paid expert witness for IG or any other entity.

I demand that he correct the statement that my testimony was about "buying natural gas made from coal instead of hydraulic fracturing." My written and oral testimony is on public record for anyone to read. I did not discuss coal or hydraulic fracturing in my written or oral testimony before the Indiana Electric Utility Commission (IEUC). My testimony was about natural gas supply, demand and price expectations. I demand that he explains in his correction that my testimony contained no statements about "buying natural gas made from coal instead of hydraulic fracturing."

His statement, "The coal industry fears getting crushed by the cleaner, natural gas movement, and Berman backed coal" is speculation by him, and does not reflect testimony that I gave to the IEUC.

I did not make this statement and did not comment in my written or oral testimony about the concerns of the coal industry concerning natural gas. I did not "back coal" and I demand that he corrects this mis-representation. I demand that he states in his correction that my testimony contained no statements that "The coal industry fears getting crushed by the cleaner, natural gas movement, and Berman backed coal."

Mr. Entine writes that I have a direct conflict of interest with Middlefield Capital in Toronto, and claims that I am compensated as a shale gas skeptic. My role with The Middlefield Group (Middlefield) is founded in a contract to conduct client presentations as well as television, newspaper and other media interviews that provide my analysis of oil and gas supply, demand and price trends.

My contractual relationship with Middlefield involves a quarterly retainer payment, and I receive no compensation other than this. I receive no direction from Middlefield on the topics of my quarterly presentations, and have never featured an "anti-shale gas investment outlook" in my association with Middlefield and its clients.

I demand that he corrects the statement "Berman not only has an indirect financial interest playing the role of shale gas skeptic, he has a direct conflict of interest."

I demand that he explains in his correction that I have no financial interest playing the role of a shale gas skeptic in my relationship with Middlefield. I demand that he explains in his correction that I have no direct or indirect conflict of interest in my relationship with Middlefield.

I demand that he explains in his correction that I receive no compensation from Middlefield other than a fixed quarterly fee, and that I receive no direction from Middlefield on the subjects of my quarterly presentations to their clients.

He states that "Berman is reportedly also a consultant and paid speaker with the Canadian Imperial Bank of Commerce (CIBC)."

I gave a paid talk in July 2010 for CIBC and have no other business relationship with that organization. I demand that he corrects the statement that "Berman is reportedly also a consultant and paid speaker with the Canadian Imperial Bank of Commerce." I demand that he explains in his correction that I have no business relationship with CIBC beyond the paid presentation that I made in July 2010.

He states that "Moreover, if any of their clients, or indeed the fund managers at Middlefield, knew that the Times story was coming out, they could face charges of market manipulation under Canadian and U.S. securities law." I never told Middlefield or any other entity that the New York Times article was going to be published. I did not have advanced access to the New York Times article and did not read the article until its publication on June 26, 2011 when I bought a copy of the newspaper.

I demand that in his correction he explains that I did not tell Middlefield or any other entity that the New York Times article was going to be published. I further demand that he explains in his correction that I or Middlefield do not face charges of market manipulation under Canadian and U.S. securities law.

He wrote "Did Berman tell his strategic partners and clients, and directly profit from the Times story? Did Middlefield's funds or clients or CIBC's clients with knowledge of the Times’ piece hold short interest in shale stocks or long interest in competitors' stocks? Did the Canadian oil sands industry, which includes Middlefield Capital, seek to influence the U.S. fracking debate, which could be a potential violation of the Foreign Agents Registration Act? Did Middlefield's funds or clients or CIBC's clients have short interest in shale stocks ahead of the Times report? Is the Times' key source dealing in inside information?"

I demand that he corrects the statement implying that I profited from the New York Times article. I have not. I demand that he explains in his correction that I did not tell my clients about the New York Times article. I demand that he explains in his correction that neither my partners, clients nor I profited from the New York Times story. I demand that he explains in his correction that I had no knowledge of any clients' interests in stock positions. I demand that he explains in his correction that I gave no advice about oil sands or any other investment to any client.

I demand that he correct the statement that states that I gave Middlefield's fund or clients or CIBC or CIBC's clients information that resulted in them taking short positions with knowledge of the New York Times article since I did not tell them about the New York Times article, and am unaware of any positions that Middlefield or CIBC have, and have had no contact with CIBC in this regard since my paid presentation one year ago.

I demand that in his correction that he explains that I did not give Middlefield any information about any position that they may have on any investment based on any statement that I made about the New York Times article.

I demand that he corrects the incorrect statement that I influenced Middlefield on the Canadian oil sands industry or the U.S. "fracking debate."

I demand that he explains in his correction that I gave no information or advice to Middlefield about Canadian oil sands or hydraulic fracturing although, as a general case, providing advice for a fee as an energy expert is appropriate and legitimate.

I look forward to the publication of these corrections and explanations.

All the best,

Arthur E. Berman

View my interview on CNBC Kudlow's Money Politics

2011-06-30T09:40:00.000-07:00

Here is the link to Kudlow's Money Politics 27 June 2011

http://www.msnbc.msn.com/id/21134540/vp/43556438#43556438

Why I Support Hydraulic Fracturing

2011-06-29T21:03:00.000-07:00

Some of you have asked if I am for or against hydraulic fracturing (fracking). I support it

The oil and gas industry has been using this stimulation technique commercially since 1949. Among the tens of thousands of wells that have been hydraulically fractured, there are few documented cases in which contamination of shallow aquifers has occurred. In those rare instances, the cause has been overwhelmingly because of improper pumping procedures or pipe specifications that have allowed parting of the conductor casing and cement that protects the aquifer. In other cases, contamination of aquifers occurred because natural gas liberated by the fracturing process found its way into improperly plugged vertical wells nearby. These unfortunate situations are preventable.

The Environmental Protection Agency (EPA) published a report in 2004 which concluded that hydraulic fracturing of coal-bed methane wells had minimal effect on groundwater quality. Since coal-bed methane wells are generally very shallow, they have higher likelihood of affecting aquifers than oil and gas wells drilled thousands of feet deeper. EPA is currently studying the impact of hydraulic fracturing on shale gas wells. The conclusion of research is expected by the end of 2012 and the study should be published in 2014.

I respect the concerns of people living in the vicinity of oil and gas wells that have been or will be hydraulically fractured. At the same time, it is difficult for me to imagine that fluids injected thousands of feet underground can migrate through multiple sealing rock formations into aquifers a few tens or hundreds of feet below the surface. The pressure requirements to do this are far beyond any pumping technology.

Hydraulic fracturing is critical to unlock the oil and natural gas found in low permeability reservoirs. There are risks associated with this stimulation technology. Those who fear the potential negative effects of fracturing must balance their concerns with their need for a continual supply of electricity generated by burning natural gas. They should also weigh the more negative impact of burning coal, the only viable alternative at least for the short term.

On the other side, the oil and gas industry should be more sensitive to the public's fears, and should be more forthcoming with information about the chemicals pumped into oil and gas reservoirs. We should also willingly undertake stricter self-regulation anticipating the less desirable but inevitable government intervention if we do nothing.

EIA Annual Energy Outlook 2011: Don’t Worry, Be Happy.

2011-01-01T07:19:00.000-08:00

See my post on The Oil Drum: http://www.theoildrum.com/node/7285

We no longer have to worry about energy supply or prices. That is the message from the U.S. Energy Information Administration’s (EIA) Annual Energy Outlook (AEO) 2011. Cheap energy will characterize the world for most of the next decade, according to the report. Oil will not reach $100 per barrel until 2017 and natural gas will remain below $5 per thousand cubic feet (mcf) until 2022 (Figure 1).

Despite four decades of oil shocks and natural gas price spikes, the future looks stable with supply and demand comfortably balanced (Figure 2). Wasn’t it just two-and-a-half years ago that $147 per barrel oil helped push the world into the current global recession? The EIA forecast is as troubling for the smooth and gradual progression of oil and gas prices as it is for the improbably low values of those prices. The history of oil and gas price, supply and demand is characterized above all by volatility but the EIA projection does not reflect this characteristic. Don’t worry, be happy.

Natural Gas

The headline of the AEO 2011 Early Release Overview (http://www.eia.gov/forecasts/aeo/) published December 16, 2010 is that shale gas resources in the U.S. have more than doubled since last year’s report. The current estimate is 827 trillion cubic feet (tcf) of gas, up 474 tcf from last year’s assessment of 353 tcf. The new figure is 25% higher than the Potential Gas Committee’s (PGC) 661 tcf from shale in its June 2009 report (http://www.mines.edu/Potential-Gas-Committee-reports-unprecedented-incre...). Notably, the PGC also presented a “probable” case of total gas resources of 441 tcf. Shale gas represents approximately one third of this estimate and is 17% of the EIA estimate (147 tcf). We hope to get more detail on how the EIA determined total and shale gas resources, along with other aspects of the EIA Outlook when the full AEO 2011 is released in March.

Technically recoverable resources should never be confused with reserves because resources do not take commercial considerations into account. These may be in accumulations so small or so deep that the gas may never be drilled or produced at any price, or may be in areas that are off limits or impractical to drill. It includes plays and basins that are, as yet, untested.

A resource assessment begins by estimating a total resource in place based on assumptions about gas richness, shale thickness, thermal maturity and areal distribution. A technically recoverable resource is a sub-set of the total resource that is determined by eliminating areas where one or more of these factors are marginal. There is great uncertainty involved in both of these estimated volumes. The expectation of future production based on as yet uncertain current production decline models is a key factor. For North America, The Baker Institute estimates 583 tcf of technically recoverable shale gas resources. Other estimates include Navigant Consulting (900 tcf), the Potential Gas Committee (661 tcf), and ARI (1000 tcf).

Given the variations in these recent evaluations (2008-2010) by credible organizations, resource estimates should not have much bearing on future production volume or price forecasts. The EIA, however, takes a different view. Slide 27 in Richard Newell’s December 26 unveiling of the AEO 2011 states, “Natural gas price projections are significantly lower than past years due to an expanded shale gas resource base” (Figure 3).

For the EIA, increased estimates for U.S. shale gas resources equate to higher production volumes, lower prices, and decreased imports of natural gas with shale gas accounting for 45% of total supply by 2035 (Figure 4). Average annual gas prices are 20-25% lower than predictions made a year ago in AEO 2010.

The only volume that really matters is proved developed reserves. While the EIA’s estimate of resources has doubled since last year, proved reserves only increased 2.5% in 2010 (EIA AEO 2011). Much of this increase will likely be proved undeveloped reserves (PUD) thanks to revisions in Securities and Exchange Commission definitions for 2009. Clearly, the commerciality of undeveloped reserves is more questionable than proved developed reserves.

The EIA fails to grasp that the exploration and production business succeeds or fails based on earnings and profit, and not on production growth, resource or even reserve additions. Natural gas operators require at least $7.00 per mcf on average to break even in the shale plays (Figure 5).

Favorable hedge positions over the past five years have carried companies through fluctuating and, more recently, low product prices. With futures strips now below $5.00/mcf for the next twelve months, hedges fail to guarantee the marginal cost of production.

While shale play enthusiasts have claimed profitability at gas prices below $5/mcf in recent years, these half-cycle economics do not include significant “fixed” and “sunk” costs such as debt service and overhead. With the flight to liquids-rich plays in recent months, the truth about true cost is being revealed. Chesapeake Energy, the paragon of shale operators, states in their most recent investor presentation that they do not intend to drill anything other than obligation wells in gas plays “until natural gas prices rise above $6.00 per mcf” (Figure 6). This reveals their commercial threshold despite past claims of profit at lower gas prices.

The EIA gas price forecast, therefore, implies that operating companies will continue to drill and produce gas at a loss for the next decade. This cannot happen. Because of the high decline rates of shale gas wells, drilling must continue at current rates just to maintain production rates.

Because some large operators in the Barnett Shale stopped drilling new wells in 2010, we can determine true portfolio decline rates, and they are substantially greater than predicted hyperbolic decline models. Figure 7 shows that the portfolio production decline rate is more than 40% for Barnett Shale wells operated by Encana, ConocoPhillips, Range Resources and Williams.

For shale gas production to double and reach 45% of total U.S. supply as the EIA predicts by 2035 (Figure 4), rig counts will have to more than double. This cannot happen unless gas prices rise substantially beyond EIA predictions regardless of improvements in drilling efficiency and economies of scale.

The most likely average natural gas spot price for 2011 will be $4.10/mcf (J. M. Bodell, personal communication). Toward the end of the year, it is possible that gas prices will strengthen toward $5.00 as drilling to hold land by production decreases.

Crude Oil

The EIA’s assessment of crude oil supply, demand and price is similarly puzzling by its departure from current data and considerable informed opinion that oil price will rise in the near term. The projection that oil prices will remain below $100 per barrel until 2017 conflicts with every credible source on the topic. The U.S. military, the world's largest single consumer of oil, has publicly stated its belief that there may be a liquid fuel shortage by 2012 (Joint Operating Environment (JOE) Report, 2010:http://www.jfcom.mil/newslink/storyarchive/2010/JOE_2010_o.pdf).

Oil closed at $91.51 on Friday, December 24, 2010 and will probably end 2010 at an average price of about $79.50 per barrel, yet the EIA estimate for the year is $78.03. Many experts predict that oil prices will exceed $100 per barrel in 2010, but my sources indicate that West Texas Intermediate crude oil prices will average $88 per barrel (J. M. Bodell, personal communication) but will increase to $95 or $100 per barrel later in the year.

The main factor that will control crude oil prices in 2011 is demand from the developing economies of countries outside of the OECD (Organization for Economic Cooperation and Development). Demand is expected to increase 3.6% (IEA) among developing nations and this should challenge OPEC (Organization of the Petroleum Exporting Countries) spare capacity. Because of subsidized oil and motor fuel prices in all OPEC countries, crude oil demand is largely insensitive to price. In contrast, the IEA predicts that oil demand in OECD countries will decrease 0.5% in 2011.

The EIA AEO 2011 report features a 14% increase in U.S. crude oil and lease condensate production from 2011 to 2020 (Figure 8) despite an 8 percent decline in production over the past decade and a 44% decrease since the 1970 U.S. production peak (Figure 9).

It further implies that unprecedented increases in nuclear, hydroelectric, biofuels and renewable energy sources will magically materialize to meet growing U.S. energy demand. EIA forecasts also imply that global liquids production will reach 115 mmbopd before 2035 while other estimates, including those by the IEA (International Energy Agency), do not anticipate that production can exceed 100 mmbopd (Figure 10), and many doubt that it can even reach that level. In any case, the price of oil would have to be substantially higher than EIA estimates to reach the production levels that it predicts.

Conclusions

It is understandable that the EIA, as a branch of government, must produce an annual report that is politically expedient and that supports a view that meets public policy expectations. The EIA approach takes a long-term economic view and is, therefore, not concerned with the fluctuations that characterize the real world of petroleum supply, demand and price. At the same time, it is not useful that this report is in conflict with industry best practices and opinion as well as trend data available to the public.

The EIA’s resource estimate of technically recoverable gas from shale is interesting but not relevant to future price or production volume forecasts. The Potential Gas Committee’s 2009 report is the benchmark of credibility, and we hope that the full EIA report in March will explain why we should accept unwarranted and insupportable upward revisions to PGC resource estimates and how these might translate to energy reserves and price. The EIA treats shale gas just like conventional gas in its forecasting and does not acknowledge the much higher decline rates and, therefore, great number of wells required to maintain supply.

Exploration and production companies involved in shale gas production have presented a position that emphasizes production and reserve growth over earnings or profit. It is confusing that the EIA has assumed that market forces and improving efficiencies will save the day for oil and gas prices. It would be more appropriate to frame the problem in the context of reasonable expectations that would be useful to public understanding of the shale gas phenomenon and its potential contribution to natural gas volumes and price. It is unsettling that the EIA has not acknowledged the belief by the U.S. military and other credible sources of an impending liquid fuel shortage that confronts the United States and the world (e.g. Hirsch, Benzdek and Wendling, 2010; JOE Report) . Instead, the EIA has provided an unrealistic view of future oil and gas supply and price that will inevitably not serve public understanding or promote reasonable planning for resource availability or price.

Oil Seepage: An Inconvenient Truth (TREICoLimited)

2010-08-01T07:44:00.000-07:00

Oil seepage an inconvenient truth-npa seep information - gom portion

View more presentations from aeberman.

BP's Deepwater Horizon - Static Top Kill vs. Bottom Kill: Weighing the Risks

2010-07-30T07:47:00.000-07:00

The original version of this post is on The Oil Drum

A permanent solution to the BP Macondo blowout in the Gulf of Mexico may be achieved soon but there are risks. Admiral Thad Allen announced on Monday, July 26 that a static top kill would be attempted on August 2. The schedule may be accelerated to July 31 or August 1 according to an announcement today (July 29). The sealing cap has successfully stopped the flow of oil and gas from the well and the pressure continues to build slowly. Temperature at the wellhead has not increased, and seeps near the well are mostly nitrogen and biogenic methane unrelated to leakage. BP Senior Vice President Kent Wells’ technical update on July 21 explained these findings and showed how the well will be killed.

There are risks involved in both the top and bottom kill procedures. The purpose of this post is to describe those risks. There are two risks associated with the static top kill. First, it may not work at all and second, it may rupture the casing by pumping heavy mud under pressure (“bull heading”).

Kent Wells described the static top kill as a process of continuously pumping mud into the well until the oil is pushed into the reservoir. This is clearly erroneous and must be a simplification designed for the general public. What will more probably take place is a practice called “bleed and lubricate”. Heavy mud is pumped into the well through the choke and kill lines on the blowout preventer (BOP) and allowed to sink to the bottom of the well. Hopefully, the mud will retard the flow so that some of the pressure can be bled off by producing oil to the surface for a short period. Then, more heavy mud will be pumped into the well, and the process repeated as necessary until the well contains enough mud to kill the well.

The first problem with stopping the flow from the top is that it has to be an annular kill: the flow was coming up the annulus outside the production casing. This is a very narrow space so mud will have to pumped at high pressure to achieve entry. It will initially be working against a full column of gas and oil and the shut-in pressure at the well head. On the positive side, if produced sand has accumulated in the annulus, the operation may not have to contend with the full force of the reservoir pressure in addition to these obstacles. On the negative side, the well head seals might prevent or restrict downward flow, or the pumping pressure could rupture the 22-inch casing, or reach a pressure high enough to call off the operation.

Figure 1a (based on a government document) shows that the upper part of the well bore is protected by three strings of casing (36-, 28-, and 22-inch) and cement down to 7,937 feet (measured depth below sea level). A fourth string of 16-inch casing extends nearly from the well head to where it is cemented at 11,585 feet, but it is apparently hung inside the 22-inch casing at 5,227 feet, leaving a gap of 160 feet. The 16-inch pipe has a burst rating approximately equal to the current shut-in pressure of 6,900 psi (80% of rating), but the 22-inch pipe does not meet this standard.

BP has said that the relief well DD3 plan will continue regardless of the success of the top kill operation. The main risk with a bottom kill is that it may take considerable time to accomplish. Because of the recent tropical storm, crews are just removing the storm packer today, and it will take time to re-enter and condition the hole before drilling resumes. BP estimates that the DD3 will intersect the Macondo well around August 10. Most efforts to intersect a blown-out wells require several attempts. The recent 2009 Montara blowout in the Timor Sea required four attempts that took a month after the relief well was near the blow out and cased. The bottom of the first Macondo relief well is currently located a few feet from the target at approximately 17,220 feet measured depth (based on Wells’ update and shown in Figure 1b).

The good news is that, in this case, the relief well does not, apparently, need to intersect the well exactly--it just needs to be close. Once the relief well penetrates the reservoir, enough mud can be pumped to hopefully overcome flowing pressure and kill the well. The bottom-kill option has the same annular flow path liabilities as the top kill, but it has the capacity to deliver higher flow rates directly to the reservoir. This approach will not cause significant pressuring near the well head and should not, therefore, pose a risk of rupturing the 22-inch casing.

The bottom kill option involves considerably less mechanical risk than the top kill, but time is the enemy, so the top kill makes sense. Maintaining the objectivity to abandon the operation rather than risk casing rupture will be critical.

Arthur Berman talks about Shale Gas: An interview in ASPO-USA's Newsletter

2010-07-28T07:05:00.000-07:00

Arthur Berman talks about Shale Gas
Posted by Gail The Actuary on July 28, 2010 - 10:40am Topic: Supply/Production
Tags: Shale Gas

Recently, ASPO-USA's newsletter printed an interview (Part 1 and Part 2) with Oil Drum staff member Art Berman (aeberman). Art is a geological consultant whose specialties are subsurface petroleum geology, seismic interpretation, and database design and management. The people doing the interview are members of the "Peak Oil Review Team," abbreviated POR in the text below. This is the shale gas portion of the interview.

POR: Can you give us your latest updated perspective on the shale gas story?

Art Berman: You have to acknowledge that shale gas is a relatively new and significant contribution to North American supply. But I don’t believe it’s anywhere near the magnitude that is commonly discussed and cited in the press. There are a couple of key points here. First the reserves have been substantially overstated. In fact I think the resource number has been overstated.

Read the rest of the interview on The Oil Drum...

My interview on CNN American Morning

2010-07-26T21:06:00.001-07:00

View my interview about the BP Macondo well on CNN American Morning: http://www.youtube.com/watch?v=Zv2ONRlaLNc

Estimated Oil Flow Rates From the BP Mississippi Canyon Block 252 “Macondo” Well

2010-06-27T12:02:00.000-07:00

Estimates of flow rates for the BP Deepwater Horizon “Macondo” well now range from 1,000-100,000 barrels of oil per day (bopd). Initial estimates were 1,000 bopd. These increased to 3,000 bopd and then to 5,000 bopd. Now the U.S. Geological Survey believes the well is flowing 20,000-40,000 bopd but other experts believe that flow rates may be as high as 60,000 bopd. Some have even suggested rates as high as 100,000 bopd, and others as high as 250,000 bopd. The purpose of this post is to provide a calibration framework for probable flow rates.

More than 8,700 wells drilled in the Gulf of Mexico since 1996 were evaluated using publicly-available production data from the Minerals Management Service (MMS). Wells in the deepwater Gulf of Mexico dominate the highest flow rates in this data set. Approximately 4,000 wells have been drilled in water depths more than 1000 ft, and more than 700 in more than 5,000 ft of water during the past 20 years. The Macondo well was drilled in 5,067 ft of water to a total depth of 18,360 ft below sea level.

Historical Context for High Flow Rates in the Gulf of Mexico

The highest flow rate for a single well in the Gulf of Mexico is 46,467 bopd (Figure 1) based on the daily average of the peak month of production. The mean of the 50 wells with the highest oil flow rates is 27,753 bopd. A probability plot (Figure 2) of these wells indicates that the most likely case is about 27,000 bopd (P50). There is a 10% probability (P10) that a well will produce 37,000 bopd, and a 90% probability (P90) that it will produce 20,000 bopd.

There is no historical precedent for a single well producing more than 100,000 bopd. Among historical blowouts, the highest flow rates known are approximately 100,000 bopd at the Spindletop Field in Texas in 1901, the Midway-Sunset Field in California in 1910, the Long Beach Field in California in 1910, and the Lake Maracaibo Field in 1922 (http://en.wikipedia.org/wiki/Blowout_%28well_drilling%29). These were all open-hole completions drilled without casing or drilling fluid so they represent maximum unconstrained flow rates.

The BP “Worst Case Scenario” Document

An internal BP “worst-case scenario” document released June 20 has been mis-interpreted by some to indicate that the company believes that flow rates as high as 100,000 bopd are possible (http://globalwarming.house.gov/mediacenter/pressreleases_2008?id=0272#main_content). The document states that the probable range is 5,000-40,000 bopd (http://globalwarming.house.gov/files/WEB/flowrateBP.pdf). It further states that the maximum theoretical rate is 60,000 bopd. It is important to note that these values represent unconstrained, open-flow rates that might be expected after removing the BOP from the well, and are estimated to be at least 10,000 bopd more than present flow. The 100,000 bopd rate assumes that flow is occurring within the production and casing and around the annulus. It again is an unconstrained rate.

The Most Likely Case

We know that the well is producing at least 25,000 bopd because that much has been collected in a single day. It is impossible to know the flow rate until the well is brought under control and rates and pressures can be measured. It is possible that the welll is flowing at a rate 25% higher rate than any well drilled to date (60,000 bopd) in the Gulf of Mexico, but it is not likely. It is less likely that it is flowing at 110% of the rate of the highest rate well so far (100,000 bopd). It is reasonable that it may be among the highest rate wells, and was initially flowing at 40,000-50,000 bopd.

Impacts of President Obama’s Order Halting Work on 33 Exploratory Wells in the Deepwater Gulf of Mexico

2010-06-12T02:12:00.001-07:00

The Presidential Order does not affect the 4,515 shallow-water wells, and it does not affect 591 producing deepwater Gulf wells.

Roughly 33% of nation’s domestically produced oil comes from the Gulf of Mexico, and 10% of the nation’s natural gas.

80% of the Gulf’s oil, and 45% of its natural gas comes from operations in more than 1000 feet of water – the deepwater (2009 data).

Suspension of operations means roughly 33 floating drilling rigs – typically leased for hundreds of thousands of dollars per day – will be idled for six months or longer.

$250,000 to $500,000 per day, per rig – results in roughly $8,250,000 to $16,500,000 per day in costs for idle rigs;
Secondary impacts include:
• Supply boats – 2 boats per rig with day rates of $15,000/day per boat - $30,000/day for 33 rigs – nearly $1 million/day
• Impacts to other supplies and related support services (i.e., welders, divers, caterers, transportation, etc.)

Jobs –

Each drilling platform averages 90 to 140 employees at any one time (2 shifts per day), and 180 to 280 for 2 2-week shifts
Each E&P job supports 4 other positions

Therefore, 800 to 1400 jobs per idle rig platform are at risk
Wages for those jobs average $1,804/weekly; potential for lost wages is huge, over $5 to $10 million for 1 month – per platform.
Wages lost could be over $165 to $330 million/month for all 33 platforms

Secondary impacts: Many offshore workers live in Louisiana. The state is going to see a decrease in income taxes and sales taxes that would normally be paid by those employees. (The state does not collect a sales tax on oilfield supplies and equipment used offshore.)

Companies Impacted:

Oil Companies Impacted

Shell has seven (7) exploratory wells that will be impacted

Others include:
Chevron (4)
Anadarko (3)
Marathon (2)
Noble Energy (2)
Eni US Operating Co. (2)
ATP Oil & Gas (2)
Statoil (2)
ExxonMobil (1)
Petrobras America (1)
BHP (1)
BP (1)
Kerr McGee (1)
Murphy (1)
LLOG (1)
Newfield (1)
Hess (1)

The 33 gulf wells where operations are suspended were the ones inspected immediately after the Deepwater Horizon blowout (per Interior Secretary Ken Salazar); in those inspections, “only minor problems were found on a couple of rigs”. Salazar believes “additional safety measures can be taken including dealing with cementing and casing of wells and significant enhancements and redundancies of blowout prevention mechanisms. Although these rigs passed the inspections, we will look at standards that are in place.”

Longer term impacts include

Idle drilling rigs in the Gulf could mean that they will be contracted overseas for work in other locations, and if/when the halt is lifted, rigs will not be available for completing the work in the Gulf.

Loss of tolls on LA Highway 1 resulting from loss of traffic related to deepwater operations; tolls go directly to retiring the bond debt for construction of LA Highway 1 improvements, and if those tolls are lost, the state of Louisiana – as the other responsible party on the bonds - will have to pay to retire that debt, meaning loss of funding for some other programs in the state’s budget.

A 6-month halt in new drilling would defer 80,000 barrels/day, or 4% of 2011 deepwater Gulf of Mexico production. (Wood MacKenzie)

Higher drilling costs might jeopardize exploration in frontier areas. More immediately, estimates are that seven current discoveries could be rendered sub-economic, putting U.S. $7.6 billion in future government revenues at risk. Proposals to increase the cap on oil companies’ liability for oil spill damages to U.S. $10 billion could exclude U.S. independents from offshore Gulf of Mexico activities. (Wood MacKenzie)

Since these wells are not yet producing, there is no decrease in the available oil supply. However, it could lead to a decrease in the availability of domestic oil, and it is hard to tell how commodity speculators are going to respond over the next six months; there is the possibility for driving oil prices to levels well over $100 per barrel.

Prepared May 28, 2010, based on most recent data available; will be updated as needed.

What caused the Deepwater Horizon disaster?

2010-05-22T06:35:00.000-07:00

See the full post on The Oil Drum: http://www.theoildrum.com/node/6493#more

The blowout and oil spill on the Deepwater Horizon in the Gulf of Mexico was caused by a flawed well plan that did not include enough cement between the 7-inch production casing and the 9 7/8-inch protection casing. The presumed blowout preventer (BOP) failure is an important but secondary issue. Although the resulting oil spill has potentially grave environmental implications, recent efforts to limit the flow with an insertion tube have apparently been effective. Continuous efforts to slow or stop the flow include drilling two nearby relief wells that may intersect the MC 252 wellbore within 60-90 days.

A Guest Post by Perry A. Fischer: Are incentives to blame in the Macondo blowout?

2010-05-21T20:32:00.000-07:00

We now know, or at least we think we know, the causes of the BP Macondo blowout. Starting from the highest “top view” downward, the first cause may have been bonus incentive. “Better, faster, cheaper” has been the mantra of NASA for more than a decade. But “Two out of three ain’t bad” is not a good song. When one is incentivized to do things faster and cheaper in the corporate arena, it is automatically better, though not necessarily safer. When Shell executives were paid bonus for reserves additions, the result was bogus reserves and the resulting scandal and industry-wide write-down. Bonus is routinely paid for faster and cheaper across many industries. Could it have played a role in the case of the Macondo well disaster?

The revelation that the company used only 50 barrels of foamed cement (TudorPickeringHolt webcast) on the most critical part of the well is mind-boggling. Also, why they chose to use N2 foamed cement across a formation (that was known to contain a supercritical slush of mixed fluids whose behavior is difficult to predict) is a bit perplexing too. Perhaps it was to prevent the gas-cut cement that has been a problem on deep, high-pressure wells, but how would light, foamy cement do that?

But the 50 barrels number seems to be missing a zero, almost like it’s a typo, reminiscent of NASA’s infamous “Was that in meters or feet?” mistake that caused more than $200 million to crash into Mars. BP took foolish risks in the interest of time-saving that I cannot explain. You don’t even need your red Halliburton book to know that with 50 barrels, BP was planning to cement, at best, a short amount over the shoe of the previous casing string, just above the producing zone. This is even more perplexing given that the zone was known to have washouts. What was the thinking here?

As perplexing as the above decision-making was, BP decided not to run a Cement Bond Log (TudorPickeringHolt webcast). This might not be so bad on a straightforward infill well at modest depth and pressure, but this reservoir had already “eaten” one drill string on the first well, which had to be abandoned. There was a Schlumberger Unit and personnel on the rig. They were not utilized. I’ve run CBLs. Even a crummy, short CBL would probably have at shown bond quality and channeling (if present) and would certainly have shown the Top of Cement; in this case, with minimal cement, it would have been extremely important to know the location of the TOC.

Adding to the puzzle was the fact that there were indications that the wellbore was taking in gas. According to the log record (http://energycommerce.house.gov/Press_111/20100512/Halliburton-Last.Two.Hours.Chart.PDF) it appears that the SPP (the circulating pressure) starts to decrease at about 8 pm as part of the riser mud displacement. The displacement continues for about 45 min. From 8:00 to 8:08, the pump rate is steady, but SPP is gradually rising. Pumps are shut off for the next hour. SPP is increasing. At 9:14, pumps are started and shut off again at 9:18. SPP is significantly increasing. Pumps are re-started and from 9:20-9:30, the SPP is considerably higher than at previous flow rates. At least an hour before the blowout, the crew would have to know that they were dealing with a potentially dangerous situation. It appears that the crew may have had time to reroute the flow to the gas blow-by pipe, which can be seen on the photos, but wouldn‘t the BOP be closed, evacuation (or at least minimal personnel) on the drill floor and other necessary emergency measures be taken? Were they? The log is hard to explain. Something must have been done, but what was it, and why was it so inadequate? Was it because of the visiting top brass?

We also know that the BOP had a weak battery, causing one of its electrical modules to go down (the other one was functioning). Also, during a test, 15 feet of drill pipe was stripped through a BOP pipe ram, causing many chunks of the ram’s rubber to appear in the mud pit, and get fished out and presented to a Transocean supervisor (eyewitness, 60 Minutes interview). Yet the BOP was not pulled.

Finally, why was the riser displaced of its 14.5-lb mud BEFORE the top cement plug was installed--a reverse order operation? The answer is it made better use of the Waiting On Cement time, shortening the well-construction time. In fact, all of these bad decisions shorten the well-construction time and enhance any performance bonus that is paid. Else, they do not make basic well-construction sense in their own right.

We may never know the exact route that the gas took--it might not be very important in any case, give the appalling sequence of decisions (unless, of course, the BOPs are found to have parts from the top casing seals stuck in them). It could have come through the bottom plug, through some casing joint above that plug into the wellbore, or straight up the production casing annulus through a failed casing hanger seal assembly into the BOPs.

Oddly, MMS just made its new SCP (Sustained Casing Pressure) ruling final this month--a testament to just how ineffective MMS regulation can be. Thirty years ago, when we had about a hundred wells with SCP in the annuli, we knew we had a serious problem. So we did nothing meaningful in the way of cement or well construction, in order to save money, and over the next decade or so, the problem grew to “Houston, we have a problem” proportions of 1000 wells. Again, we rearranged the paperwork and asked MMS for more Casing Pressure Exemptions, which were usually granted. So the problem grew to 8,000 wells (a conservative MMS estimate).

Now, with the guidance and help of just two entities, BP and API, new regulations come into force that promise not to cost hardly anything, but do require new paperwork and, most importantly, require more monitoring of casing pressure annuli, and still allow a strung-out timeframe in which to act, if ever, including Casing Pressure Exemptions. The existing regs had already been weakened to allow for SCP of 20% of casing design. The new API RP90 that MMS adopted speaks only of SCF “management.“ In short, the new MMS regs ensure that there will be 12,000 wells with SCF problems, made worse as water depths and pressures increase.

One thing MMS was right about, SCP “…represent a clear hazard to the safety of personnel or the environment.” The BP well design and execution, if completed, would likely have been a future SCP problem--it just happened a lot sooner. If MMS did, as reported on some blogs, grant BP an exemption to the normal sequence of well construction on Macondo, it would not be a surprise--MMS overwhelmingly says “yes” to requests from oil companies (I don’t know the percentage, but I’ll bet it’s well over 90%. In the 50 or so MMS requests that I‘ve been privy to, all of them were granted).

According to the Wall Street Journal (http://www.rigzone.com/news/article.asp?a_id=92962), in the last 10 years, MMS enforcement cases that resulted in penalties were 66 in 2000 (a high point) to just 20 last year (it‘s lowest number). A report by the Interior Dept. Inspector General in 2000 found that MMS seldom referred safety or environmental violations to the Justice Department for criminal prosecution, even when it should have done so. Rig inspections all fell, according to agency data, to 760 in 2009, down from 1,292 in 2005. Increasingly, MMS has shifted toward a policy of industry self-regulation. The MMS in a 2005 rule change pointed to a older law that “encouraged federal agencies to ‘benefit from the expertise of the private sector’ by adopting industry standards, said the WSJ article.

All told, it seems difficult to find the common thread to the bad decisions of a minimal, foamy cement job, no CBL confirmation of placement, premature displacement of drilling mud, ignoring known problems with the BOP, and a willingness to disregard data and forge ahead, except that they all speak to hurry up and “get ’er done.” All of these were human errors, not mechanical ones. The real shame is that if even one of these decisions were made differently, this disaster probably would not have happened.

Nothing New in Obama Plan for Offshore Drilling

2010-04-20T03:35:00.000-07:00

In early April, the Obama Administration announced that it will expand offshore exploration and development to reduce dependence on foreign oil. The plan that was announced is, in fact, more restrictive than what was already in place, and will have no near- or mid-term impact on our need to import oil. It maintains the status quo by allowing leasing in the eastern Gulf of Mexico and offshore Virginia, and by allowing drilling in certain areas offshore Northern Alaska, but it closes the Bristol Bay area offshore southern Alaska. All areas in the Pacific Ocean off the coasts of California, Oregon and Washington remain closed.

The portion of the eastern Gulf of Mexico that is offered for leasing in the government’s plan is limited to areas more than 125 miles offshore that are mostly in water depths of 6,000 feet or greater (Figure 1). While the administration describes this as a development area, it is a high-risk, ultra deep-water wildcat province. Sixty-two wells were drilled in shallower areas of the eastern Gulf before the drilling moratorium, and the only prospective area found so far is the shallow-water Destin Dome region off the Alabama coast where reserves are estimated to be 2.7 trillion cubic feet of gas (equal to about 1.5 months of US natural gas consumption). The geology of the eastern Gulf of Mexico is different from the traditional producing area of the central and western Gulf. While it contains legitimate petroleum systems, it is a relatively high-cost, high-risk area.

The area of the Atlantic coast that is included in the government plan is offshore Virginia (Figure 2). The Atlantic margin of the U.S. was drilled and evaluated before the area was closed to exploration in the 1980s, and the results were dismal. More than 50 wells were drilled, and only a few wells in the Baltimore Canyon area off the coasts of New Jersey, Maryland and Virginia had any indications of petroleum. A few wells tested showed that natural gas could be produced at rates that would probably be commercial onshore today, but not 100 miles offshore.

In frontier areas like the Atlantic Margin and Eastern Gulf of Mexico, big fields are commonly discovered early in the exploration cycle because industry identifies and drills the largest, most obvious features first. The fact that approximately 50 largely unsuccessful wells have been drilled in each of these areas is discouraging. The Atlantic Margin seems to be an area where any hydrocarbons that are found will be natural gas rather than crude oil, based on geochemical analysis to date. While that is not a completely negative factor, further exploration there does little to change our dependence on foreign crude oil, and we currently have abundant supplies of onshore natural gas that can be found and developed at considerably lower cost.

On the positive side, the Atlantic Margin and eastern Gulf of Mexico are huge areas where important discoveries may have eluded early exploration efforts. Neither of these regions has been evaluated using modern seismic methods that could yield a different view of its potential for producing natural gas or oil.

As someone who works in the exploration and production business, I am in favor of opening these areas and letting industry decide if they have merit. At the same time, it is important to be objective. Under the most favorable scenario, it will take many years to acquire and interpret the necessary seismic and geochemical surveys that precede drilling. If discoveries are made, appraisal drilling, economic analysis, and development planning will require more time. Infrastructure adds yet another layer of time and complexity. Evaluation of large oil and gas projects worldwide commonly takes at least six years from discovery to first production. High-risk, capital intensive oil and gas exploration cannot be expected to produce quick results.

100 Years of Natural Gas Supply from Shale? It’s More Like 6 Years.

2010-02-27T03:50:00.000-08:00

The widespread belief that there is 100 years of natural gas supply in the U.S. because of shale plays is incorrect. The Potential Gas Committee (PGC) estimated 1,836 Tcf of technically recoverable gas resources for the U.S. in its report released in June 2009. Along with proved reserves of 238 Tcf, there are 2,074 Tcf or 85 years of total supply based on current demand of 25 Tcf per year (EIA). The contribution of shale gas is 661 Tcf, or about one-third
of the total, technically recoverable resource (Figure 1). The PGC estimate of probable resource volume is 441 Tcf, or about 18 years of supply. Shale gas accounts for one-third of that amount, or 147 Tcf, which is about 6 years of supply at current U.S. demand. That is a lot of gas, but far less than the volume that is routinely stated in the press or by shale-gas advocates. These public statements often do not take high decline rates or anticipated future demand growth into account.

2010-02-26T04:18:00.000-08:00

ExxonMobil’s Acquisition of XTO Energy: The Fallacy of the Manufacturing Model in Shale Plays

See the original full post on The Oil Drum:
http://www.theoildrum.com/node/6229

Posted by aeberman on February 22, 2010 - 8:26am
Topic: Geology/Exploration
Tags: exxonmobil, natural gas, original, shale gas, xto energy [list all tags]

Most analysts believe that the ExxonMobil acquisition of XTO Energy (XTO) represents a dramatic shift in strategy by the premier exploration and production (E&P) company, and a validation of shale plays. It is neither. The move represents a considered and deliberate choice that acknowledges diminished opportunities for the oil giant to add and replace reserves. The acquisition acknowledges that natural gas is the only viable short-term solution to North America’s energy needs, and that demand will grow. It implies that ExxonMobil believes that higher natural gas prices will be part of that energy future. It presumes that the company can improve on the flawed manufacturing model that has dominated the way that U.S. shale plays have been pursued.

ExxonMobil’s acquisition of XTO only seems dramatic to those who have not paid attention to the company’s strategy and change in project mix over the past decade. Its portfolio consisted of 75% unconventional resources before the XTO acquisition (Figure 1) with a strong emphasis on tight, acid and sour gas, LNG, and heavy oil projects. Tim Cejka, President of ExxonMobil Exploration Company, told The Wall Street Journal last year that his company has been “bullish” on shale plays since 2003 (Wall Street Journal, July 13, 2009). David Rosenthal, ExxonMobil Vice President of Investor Relations recently said, “It’s not a strategic shift” (Houston Chronicle, February 2, 2010).

See the rest of the original full post on The Oil Drum:
http://www.theoildrum.com/node/6229

Implications of Exxon Mobil acquisition of XTO Energy Presentation February 2010

2010-02-26T04:07:00.001-08:00

Check out this SlideShare Presentation:

Implications of Exxon Mobil acquisition of XTO Energy Presentation February 2010

View more presentations from aeberman.

McMoran Davy Jones Gas Discovery

2010-01-18T03:33:00.000-08:00

Arthur E. Berman and Joshua H. Rosenfeld

McMoran Exploration Company has made a significant discovery in the U.S. Gulf of Mexico that may contain 2-6 trillion cubic feet (Tcf) of natural gas reserves. The well was drilled in 20 ft of water 10 miles south of the Louisiana coast on South Timbalier Block 168 (Figure 1). The discovery by McMoran (operator) and partners Plains Exploration & Production Company and Nippon Oil Corporation is very deep (28,125 to 28,262 feet drilling depth) but with excellent quality gas-saturated reservoir rock in the upper Wilcox Sandstone (Paleocene-Eocene--135 ft of gas pay with as much as 20% porosity and 10-20 ohm-meters of resistivity).

The Davy Jones well was drilled on a large anticlinal feature with approximately 20, 000 acres of structural closure at Wilcox level (Figure 2). McMoran intends to continue drilling another thousand feet or so in order to evaluate the next two potential reservoir strata known as the lower Wilcox “Whopper Sand” and the Cretaceous Tuscaloosa Sandstone (Figure 3). The Tuscaloosa is a prolific producing reservoir onshore.

The discovery is especially important because it provides a link between onshore Wilcox production and a series of discoveries from equivalent strata in the deep-water Gulf of Mexico including the Tiber Field announced by BP in September 2009. In 2001, the announcement of a Wilcox discovery in Unocal’s deepwater Trident-1 (Perdido) well came as a complete surprise to most of the industry. Since then, these reservoir sands have been found in a 300-mile long and 50-mile wide fairway parallel to the present-day shelf margin beneath 5,000 to 10,000 feet of water, containing more than 20 fields. The stratigraphy of the undrilled gap between the onshore and the deepwater Wilcox under the coastal plain and continental shelf of Texas and Louisiana, however, has remained conjectural. This “down dip” Wilcox play has been ignored by drillers until McMoran’s test because structural complexity and deep targets involve high risk, expensive exploration.

Recent discoveries of oil and gas in the deep-water offshore region of the Gulf of Mexico may have recoverable resources of up to 15 billion barrels of oil equivalent. Reservoirs consist of Paleocene to Eocene submarine fan and turbidite sandstones whose thickness exceeds 1000 feet. This sequence has been correlated with the onshore Wilcox Group. The considerable thickness, and wide areal extent of the deep-water offshore Wilcox interval challenges the common perception that most sandstone in the Wilcox was deposited within shelf and upper continental slope environments with only thin, channelized sands reaching the deep basin within shale-dominated turbidites.

For the last decade, curious geologists have struggled to explain the counter-intuitive presence of hundreds of feet of massive Wilcox sand across a wide swath of the Gulf of Mexico so far from the contemporaneous shoreline, and whether this sand trend is continuous from the onshore into the deepwater (Berman and Rosenfeld, World Oil, June, 2007). Conjecture also swirls around whether the Wilcox extends southward and underlies Mexico’s deepwater and shelves.

The news from the Davy Jones well appears to open an important new gas play in the Gulf of Mexico. McMoran’s findings will undoubtedly encourage more deep drilling for Wilcox targets in this trend. Meanwhile, the next 1,000 feet in the Davy Jones well may yet reveal the highest quality reservoir sands that correlate with the basal Wilcox “Whopper Sands” in the deepwater.

Some analysts have said that this discovery proves that concerns about peak oil and gas are unfounded. This is common whenever important discoveries are announced. It is, therefore, worthwhile to place the Davy Jones discovery in the context of broader petroleum supply, demand, cost and timing factors. While 2 Tcf is a lot of gas, it is about equal to one month of U.S. consumption during peak winter months, and we currently have an over-supply of natural gas that may persist for some time.

It is worth mentioning that the announced discovery is based on sketchy information from well logs and is does not represent an actual flow test. The reason for this incomplete data is the extreme depth, pressure and temperature of the Wilcox reservoir in this well.

Bottom-hole pressures may be as high as 25,000 pounds per square inch, by far the highest pressures known in Gulf of Mexico wells, and almost 10 times the rocket engine chamber pressure required for spacecraft liftoff. While not specifically mentioned, reservoir temperature is probably considerably more than 400 degrees Fahrenheit. Gas has never been produced at these temperatures and pressures, and may be present engineering obstacles. In addition, gas reserve volumes will shrink at surface conditions. There is also a possibility that the gas will contain carbon dioxide, which will reduce the volume of commercial gas and present a disposal problem.

The Davy Jones well has cost almost $200 million so far, and development drilling is expected to cost $1.5-2.0 billion. Production facilities will add to that cost. There are few rigs in the world that are capable of drilling at these depths and temperatures, so Davy Jones will have to stand in line with all of the deep-water Wilcox discoveries in the Gulf of Mexico and the pre-salt fields in Brazil’s Santos Basin for rig availability. The earliest estimates for first production are in 2013.

At the same time, the apparent discovery opens a new trend in the Gulf of Mexico that could contain considerable new reserves. The Davy Jones discovery announcement comes at a time when few oil and gas companies are pursuing objectives other than shale plays. Fortunately, there are wildcatters that are willing to pursue these high-risk, high-reward plays, this time with apparent success. Stay tuned because this is a promising development.

The Data That We Cannot Get

2009-11-24T20:29:00.000-08:00

I would like to clarify what I mean about operators not showing their data.

Anonymous says that there is no data to show because we only disagree about how to project existing data. That is partly true, but some of the rebuttals to our work dispute the reliability of Texas Railroad Commission production data for the Barnett Shale play. They claim that they have "other data" that somehow leads them to different conclusions, but will not show it.

That's a really interesting tactic that I remember from the elementary school playground as "I know something you don't know".

I think that questioning Railroad Commission data is a red herring since production taxes and royalty payments are based on what operators report to the Commission. Those who claim that this data is no good imply that operators are improperly reporting production to the state. I would very much like people that doubt the reliability of Railroad Commission data take this issue to one of the Commissioners.

Beyond the "data" issue is the larger question of how the operators and financial advisory companies arrive at such high reserves. I can reproduce these high reserves by using absurd hyperbolic exponent b values, no terminal decline rate, or no economic limit.

When I use group vs. individual well-decline methods and b factors somewhat greater than 1.0, I can get to higher average EURs (more detail on this in a few days) than what I have published, though these reserves are still marginally commercial. Since I assume the integrity of the people who claim reserves that are 50-100% more than my most generous projections, I would like to understand how they reach those reserves.

In addition, we have always cautioned that without pressure data that only operators have, we may be too pessimistic in our EUR projections. Decline-curve analysis is only a part of the EUR evaluation process. Other factors include calculating a drainage area and running reservoir simulations to match production history with reservoir properties. These require data that we cannot get.

Operators are not required to report water production to the state of Texas. Water disposal can be a considerable cost, and the onset of water production may result in catastrophic production rate decline. This is data that we cannot get.

Some readers point out the current decline rates are much lower that we predict in some cases. This may be true because of the frequent workovers and re-fracs done in the out years of many shale years. In order to evaluate the result of lower decline rates due to human intervention, we need to know the cost. This is data that we cannot get.

Some operators claim that natural gas liquids provide uplift to their Barnett Shale economics. NGLs are not reported to the state because they are separated during gas treatment and processing in a plant. Only operators know the volume of NGLs and the gas shrinkage that results from their extraction. This is data that we cannot get.

While it is true that much of the EUR debate focuses on how to project future production from exiting data, it is hardly the entire story. A respectable EUR does not necessarily mean that the well is commercial.

From Perry Fischer, former World Oil Editor

2009-11-06T12:42:00.000-08:00

November 5th, 2009

When I got up this morning, I decided not to pack my usual snack lunch--I thought that it would be my last day. I was right--I was fired.

On Oct 22, I received two emails forwarded to me via the World Oil Circulation Department. They were from DS and KR at two Houston oil and gas companies, and they both said that they were canceling their free subscriptions due to Art Berman's columns on shale plays. DS went further by faxing and then phoning to the president his feelings about Art Berman.

Let me be clear: The decision to pull Art's column was due to pressure from these two companies.

The next day, the president stopped by to tell me that we had to stop Art from writing about shale plays.

I said, "I'm surprised that there haven't been at least a dozen complaints. I've seen worse on other topics."

It was no use arguing. Ironically, I had already decided that Art should take a break from the shale plays for a while anyway, just because he was running out of new things to say, having written 8 (I'm guessing) columns on that one subject.

It was the 23rd of October and we usually have all of the columns in by the 15th of the month, but we have been so understaffed--just myself and 1.5 other people (we share one)--that we are now often late. So I called Art to see where he was at on his column. I quickly realized that Art's mind, and some of the work, were already committed. He felt that he owed it to his readers to comment on some of the recent rebuttals to his positioins on shale plays, so I decided that we'd go ahead and print what he had for the November issue.

Again ironically, Art agreed that going forward he was going to take a break from the shale topic, mostly because as he put it, "I'm not sure what more I can say."

Immediately after I hung up the phone with Art, the Publisher walked in, slapped down a fax from DS, and said, "We've got to stop Art from writing about these shale plays, we're getting too many complaints!"

I replied that I was aware of the complaints and said that the president was just in to discuss it, but that it was too late in the cycle to stop the November column but, in December, we would take "a little break." He said "Fine."

Normally, the magazine would be going out the door by then, but insufficient staff in both Editorial and Production departments caused further unforeseen delays. On Nov. 2, the magazine had been shipped, the "bluelines" were back (proof sheets), and they were about to go to press; we were minutes from being done done, when the Publisher walked in and said we had to pull Art's column.

I said, "I can't, I won’t; it’s finished, plus, we agreed that we'd leave November alone."

He said that it wasn't his decision, and that I was welcome to talk it over with the President, which I did. That conversation went nowhere. In his mind, there had been too many complaints (2), including 2 phone calls, and the column had to be pulled.

After three protests, including the fact that it would delay printing, I finally said, "This is a really bad decision, the best thing that you could do is nothing; there is no compelling reason to pull this; just let it go to press; the idea that we can please all of the people all of the time is impossible, unless we are careful to say nothing, print pabulum."

Obviously, I lost that battle. The last thing that I wanted to do Monday night (along with the Production Department person) was to write a quick column to replace Art's in two and-a-half hours; it was a step down in quality from his, and betrayed an incredibly thin skin on the part of World Oil management. I certainly would never have pulled it. A spineless Editor isn't an Editor at all.

It's important to know that Art left voluntarily. The decision was his alone. In my opinion, he was pissed. But then, if I worked my ass off on a good column, asked my friends for their counsel, opinion, and proofing, had the editor question a graph and ended up changing it, and then had it pulled and just set aside for the crummiest of reasons... well, I'd be pissed off too. If Art had stayed, he would have been under a magnifying glass. It's like breaking a pencil in half and then trying to put it back together.

I got through the night, emailed/talked to Art, and took two days of vacation. A minor brouhaha ensued on this blog and elsewhere and, when I returned, I was fired. I wasn't told why. Neither was I surprised.

In my 11 years at World Oil, I tried to take the "trade" out of "trade journal." The current management is trying to put it back in. Increasingly, decisions are being made for the sake of advertising. Unfortunately, the last vestige of “the separation of church and state,” meaning, between corporate and editorial, is gone. The marketing folks have won. Dilettantes’ meddling in day-to-day operations is now the norm.

I dare say that the last President, RM, who was summarily fired in April without explanation (so that's how he felt!), would have handled the situation much more deftly. (By the way, when you fire a president, aren't you supposed to trade up? I'd bet that not one employee feels that that is the case). But RM was old school (probably why he was fired). And so am I. My field experience and physics background will probably make me the last editor of World Oil with a technical background; part of a line of technically qualified Editors going back decades.

World Oil Editor Fired Over Shale Columns

2009-11-05T13:24:00.000-08:00

World Oil Editor Perry Fischer was fired today by John Royall. While no reason was given, it is clear that this was related to his role in allowing me to publish a different view of the shale plays. Perry did a lot to elevate World Oil above the level of a trade magazine since joining the staff in 1998.

It is particularly unfortunate to see this behavior from the management of an old and respected publication like World Oil (it was first published in 1916).

As John Dizard recently wrote in the Financial Times about shale plays, "...along with the technology you can also thank the advanced American ability to extract money from investors. The key element of this national characteristic is the willingness to listen carefully to determine what people with money want to hear, and then tell them that. Again and again."

I wish Perry all the best in his job search.

A Call from John Royall

2009-11-04T15:09:00.000-08:00

I got a call today from John Royall, President and CEO of Gulf Publishing, the company that owns World Oil magazine.

John told me that I "need to get my facts straight". He claims that he did not cancel my November column as I was told. Rather, he said, he, Editor Perry Fischer, and Publisher Ron Higgins agreed three weeks ago that I would write no more shale articles. He also claims that there was no pressure from Petrohawk.

I offered to post his comments on my blog, and now I have.

I have never been an employee of World Oil, and have never spoken to John Royall before today. I find it wholly inconsistent with my three-year history with Perry Fischer that he would keep a decision on what I should or should not write from me. My work relationship with the magazine has been contingent from the beginning on my right to choose content. When the magazine broke its commitment to our agreement, I decided not to write for it anymore.

Another bit of interesting information: when Houston Chronicle energy reporter Tom Fowler asked Petrohawk's Investor Relations VP Joan Dunlap about the alleged pressure from her company she said:

"It is doubtful that his termination was a direct result of comments made by Petrohawk. We suspect it was more likely a result of Berman's history of inconsistent data gathering and poorly supported opinions."

If there had been no pressure, why wouldn't she just say that?

I leave it to my readers to decipher the truth.

Pressure from Petrohawk helps cancell World Oil column

2009-11-02T20:22:00.000-08:00

In an act of extraordinary courage, a top Petrohawk executive threatened to cancel his free subscription to World Oil if the magazine continued to publish my column. Today, John Royall, President and CEO for Gulf Publishing, cancelled my November column.

I have accordingly resigned as contributing editor.

I greatly enjoyed the nearly three years that I have written for World Oil. I especially appreciated working with Editor Perry Fischer who never questioned the content that I chose for my columns, and always emphasized accuracy and intellectual honesty. I know that he got a lot of pressure because of my position on shale plays but never wavered in his support. Thanks, Perry.

Thanks also to my many readers for their interest, willingness to write and call, and to both challenge and support. Special thanks to Lynn Pittinger for his incredibly valuable collaboration during the past few months.

Shale gas numbers may not add up by John Dizard

2009-11-02T03:58:00.000-08:00

There is an interesting article on shale gas plays by John Dizard in the November 1, 2009 Financial Times:

http://www.ft.com/cms/s/0/b4240cf4-c585-11de-9b3b-00144feab49a.html

Facts are stubborn things

2009-10-25T14:17:00.000-07:00

Several rebuttals to our position that shale gas reserves may be overstated have surfaced in recent weeks. This development is welcomed and positive because it elevates the important discussion of shale reserves and economics to a higher level of public awareness and dialogue. Although these rebuttals have been directed at me, I am not the only one with doubts. Ben Dell at Bernstein Research has published several reports recently that express similar, independently determined concerns about the cost, efficiency and reserves of shale plays. These doubts are shared among many petroleum industry scientists and financial analysts despite the enthusiasm for these plays by large public companies.

Critics of our position on shale gas plays have focused on methods of decline-curve analysis, and the projections of estimated ultimate recovery (EUR) that result. The problem with this debate from all sides is that we are uncertain about how to apply decline models to newer shale plays because there is insufficient production history to satisfy all of our questions. I will, therefore, focus on some stubborn facts about Barnett Shale cumulative production and approaches to play development.

(Click figures to enlarge)

Major operators claim that their average Barnett EUR will reach 2.2-3.3 Bcf/well. Figure 1 shows that those levels of EUR are unlikely to occur in an economically meaningful time frame based on cumulative production to date. Figure 2 shows that well performance has been erratic since operators began drilling horizontal wells, though the trend has been improving in recent years. This is probably due to drilling in areas outside of what are now known to be the core areas. The manufacturing paradigm that is prevalent in shale plays has lead many companies to assume that all areas in the Barnett Shale and other plays are uniformly attractive. Shale plays typically begin with a leasing frenzy whereby major players accumulate hundreds of thousands of acres, often at astronomical bonus prices. Next, a drilling frenzy ensues driven more by lease expiration schedules than by science. Only after considerable capital has been destroyed in this manner are the core areas recognized. This “Braille method” is completely opposite to the customary approach to E&P projects, where a cautious approach based on science is used to high-grade focus areas.

The methods used to obtain decline rates and reserve estimates for shale plays presented in this column employ best practices in the petroleum industry. Yet a group of professionals believe that some shale plays are exceptions to the methods of decline-curve analysis established by the Society of Petroleum Engineers (SPE). They should take this dispute to the SPE. It does not seem logical that type-curve methods should be more reliable than individual well decline-curve analysis. If the pattern of well decline is empirically exponential, it makes no sense that it should be treated as hyperbolic for conceptual reasons or because of a preference based on production from tight gas sand reservoirs that are not comparable in performance to shale gas reservoirs. We recognize that it may take many years before true steady-state flow is reached. But in the Barnett, decline trends are well developed in thousands of wells, and we must forecast reserves based on those trends, and not on some future, model-driven expectation of flattening decline rates.

Let me be clear. We do not dispute the volume of gas resources claimed by operators. We do question the reserves that, by definition, must be commercial on a full-cycle economic basis.

The time has come for the companies that operate in the shale plays to show the data that supports their optimistic forecasts for natural gas supply in the U.S. The economic viability of shale gas is a serious issue with profound implications for policy, alternate energy research funding, and national security. To simply say that those that have doubts about shale plays are wrong will no longer satisfy the many intelligent people who follow this debate.

Data provided courtesy of IHS Inc. However, the analysis and opinions expressed here are solely those of the authors and do not represent those of IHS or any other organization.

Rebuttals To Our Shale Play Research

2009-10-20T20:46:00.001-07:00

Tudor, Pickering and Holt's rebuttal to Lynn Pittinger's and my work is not publicly available and is provided only to subscribers to their investment services. Below, however, is a transcription of their retort. I have also provided the articles by Devon and Chesapeake, coincidentally published on the same day as TPH's report, in Oklahoma City news publications (where their headquarters are located).

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Putting the Skeptics shale hypothesis to permanent rest ($4.50/mcf) TPH E&P Research Team

Tudor, Pickering and Holt
October 19, 2009

Taking the high road – After much internal debate, we have opted to take the high road and not call out these shale skeptics by name. While it would make us feel better, it would probably give more credibility and attention to some individuals than is warranted.

The calm before the storm. First, let us say that this is not a personal attack on these skeptics. We’ve met them. They seem like nice folks. While we believe their analysis is incorrect in almost every way, we do believe that they are sincere in their efforts. With those niceties out of the way, let’s put our cards on the table. We were willing to let sleeping dogs lie in our disagreement with their conclusions. The world is made up of differing opinions and the beauty is that the market is efficient in sorting them out (for example, it was pretty quiet in February from the $200/bbl oil crowd). However, we simply get too many questions about these skeptic’s work to ignore it…particularly since a recent Denver presentation questioned our own work on the topic. Two can play this game..and we say GAME ON!

Technical credentials. In any technical discussion, one must establish technical credibility. The TPH equity research team is staffed with engineers that have worked at Shell, Tenneco, Arco, Exxon Mobil, reservoir consultant Holditch & Associates and reserve auditor Netherland & Sewell. Dave Pursell has taught petroleum engineering courses at Texas A&M. Not only do our guys know words like non-linear flow and pseudo-steady-state..they actually understand what they mean. We’ve done decline curve work for 10-20 years. Our A&D team on the ibanking side has another group of engineering talent just like us – and they make technical assessments of reserves for a living. We know how to do this type of work.

Depth of analysis on this topic. Within the past six months, we’ve looked at 32 subsegments of US production, including individual analyses of various historical shale results (Barnett, Fayetteville, etc). The culmination of the analysis was our US Natural Gas Supply Study. We’ve got data coming out of our ears…we haven’t published it all (and won’t), but it confirms the technical work being done by literally hundreds of industry folks.

10 Reasons Why Skeptics Are Wrong:

1. Technical stuff matters – The skeptics claim Estimated Ultimate Recovery (EUR) in shales is much lower than stated by industry, analysts and reserve engineers. This is because their decline method is technically flawed and is biased to under-estimate recovery. They suggest that it is appropriate to assume Barnett Shale wells exhibit exponential decline after one year (and not apparent hyperbolic behavior). Reality – it takes many years for a very tight (low permeability) gas reservoirs to exhibit exponential decline behavior. Thus, hyperbolic decline can and should be used to approximate/extrapolate EUR’s. Whew – got through that explanation without a mind numbing discourse of transient vs. pseudo-steady-state flow.

2. Type Curves work – Skeptics further suggest that it is inappropriate to use type curves because it makes the data look smoother than it really is…and suggest that all wells should be analyzed individually. This is wrong for multiple reasons: (1) It is accurate/widely accepted to use normalized curves as long as there is a relatively stable well count and vintage/area effects are accounted for. (2) Projecting individual wells without checking the type curve trends will lead to overly pessimistic projections (see Reason #4). Type curves actually normalize for a negative bias that might be driven by individual well declines. (3) Reserve auditors project EUR’s on a by-well base…supplemented with type curves. Their by-well analysis is consistent with the type curve methods reported by companies. The answer is generally the same either way if the work is done correctly!

3. High Terminal Decline Rate is wrong – Skeptics state that terminal declines will be high in shale plays (>15%). Without 10-20 years of Barnett history (the oldest shale play), this cannot be disproved. However, there are literally thousands of data points (actual well production) that show low terminal decline rates in tight gas reservoirs. Read the technical papers. Look at the data. Enough said.

4. Reality bites - We loaded the skeptics Barnett ~1bcf EUR type curve (which are called optimistic) into our Barnett Shale model. We applied their type curve to the ~3,000 wells drilled in 2008. During 2008, actual Barnett production grew by 1.2bcf.day. The skeptics “optimistic” EUR curve estimated growth of only 0.7bcf.day – which says it underpredicted actual incremental production by 0.5bcf/day or 70%. This is only for one year. If we went back to 2005/2006 and applied the type curve to all Barnett wells drilled, there is NO WAY this low type curve would match actual Barnett production of 5bcf/d. Scoreboard!

5. Like a fine wine, wells can get better over time – Skeptics also indicate that Barnett well performance has not improved over time. Au contraire, mon frère! In the Barnett and Fayetteville, reported well production shows higher y/y rates and higher projected EURs due to improved technology and better understanding of the reservoir (its called a learning curve). The skeptics decline-curve methodology (assuming the wells exhibit exponential behavior after one year) biases newer wells to have lower EUR’s than older/mature wells. Industry has shown consistent positive performance-based revisions in shale plays…wells get better and reserves increase over time.

6. Peak rate IS a good indicator of EUR – Skeptics are incorrect in stating that there is no correlation between peak rate and EUR because his decline curves/EUR’s are wrong. Clearly, peak rates alone shouldn’t be used to forecast EURs, but we find on average a strong correlation between IP and EUR (a widely accepted premise in tight gas analysis). Read the technical papers. Look at the data. Enough said again.

7. Economic new math – Skeptics also believe that the Barnett/Fayetteville will recover less gas than people think (and by extrapolation, other shales like the Haynesville will also disappoint). With less gas from shales, the marginal costs of supply will be high – some skeptics say as high as $8/mcf. We agree that if shale disappoints, gas prices will be quite high. Yet some skeptics run economic analysis of shales at $4/mcf gas prices..to prove that the Barnett is uneconomic. Circular logic here (queue Vince Vaughn in Wedding Crashers – Erroneous! Erroneous!). If recovery is low and prices are therefore high..you MUST use the higher price when evaluating shale economics.

8. Data Quality? Skeptics rely on Barnett monthly data reported to the Texas RRC. Because of the high amount of downtime in the Barnett due to completing offsetting wells, high line pressures, and other issues early in production, monthly data biases lower estimates of recovery. For these periods, the Texas RRC reports look artificially low because they reflect only partial months of production. The daily production data shows a much different story…CHK’s Analyst Day presentation shows this clearly.

9. Collusion? No. You, sir, are simply wrong – Skeptics discuss a conspiratorial angle and incorrectly suggests there is collusion between E&P companies, Wall Street analysts and engineering companies: “E&P companies that claim success, investment companies that promote their stock and activities, and engineering companies that certify assets must be held accountable for their conclusions…” We’re plenty happy to be held accountable for our conclusions..we publish them daily. The skeptics conspiracy angle is categorically wrong. The truth is much less sensational. Simply, many people representing hundreds of companies analyze the data and come to a different conclusion. It is laughable to think that: A) thousands of people are conspiring to make the Barnett/Fayetteville seem better than it is or B) all of these people are just incompetent.

10. Don’t go away mad…just go away – One skeptic stated that “Lack of material response either means they do not take my position seriously, or they do not contest it”. A Chihuahua can only bark at a bull dog for so long before the bull dog snaps back. And the dogs are snapping. Look at the BILLIONS of dollars being invested in shale activity. The industry is responding with its actions every single day. We are responding with this report. NO MAS!
_______________________________________

Shale speculation off base
POINT OF VIEW: MISINFORMATION CLOUDS NATURAL GAS GAINS

BY DAVID A. HAGER
Published: October 19, 2009
NewsOK.com

At a time when we are seeking solutions to our long-term energy questions, it is too bad that progress can be clouded by misinformation.

"Gas shale’s future is uncertain” (Associated Press business story, Oct. 13) cast
inexplicable doubt on a new resource that has changed the landscape of our energy future.

Geological consultant Arthur Berman has been making a name for himself recently by writing columns and giving speeches that question the long-term viability of shale as a source of natural gas.

There is nothing new about shale. It is a type of rock that energy companies have been drilling into and around for decades. We knew how natural gas and oil can emanate from shale, but until recently we did not know how to produce energy from the dense, tight formations themselves.

By unlocking the shale, we have opened vast new natural gas supplies that were beyond our reach a decade ago. This would be exciting news at any time, but at a time in history when we are worried about energy independence and clean energy, this new development is better than a ninth-inning homer to win the Series. Meanwhile, Berman is in the stands speculating on whether the slugger is on steroids.

Questions are an important part of the scientific process. But Berman slings doubt with a broad brush. Speaking last week to the Association for the Study of Peak Oil and Gas, he called shale natural gas the nation’s next speculative bubble likely to burst. He compared optimism surrounding shale to banks buying into mortgage-backed securities.

I guess it is true that every paradigm shift has its doubters. After all, there were people who downplayed Thomas Edison and his incandescent light bulb.
The fact is that shale is a proven success story. The Barnett Shale, which Berman targets with his skepticism, has grown from almost nothing 10 years ago to the largest producing gas field in the United States. Today, the Barnett’s annual production is enough to heat 20 million homes for a year.

The shale story doesn’t stop at the Barnett. Devon and many other energy companies across North America are applying what we have learned in the north Texas field to other shale fields. The industry is investing billions to develop natural gas production other shale fields. The industry is investing billions to develop natural gas production from untapped shale formations in Louisiana, Texas, Oklahoma, Pennsylvania, New
York, British Columbia and elsewhere.

Because of shale, natural gas production in the United States has been on the increase in recent years, reversing a prolonged trend downward. And, these wells are expected to produce for 40 or 50 years. Meanwhile, the country’s natural gas inventory is growing. The Colorado-based Potential Gas Committee estimates reserves are up 35 percent over 2006 estimates,
largely because of new access to shale natural gas. Estimates suggest the United States has nearly 2,000 trillion cubic feet of natural gas reserves, enough to last more than a century.

To borrow from Mr. Berman’s terminology, that is a mighty big bubble.

Hager is executive vice president of exploration and development for Devon Energy.

________________________________________________

BY JAY F. MARKS
Published: October 15, 2009
NewsOK.com

Chesapeake Energy Corp. officials are optimistic about the future, with a stable of
"legacy assets” they expect will provide revenue for years to come.

Officials touted Chesapeake’s strengths Wednesday in New York at a conference for
investors and analysts that was broadcast live via the company’s Web site. They pointed out Chesapeake is the most active driller in the United States, with substantial lease holdings in the most lucrative shale gas plays.

"We do feel like we have the No. 1 resource base in the nation,” said Steve Dixon,
Chesapeake’s chief operating officer.

Dixon said Chesapeake’s shale holdings will continue producing for years to come,
despite "misguided” predictions from an analyst at an industry conference in Denver
earlier this week.

"We’re very confident that these types of rocks will continue to bleed gas for decades
and decades,” he said.

Jeff Fisher, the company’s senior vice president of production, said the unique size of Chesapeake’s assets will allow the company to develop new technology to maximize production.

"We’ve achieved great results to date, and we’re just getting started,” Fisher said.

Chesapeake detailed its holdings in the nation’s two largest shale plays: more than
500,000 acres in the Haynesville shale in Louisiana and Texas and 1.45 million acres in the Marcellus shale in West Virginia, Pennsylvania and New York. The company produces an average of 210 million cubic feet equivalent per day of natural gas in the Haynesville shale, a "world class” asset Chesapeake discovered in 2007.

"We’re just scratching the surface on the production side,” geoscience manager John
Sharp said of the Haynesville operation, which is being supplemented by additional
plays in Louisiana.

Chesapeake is the most active driller in the Marcellus shale, a massive play close to the best gas markets in the northeast. Tom Layman, the company’s vice president of geoscience for the eastern division, said Chesapeake is determined to make its efforts count in that area.

"We are gathering data and learning about the play like no other company,” he said.

Marc Rowland, Chesapeake’s chief financial officer, said Wednesday’s technical
presentations were meant to show analysts the value embedded in the company’s
assets. Officials project Chesapeake will produce 5 trillion cubic feet equivalent a year for the next several years, while finding an additional 3 trillion cubic feet equivalent each year, Rowland said.

CEO Aubrey McClendon said he expects gas production to decline, but he is optimistic prices will continue to rise, which will lead to an increase in drilling and production.

"We think all of the elements are in place for gas prices to be higher in 2010 than they are today,” McClendon said.

He also said gas prices could be affected by increased demand from China, much the same as other commodities. McClendon said he and other natural gas company executives are working to increase demand, focusing on making inroads into transportation and power production, which is reliant on coal and transportation.

He borrowed a line from fellow gas advocate T. Boone Pickens to sum up his thoughts on the issue. "If you’re not for this ... you are for foreign oil,” McClendon said. "That’s one of Boone’s best lines, I think.”

He said transportation seems like an easy place to increase natural gas use.
"There is no alternative for trucks because you can’t move an 18-wheeler by battery,” McClendon said.

He also said he expects the market for liquefied natural gas to continue to grow because it is cheaper and more environmentally friendly than other alternatives.

The Empire Strikes Back

2009-10-19T20:53:00.000-07:00

Today, Chespeake, Devon, and Tudor, Pickering and Holt published objections to Lynn Pittinger's and my articles on the Barnett and other shale plays. I choose not to respond at this time since there is little substance in these commentaries.

The only response that is appropriate at this time is contained in the accompanying graphs of cumulative Barnett Shale production. These are not interpretations but ha rd data. I leave it to our critics to explain why production trends cannot be extrapolated to the levels claimed by operators (click images to enlarge).

A Haynesville Shale Symposium

2009-10-04T16:34:00.000-07:00

Arthur E. Berman and Lynn Pittinger
Reprinted with permission from World Oil, October 2009 issue

Presentations at the GCAGS (Gulf Coast Association of Geological Societies) Haynesville Shale Symposium underscored the great uncertainty about reservoir performance and resulting economic aspects about the play. While operators claim early success based on IP (Initial Production) rates and the impressive cumulative production of a few wells, my coauthor, Lynn Pittinger, and I are concerned about the extremely high decline rates and the lack of evidence for hyperbolic flattening seen for most wells.

Ductility of the reservoir and its subsequent compaction as pressure is reduced suggest that ultimate recoveries may be sub-commercial. Formation damage from the loss of millions of gallons of treatment water to the reservoir is another concern.

“Haynesville Shale and Other Shale Plays—a Symposium” was the opening technical session of the GCAGS Annual Meeting in Shreveport, Louisiana on September 27, 2009. There were many outstanding presentations at the all-day session, a few samples of which follow.

Dan Buller, Principal Petrophysicist for Halliburton’s Southeast Technology Team, explained that the Haynesville is a “soft” shale with low Young’s Modulus and Poisson’s Ratio. Because of this, cross-linked gel fracture stimulations are twice as effective as slick-water stimulations. Subtle increases in shale brittleness due to higher calcite composition are important when choosing zones to perforate and stimulate. Formation damage during stimulation treatment is also a factor in reservoir performance. Fracture stimulations can use as much as 3 to 10 million gallons of water, but only 30% of the fluid is typically recovered.

Li Fan, Chief Reservoir Engineer with Schlumberger Consulting Services, showed simulations that determine critical performance factors in the Haynesville. An abnormally high-pressure gradient (0.7-0.9 psi/ft) distinguishes the Haynesville from other shale plays. It may also explain the extremely high decline rates, as pressure depletion transfers stress to the rock and allows proppant-filled and open fractures to compress, thereby reducing the effective reservoir permeability.

In preparation for my presentation at the meeting, Lynn and I updated our reserve forecasts for the Haynesville Shale. EUR projections were made for 67 wells based on standard rate versus time decline-curve analysis. Major challenges include the limited production history and lack of access to producing pressures. We recognize that our reserve estimates may be somewhat pessimistic because the average decline curve consisted of only seven months of data. Without pressure data, we do not know if for some wells decreasing flow rates represent depletion or flow against high production system pressures.

We forecast a sub-commercial average EUR for the Haynesville Shale because of the extreme rates of production decline. Most wells with an IP of more than 10 MMcfd have a decline rate of 25% per month. The average EUR in our study is 1.72 Bcf/well, compared to the 6.5-7.5 Bcf/well reported by many operators. Only two wells of the 67 evaluated have an EUR greater than 6.0 Bcf. At the same time, seven wells have already produced more than 2 Bcf and one has exceeded 4 Bcf.

Petrohawk has the best well performance with an average EUR of 3.4 Bcf/ well (19 wells evaluated). Chesapeake has the most wells on production (29 wells evaluated) but we project an average EUR of only 1.2 Bcf/well. In our study, one-half of the wells followed an exponential decline trend with little-to-no subsequent flattening. The remaining wells had a low-to-moderate flattening trend modeled by hyperbolic decline. Only wells with the lowest IP rates and EUR predictions followed a hyperbolic decline rate similar to those published by major operators in the play.

Values of the hyperbolic exponent b in our sample set ranged 0.1-0.7 with an average value of 0.26. This is consistent with our findings in the more mature Barnett and Fayetteville Shale plays, but is much less than what is found in operator type decline-curves, where values approaching 1.0 or greater are typical.

The amount of hyperbolic flattening assumed in reserve estimates deserves special attention. A production profile with a 10 MMcfd IP and 25%/month decline in the first six months, and a hyperbolic b exponent of 0.5 reaches an economic limit of 2,000 Mcf/month in six years, yielding an EUR of 2.1 Bcf. The same initial decline rate modeled with a sub-sequent hyperbolic flattening with exponent b=1.0 reaches the economic limit in 45 years with an EUR of 5.2 Bcf.

Constrained to the same initial decline in the first six months, raising b from 0.5 up to 1.0 extends the economic well life by 39 years and raises EUR by 143%. Another important consideration about hyperbolic flattening is that production after 10 years increases EUR by 42% but only increases the net present value by 7% (discounted at 10%/year). Large volumes of gas are included in the finding and development costs that have little impact on the value to investors. Much of what is claimed and apparently booked as reserves is predicated on the assumption of hyperbolic flattening. This cannot be supported by individual well decline-curve analysis, at least not with the production histories given so far.

At some point, shale operators and their auditors must be held accountable based on results. And while it is too early to predict the future commercial outcome of the Haynesville Shale play, there are many reasons to take a cautious approach to drilling. Our concerns that the play may be marginally commercial were shared by many presenters and participants at the recent GCAGS symposium.

Data provided courtesy of IHS Inc. However, the analysis and opinions expressed here are solely those of the authors and do not represent those of IHS or any other organization.

Realities of shale play reserves: Examples from the Fayetteville Shale

2009-09-17T19:27:00.000-07:00

Arthur E. Berman and Lynn Pittinger

When asked about the production life of shale gas wells, Chesapeake Energy CEO Aubrey McClendon recently explained, "Yes, that's 65 years. And I believe that's our standard across all shale plays, which is actually a pretty interesting point to talk about" (Second Quarter Earnings Call, Aug. 4, 2009).

It certainly is, and it helps us understand the optimistic reserves that operators like Chesapeake claim for these plays.

The reserve levels claimed by operators and analysts for shale plays are difficult to justify by standard decline curve analysis unless production is projected decades beyond any reasonable economic limit. Companies and analysts that take an optimistic view of shale gas reserves commonly show pro forma group decline curves to justify their reserve estimates. The type curves for the Fayetteville Shale predict reserves that cannot be supported by the underlying data.

In order to understand the disparity among reserve estimates for shale plays, Lynn Pittinger and I evaluated the individual decline trends for Fayetteville Shale horizontal wells. We also normalized group-average decline projections for the same well set to understand how the two methods differed. The group curve-fitting approach resulted in higher Estimated Ultimate Recovery (EUR) predictions than the individual decline-curve analysis, but both methods estimated considerably lower reserves than those claimed by major operators in the play.

Southwestern Energy Company is the leading operator in the Fayetteville Shale play with about 700 producing horizontal wells. Southwestern and other key operators claim average per-well EUR of 2-3 Bcf and drilling and completion cost of $3 million per well.

From our decline-curve analysis of about 1,300 individual horizontal wells, we determined that the average EUR for a Fayetteville Shale well is 0.85 Bcf. Southwestern Energy has the highest average EUR at 1.04 Bcf/well, followed by Chesapeake at 0.68 Bcf, Petrohawk at 0.63 Bcf and XTO at 0.59 Bcf. Most of Southwestern Energy's wells are located on a broad structural nose, and this seems to explain their superior results compared to other key operators with less favorable structural positions.

Next, we estimated average EUR using a group decline "curve-fitting" method. We normalized well rates to their first month of production, and averaged monthly production for wells that were active in each producing month. This approach resulted in an average EUR of 1.3 Bcf/well.

The higher EUR that resulted from the group decline method is produced by an apparent flattening in the hyperbolic- shaped decline trend of the averaged data. We believe that this represents an artifact of the method, and does not reflect true EUR. The decline trends for individual wells are commonly segmented, and follow a steep initial trend and later, a flatter exponential decline. The apparent hyperbolic decline pattern seen in the group-method data probably results from summing many individual wells with this segmented decline profile. The curvature of the resulting hyperbolic group decline curve--determined by the hyperbolic exponent b--results in more flattening of the decline than what is observed in any of the individual wells. Increased rates from the many workovers that occur in Fayetteville Shale wells further contribute to flattening of the group-decline curve.

Consequently, we believe that individual decline-curve analysis provides a more precise accounting of changes in decline trends than group-decline methods. We acknowledge, however, the potential for underestimating reserves using this method because of the lack of publicly available flowing-tubing pressure information and the limited production data for recently drilled wells.

Chesapeake showed a pro forma hyperbolic decline curve for a typical Fayetteville horizontal well in a presentation to investors in October 2008. The well began with an IP of 2.15 MMcfd and had an EUR of 2.2 Bc£ The decline curve has a hyperbolic exponent b value of 1.4, a degree of flattening seen in less than 1% of the individual well trends analyzed. It would take 65 year produce the stated 2.2 Bcf, but most of the individual wells that we analyzed reach an economic limit in less than 15 years. The effect of projecting production 50 years beyond the economic limit adds substantially to the EUR--in this case it almost doubles--but none of the production is commercial past year 15.

The enthusiasm for plays like the Fayetteville Shale is perplexing. It can only be explained by the urgency that companies feel to add large reserves at almost any cost. The reserves claimed by some shale play operators cannot be supported by either the individual or group decline methods that we used in this evaluation. It seems that the most convincing evidence for the success of shale plays should be found in the balance sheets of the various E&P companies rather than in their long-term reserves. Yet many of these companies appear financially tentative with high debt, ongoing asset sales to raise cash, and large impairment writedowns in recent quarterly reporting.

If our evaluation of decline rates is correct, the true reserves of the Fayetteville Shale play will be evident in just a few years. At the very least, it seems appropriate that operators and investors should take a more cautious approach, and abandon the "gas factory" paradigm that dominates shale-play thinking. And one last interesting point to talk about: They must acknowledge the need to reduce both cost and commercial risk through better geotechnical science.

A Long Recovery for Natural Gas Price: revisiting the Haynesville Shale

2009-06-04T03:47:00.000-07:00

Natural gas prices increased 39% from a 6 1/2 -year low of $3.19/MMBtu on April 27 to $4.42 on May 13, 2009. Some think that the worst of the price collapse that began in July 2008 is over, and that gas prices will return to normal. I do not believe that is the case, though I certainly hope that I am wrong. Chesapeake Energy proclaimed in a recent investor presentation that “the fix is under way”, and that natural gas prices will soon return to $7-8/Mcf. Chesapeake and other companies make the case that prices will rebound because of the drastic decrease in drilling. The gas-directed rig count has fallen from 1,606 to 728 since September 2008 and, because about 1,100 rigs are needed to maintain supply, we are creating a deficit that should cause the price to rise.

The argument is logical and may prove true in the long term, but it is difficult to support based on current events. During the same two-and-a-half week period of rising prices, working gas in storage has been well above the five-year average (23% above the 2004-2008 average), indicating that supply is strong (Figure 1). While proponents of increased gas price may find some support in short-term price fluctuations that are based on sentiment, gas storage is what drives traders, and traders determine price. In other words, until storage levels decrease to 5-year averages or lower, I doubt that there can be any sustained gas-price increase. The recent rally is probably related to rising crude oil price, a weaker US dollar, and short-selling of gas futures contracts rather than a change in market fundamentals. At this writing, gas prices have already lost most of their recent gain.

US gas supply includes two external sources: pipeline imports from Canada and LNG cargoes from all over the world. Imports from Canada are down, but LNG deliveries are way up. April LNG imports averaged 2 Bcfd, compared to half that amount in March, according to Jeffries & Company (1). Pritchard Capital Partners expects LNG deliveries to average 3.5 Bcfd for 2009, and to be as high as 5 Bcfd (1). Global liquefaction capacity has increased more than 5 Bcfd this year as several large projects came on line. Also, LNG price has decreased due to lower global demand, reduced tanker costs, and because contract prices are tied to a trailing index of crude oil and other commodity prices that have fallen.

Oversupply of gas may continue for longer than some expect. Average US gas production increased from about 62 Bcfd during the first half of 2007 to almost 65 Bcfd in the second half of 2008 (Figure 2). In addition, there are large volumes of gas available from wells that are not yet connected to sales because of limited pipeline capacity and low netback cost. The Rocky Mountain Express Pipeline will open considerable volumes of gas that have not been previously available (3.2 Bcfd by June 2009, and an additional 1.8 Bcfd in November), and the Mid-Continent Express Pipeline recently added 0.64 Bcfd of capacity. Also, in the Gulf of Mexico Independence Hub, Thunderhorse and Tahiti platforms, as well as initial production at Perdido, will increase gas production in 2009-2010.

Reduced demand because of the global economic crisis may contribute to a prolonged slump. Demand in February 2009 fell 14.5 Bcfd (16%) compared to January, and 7.4 Bcfd (9%) compared to February 2008. In Februrary, all sectors of gas usage fell.

While the gas-directed rig count is down, drilling activity is strong in the Haynesville Shale play, where high-volume initial production rates work at cross-purposes to offset the over-supply of gas. There are at least 75 horizontal wells that are currently drilling, completing, or shut-in pending pipeline connection. This could increase Haynesville daily production to more than 300 MMcfd.

I want to thank readers and operators for their willingness to share information with me in response to my earlier column on the Haynesville Shale (World Oil, April 2009). There is no doubt that the Haynesville is different from other shale plays, mainly because it is overpressured (~0.85 psi/ft). Overpressure and corresponding microfracturing combined with high shale porosity result in average initial production rates of more than 12 MMcfd and per-well EURs as high as 9.0 Bcf.

I now think that the Haynesville Shale reserve estimates that I presented previously were too low. I have evaluated 43 horizontally drilled wells with some production history, and 14 wells with initial production rates only (Figures 3a and 3b). The most-likely average EUR for all operators is 3.6 Bcf per well within a probabilistic range of 2.8-3.6-4.4 Bcf/well (RBC Capital is more pessimistic, projecting an average 2.5 Bcf EUR for all horizontal wells (2). The average EUR for key operators in the play varies: Petrohawk Energy Corporation has higher average EURs (3.9-5.1-6.2 Bcf) while Chesapeake Energy Corporation’s EURs are lower (2.2-2.8-3.3 Bcf). The average for other operators is 2.8-3.7-4.5 Bcf/well.

I have not changed my conclusion that the Haynesville Shale play is marginally commercial. Drilling and completion costs vary from $7.5 to $10.5 million per well. The marginal cost for operators to find and develop natural gas reserves is $7 to 8/Mcf, and current netback prices in the play are less than $3/Mcf. The threshold netback gas price for a better-than-average 5.5 Bcf well to break even is $7/Mcf at NPV10 (Bodell and Pittinger, in press). For companies that have favorable hedge positions, realized gas prices for 2009 will be as high as $6.50/Mcf and $6.00/Mcf for 2010. This means that the play is marginally commercial today for operators with favorable hedge positions, but not commercial based on cost and price fundamentals.

While many believe that natural gas prices will increase to $7-$8/Mcf by the end of this year, I am more pessimistic. Increased LNG imports and strong current gas supply, expanded pipeline capacity and ongoing gas-directed drilling contribute to strong gas supply, while the recession is reducing demand. This leads me to conclude that prices may not increase until the second quarter of 2010. I am also skeptical that price will recover beyond approximately $5.50/Mcf, the average inflation-adjusted gas price since 1995 (Figure 4). Shale plays have increased the marginal cost of production by approximately $2/Mcf, and I doubt that the market will reward that inefficiency. It seems more likely that LNG and conventional gas will play an increasingly important role in US gas supply in the future because of cost.

(1) Platt’s Inside FERC’s Gas Market Report, May 1, 2009

(2) RBC Capital Markets, Weekly Haynesville Shale Report: May 13, 2009

Haynesville Sizzle or Fizzle: Let’s be fair!

2009-04-21T07:50:00.000-07:00

When I read some of the comments posted on this web log to a friend yesterday, he said, “Anything that gets this much flak, must be close to the mark.”

I have received dozens of e-mails and a half-dozen posted comments on this web log about the Haynesville Shale. Many of the e-mail authors strongly disagree with my opinions about the Haynesville, but are respectful and professional. In contrast, the authors of many web log postings who disagree with me are often disdainful, caustic and even vulgar, not only about my opinions but also about my professional qualifications. Some indignantly demand that I disclose the wells (be patient inquisitors—a list of wells follows as Figs. 1 and 2) that I used in my evaluation—I wonder if these same people issue similar demands to the companies that make pronouncements that the Haynesville Shale has 250 Tcf of reserves when there are fewer than 50 wells with any production so far, or that an average well will produce 6.0 Bcf when none have yet produced more than about 3.0 Bcf and most, considerably less.

To be fair from my side, readers have sent me data on Haynesville Shale production that was not available to me when I did my research and published my World Oil column and the previous web posting. That new information modifies my view of the Haynesville play somewhat, and requires an update to my observations and conclusions. Also, there is now a month or two of additional production history since I did the research for that work.

Based on this information, approximately 59% of Haynesville wells may have ultimately recoverable reserves of 0.5-2.0 Bcf (16 wells), while 41% may produce 2.0 Bcf or greater (11 wells), according to my analysis. The mode of 27 wells is 1.5 Bcf and the mean is 2.2 Bcf. These reserve projections are approximations, and are only intended to provide a range of possible outcomes for wells with too little production history to accurately project.

For those reservoir engineers who disparage my qualifications to pick a trend line through data points on a graph (something that apparently is beyond the capability of those with advanced degrees in science unless their degree is in reservoir engineering), I hope that you have never picked a top unless your degree is in geology.

The crucial issue about the Haynesville Shale play, however, is not rates and reserves, but cost. As I explained in “Haynesville Sizzle could fizzle”, threshold economics for the Haynesville Shale require netback gas prices of $8.50/Mcf, and minimum reserves of 2.5 Bcf/well. This is because drilling and completion costs are from $7.5-9.5 million. It is simple algebra once the costs are known.

I have studied the 10-K SEC filings by the major players in the Haynesville play. These are public documents prepared by the operators. With most operating costs between $2.50 and $3.50 per Mcf, rates and reserves simply do not matter at current gas prices of $2.50 netback in the Haynesville. When capital expenditures are added, it costs most operators about $7.50/Mcf to find, develop and operate in the play. While some operators are currently hedged at higher prices, this is a short-term situation, and no one will take the other side of a hedge at more than $7.50/Mcf today or at any time in the foreseeable future.

If you don’t believe me, you should read reports by Credit Suisse, “The True Cost of Shale Gas” (April 2009), and by Bernstein Research, “Why the Haynesville Won’t Work…at $4, $5, or $6/Mcf gas” (April 2009).

I am more optimistic now, based on new information, that the Haynesville Shale may be different from most other shale plays. If operators can substantially reduce cost, and if gas prices improve to levels during the first half of 2008 (average $10/Mcf Henry Hub), some percentage—perhaps 25-50%--of wells in this play may become commercial, but it’s really not about EUR as much as it is cost and gas price.

I have been fair in admitting that new information has modified my view of the Haynesville Shale play. I acknowledge that rates are extremely impressive for several wells, and that some wells have already produced more than 1.0 Bcfg.

For those who disagree with my views on this play, I ask that you be fair too. Look at costs, and not just rates and reserves. If the marginal cost to produce gas is more than $7.50/Mcf (which all operators admit and many state in public presentations–for example, Range Resources’ “IPAA 2009 Oil & Gas Investment Symposium”), then no one is making money on this play today regardless of impressive rates and strong reserves. Unless prices rise above levels they have reached during only 15 months over the past 10 years (or 20 years, for that matter), none of the wells in the Haynesville Shale play is likely to be commercial (Fig. 3).

I am not a gladiator. I don’t perform in my columns and web log waiting for thumbs up or down from readers to validate my methods or conclusions. I put my work in a public forum to share what I observe, and to generate a dialogue that may help us all move closer to the truth. I return every e-mail message that I get, because the people who write them want to engage in the conversation, and deserve my time and respect. For those who prefer to comment anonymously on this web log, I welcome your views also. I encourage you to join the conversation as peers and not as blood-sport spectators looking for entertainment at the Coliseum.

Haynesville Sizzle Might Fizzle

2009-04-14T06:44:00.000-07:00

Despite lower natural gas prices, the Haynesville Shale is the hottest onshore play in North America. Production is more than 150 MMcfd from recently drilled horizontal wells, and single-well Initial Production (IP) rates are as high as 24 MMcfd.

I used standard rate-versus-time methods to determine estimated ultimately recoverable reserves (EUR) for 14 horizontally drilled wells that had sufficient production history to project a decline rate. Production was extrapolated using a hyperbolic decline, and an economic limit of 1.0 MMcf/month. The wells had an average EUR of 1.5 Bcf, and 67% (10 wells) had reserves less than 1.5 Bcf. This is an early evaluation, and does not include several recently completed wells because of insufficient production data. Reserves were, with one exception (5.3 Bcf), considerably lower than the 6.5 Bcfe most-likely per well reserves, and 4.5-8.5 Bcfe range, claimed by leading operators in the play Chesapeake Energy Corporations and Petrohawk Energy Corporation.

Problems with the Haynesville Shale include high decline rates and costs. Average monthly decline for the wells that I analyzed is 20–30%, and projected annual decline rates average 80−90%. Rapid decline makes IP rates unreliable indicators of well productivity. The average production history of wells used in this analysis is less than five months; current production rates already average only 48% of IP.

Drilling and completion (D&C) costs are about $7.5 million per well, although Petrohawk recently revised its D&C costs upward to $8.5–9.5 million. Average true vertical depth of wells in this study is 11,500 ft, and average measured depth is 15,250 ft. Five- to ten-stage hydraulic fracturing is typical with 600–750 lb sand/lateral foot in horizontal boreholes, which average 4,500 ft long. Leasing costs in active areas during 2008 were $10,000–30,000/acre, increasing capital expenditures for an 80-acre spacing unit $0.8-2.4 million above D&C costs.

Operating costs average $2.25/Mcf, based on US SEC 10-K filings and annual reports. After gathering and transportation costs, netback gas prices for early March 2009 were less than $2.50/Mcf (RBC Richardson Barr). Net revenue interest, after royalties, is typically 75%, and Louisiana severance tax is $0.27/Mcf (included in operating cost) . While current prices are the lowest in many years, and hedging has helped careful operators, it cost many operators a $7.25/Mcf or more to produce gas during the fourth quarter of 2008.

Clearly, most Haynesville Shale wells will not approach a commercial threshold until both gas prices and per-well reserves increase. To quantify that reserve and price threshold, I ran a basic NPV10 model using the cost information already mentioned. I used decline rates from the Barnett Shale (65%—Year1, 40%—Year 2, 30%—Year 3, 25%—Year 4, and 20% thereafter) instead of the higher decline rates projected from Haynesville production to date.

The break-even (NPV10= 0), minimum per-well reserve volume is 2.5 Bcf with a netback gas price of $8/Mcf (~$9/MMBtu Henry Hub spot). This means that the play would have been marginally commercial in 2009 dollars during only 15 months (12.5%) over the past decade—and over the past 20 years since the advent of the natural gas commodity market in 1989—if an average well had reserves of 2.5 Bcf instead of only 1.5 Bcf. At 1.5 Bcf/well, $12/Mcf netback gas price is needed to break even.

Chesapeake CE O Aubrey McClendon recently said, “We only need gas prices to be ‘good’ for three to six months out of every two-year period.” (Houston Chronicle, February 11, 2009). If ‘good’ means to break even in the Haynesville Shale, it looks like he will meet costs no more than 12.5% of the time, and lose money the other 87.5%, assuming that per-well reserves can be doubled. That business model is difficult to understand, although successful hedging might change those percentages. But that’s not the entire business model.

“We believe in volatility...You can sell volatility. Volatility has value,” McClendon continued. “Our company makes additional money when we sell those calls.” What McClendon means is that his company can make money by selling deals to other companies that fear they will be left behind during brief periods of rising prices. For example, in 2008 Chesapeake sold interests in its shale plays to Plains, BP and StatoilHydro. Chesapeake made $10.3 billion on those transactions.

Why do I reach different conclusions about the Haynesville and other shale plays than some industry analysts? First, they are not industry insiders and, therefore, many do not incorporate true operational costs including interest expense for debt service, or netback gas prices into their evaluations. Second, investment company analysts are marketing a product and make a commission on stock that they sell to clients—their analyses cannot be truly objective. Third, they do little investigative research, and generally accept information on rates, reserves, and declines provided by the companies that promote these plays. They cannot have done independent decline analysis on the Haynesville Shale or they would have recognized the obvious reserve discrepancy (1.5 vs. 6.5 Bcf/well).

I expect shale plays to be part of the natural gas landscape for awhile, despite the fact that they are marginally commercial at best. Most companies in these plays have a lot of debt, and the only way to service the debt is to generate cash by drilling wells to produce gas.

The Haynesville Shale play appeared at a time when gas prices were rising. Companies rushed to pay great sums to obtain positions based on the irrational belief that prices would continue to rise. This is the same thinking that brought us the global financial crisis. The magnitude of capital expenditure for leasing and drilling illustrates a profound breakdown of due diligence by the financial and E&P industries.

It is difficult to imagine that the Haynesville Shale can become commercial when per-well reserves are similar to those of the Barnett Shale at more than twice the cost. Maybe the most recently completed wells will tell a different story; otherwise the Haynesville Shale play will likely be replaced by other shale plays that lose less money.

Shale Plays, Risk Analysis and Other Perils of Conventional Thinking: Haynesville Shale Sizzle Turns to Fizzle

2009-03-06T07:14:00.000-08:00

In mid-July 2008, the United States somewhat unexpectedly discovered that it had an oversupply of natural gas, and prices fell sharply. Jen Snyder, head of Wood Mackenzie Ltd’s North American Gas Research Group, recently said that the development of shale gas plays has caused "a significant potential over-supply" (Oil and Gas Journal, December 1, 2008). Shale plays had become increasingly irresistable to the North American industry before prices fell this summer. Many traditional E&P companies, including some majors, decided to become shale players, and many are still considering the possiblity despite low gas prices. The global financial crisis has accentuated the aversion to risk that fueled shale plays to begin with, and it seems that no one now wants to pursue anything but shale.

In the first half of July, spot gas prices were more than $13.00 per million British thermal units (MMBtu). Six weeks later, the price had fallen below $8.00, and in March 2009, it is around $4.25/MMBtu. Some analysts predict that gas prices will average $4.00-6.00/MMBtu range at least through the end of 2010.

A total of 1,966 horizontally-drilled producing wells from the Barnett Shale were evaluated to determine commercial gas reserves using standard decline methods. Based on this analysis, only 30% of Barnett Shale wells will realize revenues that meet or exceed drilling, completion and operating costs in the most-likely case based on assumptions incorporated into a 10% net present value (NPV10) economic model. The economic model includes per-well drilling and completion costs of $3.25 million, a wellhead gas price of $6.25/MMbtu (the average spot sales price for 2007), 75% net revenue interest, 7.5% Texas severance tax, and $1.25/Mcfg lease operating and overhead cost. These assumptions are consistent with information published in 10-K U.S. Securities and Exchange Commission (SEC) filings by key Barnett Shale operators. The model requires per-well cumulative production of about 1,325 MMcfg over 10 years to reach an economic threshold.

An early analysis of 20 horizontally drilled wells in the Haynesville Shale play in Louisiana and parts of adjacent East Texas suggests a disappointing outcome because of extremely high decline rates. Average monthly decline rates are 24%, with 75% of wells declining 20-35% per month. The impressive initial production rates (IP) for these wells do not, therefore, necessarily translate into high reserves (actual daily production rates from the maximum 30-day period were, in fact, about 20% lower than reported IPs).

Fifteen Haynesville Shale wells had sufficient production history to analyze using standard rate-versus-time decline methods. Estimated ultimately recoverable reserves (EUR) averaged 1.5 Bcfg, and 67% of wells had reserves between 0.5 and 1.5 Bcf. These results indicate that Haynesville Shale reserves will be about the same as Barnett Shale wells at approximately twice the cost to lease, drill and complete.

I have struggled to understand the appeal of shale plays based on economic factors, and thought that low gas prices would greatly reduce activity. At $10.00/MMBtu, about half of horizontally drilled and fractue-stimulated Barnett Shale wells were commercial so, while prices were rising even higher, shale plays made some sense. At current prices, however, only about 11% of Barnett wells pay out, and all indications are that prices will fall lower or, at best, remain at current levels. While leasing has largely stopped, drilling continues*, and enthusiasm from both companies and analysts seems strong, at least for the Barnett, Haynesville and Fayetteville shales.

How can we understand what is happening with shale plays?

The diffusion model of innovation (Ryan and Gross, 1943; Rogers, 1962) shows that people adopt new ideas and technologies slowly, and that only about 5% of people make the decision to adopt based on information. The other 95% decide because of the the views of opinion leaders in the community, and on the eventual social momentum that develops—what Malcolm Gladwell called the “tipping point”. The 5% who base decisions on information in the diffusion model are critical thinkers; the rest are conventional thinkers.

What causes people to decide to abandon an idea that almost everyone previously accepted? It is reasonable that only critical thinkers make this decision based on information, and that conventional thinkers follow in what may become a stampede. Thomas Kuhn (1962) explained that scientists resist abandoning a ruling theory in favor of a new paradigm with a kind of orthodox fervor of conventional thinking, and often ostracize those critical thinkers who point out problems with the existing model. At some point, when opinion shifts to support a new paradigm, the previous theory is unceremoniously dropped, and its remaining supporters are criticized as dinosaurs.

It is useful to review some of the history of how our industry arrived in its present state. The collapse of oil prices in 1982-1986, and the ensuing 13 years of over-supply and low prices created an environment in the E&P business where cutting cost and reducing risk were paramount. Thousands of jobs were lost, and companies disappeared as layoffs, reorganizations, mergers and consolidation became the core business of oil and gas companies.

As oil prices slowly recovered in the late 1990s, risk analysis teams were formed to manage technical work. Executives abdicated their technical responsibilities to risk committees, and turned their attention to buiness models. With the help of consultants, they envisioned companies in which exploration and production would become a manufacturing operation, and risk was eliminated. Execution was paramount, standardization was essential, and new geological ideas were unnecessary. The new vision for the E&P business represented the victory of conventional over critical thinking.

Shale plays not only satisfied this model, but also solved the perennial E&P problem of being opportunity-constrained: because shale is practically ubiquitous, there are no limits to what can be spent pursuing new and existing opportunities. This shift was widely supported by the capital investment community because of the low perceived risk, and the fact that non-scientists could understand the play.

Returning to the present, myths about the current state of domestic E&P must be clarified in order to put shale plays in context. These plays are an important component of domestic natural gas production, but represent a relatively small—though growing—portion of the total gas supply. Even among unconventional gas resources, tight gas and coal-bed methane dominate production.

Second, these plays involve considerable risk. The fact that 75% of wells are commercial failures at current gas prices is a tangible risk. Great emphasis is placed on engineering ideas and technology, but it seems that concern for geological and geophysical understanding is uneven among shale players. All shale plays are different, and require unique approaches based on thermal maturity, structural factors, fracturability, and identification of sweet spots.

Third, economic models must be aligned with full-cycle PV₁₀ industry standards. Wood MacKenzie’s Snyder says that established shale plays have "sufficient volumes available at a development break-even price of $5.50/MMbtu or below" (Oil and Gas Journal, December 1, 2008). I don’t believe that. I do not know any credible industry analysts who believe that shale plays are commercial below $7.50. The only way to arrive at the thresholds that Snyder mentions is to understate or ignore current levels of capital expenditure, as well as general and administrative, lease operation, midstream, and discounted capital costs, or to inflate rates and reserves beyond what can be supported by performance history.

Additionally, the over-supply of natural gas that analysts describe may be relative, and that would be positive for shale plays. Spot prices rose to $13.00/MMcf because of an imbalance between supply and demand. Prices fell when about 2 Bcfd of additional supply came online from the Independence Hub, Thunder Horse and Tahiti in the offshore Gulf of Mexico, in addition to increased unconventional gas production, including shale gas. Monthly natural gas production over the past year averaged approximately 1.75 Tcf. The additional 2-3 Bcfd that produced an over-supply is only 3.5-5.5% of total production. Many circumstances might quickly upset the supply-demand balance and result in higher prices. At the same time, the global financial crisis will probably reduce demand, and somewhat offset other factors that may favor rising price. The point, however, is that the difference between what the market perceives as over- and under-supply can be razor thin.

Finally, gas rig counts and rates have fallen sharply in recent months from more than 1,600 in September 2008 to 970 in late February 2009. Some predict that rig counts may fall to 800-900 in coming months. Unconventional wells have steep decline rates, and any decrease in drilling will quickly result in dramatically lower gas production from these plays. That, in turn, will affect supply, and prices could rise, but may also expose the ephemeral contribution of unconventional gas sources to total natural gas supply.

There is little doubt that Shale Plays are likely to be important for some time. I hope that operators will continue to learn how to reduce cost, optimize production, and better incorporate geology and geophysics into their play strategies. It is not certain that the U.S. has a long-term over-supply of natural gas, or that today’s surplus is chiefly because of shale gas production.

Shale plays represent a disturbing tendency in the E&P business away from critical thinking. The belief in reward without risk is irrational. Failure to acknowledge the marginal economics of the play is bewildering. Unless opinion leaders confront the underlying economic and geological risks of these plays, I fear that a financial crisis may develop that will discredit the E&P industry.

*Barnett Shale completions have dropped from about 250 wells/month in May 2008 to approximately 125 wells/month in late 2008.