A Brief History of a Shale Play

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1 September 1, 2011 Excerpt Issue 38 By: Bill Powers A Brief History of a Shale Play While North America natural gas prices continue to reflect the misguided belief that recently emerged shale plays will keep prices sub $5.00 for years, a look at the oldest significant shale play in North America indicates that the shale gas production growth of recent years may soon be coming to an end. Though much of the investment community has long forgotten the Antrim, it is currently the 15th largest field in the U.S. by proven reserves according to the EIA. The Antrim Shale of Michigan was largely developed during the 1990 s using vertical wells and development was spurred along by Section 29 credits. Section 29 credits were part of the of the Windfall Profits Tax Act of 1980 and designed to not only encouraged the development of unconventional gas but also shale oil and other forms of unconventional oil. Similar to coal bed methane wells that require the hydrostatic pressure in the wellbore to be reduced through a dewatering process, Antrim Shale wells require a brief de-watering period of several months before they reach their peak production. Though there are many differences between modern shale gas fields, which I define as plays that are developed using horizontal wells and hydraulic fracturing, and the Antrim Shale, there are many important lessons to be learned from the more than 20-year development history of the play. In fact, one of the early leaders in the Barnett Shale, such as Quicksilver Resources, was involved in the development of the Antrim. In this issue I will examine what development of the oldest significant shale play in North America can tell us about the future of the shale industry. [Note: While the first natural gas well was drilled into the shallow, naturally fractured Devonian Shale of Appalachia in the 1820 s, only minor amounts of natural gas has been produced from the shallow Devonian Shale.] Additionally, I will look at what the lessons learned from the Antrim tell us about North American natural gas supplies and how to profit from the changing perception of future supplies. The Antrim Shale is located in the northern reaches of the lower peninsula of Michigan and is found throughout the Michigan Basin. However, development of the organic-rich Antrim, which has a total organic content ranging from 1 to 25 percent and an average of 8 percent, began in earnest in 1986 and is currently centered around in Antrim, Otsego, and Montmorency Counties and to a lesser extent, Kalkaska, Crawford, and Oscoda Counties (Source: U.S. Geological Survey (USGS)). Below is a graphic showing the occurrence of Antrim development in area 6319 and area 6320 that the USGS considered in 1996 to be prospective for development of the Antrim. Area 6320 remains almost completely undeveloped: 1

2 Once again, while there are very large differences between the Antrim Shale and the numerous modern shale plays currently under development such as the Barnett, Haynesville and Marcellus shales, there are many important similarities that provide insight into what the future may hold for the modern shale gas industry. Below are a few of the most important takeaways from the more than two decades of development in the Antrim: Traps Matter: One the great myths of the modern shale gas industry is that shale gas acreage is largely homogeneous and that the geological setting of shale acreage is less important than the thickness and total organic content of the shale. While the proper chemical make-up of shale is a prerequisite for commercial shale development, the long history of the Antrim tells us that geological setting is equally or more important. The Antrim shale is found over a large are of the Michigan Basin (see below) but only a very small portion of the Antrim is commercially productive. Why? A very likely reason why some of the Antrim is productive and the majority of not has to do with the presence of a geological trap that was formed millions of in the northern part of the basin centered around the Antrim subcrop. (Schlumberger s Oilfiled Glossary defines a petroleum trap as a configuration of rocks suitable forcontaining hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.) According to an in-depth history of the Antrim that was Source: United States Geological Survey Additionally, as you can see from the below graphic, Antrim development makes up only a small part of the entire Michigan Basin: 2

3 produced by the staff of the Michigan Public Service Commission in April 2010 titled, Michigan Antrim Shale Production: History and Physical Attributes as it Relates to U (U was a public hearing on whether wells in the Antrim should be allowed to be produced using vacuum.), The productive fairway is located immediately inside the Antrim subcrop belt. - Page 6 The below graphic displays the Antrim field as well as the Antrim subcrop: The work of independent geologist Art Berman has shown that traps are an important precondition for shale gas production. Mr. Berman has studied every commercial shale play in the U.S. which has shown the existence of traps in to be present in every shale play under development. Source: Michigan Public Service Similarly, the entire productive area of the Barnett Shale is part of a trap system that is wedged between the Muenster Arch and the Ouachita Thrust Belt: Importance of Natural Fractures: One theory on why some areas of shale plays are productive and some are not is related to natural fractures. Since natural fractures do not show up on 2D or 3D seismic images, only drilling and will provide the proof of the existence of fractures. According to the USGS, though the Antrim Shale is up to 800 feet thick, production appears feasible only where the shales are sufficiently fractured. (Source:USGS) More importantly, though this observation came from a 1996 USGS research paper on the Antrim, production has not extended beyond the area of known natural fracturing despite the advent of horizontal drilling and hydraulic fracturing. One explanation for the 3

4 lack of production outside the area of known natural fractures is that a natural fracture system may be required to establish shale commercial production. It is quite possible that the success of modern shale wells is due to man-made fractures tapping into systems of natural fractures. In other words, man-made fractures may simply act as a conduit between the well bore and an existing natural fracture system. The presence of a natural fracture system in close proximity to a well-bore which has been hydraulically fractured may explain the large variances in well performance within even core areas of shale plays. It should be noted that horizontal drilling and hydraulic fracturing in the Antrim has had little impact on the area outside of the area of known natural fractures. The Marcellus Shale is a great example of a modern shale play where natural fracture systems are likely playing a critical role in the establishment of commercial production. One of the secrets of the shale industry is the existence of what I call the world s greatest cheat sheet. In north central Pennsylvania thousands of wells have been drilled into the Oriskany sandstone which is found below the Marcellus since the 1930 s. It is commonly believed that the Marcellus is the source rock for gas accumulations in the Oriskany sandstone. Historical logs of Oriskany wells provide modern Marcellus operators with a roadmap of where natural fractures are present. More importantly, by using the cheat sheet created from Oriskany wells, Marcellus operators have been able to drill what are likely to be the best wells first. This has allowed Marcellus operators to attract latecomers to the play who have paid enormous sums for a piece of the action through joint venture agreements. It appears a similar dynamic occurred in the Haynesville and possibly other shale plays in recent years. The enormous amounts of money poured into shale plays by latecomers has grossly distorted the North American natural gas market by allowing shale operators such as Chesapeake Energy to drill thousands of uneconomic wells through the use of funds that were part of joint venture agreements. Without the uneconomic drilling of the last three years, natural gas prices would be substantially higher than today s woefully unsustainable sub-$4.00 per mcf spot price. While little has been written about the importance of natural fracture systems in modern shale plays, the history of the Antrim indicates that a naturally occurring fracture systems is key to the establishment of commercial shale production. I plan to continue to research the subject of the importance of natural fracture systems in shale basins since I believe it is possibly the single most important factor in determining the size of America s future production from modern shale gas fields. The Antrim Peaked Early: With over 20 years of production history, we now have enough production data from the Antrim to see when peak production occurred and to understand the impact of rising natural gas prices and technological advances on production once a shale play reaches peak production. The below table shows both natural gas production from the Antrim since 1989 as well as the percentage change from the previous year: Antrim Shale Production Year Production in BCF Percent Change

5 Year Production in Percent BCF Change (est.) Source: The pace of development in the Antrim peaked in 1992 when more than 1,200 wells were drilled due to the need to have wells drilled by the end of that year of Section 29 credits. Production peaked in 1998 and production has fallen every year since despite many technological advances in shale gas development, higher prices and approximately 75 percent of the play s estimated ultimate recovery (EUR) still in the ground. The Antrim Shale experienced peak production after producing slightly more than 1 tcf of the 5 tcf the play is expected to produce over its lifetime. A similar pattern has developed with modern shale plays. The Barnett Shale plateaued after producing approximately 8 of the 25 tcf the play can be expected to produce over its lifetime. While the Haynesville and Fayetteville have far fewer wells drilled into them than the Barnett, it appears they also reached peak production early in their productive lives. I expect a the Marcellus to follow a similar patter. Without the discovery of new shale plays to compensate for the rapidly maturing Big Four shale gas plays (Barnett, Fayetteville, Haynesville and Marcellus), the U.S. is likely to see a material decline in its natural gas production. The Antrim s High Terminal Decline Rate: While some in the shale gas industry use mid single digit terminal decline rates for their modern shale gas projects Devon Energy uses 6 percent as the terminal decline rate for its Barnett wells. Production history from Antrim suggests that modern shale operators are understating this figure. (I was able to attain Devon s terminal decline rate only through speaking with a company officer since the company does not publish it.) According to a 2008 study on the Antrim by Wayne Goodman and Timothy Maness titled Michigan s Antrim Gas Shale Play A Two-Decade Template for Successful Devonian Gas Shale Development, the authors concluded that the typical Antrim Shale well has a terminal decline rate of 9 percent per year. The authors also correctly observed that the play declines 4 to 5 percent per year due to continuous development. So why is this important? Given that Antrim wells are far shallower (typically 500 to 2000 feet versus 7,000 to 10,000 feet for modern shale gas wells) and produce from a formation that is under far less pressure than modern shale gas wells, one would expect modern shale gas wells to have higher rather than lower terminal decline rates. Since modern shale gas operators book reserves over four to six decades, a small under-estimation 5

6 of terminal decline rate can have an enormous impact on both the EUR of the well and the length of its productive life. For example, if Devon Energy s wells in the Barnett terminally declined at the same rate as wells in the Antrim 9 percent rather than 6 percent the company would be over-stating its reserves per well between 25 and 50 percent. Devon is the not the only company that is likely to be using a terminal decline rate that does not reflect reality. I suspect nearly all shale gas operators are underestimating terminal decline rates. Conclusions: Though there are many important differences between the Antrim Shale play and modern shale plays, I believe there are also many similarities that provide insight into what we can expect as the modern shale plays mature. Should the investing public and policy makers realize that the commercial areas of shale plays are far smaller, terminal decline rates higher and productive lives shorter than previously advertised by the industry, natural gas prices and shares of companies leverage to natural gas will move dramatically higher. Bill Powers Editor, Powers Energy Investor Information presented in this newsletter was obtained from sources believed to be reliable but accuracy, completeness and opinions based on this information are not guaranteed. Under no circumstances is this offer to sell or a solicitation to buy securities suggested herein. The editor may have an interest in the companies mentioned. All data and information and opinions expressed are subject to change without notice Powers Energy Investor, LLC. All rights reserved. SUBSCRIPTION INFORMATION SUBSCRIPTION RATES Online Access: $299 Includes: Single user online access for 12 months, (24 issues published during this time). Hardcopy delivery service is also available. If interested, please call PAYMENT METHODS Online Payment: Visa, Mastercard, American Express, Discover Card and Paypal Credit Card by Phone: We can now accept credit cards by telephone. Please contact us at for more details. Check/Money Order: (Payable to:) Powers Energy Investor 5834 N. Paulina St., 2N Chicago, IL

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