CHAPTER ONE

Update on North America Shale-Gas Exploration and Development

DAVID G. HILL 1, JOHN B. CURTIS 2, PAUL G. LILLIS 3 1. EnCana Oil & Gas (USA) Inc., Denver Colorado 80202; 2. Department of Geology and Geological Engineering, Colorado School of Mines, Golden, Colorado 80401; 3. U.S. Geological Survey, Denver, Colorado 80225

ABSTRACT

In the oil and gas industry, shale has overcome its stigma as an odd unconventional hydrocarbon reservoir to become one of the most sought-after resource plays in North America. Spurred by develop - ment of the Barnett Shale in the Fort Worth Basin, U.S. drilling and exploration for this unique play type is at an all time high at year-end 2006. Recent shale specific consortia, workshops, symposia and confer - ences reflect this increased emphasis on shale plays. Shale-gas plays have emerged as commercially viable and encouraging exploration is ongoing in many basins in North America. Hydrocarbon production from shale-gas systems has a long and important history in North America. The first commercial U.S. natural gas production (1821) came from organic-rich Devonian shale in the Appalachian basin. The first commercial U.S. oil production from shale (1862) came from the Upper Cre - taceous Pierre Shale in Colorado. Both plays are still producing today. With the recent growth of shale-gas plays, defining and classifying shale reservoirs has become increasingly complex. Including both gas and oil productive systems and expanding the definition to include fine-grained source rocks creates a more encompassing taxonomy. Shale-gas systems are generally unconventional, self-sourced, continuous-type accumulations (biogenic, thermogenic or combined bio - genic-thermogenic gas accumulations). The principal shale-gas plays are characterized by widespread gas saturation, subtle trapping mechanisms, seals of variable lithology and enhanced permeability due to nat - ural fractures and/or variable interbedded lithology. It now is commonly accepted that gas is stored in shale-gas reservoirs in a variety of ways including in natural fractures and intergranular porosity as free gas, sorbed onto kerogen and possibly dissolved in bitumen. Shale-oil systems can also be continuous- type accumulations, characterized by widespread oil saturation, subtle trapping mechanisms, primary permeability from natural fractures and interbedded lithologies and seals of variable lithology. Shale oil reservoirs are typically a dual porosity system where oil is primarily stored in the natural fracture net - work and intergranular porosity. Natural gas production from the five principal shale plays has increased 151% from 2000 to 2006. These plays include Devonian Ohio Shale of the Appalachian Basin, Devonian Antrim Shale of the Michi - gan Basin, Devonian New Albany Shale in the Illinois Basin, Mississippian Barnett Shale in the Fort Worth Basin, and Cretaceous Lewis Shale in the San Juan Basin. The great majority of this increase has been in the Barnett Shale. The other principal plays have increased slightly or declined. These plays are being used as analogs for exploration and development in other basins. At year-end 2005, a new shale-gas play, the Fayetteville Shale, has emerged in the Arkansas portion of the Arkoma Basin and is proving to be commer - cially viable and potentially very large. Production is beginning to be established in several other plays such as the Baxter Shale in the Greater Green River Basin and the Woodford Shale in southeastern Oklahoma. Numerous other shale plays in the pilot stage are being worked to establish production.

Gas Shale in the Rocky Mountains and Beyond, D. Hill, P. Lillis, and J. Curtis, eds., Rocky Mountain Association of Geologists 2008 Guidebook CD, p. 11-42.

11 David G. Hill, John B. Curtis, Paul G. Lillis

New technologies have played a critical role in expanding industrys understanding of shale-gas plays and unlocking their potential. These technologies include advances in hydraulic fracturing, horizontal drilling and reservoir characterization. Operators and service companies have adapted, modified and cre - ated new approaches to exploration and development of shale reservoirs through innovation and trial and error. In the established shale-gas plays, approximately 38,000 shale-gas wells produced an estimated 1.0 Tcf of gas at year-end 2006. Cumulative natural gas production has exceeded 8.7 Tcf from 1979 to 2006 from these plays. The estimated technically recoverable resource ranges from 53 to 114 Tcf.

INTRODUCTION predominate in the Michigan and Illinois Basin plays (Schurr and Ridgley, 2002; Schoell, 1980; Martini et al, Gas-productive shales occur in Paleozoic and Mesozoic 1998; Walter et al, 2000). rocks in the continental United States (Figure 1). As with Economic production typically, if not universally, most unconventional or continuous-type accumulations requires enhancement of gas shale’s inherently low matrix (Curtis, 2001; U.S. Geological Survey National Oil and permeability (<0.001 md) (Hill and Nelson, 2000). Well Gas Resource Assessment Team, 1995), these systems rep - completion practices employ hydraulic fracturing technol - resent a potentially large, technically-recoverable gas ogy to access the natural fracture system and to create new resource, even though past production and proved reserve fractures. Less than 10% of shale-gas wells are completed estimates are small (Figure 2). The resource pyramid con - without some form of reservoir stimulation. Early attempts cept depicted in Figure 2 was first used in the late 1970s to fracture these formations employed nitroglycerin, pro - for analyzing natural gas accumulations in low-permeabil - pellants and a variety of hydraulic fracturing techniques ity reservoirs (Sumrow, 2001). If exploration and develop - (Hill and Nelson, 2000). ment companies are to access the gas resources towards the This paper is an update on shale-gas activity in North base of the pyramid, some combination of incrementally America reviewing the original five principal shale-gas sys - higher gas prices, lower operating costs and more advanced tems in the U.S., and discussing several emerging shale-gas technology will be required to make production economic. plays and plays that are in the early stages of exploration Production of gas deeper within the resource pyramid is and evaluation (Figure 1). required to fully realize the potential of this type of petro - leum system. More than 38,000 shale-gas wells have been drilled in HISTORICAL PERSPECTIVE the United States since the early 1800s (Hill and Nelson, 2000). Paucity of shale-gas production outside the United The birth of the oil and gas industry occurred in the States may be attributable more to uneconomical flow Appalachian Basin. Although the start of the oil industry is rates and well-payback periods than to the absence of commonly attributed to the Drake well drilled near Oil potentially productive shale-gas systems. Creek, Pennsylvania in 1859, the first gas well was report - These fine-grained, clay and organic carbon-rich rocks edly dug in 1821 to the Devonian Dunkirk Shale by are both gas source and reservoir rock components of the William A. Hart in Chautauqua County, New York. This petroleum system (Martini et al, 1998). Gas is thermogenic well produced natural gas that was used to illuminate the or biogenic and may be stored as free gas in fracture and town of Fredonia, New York (Roen, 1993). Both of these intergranular porosity, sorbed onto kerogen, and perhaps historic wells were shallow, and both of these areas are still dissolved in bitumen (Martini et al, 1998; Schettler and commercially productive. Parmely, 1990). Trapping mechanisms can be ambiguous Shortly following the oil discovery by the Drake well, oil with gas saturations covering large geographic areas (Roen, production was established west of the Mississippi river in 1993). Postulated seal-rock components differ among the 1862 in what is now Fremont County, Colorado. This pro - major shale-gas plays, including bentonites (San Juan duction came from the fractured Cretaceous Pierre Shale Basin), shale (Appalachian Basin and Fort Worth Basin), establishing the Florence-Cañon City field (Mallory, 1977). glacial till (Michigan Basin) and shale/carbonate facies Like the Devonian age shale in the Appalachian Basin, oil is changes (Illinois Basin) (Hill and Nelson, 2000; Walter et still being produced from the Pierre Shale in this field today. al, 2000; Curtis and Faure, 1997). While oil production spread quickly across the U.S. Thermogenic and biogenic gas components are present from east to west, shale-gas production was much slower in shale-gas reservoirs; however, biogenic gas appears to to develop. Production was concentrated in the eastern

Gas Shale in the Rocky Mountains and Beyond 12 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT . s y a l p e l a h s d n a s n i s a b y r a t n e m i d e s . S . U r o j a M . 1 e r u g i F

Gas Shale in the Rocky Mountains and Beyond 13 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

U.S., mainly due to proximity to markets and infrastruc ture. Natural gas production from the New Albany Shale in the Illinois Basin was established in 1863. Growth stalled until the 1920s. By 1926, the Devonian shale-gas fields of east - ern Kentucky and West Virginia comprised the largest known gas occurrences in the world (Roen, 1993). The next period of revitalization for gas shales came with the shortages of natural gas during the early 1970s. Several initiatives increased gas production from approxi - mately 70 Bcf per year from one basin to over 400 Bcf per year in 2000 from 5 basins. These efforts included focused research and development and a federal tax incentive for producing gas from shale. In 1976, The Energy Research and Development Administration (ERDA), forerunner of U.S. Department of Energy (DOE) initiated a focused research effort on the eastern gas shales called the Eastern Gas Shales Project. This project concentrated on shales in the Appalachian, Illinois and Michigan basins with a series of geological, geochemical and petroleum engineering stud - ies and was terminated in 1992. During this time, DOE invested approximately $137 million dollars (Bezdek, 2002). Research was also conducted by the Gas Research Institute (GRI—now the Gas Technology Institute, GTI) Figure 2. U.S. lower-48 states shale-gas resource base, known or assessed plays. Modified from Hill and Nelson (2000). through the 1980s and early 1990s. This research built on DOE’s work and expanded into the Barnett Shale in the Fort Worth Basin. GRI’s investment in gas shale R&D was approximately $30 million (Bezdek, 2002). In 1980 a fed - eral tax credit was established (Section 29 Tax Credit) for gas produced from Devonian shale. This price incentive

Figure 3. U.S. shale-gas annual production from principal plays. Modified from Hill and Nelson (2000).

Gas Shale in the Rocky Mountains and Beyond 14 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT

Figure 4. Actual Shale-Gas annual production and Energy Information Administration (EIA) Forecast (Caruso, 2007).

expired in December, 1992. At that time, many believed play analog. Some of the technologies are new and some that gas production from shale would no longer be viable have been adapted for application in shales. These tech - without the tax credit and production would decline. nologies include refracturing (hydraulically fracturing an While gas production from the Devonian age Antrim interval already stimulated), slick water stimulation, micro - Shale of the Michigan Basin was established in the 1960s, seismic, horizontal drilling and reservoir characterization. production was not well established until the GRI program These technologies are being adapted or modified by oper - in the late 1980s. The Antrim Shale was the most active ators as new plays are explored and commercial produc - U.S. natural gas play in the early to mid-1990s, after expi - tion established. ration of the Section 29 Tax Credit. Commercial gas pro - Gas production from shale has grown from less than 70 duction was established from the Mississippian age Barnett Bcf per year in the late 1970s to over 1.0 Tcf per year in Shale in the Fort Worth Basin in the early 1980s, but did 2006 (Figure 3). The growth has been achieved through the not grow until the late 1990s and is now one of the most exploration and development of five gas shale plays, with active natural gas plays in the U.S. the majority of the growth in one play, the Barnett Shale. Because of the success of the Antrim and Barnett Shale The Energy Information Administration (EIA) estimates plays, shale-gas has become a primary focus of exploration that gas production from shale will grow to 2.31 Tcf annu - and development efforts in North America, with new and ally by 2030 and overtake coalbed methane production by old plays being assessed across the U.S. and Canada. Figure 2025 (Caruso, 2007) (Figure 4) . In 2030, gas production 1 shows the major basins and shale plays that are either from shale is estimated to be over 11% of U.S. production currently producing or being evaluated. (Caruso, 2007). How will the oil and gas industry meet The current increase in interest in gas shales can be this estimated growth in gas production from shales? attributed to several factors. These include the following: • Historically high natural gas prices RESOURCE BASE • Success of the Barnett Shale play Existing and future gas shale exploration and develop - • Mergers and acquisitions (>>$10 billion) ment activity will need to continue at a rapid pace to meet • Improvements in technology the EIA projections. In addition, new emerging shale-gas plays will need to be developed with a shorter learning Technology is a significant contributor to the success of curve than the previous development cycles of the Antrim the Barnett Shale play (Figure 1) currently being used as a Shale and Barnett Shale plays. Knowledge of the resource

Gas Shale in the Rocky Mountains and Beyond 15 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

Figure 5. Barnett Shale annual natural gas production, Fort Worth Basin. Data source IHS, 2006.

Figure 6. Barnett Shale annual producing well count, Fort Worth Basin. Data source IHS, 2006.

Gas Shale in the Rocky Mountains and Beyond 16 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT d e r e * ) v f o c c T 7 6 ( s . . A A A A i s d 0 0 e d N N N N a e 9 4 c n t r G a U u e l l m o i a a s t t e s h o E T S R ) 0 0 d 6 0 n 5 0 2 a 9 0 ( d , 9 e 2 l n 5 1 n . b a 9 o e , o S a 9 8 r c 2 s C 1 3 G r l 9 e 9 5 0 y u S 9 v e 2 9 0 S 0 g o 1 0 o 1 U 0 r N 2 3 G s . 0 c 2 e l . 0 d d S e l 2 e . d n a 0 n l n l a U R t R n E 2 a a a a t , e t . t a s d t e l 0 2 2 5 s e a l a . e e a 8 9 9 l 9 2 e o t a i 7 . 7 . t y r G 9 9 9 y . r a t w 2 8 7 9 e e 1 1 1 k e H 6 s * e h l i – 1 7 1 z 0 l m ) t s 2 a i f g c l 2 – 1 – C e C C 2 a i t u l u . . – l . m c d 5 9 i P P i P s h w o o u 2 . 0 0 . 1 T o E S ( M N 1 S N 7 1 S 1 R P K 1 1 N r f d e i f i d o . l M a . C C t C s e P P P ) f y s N N N c a e g l T 2 2 2 c n ( i p 9 9 9 a * n l 9 9 9 e * e n 1 1 1 P c 8 - r v e 4 0 i & & J & n u t 2 6 6 i e - l o c 0 – 0 7 7 0 1 8 s a s 1 8 5 8 – 9 . 8 – u a e A A h 9 2 9 5 9 6 6 9 d e S G R 1 2 1 3 1 N 9 N 8 1 l o r b a p T l . 8 + y ) 3 6 3 0 t a ) . . . . 8 0 i 2 . . . r p 1 0 1 1 o 1 i 3 2 u – – – – R 0 – t – c 4 4 0 4 0 . . . . 6 a 2 n . . 0 % i 0 0 1 0 / 1 M ( 1 r 0 0 p - I e R l 5 h a G . n t ( 5 0 2 5 o . m 5 l 5 5 2 – 2 n r 4 . b – 1 i a r – 5 – e ) t – 4 0 2 a 1 4 1 h 0 s 2 o . % T T C ( e 0 o t c ) r d 2 n u i * * a 0 0 * * c 0 0 o i 0 0 * * m m 0 0 s ( 0 0 0 0 n e n , , 5 0 e i , , 0 0 a a D 0 2 r s 4 3 1 2 g e 6 2 , , d r a r 1 5 e n 1 1 1 4 l O B A a a y l h p s e p l e l u a g a S h n h y i - S e S g r l e e r l e y l a a l e e e a l n n a l h a l e n i h a o p a h S h E i b v S g b h t u - . S t l S e t n t a o S S s r i t A . e r m s r i i a o e m o n U r j i a G w t r r y w g f a h e e n a o r a e o . M B F o O A N L F B n S . o i t , U c Y A e n j H V N Y o o i , ) r , O t K r s M V Y P , ( , o K N e N e . W N p I t , , n y I i , l , l a , I H n O t R e X . A L o y s l S O P M I A C T a s n B e o l I n a a a R h e i h r s t G n h r n a k c a o 0 a a c y a u 0 l g s a a n i l l J m i W 0 i a h o o t 2 B P s p n r c k n i a i * p r a o l * * l B A M I A S F * * *

Gas Shale in the Rocky Mountains and Beyond 17 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis base of gas shales is incomplete with respect to known the early 1980s through the mid-1990s using vertical well accumulations and estimates have not been updated with technology, and large hydraulic fracture treatments using new reservoir data and production information. Moreover, foam, cross-linked gel or gel fluids to place large amounts the majority of the new plays, either emerging with newly of proppant. established economic production or still in the exploration A comparison of Table 1 and Figure 3 indicates that while phase, have not been characterized with respect to gas-in- the Ohio Shale contains the greatest in-place and technically place, recoverable gas or technically recoverable gas esti - recoverable resources, its share of total shale-gas production mates. Table 1 was originally published by Hill and Nelson has been declining since 1994, even though yearly production (2000) and is herein updated with more recent data from continues to increase. Annual Appalachian Basin shale-gas the USGS and industry. Information from the emerging production was surpassed by Antrim Shale gas production in Fayetteville Shale play has been added for comparative 1994, and by Barnett Shale gas production in 2002. Note purposes and the Barnett Shale estimated recoverable that Mitchell Energy Development Corporation (MEDC) shale-gas resource data have been updated. However, gas- only required approximately 20 years to surpass the produc - in-place estimates for the Barnett and Fayetteville shale tion in the Appalachian Basin. Cumulative Barnett Shale pro - plays are not available. duction is now approximately three-fourths of the magnitude The shale-gas resource pyramid first published by Hill of Appalachian shale-gas production. Lewis Shale gas poten - and Nelson (2000) pulls together the gas resource data tial is currently unknown, but is promising based both on along with proved reserves and historic production to for - production trends in the last four years and on the fact that mulate a snapshot of the full potential of shale-gas (Figure individual well economics do not rely solely on Lewis Shale 2). Historic production and proved reserves have more production. than doubled in the past 6 years. The estimated technically recoverable reserves have increased, mainly from the update on the Barnett Shale and the addition of the Fayet - PRINCIPAL PLAYS teville Shale plays. The undiscovered and gas-in-place esti - mates have not changed significantly. The undiscovered Table 2 is a comparison of reservoir properties and key estimates were generated by the Gas Research Institute, information for the five principal shale-gas plays. The which has not published any new data since 2000. The gas- emerging Fayetteville play from the Arkoma Basin has been in-place numbers should be considered conservative since added to the table for comparison purposes and is covered the Barnett Shale and Fayetteville Shale values are not pub - in the next section. lished. Adding gas-in-place numbers for these two plays would likely double or triple the existing estimate of 600 Tcf gas-in-place. Adding other plays currently being evalu - Ohio Shale—Appalachian Basin ated will also expand the resource base and increase the size of the overall shale-gas resource pyramid. The Appalachian Basin contains both the oldest commer - Moving down the shale-gas resource pyramid and con - cial natural gas production and the first shale to establish verting resource to reserves or production is both an production (Figure 1). Through 1994, the basin was also opportunity and a challenging task. Moving from the more the largest producer of shale-gas until it was overtaken by economic and known plays into new plays or more diffi - development of the Antrim Shale in the Michigan Basin. cult areas in existing plays typically involves greater risk, The Appalachian Basin is the largest shale-gas producing higher development costs and more technology to unlock basin with respect to cumulative production (Table 2). these resources. One example of moving down the pyramid The largest producing field in the Appalachian Basin is within a given play that demonstrates these assumptions is the Big Sandy Field, located in eastern Kentucky and south - the Barnett Shale play in the Fort Worth Basin. western West Virginia, which has produced shale-gas since Because of the recent success of the Barnett Shale, many 1921 (Hunter and Young, 1953). Cumulative basin pro - operators are using this play as an analog for exploration duction through 2006 is estimated at 3.76 Tcf, the major - and development. The history of the play reveals the ity coming from the Big Sandy Field. impact of technology, industry risk and how the oil and gas The Ohio Shale holds both the greatest in-place and industry overcame challenges to unlock the resource poten - technically recoverable resources (Table 1). This is likely tial and improve recovery factors. Figures 5 and 6 shows due to the extensive research conducted by the U.S. the development history for the Barnett play using annual Department of Energy and the Gas Research Institute. Gas- gas production and producing well count. The graphs high - in-place is estimated at 225-248 Tcf and recoverable gas light both vertical and horizontal well production and well resources estimates range from 12.2 to 27.5 Tcf. The shale count. The play was quietly developed by one operator in is pervasive throughout the Appalachian Basin and has a

Gas Shale in the Rocky Mountains and Beyond 18 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT e l a h N I S , . y 0 o n 0 C a 5 5 n , 7 b n a 2 . l i ) 5 2 o – . 0 n A s 0 3 0 0 0 s i 0 1 – i o 0 4 3 1 0 2 7 8 0 r o . 0 – 5 v r w 0 6 0 – 2 1 – – 1 n 0 0 6 2 e e i A a 2 8 , 8 0 . – – 0 0 – . 0 l l ( N I D 1 1 1 8 0 5 5 5 4 ~ 7 0 N 5 H n o s l I e N M e l , . a d o 0 h n n 0 a C S n a 5 l i a , 0 7 l o . i n g m 2 0 0 i g i 0 1 o H 0 – 5 2 7 1 5 r h e – 3 5 8 t v 4 0 0 1 1 – – 1 c s 6 4 i 7 4 t n e A m 9 0 6 5 . – – 5 0 . – . , A M D 1 5 1 7 0 5 5 5 4 0 6 0 N 2 O o r f d e , t . a o e 0 l d C s & 0 a p 0 u 0 a h n n , 0 o U 0 b a a 6 9 i S e , 7 9 5 5 r d u u – . . . c s r ’ 1 1 5 5 s J J n 0 1 2 0 i a A 0 – – 7 4 t a 0 – – 2 – n n w 5 0 0 5 – – 9 e o 5 6 5 2 1 r A i M a a e 9 , 0 3 . . 0 – 5 . . 0 6 d L S C 1 4 5 1 1 0 5 2 1 0 0 4 N 2 S R N e i f i d o M . 0 Y s n e 0 a a l t K 0 i f 0 e a / , n , 0 h i . r h c a s 6 0 o a i , 0 9 5 a S p – . . l n 1 0 0 C c 2 0 1 0 6 i a o 3 1 – 6 1 0 o r . 0 – i – 7 e v p e 2 0 0 6 – 6 – 1 l k 0 5 6 1 2 o h e A p i 8 , 0 0 . – 5 – 0 . – , t b O A D 1 2 3 1 0 2 4 2 2 ~ 0 5 N 3 P s a i T h n i s e l y n X a 0 a a l i T 0 h h p p , 5 t S . , r p 0 0 i s o t 8 o t 0 6 4 s a – . C e s 4 0 0 1 W g i 0 1 0 - 1 – 7 n 8 – e s t 0 – 6 r r e s 8 0 0 5 – 7 – 0 s i l 0 1 5 i 4 5 5 a o 9 , 0 0 . – 5 – 0 . . 4 . , a B F M 1 7 2 2 1 2 4 3 3 0 1 1 2 2 W h s e v e i l t a R c h u A S , n d . s 0 & a e o e i o l 0 r t l n p i a 0 4 C p , e p v 0 0 4 . i r m y 5 . i e a 0 5 0 0 6 0 s t u S t a – . 0 . . . s s t 3 1 0 2 5 m i B 0 3 – 0 2 w E e 3 – – 7 1 6 U s o 0 – 0 – – n t n y 0 0 0 5 – 8 – – s k 0 2 i 4 2 6 x o n r a a 0 , 0 0 . – 0 – 0 . . 5 . 7 i e F M A 2 3 2 1 1 2 3 4 4 0 0 2 0 1 V C s d r n e o f p e s d e ) n i I t e ) ) n f ) r t d * y f o c e e , i / n a f i a t ) l B 6 p a c e s ) c ( ) r F 0 o C s p B e ˚ n ) C - r 0 ( ( A ( t e R o i f S n p 2 t t . O / ( c g / U ) f s o R – n f p T n y n c s a E i 8 c e N U e % e i s m r l B c s 7 g G l % E r d ( e e K a , u a 9 e % l t a t V T n e l e e ( d ) 1 r ( e k n v w e c Y t o W i e ( y c l G t r e n % n a a i . t t l y ( ) g t W o a o s o P t r y h l i e r n i S f o t P h t s r y t l e z ( u T e t o c r , c i i e u a v a n m ) r V H e r S s r h s C I u m s n n o t o e i o . . s u p e H o s d t f c h t t s s I p m e s t r g g o n o e o c s c s a i r a a i e i u i r g a o o r r v v * B P A B D D G B M R M G P P G A A C P ( H *

Gas Shale in the Rocky Mountains and Beyond 19 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis gross thickness from 300 feet at the margins to well over gas production increases slowly, peaking for a period of 1,000 feet in some portions of the basin. time and then declining slowly. The natural gas also con - The primary completion interval is the Huron Member tains a large concentration of carbon dioxide. Full-stage of the Ohio Shale. Additional targets include the following: development of the Antrim Shale in the Michigan Basin • Upper Devonian Rhinestreet Member of the West Falls occurred during the late 1980s and natural gas produc - Formation tion peaked in 1998 at 200 Bcf. Activity levels in the Antrim Shale have remained fairly level over the past 4 • Dunkirk Shale Member of the Perrysburg Formation years, with drilling in the range of 400 to 450 wells per • Cleveland Member of the Ohio Shale, year. Produc tion has declined slowly since 1998 to approx - imately 140 Bcf in 2006 from 9,041 wells. • Lower Devonian Marcellus Shale The Antrim Shale gas-in-place ranges from 35 to 76 Tcf • Mississippian Sunbury Shale (Boswell, 1996). and technically recoverable resource from 7.5 to 18.9 Tcf (Table 1). The lower numbers for both cover just the pro - Average reservoir properties for the Ohio Shale are sum - ducing trend located in the northern third of the basin. marized in Table 2. The gas-in-place per section (which Commercial production has yet to be established else - includes gas stored by compression in the pore space and where in the basin. The shale is pervasive throughout the natural fractures plus sorbed gas) ranges from 5 to 10 Bcf Michigan Basin and has a gross thickness from 100 to 200 per section. Total organic carbon (TOC) present in the feet. shale ranges from 2 to 6%. The highest concentrations are Average reservoir properties for the Antrim Shale are located in eastern Kentucky and southwestern West Vir - summarized in Table 2. The gas-in-place per section (which ginia for the Ohio Shale and coincident with the Rome includes gas stored by compression in the pore space and Trough (Curtis and Faure, 1997, 1999). Thermal maturity natural fractures plus the gas adsorbed onto the organic of the organic matter, as measured by vitrinite reflectance, matter in the shale) ranges from 6 to 15 Bcf per section. varies across the basin from approximately 0.6 to 1.9 % Total organic carbon (TOC) is present in the shale from 5 Ro, going from west to east (Curtis and Faure, 1997, to 15%. Thermal maturity of the organic matter, as mea - 1999). sured by vitrinite reflectance, in the northern production Initial production rates (IP) and reserves by well vary trend ranges from approximately 0.4 to 0.6 % R o (Rullkot - widely across the basin and within a given area or field. ter et al., 1992). Reserves range from less than 100 Mmcf to 1.0 Bcf. A typi - Cumulative production from 1978 through 2006 is esti - cal vertical Ohio Shale well will produce approximately mated at 2.48 Tcf. The primary completion intervals are 300 Mmcf of gas over a 30 year life. the Norwood and Lachine members of the Lower Antrim The Ohio Shale is an attractive development target for Shale. Additional targets include the following: operators. Proximity to market (low transportation costs and a commodity price premium), long-lived reserves (30 • Upper Antrim Shale to 50 years), potential for stacked pay and high success rates will underpin the continued development of this large • Ellsworth Shale natural gas resource. However, the play is very mature and continued growth will require new technologies to assist Antrim Shale wells have initial production rates that operators in expanding the play boundaries, lowering over - range from less than 10 Mcfd to over 1,000 Mcfd. How - all well costs and improving gas production rates and well ever well IPs and individual well performance are masked reserves. Operators are experimenting with horizontal by the use of central facilities for collection, metering and wells and hydraulic fracturing fluid systems and fracture data reporting on groups of 10 to 30 wells (termed pro - stimulation designs. jects), often connected to a single water disposal well. Sta - tistically, the average well produces 44 Mcfd with 26 bar - rels per day (bpd) of water. Figure 7 shows production Antrim Shale—Michigan Basin information for one of the oldest producing Antrim wells (Ausable 9-34) with a date of first production in October The Devonian Antrim Shale of the Michigan Basin is a 1968. The well has produced 1.68 Bcf of natural gas and is unique shale-gas play (Figure 1). The origin of the gas in currently producing at an average rate of 40 Mcfd. While the northern producing trend is predominately biogenic water production is not reported, gas production started at and the formation produces both natural gas and water, a low rate, inclined to a peak of nearly 200 Mcfd, stabi - similar to many coalbed methane plays. Water production lized and then began declining. Newer wells using more peaks early in the life of a well and declines rapidly while advanced completion techniques with improved dewatering

Gas Shale in the Rocky Mountains and Beyond 20 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT

Figure 7. Ausable 9-34 Antrim Shale natural gas production. Data source PI/Dwights Production Database Version 1.7, 2006.

of the natural fracture system show improved performance New Albany Shale—Illinois Basin with shorter times to peak gas production as well as greater overall recovery. The Mississippian-Devonian New Albany Shale of the Research conducted in the Antrim Shale by the Gas Illinois Basin (Figure 1) is also a unique shale-gas play in Research Institute through the University of Michigan has that the origin of the gas in the northern producing trend established the origin of the gas. Detailed study of the for - (Indiana) is predominately biogenic and the formation pro - mation water chemistry, gas geochemistry and geology duces both natural gas and water, similar to fluid produc - established the dual origin of the natural gas from thermal tion in the Antrim Shale. To the south in Kentucky, the gas maturation of the organic material and microbial methano - mix changes becoming predominately thermogenic with genesis (Martini et al 1998, 2003). The shallow nature of higher nitrogen concentrations and lower water cuts the Antrim Shale along the basin margin and Pleistocene (McIntosh et al., 2002). No commercial production has glaciation history resulted in the permeable natural fracture been established in the Illinois portion of the basin. network for effective fluid flow and reservoir capacity. Exploration and development activity in the New The Antrim Shale is still an attractive target for opera - Albany Shale began in 1863, making it the second oldest tors to develop. However, the play is mature (production shale-gas play in the U.S. (Hassenmueller and Comer, declining) and continued growth will require new technolo - 1994). Activity levels in the New Albany Shale have gone gies to assist operators in expanding the play boundaries to through numerous cycles over the years and activity has the south in the basin, and in lowering overall drilling and recently increased in the play. Production data are not pub - operating costs. Operators are experimenting with horizon - licly available for the play, thus estimates are based on tal wells (both single and multi-laterals from a single well - drilling activity and average well rates from various public bore), up-hole recompletions and restimulation of produc - sources. Activity level in the basin has increased since 1998 ing zones. Operators are also evaluating infill development and has stayed fairly level over the past 4 years with in certain areas. drilling in the 20 to 45 wells per year range with yearly

Gas Shale in the Rocky Mountains and Beyond 21 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis production slowly increasing to approximately 3.0 to 4.0 ment and associated increasing production. Success will Bcf in 2006. require new technologies to assist operators in increasing Estimates of New Albany Shale gas-in-place ranges from well productivity, inv estment in infrastructure and sustained 86 to 160 Tcf and technically recoverable resource from higher natural gas prices. Results from a GRI consortium 1.9 to 19.2 Tcf (Table 1). The range in technical recover - study suggested that the New Albany Shale would be a able resource estimates reflects the difficulty establishing good horizontal well candidate due to natural fracture and the commercial viability of the play and expanding beyond permeability anisotropy (Zuber et al, 1999b). Recent a few productive fields. The majority of the production drilling has focused on horizontal wells and increased from the New Albany Shale has been from the southeast - emphasis on reservoir characterization. Since 1997, an esti - ern portion of the basin. The shale is pervasive throughout mated 57 horizontal wells have been drilled. Production the Illinois Basin and has a gross thickness from 100 to results are not available for comparison or analysis at this 400 feet at depths from 600 to 5,000 feet. time. Average reservoir properties for the New Albany Shale are summarized in Table 2. The gas-in-place per section ranges from 7 to 10 Bcf per section. Total organic carbon Lewis Shale—San Juan Basin (TOC) is present in the shale from 5 to 20%. The highest concentration of organic carbon is in the uppermost inter - The Cretaceous Lewis Shale of the central San Juan val of the New Albany Shale, the Clegg Creek Member, Basin of Colorado and New Mexico (Figure 1) is the with values of over 15% TOC (Hassenmueller and newest of the principal shale-gas plays, and is also the Leininger, 1987). The majority of the completions are in youngest in geologic age. It is one of the more organic-lean this upper, organic-rich member as well (Comer et al shale-gas plays with TOC values ranging from 0.5% to 2006). Thermal maturity of the organic matter varies 2.5%. Activity levels in the Lewis Shale have remained low across the basin from approximately 0.6 to 1.0% R o, but steady over the past few years. This play is typically increasing with depth towards the depocenter of the basin commingled with other productive intervals in the San (Barrows and Cluff, 1984 ). Additional targets in the New Juan basin and Lewis Shale production is not reported sep - Albany Shale include the following members: arately. • Camp Run/ Morgan Trail The Lewis Shale gas-in-place is estimated at approxi - mately 96 Tcf and technically recoverable resource at 10.2 • Selmier Tcf (Table 1). Activity in the play overlies the northwest to • Blocher southeast trending coalbed methane and Mesaverde pro - duction fairways. The area covers approximately 1,100 Well initial production rates and per well reserves vary square miles. The shale ranges from 500 to 1,900 feet in widely across the active area of the basin and within a thickness in the basin and averages approximately 1,500 given area or field. Reserves range from less than 100 feet thick in the fairway. Mmcf to 1.0 Bcf per well. A typical vertical New Albany The Lewis Shale is informally divided into four mem - Shale well will have an initial production of 10 to 150 bers; Otero Second Bench, Otero First Bench, Navajo City Mcfd and produce approximately 200 Mmcf of gas over a and Ute members (Dube et al., 2000). The highest perme - 30 year life. Individual well production and reserves are ability is found in the lower two-thirds of the shale which dependent on natural fracture spacing and permeability contains higher quartz content. Completions are focused (Zuber et al, 1999a). The primary completion interval is on the higher quartz-content intervals for improved reser - the Clegg Creek member of the New Albany Shale. voir quality because these zones are more prone to natural One of the longest active producing New Albany Shale fracture development (Dube et al., 2000). fields is the Shrewsbury field in west-central Kentucky, dis - Average reservoir properties for the Lewis shale are sum - covered in 1938. The average well IP is 40 Mcfd with marized in Table 2. The gas-in-place per section is esti - reserves of approximately 150 Mmcf (Zuber et al, 1999a). mated at 40 Bcf per section. The average composition of The depth to the New Albany Shale ranges from 1,400 to the Lewis Shale is approximately 25% clay and 56% 1,600 feet in the field. Production data at year-end 2005 quartz (Dube et al., 2000), and lithologically consists of showed 36 wells active with an average rate of 4 Mcfd per very fine sandstone, siltstone, and mudstone. The average well (IHS, 2006). TOC is low at approximately 1.0 wt %. Thermal maturity The New Albany Shale is still an attractive target for of the organic matter, as measured by vitrinite reflectance operators and exploration is ongoing in the play. Despite his - ranges up to 1.6 to 1.8% R o in the current active play area . toric production and periodic episodes of activity, the play Well initial production rates and reserves vary widely has not been firmly established through ongoing develop - across the active area of the play. Reserves per well range

Gas Shale in the Rocky Mountains and Beyond 22 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT from less than 100 Mmcf to 1.0 Bcf (Dube et al., 2000). A cally recoverable resource of the Barnett Shale in the Fort typical vertical Lewis Shale well will have an initial produc - Worth Basin to 26.2 Tcf (Pollastro et al., 2004a). The play tion rate of 100 to 130 Mcfd and produces approximately has continued to expand and new technologies such as hor - 300 to 500 Mmcf of gas over a 30 year life. Due to low izontal drilling have contributed to the dramatic growth of matrix permeability and low pore pressure, individual well the play. production and reserves are dependent on natural fractur - The Barnett Shale play was established in 1981 and the ing (Frantz et al., 1999). Reservoir pressure gradient in the majority of the production has been from the Newark East Lewis Shale is low (0.22 psi/ft) compared to the Barnett field. Barnett Shale development was initially focused in Shale play (0.5 psi/ft), and the rule-of-thumb average of Wise, Denton and Tarrant Counties. Technology and 0.43 psi/ft. exploration are successfully expanding the play south and The Lewis Shale continues to be an attractive play for west of the core area into Parker, Hood, Johnson and operators in the San Juan Basin. While shale-gas specific Bosque counties. The Fort Worth Basin is the second activity is difficult to track, operators are regularly adding largest shale-gas producing basin with respect to cumula - the Lewis Shale into the completions in the main produc - tive production (Table 2). Through 1994, the Barnett Shale tive fairway. Reduced spacing and commingling have was number three in annual production behind the Ohio allowed operators to more efficiently exploit this large and Antrim Shale plays (Figure 3). By 2006, Barnett Shale resource in the basin. Horizontal wells have not been annual production was more that two times the production applied to date, mainly due to the commingling of multiple of all of the other shale-gas plays combined. pays in a single wellbore and the thin pay targets within Average reservoir properties for the Barnett Shale are the thick Lewis Shale interval. summarized in Table 2. The gas-in-place per section ranges from 140 to 160 Bcf per section. This is the largest gas-in- place number for the principal gas shale plays, mainly due Barnett Shale— Fort Worth Basin to high gas saturations in the porosity, high TOC and adsorbed phase gas and a thick shale section. Total organic The Mississippian Barnett Shale in the Fort Worth Basin carbon (TOC) is present in the shale from 2 to 5%. The is one of the most active natural gas plays in the United highest concentrations of TOC in the subsurface appear to States (Figure 1). Activity levels in the Barnett Shale have follow a depocenter that is coincident with a paleo-axis of increased dramatically since 2000, from 190 completions the basin (Pollastro et al., 2003). Thermal maturity of the to over 1,300 completions in 2006. Production has also organic matter, as measured by vitrinite reflectance, varies increased significantly over this same time period, growing across the basin from approximately 0.6 to 1.9% R , going from 80 Bcf in 2000 to over 700 Bcf in 2006. Cumulative o from west to east (Pollastro et al., 2004b), but the produc - production through 2006 is estimated at 2.56 Tcf (IHS tive shale-gas play area has maturities between 1.1 and Energy, 2006). This success has spurred an increased inter - est in shale gas and the Barnett has become the type exam - 1.4% R o (Table 2). The Barnett Shale is present across ple for shale-gas exploration and the analog for the next most of the Fort Worth Basin and has a gross thickness successful play. from 200 to 700 feet. While no formal gas-in-place estimates are publically Initial production rates and reserves by well vary widely available for the Barnett, it contains the second highest across the basin, within a given area and by well type (ver - estimate for technically recoverable resources (Table 1). tical or horizontal). Vertical well initial production rates Estimating technically recoverable resource can be an elu - range from 0.5 to 2.0 Mmcfd with reserves per well from sive target as a play progresses and data and information 0.5 to 2.0 Bcf (Montgomery et al, 2005; Frantz et al., become available. The Barnett Shale is a good example of 2005). Horizontal well initial production rates range from how new technology, exploration activity and data can 1.5 to 8.1 Mmcfd and reserves per well range from 1.0 to 8 impact an existing assessment and the need for periodic Bcf (Montgomery et al., 2005, Frantz et al., 2005). Hori - new assessments. Although the play has been active since zontal well estimated ultimate recoveries (EUR) are 3.8 1981, no formal assessment was done until 1996, when the times greater that vertical well EUR’s (Frantz et al., 2005). resource potential of the Barnett was estimated to be 3.4 This multiple of well performance is the one of the primary Tcf (Schmoker et al., 1996). In 1998, an updated assess - factors that caused the dramatic increase in development ment was made that increased the technically recoverable activity in the Barnett Shale. Vertical well drilling has resource to 10 Tcf (Kuuskraa et al., 1998). Using addi - declined significantly as horizontal well drilling began in tional production data, drilling activity, expanded assess - earnest in 2003. In 2006, 223 vertical wells were drilled ment area and a more refined assessment methodology, an compared to 1,081 horizontal wells in the Barnett Shale updated assessment was made that increased the techni - play (IHS, 2006).

Gas Shale in the Rocky Mountains and Beyond 23 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

Table 3 Key properties for four emerging shale-gas plays in the U.S.

Property Fayetteville Shale Woodford Shale Caney Shale Baxter Shale

Basin Arkoma Arkoma Arkoma Vermillion/Greater Green River

Age Mississippian Devonian Mississippian Cretaceous

Depth (ft) 3,000 –5,000 5,000 –12,000 3,000 –6,000 9,500 –13,-000

Gross Thickness (ft) 200 –300 50 –220 100 –250 2,500 –3,500

Bottomhole Temp. (˚F) 100 –150

Maturation (Vr %) 1.2 –3.0 0.5 –2.5 0.6 –1.1 1.3 – >2.0

Richness (wt % TOC) 2.0 –5.0 4.0 –7.0 2.0 –8.0 1.0 –2.5

Porosity (%) 4.0 –8.0 3.0 –9.0 2.0 –12.0 3.0 –5.5

Pressure Grad. (psi/ft) 0.40 –0.44 0.40 –0.50 0.40 –0.44 0.6 –0.85

Gas In Place, Bcf/Section* 25 –65 40 –120 13 –23 ~440

Average Vertical Well EUR (Bcfe) 0.2 –0.6 2.0 –4.0*

Average Horizontal Well EUR 0.6 –2.0 3.0 –3.4 (Bcfe)

Average Well Cost ($) $5,500,000 $5,000,000

# Wells Drilled in 2006 105 50 3 12

# Producing Wells in 2006 160 90 26 14

Cumulative Production, Bcf 17 15 3.9 2.6

Emerging Producing Area Van Buren & Coal Hughes McIntosh County, Sweetwater, WY Conway Co., AR Counties, OK OK

* Baxter and Frontier

Several techniques have been used to further optimize wells by using integrated approaches to understand frac - horizontal wells and improve well performance and costs. ture initiation (Ketter et al., 2006), perforation placement These include shifting from completions using uncemented using well image tools (Waters et al., 2006) and well per - liners to cemented liners (Iiseng et al., 2005), experimenta - formance by coupling reservoir simulation and microseis - tion on fracture treatment fluid volume and proppant vol - mic technology (Mayerhofer et al., 2006). ume (Coulter et al., 2004), proppant type (Schein et al., The Barnett continues to be the most active shale-gas 2004) and fluid type (Grieser et al., 2006). Hydraulic frac - play in North America. The play will continue to evolve turing treatments are being further optimized in horizontal and expand through drilling and application of new tech -

Gas Shale in the Rocky Mountains and Beyond 24 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT

Figure 8. Fayetteville Shale production and producing well count, Arkoma Basin. Data source IHS, 2006.

niques and technologies to overcome challenges in new (Figure 8). This success has spurred an increased interest in areas in the basin. Through application and testing in the the play and expansion eastward. Operators are also Barnett shale, operators are gaining a greater understand - experimenting with the deeper Mississippian Moorefield ing of new approaches and techniques to adapt to other and Devonian Chattanooga Shales for production potential gas shale plays that are emerging throughout North Amer - (Shelby, 2006, Southwestern Energy Company, 2006). ica and accelerating the learning curve and increasing the Four fields have been established with the Fayetteville chance of success of new plays. Shale as the reservoir; Scotland, Gravel Hill, Griffin Moun - tain and Cove Creek Fields (AOGC, 2004, 2005a, 2005b, and 2005c). These fields are located in Van Buren, Conway EMERGING PLAYS and Faulkner Counties. The Arkansas Oil and Gas Com - mission (AOGC) later established a new rule (B-43) that Several new shale-gas plays are beginning to establish established drilling units for gas production from conven - production and are emerging as viable plays (Figure 1). tional and unconventional sources of gas supply not cov - Limited reservoir data are available for analysis and com - ered by field rules (AOGC, 2006). Under the statewide parison purposes. These plays are early in their develop - rules each drilling unit would consist of a governmental ment phase and the learning curve is steep. However, the section of approximately 640 acres and operators would be plays are benefiting from experience with the Barnett Shale permitted to drill up to 16 wells per drilling unit for each in the Fort Worth Basin. Table 3 summarizes available unconventional source of supply. information on the plays for comparative purposes. Average reservoir properties for the Fayetteville Shale are summarized in Table 2 and Table 3. The play is devel - oping in a depth range of slightly less than 3,000 feet deep Fayetteville Shale—Arkoma Basin to over 5,000 feet. Gross thickness of the productive sec - tion ranges from 200 to 300 feet. The gas-in-place per sec - The Mississippian Fayetteville Shale of the eastern tion is estimated to range from 25 to 65 Bcf per section. Arkoma Basin is one of the newest plays to emerge and The average composition of the Fayetteville shale is already has significant drilling activity and production. The approximately 20 to 40% clay, 20 to 60% quartz and play is being developed in the Arkansas portion of the phosphatic material present at 5 to 30% (Shelby, 2006). Arkoma basin (Figure 1). Drilling first began with one well TOC ranges from 2 to 5 wt %. Thermal maturity of the in 2003 and has grown to over 100 wells drilled in 2006. organic matter, as measured by vitrinite reflectance ranges Production has also ramped up with the increase in drilling from 1.5 to more than 4.0 % R o (Shelby, 2006 and Ratch - activity and reached 88 Mmcfd through December 2006 ford et al., 2006) in the current active play area .

Gas Shale in the Rocky Mountains and Beyond 25 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

Technologies successfully used in the Barnett Shale play towards the Reelfoot Rift and Mississippian embayment. have been adapted and applied to the Fayetteville Shale. Risks associated with greater depths and higher thermal These include reservoir characterization, microseismic maturities (>3.6 % R o) include presence of carbon dioxide mapping of hydraulic fracture treatments, horizontal wells, and destruction of reservoir quality (Ratchford et al., 2006). staged hydraulic fracturing, slick water fracturing treat - Other challenges in the play will be related to structure and ments and 3-D seismic. complexities associated with the highly faulted region. Initially, vertical wells were drilled and evaluated in the play. Initial potentials (IP) of these wells ranged from 300 to 1,500 Mcfd and ultimate recoveries were estimated at Woodford Shale—Arkoma Basin 200 to 750 Mmcf per well. An average vertical well had an IP of 375 Mcfd and reserve estimate of 300 Mmcf (South - The Devonian Woodford Shale of the Arkoma Basin is western Energy Company, 2005, Shelby, 2006). In 2005, also one of the newer plays to emerge with significant horizontal wells were drilled and tested. Results were drilling activity and production. The focus of the emerging encouraging and operators began to shift to development play is in southeastern Oklahoma in Hughes, Pittsburg and of the play from vertical to horizontal wells (Figure 9). An Coal Counties (Figure 1). This portion of the basin has average horizontal well has an IP of 2 Mmcfd and reserve multiple zones that are gas productive and have historically estimates of 1.3 to 1.5 Bcf (Southwestern Energy Company, been completed and commingled. Initial testing of the 2006, Shelby, 2006). A typical horizontal well costs Woodford Shale used vertical wells and completion of approximately $2.9 MM and includes a lateral section other reservoirs. Focused efforts began in 2003 to target 2,500 in length with 4 to 6 frac stages. Operators are the Woodford Shale and results were encouraging. The working on efficiencies and improved well economics by play has continued to develop and production at the end of drilling longer horizontal lateral sections and increasing the 2006 was approaching 80 Mmcfd from approximately 90 number of frac stages per lateral. wells (Figure 10). Operators will face challenges as they explore and test Gross thickness of the Woodford Shale in the play area the shales deeper in the basin along the southernmost por - ranges from 50 to 220 feet. Depth to the Woodford in the tions of Arkansas (Ouachita thrust front) and eastward active area ranges from 5,000 to 12,000 feet (Cardott,

Figure 9. Fayetteville Shale monthly producing well count by type, Arkoma Basin. Data source IHS, 2006.

Gas Shale in the Rocky Mountains and Beyond 26 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT

Figure 10. Woodford Shale production and producing well count, Arkoma Basin. Data source IHS, 2006.

Figure 11. Woodford Shale monthly produc - ing well count by type, Arkoma Basin. Data source IHS, 2006.

Gas Shale in the Rocky Mountains and Beyond 27 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

2006). Estimates of gas-in-place per section show a range Operators are working on efficiencies and improving from 40 to 120 Bcf. Natural fractures and high silica con - well economics by drilling longer horizontal lateral sections tent reportedly contribute to the success of the Woodford and increasing the number of frac stages per lateral. Opera - Shale play (Newfield, 2006). Clay content averages 13% tors will also be challenged to expand the play outside of and silica ranges from 50 to 90%, averaging 71% (Haines, the current three-county area and test more thermally 2006). This is higher than the Barnett Shale. Thermal immature regions of the basin. Seismic will be critical to maturity of the organic matter, as measured by vitrinite the continued success of the play. reflectance ranges from 0.8 to greater than 2.5 % R o in the current active play area (Cardott, 2006). In the early stages of the play, vertical wells were drilled Caney Shale—Arkoma Basin and evaluated. Initial potentials (IP) of these wells ranged from 50 to 2,100 Mcfd. Ultimate recoveries for vertical The Mississippian Caney Shale of the Arkoma Basin has wells have not been reported. An average vertical well had also received attention from operators working in the basin. an IP of 400 Mcfd (Cardott, 2007). In 2004, horizontal The Caney is age equivalent to the Barnett and Fayetteville wells were drilled and tested. Results were encouraging and Shales. The focus of the emerging play is also in southeast - operators began to shift to development of the play from ern Oklahoma, mainly in McIntosh County. The play has vertical to horizontal wells (Figure 11). Horizontal well not developed as much as the Fayetteville and Woodford, productivity as measured by IP’s, ranges from to 160 to mainly due to the poor initial production rates and associ - 6,840 Mcfd and average 2,100 Mcfd (Cardott, 2007). An average horizontal well has reserve estimates of 3.0 to 3.4 ated water production. Focused efforts began in 2000 to Bcf (Newfield, 2007). A typical horizontal well costs target the Caney Shale. Drilling increased in 2004-2005 and approximately $5.5 MM and includes a lateral section has fallen off since late 2005 (Figure 12). Operators are 2,500 in length with 4 to 6 frac stages (Newfield, 2007). continuing to experiment with the play and are testing the Woodford Shale horizontal wells reportedly outperform Caney to the south and west in Okfuskee, Hughes, Stephen vertical wells by 3 to 10 times, with the average horizontal and Love counties, Oklahoma. Production at the end of well IP being approximately 5.25 times greater than the 2006 was approaching 2.2 Mmcfd from approximately 26 average vertical well IP (Newfield, 2006). wells (Figure 13).

Figure 12. Caney Shale monthly producing well count by type, Arkoma Basin. Data source IHS, 2006.

Gas Shale in the Rocky Mountains and Beyond 28 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT

Figure 13. Caney Shale production and producing well count, Arkoma Basin. Data source IHS, 2006 and Cardott, 2007.

Gross thickness of the Caney Shale in the play area tion data show that vertical wells on average outperform ranges from 40 to 280 feet. Depth to the Caney in the horizontal wells. Figure 14 is a zero time production plot active area ranges from 2,800 to 4,200 feet, and the gas-in- of average well production for both vertical wells and hori - place per section ranges from 13 to 27 Bcf (Schad, 2004). zontal wells in the Caney Shale play. The Caney Shale has lower quartz content and higher clay Operators will need to work on improving well perfor - content than the Barnett, Woodford and Fayetteville Shales mance (both vertical and horizontal) for this play to (Brown, 2006; Schad, 2004), which may contribute to the develop successfully. Additional work is required to under - poorer production performance of this play compared to stand well performance based on reservoir properties and the others. Total organic carbon ranges from 2 to 8% and geologic structure. There may be potential to commingle thermal maturity of the organic matter, as measured by vit - this play with the deeper Woodford Shale in some areas of rinite reflectance ranges from 0.98 to 2.0 % R o in the cur - the basin. However, associated water production in the rent active play area (Schad, 2004; Cardott, 2006). Caney may be a limiting factor. Understanding the source Initially, vertical wells were drilled to evaluate the play. of the water being produced may also assist operators in Initial potentials (IP) of these wells range from 1 to 1,125 finding new completion techniques or areas of focus. Mcfd gas and 0 to 625 Bwpd. Ultimate recoveries for verti - cal wells have not been reported. An average vertical well had an IP of 127 Mcfd and 70 Bwpd (Cardott, 2007). In Baxter Shale— Greater Green River Basin 2005, horizontal wells were drilled and tested with less than encouraging results as compared to horizontal wells The Cretaceous Baxter Shale in the Vermillion sub- in the Fayetteville and Woodford Shales. Horizontal IP val - basin of the Greater Green River Basin is gaining momen - ues range from 2 to 500 Mcfd and 5 to 720 Bwpd. An tum as a viable shale play. The focus area of the play is average horizontal well has an IP of 285 Mcfd and 286 Sweetwater County, Wyoming and Moffat County, Col - Bwpd (Cardott, 2007). While the IP data suggest that a orado. The Baxter is equivalent to the Hilliard and Man - horizontal well is twice as good as a vertical well, produc - cos Shales regionally and grades eastward into the more

Gas Shale in the Rocky Mountains and Beyond 29 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

Figure 14. Zero time production comparison for average well vertical and horizontal wells in the Caney Shale, Arkoma Basin. Data source IHS, 2006.

Figure 15. Baxter Shale production and producing well count, Vermillion Basin. Data source IHS, 2006.

Gas Shale in the Rocky Mountains and Beyond 30 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT cal careous marine carbonates and marine shales of the immature regions (with an assumed potential for normal Niobrara formation (Finn and Johnson, 2005). The play pressured and increased oil production) of the basin and began in 2004 as operators began testing deep gas poten - non-structural areas. tial in the Nugget, Dakota, Frontier, and Baxter formations at depths from 10,000 to 15,000 feet. Initially, several older deep wells were re-entered and tested. New wells EXPLORATION / PILOT PLAYS were drilled, evaluated and commingled. Well performance and experimentation has demonstrated that the Baxter There are a multitude of shale plays that are currently Shale should be a viable new play in this area. This is sig - undergoing exploration and evaluation activity as well as nificant in that it is the deepest producing shale with early pilot completion programs. These plays have yet to depths up to 13,000 feet. The formation is also highly establish commercial production and emerge as economi - over-pressured with pore pressure gradients of 0.6 to 0.85 cally viable plays. Additional time, testing and evaluation psi/ft, (Rattie and Parks, 2006). Production at the end of will be needed to determine their viability. Table 4 is a 2006 is estimated at 4.0 Mmcfd from approximately 14 summary of the plays discussed in this section, highlighting wells (Figure 15). formation name, geologic age and estimated drill depths. Gross thickness of the Baxter Shale in the play area Figure 1 shows the location of the majority of these plays ranges from 2,500 to 3,500 feet, (Rattie and Parks, 2006). as well. The gas-in-place per section is estimated at 440 Bcf (Rattie and Parks, 2006). No X-ray composition data has been released to date on the Baxter Shale in the play area to Eastern U.S. evaluate clay and non-clay components. Operators report more silt-rich or fine-grained quartz-rich intervals within Several new plays are being evaluated in the eastern the formation and the presence of natural fractures as key United States, predominately within the Appalachian and to enhanced productivity. The middle member of the Bax - Black Warrior Basins. ter Shale appears to be a major contributor to well produc - In the Appalachian Basin, exploration activity has been tion, however other completion intervals also contribute to focused on the Ordovician Utica Shale. Current activity is overall flow. Total organic carbon ranges from 1 to 2.5% located in the northern portion of the basin in New York and thermal maturity of the organic matter, as measured by and has extended across the border into Canada. The vitrinite reflectance ranges from 1.3 to over 2.0 % R o in Ordovician Shale ranges in thickness from approximately the current active play area (Rattie and Parks, 2006, Finn 150 feet to over 1,000 feet moving from west to east in and Johnson, 2005). New York. The Utica is typically considered the source Vertical wells have been the primary wells drilled to date rock for the Lower Devonian through Cambrian produc - to evaluate the play. Initial potentials (IP) ranges from 1 to tive sections. Drilling depths range from outcrop to over 7 Mmcfd gas and ultimate recoveries for vertical wells have 9,000 feet in the southern most part of the state. No gas been estimated with limited data at 2.0 to 4.0 Bcf (Questar, production in commercial quantities has been reported to 2007a). The formation also produces associated conden - date from the Utica Shale. sate. Multiple frac stages are being pumped in the vertical Two shales have been the recent focus of activity in the Baxter Shale wells, up to 7 stages per well. In 2007, the Black Warrior Basin (Figure 1). The first is the Mississip - first horizontal wells have been drilled in the middle mem - pian Floyd Shale. It is believed to be an analog to the Bar - ber of the thick Baxter Shale with encouraging results. Nat - nett and Fayetteville Shales and is similar in terms of age ural fractures are reported to be critical to this play and and setting along the Appalachian –Ouachita tectonic front. have been identified in cores and from well logs (Questar The shale lies at target depths of 4,000 to 7,500 feet and is 2007b). approximately 200 to 800 feet thick. Recognized as a As the play progresses, operators will need to improve probable oil source rock in the Black Warrior Basin, it con - their understanding of key production mechanisms, and tains TOC in excess of 3 percent and has a thermal matu - improve well economics through efficiency and optimiza - rity ranging from 0.92 to 1.6 % R o (Pawlewicz and Hatch , tion of operations with expansion of the productive area. 2007). Drilling has focused in Pickens and Lamar Coun - Seismic will likely be a critical factor for continued success ties, Alabama. No commercial production has been of the play by locating sweetspots and/or natural fractures. reported to date (Alabama Oil and Gas Board, 2007a). Well economics and performance may be enhanced by con - The second shale exploration target in the Black War - tinuing to expand on the early success of horizontal wells. rior Basin is the Cambrian Conasauga Shale. Activity has Operators will also be challenged to expand the play out - concentrated in St. Clair County, Alabama. Drilling began side of the current productive area and test more thermally in 2005 and through 2006 approximately 9 wells were

Gas Shale in the Rocky Mountains and Beyond 31 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

Table 4 Other U.S. shale-gas plays being evaluated for commercial potential

Shale Basin Age Drill Depth (feet)

Utica Shale Appalachian Ordovician 1,000 –10,000 Floyd Shale Black Warrior Mississippian 4,000 –10,000 Conasauga Shale Black Warrior Cambrian 3,000 –10,000 Bend Shale Palo Duro Pennsylvanian 7,000 –10,500 Woodford Shale Permian Devonian 10,000 –15,000 Barnett Shale Permian Mississippian 7,500 –14,000 Wolfcamp Shale Permian Permian 5,000 –14,000 Pearsall Shale Maverick Cretaceous 6,000 –9,000 Mancos Shale Uinta Cretaceous 12,000 –16,000 Hillard Shale Greater Green River Cretaceous 10,000 –18,000 Gothic Paradox Pennsylvanian 5,000 –10,000 Cane Creek Paradox Pennsylvanian 9,000 –12,000

drilled. Production has been established from several wells In northwest Texas, operators are drilling and complet - and in February 2007, Big Canoe Creek Field was recog - ing wells in the Pennsylvanian Bend Shale. In addition, the nized by the Alabama State Oil and Gas Board, encom - Permian Wolfcamp Shale is being targeted for evaluation. passing 40 square miles with 320-acre drilling units Drilling depths range from 7,000 to 10,500 feet and the (Alabama State Oil and Gas Board, 2007b). Drilling gross thickness of the shales range from 500 to 1,000 feet. depths range from 3,400 feet to 9,023 feet (the formation Gas-in-place is estimated at 80 to 180 Bcf per section is steeply dipping). Initial flow rates reported to the Board (Bankers Petroleum, 2007). Drilling and testing is ongoing range from 26 Mcfd to 233 Mcfd (Alabama State Oil and in Floyd and Motley Counties, Texas. Secondary zones are Gas Board, 2007b). also being evaluated in order to assist in achieving viable Challenges for the play include well bore deviation, lost well economics. circulation and formation damage. Well deviation will be a West Texas is the focal point for exploration aimed at challenge with regard to drilling and completing wells in repeating the success of the Barnett Shale in the Fort Worth the play due to the steeply dipping beds caused by folding Basin. In the Delaware Basin, the Barnett is thicker, has and faulting. Thrust faults are the principal faulting mecha - higher gas-in-place and is significantly deeper. Large nism in the area and can cause exaggerated thickness in the acreage positions have been established by operators and section (Alabama State Oil and Gas Board, 2007b). The drilling is ongoing to test the commercial viability of the formation is also reported to be water-sensitive mainly due Barnett and Woodford Shales at depths from 7,500 to to reported high clay content, and is thus being drilled with 15,000 feet. In addition, the Permian Wolfcamp Shale is air (Alabama State Oil and Gas Board, 2007c). also being evaluated. Activity is focused in the Delaware Basin—Reeves, Culberson and Ward Counties, Texas—and Eddy County, New Mexico. Gross shale thickness ranges Texas from 400 to 1,000 feet. Currently there are a wide range of gas-in-place estimates (100 to 1,000 Bcf per section), indi - Several shale-gas plays are being actively evaluated by cating the early nature of the play (Abraxas, 2007; Chesa - drilling and testing in Texas. These include the Bend and peake, 2007). The depth of the shale is one of the major Wolfcamp shales in the Palo Duro Basin, the Barnett Shale challenges along with completing multiple pay intervals in and Woodford Shales in the Delaware Basin (western Per - vertical or horizontal wells. Initial production rates have mian Basin) and the Pearsall Shale in the Maverick Basin. been high, but have quickly declined in wells completed to

Gas Shale in the Rocky Mountains and Beyond 32 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT date. Operators will need to develop an independent bore was unsuccessful. A second completion was done in approach to this play and break free of the Fort Worth the upper Hilliard resulting in gas flow rates of 1.5 Mmcfd model. for six days (Questar, 2006). The completion was later The Cretaceous Pearsall Shale in the Maverick Basin of abandoned due to high costs. To date, no additional work south Texas is actively being explored for shale-gas poten - has been reported on the Hilliard Shale in the area. tial. Pearsall Shale production was established in the Los In the Paradox Basin fold and fault belt, Paleozoic shales Cuatros Field (Maverick County, TX) in the 1970’s prior are being evaluated for shale-gas potential. Both the Penn - to the new completion and hydraulic fracturing technolo - sylvanian Gothic and Cane Creek Shales are seeing gies. Wells averaged approximately 450 Mmcf in reserves. renewed interest in southwestern Colorado and eastern While it is too early to tell if the play will be successful, Utah. operators are drilling wells, collecting data and testing new The Gothic Shale of the Hermosa Formation, lying just completion technologies to unlock the potential in the above the Paradox Salt, is being targeted from depths of shale. Gas-in-place is estimated at 100 to 300 Bcf per sec - 5,500 to 7,500 feet in Dolores and Montezuma Counties, tion in the 600 to 700 feet thick shale (TXCO, 2007). Colorado. Thickness is reported at 100 to 150 feet. Several Drilling depths range from 6,000 to 9,000 feet. wells have been drilled and evaluations are underway using There are several other basins and potential shale-gas logs, core and production testing. plays being evaluated in the region. Organic-rich shales in Within the thick Pennsylvanian Paradox Salt section, the Marfa Basin (TXCO, 2007) and the Bossier Shale in there are interbedded clastic cycles containing organic-rich East Texas are being evaluated for shale-gas potential. source rocks with established hydrocarbon production. Ini - tial hydrocarbon production was established from the Cane Creek Shale of the Alkali Gulch zone in the early Rocky Mountain Region 1960’s. Here the Cane Creek is an overpressured, self- sourced oil reservoir. Operators attempted to develop the The Rocky Mountain region is rich in natural gas Cane Creek oil potential into the early 1990’s with limited resources and shale-gas reserves could further increase the success. region’s production. Several shale systems are being evalu - Recently, gas production has been tested from the Cane ated across multiple basins including the Cretaceous Creek interbedded clastic cycles approximately 25 miles Hilliard, Mancos and Niobrara Formations as well as the north of the oil productive area in Grand County, Utah. Pennsylvanian-age shales in the Paradox Basin. Several wells have been drilled and tested with positive The Cretaceous Mancos Shale is a deep target in the results. Short term gas flow rates have been reported from Uinta Basin. With well depths going down to 14,000 to 2.0 Mmcfd to 4.5 Mmcfd and 500 to 125 barrels of con - 16,000 feet, multiple pay zones (tight gas and shale) are densate per day (Delta, 2007). Within the 3,500 to 4,000 targeted for evaluation including the Dakota, Mancos, foot thick salt section, 12 to 15 zones are present with pay Blackhawk, Mesa Verde and Wasatch Formations. Well potential. Initial information on the play indicated the costs range from $7 to $8 million during the initial evalua - presence of overpressure, reserve potential of 2.7 to 5.8 tion phase and include testing multiple play types. Long Bcfe, well costs at $3.0 to $3.5 million, and average well term production has not been established, however prelimi - depths of 9,800 feet (Delta, 2007). Additional drilling and nary reserve estimates range from 3 to 6 Bcfe (Questar, testing are ongoing in the area to further evaluate the 2007c). The majority of this activity is centered in Uintah extent and viability of the play. A pipeline will need to be County, Utah. constructed to get the gas to market. In southwest Wyoming, the Upper Cretaceous Hilliard As exploration continues in shale-gas plays, operators Shale was a deep shale-gas target in the prolific Pinedale are drilling more complex geologic environments and Field in late 2005. Age-equivalent to the Baxter Shale, the drilling deeper shales. Many of the emerging and explo - Hilliard Shale was penetrated from 16,000 to 19,500 feet ration plays discussed here highlight some of the challenges and large gas shows were encountered with extreme over - of unlocking deep shale-gas potential (Figure 16). These pressuring (19,000 to 20,000 psi). Casing was set on the challenges include: well and a three stage hydraulic fracturing treatment was done on a 900 foot interval from 18,500 to 19,400 feet. • Overpressure Initially the completion flowed back strongly, gauging gas at 10.7 Mmcfd for 32 hours at 12,000 psi flowing casing • Formation stability pressure before the flow was stopped by formation plug - • Wellbore casing integrity ging of the wellbore (Questar, 2005). The completion was abandoned in 2006 and an attempt to clean out the well - • Completions in vertical and horizontal wellbores

Gas Shale in the Rocky Mountains and Beyond 33 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

Deeper shale plays will also have a different mix of gas tion, subtle trapping mechanisms, primary permeability storage mechanisms compared to the principal shale-gas from natural fractures and interbedded lithologies and seals plays that are at depths of 2,000 to 8,000 feet. Since gas of variable lithology. Shale-oil reservoirs are typically a storage by adsorption is inversely proportional to tempera - dual porosity system where oil is primarily stored in the ture, deeper shale plays will contain significantly less gas natural fracture network and intergranular porosity. stored by this mechanism. This is further compounded by As with shale-gas, unconventional fractured shale-oil the reduced TOC of deeper shale plays due to thermal mat - plays have also seen an increase in activity over the past uration. Deeper shales are, however, typically overpres - decade. Horizontal wells have been a key technology to sured, increasing the amount of gas stored as free gas in the help unlock this large hydrocarbon resource. Figure 1 high - porosity and natural fracture system. lights many of the shale-oil plays with established produc - tion. These include the following: FRACTURED SHALE-OIL PLAYS • Mississippian Bakken Shale, Williston Basin Fractured shale-oil plays are typically characterized as • Pennsylvanian Cane Creek Shale, Paradox Basin organic-rich, self-sourced, naturally fractured reservoirs often associated with structures (Mallory, 1977). Productive • Devonian Woodford Shale, Anadarko Basin intervals can also be associated with interbedded lithologies • Cretaceous Mancos Shale, Piceance and San Juan Basins such as siltstones or other non-shale facies. The producing (mostly conventional) plays may be underpressured or overpressured, and conven - tional or unconventional accumulations. Unconventional • Miocene Monterey and McClure Shale, California shale-oil plays are characterized by widespread oil satura - basins (mostly conventional)

Figure 16. Average drill depth to select U.S. shale-gas plays.

Gas Shale in the Rocky Mountains and Beyond 34 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT

• Eocene Green River Shale, Uinta Basin (mostly conven - The lines may be blurring between what is considered a tional) shale-gas reservoir and other play types. One such area is tight-gas sand reservoirs. Operators are now evaluating the In addition, there are several Rocky Mountain region reservoir system in stacked tight gas sand plays, especially Cretaceous shale-oil plays that have historically been pro - in plays that have thick sections / sequences of sands and ductive. They include the Pierre Shale in Colorado, the siltstones interbedded with shales. These include prolific Niobrara Formation in Colorado, and the Mowry Shale in reservoirs such as the Lance Formation at Jonah Field and Wyoming. In the Gulf Coast Region, the Cretaceous on the Pinedale Anticline and the Bossier Shale play in east Tuscaloosa Shale has been touted to have significant oil Texas. How do the interbedded shales contribute to gas-in- potential, yet to be realized (Chacko et al., 2005). place, long term deliverability and reserves? Considering the Niobrara Formation as a fine-grained source rock also puts chalks and marlstones in the mix of shale plays. What UNRECOGNIZED / FORGOTTEN PLAYS defines a play as a shale-gas play is less critical than what makes a shale-gas play productive. There are numerous gas plays that might be character - ized as forgotten, misunderstood or simply uncharacter - ized using today’s resource play terminology. They can be described as gas-productive fine-grained source rocks. CANADA SHALE-GAS ACTIVITY They include the shallow biogenic gas play in the North - ern Great Plains (Gammon or Pierre), and the Niobrara North of the U.S. border, exploration for shale-gas is Formation gas play in eastern Colorado. The Niobrara growing at a fast pace. While still early in the exploration play is divided into the thermogenic gas play in Watten - and characterization phase, activity is occurring across berg Field of the central Denver Basin and the shallow Canada from British Columbia to Quebec. No commercial biogenic gas play on the eastern flank of the Denver production has been reported to date. The Gas Technology Basin. Institute published one of the first studies of the shale-gas The Cretaceous Niobrara Formation was deposited dur - potential of Canada, reporting an estimated 860 Tcf of ing a major marine transgression in the Western Interior gas-in-place in selected shales in the Western Canada Sedi - Seaway and covers a large portion of the Rocky Mountain mentary Basin (Table 6) (Faraj et al. 2002). No estimates of region. The Niobrara is rich in organic carbon and con - technically recoverable resource have been published. This tains significant carbonate material. The lithology of the is a reflection of the early stages of assessment in Canada. formation was controlled by many factors during its depo - In 2006, the Geologic Survey of Canada published a sition and ranges from siliciclastic-rich intervals in the report on the “shale-gas concept” in Canada (Hamblin, western part of the seaway to chalk and marlstone in east - 2006). The study reviewed 50 shale units in 7 regions ern Colorado (Longman et al., 1998). across the country. Sixteen units are considered to be Table 5 compares the shallow biogenic Niobrara play prospective on a regional scale to justify further study. The to the biogenic Antrim Shale play and the deeper thermo - author further defined 7 regional plays that have excellent genic Niobrara play to the Barnett Shale play in the Fort geologic potential in addition to proximity to infrastruc - Worth Basin. There are several similarities and differences ture and potential analogs (Table 7). based on the listed properties. However, the Niobrara pro - Exploration activity is being conducted in British ductivity is lower than the Antrim or Barnett and is likely Columbia, Alberta, Saskatchewan and Quebec. This work related to lithologic differences as well as other geologi - is being carried out by well-known companies as well as cally controlled parameters. Both Niobrara plays are eco - focused junior oil and gas companies. Table 8 summarizes nomic and have been under development for a number of some of the ongoing activity across Canada (Roche, 2006). years. In Wattenberg Field, the Niobrara is one of three Success in Canada will depend on several factors. While primary pay intervals that are completed and where pro - analogs are important, making direct comparison to U.S. duction is commingled. The two other reservoirs are the plays may be misleading. Factors such as thermal maturity, Cretaceous Codell and J Sand, both tight gas sands. The shale mineral composition, clay type, fluid saturations and primary pay target in the shallow Niobrara play on the fluid sensitivities will require unique solutions to overcome eastern plains is the 45 foot thick upper chalk member commercial barriers. Some plays are in mature producing called the Beecher Island, and production is associated regions with proximity to infrastructure; others are remote with small structural features that are naturally fractured. and will require significant investment for services and Cumulative production from both plays combined exceeds transportation to market. 1 Tcfe.

Gas Shale in the Rocky Mountains and Beyond 35 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

Table 5 Comparison of thermogenic and biogenic Niobrara shale-gas play types with Barnett and Antrim shale plays

Thermogenic Biogenic

Property Barnett Shale Niobrara Antrim Shale Niobrara

Basin Fort Worth Denver Julesberg Michigan Denver Julesberg

Age Mississippian Cretaceous Devonian Cretaceous

Discovery Year 1981 1980 1940 1912

Depth (ft) 7,000 –8,500 6,600 –7,500 500 –2,500 1,000 –3,000

Gross Thickness (ft) 200 –400 300 –400 160 300 –400

Bottomhole Temp. (˚F) 200 220 –250 75 80 –105

Maturation (Vr %) 1.1 –1.4 0.9 –1.4 0.6 –0.7 0.30 –0.60

Richness (wt % TOC) 2–5 1–6 5–15 0.4 –6

Mineralogy (% Non-Clay) 45 –70 80 55 –70 95 –70

Porosity (%) 3–7 5.0 –10.0 5–12 30 –40

Gas Content (scf/ton) 30 –80 15 –40 40 –100 Undefined

Pressure Grad. (psi/ft) 0.5 0.55 –0.65 0.43 0.2 –0.3

Gas in Place, Bcf/Section 140 –160 100 –120 6–15 0.9 –6.2

Avg. Vert. Well EUR (Bcfe) 1.4 0.10 –0.30 0.75 0.15 –0.35

Avg. Hz Well EUR (Bcfe) 2.5 na na na

Cummulative Gas Production 2,560 696 2,481 423 1978 2006,* (Bcfe)

Historic Producing Area Wise Co., TX Wattenberg Field, Otsego Co., MI Beecher Island Field, Weld Co., CO Yuma Co., CO

* IHS, State agencies and independent estimates.

Gas Shale in the Rocky Mountains and Beyond 36 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT

Table 6 and in situ stress. While it is useful to debate and evaluate Gas-in-place for selected shales in Western Canada the role of natural fractures in developing a shale-gas play, Sedimentary Basin. From Faraj, et al., 2002 it is difficult to discount their role in many of the existing plays, especially when considering shale matrix permeabili - ties that have been measured and reported by industry are Formation Gas-In-Place (TCF) at or below the nanodarcy range. Not all natural fractures Wilrich and Equivalnets 156 are beneficial, as fractures and other geologic discontinu - ities such as faults can play a detrimental role by acting as Duvernay 377 flow barriers or by providing a hydrodynamic link to water Doig Phosphate 129 that is either above or below a potential productive system. Doig 10.7 Figure 17 is a depiction of key elements in a shale-gas play. No values or relative measure is provided to indicate Montney 187 success. Principal, emerging and exploration shale-gas Total 859.7 plays described here demonstrate the wide range of proper - ties that may make or break a play. A maximum value for all of the primary elements does not guarantee a commer - cial play. Rather it is the mix or unique relationship of the elements in a given basin setting that defines the productiv - PRODUCTION MECHANISMS ity, extent and viability of a potential shale-gas play. Tech - nology must also be recognized as critical to unlocking a The key production mechanisms that will work in play and allowing it to develop beyond the boundaries of shale-gas plays are extremely difficult to generalize. Hill restrictive sweetspots to a larger area. This expansion is and Nelson (2000) described several key properties com - vital for repeatability and scale, thereby improving project mon to a shale-gas play. They characterize differences in economics and supporting continued development. the principal plays, thermal maturity, adsorbed gas percent - age, gross thickness, TOC and gas-in-place and stress that each play is unique and must be examined, explored and CONCLUSIONS exploited differently. There are other properties that likely contribute to how shale-gas plays produce, including U.S. natural gas production first began from organic- matrix and bulk permeability, pore pressure, mineralogy rich shale, and given the large, technically recoverable

Figure 17. Elements of a successful shale-gas play.

Gas Shale in the Rocky Mountains and Beyond 37 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

Table 7 Canadian shale prospects identified for serious consideration and study. Data source Hamblin, 2006

Groups, Members/ Kerogen Region Age Formations Type Play Type

Eastern Canada Middle/Upper Ordovician Macasty –Vaureal l/ll A/B Utica/Lorraine ll/lll A/B Collingwood/Blue Mtn. ll A/B

Middle/Upper Devonian Marcellus ll/lll A/C Kettle Point ll/lll A

Western Canadian Middle/Upper Devonian Duvernay –Ireton ll A/B Sedimentary Basin North Muskwa/Fort Simpson/ ll/lll C/D Interior Platform Besa River Exshaw/Bakken/Banff ll/lll A/B

Lower/Middle Triassic Montney/Grayling/ ll/lll A/D Phroso/Vega Doig/phosphatic/Toad ll B Whistler

Lower/Upper Jurassic Nordegg/Gordondale l/ll C/D Fernie/Rierdon

Lower Cretaceous Wilrich/Moosebar/ lll D Clearwater/Ostracod/ Buckinghorse

Middle/Upper Cretaceous Lower Colorado ll/lll A/D Upper Colorado l/ll/lll A/D

Upper Cretaceous Lea Park/Pakowki/ lll A/D Nomad/Pembina

North Mainland Upper Devonian –Upper Bluefish/Har Indian ll/lll B/C Carboniferous

A=Antrim Shale B=Ohio/New Albany Shale C=Barnett Shale D=Lewis Shale

Gas Shale in the Rocky Mountains and Beyond 38 The Rocky Mountain Association of Geologists UPDATE ON NORTH AMERICAN SHALE -G AS EXPLORATION AND DEVELOPMENT

Table 8 Canadian shale-gas activity. Data source Roche, 2006

Province Area Shale Zone Age Company

British Columbia Ootla Devonian-Cretaceous Apache Canada British Columbia Tuppe Montney Triassic Bear Ridge British Columbia Hudson’s Hope Gething Cretaceous Spirit Resources British Columbia Kotcho Lake Devonian-Cretaceous ConocoPhillips British Columbia Fort Nelson Devonian-Cretaceous EOG Resources British Columbia Fort Nelson Devonian-Cretaceous EnCana British Columbia Swan Montney Triassic EnCana British Columbia Blair Creek Kereco British Columbia Bag Jedney Devonian-Cretaceous Petro-Canada Alberta Viking-Kinsella Cardium Cretaceous ConocoPhillips Alberta Wainwright Viking Cretaceous Husky Alberta Wildmere Colorado Upper Cretaceous Stealth Ventures Saskatchewan Foam Lake Colorado Upper Cretaceous PanTerra Energy/Stealth Ventures Saskatchewan Moose Jaw Colorado Upper Cretaceous PanTerra Energy/Stealth Ventures Saskatchewan Shell Lake Cretaceous PanTerra Energy/Stealth Ventures Quebec Gaspe Utica Ordovican Junex Quebec Utica Ordovican Talisman Energy

Modified from Roche, 2006

resource base and long life of a typical well, shale-gas may with technology to improve well performance, and per - represent one of the Lower-48 States’ last remaining signifi - sistent testing of the nature and limits of the sweet spots. cant onshore natural gas resources. The five principal and four emerging shale-gas plays dis - • Exploration plays will require comprehensive datasets cussed in this paper exhibit wide ranges of key geological, for evaluation, extended testing, new insights and tech - geochemical and engineering parameters, but each play nologies to unlock the vast potential of the gas-in-place produces commercial quantities of natural gas. Still, opera - and new models for successful exploitation. tors face considerable challenges in unlocking the vast resource potential of shale-gas across North America and It is apparent that new technologies have also played a bringing substantially more of this gas to market: critical role in expanding industry’s understanding of shale- gas plays and unlocking their potential. These technologies • Mature plays will require new technologies to assist include advances in hydraulic fracturing, horizontal drilling operators in expanding the play boundaries, reducing and reservoir characterization. Operators and service com - well spacing, lowering overall well costs and improving panies have adapted, modified and created new approaches gas production rates and well reserves. to exploration and development of shale reservoirs through innovation and trial and error. This will need to • Emerging plays will require more detailed information continue to meet or exceed the production forecast shown on geologic and reservoir parameters to fully understand in Figure 4. production mechanisms, continued experimentation

Gas Shale in the Rocky Mountains and Beyond 39 The Rocky Mountain Association of Geologists David G. Hill, John B. Curtis, Paul G. Lillis

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Gas Shale in the Rocky Mountains and Beyond 42 The Rocky Mountain Association of Geologists