AUTHORS

Anna M. Martini � Department of Geology,Amherst College, Amherst, Massachusetts 01002;ammartini@amherst.edu

Anna M. Martini received her B.A. degree in ge-ology from Colgate University, her M.S. degreefrom Syracuse University (1992), and her Ph.D. fromthe University of Michigan (1998). She is currentlyan associate professor of geology at AmherstCollege. Her research interests include unconven-tional natural gas plays, isotopic tracing of mi-crobial pathways, and the geochemistry of salinefluids.

Lynn M. Walter � Department of GeologicalSciences, University of Michigan, Ann Arbor,Michigan 48109; lmwalter@umich.edu

Lynn M. Walter received her M.S. degree from Loui-siana State University (1978) and her Ph.D. fromthe University of Miami (1983). She was an assistantprofessor at Washington University in St. Louis until1988. She then joined the University of Michigan,where she is now a professor of geological sciencesand director of the Experimental and AnalyticalGeochemistry Laboratory. Her research interestsfocus on the hydrogeochemistry of near-surface anddeeper basin environments, with emphasis oncarbon transformations and mineral mass transport.

Jennifer C. McIntosh � Department of Hy-drology and Water Resources, University ofArizona, Tucson, Arizona 85716;mcintosh@hwr.arizona.edu

Jennifer C. McIntosh received her B.A. degree ingeology-chemistry from Whitman College and herM.S. degree and her Ph.D. in geology from theUniversity of Michigan (2000 and 2004). She is cur-rently an assistant professor at the University ofArizona. Her research interests include hydrogeo-chemical controls on microbial methane generationin organic-rich sediments, origin and transport ofsaline fluids, and impacts of past climate change onmodern groundwater resources.

ACKNOWLEDGEMENTS

We acknowledge Tim Ku, John Hanson, and NateDiedrich for fieldwork assistance. This project wassupported by Gas Research Institute grant 00/0158to Walter and Martini, American Chemical Society-Petroleum Research Fund grant 361133 GB2 toMartini,and Research Partnership to Secure Energy for Amer-ica grant R-520 to Martini. We thank Steven Creamey,William Harrison, and Jeanie Ridgley for theirthoughtful and thorough reviews of the manuscript.

Identification of microbial andthermogenic gas componentsfrom Upper Devonian blackshale cores, Illinois andMichigan basinsAnna M. Martini, Lynn M. Walter, andJennifer C. McIntosh

ABSTRACT

Differentiation ofmicrobial versus thermogenicmethane in coalbed

and black shale accumulations can affect strategies for exploration

and may influence the total gas content in a given area. Early iden-

tification of these processes from crushed core materials, even be-

fore formation fluids and produced gas samples are available, could

permit a more efficient and cost-effective exploration. Total gas

contents and compositional and isotopic data from New Albany

Shale core materials are presented, which delineate regional occur-

rence of microbial, thermogenic, and mixed gas generation in the

Illinois Basin. These trends are consistent with those identified from

detailed prior studies of produced gas and water chemistry from the

same locations. Themost usefulmarkers formicrobial gas in crushed

core gases are elevated CO2 contents characterized by high d13CCO2

values (>5x). Core gas analyses from wells in which microbial gas

is identified commonly have significantly more total gas absorbed

than do core samples from wells producing gases solely of thermo-

genic origin. These observations are independent of variations in

sample depth and organic carbon content in a given core. Thus, this

integrated case study of core and produced gases in the Illinois Basin

illustrates that the areas containing microbial gas, in addition to

early thermogenic gas, may be more productive than pure thermo-

genic zones for these early to immature unconventional gas deposits.

GEOHORIZONS

AAPG Bulletin, v. 92, no. 3 (March 2008), pp. 327–339 327

Copyright #2008. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received April 21, 2006; provisional acceptance July 11, 2006; revised manuscript receivedMay 9, 2007; final acceptance October 18, 2007.

DOI:10.1306/10180706037

INTRODUCTION

Unconventional gas accumulations, such as those found

in fractured shale-gas or coalbed plays, commonly con-

tain both thermogenic and microbial gas components.

Strategies for exploration and development depend on

where each system falls along this gas compositional

spectrum (Curtis, 2002; Schurr andRidgley, 2002). For

a predominantly microbial gas play, the hydrologic

framework is critical, and basin margins, where the or-

ganic matter is less mature and fractures more open,

should be targeted. For a predominantly thermogenic

unconventional gas accumulation, explorationwill focus

on deeper, more thermally mature sections of a basin

where formation water chemistry is irrelevant to de-

lineating the play. The Upper Devonian Antrim and

New Albany shales (Figure 1) are emblematic of the

issues of thermogenic versus biogenic exploration. Both

basins contain variousmixtures of these gases, although

in the Antrim Shale, the productive wells are focused

along the northern margin where the gas is predomi-

nantly microbial, whereas in the New Albany Shale,

microbial, mixed, and thermogenic gases are produced

from different parts of the basin. In both basins, pre-

vious studies have employed awide array of geochemical

and isotopic analyses on both the gas and coproduced

water to determine the origin of the produced gas. The

most diagnostic geochemical variables have been shown

to include the following:

1. Alkalinity and d13C of dissolved inorganic carbon

(DIC) in the coproduced water

2. d2H of methane and coproduced water

3. d13C of carbon dioxide

Other common indicators, such as the d13C of

methane and the ratio of C1/[C2 + C3], have proven

somewhat unreliable in these unconventional reservoirs

where a host of secondary effects occurs and the micro-

bialmethane generated commonly has high d13C values

(approximately �48x) that overlap early thermogenic

methane values (Whiticar, 1999; Martini et al., 2003).

The identification and, thus, exploration strategies

for these resources, would be expedited if the determi-

nation of gas origin could be made as early as possible,

before well completion. This article explores the iden-

tification of microbial and thermogenic gas components

from core materials, including well cuttings, whole core,

and sidewall cores where available. The Antrim and

New Albany shales are excellent testing grounds be-

cause detailed geochemical and isotopic data for gas and

water from both basins have clearly defined regions of

microbial, thermogenic, and mixed gas production.

Background

The New Albany and Antrim shales are organic rich

(up to�16 wt.% total organic carbon [TOC]) and range

from immature in sections of the Antrim (Ro = 0.45%)

to early maturity (Ro = 0.5–0.7%) in the New Albany

black shales (Dellapenna, 1991). The NewAlbany Shale

total gas content (TGC) has been estimated to range

from 86 to 160 tcf in the Illinois Basin (Hill and Nelson,

2000).Approximately 200wellswere drilled in theNew

Albany Shale during the most recent phase of develop-

ment (Hill andNelson, 2000), increasing the total num-

ber of wells drilled to about 800. Most of this activity

has been aimed at developing the unconventional black

shale gas play along the shallow eastern margin of the

Illinois Basin (Figure 1a). Wells drilled to the south in

northwesternKentucky contained thermogenic gas asso-

ciatedwith the Shawneetown–RoughCreek fault zone.

The number of wells drilled in the New Albany

Shale is sparse compared to the number of wells drilled

in the Antrim Shale, northern Michigan. Currently,

more than 12,000 producing wells are present in the

northern producing trend (NPT) of the Antrim Shale.

Of these, most wells have been shown to produce domi-

nantlymicrobial gas (Martini et al., 1996, 1998).Micro-

bial gas exploration has also expanded to the western

and southern margins of the Michigan Basin. Antrim

Shale wells in the central Michigan Basin and eastern

basin margin contain thermogenic gas and highly saline

formation waters (>5 mol/L Cl�). However, these

wells were abandoned because of low production rates,

and the purely thermogenic gas targets in the Antrim

Shale in the Michigan Basin have not proven to be eco-

nomically successful (Martini et al., 2003).

In the Michigan Basin, the Cl� content of Antrim

Shale formation waters in northern Michigan increases

sharply from less than 0.1mol/L near the shale subcrop

to greater than 5 mol/L, approximately 75 km (46 mi)

basinward (Figure 1b). A similar salinity gradient is ob-

served along the southern margin of the basin. The vari-

able Cl� content in the Antrim Shale likely reflects

mixing of dilute meteoric waters and highly saline Na-

Ca-Cl basinal brines. During times of glacial loading,

as recently as the late Pleistocene, hydraulic gradients

were reversed, and freshwaters recharged into evaporite-

bearing Silurian–Devonian aquifers along the basin

margins and dissolved large quantities of halite. These

NaCl-rich Pleistocene waters then migrated vertically

328 Geohorizons

into the overlying fracturedAntrimShale (Martini et al.,

1998; McIntosh and Walter, 2005). High salt concen-

trations in shale fluids severely inhibit many micro-

bial populations, includingmethanogens (Zinder, 1993;

Ollivier et al., 1994), as evidenced by the decreasing al-

kalinity values and mole percent CH4 in wells basin-

ward of the NPT (Martini et al., 1998).

In the Illinois Basin, New Albany Shale formation

waters are much less saline than fluids in the Antrim

Shale; the maximum salinity of New Albany Shale

waters is less than 2.5 mol/L Cl� (Figure 1b). Illinois

Basin fluids, overall, are approximately half the salinity

of Michigan Basin brines, and no extensive evaporite

deposits are present in the Illinois Basin. A strong, north-

to-south suppression of salinity in the New Albany Shale

exists, with dilute meteoric waters (<0.3 mol/L Cl�)

located hundreds of kilometers from the basin margin

and up to 800 m (2600 ft) depth. Microbial gas accu-

mulations are generally located in areas that received

meteoric recharge along the margins of the Michigan

and Illinois basins, driven by Pleistocene glacial loading

and/or modern topographic gradients.

Figure 1. Upper Devonian fractured black shale gas plays in the Illinois and Michigan basins. (a) The New Albany and Antrim shalesubcrops are shown in black, along the margins of the Illinois and Michigan basins, respectively. The shale gas fields are highlightedin gray. Most of the gas wells (>8000) are located in the northern producing trend (NPT), along the northern margin of the MichiganBasin. The Antrim Shale subcrop beneath the Great Lakes is also shown in light gray. (b) Contour map of Cl� concentration of NewAlbany and Antrim shale formation waters overlain on the shale subcrops. Most of the New Albany Shale formation waters containless than 2 mol/L of Cl� , whereas Antrim Shale fluids are much more saline, with Cl� values ranging from less than 1 to greater than6 mol/L. M = mol/L.

Martini et al. 329

Hydrogeologic Framework of Upper Devonian FracturedBlack Shales

The hydrogeology of the Illinois and Michigan basin

margins has been a key factor in the migration of fluids

and hydrocarbons and the generation of unconvention-

al shale gas resources (Figure 2). The New Albany and

Antrim shales are highly fractured and may be hydro-

logically connected to over- and underlying units. The

shales are underlain by the Silurian–Devonian regional

aquifer system, composed primarily of permeable car-

bonates. The Silurian–Devonian carbonates subcrop

along a wide band across the margins of the Michigan,

Illinois, and Appalachian basins. In the arches region

between the basins, the Silurian and Devonian carbon-

ates contain relatively dilute meteoric waters that are

Holocene to Pleistocene in age (McIntosh and Walter,

2006).Downgradient in the basins, a sharp freshwater–

saline water mixing zone is present, where salinity rap-

idly increases.Melting of kilometer-thick ice sheets during

the Pleistocene enhanced recharge of meteoric waters

into the Silurian–Devonian aquifers along the basinmar-

gins and suppressed the freshwater–saline water mixing

zone to great depths. These dilute fluids then migrated

into the overlying fractured black shales and promoted

the generation of microbial gas (Martini et al., 1998;

Martini et al., 2003; McIntosh and Walter, 2005).

The New Albany and Antrim shales are confined

by overlying Mississippian gray shales and siltstones

(Figure 2b, c). In south-central Indiana, the Mississippian

Borden siltstone prevented fluid mixing between the

shale and the overlyingMississippian carbonate aquifer

system. Dilute waters in the New Albany Shale in this

region likely migrated from the underlying confined

Silurian–Devonian aquifer system. In southern Indiana–

northern Kentucky, the Borden siltstone rapidly thins

and is absent in some areas, and the Mississippian car-

bonates directly overlie the shale. Here, recent mete-

oric waters likely recharged into the New Albany Shale

through overlying highly permeable Mississippian car-

bonates, driven by modern topographic gradients (Mc-

Intosh et al., 2002).

Thick glacial drift deposits overlie theAntrimShale

subcrop along the northern margin of the Michigan Ba-

sin (Figure 2b). Modern recharge of meteoric waters in

northern Michigan is restricted to the shallow glacial

drift and bedrock aquifers; most of the Antrim Shale

formationwaters are greater than7000 yr old and are not

Figure 2. Hydrogeologic framework of the New Albany and Antrim shale gas plays along the margins of the Illinois and Michiganbasins, respectively. (a) Geologic map of regional aquifers and confining units in the Illinois, Michigan, and Appalachian basins. TheUpper Devonian fractured black shales are shown in black, underlain by the regionally extensive Silurian–Devonian carbonateaquifer system and overlain by Mississippian shale confining units. (b) Geologic cross sections through the Antrim Shale gas playalong the northern margin of the Michigan Basin, and (c) the New Albany Shale gas play along the eastern margin of the IllinoisBasin (modified from McIntosh et al., 2002).

330 Geohorizons

in communication with shallow flow systems (Martini

et al., 1998; McIntosh and Walter, 2006).

New Albany Shale Salinity and Thermal Maturity

The salinity pattern of New Albany Shale formation

waters shows a dramatic invasion of dilute waters

(<0.3 mol/L Cl�) into the shale from the north, as

shown by the striking north-to-south salinity gradient

and the presence of dilute waters so far basinward from

the shale subcrop, up to about 800 m (2600 ft) depth

(Figure 3a). The Cl� content of shale formationwaters

does not increase systematically with lateral distance

from the shale subcrop as would be expected for re-

charge from the arcuate shape of the shale subcrop. A

secondminor axis of lower salinity waters (<1.5 mol/L

Cl�) is apparent along the southeastern margin of the

basin. The underlying Silurian–Devonian aquifer system

shows an evenmore pronounced north-to-south depres-

sion in salinity. In contrast, fluids in the overlying Mis-

sissippian aquifer system display a markedly different

salinity pattern, with chloride concentrations simply in-

creasingwith distance from the carbonate subcrop. The

Borden confining unit separates the Mississippian car-

bonate aquifers from the underlying NewAlbany Shale

and Silurian–Devonian aquifers. Microbial gas produc-

tion in the New Albany Shale is greatest along the east-

ern margin of the basin, where dilute waters have in-

vaded the fractured shale through either the underlying

Silurian–Devonian aquifer system, during Pleistocene

glaciation, ormore recently through the overlyingMissis-

sippian carbonates along the southern basinmarginwhere

the Borden Group is absent (McIntosh et al., 2002).

The New Albany Shale has low thermal maturity

across the eastern margin of the Illinois Basin, with vi-

trinite reflectance values less than 0.6% (Figure 3b). At

vitrinite reflectance values lower than 0.6%, thermal

gas generation is not thought to occur in economic vol-

umes (Waples, 1981; Tissot et al., 1987). However, in

mixed type I and type II kerogen environments, such as

the Antrim Shale, thermogenic gas generation has been

recorded and evidenced by the generation of significant

quantities (�5–10 mol vol%) of ethane and propane in

wells that producemore than100mcf/day (Dellapenna,

1991). In the northern producing zone of the Antrim

Shale, vitrinite reflectance is below 0.5%, although in

the basin center, it rises to approximately 1.1 (Decker

et al., 1992; Rullkotter et al., 1992). Thus, hydrostra-

tigraphy and recharge history of basin margins, in ad-

dition to shale burial depth and maturation, appear to

be the major controls on occurrence of microbial gas in

these fractured organic-rich shales (Krumholz et al.,

2002; McIntosh et al., 2002).

Gas Storage Mechanisms

The New Albany Shale and the Antrim Shale are both

unconventional reservoirs in which the gas is generated

and stored in situ. Little evidence exists in either basin

of large-scale gas migration because the close relation-

ships between hydrogen isotope values of produced

methane and coproduced formation waters require a

genetic link (Martini et al., 1998, 2003). It has been

estimated for the Antrim Shale that about 70–75% of

the produced gas is desorbed from organic matter and

clay within the shale, the remainder coming from po-

rosity and fractures within the shale (Frantz, 1995–

1996). The strong absorption of the various gas compo-

nents in the shale matrix leads to the following related

phenomena:

1. Gas must be produced by lowering of pressure at

the borehole.

2. Gas is less likely to have migrated.

3. In-situ reservoir conditions control microbial pro-

duction and consumption of hydrocarbons.

4. Absorption properties of gases vary (for example,

CO2 is sorbed much more strongly than CH4).

Most studies on gas absorption have concentrated

on coalbed reservoirs (Arri, 1992; Toth, 1997;Cui et al.,

2004). These gas deposits sharemany isotopic and com-

positional features with those found in the New Albany

and Antrim shales and are also unconventional in that

the gas is produced and stored in situ (Scott et al., 1994).

The CO2 fraction is more strongly sorbed initially, but

as pressures decline with continued production, an in-

creasingly greater percentage of CO2 is desorbed.How-

ever, studies of the isotopic composition of the various

fractions as desorption proceeds have shown little change

in isotopic composition (i.e., fractionation of only 1–

2xwith desorption andmigration) (Zhang andKrooss,

2001). Therefore, whereas this mechanism has a tre-

mendous effect on the various gas concentrations (in

mole volume percent) being produced over time from

a given well, the isotopic composition of the CH4 and

CO2 should remain nearly the same. For core gas data

discussed herein, the differences between production

gas and crushed gas chemistries are partially explained

by this phenomenon.

Martini et al. 331

DISCUSSION

Regional Trends in New Albany Shale CoproducedFormation Waters and Gas Composition

The New Albany Shale wells can be divided into three

subgroupsbasedon formationwater andgas composition,

depth, and location within the Illinois Basin (Figure 4).

NewAlbany Shale formationwaters in group 1 (Silurian

shelf) have lowCl� values (<1.5mol/L, Figure 4a) and

a pronounced north-to-south depression in the salinity

gradient, similar to underlying Silurian–Devonian car-

bonate aquifers. Glacial meltwaters recharged the frac-

tured shale and adjacent carbonate aquifers during times

of ice-sheet advance from the north. In the Silurian shelf

region of the basin, the New Albany Shale is confined

by the Borden Group, which prevents communication

of fluids between the New Albany Shale and the over-

lyingMississippian aquifer system.Group1waters have

variable concentrations of DIC, ranging from less than

4 to greater than 16 mmol/L (Figure 4b). Waters with

high DIC or alkalinity values (>6 mmol/L) and posi-

tive d13C values of DIC (> +20x) are indicative of

microbial methanogenesis.

Theoccurrence ofmicrobial activity in group 1wells

is associated with high CH4 and CO2 concentrations

of produced gases. Log C1/C2 values for group 1 wells

range from1 to 2.5 (Figure 4c).Microbial gas (CH4 and

CO2) has high log C1/C2 values, whereas thermogenic

gas commonly contains more ethane (C2), decreasing

the log C1/C2 value. However, secondary processes

such as microbial oxidation of higher chain hydrocar-

bons (thermogenic gas) can increase the log C1/C2 to

values similar to that of microbial gas. Methane is also

oxidized; however, because it commonly comprises the

bulk of the gas from these wells, an equal decrease in

concentration will lead to higher log C1/C2 ratios.

New Albany Shale wells in group 2 (Mississippian

recharge) are located along the southeastern margin of

the basin.Here, the BordenGroup is thin or absent, and

Mississippian carbonate aquifers directly overlie the

shale. These fluids have lowCl� contents (<1.5mol/L)

Figure 3. (a) Salinity gradient of New Albany Shale formation waters superimposed on the shale subcrop. Dark circles indicate wellssampled (modified from McIntosh et al., 2002). (b) Vitrinite reflectance values of the New Albany Shale with well control shown (Hill,2000).

332 Geohorizons

like group 1 (Figure 4a); however, their d18O values are

similar to modern precipitation. Group 2 waters con-

tain high DIC values (>16 mmol/L) and high CH4 and

CO2 concentrations, indicative of microbial methano-

genesis (Figure 4b, c). Most of the group 2 wells have

log C1/C2 values greater than 2.25.

New Albany Shale waters in group 3 (basin brine)

havehighCl� concentrations (1.5–3.0mol/L, Figure 4a)

Figure 4. Spatial trendsof New Albany Shale for-mation water salinity, DICcontent, gas C1/C2 ratios,and location of casinggas and core samples.(a– c) New Albany Shalewells are divided intothree geochemically dis-tinct groups. Group 1:Silurian shelf wells containrelatively dilute formationwaters (Cl� < 1.5 mol/L),with variable DIC values(<4 to >16 mmol/L), andhigh methane concentra-tions ( log ratio of C1/C2 =1–2.5). Group 2: Missis-sippian recharge wells arealso relatively dilute (Cl�

< 1.5 mol/L), with high DICvalues (>16 mmol/L) andhigh methane concentra-tions ( log ratio of C1/C2 >2.25). Group 3: basin brinewells contain highly salinefluids (Cl� > 1.5 mol/L),no measurable DIC, andlow log C1/C2 ratios (<1.1)because of higher concen-trations of ethane. (d) Wellcontrol for casing gas sam-ples (shown in dark andopen circles), crushed coresamples with gas composi-tion (counties highlightedin light gray), and the twowells with isotope compo-sition of the crushed gassamples (shown in whitediamonds) (modified fromMcIntosh et al., 2002).

Martini et al. 333

and low d18O valueswithin the range of remnant evapo-

concentrated Illinois Basin brines. These waters have

not been significantly diluted by meteoric recharge.

Group 3waters also have no detectableDIC (Figure 4b),

typical of saline basinal fluids with no microbial activity.

Group 3wells have low logC1/C2 values (0.9–1.7,most

<1.0; Figure 4c) with relatively high concentrations

of ethane and propane (2.4–7.8% C2H6, 0.2–3.1%

C3H8). The highest DIC and log C1/C2 values in the

New Albany Shale, thus, are associated with regions

inundated by meteoric water recharge (low Cl� con-

centrations) along the northeastern and southeastern

margins of the Illinois Basin (groups 1 and 2). This sug-

gests an important link between meteoric recharge and

generation of significant accumulations ofmicrobial gas.

Here,wepresent newcrushed core gas analyses from

New Albany Shale wells, showing distinct geochemical

trends consistent with the formation water and pro-

duced gas compositions of the three groups.NewAlbany

Shale casing gas sample locations are shown in the dark

circles in Figure 4d (data published in Hill, 2000; Mc-

Intosh et al., 2002). Counties where we have crushed

core samples are highlighted in light gray, and twowells

with isotope composition of the crushed gas samples are

shown in white diamonds (data presented in Table 1).

Sidewall core samples were crushed, and the gas was

collected by Terratek Inc. and analyzed for gas concen-

trations and isotopic values at either Isotech Laborato-

ries or by Barbara Sherwood-Lollar at the University of

Toronto.

New Albany Shale Rock Properties and Gas Compositions

The relationship betweenTGC(scf/t) andTOC(wt.%)

from individual core analyses are shown for the three

different NewAlbany Shale groups in Figure 5a. Multi-

ple paired analyses were performed on each well (Hill,

2000). The range in TOC is similar among the threeNew

Albany Shale groups, but the TGC values are highest at

Figure 5. Total gas content (TGC) versus (a) TOC content and (b) depth for crushed core gas samples from the three New AlbanyShale subgroups (Hill, 2000).

334 Geohorizons

an equivalent TOC content for group 1 cores. The TGC

does not vary significantly with depth (Figure 5b). In-

stead, the highest TGC values are found in the areas

where water and gas geochemistry identify microbial

generation of gas. This suggests that hydrogeologic en-

vironment may be more important than shale burial

depth and maturation variation in explaining gas con-

tents. This, in turn, reflects areaswherewater chemistry

indicates microbial activity.

Examination of TGC and organic content in cores

from two wells from the Silurian recharge zone, one in

Clay County and one in Martin County, demonstrates

a significant difference between individual wells even

within one zone (Figure 6). Bothwells are at nearly the

same depth and are thus under similar pressure regimes,

assuming hydrostatic pressure, yet have very different

relations betweenTOCandTGC.Each individualwell’s

data set typifies the excellent correlation between TGC

and TOC (r2 = 0.876 and 0.934, respectively). How-

ever, the slopes are quite different from each other (m=

2 for the Clay County well; m = 5.8 for the Martin

County well). For a given value of TOC, the core in

Martin County contains nearly three times as much

gas as the well in Clay County. Microbial generation

of methane in Martin County is likely more significant

than in Clay County, a theory that is supported by the

water chemistry in these two areas. The DIC in Clay

County wells is, on average, 7 mmol/L, whereas the val-

ue in Martin County is about 13 mmol/L. Roughly, it

seems that a doubling in DIC, a robust indicator of

microbial activity, leads to an approximate doubling

in the TGC in the core.

Table 1. Core Gas Data from New Albany Shale Wells

ID

Depth

(ft)

Cannister

Gas*Crush

Gas

Total

Gas C1** C2 C3 CO2

*** d13C� C1 d13C� C2 d13C� CO2

Meade County Sampley

1 937 20.96 70.1 91.06 92.42 0.97 0.65 5.55

3 939 7.35 61.72 69.07 90.22 0.96 0.65 7.35 �50.3 �42.8 11.3

5 942 13.25 51.32 64.57 86.29 1.69 2.47 7.96 �48.4 �43.7 10

6 947 11.15 43.78 54.93 55 6.23 11.98 5.01

7 955.5 5.81 27.66 33.47 86.38 0.82 0.83 10.23 �50.8 �41.8 2.6

8 958 6.12 30.35 36.46 53.32 5.43 10.6 8.01

10 971 7.02 23.25 30.28 31.23 16.12 14.32 nd

12 982 8.21 30.26 38.47 43.05 20.23 17.25 nd

14 1002.5 4.01 30.8 34.8 43.05 16.02 12.68 5.99

15 1009 5.85 38.62 44.46 54.22 18.52 12.91 8.01 �52.3 �45.8 9.7

Edmonson County Sampleyy

1 1730 7.57 42.65 50.22 50.64 21 19.91 nd �49.13 �46.17

3 1719 7.16 34.95 42.11 49.08 20.37 20.15 nd �51 �46.51

5 1701 9.29 32.98 42.27 43.97 22 22.34 nd �50.82 �46.66

7 1684 6.76 45.83 52.59 56.52 20.56 16.48 nd �50.11 �46.8

9 1669 7.37 34.19 41.56 52.39 20.67 18.26 nd �50.45 �46.72

11 1650 9.89 58.62 68.5 57.4 22.56 14.49 nd �50.73 �47.31

13 1632 7.03 51.65 58.68 55.3 23.18 15.69 nd �50.61 �47.13

15 1612 6.03 29.28 35.31 53.49 22.64 16.36 nd �51.35 �47.37

17 1598 7.32 52.09 59.41 58.02 22.86 12.69 nd �50.24 �47.46

19 1591 8.49 57.46 65.96 59.66 22.8 12.2 nd �48.85 �47.18

22 1576 10.28 56.39 66.67 54.51 23.96 15.89 nd �49.23 �46.68

*Gas content in standard cubic feet per ton.**All concentrations are in mole volume percent.***nd = not detected.yMeade gas samples were analyzed by Isotech Inc.yyEdmonson gas samples were analyzed by Barbara Sherwood-Lollar at the University of Toronto.

Martini et al. 335

Variation in Composition and TGC amongHydrogeochemical Groups

Compositional analyses of gases released from core crush

studies were available for several wells throughout the

New Albany Shale trend from industrial core evalua-

tions. Depth profiles of mole percent values for meth-

ane, ethane, and propane are shown in Figure 7 for

typical cores from each of the three New Albany Shale

groups and from the NPT in the Antrim Shale. Carbon

dioxide values are also plotted where available. Wells

in groups 1 and 2 have variable methane mole percent,

with the highest values found at the top of the Clegg

Creekmember of the shale.WhereCO2 values are high,

ethane and propane values are lower because of either

the dilution from the influx of microbial gas or the an-

aerobic oxidation of the higher chain hydrocarbons from

microbial activity. The representative well from group 3

has the lowest mole percent of methane, which remains

constant with depth. The ethane and propane mole

percent is also greater in group 3wells than group 1 or 2.

This profile and compositions are indicative of the purely

thermogenic origin of the gas from thesewells. Themore

variable compositions of gas from groups 1 and 2 wells

suggest microbial enclaves, with the greatest addition

of microbial gas at the top of the New Albany, where

fluid flow may be enhanced, and the TOC content is

the highest.

In comparison, Antrim Shale gas compositional pro-

files from the NPT (Figure 7d) are roughly the same

throughout both the Lachine and Norwood organic-

richmembers.However, unlike the thermogenic profile

in group 3 wells, the Antrim core samples show high

CO2 concentrations and virtually no higher chain hy-

drocarbons. Here, themicrobial addition to the TGC is

universal and not confined to microenvironments.

A comparison of gas chemistry and TGC versus

depth highlights the geochemical differences between

thermogenic, microbial, and mixed zones of produc-

tion (Figure 7). Total gas contents are highest in zones

where microbial gas has been identified. Depth does

not seem to be predictive of TGC because core samples

from the Antrim Shale have roughly the same TGC (in

standard cubic feet per ton) as New Albany Shale wells

in groups 1 and 2 and more than wells in group 3, al-

though the depth, and thus, hydrostatic pressure, is far

lower. These differences between basins may be attrib-

utable to the degree of microbial methanogenesis.

If the microbial generation of gas is increasing the

overall volume of gas present in the shale, the d13Cvalues of carbon dioxide from crushed core materials

should increase relative to TGC. In Figure 8, the pres-

ence of microbial gas in a group 2well (Meade County)

is clearly demonstrated by the high d13C values overall.

The link between TGC and d13CCO2suggests that the

addition of microbial gas to this reservoir is econom-

ically significant.

Value of Refined Core Gas Composition and IsotopeAnalyses: A Case Study

During this study, sidewall core samples became avail-

able for two wells, one located in the group 2 area and

one from the group3area.These samples, obtainedwithin

the organic-rich zones of each reservoir, were crushed,

and the gas was collected and analyzed for both isotopic

composition and gas chemistry (Table 1). The C iso-

topic composition of methane and ethane extracted

from the crushed core samples is compared to that of

produced gases fromwells near the core sample location

(Figure 9).

The variation in d13CC2versus ethane concentra-

tion indicates that microbial oxidation is occurring in

the core and the produced gas from the field in Meade

County (group 2, Mississippian recharge). This process

accounts for both the decrease in the amount of ethane

Figure 6. Total gas content versus TOC content for two NewAlbany Shale cores located at similar depths along the easternmargin of the Illinois Basin (group 1: Silurian shelf) (Hill, 2000).The slopes (m) of the linear trend lines are shown for reference.The locations of the two wells shown in this figure are high-lighted in Figure 4 (open circles).

336 Geohorizons

Figure 7. Profiles of crushed core gas composition and TGC versus depth for representative wells in the three New Albany Shalesubgroups and one Antrim Shale well from the NPT in northern Michigan (Hill, 2000). Carbon dioxide concentration was not measuredin the Daviess County core (top panel).

Martini et al. 337

and the isotopic shift as microbes metabolize ethane

with low d13CC2values first. In contrast, ethane con-

centrations from the Edmonson County well (group 3,

basin brine) are invariant and have values typical of early,

thermogenic natural gas. The isotopic composition of

methane is not as consistent between core and casing

gases, with the produced gas having lighter isotopic val-

ues. This suggests that more microbial gas is present in

the produced gas, likely from the contribution of free

gas affected by the continuing active generation of mi-

crobial methane.

The integration of core crush gas analyses with

production casing gas compositions yields considerable

insight into the gas generation mechanism. It is impor-

tant to include CO2 measurements on all core crush

analyses in the early stages of exploration. Isotopic com-

positions of CO2 and ethane are also very useful on both

core and casing gases because these are especially sen-

sitive indicators of microbial and thermogenic gas gen-

eration, respectively.

CONCLUSIONS

The results of this study confirm the utility of the in-

tegrated geochemical analyses of produced water, gas,

and corematerials fromnaturally fractured organic-rich

shales. Taken together, the series of investigations of

the Devonian black shale gas resources (Martini et al.,

1996, 1998, 2003; Walter et al., 1996, 1997, 2001; Mc-

Intosh et al., 2002, 2004) provide valuable insight into

the development of these gas accumulations. Under-

standing the hydrogeology, recharge history, and salin-

ity patterns of fluids in fractured black shale and coalbed

plays places constraints on the likely areas of microbial

methane generation and may guide future drilling ef-

forts. Specifically, the following analyses are key in de-

termining the presence of methanogenesis and are sug-

gestive of the abundance of microbial methane in core

samples:

1. Crushed gas composition, especially carbon dioxide

concentrations

2. d13CCO2of the gas

Figure 8. Carbon isotope composition of CO2 versus the TGCin the crushed New Albany Shale core sample from a well inMeade County, Kentucky (group 2: Mississippian recharge).

Figure 9. Comparison of carbon isotope values and molepercent of methane and ethane in casing (produced) gas versuscrushed core gas from two New Albany Shale wells. One well islocated in Meade County, Kentucky (group 2: Mississippianrecharge), the other well is located in Edmonson County, Kentucky(group 3: basin brine).

338 Geohorizons

3. Coupled TOC and TGC analyses on core materials

4. d13CCH4and d13CC2H6

of the gas

With these analyses, making estimates of both mi-

crobial and thermogenic gas components as well as

delineating the areas where microbial generation of

methane is occurring are possible.

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