2.2 Non-conventional gas - Treccani, il portale del sapere

2.2.1 Introduction

DefinitionThe expression non-conventional gas, historically,

has meant many different things to differentgovernments, organizations, and public/privatebusinesses. Early distinctions in the USA(mid-1970s) were based primarily on economics:sub-economic to marginally- economic gas resourceswere termed non-conventional or unconventional.The term non-conventional gas (and unconventionalgas) began to gain widespread use in the late 1970sin the USA as a result of the US Government’sNatural Gas Policy Act of 1978 and the Crude OilWindfall Profits Tax Act of 1980, which provided taxincentives for businesses to encourage energyconservation and the production of alternative energysources, including non-conventional gas (NPC,1980). Recently, geologic distinctions have beensuggested to identify non-conventional gas. In thiscategorization, conventional gas resources arebuoyancy-driven deposits whereas non-conventionalgas resources are not buoyancy-driven (Law andCurtis, 2002). These non-conventional resources areregionally pervasive and often independent ofstructural or stratigraphic traps. So, what exactly isnon-conventional gas?

Numerous reservoirs and gas deposits havebeen associated with the term non-conventionalgas. These include: a) natural gas in coal, i.e., CoalBed Methane (CBM), coal gas, coal seam gas, andCoal Bed Natural Gas (CBNG); b) natural gas inshale/mudstone, i.e., shale gas, gas shale, andDevonian shale gas (in the eastern USA); c) naturalgas in low permeability clastic deposits (tight sandgas, tight sandstone gas, or tight gas); d ) biogenicnatural gas in conventional reservoirs; e) naturalgas hydrate (methane hydrate); f ) natural gas in

municipal solid waste (landfill gas, biogenic gas);g) natural gas in geo-pressured aquifers; h) naturalgas in naturally fractured igneous andmetamorphic rock; and i) natural gas in deepclastic or carbonate formations (�6,000 m).Although all of these reservoirs or deposits may beidentified as non-conventional gas, currently fourprimary reservoir types are the focus of theinternational natural gas exploration andproduction industry: coalbed methane, shale gas,tight gas, and gas hydrate. Tight gas hastransitioned during the last 20 years to beconsidered a more traditional (albeit lowpermeability) conventional gas reservoir; andcoalbed methane and shale gas are presented indetail below. Gas hydrate is the subject of the nextchapter in this volume and therefore is notdiscussed in detail here.

Historical developmentSerendipitous historical examples exist of

commercial production from coal and gas shalereservoirs: shale gas production from a well drilledin 1821 in the Dunkirk Shale of western New York,USA (Broadhead, 1993), and coal gas productionfrom the Pittsburgh coal in the Big Run Field ofnorthern West Virginia, USA, in the early 1920s(Patchen et al., 1991). However, the large-scale,worldwide commercial development ofgas-charged coal and shale reservoirs as sources ofnatural gas is a recent development in the worldhydrocarbon industry.

Prior to the mid-1970s, attempts had been madeworldwide to recover the methane that is containedin coal. These were primarily conducted within acoal mining environment (underground) andfocused on the removal of the methane from thecoal to enhance mine safety and coal mining

57VOLUME III / NEW DEVELOPMENTS: ENERGY, TRANSPORT, SUSTAINABILITY

2.2

Non-conventional gas

productivity. Generally, these attempts employedthe use of horizontal (or angled) boreholes thatwere drilled from within the mine workings intothe mined coal seam or adjacent seams and strata.Beginning in the mid-1970s, research efforts in theUSA began exploring the possibility of applyingoilfield technology to the removal of gas from coalseams.

The advantage of these new approaches, whichconsisted of drilling vertical wells from the surfaceinto the coal seam(s), was that it permitted theremoval of methane from the coal seam in advanceof mining operations (using vertical, hydraulicfracture-stimulated wells). Initial attempts usingthese techniques at coal mines in the Warrior andAppalachian Basins, USA, and in virgin, un-minedareas of the San Juan Basin, New Mexico, USA,were successful. Moreover, this success wastwofold: not only was the methane readilyrecovered from the coal seam in advance of miningor in the gob areas, but also the recovery rates werehigh enough to be considered commercial. As aresult, the first modern commercial production ofmethane from coal seams in the USA began. Thefirst instance was in 1977 in the San Juan Basin,New Mexico, USA (at Amoco ProductionCompany’s Cedar Hill Field in a virgin coal areanot in conjunction with a mining operation). Thesecond was in 1981 in the Black Warrior Basin,Alabama, USA (at the USS Mining Company’sOak Grove Mine and at the Jim Walter Resource’s

No. 4 and No. 5 Mines). Thus, the commercialcoalbed methane industry in the USA was initiated(Boyer and Qingzhao, 1998).

Coalbed methane development and productionhave increased dramatically during the past twodecades. Beginning from a few wells in the late1970s, the industry grew slowly, such that by themid-1980s less than 100 wells were commerciallyproducing coalbed methane in the USA. However,during the late 1980s through 2004, the industryunderwent a rapid expansion. By the end of 2004,over 23,000 wells were producing natural gas fromcoal seam reservoirs, with an annual productionrate of approximately 4.8�1010 m3 or a rate ofapproximately 13�108 m3 per day (Fig. 1).

Shale gas production was initiated in the USAin 1821 near the town of Fredonia, New York.Peebles (1980) stated: “The accidental ignition bysmall boys of a seepage of natural gas at the nearbyCanadaway Creek brought home to the localtownspeople the potential value of this ‘burningspring’. They drilled a well 27 feet (8 m) deep andpiped the gas through small hollowed-out logs toseveral nearby houses for lighting. These primitivelog pipes were later replaced by a three-quarter inch(1.9 cm) lead pipe made by William Hart, the localgunsmith. He ran the gas some 25 feet (7.5 m) intoan inverted water-filled vat, called a ‘gasometer’and from there a line to Abel House, one of thelocal inns, where the gas was used for illumination.In December 1825 the Fredonia Censor reported:

58 ENCYCLOPAEDIA OF HYDROCARBONS

HYDROCARBONS FROM NON-CONVENTIONAL AND ALTERNATIVE FOSSIL RESOURCES

annu

al C

BM

pro

duct

ion

(109

m3 )

prod

ucin

g C

BM

wel

ls

0

10

20

30

40

50 gas production

producing wells

60 22,000

20,000

18,000

16,000

14,000

12,000

10,000

8,000

6,000

4,000

2,000

0

1981

1982

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1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

Fig. 1. Growth in coalbed methane production and number of producing wells in the USA, 1981 to 2004 (Anderson et al., 2003).

‘We witnessed last evening burning of 66 beautifulgas lights and 150 lights could be supplied by thisgasometer. There is now sufficient gas to supplyanother one [gasometer] as large’. Fredonia’s gassupply was acclaimed as: ‘unparalleled on the faceof the globe’. This first practical use of natural gasin 1821 was only five years after the birth of themanufactured gas industry in the United States,which most commentators agree was marked by thefounding of the Gas Light Company of Baltimore(Maryland) in 1816”.

Development of these Devonian-age organicshale formations spread throughout this region ofthe eastern USA during the remainder of the 19th

and beginning of the 20th century. In 1921 thediscovery well for the Big Sandy Field was drilledinto the Devonian Ohio Shale in eastern Kentucky,USA, producing up to 2.8�104 m3 per day. By themid-1930s this field was recognized as the largestgas accumulation in the USA (Ley, 1935).

USA government- and industry-sponsoredgeological, geochemical, and petroleumengineering studies in shale gas were initiated inthe mid-1970s and continued through the early1990s. Results of this work led to the furtherexpansion of the shale gas industry into theDevonian Antrim Shale of the Michigan Basin(Michigan, USA), which became commerciallyproductive in the late 1980s. Subsequent to this,commercial development of the Cretaceous LewisShale of the San Juan Basin and the Mississippian

Barnett Shale of the Fort Worth Basin (Texas,USA) was initiated in the 1990s (Curtis, 2002).The number of shale gas wells and the annualproduction in the USA has increased annually, buthas recently seen a more rapid growth (Fig. 2) dueto the production success of the Barnett Shale,currently one of the most prolific gas reservoirs inthe USA. Current production is approximately3.5�107 m3 per day with over 3,700 producingwells. Since 1981, the total gas produced from thefield is estimated at almost 4.0�1010 m3. In 2004alone, the Barnett Shale produced over 1.0�1010 m3

making it the largest gas field in the state of Texas,USA (Frantz et al., 2005).

World resourcesMany researchers have evaluated the coalbed

methane potential of most of the majorcoal-bearing regions and countries of the world(Kuuskraa et al., 1992). Boyer (1994) presented asummary of this work, which is shown in Table 1.As seen in this table, the overall size of the naturalgas resource that is contained in the coal depositsof the world is significant: 83.4�1013 m3 to263.3�1012 m3. Accordingly, coalbed methanerepresents a major new international source ofnatural gas. While initial interest has focused onthe major coal-bearing countries, many countrieshave small but significant quantities of coalbedmethane. Individual plays in small basins,particularly those close to markets for the gas, may


NON-CONVENTIONAL GAS

annu

al s

hale

gas

pro

duct

ion

(109

m3 )

prod

ucin

g sh

ale

gas

wel

ls

0

5

10

15

20gas production

producing wells

25

1979

1980

1982

1981

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35,000

30,000

25,000

20,000

15,000

10,000

5,000

0

Fig. 2. Growth in shale gas production and number of producing wells in the USA, 1979 to 2004 (Curtis, 2002).

provide commercially attractive opportunities foroperators (Boyer et al., 1992).

Conversely, the world’s shale gas resources arenot as well understood. Estimates of the shale gasresources in the five producing basins in the USA(Table 2) range from 14�1012 m3 to 22.1�1012 m3.Significantly more gas is estimated to occur withinthe 12 other identified gas shale formations in theUSA (Hill and Nelson, 2000), but no estimate ofthe volume has been made to date. A 2002 estimateof the shale gas resources of the western Canadasedimentary basin by Faraj indicated greater than2.4�1012 m3 of gas in place (Faraj et al., 2002). Aninitial assessment of the shale gas potential of theUnited Kingdom (Selley, 2005) identified potentialreservoirs, but no volumetric estimates wereprovided. To date, no detailed estimate of the shalegas resource in the shale formations throughout theworld has been made.

2.2.2 Reservoir fundamentals

OverviewUnlike conventional reservoirs, coal and shale

are the source, trap, and reservoir for natural gas.

Methane (and other gases-heavier hydrocarbons,carbon dioxide, water, nitrogen, and others) isgenerated in-situ from the transformation oforganic matter, and exists as both free gas in themicropores and sorbed gas on the reservoirsurface. The matrix permeability of coal and shalereservoirs is extremely low; because of this,secondary natural fracture permeability is requiredfor commercial production. Coal gas reservoirscontain an orthogonal fracture set called cleats thatare perpendicular to bedding and provide theprimary conduit for fluid flow. In gas shalereservoirs, tectonic fracture sets provide thisconduit. Gas flows from the matrix to the fracturesby a combination of diffusion and Darcy flow.

Production profiles for coal and shale gas wellsusually differ from those of conventional reservoirs.In a typical coal gas reservoir, the cleats are initiallyfilled with water that must be produced to lower thepressure in the cleat system. This causes gas todesorb at the coal matrix-cleat interfaces, creating amethane concentration gradient across the coalmatrix. Thus, gas diffuses through the matrix and isreleased into the cleat system. Over time, theproduced water volume decreases (due to relativepermeability effects) and the gas rate increases.However, in some isolated cases, coal reservoirs aredry and require no dewatering. As productionmatures, shrinkage of the coal matrix can increasethe absolute permeability of a coal gas reservoirseveral-fold and accelerate gas production. In gasshale reservoirs, which typically contain a larger freegas component than coal reservoirs, methane andwater are usually produced simultaneously. Asreservoir pressure decreases, gas begins to desorbfrom the organics in the matrix to supplementproduction of the free matrix gas and reduce the gasproduction decline rate.



Table 1. Summary estimates of world coalbed methaneresources (Boyer, 1998)

Country/RegionCoalbed methane resource,

1012 m3 (trillion ft3)

China 30.0-35.1 (1,060-1,240)

Russia 17.0-113.3 (600-4,000)

United States 9.7-11.7 (343-414)

Australia 8.5-14.2 (300-500)

Canada 5.7-76.5 (200-2,700)

Germany 2.8 (100)

Poland 2.8 (100)

United Kingdom 1.7 (60)

Ukraine 1.7 (60)

Kazakhstan 1.1 (40)

India 0.8 (30)

Southern Africa 0.8 (30)

Other 0.8 (30)

Total 83.4-263.3 (2,953-9,304)

Table 2. Summary estimates of shale gas resourcesin historically productive plays in the USA

(Curtis, 2002)

Basin Shale formationShale gas resource,

1012 m3 (trillion ft3)

Appalachian Ohio Shale 6.4-7.0 (225-248)

Michigan Antrim Shale 1.0-2.2 (35-76)

Illinois New Albany Shale 2.4-4.5 (86-160)

Fort Worth Barnett Shale 1.5-5.7 (54-202)

San Juan Lewis Shale 2.7 (97)

Total 14-22.1 (497-783)

Both coal gas and gas shale reservoirs arecontinuous gas accumulations. These are reservoirsystems where gas-bearing strata are notdensity-stratified, do not contain a gas-watercontact, and persist over a very large geographicalarea. The challenge in these accumulations is toidentify the most prospective (potentiallyproductive) areas and to efficiently appraise anddevelop them. A useful first step in this process is tocompare the characteristics of prospective areas tothose of existing commercial projects for coal gas

and gas shale reservoirs (Tables 3, and 4; see againTable 2). Successful projects have many similarities,including concentrated gas resources, sufficient gasrates, and access to technologies and markets.

Coal as a reservoir

Coal composition Coal is a chemically complex, combustible

solid consisting of a mixture of altered plantremains. Organic matter comprises more than



Table 3. Summary reservoir and production characteristics of four coalbed methanefields in the USA

Basin San Juan Uinta Black Warrior Powder River

Target play Fairway Drunkard’s Wash Cedar CoveRecluse/Rawhide

Butte

Area (km2) 1,000 500 200 200

Wells 600 400+ 500 1,000

Gas production rate(m3/d/well)

70,800 15,000 4,000 4,000

Reserves (106 m3/well) 85-140 40-110 15-40 5-15

Coal seam age Cretaceous Cretaceous Carboniferous Paleocene

Coal formation Fruitland Ferron Pottsville Fort Union

Coal thickness (m) 15-30� 4-15 7-10 12-30

Number of seams 1-5 3-6 5-15 2-5

Stratigraphic intervalthickness (m)

15-60 30-45 180-365 30-45

Gas content (m3/t) 12-18 11-14 8-16 1-2

Permeability (mD) 5-100+ 5-50 1-30 10-500

Pressure gradient(MPa/100m)

0.99-1.43 0.97-1.20 0.88-0.95 0.72-0.97

Producing depth (m) 880-1,000 360-1,040 240-910 90-360

Completed zones 1-3 2-3 2-4 1

Well cost (103 $) 500 275 260 60-75

Coal rankHigh volatile A-medium

volatile bituminousHigh volatile B

bituminousMedium-low

volatile bituminousSub-bituminous B

Gas saturation state Saturated SaturatedUndersaturated

to saturatedSaturated

Completion type Cavitated Hydraulic fracture Hydraulic fracture Water infusion

Well spacing (km2) 0.65-1.30 0.65 0.32 0.32

50% of coal by weight and more than 70% byvolume (Schopf, 1956). Coals are described andclassified by differences in composition (type),maturity (rank), and purity (grade). Coal type isbased on the kinds of altered vegetative material(macerals) that form the coal. The two primarytypes of coal are humic (most coals) andsapropelic (rare). Coal type is important becauseeach maceral type generates different volumes ofgas during maturation. Each maceral type alsoadsorbs (stores) different quantities of methane,has different diffusion characteristics, and

impacts natural fracture (cleat) developmentwithin the coal (Mukhopadhyay and Hatcher,1993). The primary method for determining coaltype is by microscopic examination of coalsamples.

Coal rank is a measure of the maturity of theorganic material within the coal, which is the resultof heat (due to geothermal gradient or igneousintrusions) and pressure (due to tectonic andoverburden forces) (Stach et al., 1975). Acomparison of coal rank versus coal classificationand measurement systems is provided in Table 5.



Table 4. Summary reservoir and production characteristics of five shale gas basins in the USA(Curtis, 2002)

Shale Formation Antrim Ohio New Albany Barnett Lewis

Basin Michigan Appalachian Illinois Fort Worth San Juan

Depth (m) 200-700 600-1,500 180-1,500 2,000-2,600 900-1,800

Gross thickness (m) 160 90-300 30-120 60-90 150-580

Net thickness (m) 20-40 10-30 15-30 15-60 60-90

Bottom-hole temperature (ºC) 10 40 25-40 90 55-75

Total organic carbon (%) 0.3-24.0 0.0-4.7 1.0-25.0 4.5 0.4-2.5

Vitrinite reflectance (% Ro) 0.4-0.6 0.4-1.3 0.4-1.0 1.0-1.3 1.6-1.9

Total porosity (%) 9 5 10-14 4-5 3-6

Gas-filled porosity (%) 4 2 5 2 1-4

Water-filled porosity (%) 4 2-3 4-8 2 1-2

Permeability thickness (mD�m) 0.3-1,500 0.05-15 n/a 0.003-0.6 2-120

Gas content (m3/t) 1-3 2-3 1-3 9-11 1-2

Adsorbed gas (%) 70 50 40-60 20 60-85

Reservoir pressure (MPa) 2.8 3.4-13.8 2.1-4.1 20.7-27.6 6.9-10.3

Pressure gradient (MPa/100m) 0.79 0.34-0.90 0.97 0.97-1.00 0.45-0.57

Well costs (103 $) 180-250 200-300 125-150 450-600 250-300

Completion costs (103 $) 25-50 25-50 25 100-150 100-300

Water production (m3/d) 6-80 0 1-80 0 0

Gas production rate(m3/d/well)

1,100-14,200 850-14,200 300-1,400 2,800-28,300 2,800-5,600

Well spacing (km2) 0.16-0.65 0.16-0.65 0.32 0.32-0.65 0.32-1.30

Recovery factor (%) 20-60 10-20 10-20 8-15 5-15

Gas in place (106 m3/km2) 66-164 55-109 77-109 328-437 87-547

Reserves (106 m3/well) 6-34 4-17 4-17 14-42 17-57

Coal rank is an important measurement for theevaluation of coalbed methane reservoirs becausegas generation in coal is highly correlated withincreasing coal rank. In addition, gas storage incoal, gas diffusivity in coal, gas composition, andnatural fracture development in coal are alsostrongly correlated to coal rank. Coal rank is mostoften measured by thermal destruction (proximateanalysis), vitrinite reflectance, or heat content(calorific value).

A final classification for coal is the coal purityor grade. Grade is a measure of the quantity andtype of non-organic material in the coal. Coalgrade includes evaluation of primary minerals,secondary minerals, and moisture. Measurement ofcoal grade can be accomplished by proximateanalysis, petrographic analysis (microscopicidentification of minerals), ash compositionanalysis (elemental oxide composition of ash fromproximate analysis), and equilibrium moistureanalysis. Coal grade is important because non-coalmaterial dilutes the concentration of organics in thecoal (gas is stored only in the organic fraction).Non-coal material also affects the amount ofnatural fracturing in the coal.

Geometric aspects of coal reservoirs In evaluation of coal reservoirs, the first issue

that must be considered is the geometric aspects of

the reservoir. The parameters relating to thegeometry of the reservoir, which are important forthis evaluation, include thickness of the coal seams(individual and cumulative), number of coal seams,depth(s) of the coal seam(s), thickness of thestratigraphic interval containing the coal seams,and aerial extent of the coal seams(discontinuities/no-flow boundaries). The geometryof the reservoir refers to the three dimensionalshape through which fluids (gas and water) flow.The geometry of the reservoir impacts drilling,completion, and production methodologies relatingto development of coalbed methane projects.

Coal is most often formed as part of a typicalclastic depositional sequence. Coal originates as anaccumulation of organic matter in swamps andmarshes commonly associated with fluvialsystems, deltas, and marine shorelines. It is criticalthat the accumulating organic matter is quicklysubmerged beneath the water table to preventoxidation. This requires a combination of basinaccommodation and a rising water table sufficientto match the accumulation rate. Organic matteraccumulates at rates ranging from 20 to 200 cm per1,000 years (Flores, 1993). The depositionalenvironment impacts the degree of coal continuity.It is important to determine if the reservoir iscontinuous (relatively infinite boundaries) or ifthere are flow boundaries caused by faulting,



Table 5. Comparison of coal rank designation and measured coal property (Levine, 1993; ASTM, 2005)

Coal rank (USA classification)Vitrinite reflectance,

% Ro

Volatile matter(dry, ash-free), wt %

Calorific value, Btu/lb

Peat �0.28 �63 –

Lignite 0.28-0.39 53-63 6,300-8,300

Sub-bituminous C 0.39-0.42 50-53 8,300-9,500

Sub-bituminous B 0.42-0.49 47-53 9,500-10,500

Sub-bituminous A 0.49-0.60 42-47 10,500-11,500

High volatile bituminous C 0.47-0.57 42-47 10,500-13,000

High volatile bituminous B 0.57-0.71 39-42 13,000-14,000

High volatile bituminous A 0.71-1.10 31-39 �14,000

Medium volatile bituminous 1.10-1.45 22-31 –

Low volatile bituminous 1.45-2.00 14-22 –

Semi-anthracite 2.00-2.50 8-14 –

Anthracite 2.50 -4.00 2-8 –

Meta-anthracite 4.00-7.00 �2 –

pinchouts, discontinuities, etc. (Fig. 3). Theinclusion of non-coal material within the coalreservoir also has a significant impact on theperformance of coal seam reservoirs, so it isimportant to understand the depositionalenvironment and the potential for non-coalminerals to be part of the reservoir.

As organic matter is buried, it is firsttransformed into peat, which consists of looselycompacted masses of organic material containingmore than 75% moisture. This transformation takesplace mainly through the compaction andexpulsion of interstitial water. Biochemicalreactions, i.e. humification and gelification (Stachet al., 1975), associated with this process transformthe organic matter into precursors of coal macerals.These reactions can also generate significantamounts of biogenic methane and carbon dioxide.Continued compaction and dehydration transform

peat into a low-quality coal (lignite or brown coal)that normally contains 30 to 40% interstitial water(Levine, 1993).

With deeper burial, temperatures increase andgeochemical processes dominate physicalprocesses. Lignite evolves into sub-bituminouscoal by expelling water, carbon monoxide, carbondioxide, hydrogen sulphide, and ammonia, leavingbehind a structure enriched in carbon andhydrogen. At temperatures above about 104°C,carbon-carbon bonds begin to break, generatinggas and liquid hydrocarbons that become trappedin the coals. As these bituminous coals are buriedmore deeply, their hydrocarbons are cracked intothermogenic methane. While some of the methaneremains in the coal, a significant volume isexpelled from the coal, as an order-of-magnitudemore gas is generated than the coal is capable ofstoring (Fig. 4). In a typical coal, the H/C atomic



14 miles (c. 26 km)

B southwest northeast B'

geophysical logs: density (den), resistivity (res), natural gamma (ng)

braidedriver

ng den ng denng den ng den ng den

ng res ng res ng resmeasuredsection

coastalplain

coalzone

coalbed

shoreface

drillhole

100 feet(c. 30 m)offshore

1,00

0 fe

et (

c. 3

00 m

)

Cal

ico

and

A-s

eque

nces

Fig. 3. Correlations of the upper CretaceousCalico and A-sequencecoals (Straight CliffsFormation, KaiparowitsPlateau, Utah, USA),showing impact of coaldeposition on coal seamcontinuity andstratigraphy (Hettinger,2000).

incr

easi

ng g

as v

olum

e

increasing coal rank

sub-bituminous bituminous

thermally-derivedmethane

volatile matterdriven off

biogenic methanenitrogen

carbon dioxide

anthracite graphitelignite

Fig. 4. Gas generationas a function of coal rank (Andersonet al., 2003).

ratio decreases from 0.75 to 0.25 as coals maturefrom high volatile bituminous to anthracite.

The generation and expulsion of hydrocarbonsis accompanied by several profound changes incoal structure and composition (Levine, 1993).Moisture content is reduced to just a few percent aswater is expelled. Micro-porosity increases as theatomic structure of the coal changes, generating ahuge surface area for adsorbing methane. Thesechanges also lower the bulk density from 1.5 g/cm3

in high-volatile bituminous coals to less than 1.2g/cm3 in low-volatile bituminous coals. Coalstrength decreases, making it easier for the coal tofracture as hydrocarbons evolve and the coalshrinks. This creates closely spaced cleats thatenhance permeability (Close, 1993).

At temperatures exceeding about 300°C,bituminous coals are altered to anthracite (�92%carbon). Methane generation and expulsiondecreases and the bulk density increases from 1.3g/cm3 to more than 1.8 g/cm3 as the coalstructure becomes more compact. Methanecontents in anthracites are typically quite highbut permeability is often lower than bituminouscoals due to cleat annealing. With furthermaturation, remaining hydrocarbons are drivenoff and carbon structures coalesce, resulting in adense coal with a very high carbon content and achemical composition similar to graphite(Levine, 1993).

In order to generate high enough temperaturesto produce large quantities of hydrocarbons, coalsmust be deeply buried, typically to depths ofgreater than 3,000 m. Exceptions to this are coalstransformed by local heat sources such as igneousintrusions. After sufficient burial and time togenerate hydrocarbons, coals must be uplifted toshallower depths to be commercially exploited. Atdepths shallower than 100 m, there is usually notenough pressure in the cleat system to holdeconomic quantities of adsorbed gas in the coal. Atdepths greater than about 1,200 m, natural fracturepermeability is generally too low to produce gas ateconomic rates.

Coal seams are typically multi-layeredreservoirs. The thickness of individual coal seamsmay vary widely (from a few centimetres to tens ofmetres). Also, the number of coal seams within thestratigraphic interval target may vary widely, froma few seams to more than 100 seams (Fig. 5).Stratigraphic sequence thickness also varies,ranging from tens of metres to hundreds of metres.In addition to depositional setting,post-depositional structural effects may deform thecoal seam and impact reservoir conditions. Of

significant importance are the three-dimensionalreservoir orientation, reservoir continuity, andinternal reservoir structure. These events may haveeither a positive or negative effect on the coalreservoir. Faulting and folding events may causeshearing (structural damage) to the coal reservoirand reduce permeability. However, faulting may



thic

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s(i

n fe

et)

selectedunits

generalizedlithologies

Waynesburgcoal bed

Little Waynesburgcoal bed

Uniontown coal bed

Sewickley coal bed

Fishpot coal bed

Redstone coal bed

Pittsburgh coal bed

sandstone

limestone

shale andsiltstone

shale

siltstone

coal

coal orcoal and shale

claystone

Pittsburgh sandstone(informal)

Benwood limestone(informal)

grou

p

seri

es

syst

em

Dun

kard

(par

t)C

onem

augh

(par

t)

Low

erPe

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n

Perm

ian

240-

430

Mon

onga

hela

Upp

er P

enns

ylva

nian

Penn

sylv

ania

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Fig. 5. Generalized stratigraphic column of the Upper Pennsylvanian Monongahela Group showing seven major coal beds within a 100 m thick stratigraphic section (Tewalt et al., 2001).

also cause fracturing swarms within the reservoir,which will enhance permeability.

Natural fractures in coal Natural fractures (cleat) provide the primary

flow paths within the coal reservoir; therefore,successful production wells must establishconnection with this natural fracture system. Cleatsgenerally occur at right angles and areperpendicular to bedding (Fig. 6). The primaryfracture direction is normally referred to as theface cleat and the secondary fracture direction isnormally referred to as the butt cleat. The primarydifference between the face and butt cleats is thecontinuity of the fracture system, with the facecleats tending to be more continuous than the buttcleats. The origin of cleating in coal is most oftenlinked to the coalification process, where theprocesses of dehydration and devolatilization of theorganic material occur in the confined, stresseddepositional/burial system. Cleating in coal mayrange in spacing from 1-2 mm to severalcentimetres. Cleating in coal is generally related tocoal rank (higher rank gives close spacing),vitrinite content (higher vitrinite content results inclose spacing), mineral matter content (highmineral matter content implies wide spacing), andtectonic activity of the reservoir. In-situ cleataperture widths vary from about 0.0001 mm to 0.1mm and can sometimes be filled by calcite,gypsum, or pyrite minerals (Close, 1993). It shouldbe noted that, in addition to the primary fracturesor cleats, coals may also have secondary naturalfractures caused by tectonic activity andpost-cleating structural events. The identificationand measurement of cleating in coals isaccomplished either by direct measurement usingcoal samples (outcrop or core samples) or bymeasurement of the coal seam flow characteristics(pressure transient testing).

Laboratory testing and field observationsindicate that cleat permeability decreases duringinitial gas production due to cleat aperture closingas a function of reduced reservoir pressure (stressdependent permeability). Conversely, the cleatapertures may widen due to the coal matrixshrinking as the gas diffuses and flows out of thecoal matrix, increasing permeability and gas rates.This phenomenon has been observed in severalwells in the San Juan Basin, USA, that have beenproducing gas for over ten years (Palmer andMansoori, 1998). Also, like conventional oil andgas reservoirs, coalbed methane reservoirs exhibitchanges in relative permeability as fluid saturationschange during production.

Gas content of coal Gas generation in coal occurs as a result of the

thermal maturation process (see again Fig. 4). Gasis generated in coals from the sub-bituminousthrough anthracite coal ranks. Much more gas isgenerated in the coalification process than can bestored in the coal (up to 8-10 times). Thecomposition of the generated gas is primarilymethane, but includes carbon dioxide, nitrogen,and higher-end hydrocarbons. Heavierhydrocarbons are relatively uncommon, due to alack of hydrogen (when compared to carbon) in thecoal. Gas from lower ranked coals often has ahigher carbon dioxide component; also, igneousintrusions through the coal reservoir can lead tohigher carbon dioxide concentrations. In additionto gas generated during thermal maturation,biogenic activity may also contribute to gas incoals. Originally, biogenic activity was thought toend at the end of the peat cycle. However, morerecent evidence suggests that microbial activitymay also occur at later stages and in higher rankcoals. This activity is thought to exist in and nearoutcrop areas (about 8 km from crop line), wherefresh water may actively recharge into the coalreservoir (Rice, 1993).

The ability of coal to store gas is dependentupon coal rank (thermal maturity), moisture, andash content in the coal, the maceral makeup of thecoal, and the geologic history of the coal reservoir.Because in-situ gas content is affected by thesenumerous parametres, the actual gas content inany particular coal reservoir can only bedetermined by direct measurement. This isgenerally accomplished by measuring the quantity



butt cleat

face cleat

10 cm

Fig. 6. Orthogonal cleat (plan view) developed in the Waynesburg coal, Northern Appalachian Basin, Greene County, Pennsylvania, USA (courtesy of the Author).

of gas desorbed from coal core or cutting samplesfrom coalbed methane wells. This methodprovides a direct measurement of the volume ofgas contained in the coal at in-situ reservoirconditions.

Gas storage in coal While gas content measurements determine the

quantity of gas contained in the coal at reservoirconditions, it is also important for reservoirevaluation purposes to understand how gas isstored in the coal. The capacity of the coal matrixto store gas as a function of pressure is describedby the Langmuir sorption isotherm (Fig. 7). Thisstorage mechanism gives coal reservoirs theirunique characteristic: the ability to store largevolumes of gas at relatively low reservoir pressure.The sorption process is physical, involving weakintermolecular attraction due to van der Waalsforces (Yee et al., 1993). Large volumes of gas canbe stored because the internal surface area of themicro-porosity in coal is very large, ranging from

less than 50 to over 275 m2/g of coal (Crosdale etal., 1998). Comparing the gas sorptive capacity ofcoal to that of conventional sandstone (Fig. 8), itcan be seen that at a relatively low reservoirpressure (6.9 MPa), coal can store 4 to 6 times thevolume of gas stored in a medium porositysandstone. The maximum sorbed gas content ofcoal at a specified pressure is defined by thefollowing equation, modified from Langmuir(1916):

Cg�(VL · P)/(PL+ P)

where Cg is the matrix gas concentration (m3/t),VL is the Langmuir volume (m3/t), PL is theLangmuir pressure (MPa), P is the reservoirpressure in fracture system (MPa).

The Langmuir volume is the theoreticalmaximum volume of gas a coal can adsorb onto itssurface area at infinite pressure. This wouldrepresent a continuous monolayer of methanemolecules over the entire internal surface of thecoal. The Langmuir pressure is the pressure at



adso

rbed

gas

con

tent

(sft

3 /t;

dry

, ash

-fre

e)0

200

400

600

800

1,000

1,200

pressure (psia)

anthracite

high volatilebituminous A

medium volatilebituminous

high volatilebituminous B

0 200 400 600 800 1,000

Fig. 7. Sorptivecapacity of coal as described by theLangmuir isotherm for various coal rank(Anderson et al.,2003).

gas

cont

ent

(sft

3 /t;

coa

l equ

ival

ent)

0

100

200

300

400

500

600

pore pressure (psia)

coal isotherm

coal

sandstones

8% porosity to gas

6% porosity to gas

4% porosity to gas

0 1,000500 2,0001,500 3,000 3,500 4,0002,500 4, 500

Fig. 8. Comparison of the volumeof gas stored in coal as sorbed gas versus that stored in a conventional sandstonereservoir at various sandstoneporosity (Anderson et al., 2003).

which the storage capacity of a coal is equal to 1/2the Langmuir volume.

Coal sorption isotherms are determined bylaboratory testing of crushed coal samples, withmoisture content and temperature closelycontrolled. The sorption isotherm test results in therelationship between pressure and adsorbed gascontent in the reservoir at static temperature andmoisture conditions. In some reservoir settings,coal seam gas contents are less than the amount ofgas a coal is capable of storing. The coals aretherefore considered undersaturated with gas. Forcoals that are 100% gas saturated, gas will beproduced as soon as the pressure is decreased byproducing water from the cleats. Gas rates willincrease to a peak over several years and thendecline. For undersaturated coals, gas will not beproduced until the pressure in the cleats has beenreduced below the saturation pressure, resulting ina longer period to achieve peak gas rates.

Gas transport mechanisms in coal Coals are fractured reservoirs, including a

matrix and a fracture system. The matrix system isthe low permeability organic portion of thereservoir and provides the primary storage for gas.The fracture system in the reservoir is low porosity,relatively high permeability, and provides theprimary storage for produced water within thereservoir. The major mechanisms which controlgas and water flow in the reservoir includediffusion in the coal matrix, desorption of gas fromthe coal matrix into the fracture system, and Darcyflow within the coal fracture system (Fig. 9).

The major storage mechanisms within coalinclude adsorption of gas within the matrix system(the major gas source for coals) and free porosity,which occurs primarily in the fracture system.Adsorption in the matrix is the primary storagemechanism for gas, and the fracture (cleat)porosity is the major source of storage of water inthe reservoir. The Langmuir isotherm equationdescribes the volume of gas stored in the coalmatrix system as a function of reservoir pressure.The porosity of the fracture systems within thecoals is generally low, ranging from less than 0.5%to 2-4%.

As already said, fluid transport mechanisms incoal include diffusion of gas in the coal matrix,desorption of gas from the matrix to fractures, andDarcy flow within the fracture system. Gas movesthrough the coal matrix via a molecular diffusionprocess as described by Fick’s law (Zuber, 1996).This process is a concentration gradient drivenprocess, which occurs because the gas

concentration within the matrix is lower at thematrix-cleat boundary than within the centre of thematrix elements. Darcy’s law generally describesflow within the coal fracture system. The relativepermeability concept is used to describesimultaneous flow of gas and water within thefracture system as a function of saturation.

Coalbed methane production characteristics and dewatering cycle

Coalbeds are complex reservoirs, normallycontaining both gas and water in the fracturesystem and gas sorbed on the coal surface in thecoal matrix system. Because of the complexreservoir mechanisms that control gas and waterflow in coals, production from coalbed methanewells tends to have complex characteristics relatedto these mechanisms. Fig. 10 shows a typicalproduction profile (for gas and water) in a coalbedmethane well. Coalbed methane water productionis normally characterized by a declining trend. Thegas production cycle for coalbed methane wellsoften consists of a trend of inclining initialproduction, reaching at a peak at some point, andthen a declining production trend. This profile isnormally exhibited by coalbed methane wells(within a pattern of producing wells) that arebounded in some manner, either by interferencedue to offset producing wells, or by naturalboundaries within the reservoirs, such as faulting.

The inclining trend in gas production exhibitedby coalbed methane wells is related to thechanging relative permeability to gas within the



wellbore,mastercleat,or fault

coal matrix

methane gaswater

nitrogen gascarbon dioxide gas

clea

t

reduce methanepartial pressure in cleat

. reduce cleat pressure by producing water. methane desorbs from matrix and diffuses to cleat. methane and water flow to wellbore

Fig. 9. Gas flow mechanisms in coal (Puri and Yee, 1990; Dallegge and Barker, 2000).

reservoir. In many coal seams the natural fracturesystem is initially saturated with water. As water isproduced from the natural fracture system, thereservoir pressure is reduced and gas desorbs fromthe coal and diffuses to the fracture system. As thegas saturation in the fracture system in thereservoir steadily increases, the relativepermeability to gas in the reservoir increases. Thiscauses the inclining gas production trend.Conversely, as the water saturation in the fracturesystem declines, the water production declines.Once the relative permeability to gas within thereservoir stabilizes (the reservoir is said to bedewatered at this point in time), the gas productionpeaks and begins to decline. In coal reservoirswhich are dry (no mobile water is in the fracturesystems), a continuous declining trend in gasproduction is observed since the desorption rate isdecreasing throughout the drainage area. Becausethe gas production of coal reservoirs is dependentupon the dewatering of the reservoir and the abilityto increase gas relative permeability in thereservoir, the characteristic production profile ofany given coalbed methane well is dependent uponthose factors that affect the ability of a pattern ofwells to dewater the reservoir. These factorsinclude well spacing, reservoir permeability,porosity of the fracture system, initial gas andwater saturations within the reservoir, and thequantity of adsorbed gas.

Variability in well production Examination of production from coalbed

methane producing fields indicates that there is ahigh degree of variability in well production fromwell to well within producing patterns. Thisvariability is not attributed to large variations in

well spacing or gas in place in the coal reservoir.The primary contributing factor to productionvariability seems to be variations in reservoirpermeability. These variations are due toheterogeneities in the natural fracture systemwithin the reservoir (number of cleats and naturalfractures and their aperture width). Permeability incoals has also been shown to be highlystress-sensitive. Field studies conducted in theBlack Warrior Basin, USA, have indicated thatvariations in reservoir stress can lead to order ofmagnitude changes in permeability from area toarea within producing fields (Sparks et al., 1993).

Examination of numerous producing wellsacross extensively developed coalbed methaneplays indicates that order of magnitude variationsin well performance is typical. Fig. 11 shows thecumulative gas production from 23 producingcoalbed methane wells in a field in the BlackWarrior Basin, USA. All of the wells were drilledand completed nearly identically, and there wereonly slight well-to-well variations in coalthickness, gas content, and other reservoirparameters. The wells were also drilled on thesame small spacing: 304 m between wells on asquare grid. Hence, only variation in reservoirpermeability can explain the large variation in wellproduction across this field. Extensive studies ofcoalbed methane production data from highlydeveloped coalbed methane plays have alsoindicated that a high degree of variability existsacross producing plays, and for smaller areas(down to field scale) within these producing plays.The variations in production within the San Juan,Black Warrior, and Central Appalachian Basins areshown in Fig. 12, which is a probability distribution



prod

ucti

on r

ate

production time

stage I

well ‘dewatered’stage II

stage III

gas

water

Fig. 10. Typical water-saturated coalbed methane well performance profile (Anderson et al., 2003).

cum

ulat

ive

gas

prod

ucti

on (

Msf

t3 )

175,000

150,000

125,000

100,000

75,000

50,000

25,000

0

time (months)0 2010 30 40 50 60 70 80

Fig. 11. Local well performance variations in a group of 23 similar wells in the Black Warrior Basin, USA, due to local changes in natural fracture permeability (Anderson et al, 2003).

of actual five-year cumulative production. Thishigh degree of variability within the coal reservoirshas significant implications for evaluatingprospective coalbed methane areas (Weida et al.,2005).

Shale as a reservoir

Shale composition Shale is the most commonly occurring type of

sedimentary rock, being typically deposited onriver floodplains and on the bottoms of lakes,lagoons, and oceans. It is formed by theconsolidation of fine-grained detrital rockfragments or mineral particles, and typicallycontains 50% silt, 35% clay, and 15% chemical orauthigenic materials. Silt and clay aredifferentiated from one another on the basis oftheir particle diameters. Silt consists of rockor mineral particles having diameters between1/256 and 1/16 mm whereas clay consists of rockor mineral particles having a diameter less than1/256 mm. Shale has a finely laminated, fissilestructure, and readily breaks into thin, parallel layers.Mudstone is compositionally similar to shale, butlacks a finely laminated or fissile structure andcommonly disintegrates upon exposure to water(Bates and Jackson, 1980). The color of shaleranges from green and gray to black, depending onthe organic matter content. The higher the organicmatter content, the darker the color of the shale.Black shale (high organic content) is a commonsource rock for natural gas and crude oil (Hill andNelson, 2000).

Producing gas shale reservoirs in the USAdemonstrate a wide range in depositional historyand composition. The Antrim, Ohio, and NewAlbany Shale of the eastern and central USA areall part of an extensive, organic-rich shale

depositional system of middle to upper Devonianage (Curtis, 2002). However, while the depositionof these silica-rich shale formations wastime-equivalent, the compositional characteristicsof these three formations differ. As shown in Table4, the Antrim Shale is characterized by highorganic content (up to 24%) whereas the organiccontent of the Ohio Shale rarely exceeds 5%.Variations in anoxic conditions within sub-basinsof this depositional system probably accounted forthe variation in preserved organic mass. Similarvariations in organic content (as representedtypically by Type II or Type III kerogen) areobserved in the Barnett (4-8%) and Lewis(0.5-2.5%) gas shale reservoirs.

Shale gas generation and storage Gas in shale gas systems is of thermogenic or

biogenic origin. Thermogenic gas is derived fromthe transformation of the kerogen via thermalmaturation, typical of conventional petroleumsystems. Jarvie et al. (2001) identified 13 otherformations (Ordovician to Pennsylvanian in age)that were sourced from the oil generated in theBarnett Shale of the western Fort Worth Basin,Texas, USA. Subsequent cracking of this oil mayhave contributed to the gas currently in place (andproduced) from this shale. Similar thermogenic gasgeneration occurred in all of the other productiveUSA gas shale systems (Antrim, Ohio, NewAlbany, and Lewis Shale).

However, in the case of the Antrim Shale itappears that the thermogenic gas has largelymigrated from the system. In this shale reservoir,the gas currently in place is probably only tens ofthousands of years old, having been produced asrecent biogenic gas (Martini et al., 1998).Methanogenic bacteria, carried into the organicshale via post-Pleistocene aquifer recharge,



five

-yea

r cu

mul

ativ

e ga

spr

oduc

tion

(M

sft3 )

10,000,000

1,000,000

100,000

10,000

probability (%)

San Juan

Black Warrior

Central Appalachian

0 20 40 60 8010 30 50 70 90 100

Fig. 12. Probabilitydistribution of actualfive-year cumulativeproduction fromcoalbed methane wellsin the San Juan, BlackWarrior, and CentralAppalachian basins,USA (Weida et al., 2005).

generated gas by consuming the kerogen in theAntrim Shale around the margin of the MichiganBasin. In this area of the basin, produced gas is amixture of recent biogenic and geologically olderthermogenic gas.

Storage of gas in shale gas systems issomewhat similar to that encountered in coal,discussed previously. Gas is stored on the kerogenas sorbed gas (described by the Langmuirisotherm), within the intergranular porosity as freegas, within the natural fracture system as free gas,and within the kerogen (and bitumen, in thermallymore mature shale) as dissolved gas. Trappingmechanisms are subtle, with gas saturationsgenerally covering large areas (Roen, 1993).Originally, based on production results from theOhio and Antrim Shale reservoirs, it waspostulated that most of the gas in shale reservoirswas sorbed gas. This gas mimics the storagemechanism described for coal, and sorptionisotherms of the organic component in shale gasreservoirs are routinely measured.

However, recent studies have shown that theproportion of gas stored in shale by the twodominant methods, sorbed versus free gas, canvary significantly with reservoir conditions. TheAntrim Shale of the Michigan Basin, USA, is ashallow, cool reservoir (24°C) with high organiccontent (see again Table 4). Comparison of thevolume of sorbed gas versus free gas in thereservoir (at a reservoir pressure of 400 psia, or 2.8MPa) shows that 74% of the gas is sorbed onto theorganics while 26% is free gas in the intergranularand fracture porosity (Fig. 13). By comparison, theBarnett Shale of the Fort Worth Basin, USA, is adeep, higher temperature/higher pressure reservoirwith relatively low total organic content. At

reservoir conditions (4,000 psia, or 27.6 MPa, and90°C) 63% is free gas while 37% is sorbed(Fig. 14). As exploration and development of gasshale reservoirs occur throughout the world, asimilar range in reservoir types is expected,ranging from sorbed-gas dominant reservoirs tofree-gas dominant reservoirs.

Gas transport mechanisms in shale Similar to coal in many respects, the

mechanisms of gas transport and flow in gas shalereservoirs is controlled by factors other than justconventional Darcy flow. A dual porosity systemexists in most productive gas shale reservoirs:primary microporosity in the shale matrix coupledwith a secondary natural fracture porosity. Naturalfractures, formed either due to tectonic forces orduring hydrocarbon generation, vary in spacingfrom one metre to several metres and are oftenpresent in an orthogonal pattern perpendicular tobedding, with a dominant and subordinate set(Fig. 15). Matrix porosity is low, generally rangingfrom 1-10%; fracture porosity is very low, less than1% (Zuber et al, 1994a; Frantz et al., 2005; Curtis,2002). The fracture porosity may be filled withmobile water, up to 100% in some areas of theAntrim gas shale play area; other gas shale areas(e.g. Barnett Shale) have little or no mobile waterassociated with the fracture porosity. Matrixpermeability is extremely low, ranging from 1�10–4

to 10–8 mD. Gas flow through this low permeabilityshale matrix has been compared to the diffusion ofgas through coal matrix. Fracture permeabilityvaries widely, from 5 mD in the shallow AntrimShale to 1�10–4 mD in the Barnett and Lewis Shale.Flow in shale gas reservoirs is, therefore, acombination of desorption of gas from the



gas

cont

ent (

sft3 )

0

10

20

30

40

50

60

pressure (psia)

free gas

sorbed gas

total gas

0 10050 200150 300250 400 450350 500

Fig. 13. Comparison of sorbed and free gas in the Antrim Shale, Michigan Basin, Michigan, USA (Zuber et al., 1994a).

gas

cont

ent (

sft3 )

pressure (psia)

free gas

sorbed gas

total gas

0

40

80

120

160

20

60

100

140

180

0 1,000 2,000 3,000 4,000 5,000

Fig. 14. Comparison of sorbed and free gas in the Barnett Shale, Fort Worth Basin, Texas, USA (Frantz et al., 2005).

organics; Darcy flow (and/or diffusion) of free gasthrough the low permeability, microporous shalematrix to the natural fracture system; and Darcyflow of gas and water (usually) through the naturalfracture system.

Shale gas production characteristics Production of gas from shale gas reservoirs

varies significantly from play to play and withinspecific plays (as is the case for coalbed methaneproduction). Three types of production have beenidentified: Type 1 co-production of gas and waterin sorption-dominated reservoirs; Type 2production of gas in sorbed gas-dominatedreservoirs; and Type 3 production of gas in free-gasdominated reservoirs. Type 1 production isreflected in the production performance of wells inthe Antrim Shale of the Michigan Basin(Michigan, USA) and the New Albany Shale of theIllinois Basin (Illinois, Indiana, and Kentucky,USA). General production performance is similarto that observed in water-saturated coalbedmethane wells, in that the gas production follows atrend of inclining initial production, reaching apeak at some point, and then a decliningproduction trend, while water production isnormally characterized by a declining trend (Zuberet al., 1994a). Type 2 production, characterized bythe Ohio Shale of the Appalachian Basin(especially in the area comprising southern WestVirginia, western Virginia, and eastern Kentucky,USA), initially produces free gas associated withthe natural fracture system and the micro-porosity.With the pressure reduction associated with thefree gas production, the sorbed gas desorbs andbecomes a source of free gas to the system. These

wells typically have low production rates but mayproduce for over 40 years (Boswell, 1996). Finally,Type 3 production reflects the reservoir responseobserved in the deep, high-pressure Barnett Shaleof the Fort Worth Basin (northeastern Texas, USA).Production from these shale reservoirs isdominated by flow from the micro-porositysystem, with sorbed gas contributing less than 10%of the total gas produced (Frantz et al., 2005)

2.2.3 Drilling, completion, andproduction

Until recently, most drilling activity was confinedto vertical wells targeting the relatively shallowcoal reservoirs 150 to 1,000 m deep, and the moremoderate depth shale reservoirs 1,000 to over2,500 m deep. Shallow coal gas wells arecommonly drilled using under-balancedrotary-percussion drilling methods (Hollub andSchafer, 1992). This technique allows for rapiddrilling rates (up to 15 m/h) and minimal damageto the natural fractures in the coal reservoir.Alternatively, conventional rotary drilling withlight-weight mud systems (balanced tounder-balanced) are used when higher reservoirpressures, excessive water flows, and wellborestability problems are expected. Similarly,shallower shale gas wells (for example, those in theupper Devonian Ohio Shale in the Big Sandy Fieldof eastern Kentucky, USA) are also drilled usingunder-balanced rotary-percussion drilling methods,while the deeper Barnett Shale wells in the FortWorth Basin, northeastern Texas, USA, rely uponboth rotary-percussion and conventional rotarywith light mud systems.

With recent improvement in downholetechnology and the associated reduction in costs,horizontal drilling is becoming an attractivealternative in certain reservoir settings to verticalwells in both coal and gas shale reservoirs. Thefirst large-scale application of horizontal wells incoal occurred in the mid-1990s in the Hartshornecoal of the Arkoma Basin in Oklahoma, USA(Rutter, 2002). In this setting, a single horizontalwellbore is typically drilled. Subsequent to thesuccess of these wells, a multi-lateral techniquewas developed for mine degasification and naturalgas production at the Pinnacle Mine in the CentralAppalachian Basin, West Virginia, USA (vonSchoenfeldt et al., 2004). As shown in Fig. 16, avertical well is initially drilled. Subsequent to this,a horizontal well is drilled to intersect the verticalwell, and from this primary horizontal section,



primary fracture

secondary fracture

Fig. 15. Natural fractures in the New Albany Shale, Illinois Basin, Indiana, USA (courtesy of the Author).

multiple laterals are drilled in a pinnate pattern.The horizontal laterals are typically completedopenhole, thus exposing the extensive, naturallyfractured coal to the entire wellbore. However,wellbore stability and artificial lift (dewatering)problems have been reported, which must beconsidered in the application of this technology toother coal areas. Reported recovery of thesemulti-lateral wells is 80-90% of the original gas inplace within 24 to 48 months, which leads tosignificant economic benefits.

Similar to the application in coal, the use ofhorizontal drilling methods in gas shale reservoirs(especially in the Barnett Shale) is rapidlyexpanding (Frantz et al., 2005). Beginning in 2003,a rapid change from vertical to horizontal wells inthe Barnett Shale occurred, such that 60% of allnew wells drilled into this shale formation are nowhorizontal. Unlike the horizontal wells in coal,these wells are typically cased, cemented, andhydraulically fractured, because the natural fracturesystem of this shale is poorly developed.

The most common form of completion in coaland shale gas wells has been perforated casedholewith single- or multi-stage hydraulic fractures.Fracturing coal reservoirs effectively has been asubject of much debate for the last three decades.In the highly fractured, low modulus coal, complexfractures are often created (especially in the near-wellbore region) that lead to shorter half-lengthsand high treating pressures over 22.6 kPa/mgradients (Palmer et al., 1993). Fluid inefficienciesdue to leak-off into the fracture system, damagedue to swelling of the coal in the presence of

certain gel systems, and out-of-zone growth due tothe relative thinness of the zones are only part ofthe complexities involved in fracturing coal seams.Although generalities may be dangerous, theindustry is trending towards less damaging fluidsystems and greater reliance on nitrified systems.

The recent and rapid development of the coalreservoirs in the Powder River Basin of Wyomingand Montana has led to the development of analternative to the traditional hydraulic fracturingoperation. The most widespread completionpractice (in over 10,000 wells currently producing)has been the application of a non-damagingopenhole completion followed by water infusion(�0.8 m3/min) to help open the coal cleats andflush coal fines (DOE/NETL, 2003). Similarly, thefast development of the dry, shallow HorseshoeCanyon coals of the Alberta Plains region inCanada has led to an alternative stimulationtechnique. Because no water is produced fromwells drilled into this coal formation, operatorshave been successful using nitrogen-only (noproppant) fracturing treatments (Gatens, 2004).

Shale gas wells almost universally rely uponhydraulic fracturing to connect the natural fractures(less well developed than in coal) to the wellbore.Although a number of horizontal openhole wellshave been attempted in the New Albany Shale ofthe Illinois Basin, most horizontal shale gas wellsare now completed using multiple stage treatmentspumped along the length of the horizontal section.To reduce the effect of cement damage on thenatural fracture system, innovative openhole andnon-cemented casedhole approaches have been



small coalseams

small coalseams

coal bed

coal bed

CDX drill siteFig. 16. Horizontal,multi-lateral pinnatewells for the productionof coalbed methane (von Schoenfeldt et al.,2004).

attempted. However, the general trend is towards amore conventional cased, cemented, stageperforated, and fractured horizontal section (Fisheret al., 2004).

During the mid-1980s, a unique ‘cavitation’completion method was developed in the fairwayregion of the San Juan Basin as an outgrowth ofobserved formation response during drilling. Thenatural or dynamic cavitation method consists ofpressure build-up and rapid pressure release,resulting in high differential pressure at thecoal/wellbore interface and the sloughing of thecoal into the wellbore (Logan, 1993). Repeatedapplication of these pressure pulses results in theformation of an enlarged wellbore (up to 5 m indiameter) and a donut-shaped area of enhancedpermeability (estimated at 15-30 m in diameter),both of which add dramatically to the wellproductivity. However, the successful applicationof this completion technique has been limited toonly the fairway region of the San Juan Basin,USA, and selected areas within Australia’s Bowen Basin.

As discussed previously, most coal seam andsome gas shale reservoirs are water saturated.Initial production (Stage 1) from these reservoirs isdominated by water with small amounts of gas. Asthe water moves out of the natural fracture system,hydrostatic pressure is reduced, gas desorbs fromthe internal surface of the coal, and a free gassystem begins to form. As gas saturation increases(Stage 2), relative gas permeability and gasproduction increase while relative waterpermeability and water production decrease. Withstabilization of the gas and water relativepermeability, peak gas production occurs. Gas andwater production slowly decline from this point(Stage 3), controlled not only by the key reservoirparameters (especially permeability) but also byinterference effects of adjacent wells. Conversely,dry coal and gas shale reservoirs typically performlike conventional gas reservoirs, with a peak initialproduction and slow decline thereafter, as thedesorption phenomenon continually replenishesnew gas into the natural fracture system.

2.2.4 Resources and reserves

Because gas molecules are stored as both sorbedgas and free gas in coals and shale, bothcomponents must be included in any gas-in-placecalculation. To determine reservoir thickness, amaximum density limit of 1.75 g/cm3 is oftenapplied in coal reservoirs. For gas shale

reservoirs the density varies from 2.1 to 2.5g/cm3. The reservoir area is generally definedusing thickness derived from logs and coredescriptions. Gas content values are obtainedfrom core desorption measurements corrected forlost gas and residual gas. The average in-situ coalor shale density can be determined from adensity log or from core measurements. Mineralmatter and moisture contents are derived fromthe analysis of coal or shale samples. Estimatesof porosity (1-4%) and water saturation (0-100%)in the fractures are generally based on numericalsimulation and well performance. The equationthat combines all of these parameters to calculategas-in-place is:

/cl(1�Swi)GIP �Ah �11112444�Gcrcs(1� fmm�fw)�Bgi

where GIP is the gas in place (m3), A is the arealextent (m2), h is the net coal thickness (m), /cl isthe fracture porosity (fraction), Swi is the initialwater saturation fraction in the fractures(fraction), Bgi is the initial gas formation volumefactor (m3/m3), Gc is the gas content (cm3/g), drymineral matter-free (dmmf) basis, rcs is the coalor shale density (g/cm3), in-situ basis, fmm is themineral matter (weight fraction), fw is themoisture (weight fraction).

The accurate determination of gas-in-placeparameters is a difficult and time consumingprocess, and the resulting estimates may often varydramatically as more information becomesavailable. This is due to the heterogeneous nature ofthese reservoirs and the uncertainties inherent in acomplex data collection and analysis process(Zuber, 1996; Mavor, 1996). In addition, coal or gasshale resources cannot be produced economicallywithout sufficient permeability, successfuldewatering, and cost-effective completion methods.This has driven many operators to acquire moresophisticated data to understand those factors thatcontrol productivity. For example, large differencesin gas rates from adjacent wells in the Barnett Shalewith similar pay thickness and completion type canoften be traced to a greater density of open fracturesindicated by image logs.

In assigning proven reserves to coal or shalereservoirs, the same criteria required forconventional proven reserves must be met. Theseinclude reasonable certainty (90% confidence),economic productivity under existing conditions,and demonstrated continuity of productionbetween wells. For a new coal gas reservoir witheconomic wells, the sorption isotherm can be usedto estimate an initial recovery factor by assuming



an abandonment pressure. A type well profile,based upon analogous reservoir performance, canthen be developed that achieves this recovery overa reasonable number of years. If the reservoirproduces shale gas, then the situation is morecomplex, because free gas produced at the startwill be augmented by sorbed gas production asreservoir pressure decreases, flattening the declineand extending well life.

A more sophisticated approach that effectivelyintegrates all core, log and well test data is anumerical simulation model. Numerous simulatorshave been developed for application to coal andshale reservoirs (Hower, 2003; Zuber et al., 2002).The advantages to this approach include the abilityto: assess the effects of variations in keyparameters; incorporate unique components suchas directional permeability and the contributions offree gas and sorbed gas; determine which portionsof the geological model should be revised such asfracture intensity and aquifer size; and evaluateappraisal and development strategies such as wellspacing, well pattern and fracture design. Onceconstructed, the model(s) can be updated andhistory matched to production data, staticpressures, and producing bottomhole pressuresobtained on a regular basis.

Once the reservoir is developed, estimates ofthe initial gas in place and recovery factor can beimproved by using a modified material balancetechnique (Jensen and Smith, 1997). This alsoserves as a good check on the initial gas in placevalues calculated from the reservoir thickness andgas content data. Decline curve analysis can alsobe used once the inclining gas period, associatedwith dewatering, has ended. The decline curves canbe compared to type well curves from mature coaland gas shale reservoirs to increase confidence inreserve estimates.

In addition to proven reserves, coal and shalegas reserves may be assigned to probable and/orpossible categories. These typically include:a) reserves that appear to be productive on thebasis of log data but lack a definitive well test;b) reserves that are separated from proved reservesby faulting or other discontinuities; c) reservesanticipated to be proved from step-out wells not yetdrilled; d ) reserves that are attributable to a moreoptimistic interpretation of performance trendsthan proved reserves; e) reserves consideredunproven due to contractual, regulatory oreconomic uncertainties; f ) reserves attributable toenhanced recovery projects (such as the injectionand sequestration of carbon dioxide in coal) not yetshown to be commercially viable.

2.2.5 Technology and futuretrends

The growth of the coal and shale gas industries isexpected to continue for the foreseeable future.The coal gas industry has shown an unprecedentedexpansion over the last 20 years, which is nowbeing eclipsed by the rapid, recent expansion ofthe shale gas industry (especially in the BarnettShale). In the US alone, over 3.7�1012 m3 ofnatural gas in coal and shale reservoirs isconsidered technically recoverable (DOE/EIA,2004). In both of these reservoir types, theapplication of new technology has been readilyaccepted by the industry.

With the existence of very large coal and shalegas resources throughout the world, what are thetechnology demands and future requirements forthe continued growth of this sector of the naturalgas industry? As with the conventional gasindustry, reservoir characterization, drilling andcompletion, and production operations are theprimary technology areas of focus. Within thesethree primary areas, the more pressing needs andpossible technologies are provided in Table 6.

Important to the development of newtechnologies is the need to understand the uniquecharacteristics of coal and shale gas production.Average daily production for a coalbed methanewell in the USA in 2004 was about 5.6�103 m3/d;average for a USA shale gas well was only1.7�103 m3/d. Simple averages do not account for thewide range in well productivity, e.g. a 5.7�104 m3/dBarnett Shale well versus a 8.5�102 m3/d OhioShale well. The relatively low productivity ofthese formations will dictate that new andcost-effective technologies continue to bedeveloped and used. In both coal and shalereservoirs, for example, improved boreholeimaging and geochemical logging is aiding in theidentification and high grading of these reservoirs.The growing application of horizontal welltechnology in the low permeability coal and deepshale reservoirs has been primarily driven by theoverall decrease in drilling cost, improvement insteering capability, and reduction in formationdamage.

Finally, in the coming years, the unique gasstorage characteristic of coal and shale reservoirs– sorbed gas – may provide the mechanism forboth improved gas recovery and carbonsequestration. Coal (and the organics in shale) hasa tendency to adsorb carbon dioxide preferentiallyover methane; carbon dioxide injected into a coalor shale reservoir will displace the adsorbed





Table 6. Areas of focus for coalbed methane and shale gas research and development(Boyer, 2005; Jenkins et al., 2003)

Primary technology areas Technology needs Technology applications

Reservoir characterization

Quantify fracture systems andvariability

Identification ofhigh-permeability areas

3-D and 4-D seismic

Downhole imaging tools

Surface geochemistry

Sorbed gas contentmeasurement

Downhole spectroscopic analysis

Geochemical logging

Permeability measurementPre- and post-closure mini-fracture analysis

Wireline-conveyed isolation/injection systems

Identification of behind pipereservoirs

Through-casing analysis

Improved interpretive algorithms

Drilling operations

Rapid, reduced-cost drilling

High pressure, jet-assisted coiled tubing systems

Telemetric and composite drill pipe

Non-damaging, environmentally benign fluids

Reduced drilling ‘footprint’Extended reach horizontal laterals

Below reservoir extraction

Horizontal well stabilityCombination drill and liner systems

Mechanical liner systems

Completion operations

Non-damaging cementing Ultra-light weight cement

Formation accessJet-assisted hydro-jetting

High-energy laser perforating

Increased hydraulic fracturingeffectiveness

Coiled-tubing conveyed systems well/horizontal application

Fracture diagnostics, including micro-seismic and tiltmeter

Environmentally benign fluids

Ultra-lightweight proppants

Production operations

Artificial lift/Water disposal

Downhole gas/water separation and re-injection

Improved reverse osmosis techniques

Improved filtration/sequestration of contaminants

Surface modification agents

Smart well and expert systems

Enhanced production

CO2/N2 enhanced injection

Enhanced horizontal wellbore configurations

Microbial enhanced gas generation

methane, resulting in a pseudo-secondary gasrecovery operation. This great affinity of coal andshale for carbon dioxide – adsorbing at a rate ofabout three molecules of carbon dioxide for everydisplaced methane molecule – also makes theseformations attractive as a carbon sink. Combinedenhanced recovery and sequestration projects arecurrently planned or underway in several countries(Stevens et al., 1998; Reeves, 2001; Pagnier et al.,2005).

2.2.6 Project summaries andcomparisons of appliedtechnologies

San Juan BasinThe San Juan Basin, located in northwestern

New Mexico and southeastern Colorado, USA(Fig. 17) is the most prolific coalbed methanebasin in the world, producing more than7.0�107 m3/d from coals of the CretaceousFruitland Formation. From a reservoir,completions, and production standpoint this basinis generally divided into two distinct regions: thefairway and non-fairway productive areas. Thefairway represents about 15% of the totalproductive area, yet this area yields over 75% ofthe total coal gas produced in the basin. Coalreservoirs are thickest in the fairway, locallyexceeding 30 m in cumulative thickness. This areais also set apart by over-pressured reservoirs,higher permeability (20-100 mD), and higher coalseam gas content. Outside of the fairway region,

coals are generally thinner (6-12 m) with lowerpermeability (1-30 mD) and normal- tounder-pressured settings (Schwochow, 2003).

The distinct differences in reservoir propertiesbetween the two areas lead to very differentcompletion techniques. Within the fairway, most(�90%) wells are completed using the cavitycompletion technique, while outside the fairwayconventional hydraulic fracturing, often multi-stage, is the norm. Typical production from afairway well is 1.7�105 m3/d with peak ratesreported at over 7.1�105 m3/d. Conversely,non-fairway production is in the range of3.0-11.0�103 m3/d. Production operations in bothareas have been transformed in the last decade.Previously, a high flowing wellhead pressure wasutilized to reduce or eliminate the need for gascompression. However, the desorption of the gasfrom the coal matrix was restricted by theseelevated pressures. Currently, many operatorsutilize a wellhead compressor to effectively reducethe flowing pressure to near or below atmosphericpressure, thus maximizing the desorption ratewithin the reservoir. Resulting improvements inproductivity have been achieved in both thefairway and non-fairway regions using this technique(Palmer et al., 1995; Ramurthy et al., 2003).

Powder River Basin The Powder River Basin in northeastern

Wyoming and southeastern Montana, USA, is themost active natural gas and coalbed methane playin the USA (see again Fig. 17). Uncertainty overthe potential for economic production of gas from



TertiaryTertiary-CretaceousCretaceous

JurassicTriassicPennsylvanian and PermianMississippian

Powder River Basin

San JuanBasin

Fig. 17. Location of Powder River and San Juan coalbedmethane basins, USA.

coals with very low gas content (�3 m3/t) delayedthe growth of activity in this basin. As of April1999, only 848 wells were producing3.8 million m3/d. By April of 2005, 14,034 wellswere producing 25 million m3/d, an increase ofover 100% annually. The combination of shallowdrilling depths (75-450 m), thick coal seams (up to90 m of total coal thickness), and highpermeability (100 mD�10�3-2 D) initiated theboom in development in the 1990s, which iscontinuing today (Williams, 2004; Hower et al.,2003).

Well drilling and completion is unique to thisbasin, in that single-zone openhole completionsdominate. These involve under-reaming or jettingof the openhole coal zone, followed by a waterinjection process to reduce skin and perhapsenhance near-wellbore permeability. In areas wherethick multiple coal seams exist within thestratigraphic interval, it is common to havemultiple wells on a single site, with each targetinga single isolated seam. Multi-zone completions areonly now beginning to be tested; there is stillconcern over formation damage in these permeablecoals during the cementing process. AlthoughPowder River coal gas production averages about1.7�103 m3/d of gas and 16 m3/d of water per well,high variability in both gas and water rate iscommon. Peak gas rates vary from less than 850 togreater than 2.8�104 m3/d while water rates inexcess of 160 m3/d are not uncommon(DOE/NETL, 2003).

Fort Worth Basin The Mississippian Barnett Shale in the

northeastern portion of the Forth Worth Basin(Newark East Field), USA, is the largest gasproducing field in the state of Texas and one of theten most productive in the USA (Fig. 18). Currentproduction is in excess of 3.5�107 m3/d with over1.5�1011 billion m3 of booked reserves. As with thecoal gas in the Powder River Basin, activity in thisshale play is relatively recent. The 450 producingwells in 1999 rapidly expanded to the more than3,700 wells existing today, with about 1-2additional wells completed daily in this shale, atdepths ranging from 2,000 to over 2,500 m deep(Curtis, 2002; Frantz et al., 2005; Montgomeryet al., 2005).

Although vertical, hydraulically fracturedwells dominated the play during its earlydevelopment (initial exploration and developmentwas in the early 1980s), there has been a rapidmove to the use of horizontal wells in the last 3years. Typical horizontal laterals vary from 150 to

more than 1,000 m and are completed eitheropenhole or cased and cemented, with thedecision often driven more by operator preferencethan reservoir requirements. Innovativemicro-seismic mapping of the induced fractureshave been widely applied in this play to betterdefine and improve fracturing techniques. Thevertical wells are typically completed with onelarge treatment (3.8�103 m3 of fluid with1.1�105 kg of proppant) while horizontals may betreated with up to 6 stages and 4.5�105 kg ofproppant. Individual vertical well productivity, aswould be expected in this naturally fracturedreservoir, varies from 2.0 to over 4.0�104 m3/d.The move to horizontal completions has increasedthe per-well daily productivity up to 7.0 to14.0�104 m3/d (Frantz et al., 2005).

Michigan Basin The heavily drilled and produced Devonian

Antrim Shale in the Michigan Basin, USA (seeagain Fig. 18), provides a unique contrast to theBarnett shale. This shale play saw initial and rapiddevelopment in a 3-year period from 1990 through1992, spurred by the US Government’s Section29 Tax Credit. Currently, over 7,000 wells areproducing approximately 5.7�109 m3/yr with totalproduction to date of 5.0�1010 m3. Although thisreservoir is present throughout the MichiganBasin, development has been limited to asix-county area along the northern edge of thebasin. Wells in this area target the shalereservoirs at depths ranging from 150 to 700 m(Curtis, 2002).

Two distinct productive zones within theAntrim Shale, the upper 24-metre thick Lachineand the lower 8-metre thick Norwood zones, havebeen targeted. Under-balanced rotary-percussiondrilling is the most common drilling technique.Although initially completed openhole, mostoperators currently use casedhole operations andtwo stage nitrogen-foam hydraulic fracturingtreatments. Unlike the Barnett Shale, the AntrimShale at first produces large volumes of water(sometimes in excess of 80 m3/d) with gasproduction starting low and subsequently peakingafter 1 to 3 years of production, similar to mostcoalbed methane plays. Gas production ratesrange from 1.4�103 to more than 1.4�104 m3/dwith average production approximately2.8�103 m3/d; water production averages 8 m3/d.Horizontal well technology and reduced wellspacing are beginning to be applied in the AntrimShale to improve per well recovery (Zuber et al.,1994a, 1994b).



2.2.7 International potential for coalbed methane and shale gas

With the success of the coalbed methane and shale gasindustry in the USA, Canada, and Australia, it wasinevitable that operators would begin to explore thevast potential for these reservoirs worldwide. Asdiscussed earlier, the overall size of the natural gasresource that is contained in the coal deposits of theworld is significant: 8.3�1013 to 2.7�1014 m3 (see againTable 1). Currently, studies are underway to more fullydefine the shale gas resource: estimates put the size ofthis resource in excess of 2�1014 m3. Accordingly,coalbed methane and shale gas represent major newinternational sources of natural gas.

Twelve countries contain approximately 98% ofthe world’s coal resources. Initial internationalcoalbed methane exploration focused on thesemajor coal-bearing areas; however, many countrieshave smaller, but significant, coal resources (andby extension important quantities of coalbedmethane resources). Individual plays in thesesmaller basins, particularly those close to markets,may provide commercially attractive opportunitiesfor operators. Shale gas resources andopportunities outside of the USA and Canada areonly now being assessed (Selley, 2005); the futurepotential may be significant.

Other important aspects of the internationalcoalbed methane and shale gas play are thelocation of these natural gas resources and thepotential environmental benefits of new gas

supplies. Many countries that have historicallybeen hydrocarbon-poor may have a significant gasresource base in these formations that wouldprovide an indigenous source of energy. Inaddition, many of these countries have reliedheavily on coal burning as the primary energysource, resulting in serious air and water pollution.Coalbed methane and shale gas may provide anenvironmentally more attractive energy alternative(Schlumberger, 2003).

Economic considerations and constraintsThe established coalbed methane and shale gas

industry has been the beneficiary of a number ofspecial situations that have greatly assisted its rapiddevelopment. The large, well-studied andgeologically simple coal basins (e.g. Warrior andSan Juan), the extensive history of gas productionand well penetrations through the shale reservoirs(e.g. Appalachian Basin), the fully integratednatural gas pipeline system, and early governmentsupport (via the Section 29 tax credit in the USA)have all boosted development and aided projecteconomics. Outside of the United States, however,many of these favourable factors do not exist. Aseries of political, geologic, engineering, andmarketing considerations need to be addressed forsuccessful international development of these gasresources.

Political constraintsCountries with established oil and gas

production have well-defined policies for the



productive gas Shale Basinsother potential gas Shale Basinsgas production areasoil production areas

WillistonBasin

Denver Basin MichiganBasin

IllinoisBasin

Fort WorthBasin

UnitaBasin

San JoaquinBasin

Santa MariaBasin

San JuanBasin

PiscanceBasin

LewisShale

BarnettShale

TuscaloosaShale

New AlbanyShale

OhioShale

AntrimShale

AnadarkoBasin

AppalachianBasin

ParadoxBasin

Fig. 18. Location of theFort Worth and Michigangas shale basins, USA.

acquisition of hydrocarbon leases or concessions.However, many countries with significant coalbedmethane resources (and possibly shale gasresources), but no prior oil and gas development,have little legal framework for administering thedistribution of these mineral resources. Thegranting of leases or concessions may be difficultand time consuming due to the lack of establishedlaws to define the method of granting or auctioningthese lands or the lack of definite laws governingthe ownership of these resources. In addition to thelegal uncertainties, incentives for the developmentof these non-conventional gas resources are oftenlacking in these countries. Where the coalbedmethane and shale gas industry of the USAflourished under the benefits of the Section 29 taxcredits, few financial incentives accrue todevelopment of these resources outside of theUSA.

Geologic constraintsThe Warrior and San Juan basins are stable,

intracratonic basins with relatively flat lying andlaterally persistent coal seams. The gas shalereservoirs in the Michigan, Appalachian, and FortWorth basins are similarly geologically simple. Theuncomplicated aspects of these basins lendthemselves to establishing large commercialprojects by providing a consistent reserve base anda simple producing horizon. Conversely, many coaland shale basins of the world have more complexstratigraphy and structure. Exploration techniquesdeveloped for these proven reservoirs are lessapplicable in these structurally complex basinsettings. These more complex coal basins willpresent a challenge to the exploration geologistmore familiar with the broad, easily definablefeatures of the coalbed methane and shale gasbasins of the USA, Canada, and Australia.

Engineering constraintsJust as the geologist may be challenged by the

complexity of these coal and shale basins, theengineer will face different but nonethelessdifficult challenges. The growth of the industry inthe USA, Canada, and Australia has relied heavilyon readily available oil field services and materials.The availability of these services internationally islinked to areas of established oil and gasoperations. While locations such as WesternEurope have extensive services and infrastructure,other major coal basins (e.g. the coal basins ofsouthern Africa or central Russia) have no locallyavailable oil and gas services or materials. Thus,shipping and mobilization costs will become a

major cost item, especially during initialexploration and pilot testing. In addition, otherfactors such as weather, especially the colderclimates of northern Europe and Asia, willadversely impact production operations (especiallywater production and disposal). The remotelocations of these basins will increase personneland overhead costs; the environmental restrictions,especially in the heavily populated regions ofwestern Europe, will increase drilling andproduction costs; and, in the case of coalbedmethane, the necessity to coordinate with localmining concerns will also need to be addressed.

Marketing constraintsIn the USA and Canada, the existing natural

gas pipeline system has provided a ready means fordistributing and marketing the produced gas.However, establishing natural gas markets outsideof the USA and Canada will be more challenging.One of the major restrictions on coalbed methanedevelopment in Australia was the lack of pipelinesto carry the gas from field to market. In manylocations there are no existing pipeline facilities forthe distribution and sale of the gas. Pipelineconstruction of hundreds of miles may be requiredto connect the coalbed methane or shale gas play tothe market. In addition to the lack of transportfacilities for the gas, a market to use the gas mayalso need to be established. This may require thelong term conversion of population and industrialcentres to natural gas use, the installation of gas-fired electric power plants (especiallyco-generation facilities), and the constructionof new chemical plants for fertilizer or methanolproduction. The use of the gas as a transportationfuel, such as Compressed Natural Gas (CNG) orLiquefied Natural Gas (LNG), may also providealternative markets for the produced gas. In manycases, a successful international coalbed methaneproject will need to be a fully integrated,self-contained project – from drill bit through theburner tip.

2.2.8 Conclusions

Coal and shale gas production is increasing newtechnology advancements and more efficient use oftools and techniques are improving ourunderstanding of reservoir conditions. Success inexploiting and producing this gas will requirecontinuing coordination and integration of inputfrom all disciplines. The pace of futuredevelopment in coal and shale gas will depend on



the economics of exploitation. Technology ratherthan prices will be the driver for enhancedunderstanding of reservoirs and improved projecteconomics.

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Charles M. BoyerJoseph H. Frantz

Schlumberger Technology CorporationPittsburgh, Pennsylvania, USA

Creties D. JenkinsDeGolyer and McMaughton

Dallas, Texas, USA



2.2 Non-conventional gas - Treccani, il portale del sapere

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