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ECONOM CSFDEVONI ANHALE COALSEAMAND

SI M LARPECI ALAPPALACHI ANASSOURCES

by Richard M. Mill’;rand Norman E. Mutchler,

Berxw Associates

——

his paper was presented at the 1980 SPE’DLIE Symposwrn M unconventional Gas Recovery held InPittsburgh. Pennsylvania, tdti~ 18-21, 1980. The material is subje

]rrection by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central ExPwy., Dallas, Texas 75206

I

.

ABSTRACT

cstlm~tes of the potentialsof the difficult gas

sou~ces were msde under existing and improvedprice

The nat ‘al gas curtailmentsduring the winter cost relationships.

of 1976-77 and the threat that gas interruptions

would become a permanent way of industriallife

THEOXY AND DEFiNITICINS

sparked widespread interest in the investigationof —

——

local, higher-costgas sources.

Analyses of the

The term marginal gas source is used to descr

technical, institutional,legal and economic cm-

a ‘highercost’ gas.

The reasons that a gas

straintsand opportunitiesassociated with these gas

source(s)may be high coat are many, varieL and oft

sp .-aslocated j.nthe

Appalachian

Region were under- ‘

interrelated.

Technical, geologic, institutional

taken for the Appalachian Regional Commission.

The

and attitudinal factors f~equently combine in some

economic potentials appeared encouragingproviding

way to adversely affect the profitabilityof recov

certain constraintsare removed andlor relaxed.

and the economics of using a marginal gas source.

Such are the circumstance~with regard to exploiti

INTRODUCTION

the relatively abundantAppalachian gas.resaurces

froa coalbed methane, the Devonian Shales and cys

Natural

gaa

is an important fuel throughout the

from other difficult Appalachian sources,.

Appalachian RegScn. Yec only two of the thirteen

Appalachian statea produces sufficientgad to supply

GAS XOM COALBEDS

their own needs (Table 1).

Understandably,then,

industrialgae curtailments resulting from the natural

T}.’reasons that this resource has not been

ges crisis during the winter of 1976-77 stirred wide-

utilized are many and varied:

spread interestamong northeast industryand public

officials to secure independent supplies of gas from

 

“.egalownership problem

sources located within the Region.

0 Coal operatorattitude towa;d utilizatio

“ Profitability

This paper describes the research and the report

0 Other institutionalfactors includin.~

done for the Appalachian Regional commissionon the

regulatory

prospects and opportunitiesof marginal gas sources

0 Technical

in Appalachia aa they r~late to maintaining and

“ Safety

increasingeconomic development tn the Region. Three

categoriesof msrginal sourcee were studied -- gas

0

Profitabilityhas not been established in the

from coalbeds, Devonian Shale and other dj.fficult

minds of many coal operators, even some who have

sources.

The Lattercategory includedother low previously cost-sharedprojects with the Bureau of

permeable gas furmationa, deep drillingand gas from

Mines.

This is probably due to the marginal econ

Lake Erie. omits and the experimentalnature of the few proje

underway or completed.

Utilization suffers from

This was pr~marily an institutional-typestudy

limited replicationof successful demonstration

of governmentalenergy and non-energy programs and

prcjects.

activitiesand the actions of the private sector.

Technical, economic and institutionalfactors were

Technology in general exists for utilization

analyze< fro% the standpohts of the literature,many

but needa s~aling down in most casee for this lowe

and varied interviews,xildfrom case histories to try

volume, lower gas pressure source.

Except for a

to discover the encouragingand constrainingaspecls

few pipeline injectionproje.ntsand-a few current

to greater expansion.

Eased on these factors

experimentalprojects there are not many examples

utilization.

Referencesand illustrationsat end of paper.

187

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- ~- ,a

AS FROM DEVONIAN SHALES

legislativeand environmentalactions, rather t

becauee of any problems with technology.

The o

Devonian Shale wells are typically low permeable, tinnd Ganadianoffshore rig count in thfl;ske

low productivity, 10ng-li?Jedwells.

The main factor

presently limited to about one-half dozen.

appears to be fracture permeability.

By some esti-

depth, projected well depth, and rock pressuree

mates only about four percent of the gae is recovered not require the larger more >owerful and costly

under preeent technology in the Eetter Fields.

tions used in the Gulf or Outer Continental She

 ,OWpermeable eources such ae the Medina Format

There are an e;stimeted9,615 producingwells

will be the maiz target.

(P. J. Browr,,1976) in eastern Kantucky (70 percent

of state as production),West Virginia, Ohio and

f

The Initial economic objective was to dete

Virginia.

the wellhead prices that would induce significa

expansion of produc~ionof each of the marginal

Fifty-five percent of Devonian Skdle production

gasses.

Productionhistory data was collected

ie estimated to be b’:utilities,40 percent by inde-

numerous repox’.s(Reference 3 is illustrativeo

pendents, and lese than five percent by producer-

documentedresearch) and from other case histor

consumers.

that was gatheredby interviews.

The economic

-:vestigationof the potentials of the three ma

The main constraints against expansion of this

‘

~s sources,however, could not be conducted wi

eource dre:

consideringthe critf.calnon-economic factors.

projectionsthat are presented, then, incorpor

0 Long payback period to recover investment

~

\udgmentalassessment of the nan-economicfacto

“ Low price of gas

0 Rising well completioncosts

ECONOMIC Projection RESULTS

0 Need for improved technology

GAS FROM COALBEDS

The total in-plac?Devonlsn gas resource has been

(Ssttited to range betweem 500 to $00 tcf in ~he coSt

Ecstem United States.*

Such an abundance of gas

caw~ot rationallybe ignored by the numerous ener~

l–

1> .mugh Bureau of Mines’ investigatorsar

deficientef.~te?nindustries.

reportedly encouraged by the economic potentia

the ve~t shaft/horizontalborehole production m

GAS FROM OTHER DIFFICULT SOURCES

iL suffers from an extremely limited cost data

since the BureaulEasternAssociated Coal Corpor

Historically,explorationand developmentof

project was experimental.

Consequentlythe co

natural gas in Appalachia has been eest?~tially a the

used for the return on investmentanalysis”wer

areas of known, easily recovered gas fxelds. Records

indicate that over 590,000 oil and SSS wells have been

associatedwith the vertical borehole, a widely

oil and gas development technique,

drilled into the Basin.

Further, the gas wells

average 3,700 feet in depth and 84 percent of accum-

The cost range depicted in Table 2 corresp

ulated natural gas productionhas come from Pennsyl.-

to variations caused by subsurfaceand surface

vanian, Mississippian,and Devonian Formatims.

tions and other cite specific locationalfactor

Correspondingly,85 percent of known Appalachian gas

i~cludingaccessibility,and also variable char

reserves lie in the same regions asthe above drillingby producer type. Since the data bas

formations.

so linited it was decided that average costs wo

be the best ir.dicatorthroughout the Region and

A difficult, low permeable formation is generally

defined as one having a permeabilityless than 1.0

therefore,a more reasonablemeasure of potent

profitability.

A second reason for choosinga

millidarcyand an effective porosity of less than

costs, as presented in Table 2, was the consid

twelve percent.

An examination of formations

that future development vould appear to have t

throughoutthe Basin reveals that such characteristics

are common. However, a gas-bearhtghorizon could be

greatest potentialamong the.larger coal opdra

whose costs would tend to correspondwith hfgh

an excellent producer in one field andi.et be a rela-

t

head ut$l .ties.

tively impermeablerock as close as a ew mtlea

‘his result, notwithstanding

tinuing coal operator”reluctance,was the cons

away.

of those interviewedduring this study,especi

utility representatives.

Yet there is an add

Drilling and completion technology for the low

modifying condition tha~ would suggest lower c

permeable formations is similar to that discuesed for

production.

It is generallyagreed that the e

Dtwonian Shales.

Of course, the stimulationmethod

design will vary for indivi~tial.ell para.-ters,

omits will only be improvedon a productionbas

say field developmentof 25-50 wells, where ec

while drilling techniqueswill be more standard.

of scale vould result in lower per well costs.

Hence, although indicationsare

that

the highe

The deeper Silurian, Ordovician,and Cambrian

head coal companiesare likely to be the prime

rocks have not been adequately explored. Deep well

opers of methane gas resources

it is also ;xp

drilling does have one additionalproblem.

In 1977,

that significantexpansion WO.IU \e on a scale

the Hughes Rig Count showed 223 rotary drille in the

ftcient to affect eoxnecost r?+~ctlnfi.

The a

entire Northeast Region of the United Statee, but

only eleven were capable of drillingbeyond

price condition ehown in Table 2 satisfiedbot

conditions.

10,000 feet.

Lake Erie offshore drilling is a difficult

source (i.e. marginal) because of the various state

—

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Production

Productiondata are presented on the basis of

typical l~ighand lowyleld methann wells (Table 3).

The production data pertain solely to removing methane

from coalbede in advance oi miningby surface vertical

boreholes. The productionprofiles reflect composite

coalbed degasificationexperience from a group of

wells

~~ the Pocahontas NO

.3 and Pittsburgh Coal-

beds.

The productionprofiles representwells

that inclu~e stimulationand continuing desline over

the 15 year analyticalper%d.

It is recognizedthat

in an actual field project individualwells could vary

widely from the norm.

Results and Projections

The analytical results of the discountedcash

flow -

return on investmentcomputations are pre-

sented In Table 4. The results show that production

from a higher volume productionwell is econo

~ally

viable at al Pricesa

Unfortunately,experience is

unable to provide assurance of achieving production

volumes as presente? in this case.

The high volume

producer represents limited oper~cing experience in

the Pittsburgh coalbed where netural fracturinghas

created unique productioncircumstances.

For%he lower volume production example it would

not be economicallyfeasible to develop this resource

at the lowe~t price. At a price of $2.00/mcf the

investmentachieves margina: acceptance. At

 43.001mcfthe lower volume proc uceria an attractive

investment.

Although various demonstrationshave shown that

production is generally improved through stimulation--

too little is known at this time of its potential for

increasingmethane production (or the effect of stim-

ulation on the mine roof and floor).

Many more

deumstrations encompassinga broader geologicaland

geographicalarea are required before definitive

results can be reported.

Nevertheless,higher wellhead prices would con-

ceivably improve the economic attractivenessof zhis

marginal source. Assuming that the lower volume

example has a higher occurrence probability,then an

increased wellhead price could have the effect of

expanding the recoverablereserve base for methane

gaa recovery.

To date, slightly less than three bcf of methane

gas has been produced for commercial sale. Ap;.ro%i-

mately one-half has been produced from 23 vertical

borehole wells over a 29 year period. And, slightly

leas than half was produced from two demonstration

vent shaftswith horizontalboreholes -- one of which

produced gaa for sale over a 2+ year period while the

other was productivefor about 1+ years;

the approxi-

mate remainder has reportedlybeen produced by sev-

eral coal companiks on a very limited basis.

Since these few examples’areinsufficientevi-

dence of potential opportunities,the approach to

estimating future reserves must otherwise depend on

judgmental analysis.

Coal operators wiI 1 extract methane gas, but

they will be reluctant to utilize it.

At 1977-78

gas prices the market value of the coal was about

100 times the value of the gas. At +2.50/mcf it

would still be 60 times greater, and given the sam

percentageof profits from coal/gas, the increase

profit would be only 1,5 percent.

Furthermore, at higher prices that apply equa

to all gas sources, the relative economics are in

favor of expansfon of conventional sources. A

higher price for all natural gases would generally

not alter the relative attractivenessof difficul

source gas as compared to conventional gss.

Unde

standably,then, deregulation affecting all gas

sources,or simply a higher c~iling price for all

would in general result in considerableexplorati

and development of new conve~tlonalAppalachian ga

and the pz%entially much larger volume of off-chor

gas in the Gulf of Mexico, gnd similar convention

gas sources.

This probable pattern of natural gas explora

and development is not meant to indicate that no

expansion would occur in recoveringmethane gae.

Obviously,a higher natural.gas price would impro

methane extraction and utilization profitability,

as a result some coal operators might be encourag

t~~reexmtie methane opportunities.

It has been estimated that the cumulative App

lachian Region coal productionbetween 1973 and 19

may be 14.2

~JillkIII

tons.6

The West Virginia -

Pennsylvania&Fea featur

many characteristicsfavorable to methane extract

- Lerge coal reserves

- Considerablepresent and future mining

activity

- Extensiblepipeline system (especiallyi

the northern sections)

- Large eized coal and utility companies

It is, therefo”ce,the ‘bestfcandidate for the dev

opment of methane extraction expansion within the

Appalachian vtates. At present 100 million cubi

feet per day (or approximately 36 bcf per year) of

methane is wasted co the atmosphere from the Pitt

burgh vein alone. If over the next 20 years ten

percent of the total 700b:? of methane were to be

recovered for commercial application then 70 bcf o

methane would be added to t’heproducible reserves

Consideringthat a vertical well has about a 20 ye

life and total producible reserves of 120 mmcf, t

the 70 bcf of methane could be recovered ~

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ECONL?fICSOF DEVONIAN SHALE, COAL SEAM AND SIMILAR SPECIAL APPALACHIAN GAS SOURCES

I

to the methane gas producible regerve base. As

noted, Appalachian coal productionmay total more

than 14 billion tons over the next 20 years.

Assum-

ingon the average that each ton of coal .on;&ins

300 cf of methane gas, then approximatelyfour tcf

of methane gas would be contained in the coal. Con-

sidering also that ten percent of the methane con-

tained in this coal might be recoveredprior to,

during and follow ngmining, then approximately

400 bcf of methane could be added to the producible

reserve base.

Figure 1 - Projected Appalachian Methane &s

From Coalbeds, illustratesthe two prospective out-

comes supportedby a higher gas price and estimetted

coal production.

Relating methane extraction to the

anticipated coal production eve. a 20 year period can

be 8upported on various fronts.

Future coal produc

tion will.largely be extracted from deeper, gassier

seams causing increased ventilation costs and

increasedrisks to the safety of the miner.

Mining

productivitywould also be affected through mining

in gassier seams.

Coal cperators could, therefore,

be attra.ted increasinglyto extracting the methane,

but it will be a gradu%l process as theybegin to

utilize more of the gas, perhaps through further in-

creaftesin gas prices.

At a price level of, say, $2.50/mcf the oppor-

tunity wi.tlbe present to induce tha necezsary experi-

mentat3.on.

At this price other constrainingfactors,

especially the gas rights issue,might be’resolved

through cooperation,especially with suc ceding gas

price increasee.

While any estimate

 

futcre pro-

ducible reser~es must necessarily be based on factors

other than experience -- such as future mining

activity - it would appear that the required tech-

nology refinementswtiilenumerous, do not need tc be

major.

GAS FROM DEVONIANSHALE

costs

L’oststo develop a Devonian Shale well can vary

wide~i due to geologic and topographicconditions,

accessibility,labor rates and work rules, overhead,

etc.

Table 5 presents cost data for Devonian Shale

producers base,lon informationcontained in the liter-

ature and supp>rtedby discussions with company-

~~fficials.?&covered under the case studies.

Pzoducers of Devonian Shale gas must StiIIMlate

their wells.

The

two most common methods of stimu-

lating a well are by shoottig, or normal hydraulic

fracturingwith primarily water-based fluids. The

stimulationmethod e~ployed would appear to depend

principally on the past practices and experiences of

the producingcompany with one particular technique.

Sttiulationcosts range between $5,000 and $150,000

per well.

The lower costs represent nitroglycerin

skts and the $150,000 is indicativeof the cost of

a k%ive Hydraulic Fracture (NHF).

Normal hydraulic

fractures are estiuatedat about $l0,00f1to $20,000

per well..

Annual operating costs, includingmaintenance,

generally fall within the range of $500 - $2,000 per

well. Agatn individualcircumstancesand opera-

tional maint~-nancepractices determine these costs,

but it would b.?unlikely that any operation costs

.

would be outside this renge.

There is not s

ference between che operating

costs

of the th

ducer types.

Production

Production data have been obtained from

study data.

The figures shown in Table’6 re

a typically good prodccing well, experiencin

productionnormally three to five yt?arsfoll

ctimulatiun. The use of a typical good pro

well perforrsnce profile is not i~.tendedto

that similar production is not Geographicall

strained.

The reported ranges of .elllife

tion are 250 to 460/mmcf. In fact, conside

variability of productioncan and does occur

wells even at the same location.

However,

prime purpose of this analysis is to compare

investmentpotentials of the various produce

is convenient to calculate the return-on-inv

employing a single productionenvironment.

production data used is taken from the prese

producing areas.

Results and Projections

The analytical results of the discounte

flow - return on investmentcomputationsare

in Table 7.

The -olmns depict the four pr

natives selected for this analysis.

The ro

include the alternative investmentcosts for

hydraulic fracturing.

The entries in the b

the Table are after-tax returns on investmen

in percent) based on a typical production pr

the alternative price levels, and the associ

revenue

- cost profile.

This analysis considersa profitable in

opportunity for ROI1=,

after taxes, of ten p

or greater.

The Table clearly illustrateswhy Devon

gas is a marginal source.

Ata price of $1

(regulatedgas price at the time of the anal

Devonian Shale development is not economical

fied. At a price of $1.75/mcf it is only a

ally attractive investmentfor the low cost

As the price reaches a level of $2.00/mcf an

the return generally is sufficientto warran

investment.

These analytical results generally conf

the operating experiences occurring at the t

the analysis.

The principal producers were

firms —

independentand utility -- whose de

costs were generally compatiblewith that de

for the low cost investment.

possibly

beca

the location, the costs of one of the larges

producers from the Devonian Shales - Kentuc

Virginia Gas c.~mpany-- are generally lower

reported for other utility companies.

Thei

costs for development may also be attributa

fact that they are quite experienced in deve

this source.

Smaller independentproducer

enced in the Devonian Shales also have costs

the average.

Alternatively,as reported, the higher

ducers, mainly the larger utilities,were no

oping this source since the return did not j

the investmentat current prices.

~is res

190

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. . .

RICHARD M. MILLER AND NORMAN E. MUTCHLER

borne out by the findings in Table 7 which similarly

illustratethat the current price le’leldid not jus-

tify the investw.& for average or high cost producers

The producer-consumeris a special category of

producer type not necessarily guided by price consid-

erations,but rather by assurance of supply. The

data base on coats for the producer-consumertype

wa

inconclusive.

Consequently,any comparison reluive

to the cost data used in the rate of return analysis

is not possible.

It is also noted that the results of the study

conductedby the Office of TechnologyAssessment (OTA)

were comparableto those preaected in this report.y

in that study, a price level of $2.00/mcfwas the

lower limit warranting significantexpansion of

these resources,essentially the findings of this

report.

The cost estimatea used in both reports are

essentiallythe same.

*

;.nthe absence of total natural gas deregulation,

or detagulationapplying only to unconventional

sourc~q,Devonian Shale production should, neverthe-

less, expand due to the recent gas price increases.

Such a csticlueionwas supportedby widence that

showed Devonian Shale well development increasing

slightly in response to higher prices. However,

expansionbased on existing price ceilings and tech-

nology would be limited to less than one tcf over

a 20 year period. The principal constraints limiting

further expansion are a low rate of return relative

to conventionalsources, developmentdifficulties,

and higher costa and risks associatedwith deposits

lying oute.tdetha already densely developed ‘better

producing brown shale areas.

Si&ificant and immediateexpansion in the short

term would be limited by geologicaland technological

constraintsand the available drilling industry capa-

City.

Consequently,the approach in-determti-i.nghe

economicallyrecoverable reserve base involves a

comparisonof alternative scenariosas shown on

Figure 2.

Total well drilling in the four state area in-

cluding West Virginia, Kentucky, Ohio and Pennsyl-

vania had been increasingat an annual rate of about

twelva percent per year.

Devonian Shale well comple-

tions in the same period averaged a little less than

three percent of total well drilling.

Based on the

available data, it is estimated that approximately

5,300 wells were drilled in the four states in 1976.

Therefore,an estimate of 1976 Devonian Shale well

completionswould be on the order of 150 wells.

Expansion of Devonian Shale reserves can be

anticipatedto occur in two phases.

~hase 1 repre-

sents the potential expansion under alternativepric-

ing policies.

The response from a higher price

shouldbe visible within three years.

Phase 2

representsa much larger potential increase in

reserves based on substantialtechnological improve-

ments, particularlywith improvementsin stimulating

the less permeable grey shale formation intervals.

Departmentof Energy test drilling and core analysis

have already shown that natural gas exists in tha

full column of the grey shales and not just in the

rich brown shales. However, the higher tensile

strengthmakes them harder to fracture than the brown

shsle;.

W’jor technology improvementson L ro

commercialbasis likely would not be available u

about 198& -- at whit% time the current DOE Eas

Gas Shales Project will have been concluded.

B

phases are shown tinFigure 2 and diBcussed below

20 year period is considered.

Phase 1

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ECONOMIC5 OF DEVONIAN SHALE, COAL SEAM AND SIMILAR SpECI~ APPALACHIAN GAS 8ovR~ES

be somewhat delayed for difficult source gas, hence

a three year lag representsChe time requiredbafore

the effects of deregulationmight be visible.

The 20 year increase in recoverable reeerves has

been es~hated et seven :cf.

Deregulationof Devonian Shale Gas (Scenario3

and 3A)

Like the basa case and total deregulation,the

effect of deregulationof Devonian Shale gas only

essentially representsa stimulantto development

witl;current technology.

In this case the natural

gas price is considered to be at a level of

$2.00/mcfwhile the priceof Devonian Shale gas is

$2.50/lncf.

Therefore, total gas industry expansion

in the Appalachian Region is assumed to grow at the

same rate used to calculate reserves

in the base

case.

Howevar, the economic disadvantagespertaining

to Devonian Shale gas would be removed and, as a

result, added incentive is provided in expanding

drilling for Devonian Shale gas rslative to conven-

tional sources.

It has already been mentioned that additional

productionwould have to come from areas other than

the so-called ‘betterproducing’ areas.

However,

the bulk of the productionwould continue to come

from these areas with more Intense well spacing both

within the area and nearby. lhis need not be a sub-

ject of probability,?v?causea massive Devonian Shale

characterizationprogram is underway involvingmost

of the affected State Geological Surveys and coordin-

ated by the U.S.G.S. Together with improved

remote sensing,aerial and ground surveys and other

techniques for locating joints and lineaments,

expanded promising areas should be known somewhat

before the beginning of the second decade.

For this

reason, this portion of the curve is shown as Scen-

ario 3A on Figure 2.

Known recoverablereserves would increase to

17 tcf between now and 1998.

Technological Improvements (Scenario3 and 4)

The significantcontributionof Devonian Shale

gas cannot be achieved without techniquesthat would

either lower costs, increasegas production,or both,

along with a higher gas price to increaseprofit

margins.

The ARC study compared the geographically

limitednaturally fractured brown shale areas wit ?

the muck larger geographicallydistributeddeposits

of non-fracturedbrown and grey shales. These lattez

shales are variously I.abelledlight grey shales, grey

shales, or greenish-greyshales. In order for these

less permeable locations of shale to make a signifi-

cant contribution, it would be neceseary that tech-

nology be advanced, principally in the area of new or

improved techniques to stimulate the grey shales and,

of course, non-fracturedareas of brown shales.

How-

ever, it should be pointed out that such a technical

breakthroughfor economicalhigh productivitystimu-

lation technology is by no means assured.

However,

the potential warrants the effort. According to

DOE, as much as 150 tcf of Devonian Shale gas could

possibly be added to the nationls producible

reserves.

Figure 2 shows that an economic technol

breakthrough in stimulationtechniquewould s

:::~l&elerate the produciblereservesbeg

. DOE’e $80 million, eight year r

program {e directed toward achievementof exp

produci?ie reserves through technological imp

and def-lnlngthe resource.

GAS FROM OTHER DIFFICULT SOURCES

This category covers all other known mar

gas sources locatad in the Appalachian Regio

includes~ (1) other low permeable formation

(2) deep drilling; and (3) offshore drillin

Lake Erie.

Other difficult source wells would invo

or more of the following characteristics:

1.

2.

3.

4.

5.

6.

Targeted horizons are below or remote f

those normally sought.

Stimulationrequires special design

considerateons.

Drilling requiresnon-standardtechnolo

Productionvolume sold is low compared t

investment Involved.

Statutory or regulatory restrictionspr

or hamper development.

Low success ratio.

Because of che general similaritiesto D

Shale well development--

geophysical,techn

and economic --

the potential of broadening t

economicallyrecoverable reserve base would b

parable to the potential opportunities for t

Devonian Shales.

Accordingly,at a price of $2.50/mcf wi

ulation of difficultsource gss only, the pot

producing reserves over the next 20 years fr

‘OtherDifficult Sources’may be in the rang

20-30 tcf, or an average of 1 to 1.5 tcf per

The bottom of the range (20 tcf) essentially

sponds to the potential from Devonian Shale.

similaritiesbetween the Devonian Shalesand

slightlymore attractive low permeable shall

gas sources permit an order-of-magnitudeest

for “DifficultSources” that corresponds to

rigorously derived Devonian Shale estimates.

upper range (30 tcf) ie a very tentativeest

reflecting the growing interestand hopefull

tials in deep well development,tight sandst

some limestones).

It is noted, however, that the potentia

expanding the recoverable reserve base may b

slightlyhigher in this category (20-30 tcf

20 years) for the followiug reasons:

1.

‘OtherD3ifftcultSources”encompasses a

other marginal gas sources at variotisd

shallow to very deep.

2. Low permeable

in the Berea,

“quick flush’

shallow wells, such as th

Clinton,Medina, etc., ha

and slightlygreater yiel

192

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.,*

RICHARD M. MILLER AND NORMAN E. MUTCHLER

. —.

3. Ohio, a major Appalachian industrialstate, is

ARC 77-2-co-5246,“Study on Dev@ian She;e, Coal

encouraging greater expansion of both low per-

and Similar Special Appalachian as Energy Prosp

meable shallow wells and deep wells.

In the

and Opportunities”.

four yeare since its inception,the results —

in terms of ticreaeeddrilling - are quite

The work was under the directionof Dr. Dav

noticeable.

Maneval, (former)Technical Project Officer and

Science Advieor, and Dr. John J. Demchalk, Direc

4. Deep well drilling,while a high risk venture,

Natural Resources Division, Appalachian Regiona

may pay off in the discove~y of large volume

Commission.

reserves.

REFERENCES

.——

A producing reeerve of 20-50 tcf over a 20 year

period would require the completionof approximately

1. Brown, P.J.: “Energy From Shale - A Little

50,000 successfulwelle (over 70,000 total drilled

Natural Resource”, National Academy of Sci

wells aseuming a 70 percent success ratio).

The

FE-2271-1, 1976, pp.86-99.

50,000 welle are based on the presumption that most

of the reeerve would be produced from low permeable

2.

Avila, J.: “Devonian Shale as a Source of

ehallow wells each producing about 400 mmcf over a

Chapter 5, Natural Gss From Unconventional

20 year life epan.

Geologic Sources, %ational Academy of Scie

1976, p.113,

Recoverable reserves from approximately50,000

wells would range between 20-30 tcf between now and

3.

TRW Energy Syetems Planning Division: Sys

1998 with deregulationof dffficult source gas only

Studies of Energy Conservation,“Methanz P

and current technology.

Again, the higher figure

duced from Coaliieds”,2 Volumes, McLean, Vi

(30 tcf) reflects the potentials primarily in deep

glnia, January, 1977.

drilling.

4.

Cervik, J. and Elder, C.H.:

‘fRemovingMet

CONCLUSIONS from Coalbeds in Advance of Mining by Surf

Vertical Borehole”, Reprinted from Prucee

Estimates of mazginal gas source devdoprnent in

Conference on the UndergroundMining Envir

the Appalachian Region must be largely judgmental due

Universityof Missouri - F.ollaand Bureau

to the many non-economicconstraints to expansion. Mines, October 27-29, 1971.

Nevertheless,a more fav;rable gas price should prom-

ote expansion eince the economic inducementshould

5. Productionprofiles of Equitable Gas Compa

encourage the eliminationof the non-economic bar-

Wells in Wetzel

COUilty

West

Virginia.

riers.

As intended in performing the study for the

{

Appalachian Regional Commission the economic consid-

6.

Miernyk, W.H.:

“Coal and the Future of th

eratio=s were presented so as to derive appropriate

Appalachian Economy”, Appalachia,October-

programs.

November, 1975, pp.29-35.

ACKNOWLEDGKMENTS

7. Congress of the United States, Office of T

nology Assessment,

“Status Report or,the G

l%is paper is based on work completed as part of

Potential from Devonian Shales of the Appa

the Appalachian Regional Commission Report,

chian Basin”, November, 1977.

193

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b

TABLE1

State

NATURALGAS PRODUCTIONAND USE

WITWIN

APPALACHIANREGION- 1976

Alabama

Georgia

Kentucky

Mmyisnd

Mississippi

New

York

North

Carolina

Ohio

Pennsylvania

SouthCaroline

Tennessee

Virginia

WestVf,rginia

BILLIONBTU

NaturalGaa

Natural0ss

Production Use

.

A

o

63,375

75

1,619

752

0

40,996

89,975

0

26

6,937

146,311

350,066

161,748

46,627

26,910

9,164

54,455

25,515

21,334

104,048

274,583

38,795

124,661

11,568

104,276

1,003,600

otals

Source:

BrookhevenNationalLaboratory,The Ener~etics

of the UnitedStatesof America:

An Atlas;

AmericanGae Association,aturalGasesof

NorthAmerica Vol.2; and BergerAssociates.

TABLE2

TOTALESTIMATEDMETHANERECOVERYCOSTSPER WELL

(1977Dollara)

Vertical

BoreholeMethod

ExtractionCoet

CollectionSystemCost

TOTAL,DEVELOPMENTCOST

Operationand Maintenance

(PerYear)

VentShaftWithHorizontal

BoreholeMethod

.— —

ExtractionCoat .

CollectionSystemCost

TOTAL,DEVELO= COST

Operationand Maintenance

(PerYear)

LargeIndependent

Producer/Large

Utility

Producer-Consumer

 52,000 5.2,000

$14,300

$ 14,300

$66,300

$66,300

$ 1,00G $1,000

NJA

$566,000

$60,000

$626,000

4 2,500

small

Independent

Producer

 33,500

 6,300

 39.,80’/,

6

:1,000

N/A

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TABLE

3

Year

..—

1

2

3

4

5

6

7

8

9

10

11

Ii

13

14

15

PRODUCTION PROF~LE FROM COALBED GAS

(mcf per year)

ah

Yield

14,400 (i.e. 40,000 cfd)

13,900

13,300

U ,800

i

12,200

11,700

11,200

10,600

10,100

9,500

9,000

8,500

7,900

7,400

6,800 (i.e. 18,900 cfd)

LOW

Yield

——

7,200(i.e. 20,000cfd)

6,800

6,500

6,100

5,800

5,400

5,000

4,700

4,300

4,000

3,600

3,200

2,900

2,500

2,200  i.e. 6,000

cfd)

TABLE 4

RETURN ON INVESTMENT,AFTER TAXES

(Pezcent)

METHANE RECOVERY

VERTICAL BOREHOLEMETHOD

WELLHEAD PRICE PERMCF

$1.42

$2.00

$3.00

PRODUCTION

High Volume

22.0

34.2

54.3

Low Volume

*

11.3

22.3

*Resultingreturn after taxes less than 10 percent

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Development

Costs

OperaRingCosts

Price

TABLE5

- XMFOSITEEVIEWOF ECONOMICDATA

DEVONIANSHALE

PRODUCERTYPEi

(1977Dollare)

,.

Independent

 &&Q

Producer

 80,000 - 160,000

 50,000-.125,000

(small

Independent)

 S0,000- 160,000

(Large

Independent)

 1,000-2,000

 500- 2,000

 0.295

- L.421mcf** 1.75- L.SO/mcf

Producer-

Consumer

*

*

*

(Interstate) (Intrastate)

 0.295- 1.42hcf**

(Interstate)

*Intereetand limiteddevelop~ntby producer-consumers6 quite

recentand generallyhas not bsen available.

;**?nxmerERCragulatadprice (1977).

TABLE7

TABLE6

TYPICAL

PRODUCTIONPROFIL

DEVONIANSHALEW

(mcfperyear

YEAR

-..

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

RETURNON INVESTMENT,AFTERTAXES

1

(Percent)

DEVONIANSHALE

WELLHEADPRICEPER MCF

—

 1.42

 1.75

~, ~

—.

NormalHydraulicFracturing

Low Coet

- 117,500

*

:0.5

12.4 21.3

AverageCc’at- 140,400

* *

10.0 17.6

.J

HighCost. 162,500

* *

*

14.9

*Reau]:ingreturnaftertaxeslees than10 percent.

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  .’

TABLE8

DEVONIANSHALE

ESTIMATEDECONOMICRESERVEBASE

(1978- 1998)

20 Year

Number Reserve

Price

of Wells Addition

1 BaaeCaae

$2.oo/mcf 14,36>

4.0 tcf

2

DeregulateAll Gaa

 2.25fmcf

25,565 7.0 tcf

3 & DeregulateDifficult

3A sources

$2.5olmcf

61,200

17.0tcf

4 TechnologyImprovemxit

* *

*

*Undetermined,ut well tn exceaaof Scenario3;

aarliestdate

equals19SS.

500

450

 

400

~.

I

/

350

300

250

200

150

100

70

50 --

MinimumBaeeCase

-— ~

...~

_~

o

t

~?

I 1

1

I 1

I

I

-f

197s 1980

1985

Time fn Years

1990

1995

FIGURE1 - PROJECTEDAPPALACHIANMSTNANEGAS FROM COALB~S

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24

22

20

18

16

14

12

10

8

6

4

2

0

1

1980

PhaseI Expansion

—..

1985

(4)

/

1

/

 

I /

I

/

/

 3a

/

/

/

/

/

/

I

I I I

1

I

I

I

I

1

I

1 1 I I

I 1

I

Time in

Years

199C

FIGURE2

- PROJECTEDAPPALACHIANDEVONIAN

1395

SHALE

,J