spe14446_shale gas reservoir

8/7/2019 SPE14446_Shale Gas Reservoir

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Evaluat ion of DevonianShale Gas Reservoi rsChar le a R. Vano rsdal e, SPE, consultant

~Summa ry. The evaluation ofpredominantly shale reservoirs presents a problem for engineers traditionaleducated either to correct for or to ignore such Mhologic zones. CurrentIy accepted evaluation techniqu~ andtheir applicability are discussed to determine $e best way to forecast remaining recoverable gas reserves fromthe Devonian shales of the Appalachian basin. This study indicates that ratehime decliie-curve analysis isthemost reliable technique and presents typical decline curves baaed on production data gathered from 508 shale . .wells in a three-state study area. The reardtant type curves illustrate a dual- (or multiple-) porosity mechanismthat violates standard dec~me-curve analysis gniddirres. The resnfts, however, are typical not only for theDevonian shales but for all naturally fractured, multilayered, or similar :hale reservoirs.i n t r oduc t i onThe first Devonian shale gas well wascompleted in NewYork in 1821andprovided gas for the lamps in the gover-nors mansion. Since then, many wells have tapped theshales reserves, but deapiti its heavy promotion in thelate 1970s and early 1980s, the Devonian shale is stilfa mysterious and complex reservoir. The U.S. DOE hasconducted mazry extensive engineering wd geologicstndies, 1-9but many shale operators have not yet capital-iced on the results: The overall success ratio for the Devo-nian shale, Iiowever, has been better than 90,%.6,10Themost reliable method for quantifying the recoverablereserves and forecasting production rates remains undeter-mined. A review of the accepted evaluation methods mustbecritically anrdyzed to see which, if imy, should be usedin a natnrally fractnred shale reservoir.The Reser vo irGas-bearing Devorr&r shales cover an area of about275,000 sq miles [712 000 kmz] in the Appalachian,Mlchlgan, and Illinois baains. This paper addresses theAppalachian baain, where more than 9,603 welk producefrom the shales, particularly in the strrdy area outliicdin Fig. 1. This study area represents a region of iimilargeologic, geoghenjcal, and reseryoti engineering char-acter compared to the west-tc-east or north-to-aoutb trendsof the much larger Appala&ifi basin.The tirst concept to understand is that there is no onehorizon knbwn as the Devonian shale, but rather a ser-ies of strata above the Onondaga limestone ~lg Lne)and below the Berea sandstone of Lower Mksissip@nAge. These strata arealmost pure shale in western Ohiobut grade or diverge into siltstonea in central and soutb-eastem West Vkgkiia ,


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OHIO PENNSYLVANIA

MARYLAND

VIRGINIAKENTUCKY

Fig. lArea of study.

with these shales dktrrrbs cafcufation of water saturationand even porosity. M These factOrs prohibit quantitativeevifuation of hydrocarbons irr pbice from.wirefine logs.Qualkative measures, however, are proliferating. Forthese purposes, fractures are sought through porosity andmicrodevice logs. Temperature logs are used to detect acooling effect associated with zones of gas entry. Thkis simifsr to noting the amplitude deflection in noiseor sibilation logs. Gas entry irito the empty borebole(almost invariably, shale wells,are entirely sir drilled) notorrfy reduces the temperature in the irnmed~te vicinitybut whistles as well. Unfortumtely, temperature andnoise logs suffer from an inability to isolate theseresponses to tlrh zones or sometimes to specific irrtervafsbecause of a rirasking effect.For a quick look, a concurrent incrsase irr gammaradiation and resistivirj may indicate the presence of or-gsnic niatkr either as solid hydrocartcm @erOg?n)Org=.In gas-bearing shales, however, there is no quick-lookporosity crossover of neutron and density porosities aswith conventional gas reservoirs.Several other methods are availablecurve overlays,various log combination correlations, snd empiricalprestidigitation-but even the wireline,companies admitthat current log srrslysis techniques add little to mfcuki-tions of the vohune of reserves. Evenwith newly advancedlogs, withmsximm,porosities of 5% (mostly fractures),quantitative a.w+wrnentis uncertain. 15fher?fore, a vOhr-metrie determination of gas resem-es is highly specula-tive and is not yet starxfmd engineering prsctice for theDevonian shales.Pressure/Currmlative Production. TheDevonian shafewells typicalfy undergo rapid pressure loss caly in theirlife bccarrse of their release mechanism. Pressures tfrere-aftsr stabdize, wlr@hleads to a nearly horizontal ordinateaxis of pressure (or pressure, p, d!vided by gas deviationfactor, z) as the abscissa values of cumulative recoveryincrease. Pressure/cumulative-production plots provideextrapolation of the result@ firremcorrelation to a givenabandonment pressure to estimate the ultimate recovera-ble reserves. If this linear correlation approaches thehorizontal early irrtheproductive life, such an extrapola-tion is either questionable or umeasonable. Actual vafuesof pressure may also be in error because arrrruaftests are

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600 -.G SQRPI ION STARTS.: acea

...2W- \\\ \ ,M,,M,WEGAS\ IN PMCEo 50 10U !50 20U 2s0 :

cUMULATIVE PRODUCTION, MMSCFFig. Z-p/z vs. cumulative production for multiporosity gareservoir.

conducted for ordy 48 hours instead of the much longertime rrecesssry to estabfish stabtied conditions in a natur-ally fractured reservoir. 12Kucuk et al. 8 illustrate typical pressure (p/z) vs.cumulative-production plots for a dud-porosity gas reser-voir. An exsnrple is given in Fig. 2, which clearly ex-hibits the inhiaf drawdown and subsequent leveling offof reservoir pressure. A straight-line extrapolation dur-ing the prwtabflization period wiffyield mrfythe volumenf free gas irrthe reservoir. At somepressure, gas beginsto come from the adsorbed Wd later from the absorbedphase. The release from these two phases.is the basis fora sorption model thst predicts this leveling phenomenonbut is not ready to be used generslly. The sorption modelindicates much higher production rates irrlater years andIargsr curmrfativeproduction estimates than woufdbe sug-gested tbrmrgh vobmnetrics. Aft-boughsuperior to volu-metric, the sorption model pressuretcumulative-production plot is still being tested.Weff Test Armfysis. Offgassing or outgassing tests havebeen conducted frequently to approximate the volume ofgas per acre-foot of reservoir. 7$ Arr encapsulated shalesample is taken and the volrrrneof gas fiberated from t@esample,is measured and converted to cubic feet per acre-foot. Unforhuratefy, this volume is usualfy representativeof ordy the free gss; if conditions were avaifable to releasethe sorbed gas as welf, a fairly accurate estimate of gasirr place coufd be resolved.Recently, pressure buifdup snd drawdown tests havebeen run to evahrate the shales, and one study concludesthat there is a flow regime pecufiar to fractured reser-voirs. 5;16This regime occurs during &rly to irrtermedi-ate transient flow and is evident on a serrrilog plot ofdimensionless pressure drop vs. dirnensiordes$time wberrtwo straight fines are observed, with the slope of the sec-ond equal to one-half the slope of the frst. The fractureflow capacity and skin factor can be deterrnin~ from datafor this flow regime and either matrix porosity or matrixperrneabiim mlcufated, provided the otlrer is krrown. Theratio of matrix to fracture storage capacities can be esti-mated from the intermediate and late-time data. Theseprocedures folfow the same genersl methodology as con-ventional history matching.

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Other investigators 17,18establish an algorithm for theprediction of gas flow rates based on knowledge of frac-ture half-lengths aud fracture widths. This method is con-tingent on single-phase flow with a constant effectiveformation pcrmcabfity to the prodrrcing phase. Whh such,. data as those obtained from the tests referred to previ-ously, future flow rates may be predicted aud an artifi-cial dec~mecurve prepared. These strrdiesfocused on tightgas sari@ and not tie Devonian shafes, however; hem%no sensitivity analysis was ducctcd toward the shales. Thesimulation of tight gas sands probably will not mimic thebehavior of a more complicated fractured shale interbed-ded with siltstones. As the shalesare produced, there isa certain amount of fracture closure that contributes totie rate at which abandonment is approached. Consequent-ly, fracture parameters wifl change continually. Well testanalysis, therefore, needs to be updated periodlcalfy toreflect the chaage.AnaIogy to Offset WeUs. This method is very rrnrelia-ble. Because shale production is tied to the existence ofa natural fracture system and not conventional geology,one well.rnaycome on at 106 ft3/D [28 30Qin3/d], whileits neighbor may yield notig. This variation dependsprimarily on the fracture orientation, but even with frac-ture mappirrg, the fracture system in a new wefI may becompletely different from that of an offset, If it is not,complication stilf exists because of the migratory natureof gas witMna fractured reservoir and the activity of drill-ing. (Drilling may serve to open existing fractures thatintersect the wellbore, or: it may plug them up withsloughed shale or patiicrrlate matter.) Fracture mappingassists in illuminating the degree of fracture intersectionand therefore provides a qualkative feel for a welfsproductivity compared with others nearby.This is not to say that infdl drifling is unwarranted. II-terference tests 1 suggest that Devonian shale well-drainage areas are elliptical arrd that considerable gasrcservesremain untapped. Additionally, vertical cormmr-nication between highly productive aud poorly produc-tive shales. within a wellbore may be very Iiiited,suggesting that the considerable productive Wlckness ofthe shales is best drained by infdl dr~ng. To attributea given magnitude of gas reserves to a new welf on thebasis of the reserve histmy of offsets, however, is a veryqrrestiomble approach.Material Balance. This method can usually be dismissedalso. Devonian shale gas wells may have associated oil,condensate; or water production, which may be ineffi-ciently recorded. The extent of recharging poorer shalemembers by strong members is notweU,understood;hencethe gas balauce is awry. Also, with the passing of time,it has been observed that conrmrrnication may exist be-tween the shales and adjacent formations, such as liie-stone aquifers (or ga.&bearingsands). This then eliinatesa closed-system approach. The extent of the fracture SYS-tern withii the PV afso confuses the issue of just whatconstitu@sthe gas storage capacity. Because the data usedin the material-balance equation are not entirely reliable,the resufts of the material balance will be erroneous.Rate-vs.-Cmrrufative-Production Amfysis. Plotting thegas prediction rate, usually measured in thousands of cu-

bic feet per day, on the ordinate vs. cumulative recoveryon the a&ciss~&sentialfy expresses independerrccof prw:sure data and stresses productivity. Care must be exer-cised to account for production rate fluctuation caused byany well downtime or restriction. An economic liit mustbe determined so that, like pressure vs. cumrdative pro-duction, extm@tion to the abandonment condition yieldstie recoverable reserves. Typically, tie abandonment rateis set by the purchasing utilities; recentfy, that rate hasbeen 6.5 Mcf/D [184 m3/d].Afters period of time, the better-prodrrciqg wells Iravehigher cumulative production levels than moderatelyproducing wells. This has no Liearingon which is a poor-er well, however, without some knowkdge of the pro-duction rate fd,qoty.19The utility of rate vs. Cumuktiveproduction then becomes apparent. The data used irr sucha plot come from data used for decliie-curve anafysis,so thk method is generally exercised as a support. tndecline curves. Of the engineering methods reviewed thusftu?this method has the fewest drawbacks rmdis the mostrehable for predktive measures. The main drawback isthat many shale wells rn+yproduce at approxirimMy thesame rate for years, thereby causing diftkulty in ex-trapol+ing to aR ending rate.Reservoir Sirmrfation. This is the most advanced tech-nique of production analysis and, as with conventionalreservoirs, involves the approximation of the reservoirby a series of blocked grids, each block with its own setof rock ahd fluid properties. Reisso states that fr+oredreservoirs are inadequately simrdatcd, however, becauseof the. formation tieterogeneityldkcontinuity, complexfluid-release propyties, less reliable and highly trarrsito-ry input data, and oversimplified reservoir descriptiveequations. Although these statements sum up the prob-lems facing the simulator rarher well, localized nmdel-ing of the shafts predictive cbaractcristics was performedby the DOE witi their Sinnrfator for Unconventional GasReservoirs (SUGAR)model. 1 SUGAR was documentedmainly in its capacity for interference well teat data anal-ysis but has a varie~ of applications. 2 SUGAS uses a dual-porosity system and atlempts to account for the v~iousflow regimes existent in the shales.Asmrdyz used SUGAR to evahrate several stimulationtechniques and their effect on production. This necessi-tated history-hratchlng acturd production from wells inthree Ohio counties and consequently determirrkg a rangefor reservoti parameters, such as fracture permeability,shale thickness, and gas content. SUGARwas successftd,but, with any simulation, there is a multiplicative effectof tie r~ervoir parameters to the overall recoveryscenario. Their actual v~ues may vary considerably with-in (mrd perhaps outside) the rangca established in theirstady. Its purpose, however, was notto perform anin-deptlr field stndy of the Appalachian Devonian shafes butrather to dkplay the use of the model in analyzing stimu-lation techniques.Despite the promising rcsuks, the computer simulationtechnique is not avaifable to all operators. Moreover, theexpense of such simulation may not have merit to smal.le~operators even if it is available.Decline-Curve Analysis. Decline-curve analysis is use-tld when a well or lease has produced for a sufficient peri-

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od of time to have established a defirriteproductiondecfinetrend, unless production may be affected by other fac-tors, e.g., accelerating water influx or increasing GOR.For wells not so affected but with lirrited production his-tory, declirre-cutie analysis essentially maybe au anrdo- ~gy to offset wells through the use of type curves.Assumptions irrbereirt in the use of type curves includehnmogenei~ of reservnir character, simifar drive mech-mrisms, comparable-quality reservoir fluids, identicaldrainage extent, approximate reservoir andlor line pres-sures, and the stie completionkeatment scerrmios.Dktnrbing factors irrthe shales tlrat complicate the rateof production include the &Tectof gas storage, preferen-tial fracture closure, arrdgas mohifitywithin the fractures.Nevertheless, of all the methods covered here, the bestindicator of producibtity is the deeline curve. This methodcontinually adjusts for, and is reflective of, thecharrgingreservoir condhions over the life of a well. Conditionalto i$ use is capaci~ production, preferably with the ini-tial rates not influenced by misleading flush production.Flush productiori is indicative of the free-gas PV mrdnotof the producible-gas PV and iq inherent release mecha-riisrmWhen flush production finishes, both free-state gasand gas adsorbed in the fractrries have been drnined, andthe larger bodies of shnle between the fractures begirrtoyield their gas. 6,7 At MS pOint, gas tmar22issi0n tOthefractires nnd then to the wellbore proceeds at a very slowpace, resulting in a flattering of the de@inecurve towarda nearly horizontal line. This represents the pressure-stabiliition phase, durirrgWrichtle reaervoii surrendersgas at lnw volume for a lengthy period of drrre, and which.is characterized by exponential production dec~me.To the best of my knowledge, ordy a few studiea2,3>21have looked at any meazringlidnumber of producing shalewells to establish a typical decline curve. Results fromthese studies have been too general or too srntistically in-significant. Moderation of results conId be obwrred bylooking at a sizable quantity of producing wells histo-ries and then assembling Ozemirrtn groups, such as bycourrty, stnte, or completion type, This avoids overgener-aliiation rmd would, we hope, avoid placing great em-phasison only a few weffs.one of tie ~mdieszl arrived at m equation that rePfe-seritedmore than 2,700 wells in 36 counties in Kentu&y,Ohio, West Virginia, and New York. This equation cal-culates the daily production rate as a function of both timeazrd,acorrstmrtpertinent to each county. The constant, irrturn, is a fraction of the average total black shrdethick-ness of the county and also varies between counties ac-cordirrgto totrd shale rfrickrress,depth, and treatment type.Unfortunately, the constants used in the Ref. 21 studywere not available for comparison with the results of thisstudy.Study Ra t i ona l eThe study area selected (Fig. 1) was chosen for severnlreasons: (1). to restrict the geologic heterogeneity topredominantly shnlemembers interbedded with siltatorres;(2) to minimize the range of formation depth variation;(3) to focus on wells locateg west of the Burning Springsanticline and the Rome trough to compare welfs of s@ri-lar fracture orierrtation/development and favorable shalestress ratios; (4) to reduce the area.to one of comparable212

geochemical composition, particnkuly cnrbmrcontent andthermal rrrmrity; (5) to concentrate on sreas deemedmostfavorable by oflrerirzvestigators6,7for Devonian shale ex-ploratimr; mrd (6) to assess the wenlth of production in-formation available for this general area, where the mostprolific Devonk+rrshale gaa fields are located. With thesefimhations in mind, a study area was chosen thntinvolves20 counties along the co~pn borders of.Ohio, West Vii-ginia, and Kenhrcky.Production data were issemblcd through the Gas Re-search Inst. Eastern Gas Data System @GDS) with thehelp of BDM Corp. and through a datn-gathering trip toseveral operators in West Viigirria and Ohio. Throughthese sources, 565 pmdrrction histories were obtained. Ofthese, 57 wells were found to be duplicated betweenEGDS and the Cohrrnhia Gas Transmission Corp. tiles.The resultant well sampling became 508 wells: 316 irrWest Virginia, 120 inKentucky, and 72 ~,Ohio. Alf wereconsidered to be producing either predixrmrantly or snle-ly from shale members nnd were individually meteredwells.Production data were then referred to a common starr-dard measurement, and the normalized dati were thenplotted vs. time with anzuralinte.rw.ls-freqrrently for 30to 40 yearsfor nll 508 wells.Additional screening criteria were then imposed. To beconsidered useful, the wells should produce in excess of5 years. The highest production Ievel shordd occur with-in the first 3 calendnr years to account for natural flushproduction. (Mmzywells nre dsmnged in driffing or byfracturing with a water medium and can take more than1 yenr to clean up under certain conditions; this carrtrarrs-late into a p~ia.f tlrst calendar year, fulf second yenr,and partial thiid year.) Additionrdly,,overall productionshordd not exhibit severe fluctuation, as irr a saw-toothpattern or a tempormy irrcrease in production rates. Noproduction Ievef should exceed the highest level from thefust 3 yesrs. Finally, any change in a wells productivity(such as a workoverlrecbmpletion) that was obviuus onthe decline curve would invalidate the entire hktory or,if occurring very late irr life, the later history.With these scre@rrg criteria appIied, the 508 welfswerepared down to 162wells-98 in WestViiginia, 54 in Ken-tucky, and 10 in Ohio. The 162 wells were then dNiifedaccording to cOmpletiOrr/stimulationypq a dispropOrdOn-ate 132 wells were shot, 11were fractured, and 19 werenatural completions. No perforated wells were in the ti-rrrd analysis. Subdivision to treatment type by county.ensued.For each countyltreatmerrt-type combination: thehiszhestDIOdUCtiOn level within the fust 3 vears is desi~-na~edasoccuminginthe tirst study yea. B~cause no su6-seqrre,ntproduction level should exceed Oy.t for the firstY=, the first study year is defied astfre.best yesr. Sub-sequent production levels are then related to the best yenras a percentage. fir this way, production is harrdfed ona relative basis and is not tied to so many thousand cubicfeet per time unit, This procedure was used intfre prratfor the Clinton srnrdsofOhio and the Big Irrjun sands ofWest Virginia. 22 The prod~ction history of each we~within the courrV/tikatrnent-type cumbiwkiorr is then an-nlyzedand percentage tabtdations constructed. Each wellstabulation is then assimMed into a general qzrve for thetourrty/trentrrzent-type combination, then, into general

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Fig. 3General decline curve for atudv area.

curves for the statdtreatment-type combinations and thestudy area/treatruent type. Fmtier generalization ensueswith overall treatment-type curves, overall state cumes,and an overall study-area curve.Study Resul t sTheoveml type curves were then subjected to the tradi-tional decline-curve analysis techniques.23,24The first ob-ser.kition was that for,the 162 wellssmdied, the averageinitial yearly decline rate was 317.. Note, however, thatthe first study yew isnot neceswily the fi,mtyear of pro-duction for many of.the.sewells. In that first year, the pro-duction decline may equal or exceed the 60% rule ofthumb used by many operators. Conversely, some wellsexperience a production rate incliie, as in the case of awellbnre cleanup, for example. Given these extremes, amoderate rate of decline should adequately approximatethe production behavior.Second, without exception, all the overall type curveswere hyperbolic decline cases with the b factor greaterthan 1.0. This viofatcs conventional decline-curve thccuy,but some investiga@rs11-13have shown that V8hIeS great-er thm 1.0 are indicative of mukipay reservoirs, mul-tiporosity systems, and tight gas reservoim. Exponentialdecline, where b=O, commands latdife performance, butthe invcatigators agree that it gives amunacceptable tit inthe early years.Fig, 3 is the overall curve for the study area. As withthe ensrdng figures, the abscissa represents Orenumberof years the wells have been on liie. The left ordinateqis has a 10&naximum sernilog scale that rcpmscnts thepercentage of the beaty&r each subscqrrentyea prcduces.(BYdefinition, the tirst study year is 100%.) On the rightordkrate axis, a coordinate stile indicates the number ofwells analyzed for each year.as a measure of the r@abd-ity for the percent-o f-best-yess curves.There ac actually two pIots for the percent-of-best-yearscale. The first, denoted by hollow dots, is the plot ofSPE ReservoirEngineering,vtay1987

actual percentages by year. The second plot,, shown bycrosses, illustrates the match.obtained by a computer prn-grarn to cafcufate the hyperbolic b exponent on the basisof actual percentages entered and to forecast future per-centages. For Figs. 3 through 5, the b exponent and ini-tial yearly decliie rate are liited on the figure. For theoverall study area, the b exponent is .2.367.Fig. 4 is the ovemll curve fo~ the study wells complet- ~ed by shooting. Similar curves for the fracture and naturalcompletions are published in Ref. 13. A comparison ofthe three completion techniques, especially by overlay-ing the curves, indkates a superiority of the shot treat-ment irrmaintaining production levels. Perhaps the samplesize favors the shot treatment, bnt the edge over fractur-ing is very slight. Naturul completion falls away from theother two within 6 years. StudIes21 state that DevoniWshale wells with initial open flows in excess of 300 Mcf/D[8500 m3/d]are not appreciably improved by fracturingcompared with conventional explosives. Wefls with ini-tiaI open flows below 10.0Mcf/D [2830 m3/d]are ex-pectcd to have a 57% flow-rate improvement by fracturinginstead of using conventional shooting. Because of the na-ture of the reservoir, however, shootiirg and fracturingoften accomplish the same thhrg-i. e., contacting gas-bearing fractures. The main difference is the abflity toprop or to keep the fractures open and flowing gas.Fig. 5.is the general dec~me curve for the study areain West Viiginia. Similar curves for the study areas inOhio and Kerihrcky ae avuilable in Ref. 13. An overlayof the three curves indicates that they are almost identi-cal. In fact, for the first 19years there is less than 10per-centage units difference between all three states. Thksuggest.vthe uniformity of the decline scenario.Because tie hyperbolic aualysis revealed here con-tradicted standard decline-cu~e theory, it was felt thata comparison shouldbe made. To evaluate a set of curves,twb factors must be held constant: the initial productionrate and the initial decliie rate. Vahmxused for compari-

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I

Fig. 4Study area general curve for shot completion. .,.

Fig. 5West Virginia study area general curve.

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>

,23 .687.. !.! 112,,,+,,,,,,,, ,,,o?!,, ,>z. m,.,,. ,.!. ,0.!,, ,. IA,,24 ,, s...YEARSONLINE

Fig. 6-Hyperbolic exponent selection sensitivity.

son were 100 dimensionless irnitsand31 % dccfine, withthe latter representing the initiaI decline rate for the studyarea. Variable b exponents were then applied, includingthe overall study-arcs base case of 2.367, as well as ex-ponents.of 1.0 (lrsrinonic), 0.5 (hyperbolic), and 0.0 (ex-ponential).A comp&on of the four cmes is illustrated in Fig. 6.Over the 40-yesr period, the projected recovery witisnexponent of1.0 waa 57% of the reserves to be recoveredin mrdtiporosity models. Likewise, a b value of 0.5 re-covers only 38% of the mtdtiporosity model reserves, andan exponent of 0.0 yields only 23%.Simlar conclusions about the b value comparisons wereretiched for tight gas aanda under the auspicea of the DOEWestern Gas Sarrds Project. 11Note that this study placed no empha.ik on Devonian

shale M well irritiaI open flows. S6versJ rescarch-lgers 3,4,2.19ZZhave expounded on the pitfalls of predict-ing future perfonnamie on the basis of initial flow tests,and their findings will not be repeated except to say thatthey concludethere is no direct relationship. Productiondecline does not necessarily depend on initiafest resultsbut rather the continual modification of the release mech-anisms of the reservoir itkelf. The observation of produc-tion decliie is analogous to monitoring the changes in thercaervoirs gas trammissibtity, but production rates tfrem-selvis are misleading. The analysis of relative produc-tion vs. time as done. here eliminates production rateranges that tend to confuse the issue.Conclus ions1. The evaluation of Devonian shale gas wells is mostreliable when a continually updated reservoir description

can be obtained. Production-rate/time decline-curve smd-ysis produces the description most easily formulated andmost readily graaped.2. Production-decline cnrves for the shale wells typi-cally exhibit a rapid drop in production rate followed bya remarkable period of production stab~iation becauseof the mukiporosity, multilayer reservoir.3:, The decline curves always follow a hyperbolic pst-tem and, from this study, display b exponent values great-

er than 1.0, contmry to traditional decline-curve theory.Tbia departure is the result of the mrdtipomsity, mrddlayersystem.4. Type curves presented here depict a representativesampling of variously completed wells in three states andan overall curve for the study aica. These curves indi-cate a shallower initial dcclirre rate than that. used as arole of thumb by several operators and some previousstpdies.5. Late-life decline rates are ve~ shallow, witi the pro-duction rate forming an almost horizontal line on theratcltinre curves.6. Explosive treabnents (shooting) minimize the lossof production level, but fracturing rnns a close second.This may, however, be a result of the sample sizes.Namr-al completions are increasingly Werior from the sixth yearonward.7. DeSpite the size of the study area, there. was littledeparture in the overall ratehinre curves. Overalf cnrvesfor the atudv area in Ohio. Kentuckv, and West Virginiaare essentitiy the same. Thk sugg&ts the uniformi-~ ofthe production-decline behavior.

.AcknowledgmentsI thank the 0ss Research lnat., particularly Rich McBan%BDM Corp., particukdy Joan Msy; Columbia Osa Tran&mission Corp., particularly Paul Hyde; the mssry opera-tors irrOhio and West Virginia with whomI met or spoke;the engineering assistance of Pamela A. Boring themanagement ofKep!inger andAssccs. ~c., and espcia!.lyCarrel Bauchat and Becky Sheram for assembling andpreparing tie data used in this study.References1,Frohne, K.H. and Mercer, J.C.: ,Fractured Shak Gas ReservoirPerformance Study-An OffsetW.U Interference Field Test, JPT(Feb. 19S4) 291-300.2, Analysis of DevonianShaleGasFIcducdm Mechankm?., kand .Assocs. fnc., Reprl No. DOE/MC/19239-1250 (DES3002855), U.S. DOE Technkal Information Center (NOV.22,19S2).

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3. Nuckols, E.B,: The Couageville(MountAlto)Gas Field,JacksonConnty, W. V..: A Case Study of Devonian Shale Gas Produc-tie,, 3Report No. LA-8918-MS, Los Akmms NatL Laboratory(Aug. 1981).4. Pulle, C.v. and Sesku$ A.P.: TJuanthative AnalysisOffh. ECO-nomicdly RecoverableResource,ReportNo.DOE/MC/08216-157,US. DOE Morgantow. Energy Technology Center (May19s1).5. Sem., K. et .1.: WellTestAnalysisorDevonianShaleWellsFinalRepro,>,RepmlNo.DOE/MC/4645-lS5(DES2013933),US. DOE Technical information Center (Sept. 30, 1981).6. Struble, R.A.: Evaluation of the Devonian ShaleProspectsin theEastern United States, Repofi No. DOEiMC/ 19143-1305(DES3CGS749),US. DOE Tecti~cal Information Center (1982).7. Evaluation of the Devonian Shale Potential in West Virginia, Tefra Tech Inc. Report No. DOFJMETC-120, US. DOEMocgantown EnergyT&nology Center (19S1).8. Kmuk, F., Alan, J., and Stieib, D.L.: Res-ervoirEngineeringAspects and Resonrce Assessment Methodology of EasternDevonian Gas SbaIes, I@pOrl No. DOE/MC/0S216-13S0(DE83M8462), U.S. DOE Technical Infonnafion Center..9. Young, C., Barbour,T., andBkmton,T.L.: Simulation R+nrdefor Shale Gas WellsA Sfrde-of-the-ArI Report, 1, Report No.DOE/MC/08216-1336 (DES4003094), U.S. DOE TechnicalInformation Center (Dec. 19S0).10.. Norlheast Acdviv Nays Aheadin 1984, Nor?heasrOilRepon:r(May 1985) 27-58.11. Bailey,W.: Opdndzed HyperbolicDeclineCuwe Analysisof GasWells, ,> Oil & Gas J. (Feb. .1S, 1982) 116-18.12. McBae, R.A. and Thompson, T.W.: ExplorationlProductionSmdies of the DevonianGas Shales, paper SPE 12833presentedat the 1984 SPE/DOE/GRI Unconventional Gas RecovewSymposium, Pittsh.rgh, May 13-15.13. Vanorsdde, C.R.: 4Evaluationof DevonianShaleGas Reservoirs,paper.SPE 14446 presented at the 1985 SPE AIImal TechnicalCmerence and E%bibition,Las Vegas, Sept. 22-25.14. Hilton, J.: Wireline Evaluation of the Devonian Shales: A Prog-ress Rec.ort,,, Proc., first Fa.sternGas Shales Symposium (1978)68-79,:15. Maslowski, A.: Nor@?asl Formations Examined, NorfheastOilReporter (May 19S4) 69-75.

16. Thompson, J.K.: Use ofConstant Pressure, FiniteCapacify1ypeCIUW.Sor Performance Prediction of Fracmred Wells in Low.Permeability Reservoirs, paper SPE 9839 presented at tie 1981SPEIDOE I.-m+Penneabili@Gas Reservoirs Symposium,Denver,May 27-29.17.Agar.wJ,R.G., Carter, R.D., andPollock, C.B.: Evaluation andPerformancePrtiction of LOw-PemneabilityGasWells Sdmulatedby Massive Hydraulic Fracturing, JPT (March 1979) 362-72;TrmIs., A2ME, 267.18. Aganval, R.G., Carter, R.D., and Pollock, C,B.: cJPT (Nov. 1963) 1183-8S.23. Arps, J.J.: Stinalysis of Decline Curies,xv Trans., A2ME(1945)160,,228-47.24., Beedict, J.: The Mathematics of Decline Cnrw.s, paper SPE10537 available at SPE, Richardson, TX.25, pUIIt, c.v.: ;A HydrodymmnicAmlogy of production DeclineforDevonianShaleWells, paper SPE 10S37presenfedat tbe 19g2SPE Unconventional Gas Recovery Symposium, Pittsburgh, MayIG19.

S[ Met r ic Conv er si on Fa c t or sf t 3 x 2.S31 685 E02 = m3psi x 6.894757 E+OO = kPa

SPEREOngi.~ rmn.wipl I Bcel .ed i n :h e Soci et y of Pelr ol eum Engineem, o ~ce SW!, 22,19s. Pa,wracwted for pubtcation Feb 7, 1986. ne.is.d ma.wr,Pt ,=e,=d M.Y23,1 s86, Paper (SPE 14446) first pres.ntti at W x985 SPE AnmJal Techn!cd C..-ferece and ExMMIIo held In Las Vegas, Sept. 22-25.

216 SPE Reservoir Engineering, May 1987

spe14446_shale gas reservoir

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