Fracture Design Considerations in Naturally Fractured Reservoirs

Therefore, accepted fracture design considerations to determine optimal fracture length and conductivity can be used in isotro-pic, naturally fractured reservoirs based on References an

SPE 17607

Fracture Design Considerations in Naturally Fractured Reservoirs

by C.L, Ctpolla, P.T, Branagan, and S,J Lee, CER Corp.

SPE Members

Copyright 1908 Society of Petroleum Engineers

This paper waa prepared for presentation at the SPE International Meeting on Palroleum Engineering, held In Tianjin, China, November 14, 1988.

This paper wee selected for presentation by an SPE ProQram Commlttae following review of information contained in an abstract submitted by the

author(s) Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Englneere and are subject to correction by the

author(s) The material, as presented, doe$ not necessarily refiect any position of the Society of Petroleum Engineers, Ite officere, or members Papers

presented at SPE meetings are eubjsct to publication review by Editorial Commltteee of the Society of Petroleum Englneere Permission to co~j:2

restricted IO an abstract of not more than 300 words, 1’ustratlone may not be copied The abstract should contain conspicuous acknowledgment of

where and by whom the paper Is presented Write Publications Manager, SPE, P.O Box 833838, Richardson, TX 76083.3336, Telex, 730989 SPEDAL.

ABSTRACT

The ability to effectively enhance production

through hydraulic fracturing is dependent on

may differ greatilydepending on the production

mechanism(s) The complex nature

ofhydraulic-ally fractured reservoirsin

whichthepredomi-nant production mechanism is a set of

inter-connected, naturally occurring fractures is

investigated in this paper The paper

inte-grates general reservoir simulation results

with actual field data from a naturally

frac-tured reservoir in the Piceance Basin,

Color-ado.

The study investigates a variety of natural

fracture/ntatrixproperties and compares the

also investigates the influence of natural

design The effect of damage to the natural

fracture system is illustrated and compared

economic considerations associated with many

of the reservoir production mechanisms are

presented.

indicate that optimum fracture lengths for

are identical to those estimated for

homogen-eous reservoirs having the same average flow

capacity Therefore, accepted fracture design

considerations to determine optimal fracture

length and conductivity can be used in

isotro-pic, naturally fractured reservoirs based on

References and illustrations at end of ~aper

the average flow capacity of the reservoir However, fracture design considerations are

fracturedamage andanisotropy areencountered.

INTRODUCTION Thebasic fracture design criteria forhomogen-eous reservoirs has been discussed in detail

by several authors.1-7 This literature also illustrates the interrelationshipof fracture length, fractureconductivityandwell product-ivity, and the economic impactof many fracture

designconsiderations inmorecomplex

,natural-ly fractured reservoirs-are not wide,natural-ly.avail- widely.avail-able in the literature This paper presents

illustrate many fracturedes ignconsideratims

in naturally fractured reservoirs.

The initial requirement for designing a hy-draulic fracturing treatment is an accurate description of the reservoir, including the predominantproductionmechanism(s) Reservoir

can be obtained from log, core, geological, well test and production data In many cases,

a limited amount of data are available, and

mechanisms are inferred from pre- and

uncertainties associated with inferringreser-voir properties based on a limited amount of data because reservoirs with vastly different production mechanisms canproducevery similar pressure /production profiles The reservoir

similarities inproduotion andpressure buildup behavior for homogeneous and naturally frac-tured reservoirs that have the same average flow capacity.

.M

FRACTURE DESIGN CONSIDERATIONS

M many cases, well test results canbe

inte-grated with core, log and geological data to

identify and quantify reservoir properties

and production mechanisms However, in many

pressures and the effects of wellbore

stor-age/afterflow reduce the accuracy and detail

that can be obtained from well test analysis.

Well test analysis methods have been presented

to identify many reservoir production

derivative analysis methods-o-% have aided

in identifying complex production mechanisms

plotting techniques can assist in identifying

linear, bilinaar, radial and natural fracture

and/or more than one predominant production

mechanism may preclude the effective use of

theabove analysis methods Complex reservoirs

may require additional data and

interpret well test and production data.

To optimize fracture length and conductivity,

the post-fracture production resulting from

each treatr ‘nt should be compared The

tran-sientproduction/pressure behavior

forhy&=ul-ically fracturedwells inahomo eneous system

?L has been presentedby Cinco etal 3andAgarwal

et a15 and can be ueed to estimate the

post-fracture production during transient flow.

The pseudo-steady state productivity of

McGuire and Sikora,l can predict well

perfor-mance during pseudo-steady state flow.

Reser-voir simulation techniques can also be used

in more complex reservoirs to redict

post-fracturewell performance,s,l~,l?which ~cl~e

effects ofcomplexnatural fracture production

mechanisms combined with a hydraulic fracture

solutions andmay require reservoir simulation

techniques to obtain quantitative predictions

of post-fracture well performance.16117

post-fracture well productivity associated

with the selection of stimulation materials:

● fracture conductivity, and

● reservoir damage.

Holditch18 and Pratslg have presented studies

productivity for homogeneous reservoirs at

the fracture faces These studies illustrated

not significantly affect well productivity.

However, Branagan et a116~20 have shown that

damage to natural fractures intersected by a

hydraulic fracture can significantly reduce

case of a naturally fractured reservoir, the

majority of fluid leakoff is into the natural

effects of damage are magnified due to the

large volume of fluid (and polymer) injected

into the natural fractures intersected by the hydraulic fracture The effects of natural fracture damage are illustrated later in the text.

The effects and magnitude of in situ fracture conductivity in homogeneous reservoirs have

general, the required insitu fracture

A Cr value of 10 or more is considered suffi-cient for most applications, providing that the fracture conductivity used in Equation 1’ ‘Mwhf’

ie representative of the actual

in s u fracture conductivity and that non-Darcy flow effects are minimal The required hydraulic fracture conductivity for naturally fractured reservoirs is investigated in this paper in terms of the required Cr value This paper integrates current design criteria for homogeneous reservoirs with a reeervoir

present fracture design criteria for naturally fractured reservoirs The results were ob-tained using a finite difference reservoir simulator that was specifically designed to model transient matrix and natural fracture flow in the presence of a hydraulic fracture.

PRESSURE BUIIJXJPBEHAVIOR OneWidely-used method forestimating reservoir permeability and the predominant production mechanism is pressure buildup testing The pressure buildup behavior of naturally frac-turedreservoirs haebeen resented inprevious

% works by Branagan et al 4 and otheks.10-12 The pressure buildup behavicr for a set of homogeneous and naturally fractured reservoirs wae conducted to compare the behavior of the two production mechanisms The simulations were performed usfnga cartesian and alyfractured gas reservoir model The

natural-ly fractured model is described and verified

16219.15 The simulated reservoirs were rela-tively tight gas formations, exhibiting an

contains the basic reservoir parameters used for the simulations.

buildup behavior of two naturally fractured reservoirs and a homogeneous reservoir, all having the same average flow capacity These simulated buildups do not include the effects

of wellbore storage The figure illustrates how the early time Horner behavior isaffocted

by the contrast in natural fracture and matrix conductivity Natural fractureCaseA exhibits

a significantly smaller slope in the early time (Horner time between 50 and 1,000) than

6SU

PE 17607 C.L CIPOLLA P.T BRANAGAN AND S.J LEE —- .—.— —

Case B which has a much smaller conductivity The simulations are intended to illustrate contrast between the natural fractures and the applicability of Equation 1, C , topredict

that natural fracture Cases A and B and the naturally fractured reservoir It should be homogeneous reservoir converge to the same noted that the value of kave used in Equation

permeabil-thatall three reservoirshave the same average ity of the naturally fractured reservoir as

or other appropriate estimations The simula-Figure 2’ is a log-log pressure/derivative tions are also intended to evaluate the long

sure and pressure derivative shapes fornatur- for these simulations are the same as listed

does not, dueto the small contrast in natural was simulated for 10 years using a constant

natural fracture production is evident from has been verified against accepted analytical

andtheseverifica-not totally domitiatedby natural fractures, tions have been presented in previous publica-well testing may not identify natural fracture tions.15#24

production.

Figure 3 is a Horner comparison identical to for isotropic naturally fractured andhomogen-Figure 1 except for the inclusion of wellbore eous reservoirs for Cr (Equation 1) values

masks the early time data that aids in identi- that well performance is identical for both

storage mask the characteristic derivative conductivity andaverage reservoirpermeability curve associated with naturally fractured fora naturally fractured reservoir (asdefined reservoirs Therefore, in many field appll,ca- by Cr) is the same as that for homogeneous tions, well testing may not provide sufficient reservoirs Therefore, accepted fracture data to identify natural fracture production design criteria to optimizehydraul ic fracture mechanisms The examples presented are in- length and conductivity for homogeneous

reser-tended toillustrate thedifficultly inidenti- voirs is applicable to isotropic naturally

solely on well test data and the usefulness

Previouswork2 4hasshownthat natural fracture fractured resemoirs relating to fluid loss anisotropyis not easily identifiednorquanti- and natural fracture damage that differ from

distinguishing

characteristicsbetweenisotrop-ic and anisotropcharacteristicsbetweenisotrop-ic naturally fractured

reser-presented assume that the process of creating the hydraulic fracture does not impair the

the post-fracture pressure buildup behavior fractures In many cases, the flow capavity

of naturally fractured reservoirs That work ofthe natural fractures can be significantly emphasized the similarity in pressure buildup impaired by stimulation fluids.16 Also, the

andanisotropic naturally fractured reservoirs design criteria to naturally fractured reser-containing hydraulic fractures The conclu- voirs assumes that treatment design and

on prior knowledge of the degree of reservoir fluid loss and natural fracture damage may

materials for naturally fractured resenoirs

compared to analogous homogeneous reservoirs POST-FRACTURE WELL PERFORMANCE

The prediction of post-fracture well perfor- ANISOTROPXC RESERVOIRS

mance of homogeneous reservoirs is well

docu-mented,l-5 ~=3 as are the criteria foroptimiz- Well Performance

ing fracture length and conductivity.1g120

The extension of these procedures to naturally In many naturally fractured reservoirs, the fractured reservoirs isevaluatedby comparinq fracture system is anisotropic.17 The degree the simulated post-fracture production for of anisotropy can often be as much as 100 homogeneous and naturally fractured reservoirs 1 and not be evident from well test data.B

section is limited to isotropic reservoirs can be directly related to the in situ stress

589

FRACTURE DESIGN CONSIDERATIONS

Field ofthe reservoir, with the

the minimum prinaiple stress.16 Therefore,

the hydraulic fracture will probably intersect

?igure 6 illustrates the minimum and maximum

?rinciple stresses, the orientation of natural

Eracture permeability and the most probable

orientation of a hydraulic fracture.

4 set of reservoir simulations were conducted

to illustrate the effect of natural fracture

rnnisotropy on pnst-fracturewell productivity

reservoir data were listed in Table 1, while

the details of each case are shown in Table

2 A natural fracture anisotropy of 10 to 1

rhe simulations predicted well performance

lengths intersecting both the minimum (most

probable case) and the maximum permeability

natural fracture set The hydraulic fracture

conductivity for all cases was held constant

at 250 md-ft, and fractures lengths of 400,

800, 1,200 and 1,600 ft were simulated The

same hydraulic fracture data set was used to

simulate post-fracture well performance for

a corresponding isotropic naturally fractured

reservoir for comparison.

Figure 7 compares the predicted 10-year well

performance for an 800-ft hydraulic fracture

that intersects theminimumand

maximumpermea-bility natural fractures (reference Figure

isotropic naturally fractured reservoir is

shown for comparison The figure illustrates

that significantly higher production rates

high permeability set of natural fractures.

stress field results inanunfavorable fracture

orientation (intersectin~the lowpem.aability

Sf3t of natural fractures”5) (reference Figure

6) Although not shown, the long term

produc-tion fcrtheunstimulated isotropic and

ar.iso-tropic cases is virtually identical.

Optimum Fracture Length and Economics

The cumulative production after 10 years as

compared in Figure 8 for isotropic and

aniso-tropic naturally fractured reservoirs The

figure illustrates againthatwell performance

is significantly affected by reservoir

same for both the isotropic and anisotropic

naturally fractured reservoirs Therefore,

two fracture orientations in the anisotropic

case, parallel to the minimum permeability

parallel to the maximum permeability natural

fractures(denoted Aniso Max) As discussed,

the more probable case is linisoMax, where

the hydraulic fracture intersects theminim.us

permeability natural fractures that are many

times oriented paralleltothe minimum horizon-tal stress (reference Figure 6).

Figure 8 illustrates the drastic effect that fracture orientation has on 10-yearcumulative

oriented in a favorable direction, parallel

to the minimum permeability natural fractures

(Aniso Min), then the cumulative production

may be almost twice that expected from the unfavorable orientation The isotropic case

emphasize the significance of natural fracture anisotropyon post-fracture well productivity Again, the fracture orientation is prcbably not in the favorable direction.16 Therefore, post-fracture well productivity inanisotropic naturally fractured reservoirs is likely to

be less than expected Without prior knowledge

of the anisotropy, post-fracture well product-ivity may erroneously be interpreted as an ineffective stimulation treatment.

To illustrate the effect of reservcir aniso-tropy on optimum fracture length, a simple economic comparison was conducted Table 3

comparison Figure 9 shows the present value prOfit (PVP) for each case The PVP is defined

as the discounted net gas revenue minus base investment and stimulation costs The figure illustrates that the optimum fractute length

is longer for the anisotropic naturally frac-tured reservoir with the hydraulic fra~ture

natUral fractures, Aniso Min (this case is not commonly found in actual practice 16/24), compared to the isotropic case The shorteet optimum fracture length is estimated fo~ the

with the hydraulic fracture oriented parallel

to the high permeability natural fractures There is considerable difference in the PVP dependingon the type of reservoir and fracture orientation, again emphasizing the importance

of identifying reservoir anisotropy.

NATURAL FRACTURE PERMEABILITY IMPAIRMENT Simulated production

The effects of permeability impairment to the natural fractures intersectedby

ahydraul-ic fracture can significantly reduce

duringa stimulationtreatment, the interjected natural fractures willbetheprimary mechanism for fluid loss into the reservoir

natural fractures will magnify the effects

of permeability impairment due to fracturing fluid residue and relative permeability/water blccking.16~20 Asetof reservoir simulations was conducted to illustrate the effects of natural fracture permeability impairment.

An isotropic naturally fractured reservoir from the previous section was selected, which contained an 800-ft hydraulic fracture The permeability of the natural fractures inter-sected by the hydraulic,fracture was reduced o

, - — — , — - —— — -—.— - -—- ——

;O 1 percent of the original value (reference As a further illustration of the effects of r8bleS 1 and 2 for original values) Again, wellbore damage on pressure buildup behavior,

?ost-fractureproduction was simulated for 10 the Horner and log-log plots of the above

#ith andwithout natural fracturepermeabil ity 14 with the well shut-in at the surface hzpairment The figure shows that significant- Reviewing the figures shows that the entire

ly less production ie realized if the inter- test is influenced by wellbore storage/after-Sected natural fractures are affected by the flow and can provide very little information Stimulationfluids Although reservoircharac- The log-log plot, Figure 14, exhibits a unit teristics and stimulation treatments vary slope for most of the buildup period There-areatly, field data has indicated that natural fore, in many tight reservoirs, a bottomhole l?racture permeability impairment of this shut-in combined with extended test duration nagnitudeis probablewhen water-based stimula- may be required to minimize wellbore stor-tion fluids are employed with no fluid loss age/afterflow and provide reliable data additives.16~20 The useof foamed stimulation

tluidscombined withsolidfluid loss additives

has been tested attheMWX, and initial results FIEIJ)DATA

me promising.26

[n many cases, naturally fractured reservoirs toprevious Ublications foradditional details

sre tested using conventional surface

shut-lns and relatively short test times AssUming results for a naturally fractured reservoir negligible permeability impairment of the at the MWX site ie presented in this section.

~rocedure may result in adequate test data publications.16J17 The reservoir was thor-iowever, in the case wherethenatural fracture oughly tested prior to stimulation to obtain system inthevicinity of t!lewellborehas been an accurate reservoir description for subse-lnfluenced by drilling and completion opera- quent hydraulic fracture design and post-Lions, conventional well test procedures and fracture well test analysis Following the

l?hepressure buildup behavior of an unstimu- attempt to quantify the stimulation resulte Lated,naturallyfracturedreservo ircontaining

6imulated The base reservoir data are listed log,

in Table 1, natural fracture Case A.

The outcrop studies These studies aided greatly permeability of the damaged zone is 1 percent in the identification of the natural fracture

of the original natural fracture permeability production mechanism, reservoir anisotropy, (l percent of l,980md= 19.8 red) Thepres- hydraulic fracture orientation and theorienta-sure buildup behavior of the corresponding tion of minimum and maximum natural fracture

conventional test durations Each well was excellent reservoir data to identify natural

MCFD For reference, the undamaged pressure

Figures 1 through 4.

The well test and production data gathered Figures 11 and 12 are the Horner and log-log in the Paludal interval at the MWX is summar-plots, respectively, of the simulated pressure ized in this section.

buildup behavior of the homogeneous

andnatur-The Paludal zone is a channel deposit approximately 700 ft wide ally fractured reservoirs using a bottomhole Figure 15 is aplotof thepre-fracture produc-shut-in (minimalwellbore storage) Reviewing

tion data from MWX-1 (production/test well) that the later time portion of the buildup

and the bottomhole pressures for MWX-1 and the two observation wells, MWX-2 and MWX-3 test may provide some reliable data However,

the calculated permeability from the Horner

plots, respectively, of the final preseure

reservoir and 0.0004 md for the homogeneous Figures 16 and 17 is the simulated pressures reservoir The actual average permeability using the above mentioned naturally fractured

the magnitude of error in estimating reservoir input data used to match the paludal pre-permeability from well test data of insuffi- fracture well test and production data The cient duration in wells with wellbore damage table shows that anatural fracture anisotropy This calculated permeability could result in of 10 to 1 was required to match the pressure

inaccurate evaluation of post-fracture well and the lack of pressure interference in the

FRACTURE DESIGN CONSXDERATXONS

Phe Paludal zone was then hydraulically

frac-kured using a water-base stimulation fluid.

F@ure18illustrates thepost-fracture

produc-tion and bottomhole pressures in MWX-1 The

figure shows that thepost-fracture production

rate is less than the pre-fracture production

rate (reference Figure 15 & A comprehensive

reservoir ZIodelingstudyl ?20 indicated that

created, but during the fracturing process,

the intersectednatural fracturesweredamaged.

AS a result, initial post-fracture production

was impaired.

well was recentered and tested again Figure

flow rates are enhanced compared to both the

initial post-fracture and pre-fracture rates.

buildup data is presented in Figure 20, along

with the reservoir simulation history match.

Table 5 lists the model input data for the

history match of the re-entry well test and

comparing the pressure and derivative curves

of the actual and the simulated data

pressure/productionbehavior for this Paludal

for the history match was 100 ft, much shorter

than the designed length of 400 ft.

Again, moredetaileddiscussions ofthePaludal

zone well test and stimulation history can

be found in previous papers.16~20 The results

do illustrate the effects of natural fracture

permeability impairment and isotropy on

noted that the hydraulic fracture orientation

was estimated to be parallel to the maximum

geology, well testing and the orientation of

situ stresses.

fracture design in naturally fractured

reser-voirsrequires extensivepre- fracture reservoir

data The reservoir simulation study focused

on the feasibility of applying accepted

hy-draulic fracture design criteria for

homogen-eous reservoirs to naturally fractured

reser-voirs The simulation study selected specific

cases for comparison and then simulated

homogeneous and naturally fractured reservoirs

with identical average/bulk rese~oir

permea-bilities.

The simulation study investigated the

pre-fracturepressure buildupbehavior ofnaturally

fractured reservoirs compared to analogous

homogeneous reservoirs This portion of the

study illustrates the concept of average/bulk

reservoir permeability for naturally fractured reservoirs and emphasizes the problems

abilitytodistinguish natural fractureproduc-tion is significantly affected bythedurafractureproduc-tion

of wellbore storage In cases where wellbore storage is extensive, natural fracture flow regimes may be completely absent, and only a

using well test data.

Post-fracture well productivity for naturally fractured wells is compared to that of

illustrate the applicability of current frac-ture design criteria inhomogeneous reservoirs for fracture design in naturally fractured reservoirs The importance ofnatural fra~ture anisotropy is investigated in detail by simu-latingthepost-fracture production for various fracture lengths andorientations The effects

fractures intersected by a hydraulic fracture

is illustrated.

The reservoir simulation results are supple-mented by field data from the DOE MultiWell

testing and reservoir modeling are provided

to illustrate the application of the fracture

impairment and anisotropy.

CONCIXYSIONS

1.

2.

3.

4.

5*

directlyto isotropic, naturally fractured reservoirs to predict post-fracture well performance and optimum fracture length and conductivity.

Well test data may not distinguish natural

wellbore storage In many field applica-tions, a bottomhole shut-in is required to

identify natural fracture flow regimes.

post-fracture well test data Assuming a constant hydraulic fracture conductivity, optimum fracture lengths may be shorter

reservoir compared toanisotropic naturally fractured reservoir with the same average flow capacity That assumes the hydraulic fracture isoriented paralleltothe maximum permeability natural fractures.

The post-fracture well productivity and present value profit for an anisotropic naturally fractured reservoir (with the

stated in Conclusion 3) will be less than

fractured reservoir.

Natural fracture permeability impairment

~ (

I well productivity and should be minimized

and quantified as much as possible.

IACIWOW’XXDG~S

This work was sponsored by the United States

information presented istheproduct of ajoint

●ffort, and the authors wish to thank the

CER/MWX field crew, Sandfa National

and computer etaff.

INOMENCLATURE

BSHI = bottomhole shut-in

C = compressibility, psi-l

Cr = dimensionless fracture conductivity

h = thickness of formation, ft = Pay

Xso = Isotropic Natural Fracture Reservoir

k = permeability, md

E= average reservoir permeability, md

Lf = hydraulic fracture half-length, ft

m = Horner slope

P = pressure, psi

Pi = initial reservoir pressure, psi

PI Group = derivative pressure group,

[(tp + Del t)/tpl[(dp2/dt)Del t]

Del p2 = (shut-in pressure)2 - (last flowing

pressure)2

PVP = Present Value Profit, $

Del P = P-P~f

testing, psi

q = flow rate, STB/D for oil, MCCFD fOr gas

re = external radius, ft

rw = wellbore radius, ft

S,G = epeoific gravity of gas

T.D = total depth, ft

Tid = Tubing Inner Diameter, in.

tp = production time before shut-in, hours

Tr = formation temperature, ‘F

Wm = distance between orthogonal sets cf

natural fractures, ft

width of fracture, in.

formation volume factor, RB/MCF viscosity, Cp

porosity, fraction

t = shut-in time, hrs

in situ stress, psi

!ANAGAN AND S.J LEE subscripts

g - gas

hf - hydraulic fracture

HO Homogeneous Reservoir

m = matrix

nf = natural fracture

NF = Naturally Fractured Reservoir min = minimum direction or value max = maximum direction or value ave = average or bulk value

s = skin

1.

2.

3.

4.

5*

6.

7.

8.

9.

10.

McGuire, W.J andV.J Sikora: I’TheEffect

of Vertical Fractures on Well Productiv-ity,”d Pet Tech (October 1960), 72-74.

Vertical Fractures on Reservoir Behavicr-Results on Oil and Gas FIow,!lSPE 593, presented at the 1963 SPE Rocky Mountain Joint Meeting, Denver, May 23-24, 1963 van Poollen, H.K., J.M Tinsley and C.D Saunders: ‘IHydraulic Fracturing-Fracture Flow Capacity vs Well Prcductivity,~~SPE 890-G, presented at the 32nd Annual Fall Meetingof SPE, Dallas, October 6-9, 1957 Tinsley, J.M., J.R Williams, R.L Tiner andW.T Malone: lWertical Fracture Height

Increase,!!J Pet Tech (May 1979), 633-638.

Agarwal, R.G., R.D Carter, and’C.B Pol-lock: $lEvaluationand perfo~ance predic-tion of Low-Permeability Gas Wells Stimu-lated by Massive Hydraulic Fracturing,”

J Pet Tech (March 1979), 362-372.

Propping Agents, 2ndEdition, Norton-Alcoa Proppants, Dallas, 1984.

Norman, M.E and C.R Fast.:Proppant

Dresser Industries, 1985.

Matthews, C.S and D.G Russell: Pressure Buildup and Flow Tests in wells, Society

of Petroleum Engineers of AIME, Dallas (1967),Volumel (HenryL Doherty Series) Earlougher, R.C Jr.: Advances in Well Test Analysis, Society of Petroleum Engi-neers of AIME, Dallas (1977), Volume 2 (Henry L Doherty Series).

Derivative Enhances Useof Type Curves for the Analysis of Well Tests,llSPE 14101, presented at the International Meeting

on Petroleum Engineering, Beijing, China, March 17-20, 1986.

— _ _—— —.—— - ——-— — ——

14-16, 1983.

Jr.: ItInfinite Conductivity Vertical 23 Penny, G.S.: ‘An Evaluation of the Effects Fracture in aReSerVOir With DOUble POrOS- of Environmental Conditionsand Fracturing

Exhibition of the Society of Petroleum

27-Dominquez-A.: ‘ITransient Pressure Behavior 30, 1987.

Hydraulic Fracture Treatmentein Naturally

15 Cipolla, C.L and S.J Lee: “The Effect 25 Warpinski, N.R and P.T Branagan:

10, 1987.

Reservoirs Symposium, Denver, Colorado,

Experi-ment: A Field Laboratory for Tight Gas

Fluvial Reservoir,llSPE 17724, presented

stress-Sensitive Fracture Systems in Flat-Lying

Fractured Gas Wells,II J, pet. Tech (Decem- Technology Symposium, Louisville,

19 prat-, M.: llEffectof vertical Fractures 29 Lorenz, J.c.: ‘Jsedimentologyof the

1982.

20 Branagan, P.T., C.L Cipolla, S.J Lee

21 Cooke, C.E Jr.: tlEffeCt of Fracturing 31 Warpinski, N.R., et al: “Fracturing and

- -Tnnrra m ml nnauacau aun Q-.7 TX%! 9

—

Tid = 2.441 in.

P . 0.0214 Cp @ pi

0.7862 ResBBUMCF @ Pi

800

0.05

10:1 anisotropy kni nin = 626 md knf ma% = 6,231 md N@urally Fractured Fksanroir

●All other input data same as in Table 1‘s Natural Fracture

Table 3 Base Economic Input Data

and Initial

1,000 hrs shut-in – BHSI & Surface Shut-In 400 392,000 Price Escalation = None

Soo 450,000 Operating Cost =“ 800 $/Mo

Working Int = 100%

Tabla 4 Pra-Fraclure Model Input Data for MWX Paludal History Match

Table 5 Ra-Entry Model hrput Data

Hydraulic Fracture Base Raservoir Data Matrix Properties Natural Fractura Properties Properties

S.G = 0.626

-.—

FRACTURE DESIGN CONSIDERATIONS

L