Fracture Design Considerations in Naturally Fractured Reservoirs

SPE
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
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presented at SPE meetings are eubjsct to publication review by Editorial Commltteee of the Society of Petroleum Englneere. Permission to co~j:2
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ABSTRACT
The ability to effectively enhance production
through hydraulic fracturing is dependent on
an accurate description of the reservoir
production mechanism(s). Fracture designs
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
productivity of these naturally fractured
reservoirs to homogeneous reservoirs with
the same average flow capacity. The paper
also investigates the influence of natural
fracture anisotropy on hydraulic fracture
design. The effect of damage to the natural
fracture system is illustrated and compared
to analogous homogeneous reservoirs.
The
economic considerations associated with many
of the reservoir production mechanisms are
presented.
The results of the reservoir simulations
indicate that optimum fracture lengths for
isotropic, naturally fractured reservoirs
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
more complex when the effects of natural
fracturedamage andanisotropy areencountered.
INTRODUCTION

Thebasic fracturedesign 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
design considerations. However, fracture
designconsiderations inmorecomplex ,natural-
ly fractured reservoirs-are not widely.avail-
able in the literature.
This paper presents
reservoir simulations and field data that
illustratemany fracturedesignconsideratims
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
production mechanisms and characteristics
can be obtained from log, core, geological,
well test and production data. In many cases,
a limited amount of data are available, and
reservoir
characteristics
and production
mechanisms are inferred from pre- and post-
fracture well performance.
There are many
uncertainties associatedwith inferringreser-
voir properties based on a limited amount of

data because reservoirs with vastly different
production mechanisms canproducevery similar
pressure /production profiles. The reservoir
simulations presented will illustrate the
similarities inproduotion andpressure buildup
behavior for homogeneous and naturally frac-
tured reservoirs that have the same average
flow capacity.
S87
.
.
.M
FRACTURE DESIGN CONSIDERATIONS
IN UAIWRAT.T.Y FRAC!ITWRF!D Wi!RIWVnTPC smn 17cn*
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
cases, the absence of preoise bottomhole
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 mecha-
nisms.81g The more recentq ti e curve and
derivative analysis methods-o
-%
have aided
in identifying complex production mechanisms

and various flow regimes.
The derivative
plotting techniques can assist in identifying
linear, bilinaar, radial and natural fracture
flow regimes. The more complex reservoirs
that exhibit a high degree of anisotropy
and/or more than one predominant production
mechanism may preclude the effective use of
theabove analysismethods. Complex reservoirs
may require additional data and luoresophisti-
cated analyeis techniques to successfully
interpret well test and production data.
To optimize fracture length and conductivity,
the post-fracture production resulting from
various
stimulation
designs/alternatives
should be predicted,
and the economics of
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 hy-
draulically fractured welle, presented by
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
non-Darcy flow and layered resemoirs.
The
effects ofcomplexnatural fractureproduction
mechanisms combined with a hydraulic fracture
can be too intricate for analytical well
solutions andmay require reservoir simulation
techniques to obtain quantitative predictions
of post-fracture well performance.16117
There are two major factors that influence
post-fracture well productivity associated
with the selection
of stimulation materials:
● fracture conductivity, and
●
reservoir damage.
Holditch18 and Pratslg have presented studies
on the effect of reservoir damage on well
productivity for homogeneous reservoirs at
the fracture faces. These studies illustrated
that in most cases, reservoir damage does
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

post-fracture well productivity.
In the
case
of a naturally fractured reservoir, the
majority of fluid leakoff is into the natural
fracture system. Therefore,
the relative
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
been discussed by many authors.21-23 In
general, the required insitu fractureconduct-
ivity for a homogeneous reservoir can be
~~Ztda~53
the following equation after
Cr = 10 = khfWhf/3.14~ave~f
(1)
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
simulation study and actual field data to
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.
The model verification, along with a more
*V::: Pypyr:i%tion’ ‘as ‘resented ‘n a
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 fracturedreservoirs
wae conducted to compare the behavior of the
two production mechanisms.
The simulations
were performed usfnga cartesian and anatural-
lyfractured gas reservoirmodel. The natural-

ly fractured model is described and verified
in SPE Paper 16434,24 while the cartesian
model is described in detail in SPE Paper
16219.15 The simulated reservoirs were rela-
tively tight gas formations, exhibiting an
average permeability of 0,02 md.
Table 1
contains the basic reservoir parameters used
for the simulations.
Figure 1 is a Horner plot of the pressure
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
the matrix.
Reviewing this figure shows
f

the required fracture conduct vity for a
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
middle time Horner slope. This confirms lshouldrepresent theaverage, bulk permeabil-
thatall three reservoirshave the same average
ity
of the naturally fractured reservoir as
flow capacity. obtained from the middle time Horner slope
or other appropriate estimations. The simula-
Figure 2’ is a log-log pressure/derivative
tions are also intended to evaluate the long
comparison of the three cases.
Natural frac-
term productivity of naturally fractured
ture Case A exhibits the characteristic pres- reservoirs.
The base resemoir data used
sure and pressure derivative shapes fornatur-
for these simulations are the same as listed
ally fractured reeervoirs,24 while Case B
in Table 1.
The performance for each case
does not, dueto the small contrast in natural
was simulated for 10 years using a constant
fracture and matrix conductivity.
In the bottomhole pressure (BHP) of 1,500 psi. It
absence of wellbore storage, predominant
should be noted that the simulation model
natural fracture production is evident from

has been verified against accepted analytical
well testing.
However, when production is
solutionswhereapplicable, 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 5 compares the lo-year performance
Figure 3 is a Horner comparison identical to
for isotropic naturally fracturedandhomogen-
Figure 1 except for the inclusion of wellbore
eous reservoirs for Cr
(Equation 1) values
storage.
The effect of wellbore storage
of 0.1, 1, 10 and 100. The figure shows
masks the early time data that aids in identi-
that well performance is identical for both
fying natural fracture behavior.
Figure 4
production mechanisms and is a function of
is the log-log comparison
of the pressure
average, bulk reservoir flow capacity only.
buildups. Againr the effects of wellbore
The relationship between hydraulic fracture
storage mask the characteristic derivative
conductivityandaverage reservoirpermeability
curve associated with naturally fractured

fora naturally fracturedreservoir (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 optimizehydraulic fracture
mechanisms.
The examples presented are in-
length and conductivity for homogeneous reser-
tended toillustrate thedifficultly inidenti-
voirs is applicable to isotropic naturally
fying naturally fractured reservoirs based
fractured reservoirs.
solely on well test data and the usefulness
of a bottomhole shut-in of test wells.
It shouldbe noted thatthere are manyhydraul-
ic fracture design criteria for naturally
Previouswork2 4hasshownthat natural fracture
fractured resemoirs relating to fluid loss
anisotropyis not easily identifiednorquanti-
and natural fracture damage that differ from
fied from well test data. There may be no
homogeneous reservoirs. The simulations
distinguishingcharacteristicsbetweenisotrop-
ic and anisotropic naturally fractured reser-
presented assume that the process of creating
the hydraulic fracture does not impair the
voirs. Also, prev+.ouswork24 has discussed
flow capacity of the intersected natural

the post-fracture pressure buildup behavior
fractures.
In many cases, the flow capavity
of naturally fractured reservoirs. That work
of the natural fractures can be significantly
emphasized the similarity in pressure buildup
impaired by stimulation fluids.16 Also, the
characteristics between various
ieotropic
applicabilityofhomogeneous resenoirfraoture
andanisotropic naturally fracturedreservoirs
design criteria to naturally fractured reser-
containing hydraulic fractures.
The conclu-
voirs assumes that treatment design and mater-
sions indicated that calculated hydraulic
ials are
of similar nature and cost for both
fracture lengths could vary greatly depending
reservoirs.
The problems associated with
on prior knowledge of the degree of reservoir
fluid loss and natural fracture damage may
anisotropy. dictate different stimulation designs and
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 fracturedreservoirs
1 and not be evident from well test data.
B
having the same average flow capacity. This
The direction of the reservoir anisotropy
section is limited to isotropic reservoirs.
can be directly related to the in situ stress
589
FRACTURE DESIGN CONSIDERATIONS
IN
NATURALLY FRA
Fieldofthe reservoir, with the lowpermeabil-
ity natural fractures aligned parallel to
the minimum prinaiple stress.16 Therefore,
the hydraulic fracturewill probably intersect
:he less permeable natural fracture set.
?igure 6 illustrates the minimum and maximum
?rinciplestresses, 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
rnnisotropyon pnst-fracturewell productivity

and fracture design criteria.
The basic
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
Was used for all anisotropic simulations.
rhe simulations predicted well performance
for 10 years using a variety of fracture
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
6).
The performance of the corresponding
isotropic naturally fractured reservoir is
shown for comparison. The figure illustrates
that significantly higher production rates
are obtained if the hydraulic fracture is
preferentially oriented to intersect the

high permeability set of natural fractures.
However, in many reservoirs, the in situ
stress field results inanunfavorable fracture
orientation (intersectin~the lowpem.aability
Sf3t of natural fractures”5) (referenceFigure
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
a function of propped fracture length is
compared in Figure 8 for isotropic and aniso-
tropic naturally fractured reservoirs.
The
figure illustratesagainthatwell performance
is significantly affected by reservoir anise-
tropy.
It should be noted that the base
production (no hydraulic fracture) is the
same for both the isotropic and anisotropic
naturally fractured reservoirs.
Therefore,
pre-fracture
production
characteristics,
even long term, can not identify natural
fracture anisotropy.
T1.e figure includes
two fracture orientations in the anisotropic
case, parallel to the minimum permeability

natUral fracture (denoted Miso Min) and
parallel to the maximum permeability natural
fractures(denotedAniso Max). As discussed,
the more probable case is linisoMax, where
the hydraulic fracture intersects theminim.us
permeability natural fractures that are many
PURED RESERVOIRS
SPE 1760
times oriented paralleltothe minimum horizon-
tal stress (reference Figure 6).
Figure 8 illustrates the drastic effect that
fracture orientation has on 10-yearcumulative
production.
If the hydraulic fracture is
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
is approximately in the middle of the two
extremes.
The purpose
cf Figure 8 is to
emphasize the significanceof natural fracture
anisotropyon post-fracturewell 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-fracturewell 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
lists the base economic data used for the
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
oriented parallel to the low permeability
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
anisotroplc naturally fractured reservoir
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 post-
fracture well productivity.
As discussed,
duringa stimulationtreatment,the interjected
natural fractureswillbetheprimary mechanism
for fluid loss into the reservoir. Thedispro-
portionate amount of fluid lost into the
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
.
17tin7 C.L. CIPOLLA. P.T. BRANAGAN AND S.J. LEE
, .
— .—. , —.

—— —. -—.— -—- ——
;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
{ears.
Figure 10 compares the production
well tests are presented in Figures 13 and
#ithandwithout natural fracturepermeability
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
There has been extensive geological, log,
Pressure Buildup Behavior
core, well test and production data gathered
at the DOE MWX cite. The reader can refer
[n many cases, naturally fractured reservoirs
toprevious Ublications foradditional details
onthe~. ~7-31 Thewell test and production
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.
latural fractures near the wellbore,
this The results are reproduced from previous
~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
Iurations may not be adequate.
stimulation treatment,
extended production
and well testing data were obtained in an
l?hepressure buildup behavior of an unstimu-
attempt to quantify the stimulation resulte.
Lated,naturallyfracturedreservo ircontaining
a 10-ft damage zone around the wellbore was
Initial reservoir data were obtained from
6imulated.
The base reservoir data are listed
log,
in Table 1, natural fracture Case A.
core, geological, stress testing and
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 fractureorientationand theorienta-
sure buildup behavior of the corresponding
tion of minimum and maximum natural fracture
homogeneous system was also simulated for

permeability for the development of accurate
comparison (reference Table 1, homogeneous
reservoir models.
It should be noted that
case). The drawdown period was 72 hours,
the pressure buildup data at the MWX was
followed by a shut-in lasting 168 hours. obtained using abottomhole shut-intominimize
The test duration was selected to reflect
wellbore storage/afterflow,
thus providing
conventional test durations.
Each well was
excellent reservoir data to identify natural
produced at a constant surface rate of 18
fracture flow regimes.
MCFD . For reference, the undamaged pressure
buildup behavior of both cases is shown in
MWX Paludal Zone
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
the log-leg plot in Figure 12, it appears
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
Figures 16 and 17 are Horner and log-log
plots, respectively, of the final preseure
plot is 0.001 md for the naturally fractured buildup shown in Figure 15.
Also shown in
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
of both reservoirs is 0.02 md, illustrating reservoir model.
Table 4 shows the model
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
a less than optimum stimulation design and buildup behavior of the test well (MWX-1)
inaccurate evaluation
of post-fracture well
and the lack of pressure interference in the
test and production data.
two.observation wells (MWX-2 and MWX-3).

FRACTURE DESIGN CONSXDERATXONS
IN
NATURALLY ERA(
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
m conductive hydraulic fracture had been
created, but during the fracturing process,
the intersectednatural fracturesweredamaged.
AS a result, initial post-fracture production
was impaired.
Following an extended shut-in period, the
well was recentered and tested again.
Figure
19 shows the re-entry production and well
test results.
The figure indicates that
flow rates
are enhanced compared to both the
initial post-fracture and pre-fracture rates.
The Horner plot of the re-entry pressure
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
production data.
The log-log plot of the
re-entry data is presented in Figure 21,
comparing the pressure and derivative curves
of the actual and the simulated data. Review-
ing Figures 20 and 21 shows that the rese~oir
simulation model accurately predicted the
pressure/productionbehavior for this Paludal
zone.
The conductive fracture length used
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 post-
fracture well productivity.
It should be
noted that the hydraulic fracture orientation
was estimated to be parallel to the maximum
permeability natural fractures, based on
geology, well testing and the orientation of
situ stresses.
The reservoir simulation study and field
data presented illustrate that hydraulic
fracture design in naturally fractured reser-
voirsrequires extensivepre-fracturereservoir
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 pre-
and post-fracture well productivity for
both homogeneous and naturally fractured
reservoirs.
The comparisons were based on
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
MJRED RESERVOIRS
SPE 176C
reservoir permeability for naturally fractured
reservoirs and emphasizes the problems associ-
ated with wellbore storage/afterflow. The
abilitytodistinguish natural fractureproduc-
tion is significantly affected bytheduration
of wellbore storage.
In cases where wellbore
storage is extensive, natural fracture flow
regimes may be completely absent, and only a
bottomhole shut-in can provide sufficient

data to accurately describe the reservoir
using well test data.
Post-fracture well productivity for naturally
fractured wells is compared to that of analog-
ous homogeneous reservoirs. The results
illustrate the applicability of current frac-
ture design criteria inhomogeneous reservoirs
for fracture design in naturally fractured
reservoirs. The importanceofnatural fra~ture
anisotropy is investigated in detail by simu-
latingthepost-fracture production forvarious
fracture lengths andorientations. The effects
of permeability impairment to the natural
fractures intersected by a hydraulic fracture
is illustrated.
The reservoir simulation results are supple-
mented by field data from the DOE MultiWell
Experiment.
The results of extensive well
testing and reservoir modeling are provided
to illustrate the application of the fracture
design criteria presented.
The field data
shows both natural fracture permeability
impairment and anisotropy.
CONCIXYSIONS
1.
2.
3.
4.

5*
Accepted
fracture design criteria for
homogeneous resemoirs can be applied
directlyto isotropic, naturally fractured
reservoirs to predict post-fracture well
performance and optimum fracture length
and conductivity.
Well test data may not distinguish natural
fracture production in the presence of
wellbore storage. In many field applica-
tions, a bottomhole shut-in is required to
identify natural fracture flow regimes.
Natural fracture
anisotropy can alter
fracture design
and interpretation of
post-fracture well test data. Assuming a
constant hydraulic fracture conductivity,
optimum fracture lengths may be shorter
in an anieotropic naturally fractured
reservoircomparedtoanisotropic 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
assumed hydraulic fracture orientation

stated in Conclusion 3) will be less than
the corresponding isotropic naturally
fractured reservoir.
Natural fracture permeability impairment
can
significantly reduce post-fracture
~
(
.
-
SPE 17607
C.L. CIPOLLA, P.T. 1
I
well productivity and should be minimized
and quantified as much as possible.
I
ACIWOW’XXDG~S
This work was sponsored by the United States
Department of Energy
in conjunction with
the Multiwell Experiment.
The technical
information presented istheproduct of ajoint
●ffort, and the authors wish to thank the
CER/MWX field crew, Sandfa National Labora-
tories MWX etaff and the CER engineering
and computer etaff.
I
NOMENCLATURE
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
Pwf = pressure at the end of flow in well
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.
Prats, M. J.S. and Levine: “Effect of
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: ‘IHydraulicFracturing-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
-Ite Effect cn Steady-State Production
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.
Hclditch, S.A.: Criteria For Selecting
Propping Agents, 2ndEdition, Norton-Alcoa
Proppants, Dallas, 1984.
Norman, M.E. and C.R. Fast.:Proppant Mono-

graph,
General
Abrasive Division of
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. DohertySeries).
Earlougher, R.C. Jr.: Advances in Well
Test Analysis, Society of Petroleum Engi-
neers of AIME,
Dallas (1977), Volume. 2
(Henry L. Doherty Series).
Pirard,
Y.M. and A. Bocock: “Pressure
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.
— _ _——.—.——- .——-—— ——
—
L1. Bourdet, D., T.If.Whittle, A.A. Douglas
Generation
High-Strength Proppant in
and YOM. pirard: ‘IANew Set of Type ~rves
Tight Gas Reservoirs,ltSPE 11633, pre-
Simplifies Well Test Analysis,c! world
sented at the 1983 SPE/DOE Symposium on
Oil, (May 1983), 95-106.

Low Permeability, Denver, Colorado, March
14-16, 1983.
12. Houze, O.P.,
R. Home and H,J. Ramey,
Jr.:
ItInfinite Conductivity Vertical
23. Penny, G.S.: ‘An Evaluation of the Effects
Fracture in aReSerVOir With DOUble POrOS-
of Environmental Conditionsand Fracturing
ity Behavior,n SPE 12778, presented at
Fluids Upon the Long-Term Conductivity
the California Regional Meeting, Long
of Proppants,” SPE 16900, preeented at
Beach, April 11-13, 1984.
the 62nd Annual Technical Conference and
Exhibition
of the Society of Petroleum
13. cinco-L., H.,
F. Samaniego-V. and N.
Engineers, Dallas, Texas, September 27-
Dominquez-A.:‘ITransientPressure Behavior
30, 1987.
for a Well with a Finite Conductivity
Vertical Fracture,w Sot. Pet. Engr. J.
24. Branagan, P.T., c.L. Cipolla, S.J. Lee
(August 1978), 253-264.
and J. Chen:
tlDe8igningand Evaluating
Hydraulic Fracture Treatmentein Naturally
14. Holditch, S.A. andR.A. Morse: “TheEffects

Fractured Reservoire,ll SPE/DOE 16434,
of Non-Darcy Flow on the Behavior of
presented at the SPE/DOELcwPermeability
Hydraulically Fractured Gas Wells,t’ J.
Reservoirs symposium, Denver, Colorado,
Pet. Tech. (October 1976), 1169-1179.
May 18-19, 1987.
15. Cipolla, C.L. and S.J. Lee: “The Effect
25. Warpinski, N.R. and P.T. Branagan: “Al-
of Excess Propped Fracture Height on tered-Stress. Fracturing,ll
SPE 17533,
Well Productivity,!! SPE 16219, presented
presentedatthe SPERockyMounta in Region-
at the SPE Production Operations Sy_mpo- al Meeting, Casper, Wyoming, May 11-13,
sium, Oklahoma City, Oklahoma, March 8- 1988.
10, 1987.
26. Sattler, A.R., B.L. Gall, C.J. Raible
16. Branagan, P.T., C.L. Cipolla, S.J. Me
and
POJ. Gill: llFrac Fluid swtfms for
and L. Yan:
ItCaseHistory of Hydraulic
Naturally Fractured Tight Gas Sandstones:
Fracture Performance in the Naturally
AGeneralCase Study fromMultiwell Experi-
Fractured Paludal Zone:
The Transitory ment stimulations,!’SPE 17717, presented
Effects of Damage,r?SPE/DOE 16397, pre-
at the SPE Gas Technology symposium,
sented at the SPE/DOE Low Permeability Dallas, Texas, June 13-15, 1988.

Reservoirs Symposium, Denver, Colorado,
May 18-19, 1987.
27. Northrcp, D.A., et al: “Muitiwell Experi-
ment: A Field Laboratory for Tight Gas
17. Branagan, P.T., S.J. Lee, C.L. CiPOlla
Sands,liSPE/DOE 11646, presented at the
and R.H. Wilmer: llPre-FracInterference
1983 SPE/DOESymposiumonLcwPermeability
Testing of a Naturally Fractured, Tight
Gas Reservoirs, Denver, Colorado.
Fluvial Reservoir,llSPE 17724, presented
at the SPE Gas Technology Symposium,
28. Lorenz, J.C., et al: ‘tFractureCharacter-
Dallas, Texas, June 13-15, 1988.
istics and Reservoir Behavior of stress-
Sensitive Fracture Systems in Flat-Lying
18. Holditch, s.A.: ‘lFactorsAffecting Water
Lenticular Formations,” SPE 15244, pre-
Blocking and Gas Flow From Hydraulically
sented at the SPE Unconventional Gas
Fractured Gas Wells,
II J, pet. Tech. (Decem-
Technology Symposium, Louisville, Ken-
ber 1979), 1515-1524. tucky, May 18-21, 1986.
19. prat-, M.: llEffectof vertical Fractures
29. Lorenz, J.c.: ‘Jsedimentologyof the Mesa-
on Reservoir Behavior -
Incompressible
verde Formation at Rifle Gap, Colorado,
Fluid Case,f’ Sot. Pet. Engr. J.

(June and Implications for Gas-Bearing Intervale
1961), 105-118.
in the Subsurface,t’Sandia Report, March
1982.
20. Branagan, P.T., C.L. Cipolla, S.J. Lee
and R.H. Wilmer:
ItComprehensive
Well
30. Lorenzt J.C.:
llpredictionSof Size and
Testing and Modeling of Pre- and Post-
Orientations of Lenticular Reservoir in
Fracture Well Performance of the MWX the Mesaverde Group, Northwestern COlOr-
Lenticular Tight Gas Sands,’~ SPE/DOE
ado,!! SPE/DOE 13851, presented at the
13867, presented at the SPE/DOE 1985 Low
SPE/DOE Symposium on Low Permeability
Permeability
Gas
Reservoirs, Denver,
Reservoirs, Denver, Colorado, May 19-
Colorado, May 19-22, 1985.
22, 1985.
21. Cooke, C.E. Jr.:
tlEffeCtof Fracturing
31. Warpinski, N.R., et al: “Fracturing and
Fluids on Fracture Conductivity,’8 J.
Testing Case Study of Paludal, T:ght,
Pet. Tech. (October 1975), 1273-1282. Lenticular Gas Sands,!’ SPE/DOE 13876,
22. Callanan, M.J., C.L. Cipolla and P.E.

presented at the SPE/DOE Symposium of
Low Permeability Reservoirs,
Denver,
Lewis:
:!TheApplication of a New Second-
Colorado, May 19-22, 1985.
- . -Tnnrra m ml nnauacau aun Q 7. TX%! 9
—
; 17607
U.k.
b&rvum? =*.
● =— -=- —-
Table 1 Base Reservoir Simulation Input Data
Table 2 Input Data for Hydraulic Fracture Simulatim?s*
Common Data
Hydraulic Fracture Propartias
Pi =
4,000 psi
khf =
25,000 md
Tr = 24CF F
Whf =
0.12 in.
Tid =
2.441 in.
T,D. = 6,000 ft
Fracture Langtfr, ft Cr
h
.
40 ft

400
10
P
.
0.0214
Cp @ pi
0.7862 ResBBUMCF @ Pi
800
#
.
1,200
3!3
Cg =
0.000196 psi-l @Pi 1,600
2.5
Homogeneous Reservoir
Anisotropic Natural Fracture Propartias
kln
0,02 md
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
A

B
Case A
km
0.0002 md
0.015 md
‘$m
0.05
0.05
.
knf
1,980 md
500 md
4mf
0.5
0.5
Table 3 Base Economic Input Data
Wnf
0.0006 in.
0.0006 in.
Wrn
5 ft
5 ft
Stimulation
and Initial
Wall Test Data
Lf, ft Imrestmant Cost
Common Data
240 hrs drawdown@ 100 MCFD
o
$360,000

Gas
Price
= 1,5 $/MCF
1,000 hrs shut-in – BHSI & Surface Shut-In
400
392,000
Price Escalation = None
Soo
450,000
Operating Cost =“800 $/Mo
1,200
590,000
Discount Rate = 10%
1,600
860,000
Net Rev. Int.
=
so%
Working Int.
= 100%
Tabla 4 Pra-Fraclure Model Input Data for MWX Paludal History Match
Basa Reservoir Data
Matrix Properties
Natural Frectura Properties
Channel width = 350 ft
km=l,O~d
knf
mex = 5,000 md
Pi= 5,400 psi
@m= 0.04

knf min = 500 md
T.D. = 7,000 ft
rjnf = 1.0
Tr=2100F
Wm=5ft
h=40ft
Wnf = 0.001 in,
S.G, = 0.626
skin, 2.5 ft in y-direction
p =
0.02 Cp
ks= 100md
Table 5 Ra-Entry Model hrput Data
Hydraulic Fracture
Base Raservoir Data
Matrix Properties
Natural Fractura Properties
Properties
Channal width= 350 ft
km=l.Ogd
knf max = 5,000 md
Khf = 5 darcy
Pi= 5,400 psi
@m= 0.04
(4%)
knf
min = 500 md
Whf = 0,25 in.
T.D. = 7,000 ft
@nf = 1.0

Lf=100ft
Tr” 21@ F
Wm=5ft
h=40ft
Wnf = O.OO1 in.
S.G. =
0.626
—
FRACTURE DESIGN CONSIDERATIONS
IN NATURALLY FRACTURED RESERVOIRS SPE 17607
L
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dlW~,dWfJdlOfJ
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—.
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SPE 17607
C.L. CIPOLLA, P.T. BRANAGAN AND S.J. LEE
11
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A
s
1,100.1,200tt
$W
em -1,100ft
4m
o
2m 400 em em Moo Im 1?400 t~
l,am
Lfofl
Fi@e 9 Comparison of Present Vakw Profit for isotropic and
Anisotropic Reservoirs, L f = O,4&W, 8# and l,2iM ft
4,0m
3,000
2,0m
l.ooa
10
\ ,
&
t ;
\
*
n a *.

lm
l,mo
11
Fkw lTnN, Mmtha
Fi~n 10 Comparison of Post-Fracture Production With and Without
Natural Fracmra Permeability Impairment
Siwt-in Tim., Hrs.
Honnr TInm
Fi~ra ?1 Homer Plot of Pressure Buildup Behavior of Natutally Fractured
and Homogeneous Reservoin With Wellbon? Damage –
Minimal
Wellbort? Storage
Fi@e 12 LopLog Plot of Pressure Buildup Behakor of Naturally Fractured and
Homogeneous Resarvoim With Wellbore Dama@ – Minimal Wellbore
storage
SPE 17607
C.L. CIPOLLA, P.T.
BRANAGAN AND S.J. LEE 13
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FRACTURE DESIGN CONSIDERATIONS
14
IN NATURALLY FRACTURED RESERVOIRS

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