AAGP B-Natural Fractures in The

AUTHORS

Julia F. W. Gale � Bureau of EconomicGeology, Jackson School of Geosciences, Uni-versity of Texas at Austin, J. J. Pickle ResearchCampus, Building 130, 10100 Burnet Road,Austin, Texas 78758-4445;[email protected]

Julia Gale obtained a Ph.D. in structural ge-ology from Exeter University in 1987. She taughtstructural geology and tectonics for 12 yearsat the University of Derby. She moved to theUniversity of Texas at Austin in 1998, workingas a research associate first in the Depart-ment of Geological Sciences and then the Bu-reau of Economic Geology. Her interests in-clude fracture characterization in carbonateand shale hydrocarbon reservoirs.

Robert M. Reed � Bureau of EconomicGeology, Jackson School of Geosciences, Uni-versity of Texas at Austin, J. J. Pickle ResearchCampus, Building 130, 10100 Burnet Road,Austin, Texas 78758-4445

Rob Reed is a research scientist associate atthe Bureau of Economic Geology. He receivedhis B.S. degree and his Ph.D. in geological sci-ences from the University of Texas at Austinand his M.S. degree in geology from the Uni-versity of Massachusetts. His current researchfocuses on various aspects of the microstruc-ture of rocks.

Jon Holder � Department of Petroleumand Geosystems Engineering, University ofTexas at Austin, Austin, Texas

Jon Holder received a Ph.D. in physics fromthe University of Illinois at Urbana Champaign(UIUC) in 1968. He was a member of the Ge-ology Department faculty at UIUC from 1969until 1981, teaching and conducting researchin areas of rock physics. He worked in geo-technical research in the private sector from1981 to 1989 and then joined the research staffin the Petroleum and Geosystems Engineeringat the University of Texas at Austin, where hecontinues to do research in mechanical behaviorin porous media, with emphasis on fracturemechanics.

Natural fractures in theBarnett Shale and theirimportance for hydraulicfracture treatmentsJulia F. W. Gale, Robert M. Reed, and Jon Holder

ABSTRACT

Gas production from the Barnett Shale relies on hydraulic frac-

ture stimulation. Natural opening-mode fractures reactivate dur-

ing stimulation and enhance efficiency by widening the treatment

zone. Knowledge of both the present-day maximum horizontal

stress, which controls the direction of hydraulic fracture propaga-

tion, and the geometry of the natural fracture system, which we

discuss here, is therefore necessary for effective hydraulic fracture

treatment design.

We characterized natural fractures in four Barnett Shale cores

in terms of orientation, size, and sealing properties. We measured a

mechanical rock property, the subcritical crack index, which gov-

erns fracture pattern development. Natural fractures are common,

narrow (<0.05 mm; <0.002 in.), sealed with calcite, and present

in en echelon arrays. Individual fractures have high length/width

aspect ratios (>1000:1). They are steep (>75j), and the dominant

trend is west-northwest. Other sets trend north-south. The narrow

fractures are sealed and cannot contribute to reservoir storage or

enhance permeability, but the population may follow a power-law

size distributionwhere the largest fractures are open. The subcritical

crack index for the Barnett Shale is high, indicating fracture clus-

tering, and we suggest that large open fractures exist in clusters

spaced several hundred feet apart. These fracture clusters may en-

hance permeability locally, but they may be problematic for hydrau-

lic fracture treatments. The smaller sealed fractures act as planes

of weakness and reactivate during hydraulic fracture treatments.

Because the maximum horizontal stress trends northeast-southwest

and is nearly normal to the dominant natural fractures, reactivation

widens the treatment zone along multiple strands.

AAPG Bulletin, v. 91, no. 4 (April 2007), pp. 603–622 603

Copyright #2007. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received June 1, 2006; provisional acceptance August 24, 2006; revised manuscript receivedOctober 13, 2006; final acceptance November 1, 2006.

DOI:10.1306/11010606061

INTRODUCTION

The Mississippian Barnett Shale gas play in the Fort Worth Basin is

the largest gas field in Texas, with reserves exceeding 2.7 tcf (Mont-

gomery et al., 2005). Success in the Fort Worth Basin has increased

interest in the Barnett Shale elsewhere, for example, in the Permian

Basin (Figure 1). Other Mississippian and Devonian shales are also

being considered as possible Barnett-like plays. The geology of the

Barnett Shale and structure of the Fort Worth Basin have been de-

scribed by many workers, including Cheney (1940), Cheney and

Goss (1952), Henry (1982), andMartin (1982, and articles therein).

More recently, there have been contributions on geochemistry by

Pollastro et al. (2003) and Hill et al. (2007), on lithologic char-

acterization (Papazis, 2005), and on depositional setting and litho-

facies (Loucks and Ruppel, 2007). Production performance of the

Barnett Shale was evaluated by Frantz et al. (2005).

The terms ‘‘Barnett Formation’’ and ‘‘Barnett Shale’’ have both

been used formally. ‘‘Barnett Shale’’ as a name is misleading because

most of the Barnett Formation is a mudstone rather than shale

(Loucks and Ruppel, 2007) but we adopt it here because of its

wider usage. In lithologic descriptions, we use the term ‘‘mudstone’’

to describe a relatively nonfissile clastic rock containing dominantly

noncalcareous, clay-size particles, in contrast to shale, which is char-

acteristically fissile because of higher clay content. In the general

discussion of the play type, however, we use the term ‘‘shale’’ to

include both shale and mudstone.

An overall evaluation of the Barnett Shale play was summa-

rized most recently by Montgomery et al. (2005), who identified

several factors that make it unique compared with other gas-shale

plays. These include the great depth and high pressure of the res-

ervoir and the complex thermal history, which has influenced the

geochemistry of hydrocarbon generation and storage. Montgomery

et al. (2005), however, also stated that natural fractures do not ap-

pear to be essential for production and, in some cases, might reduce

well performance, giving the impression that natural fractures are

unimportant or undesirable. We do not concur with this general

finding, although we agree that there are circumstances where they

could be detrimental to well performance, for example, if natural

fractures are connected to the water in the underlying Ellenburger

Group. The purpose of this article is to demonstrate the nature of

the natural fracture system in the Barnett Shale and explain why

natural fractures can be useful for improving hydraulic fracture treat-

ment efficiency and, thereby, gas production. Moreover, general prin-

ciples learned in the Barnett Shale in the Fort Worth Basin might

be applicable elsewhere.

Two separate questions regarding natural fractures in the Bar-

nett Shale must be addressed. First, can they provide enhanced per-

meability or storage capacity for the reservoir? Second, do they

enhance or hinder hydraulic fracture treatments? In addressing the

first question, we show that whereas storage capacity of the natural

fracture system is low because most small fractures are sealed, it is

ACKNOWLEDGEMENTS

J. F. W. Gale thanks Bob Loucks and Steve Ruppelfor encouragement to work on the BarnettShale. Peggy Rijken did the subcritical testing.Randy Marrett, Steve Laubach, and Jon Olsonprovided the foundation for ideas concerningfracture scaling and sealing and fracture pat-tern evolution. In-situ stress data were obtainedfrom the World Stress Map, an open-accessdatabase project of the Heidelberg Academyof Sciences and Humanities and the Geophys-ical Institute at Karlsruhe University. Helpfulreviews by Ron Hill, Ron Nelson, and GaryProst, together with editorial comments fromErnie Mancini, helped us to improve the man-uscript. The State of Texas Advanced ResourceRecovery program supported J. F. W. Gale. J.Holder and R. M. Reed were supported by theUniversity of Texas Fracture Research and Appli-cation Consortium. Additional support was pro-vided in part by the John A. and Katherine G.Jackson School of Geosciences and the GeologyFoundation at the University of Texas at Austin.This article is published with permission of thedirector of the Bureau of Economic Geology,University of Texas at Austin.

604 Natural Fractures in the Barnett Shale

possible that there are large, open fractures in widely

spaced clusters that may enhance permeability locally.

With respect to the second question, evidence is mount-

ing from microseismic monitoring of hydraulic frac-

ture propagation (e.g., Fisher et al., 2004; Warpinski

et al., 2005) that reactivation of the natural fracture

network improves efficiency of stimulation (Figure 2).

The method of completion in the Fort Worth Basin

Barnett Shale has evolved so that horizontal wells are

stimulated with low-proppant, high-flow-rate, water-

based hydraulic fracture treatments (Warpinski et al.,

2005). The wells are commonly drilled normal to the

expected hydraulic fracture propagation (normal to

the maximum horizontal stress, SHmax) to maximize

Figure 1. Distribution of Barnett Shale and equivalents and Mississippian carbonates in the southern mid-continent (after S. C.Ruppel, 2005, personal communication). Large structures are after Montgomery et al. (2005). Maximum horizontal stress (SHmax)directions derived from the World Stress Map (Tingay et al., 2006) are shown. SHmax trends are consistently northeast-southwest inthe Fort Worth Basin, but are less consistent to the west in the Permian Basin because this region is at the modern-day stressprovince boundaries of the mid-plate compressional province, the southern Great Plains province, and the Cordilleran extensionalprovince. Cores studied here are indicated by numbered circles: 1 = Mitchell Energy 2 T. P. Sims; 2 = United Texas 1 Blakely; 3 =Houston Oil and Minerals MC-1 Johanson, Harold; 4 = Cities Service 1 St. Clair C.

Gale et al. 605

the volume stimulated by induced fractures. Natural

fractures, however, reactivate during treatment, widen-

ing the zone of stimulation. Characterization of the nat-

ural fracture system and local SHmax is therefore highly

desirable to maximize the efficiency of hydraulic frac-

ture treatment design.

Published data from theWorld Stress Map (Tingay

et al., 2006) indicate a consistent northeast-southwest

trend for SHmax in the northern part of the Fort Worth

Basin near Wise County (Figure 1), which is in agree-

ment with the known dominant hydrofracture prop-

agation trend. By contrast, little published information

on natural fracture attributes in the Barnett Shale exists,

although natural fractures are common. In this study,

we characterized natural fractures in terms of orienta-

tion, size, and sealing, and we measured a mechanical

rock property, the subcritical crack index, which governs

fracture pattern development. Our aim is to provide a

basis for investigating how natural fractures might af-

fect the play, with particular emphasis on the inter-

action with hydraulic fracture treatments.

Approach for Natural Fracture Characterization

Natural fracture data from the subsurface were ob-

tained from vertical cores. Because natural fractures in

the Barnett Shale are also mostly subvertical, we en-

countered a sampling problem where large fractures

Figure 2. Diagrammatic representation of hydraulic fracture growth showing why natural fracture systems are important for optimalstimulation. (a) Hydraulic fracture growth proceeds northeast-southwest and reactivates natural fractures (dashed lines) trending west-northwest–east-southeast and north-south. Arrows indicate the propagation direction of hydraulic fractures. (b) Map of microseismicdata from Warpinski et al. (2005, reprinted with permission from the Society of Petroleum Engineers). (c) A sealed west-northwest–trending fracture and an open, unmineralized, northeast-trending, induced fracture in a disc from the T. P. Sims core.


are typically more widely spaced than the diameter of

a borehole and are rarely sampled. Smaller fractures in

the same set may be clustered, and the apparent local

intensity (fractures per unit volume, area, or scanline

length) of fractures observed at any sampling point in

a core or image log may not reflect the fracture inten-

sity away from the wellbore. Fractures may be more

or less intense than suggested by the sampling. Direct

evidence of fracture spacing is typically lacking. Proba-

bilistic methods using fracture data from vertical core

have had success in predicting average fracture spacing

where fractures are evenly spaced (Narr, 1996), but

they do not address the degree of fracture clustering.

To avoid the sampling problem, several workers

have used seismic attributes to measure anisotropy as-

sociated with fractures. Simon (2005) tried this ap-

proach in north Texas using new seismic attributes,

including azimuthal interval velocity, seismic volumet-

ric curvature, and interazimuth similarity. Open frac-

tures that correlatedwith fracturesmapped usingmicro-

seismic data were detected. These fractures, orthogonal

to SHmax, had been reactivated by hydraulic fracture

treatments. Thus, although the technique can detect

reactivated fractures and provides confirmation of such

reactivation, it cannot, at this stage, provide sufficient

detail to characterize the natural fracture system.More-

over, because it does not detect sealed, unreactivated

fractures, it cannot be used in advance of stimulation to

predict mechanical behavior of the reservoir.

An alternative approach is to use microfractures

that are abundant in core to predict macrofracture at-

tributes. We define a macrofracture as a fracture that

can be observed by the eye, whereas a microfracture re-

quires magnification greater than�10 to be detected. An

opening-mode fracture set comprises fractures across a

range of sizes. Within a set, orientation (Laubach, 1997)

and timing (Laubach, 2003) are consistent across the

range of scales, and intensity shows a size-dependent

power-law distribution (Marrett et al., 1999). Frac-

ture population attributes of porosity and permeability

(Marrett, 1996) and the sealing of opening-mode frac-

tures (Laubach, 2003) are also size dependent. We are

able to use these size-scaling relationships to predict

the attributes of large fractures from observations of

smaller ones in the cores. Additionally, an understand-

ing of opening-mode fracture growth has been devel-

oped by Olson (2004) through geomechanical mod-

eling using a measured rock property, the subcritical

crack index, as an input parameter (Holder et al., 2001).

We have synthesized these different aspects of fracture

evolution in case studies in sandstones (Laubach and

Gale, 2006) and carbonates (Gale, 2002; Gale et al.,

2004), and in this study, we apply a similar approach to

the Barnett Shale.

In describing fracture attributes, it is essential to

indicate the size range of fractures present. Fracture in-

tensity should be reported with reference to a partic-

ular size range, for example, 10 fractures per meter

greater than or equal to 1 mm (0.04 in.) wide. Average

spacing of fractures is the inverse of intensity and, again,

depends on the size of fractures being considered. In

the Barnett Shale, many sealed fractures having aper-

tures of less than 50 mm are part of the population. Al-

though these donot contribute to thepermeability of the

reservoir, they are important planes of weakness that

tend to be reactivated by hydraulically induced frac-

tures. All natural fractures, including small sealed frac-

tures and large potentially open fractures, must there-

fore be taken into account when predicting hydraulic

fracture behavior.

Structural Geology of the Fort Worth Basin

The large-scale structure of the Fort Worth Basin con-

tains several arches and faults (Figure 1). These are

mostly associated with the late Paleozoic Ouachita orog-

eny. Possible mechanisms of fracture formation might

be deduced from kinematic analysis of these large struc-

tures, together with burial-history data. It is generally

not valid, however, to link opening-mode fractureswith

large structures on the basis of orientation alone. Equiv-

alence of timing, tied with sound mechanical reasons

for linking the structures, is required. Opening-mode

fractures can form readily under many different condi-

tions partly because rocks have low tensile strength.

Moreover, evidence of crack-seal texture in north-south–

trending fractures indicates fracture growth proceeded

by multiple events. In the Fort Worth Basin, because of

the complex structure and the added possibility of hy-

drocarbon cracking and migration, there could be sev-

eral different mechanisms of fracture formation. For

this reason, although themajor structures are presented

for the sake of context, we do not speculate on fracture

origin from the range of possibilities. Detail on fracture

orientation and relative timing is given where known,

but it is generally insufficient to pin down the cause of

fracturing.

In addition to the structures shown in Figure 1,

saglike features in the Barnett Shale have been de-

scribed and interpreted by Hardage et al. (1996) and

McDonnell et al. (2006) as being related to paleokarst

Gale et al. 607

collapse in the underlying Ellenburger Group. The sags

are bounded by circular fault systems, which connect

down to the Ellenburger Group. The sag zones are con-

sidered undesirable for gas production because of the

potential of the faults to connect into water in the Ellen-

burger Group. Locally, opening-mode fractures may

have developed around these faults, but they would be

a separate population from the regionally developed

opening-mode west-northwest–trending fractures that

are the subject of this article.

METHODS

Fracture Characterization

Natural fractures were analyzed in two Barnett Shale

cores fromWiseCounty in the FortWorth Basin (Mitch-

ell Energy 2 T. P. Sims and United Texas 1 Blakely)

one from Erath County (Cities Service 1 St. Clair C),

and one from McCullough County close to the Llano

uplift (Houston Oil and Minerals MC-1 Johanson, Har-

old) (Figure 1). Fracture dimensions and mineral fill

were recorded for individual fractures, and fracture pat-

tern characteristics were also noted. Of the cores stud-

ied, only the T. P. Sims core was oriented. Fracture ori-

entation information is therefore confined to this core,

although it is possible to determine angles betweenmul-

tiple sets in unoriented core. Coremay be broken along

natural fracture planes; calcite crystals on the fracture

surface allow distinction between natural and induced

fractures. Previous work on natural fractures has been

included where appropriate. Specifically, fracture ori-

entation data from the T. P. Sims core were obtained

from an FMS (Formation MicroScanner) log by Hill

(1992).

Microscopy

Samples

Two samples from the T. P. Sims core, one from a

typical mudrock layer and one from a dolomitic layer,

were chosen for analysis. Some additional mudrock thin

sections were examined briefly for comparison with

observations made on the first mudrock sample. The

T. P. Sims core is from the lower unit of the Barnett

Shale. The cored interval starts 12.2 m (40 ft) below

the Forestburg limestone, extends for 44.2 m (145 ft),

and ends 35 m (115 ft) above the base of the lower

shale unit.

Instrumentation

Samples were examined using a variety of imaging and

analytical techniques. The dolomitic thin section was

first examined using cold-cathode cathodoluminescence

(CC-CL) microscopy, in which CC-CL images were

pairedwith transmitted light images.Cold-cathode catho-

doluminescence was done using a Technosyn MK-II sys-

tem operating at approximately 15 kV.

The scanning electron microscope (SEM)–based

analytical methods used on the samples were second-

ary electron and backscattered electron imaging and

SEM-based cathodoluminescence (SEM-CL) imaging.

Energy-dispersive spectroscopy (EDS) was used to de-

termine elemental composition of minerals present in

the samples. All SEM imageswere done on an FEIXL30

SEM equipped with an Oxford Instruments ISIS EDS

system and an Oxford Instruments MonoCL2 cathodo-

luminescence system. The SEM was operated at 15 or

20 kV and at large sample currents for CL imaging. Be-

cause of problemswith persistent luminescence, inmost

cases, SEM-CL imaging of carbonates requires acquir-

ing only shorterwavelengthCL emissions,which is done

most easily by inserting a broadband, short-wavelength

(ultraviolet-blue) filter between the mirror and the

photomultiplier tube (Reed and Milliken, 2003).

Mechanical Rock Properties

Subcritical Crack Growth

Mechanical rupture of amaterial occurs when themode I

(normal opening) stress intensity factor, K I, is equal to

the critical stress intensity factor or fracture toughness,

K IC, at which time the fracture propagates with a ve-

locity slightly below the shear-wave velocity. However,

fractures can also propagate at stresses well below this

level at velocities several orders of magnitude slower

than the rupture velocity. During this regime of crack

growth, the material is strained at levels below that nec-

essary for breaking bonds, but the strained bonds are

weaker andmore prone to chemical attack (Lawn, 1975;

Atkinson and Meredith, 1981). The bonds are further

weakened and ultimately broken by thermally activated

chemical interactions. An empirical power law, intro-

duced by Charles (1958), provides a good correlation

between subcritical fracture velocity, V, and the stress

intensity factor (or, because of its proportionality toK I,

applied load, P):

V ¼ k0KI

KIC

� �n

¼ APn ð1Þ


where n is the subcritical crack index, and k0 and A are

constants. This is the defining equation for the subcriti-

cal index.

In tectonically stressed crustal rocks, subcritical crack

growth can be significant, and studies have shown that

fracture-spacing length distributions, connectivity, and

fracture aperture can be controlled by this process (Olson

et al., 2001). For low values of n (<20), computed nat-

ural fracture patterns exhibit small spacing relative

to bed thickness. At high values (n � 80), fractures

are spatially arranged in widely spaced swarms or clus-

ters. Intermediate values (20–80) result in more regu-

lar fracture spacing that is roughly proportional to

layer thickness. Discrete fracture flow modeling of

geomechanically generated fracture patterns has dem-

onstrated variations in effective permeability with sub-

critical index, primarily through its influence on frac-

ture length distributions (Philip et al., 2002; Rijken,

2005).

The subcritical index can be measured in the labo-

ratory (Atkinson andMeredith, 1981;Atkinson, 1984),

and values for a range of rocks and testing environ-

ments have been reported (Atkinson and Meredith,

1981; Holder et al., 2001; Rijken et al., 2002; Rijken,

2005). The experiments are conducted in ambient

laboratory conditions at zero depth. Theoretically, this

should not affect the subcritical crack index, whose gov-

erning equation is only marginally affected by confining

pressure. For most studies, including the present study,

values for the subcritical indices are determined from

measurements of load decay in a dual torsion beam con-

figuration at constant displacement (Williams and Evans,

1973). This technique is based on empirical evidence

that the effective specimen compliance, S, is a linear

function of crack length, a. This is equivalent to the

ratio of displacement normal to the plane of the test

specimen, y, to the normal load, P:

S � y=P ¼ S0 þ B� a ð2Þ

In this expression, B is a constant; S0 is compliance

when a = 0; and the crack velocity, V, is given by the

time derivative of a. For a constant normal displace-

ment, y0, the crack propagation velocity is determined

by the rate of change of the load, P.

V ¼ � C

P2

@P

@t

� �ð3Þ

where C is another constant. The crack velocity can

then be determined from numerical differentiation.

Subcritical Crack Index Measurement

Subcritical crack index measurements were made on

two samples from theT. P. Sims core. The core samples

were sliced parallel to bedding, and several test speci-

menswith dimensions of 2.5 cm� 5 cm� 1.5mm (1�2 � 0.6 in.) were cut from the slices, polished on one

side, and grooved along the center of the nonpolished

surface.

Measurements of subcritical crack propagation were

conducted in the following test sequence:

1. The specimen is loaded in steps of approximately

0.23 kg (0.5 lb), holding the applied load constant

during each interval by means of a programmed step-

per motor.

2. When crack formation and propagation were indi-

cated by increases in vertical displacement of the

loading ram, further displacements were stopped.

3. The load was allowed to decay for approximately

10 min, attaining an approximately constant value.

Microsoft Excel’s SOLVE option was used to de-

termine the parameters from a least-squares fit of all

load decay data. This process is set up in an Excel tem-

plate, and the entire fitting procedure is conducted in a

few seconds.

RESULTS

A summary of fracture attributes for the four cores

examined is given in Table 1.

Fracture Characterization, T. P. Sims Core

All natural fractures in this core are sealed with calcite

and are typically present in en echelon groups (Figure 3).

Offsets between adjacent en echelon fractures are typi-

cally less than 5 mm (0.2 in.), and the sense of offset

may change within a group. Fractures range from less

than 50 mm to 0.265 mm (0.01 in.) in width in the

mudstone and up to 2.15 mm (0.08 in.) in a concretion

(Figure 4a). The tallest fractures extend up to 81 cm

(32 in.) in height before continuing out of the core, so

this represents a truncated value for height (Figure 4b).

True heights of the tallest fractures are not known. For

each fracture, the nature of upper and lower termina-

tions was recorded as being gradually tapered, abrupt at

bedding, abrupt at a concretion, or out of core. Of the

84 fractures measured in 110 ft (34 m) of core, 40%

of terminations were gradually tapered, 4% abrupt at

Gale et al. 609

bedding or at concretion, and 56% out of core.Mechani-

cal boundaries within the shale are most commonly

associated with changes in the carbonate content, but

carbonate layers are not always barriers to fractures.

Aperture-height relationships were plotted for all frac-

tures with a true measured height, but were distin-

guished on the basis of whether they terminated at a me-

chanical boundary or they gradually tapered (Figure 4c).

No correlation exists; fractures of a given aperture have

a wide range of heights.

Examples of induced fractures are present but

are distinguished from natural fractures by the absence

of calcite cement and, in the case of drilling-induced

petal centerline fractures, on the basis of geometry. Frac-

tures trend dominantly northeast-southwest (Hill, 1992)

(Figure 5a). One dip-slip fault trending 109j/55jSSWwas identified in the T. P. Sims (Hill, 1992). Other un-

oriented dip-slip faults with slickensides and calcite-

cemented breccias have been observed in other Bar-

nett Shale cores (Papazis, 2005).

Microfracture Analysis, T. P. Sims Core

Mineralized fractures range from 50 mm to 0.2 mm

(0.008 in.) width in the samples chosen for detailed

study. Macroscopically nonmineralized, apparently

induced fractures are also present in both. Minimal

micrometer-scale fracture porosity exists in the small

macrofractures. Bowker (2003), in trying to explain the

abundant Barnett Shale gas, yet low-permeability sug-

gested that natural microfractures might be present that

could enhance permeability. We see no evidence of

widespread open natural microfractures; fractures that

are present are sealed. Conversely, extensive SEM-based

examination of open, northeast-trending fractures in

both samples showed no evidence of mineralization.

Open microfractures in core samples are most likely

induced by drilling or core removal and handling. Ma-

terial present near the tips of these fractures is a mix-

ture of clay and barite, apparently drilling mud that

was not removed prior to epoxy impregnation.

Mudstone Layer

The mudstone sample is composed primarily of clay-

size quartz and feldspar with subsidiary dolomite, clay

minerals, organic material, pyrite, and microfossils and

fossil fragments. Two sets of fractures are present with-

in the mudstone sample (Figure 5b). One set trends

east-northeast and is apparently drilling induced. One

set trends northwest and is mineralized and, thus, nat-

ural. No unequivocal evidence of a second set of min-

eralized fractures has been observed in any of the mud-

stone core examined for this study. Fracture fill in

Barnett Shale mudstone fractures is mostly calcite.

Other phases are developed locally, near composi-

tional anomalies in the host rock, or near fracture tips.

Changes in type, amount, and proportion of mineral-

ization are common near fracture tips in other clastic

rocks (Laubach, 2003).

Table 1. Summary of Fracture Parameters Observed in Each of the Four Cores Studied*

Well Name

Core Length

Examined (ft)

Number of Natural

Fractures (All Sealed)

Fracture Kinematic

Aperture (Minimum and

Maximum Values, mm)

Maximum

Observed Fracture

Height (cm)

Number of

Fracture Sets

2 T. P. Sims 110 74 in shale <0.05–0.265 81.0** 1 in shale, at least 3

in dolomitic layer

10 in concretions 0.05–2.15 17.0 Unknown

1 Blakely 121 14 in Forestburg <0.05–0.95 68.0 2 in Forestburg

1 in shale <0.05 3.2 1

8 in concretions <0.05–0.4 6.0 Unknown

MC-1 Johanson 13 0 in shale – – –

2 in concretions <1.00 1.5 Unknown

1 St. Clair C 23 3 in shale <0.05 9** 1

*Fracture aperture data are provided as maximum and minimum values. Kinematic aperture is the wall-to-wall distance across the fracture, including the sealed portionand is a measure of the extension accommodated by each fracture. Because apertures may have a power-law distribution, mean values are not reported. Maximumfracture heights are given. Those marked with double asterisks are lower estimates because the fracture continued out of the core. True fracture orientations areonly known for the T. P. Sims core, and these are discussed in the text, as are the details of fracture fill. The number of sets on the basis of relative orientation isgiven. The number of sets in concretions is unknown because of their highly variable geometry and isolated nature. Fracture occurrence is not listed by depth orfacies because the sampling bias for recording vertical fractures in vertical cores makes this information misleading.


The west-northwest–trending macrofracture set

in the mudstone layer has an atypically large assem-

blage of fracture-lining minerals: calcite, quartz, albite,

pyrite, barite, and dolomite (Figure 6). Albite and quartz

dominate at the fracture tips. Away from the fracture

tips, calcite is the dominant fracture-filling cement.

Papazis (2005) noted all these fracture cement types

(plus sphalerite), but not the occurrence of all six in a

single fracture. Quartz, which forms partial or com-

plete bridges, is less common than albite. The SEM-CL

imaging reveals complex zoning and shows the connec-

tion of albite and quartz cement with grains in matrix.

The SEM-CL imaging of calcitemineralization shows

faint zoning parallel to fracture walls in some places. It

could be growth zoning, but it is more likely to indicate

limited crack-seal texture, in which the fracture opened

Figure 3. Natural frac-tures in the T. P. Simscore sealed with calciteand arranged in en ech-elon arrays at (a) meterand (b) centimeter scale.(c) Broken fracture sur-face showing calcite min-eralization. Note thatsubtle changes in hostrock composition are re-flected in differences inthe character of cement.The numbers on the coreare depths in feet.

Gale et al. 611

in three or more small steps. Calcite formed after at

least some quartz. Single crystals of calcite fill that are

in optical continuity extend for severalmillimeters along

the fracture length, although some fibrous structures

are visible. Pyrite is present in large patches containing

micrometer-scale inclusions of albite and quartz. Pyrite

shows euhedral faces against calcite. Limited develop-

ment of pyrite hinders textural interpretation. Barite is

confined to the center of the fracture in dispersed small

patches, commonly greater than 10 mm in diameter, but

a few are up to 0.5 mm (0.02 in.) in diameter. Barite

is most commonly surrounded by albite and is rare in

calcite-filled areas of the fracture. Dolomite is relatively

rare and found in association with both calcite and albite.

Dolomite rhombohedra within calcite fracture fill are

late, and the crystal shape suggests that dolomite is re-

placing calcite instead of growing into fracture porosity.

The paragenetic sequence within the fracture is

complex, with evidence of synchronous growth of some

phases. Quartz and albite are partly synchronous and

early, forming syntaxial crystals that nucleated on grains

in the matrix. Some albite predates calcite; in calcite-

dominated segments of the fracture, albite forms par-

tial bridges, with gaps filled by calcite. At least some

Figure 4. Fracture-size data from T. P. Sims core. (a) Fracture aperture size distribution for all fractures. Fractures less than 0.05 mm(0.0019 in.) wide, our lower limit for core sample measurement, are nominally shown having an aperture of 0.03 mm (0.0011 in.).(b) Fracture heights arranged from largest to smallest, including truncated and true height values. (c) Length versus width plot for truefracture heights where heights are distinguished according to whether heights are constrained by a mechanical boundary. Fracturedata from the Blakely and St. Clair cores are also included on this plot. Nominal values for apertures below the measurement limitare 0.035 mm (0.0013 in.), so that they may be distinguished from the T. P. Sims data.

Figure 5. Rose diagrams showing fracture trends in the T. P. Sims core (a) from Hill (1992), used with permission from the GasTechnology Institute; (b) in the mudrock sample from this study; and (c) in the dolomitic sample from this study.


calcite predates pyrite, where the pyritemay be replacing

calcite. Barite postdates most albite, and because it is

confined to themiddle of the fracture fill, we interpret

it as a late phase.

Carbonate concretions, which locally can be sever-

al tens of centimeters in height, are developed through-

out the Barnett Shale. Concretions are commonlymore

fractured than the mudstones, but fractures terminate

within individual concretions. Fractures in concretions

typically have complex geometries andmultiple phases

of fill and are unlike fractures in the mudstones. Be-

cause they are local to individual concretions, these

fractures are not considered important with respect

to hydrocarbon production, and we did not study them

further.

Dolomitic Layer

The dolomitic sample comprises mostly ferroan dolo-

mite and calcite, butwith significant pyrite, phosphatic

material, and clay. Fossil fragments and microfossils

of several compositions are present, along with small

amounts of albite. This lithology is one of the thin coarse-

grained accumulations noted by Papazis (2005), specifi-

cally a ripple cross-laminated interval. Loucks and Ruppel

(2007) interpret these layers to have been starved ripples

formed by contour currents in deep water.

Three or more sets of fractures occur in the dolo-

mitic layer (Figures 5c, 7). Three compositional variants

(dominantly calcitic, dominantly dolomitic, and those

with highly variable cements) do not correspond strictly

to the three fracture sets. All northwest-trending frac-

tures are dominantly calcite, as is the corresponding

set in mudrock. Also present are two sets of roughly

north-south–trending fractures that are difficult to dif-

ferentiate. Similar fracture fills are present in both sets:

dolomite + calcite ± pyrite and quartz. In a couple of

fractures in the sample, pyrite is locally the dominant

cement. Crack-seal texture was observed in one of the

predominantly dolomitic north-south–trending frac-

tures (Figure 8). Where present, quartz forms partial

bridges with chaotic CL zoning.

Fracture-filling pyrite in the dolomitic sample con-

tains numerous micrometer-scale inclusions of calcite,

suggesting partial replacement of calcite by pyrite. Py-

rite growths fill the fracture and then continue into the

host rock, exceeding the width of the fracture where

dolomite + calcite ± quartz is the fracture fill. This

relationship also suggests that pyrite is replacing some

fracture-liningmineral (probably calcite) instead of grow-

ing into the fracture porosity.

The more westerly trending set seems to be youn-

ger, although timing relations are not definitive. In at

least one case, this set appears to reactivate parts of the

Figure 6. Images of fracture fill in the T. P. Sims mudrock sample. Six phases of mineralization (calcite, albite, pyrite, quartz, barite,and dolomite) are present in the fracture fill. Some phases are best differentiated in secondary electron image (right), some phases inbackscattered electron image (center), and some in element map (left). Element map is a false color combination of three grayscaleelement maps: red is Si, green is S, and blue is Ca. Phases are labeled albite (a), barite (b), calcite (c), dolomite (d), pyrite (p), andquartz (q).

Gale et al. 613

Figure 7. Cold-cathode CL, plane light, and EDS element map images of multiple fracture sets in the dolomitic layer. Early, middle, and late labels refer to the relative timing offractures. Phases are labeled as for Figure 6.

614

Natural

Fracturesinthe

BarnettShale

earlier set, contributing to the complexity of fracture

cement in the resulting composite fracture. Both sets of

north-south–trending fractures are cut by northwest-

trending fractures, establishing the north-south frac-

tures to be older than the northwest-trending fractures.

Extensive examination of the mudstone layer in

the T. P. Sims core using numerous imaging methods

failed to produce any evidence of the two early sets of

generally north-south–trending fractures seen in the do-

lomitic layer. One possible explanation is that because

the dolomitic layers consolidated prior to the mudstone,

they retain evidence of earlier fracturing events. Another

possibility is that the distribution of these fractures in

themudstone layers is such that they do not occur in the

size of sample we examined. This could be caused by

either low overall intensity or a high degree of clustering

with the sample in the study being outside of a cluster.

Fracture Characterization, Blakely Core

The Blakely core contains upper and lower Barnett

Shale, separated by the Forestburg limestone. Most nat-

ural fractures in this core are found in the Forestburg

interval, for example, at 7132 and 7134.25 ft (2173 and

2174.51 m) (Figure 9a, b, respectively), or are associ-

ated with concretions (Figure 9c). Only one natural

fracture was observed in the shale. Fractures in the

Forestburg interval are arranged in subvertical clus-

ters, terminating within the limestone. Two natural

fracture sets in the Forestburg limestone exist with

trends differing between 21 and 31j (Figure 9b). Thesemay be related to the two north-south fracture sets in

the dolomitic layer in the T. P. Sims core (Figure 5c).

Aperture and length data for fractures in the Forest-

burg limestone are plotted together with data from the

Figure 8. Backscattered electron image showing crack-seal texture within a fracture cutting dolomite-rich carbonate with aphosphatic nodule (P). Slivers of phosphatic nodule are preserved as inclusion trails within the fracture fill. The inclusion trailsdelineate incremental fracture growth steps. Slight changes in mineral chemistry in the dolomite fracture cement (D) also highlightcrack-seal texture. Crack-seal texture indicates this fracture opened by multiple events.

Gale et al. 615

T. P. Sims for comparison (Figure 4). Several fractures

in both cores have similar dimensions, but there are

also wider and longer fractures in the Forestburg in-

terval than in the Barnett Shale in the T. P. Sims core.

It is possible that more fractures are present in the

mudstone than are suggested by the limited sample

provided by this vertical well. Alternatively, fracturing

may have occurred preferentially in the Forestburg

limestone because it was more brittle than the sur-

rounding mudstone. Although the Barnett Shale is

considered to be relatively brittle in comparison with

other shales because of its low clay content, it is, nev-

ertheless, likely to be less brittle than the Forestburg

limestone.

Fracture Characterization, MC-1 Johanson Core

The Barnett Shale section in this core from close to the

Llano uplift is just 13 ft (4 m) thick. The core, which

is 2 in. (5 cm) in diameter, has parted along bedding

planes but is relatively well preserved. No natural frac-

tures were observed in the mudstone, which is locally

Figure 9. Fractures inthe Blakely core. (a) Frac-tures with splayed termi-nation in the Forestburgshale. (b) Two, nonpar-allel natural fracture setsare present in the Forest-burg shale. The sets arelabeled 1 and 2. In the slabview at 7134 ft (2174 m),set 2 is demonstrably theyounger set. In the otherviews, in the absence ofcrosscutting relationships,the sets are labeled on thebasis of relative orienta-tion. (c) Fractures associ-ated with a carbonate-richconcretion.


rich in skeletal debris. Two calcite-sealed fractures

approximately 1.5 cm (0.6 in.) tall and less than 1 mm

(0.04 in.) wide that are present in concretions do not

extend into the mudstone. Fracture intensity in this

location is apparently low, although if fractures are

clustered, the local intensity could be misleading.

Fracture Characterization, St. Clair Core

A Barnett Shale section 23 ft (7 m) thick at a depth

of 4973–4996 ft (1515–1522 m) is present in this

core from the Erath County. Three natural fractures

were observed in the mudstone, each being less than

0.05 mm (0.001 in.) wide and sealed with calcite. The

fractures terminate outside the core, so the heights of

9, 4, and 3.5 cm (3.5, 1.5, and 1.3 in.) are minimum

values (Figure 4c). The fractures are steeply dipping

and resemble those in the T. P Sims core, but the core

is not oriented, and the fracture orientations are there-

fore unknown.

Subcritical Crack Index Measurements

Representative load decay data from two of the Barnett

Shale tests in this study, for which subcritical indices

are included in parentheses, are shown (Figure 10).

The total time for each test is approximately 10 min.

Note that the ranges in load differ significantly be-

tween the two indices, but variations are smooth and

fit well to the behavior predicted by equation 3. To de-

termine the magnitude of the subcritical index from

equation 1, the load decay curves are numerically dif-

ferentiated to obtain the velocities. From a log-log plot

of velocity against load, the index, n, is given by the

slopes of the curves, independent of all the constants

in the equations given in the methods section of this

article (Figure 11).

Indices for all the specimens tested range from

109 to 326, with means of 276 ± 54 for the specimens

from 7692 ft (2344m), and 122 ± 20 for the specimen

from 7749 ft (2361m) (Table 2). The results for speci-

mens at a depth of 7692 ft (2344 m) are from tests on

different specimens. Data from the 7749-ft (2361-m)

depth are from multiple tests on the same specimen be-

cause other specimens failed in preparation. The range

of indices is near the high end of measurable values;

the specimens behave as almost perfectly brittle. High

indices indicate a rapid transition from zero propagation

to almost rupture-crack velocity as load increases by a

small amount (equation 1). The indices determined for

these shale samples are comparable to indices for dolo-

stones and chalk (Table 3), but are high relative to those

for sandstones, which have means of approximately 55

(Rijken, 2005).

Figure 10. Load decaycurves measured for twoof the shale specimens.Subcritical indices deter-mined for these tests areshown in parentheses.Behavior predicted byequation 3 is shown bythe solid red curves in theplots; the test data arepoints. Points and curvesare coincident, indicat-ing good agreement be-tween expected and actualbehavior. Arrows referto appropriate y (load)-axes for each of thecurves.

Gale et al. 617

DISCUSSION AND INTERPRETATION

Natural opening-mode fractures in the Barnett Shale

are most commonly narrow, sealed with calcite, and

present in en echelon arrays. The narrow fractures are

all sealed and cannot contribute to reservoir storage or

enhance permeability. Individual fractures have high

aspect ratios. The host rock has a high subcritical crack

index. These characteristics are also seen in fractures

in the Austin Chalk, a well-known fractured reservoir

(Gale, 2002) (Figure 12a, b). We consider the Austin

Chalk to be a good analog for the Barnett Shale with

respect to natural fracture patterns. It is similar in the

sense that the Barnett Shale consists of mudstones in-

terspersed with carbonate layers, and the Austin Chalk

comprises chalk-marl couplets. Both are fine-grained,

layered systems with low matrix permeability. More-

over, their mechanical rock properties are similar

(Table 3).

In the Austin Chalk, fracture aperture sizes fol-

low a power-law distribution, and commonly only the

largest fractures, above an 11-mm (0.43-in.) emergent

threshold, are open (Figure 12c). The emergent threshold

Table 2. Summary of Subcritical Crack Index Test Results forBarnett Shale in the T. P. Sims Core

Depth (ft) Specimen Index Average

7692 1-8B1 227

1-10B1 232

1-12A1 326

1-13B1 318 276 ± 54

7749 2-7B 145

2-7B3 109

2-7B4 111 122 ± 20

Figure 11. Log-log plotof velocity (vertical axes),numerically computedfrom equation 3, againstload (horizontal axes),for the specimens in Fig-ure 10. The slopes of thetwo curves are the sub-critical indices, shown inparentheses. Arrows referto appropriate axes forthe two different curves.

Table 3. Comparison of Mechanical Rock Properties for

Austin Chalk and Barnett Shale*

Lithology

Young’s Modulus

(Static) (GPa)

Poisson’s

Ratio

Subcritical

Crack Index

(in Air)

Barnett Shale 33.0** 0.2–0.3y 109–326**

Other shales 4.5–61.0yy 0.03–0.3yy No data

Austin Chalk 48.0yy 0.1–0.4yy 95–124z

Other chalks 25.6–65.0yy 0.24yy No data

*The subcritical crack indices for these lithologies are similarly high and arelarger than sandstone indices, which have a mean value of 55 (Rijken,2005). Young’s modulus for the Barnett Shale, determined from a samplefrom the T. P. Sims (33.0 GPa), lies within the range reported for othershales and chalks and is a little lower than that determined for AustinChalk. Poisson’s ratio is similar for all lithologies.

**Data are from this study.yData are from Hill (1992).yyData are from Rijken and Cooke (2001) and references therein.zData are from Holder et al. (2001).


Figure 12. (a, b) Similarities between fractures in Austin Chalk and Barnett Shale (image from Papazis [2005]). (c) Aperture sizes offractures measured in an Austin Chalk outcrop scanline with emergent threshold of 11 mm (0.43 in.) shown (size above whichfractures are open). The only open fractures are in a cluster at about 150 m (492 ft) along the scanline. (d, e) Open fractures from thelarge fracture cluster. Similar large fractures in widely spaced clusters may be present in the Barnett Shale.

Gale et al. 619

is the size above which fractures in a given population

are likely to retain porosity (Laubach, 2003). We have

not directly observed large open fractures in the Barnett

Shale, although we note that Simon (2005, p. 47, his

figure 31) reported partly open natural fractures in

an image log. We suggest here that fracture apertures

in the Barnett Shale may follow a power-law distribu-

tion where, without stimulation, only the largest frac-

tures are open to flow. In the Austin Chalk, the largest

fractures are at least 10 cm (4 in.) wide and are mostly

sealed, but they have openings up to 1 cm (0.4 in.) wide

(Figure 12d, e). Horizontal wells drilled in the Austin

Chalk exploit these open fracture clusters. By analogy,

horizontal wells drilled normal to natural fractures in

the Barnett Shale might intersect an open fracture clus-

ter. If the fractures are contained within the shale, then

this could be useful in enhancing permeability. They

could be problematic with respect to hydraulic fracture

treatments, however, because open natural fractures

can capture treatment fluids and prevent new fractures

from forming. If the large natural fractures connect to

water in the underlying Ellenburger Group, they could

be detrimental. The effect of drilling into an open, natu-

ral fracture cluster is therefore partly dependent on the

height of the fracture system and whether it connects

to the Ellenburger Group.

The maximum aperture of elastic fractures scales

with the smallest dimension normal to aperture, which

is generally the fracture height. In the case of the

Austin Chalk, mechanical layer thickness, which con-

trols height, can be several tens of meters. Mechanical

layer thickness has not yet been determined for the

Barnett Shale. The upper constraint is the entire thick-

ness of the formation, including the Forestburg lime-

stone (>300 ft [>92 m] in the thickest part). Alter-

natively, the upper and lower Barnett thicknesses may

provide an upper limit. These are on the order of 100–

250 ft (30–76m) thick, respectively. Internal carbonate-

rich layers provide smaller scale mechanical boundaries

for propagation of some fractures (Figure 9c), but not

for others (Figure 12b). Vertical persistence of frac-

tures is affected by the relative thicknesses of the frac-

turing layer and the bounding layers, together with the

size of the propagating fracture when it arrives at the

boundary.

The Forestburg limestone is approximately 38 ft

(12 m) thick in the vicinity of the Blakely well (Loucks

and Ruppel, 2007). Fractures could attain this height

before being constrained by the surrounding shale. At

a height of 12 m (39 ft) and a height/width aspect ratio

of 1000:1 (Figure 4c), fractures could grow to be 12 mm

(0.47 in.) wide. These fractures may retain significant

porosity and permeability. If this is the case, then al-

though the Forestburg is regarded as being a barrier for

hydraulic fractures (Hill, 1992), isolated, open, natural

fracture swarms might connect the upper and lower

Barnett shales if they are tapped into during hydraulic

fracture treatment.

Geomechanical modeling of growing fracture sys-

tems has shown the importance of the subcritical index

for controlling the degree of fracture clustering (Olson,

2004). Large indices are linked with strongly clustered

fractures. Because the subcritical index in the Barnett

Shale is large, we interpret the fractures to be strongly

clustered. Geomechanical models using high subcriti-

cal indices indicate that the spacing between clusters

may be two to three times the mechanical layer thick-

ness. For the largest fractures, a mechanical layer thick-

ness of the whole Barnett Shale might be appropriate.

Fracture spacing would then be between 600 and 900 ft

(184 and 276 m), a value comparable to Austin Chalk

cluster spacing,which is in excess of 250m(820 ft) (Gale,

2002). If cluster spacing is similar to that in the Austin

Chalk, then we predict that large open fractures will

be seen on horizontal well image logs, and evidence of

them should be present during drilling. They are un-

likely to be sampled in vertical core or on vertical well

image logs, however. If the mechanical layer thickness

is much smaller, then the maximum fracture aperture

will be smaller, and most fractures will probably be

sealed. Simon (2005) saw a marked northwest-oriented,

fastest azimuthal interval velocity around a well in the

Barnett Shale where fractures were seen in the image

log. If the fractureswere clustered, then Simon’s (2005)

inference that fractures outside the image volume add

to the fastest azimuthal interval velocity signal may be

correct.

Large natural fractures perpendicular to present-

day SHmax may be open, although the stress regime is

unfavorable. This is because fracture cement props the

fracture open, and cement that precipitated in the host

rock during or after fracturing renders the rock less

compliant and preserves the opening (Laubach et al.,

2004).

Why Natural Fractures Reactivate

Hydraulic fractures follow SHmax, until they encoun-

ter natural fractures. In the case of the Barnett Shale,

microseismic monitoring (Fisher et al., 2004; War-

pinski et al., 2005) has shown that the hydraulic frac-

tures stimulate the natural fractures to open, producing


a complex network (Figure 2). In many reservoirs

where hydraulic fractures encounter natural fractures,

the hydraulic fractures are blocked from further

propagation (Warpinski and Teufel, 1987), but this is

not a problem in the Barnett Shale (Warpinski et al.,

2005). We propose that natural fractures are not a bar-

rier because the tensile strength of the contact between

the calcite fracture fill and the shale wall rock is low.

The strength is low because calcite in the fracture is not

growing in crystallographic continuity with grains in

the wall rock. No crystal bond exists between the wall

rock and the calcite cement. This is in contrast to quartz

cement in fractures in tight-gas sandstones (Laubach,

2003). We know the fracture-host boundary in the Bar-

nett Shale fractures is weak because fracture-cement

fills in the cores are commonly parted from the wall

rock (Figures 3, 12). Although these cases are caused

by core-handling damage, we suggest that elevated fluid

pressures from a hydraulic fracture treatment cause

similar failure in the subsurface. Thus, when natural

fractures are encountered, they are opened up to fluids,

and they provide a network connected to the wellbore.

Natural fractures in this scenario are advantageous to

optimal stimulation of the well.

CONCLUSIONS

Natural, regionally developed, opening-mode fractures

in the Barnett Shale can reactivate during hydraulic frac-

ture treatments, providing a larger rock volume in con-

tact with the wellbore than would be the case with a

single hydraulic fracture. The natural fracture system

must therefore be characterized, and in-situ stress must

be determined for hydraulic-fracture treatments to be

optimized.

Although natural fractures observed in the Barnett

Shale are mostly sealed, they probably follow power-

law aperture size distributions, so that a few wide frac-

tures may be open. Barnett Shale has a high subcritical

crack index, indicating that fractures are highly clustered.

In the Fort Worth Basin, at least two sets of natural frac-

tures are present, an older north-south–trending set and

a dominant, younger, west-northwest–east-southeast–

trending set. Cements in the fractures are not generally

templated onto grains in the wall rock, and the frac-

tures act as planes of weakness that can reactivate. The

in-situ stress in the Fort Worth Basin is well known,

with SHmax trending northeast-southwest. SHmax trends

are less consistent to the west in the Permian Basin be-

cause this region is at the junction of several modern-

day stress province boundaries. When the Barnett Shale–

type play is extended outside the Fort Worth Basin, the

natural fracture system should be characterized, and in-

situ stress should be measured.

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AAGP B-Natural Fractures in The