barnett shale aapg
TRANSCRIPT
AUTHORS
Hank Zhao � 3906 Dunwich Drive, Richard-son, Texas 75082; [email protected]
Hanqing ‘‘Hank’’ Zhao is currently an indepen-dent geologist. In his more than 20-year career inoil and gas, he had been with Republic Energy,mainly working on Barnett Shale; Southwest-ern Energy, working on Fayetteville Shale; andDagang Geophysical Exploration and SouthwestPetroleum University in China. He received hisPh.D. in geology from the University of Wyo-ming, and his M.S. and B.S. degrees in petro-leum geology from Southwest Petroleum Uni-versity in China. His areas of interest are mainlyon the geological and geophysical aspects ofunconventional gas.
Natalie B. Givens � EnCana Oil & Gas (USA),Dallas, Texas 75240; [email protected]
Natalie is a geologist concentrating on uncon-ventional oil and gas plays. She received herM.S. degree in geology from the University ofKansas in 2006 and her B.S. degree in geologyfrom the Southern Methodist University in2000. Natalie spent 3 years with RepublicEnergy, Inc., prior to continuing her educationand obtaining her M.S. degree.
Brad Curtis � Republic Energy Inc., Dallas,Texas 75206; [email protected]
Brad Curtis is vice president of Geoscience andhas been with Republic Energy since 1990. Hereceived his B.S. degree in petroleum geologyfrom Midwestern State University in 1983 andthen worked for Expando Oil Co. in WichitaFalls, generating prospects in the Fort Worthand East Texas basins.
ACKNOWLEDGEMENTS
We thank Republic Energy for the support of thispublication and EnCana Oil & Gas (USA) forproviding gas heating value data. We thankRichard M. Pollastro (U.S. Geological Survey,Denver), Daniel M. Jarvie (Humble GeochemicalServices), and Kent A. Bowker for their detailedand helpful comments and suggestions, whichimproved the final draft. We thank Dan Steward(Republic Energy) and Robert Ehrlich for theinitial review and Ronald Hill (U.S. GeologicalSurvey, Denver) for editing the special issue.
Thermal maturity of theBarnett Shale determinedfrom well-log analysisHank Zhao, Natalie B. Givens, and Brad Curtis
ABSTRACT
Intensive development with large-scale fracturing treatments has
made the Barnett Shale play (Newark East field) in the Fort Worth
Basin the largest shale-gas field in theworld. TheMississippian Barnett
Shale is an organic-rich, self-sourced reservoir rock. Thermal matu-
rity, thickness, and total organic carbon are the most important geo-
logical factors for commercial gas production from this shale forma-
tion. The log-derived thermal-maturity index (MI) has beendeveloped
in an effort to better understand and predict hydrocarbon phases
across the basin. Maturity index was calculated using three types
of open-hole logs: neutron porosity, deep resistivity, and density
porosity (or bulk density). The derivation of MI is based on the hy-
potheses that shale gas is generated and stored locally without ap-
parent migration from outside sources, and that the water saturation
and the density of generated hydrocarbons decrease with an increase
in thermal maturity. Maturity index correlates well with initial
gas:oil ratios (GOR) from well production data. Based on this cor-
relation, an empirical relationship has been demonstrated for the
Fort Worth Basin. This method is useful in understanding the
thermal-maturity levels of Barnett Shale source rock in the gas-
generationwindow.MappingMI, GOR, and gas heating value from
hundreds of wells identifies the various maturity stages and areas of
Barnett Shale that generate oil, condensate, wet gas, or dry gas in
the Fort Worth Basin.
INTRODUCTION
By June 2006, Newark East field (Barnett Shale) had become the
largest shale-gas field of its kind in the world in areal extent (6000mi2;
15,500 km2), daily rate (1.97 bcf of gas and 6000 bbl of oil or con-
densate), and cumulative production (2.2 tcf of gas and 7.5 million bbl
of condensate or oil). In the field, the Barnett Shale produces gas
AAPG Bulletin, v. 91, no. 4 (April 2007), pp. 535–549 535
Copyright #2007. The American Association of Petroleum Geologists. All rights reserved.
Manuscript received June 1, 2006; provisional acceptance August 31, 2006; revised manuscript receivedOctober 18, 2006; final acceptance October 27, 2006.
DOI:10.1306/10270606060
with some oil or condensate only after a hydraulic frac-
turing treatment, because of its low permeability (less
than 0.003 md). Historically, the average gas reserve
per well has doubled or tripled because of technologi-
cal improvement in drilling (horizontal) and comple-
tion (increasing sizes of fracturing treatment; Bowker,
2003; Givens and Zhao, 2004). A complete geologi-
cal, geochemical, and production review on the Barnett
Shale has been accomplished by Montgomery (2004)
and Montgomery et al. (2005).
Productivity of individual Barnett Shale wells is
geologically related to the thermal maturity, total or-
ganic carbon (TOC, defined as the remaining insoluble
solid organic matter and generated soluble bitumen),
and the thickness of the shale. The hydrocarbon (de-
fined as the generated and movable oil and gas in the
shale) molecule’s size is linked to the degree of thermal
maturity; that is, the greater the degree of thermal mat-
uration, the smaller the hydrocarbon molecule’s size
(methane is the smallest). Because of the low perme-
ability and small pore throats in shale, gas mobility
through tight shale matrix is increased for gas with a
higher percentage of methane. The Barnett Shale is
both the source and reservoir rock for the gas in place.
Unlike conventional gas reservoirs, there is no appar-
ent process of gas accumulation or secondary migration
from outside sources for shale gas. Typically, the ther-
mal maturity of source rocks is determined by mea-
suring vitrinite reflectance. Other methods employed
include anhydrous pyrolysis, smectite-to-illite transition
of smectite and illite mixed-layer clay through x-ray
powder diffraction, aromaticity ratio of organicmatter
from nuclear magnetic resonance, and color alteration
of spores or conodonts. For the Barnett Shale in the Fort
Worth Basin, a systematic study of the thermalmaturi-
ty has been completed using vitrinite reflectance (Ro)
(Jarvie et al., 2001, 2007; Pollastro, 2003; Pollastro et al.,
2003, 2004).
Studying shale source rocks using open-hole wire-
line logs has a long history. The potential of shale as
source or reservoir rock was evaluated (King and Fertl,
1979; Meyer and Nederlof, 1984; Fertl et al., 1988)
through gamma-spectra log, resistivity, and bulk den-
sity logs. The TOC of source rocks was estimated using
sonic and resistivity logs (Passey et al., 1990). The gas
window of regional shale formations as source rocks
and their associated anomalous pressure regimes have
been delineated by the analysis of sonic logs in Rocky
Mountain Laramide basins (Surdam et al., 1994; Sur-
dam et al., 1997; Zhao, 1996). Using various well logs,
Guidry and Walsh (1993) calculated mineral compo-
nent volumes, porosity, and hydrocarbon saturation for
theDevonian shale (gas shale) in theAppalachianBasin.
This article focuses on the following aspects: (1) es-
tablishing a maturity index (MI) from analysis of neu-
tron, induction, and bulk density (or porosity) logs and
explaining its petrophysical meaning; (2) correlating
MI with the initial gas:oil ratio (GOR) to scale the lev-
els of thermal maturity in the gas window of the Bar-
nett Shale; and (3) determining the areal boundaries of
defined thermal-maturity levels and hydrocarbon phases
(oil, condensate, wet gas, or dry gas) in the associated
areas through mapping MIs and GORs in the basin.
Determination and delineation of the areas with differ-
ent hydrocarbon phases closely associated with thermal-
maturity levels in the gas window have a practical im-
portance in the exploration and development of this
gas shale. With this importance in mind, this work was
undertaken. It has helped us to quickly estimate the
thermal-maturity levels of the shale and predict hydro-
carbon phases such as oil, condensate, wet gas, or dry gas
during the field expansion. When the MI is well cali-
bratedwith actual and reliable production data (GORs),
this method is faster and more readily available than
lab analysis of rock samples (core or cuttings). The Bar-
nett Shale in the Fort Worth Basin has a complete hy-
drocarbon maturity spectrum from oil to dry gas, which
provides a unique advantage for studying thermal ma-
turity from log responses and their relationship to the
phases of produced hydrocarbons for a specific well or
basin. This complete maturity spectrum commonly does
not exist for shale sources in most of the other basins.
GEOLOGICAL SETTING
The Fort Worth Basin is a Paleozoic foreland basin de-
fined by the Ouachita thrust and fold belt to the east,
Muenster (thrust) arch to the northeast, Red River arch
to the north, Bend arch to the west, and the Llano uplift
to the south (Wermund and Jenkins, 1968). A general-
ized structure on the base of the Barnett Shale (equiva-
lently on top of Viola in the eastern part of the basin or
on top of Ellenburger in the west) was completed using
481 well data points throughout the basin (Figure 1).
Within the basin, the Mississippian Barnett Shale sits
directly on the Ordovician Viola Limestone or Ellenbur-
ger Limestone, with a major unconformity in between.
The Pennsylvanian Marble Falls Limestone rests on the
Barnett Shale (Figure 2). The Barnett Shale was depos-
ited on a marine shelf on the southwestern flank of
southern Oklahoma aulacogen, which was subsiding as
536 Barnett Shale Thermal Maturity from Log Analysis
a result of the middle or late Mississippian collision of
the North American plate with the South American
plate (Flippin, 1982; Henry, 1982). The Ouachita thrust
and fold belt is the final remnant of this collision. In the
northeastern part of the basin, the Forestburg lime-
stone separates the shale into minor upper and major
lower Barnett Shale intervals. The upper Barnett Shale
is almost uniformly 60–70 ft (18–21m) thick through-
out the northeastern part of the basin. In the remaining
area of the basin, no differentiation exists between the
upper and lower Barnett Shale because of the disap-
pearance of the Forestburg limestone. The gross thick-
ness of lower Barnett ranges from more than 600 ft
(182 m) in the northeast near the Muenster arch to less
than 50 ft (15 m) on the Bend arch in the western part
of the basin (Figure 3). The increased thickness near
the Muenster arch is caused by the interstratification of
shale, limy shale, and lime beds of various thicknesses.
Figure 1. Regional geology and general structure on the base of the Barnett Shale, which is equivalent to the top of the Ellenburgeror Viola limestone, in the Fort Worth Basin. The contour interval is 1000 ft (305 m). The current (2006) outline of the Newark Eastfield (Barnett Shale) is a red line.
Zhao et al. 537
The geological characteristics of the Barnett Shale
were summarized (Bowker, 2003; Montgomery, 2004;
Montgomery et al., 2005) and compared with other sim-
ilar gas-producing shales (Hill and Nelson, 2000; Curtis,
2002). The Barnett Shale is a subtly heterogeneous
rock in both mineral composition and physical proper-
ties, includingmatrix porosity, permeability, andmicro-
fractures. X-ray powder diffraction analyses of 35 cut-
tings samples from three wells in Wise and Denton
counties give the following shale composition by weight:
45–55% silts (consist of mostly quartz and some pla-
gioclase); 15–25% carbonates (mostly calcite, some
dolomite, and siderite); 20–35% clayminerals; and 2–
6% pyrite. Total organic carbon ranges from 3.5 to
4.5% by weight (Hill and Nelson, 2000; Jarvie et al.,
2001), which is equal to 7–9% by volume because the
density of the organic matter is about half that of min-
erals. The organic matter in the shale is type II kerogen
(Jarvie et al., 2001, 2007, remaining insoluble solid
organic matter), which can generate both oil and gas
Figure 2. GeneralizedPaleozoic stratigraphiccolumn of the Fort WorthBasin. The expanded sec-tion shows a more de-tailed interpretation ofMississippian and Ordo-vician stratigraphy. Modi-fied from Pollastro et al.(2003) and Montgomeryet al. (2005).
538 Barnett Shale Thermal Maturity from Log Analysis
directly (then oil can be thermally cracked and become
gas). Porosity of the shale ranges from 3.8 to 6.0%, and
its reservoir permeability is, on average, 0.15–2.5 md(Lancaster et al., 1992; Kuuskraa et al., 1998). Because
of differential compaction, the shale is generally tight-
er (low in permeability and porosity) on residually
(nose) and structurally (bump) high areas of the Viola
or Ellenburger Limestone; the opposite occurs in low
areas (Zhao, 2004). Shale with higher porosity com-
monly has much higher gas productivity because the
produced gas is mainly free gas, stored in micropores
at current reservoir pressure (1000–3000 psi; 6.89–
20.68 MPa). Desorbed gas from the surface of organic
matter is believed to be a very small percentage of the
gas produced at the current stage of development.
THERMAL-MATURITY INDEX FROM LOG ANALYSIS
To measure the thermal maturity of the Barnett Shale,
an MI was established by analyzing several log curves,
including bulk density, neutron, and deep resistivity.
Figure 3. General isopach of the Barnett Shale (only lower Barnett Shale where upper and lower are differentiated) in the FortWorth Basin. The contour interval is 50 ft (15 m).
Zhao et al. 539
A typical well-log suite in the field includes gamma-
ray, bulk density or density-porosity (matrix density of
2.71 g/cm3), neutron-porosity, photoelectric absorp-
tion index (Pe), and induction resistivity, as shown in
Figure 4. The Republic Energy 7 T. H. Zorns unit has
slightly lower neutron porosity and higher deep resis-
tivity than the Henry Energy 1 Williams unit. These
subtle differences are mainly attributed to the levels of
gas saturation and the size of hydrocarbon (oil and gas)
molecules in the shale, both of which are directly re-
lated to the levels of shale thermal maturity. The MI
from the log curves has been statistically calculated on the
basis of several reasonable assumptions. (1) The Barnett
Shale is both source and reservoir rock for the gas
currently within the shale; therefore, no measurable
secondary gasmigration or accumulation into the shale
has occurred, although much gas and oil that gener-
ated from the shale had been moved out of the shale
through its primary migration. (2) Gas saturation lev-
els in the shale generally increase with the degree of
the thermal maturity, which is affected by heat levels
and amount of time at various heat levels. (3) During
Figure 4. Cross section of the Barnett Shale interval showing typical open-hole well logs (depth in feet). The 7 T. H. Zorns unit hasslightly lower neutron porosity and higher deep resistivity than the 1 Williams unit. The maturity index of the shale in 7 T. H. Zornsunit is 6.5, and its initial GOR is 1610 mscf/bbl. The maturity index of the shale in the 1 Williams unit is 5.3, and the GOR from anearby well is 126 mscf/bbl (1 Williams unit is the older well, which was drilled and logged through the Barnett Shale, but does notproduce from the Barnett Shale).
540 Barnett Shale Thermal Maturity from Log Analysis
the progressive process of hydrocarbon generation, the
water saturation of shale generally decreases through
expelling free water and water from mineral transfor-
mation (smectite to illite) caused by periodically high
pressure and increasing temperature. Besides, hydrocar-
bon chains in organic matter and hydrocarbons (gener-
ated oil and gas) become shorter in further generation and
thermal crack. As a result, the content of elemental hy-
drogen in the shale decreases as thermal maturity in-
creases because both hydrocarbons and water are ex-
pelled from the shale during the maturation process.
To calculate the gas saturation and the MI, shale
matrix porosity must first be estimated for each well
used. Lab measurements of the effective porosity and
total porosity from core samples of Mitchell Energy 2
T. P. Sims located in southeastWise County (Lancaster
et al., 1992) are listed in Table 1. The average effective
porosity (whole core) is 3.8%, and the average matrix
total porosity (crushed core) is 5.4%. The average po-
rosity from the bulk density-porosity curve (2.71 g/cm3
matrix) corresponding to the depths of these measured
core samples is 12.7%. The average difference between
the log porosity and total core (crushed) porosity is 7.1%.
The average difference between the effective (whole)
core porosity and the log porosity is 8.93%. Therefore,
the total porosity values of the shalewere approximated
by deducting 7.1% from the log curve porosity, and the
effectivematrix porosity of the shale were approximated
by deducting 9% from the log curve. A cutoff of 9% log
porosity was used to filter out any samples less than
9% in bulk density porosity (or higher than 2.556 g/cm3
on bulk density curve) to get the effective matrix po-
rosity of the shale. Shale with less than 9% on the po-
rosity curve is non-gas shale because of being either
too limy (limestone layers or concretions) or too low
in TOC. The total matrix porosity acquired by log po-
rosity minus 7.1% was used in the calculation of water
saturation.
Hydrocarbon saturation is estimated using a simple
Archie equation (Archie, 1950). In the Barnett Shale,
TOC is approximately 7–9% by volume (3.5–4.5% by
weight, Hill andNelson, 2000; Jarvie et al., 2001). This
represents a small percentage relative to the total vol-
ume of shale sediment grains. The remaining hydrocar-
bon (generated) in the shale is mostly gas, with smaller
sizes of molecules and less surface tension than those
of liquid hydrocarbon. A simple test was performed on
a Barnett Shale core sample from the Mitchell Energy
1 Blakely well in southeastern Wise County. When a
drop of water was put on a new surface (without sur-
face contamination) of the sample, the water quickly
spread and had a very low contact angle on the sample
surface. This indicates that the Barnett Shale, at least in
the area of the gas window, is mostly water wet. A
water-wet rock has anion and cation transport under an
electric field. Thus, the Archie equation is applicable to
estimate water saturation (Swi) for the Barnett Shale.
The following is an application of the Archie equation.
Swi ¼Rw
fmd9i
Rt
!1=2
ð1Þ
where Rw is the formation water resistivity in ohm
meters; fd9i is an estimated matrix porosity from the
density log porosity (fd) by (fd9i = fd � 9%); R t is the
deep formation resistivity; andm is the exponent factor
of rock cementation.
Table 1. Porosity Cutoffs from the Difference between Log Density Porosity and Measured Porosity
Sample
Depth (ft)
Porosity*
(Whole Core, fw)Porosity*
(Crushed, fc)Log porosity
(fL)Cutoff for Effective
Porosity (fL � fw)Cutoff for Matrix
Porosity (fL � fc)
7656 3.5 5.4 11.4 7.9 6.0
7676 5.0 5.3 13.1 8.1 7.8
7680 3.7 5.8 14.6 10.9 8.8
7690 4.8 6.3 12.0 7.2 5.7
7701 6.4 5.9 10.5 4.1 4.6
7716 3.6 4.8 15.0 11.4 10.2
7724 3.3 5.7 12.0 8.7 6.3
7738 2.7 4.0 12.8 10.1 6.1
7740 1.5 5.3 13.5 12.0 8.2
Average (%) 3.8 5.4 12.7 8.93 7.1
*From Lancaster et al., 1992.
Zhao et al. 541
The cementation exponent factor (m) in Archie’s
equation for mudrock or chalk was identified as about
2.0 from the relationship between the measured po-
rosity and formation factors (Focke and Munn, 1987).
The matrix of Barnett Shale is similar to mudrock or
chalk. Some fractures (vertical) and streaks or cleavages
(horizontal) exist in the shale. The existence of frac-
tures and streaks will lower the value of the cementa-
tion exponent factor (Aguilera, 1974), but the fracture
porosity is a very small percentage of the total shale
porosity. Therefore, the cementation factor for the Bar-
nett Shale was chosen to be 1.9 as an approximation
in this study.
The chemical analysis of 42 water samples was
used to calculate the average equivalent NaCl concen-
tration using conversion factors fromDunlap andHaw-
thorne (1951). The salinity of produced water from
Barnett Shale wells mostly represents that of the wa-
ter from the Viola Limestone or Ellenburger (porous)
Limestone immediately below the Barnett Shale (Bow-
ker, 2003). The average equivalent NaCl concentra-
tion of water from the 42 Barnett Shale wells is about
85,000 ppm. The salinity of the true Barnett Shale
water is most likely higher than 85,000 ppm because
of the less possible effect by recharging ground surface
water.At average reservoir temperatures of about 200jF(93jC) in the field, a water resistivity of 0.03 ohm m
was chosen to be used on the basis of the chart of NaCl
concentration versus solution resistivity (Schlumberger,
1989). In addition, considering the anions and cations
in clay minerals of the shale, for the same equivalent
NaCl concentration from measurement of produced
water, water resistivity in the shale reservoir conditions
should be even lower than that in the Viola or Ellen-
burger limestones.
The water saturation was calculated from log curves
on the basis of the previously mentioned parameters
and log porosity cutoffs. The final samples of log data
were also filtered by a water saturation of 75%. Only
the log interval with water saturation lower than 75%
(or hydrocarbon saturation >25%) is counted as a pos-
sible pay interval; intervals withwater saturation higher
than or equal to 75% are filtered out. Depending on
the variation of total matrix porosity (3–7%), any in-
terval with resistivity between 11 and 60 ohm m may
be filtered out. Any interval with less than 10 ohm m
of deep resistivity will be filtered out by the water satu-
ration cutoff (<75%).
Based on these assumptions, the estimation of the
shale matrix porosity from bulk density log, and hy-
drocarbon saturation (1 � Sw75i) frombulk density and
deep resistivity logs, a statistical equation was formu-
lated and tested to acquire an index number reflecting
the petrophysical changes in the shale with increasing
thermal maturity. An equation for MI was established
as follows:
MI ¼XNi¼1
N
fn9ið1� Sw75iÞ1=2ð2Þ
in whichN is the total number of data samples selected
only if the log density porosity is 9% or higher andwater
saturation is 75% or lower at each sample depth; fn9iis the neutron porosity for the samples selected only
when log density porosity is 9% or higher at each sam-
ple depth; and Sw75i is the water saturation for the sam-
ples selected only when the log porosity is 9% or higher
and the water saturation is 75% or lower at each sample
depth.
Digital log data samples used for the calculation
were selected only if the raw log data at a depth have a
density porosity (2.71 g/cm3 matrix) of 9% or higher
and water saturation of 75% or lower. The reasoning
behind this originates from the hypothesis that only the
shale with greater than minimum porosity (9% cutoff)
and minimum hydrocarbon saturation (25%) qualifies
as source and reservoir rock with minimum effect from
lithological variation. The MI is an average number for
the selected digital log data samples covering the Barnett
Shale interval (or lower Barnett if the Forestburg lime-
stone exists) in each well, so it is not affected by the
variation of gross thickness. The neutron porosity has a
greater effect on the MI than the hydrocarbon satura-
tion in the equation because of the square root applied
to the hydrocarbon saturation (1 � Sw75i), which is in-
versely related toMI. The lower neutron value (fn9i) rep-resents higher gas saturation, shorter chains of hydro-
carbon, and less water in the shale, which reflects higher
maturity. High hydrocarbon saturation (1 � Sw75i) with
low neutron values represents higher gas saturation and
higher thermal maturity, whereas high hydrocarbon
saturation (1 � Sw75i) with high neutron values rep-
resents lower gas saturation and lower maturity.
The neutron log is designed to detect the density of
elemental hydrogen in rocks. During the process of ther-
mal hydrocarbon generation, oil and gas are expelled out
of the Barnett Shale, and a part of the original interstitial
water is also expelled and replaced by generated hydro-
carbons (oil and gas). A part of the structural water in
the clay minerals is expelled after becoming free water
during the transformation of the clay minerals. Liquid
542 Barnett Shale Thermal Maturity from Log Analysis
hydrocarbons (oil) have a much higher hydrogen density
(number of elemental hydrogen per unit volume) than
gas hydrocarbons.Wet gas with a high percentage of C2+
(relative density to air >1.04 at 14.7 psi [101 kPa] and
60jF [15jC]) has a higher hydrogen density than dry gas
with a very low percentage of C2+ (mostly methane C1,
relative density to air = 0.554 at 14.7 psi [101 kPa] and
60jF [15jC]). Theneutron-porosity readings of the shalewill vary depending on the stage of thermal maturation
present in the well. In the oil-generation window, the
decrease in neutron porosity is subtle and small; in the
gas-generation window, the decrease in neutron porosity
is easily detectedbecauseof themuch lower density of gas
than that of oil and because of the continuous decrease in
density and elemental hydrogen from wet to dry gas.
A specific computer program was developed for
the calculation of the MI and other petrophysical pa-
rameters. The software takes raw log data in log-ASCII-
standard (LAS) format and with sample rates of every
0.5 ft (0.15 m). The top and base of the Barnett Shale
(using a lower Barnett Shale interval if the upper and
lower are separated) are used as input. A total of 184wells
widely dispersed across the basin were used in the cal-
culation. All these wells have three types of log curves
run through the Barnett Shale interval (or lower Barnett
interval where separate). Results from the eight selected
wells arranged by their locations from the northwest to
the southeast of the basin are listed in Table 2.
Several factors affecting the MI are density poros-
ity, reliability of old logs (mainly logged in the 1960s
and 1970s), and log calibration. When average density
porosity filtered by 9% is greater than 11%, the variation
in average porosity has a very slight effect on the MI.
However, when the average density porosity filtered by
9% is less than 11%, the MI will be slightly larger be-
cause of the increase in water saturation in the tighter
shale. A fewwells with average density porosity between
9 and 10% on log curves were not used because either
the shale is too tight or the logging tool (older logs) was
poorly calibrated. In addition, some neutron logs from
the 1970swith abnormally high or low readings relative
to many nearby wells were not used in the analysis.
INITIAL GAS:OIL RATIOS VERSUSMATURITY INDEX
The initial GOR is acquired by dividing the cumula-
tive gas production by the cumulative oil or conden-
sate production of a well in the first full month. The
initial GOR represents the more original property of
hydrocarbons in the shale reservoir. With production
continuing, a decrease in reservoir pressure causes a
separation of liquid and gas within reservoirs. Gas:oil
ratios of a well gradually increase because of a faster
decline of condensate (or oil) relative to gas. This is
commonly seen in production decline curves of Barnett
Shale wells. To keep GOR values shorter in this article,
gas volume is expressed in thousand cubic feet per barrel
(mscf/bbl at standard surface condition of 14.7 psia
[101 kPa] and 60jF [15jC]). The values of the initial
GOR throughout the Fort Worth Basin range from 1
to 10,000 mscf/bbl. For conventional reservoirs, the
variation in GOR may only reflect the gravity separa-
tion during secondary migration and accumulation. For
the Barnett Shale, the initial GOR generally reflects the
thermal maturity of the shale at well locations because
it is assumed that no apparent lateral migration and
accumulation of hydrocarbons occurred into the shale.
Some of the initial GORs are listed in Table 2 and
are correlated with MI values of the wells or nearby
wells. Initial GORs increase as MI increases. For some
Table 2. Comparison between Maturity Index and GOR for Selected Wells
Operator Well No. Lease County Maturity Index GOR (mscf/bbl)
Republic Energy 1C Benson Montague 4.2 1.0*
Earth Science 2 Annie Heard Est. Montague 4.4 1.1**
Republic Energy 1 Crystelle Waggoner Wise 5.4 24
Republic Energy 2 Cocanougher 287 Wise 5.8 40
Mitchell Energy 2 Thomas P. Sims Wise 6.0 171
Republic Energy 2 Barkley Wise 7.0 1044
Republic Energy 1 Blair Tarrant 7.1 4460
Chevron 1 Mildred Atlas Johnson 9.6 DG (dry gas)
*GOR from nearby well Dallas Production 1 Swint.**GOR from nearby well Stone J. G. 1 Silver.
Zhao et al. 543
wells, either MI or GOR was available. In these cases,
the MI or GOR from the closest nearby well was used.
When a well produced less than one barrel of oil or
condensate in the first month, one barrel was used in
the calculation of GOR. The wells with no oil or con-
densate production from the Barnett Shale are marked
with DG (dry gas).
A total of 44 wells, where both the MI and initial
GOR could be calculated, were used in plotting a cor-
relation chart with a 10-based logarithmic scale for ini-
tial GOR and with a linear scale for MI (Figure 5). A
linear relationship exists between the MIs and the cor-
responding GORs on these scales of coordinates. The
curve fit equation from the correlation is MI = 0.373
log(GOR) + 4.452. The correlation coefficient (R2) is
0.85, which means that MI and log(GOR) are related
fairly well. The statistical linear relationship between
the MI and log(GOR) is caused by the remaining hy-
drocarbon (oil, condensate, and gas) locally generated
in the shale and without large lateral migration. At the
high end of the correlation, data points are more scat-
tered because of the inaccuracy of reporting a small
amount of condensate from the wells.
The good correlation between MI and log(GOR)
provides a tool for delineating the thermal maturity of
the Barnett Shale in the Fort Worth Basin. As the ther-
malmaturity progresses, MI increases from 4.0 to 9.0
in the Barnett Shale. Several maturity levels can be
established with increasing GOR and MI. Generally,
when MI is 5.0 or less (GOR < 10 mscf/bbl), the shale
is within the oil-generation window, and mostly oil
with some dissolved gas is produced. When the MI is
between 5.0 and 6.0 and the GOR is between 10 and
100 mscf/bbl, the shale is at an early stage of gas gen-
eration whenwet gas andmost condensate are produced.
At an MI between 6.0 and 7.0 and a GOR between 100
and 1000 mscf/bbl, the shale is at a middle stage of gas
generation when mostly wet gas with some condensate
is produced. When MI is above 7.0 and GOR is above
1000 mscf/bbl, the shale is at a late stage of gas genera-
tion when mostly dry gas is produced. As the thermal
maturity progresses to the late stage of gas genera-
tion, the gas heating value falls as low as approximately
1000 Btu/scf because produced gas consists of more
than 96% methane and a minor amount of nonhydro-
carbon gases (mostly CO2 and N2).
THERMAL MATURITY OF THE BARNETT SHALE
Maturity indices calculated from the 184 well logs are
plotted on the map of Figure 6. A thermally mature
area with an MI greater than 7.0 is identified over most
of the Tarrant and Johnson counties. The onset of the
thermal gas-generation window is defined by an MI of
greater than 5.0 (Figure 6). The total area of the shale
within the gas-generation window encompasses about
6000mi2 (15,500 km2) inmore than 10 counties. Areas
Figure 5. Correlationbetween the MI in linearscale and the initial GORin logarithmic scale. Fourthermal-maturity levelsand their correspondingtypes of produced hydro-carbons are indicated.
544 Barnett Shale Thermal Maturity from Log Analysis
with an MI less than 5.0 initially produce oil with some
dissolved gas. Areas having an MI between 5.0 and 6.0
likely produce both wet gas and oil (or condensate).
Areas having anMI between 6.0 and 7.0 likely produce
wet gas with a small amount of condensate. Dry gas
without any condensate is expected in areas with an
MI greater than 7.0. An anomalously low MI occurs
in southern Parker County, as shown in Figure 6. Cur-
rently, there is no explanation for this anomaly.
Gas:oil ratios from 210 Barnett Shale gas-producing
wells were mapped throughout the basin (Figure 7).
The pattern established from the contouring GOR is
Figure 6. Pattern of the thermal maturity from log analysis. The MI for each well is marked beside the well symbol. Eight wells andtheir MIs from 4.2 to 9.6 on the line AA0 are listed in Table 2. The contour interval is 0.5 in MI. The area less than 5.0 is mainly for oil;the area between 5.0 and 6.0 is mainly for both wet gas and condensate (or oil); the area between 6.0 and 7.0 is for wet gas with alittle condensate; the area over 7.0 is for dry gas.
Zhao et al. 545
found to be very similar to that from the contouring
MI. As with MI, the areas with the highest GORs
(above 1000 mscf/bbl) are located mostly within Tar-
rant and Johnson counties. Areas with GOR less than
10 mscf/bbl produce oil, whereas areas with GOR be-
tween 10 and 100mscf/bbl contain both wet gas and oil
(or condensate). Similarly, areas with GOR between
100 and 1000 mscf/bbl contain wet gas and minor con-
densate. Dry gas without condensate is likely found in
the areas with a GOR greater than 1000 mscf/bbl.
Gas heating value measured with British thermal
units per standard cubic foot can be used as an indicator
Figure 7. Contour pattern of the initial GOR based on production from Barnett Shale wells. The GOR for each well is marked besidethe well symbol in units of thousand cubic feet per barrel. The contour interval is one unit of log(GOR). Most of the wells in Tarrant,Johnson, and Hill counties produce only dry gas, so there are no GOR values (marked as DG) on the map for these counties. Theeight wells and their GORs from 1.0 to 9700 mscf/bbl on the line AA0 are listed in Table 2.
546 Barnett Shale Thermal Maturity from Log Analysis
of the shale thermal maturity if nonhydrocarbon gas
content (N2 and CO2) is small and generally stable.
Most of the Barnett Shale wells have about 2% N2 and
less than 1% CO2 in produced gas. Gas heating values
decreasewith the decrease in gas hydrocarbonmolecule
size. Among the various gas hydrocarbons, methane
has the lowest heating value, which is 1010 Btu/scf.
With the thermal maturity of the shale increasing, the
percentage of methane in the gas increases. Therefore,
the areas with low gas heating values generally indicate
high thermal maturity in the shale. Gas heating values
from 68 Barnett Shale wells are mapped for the basin
(Figure 8). Areas with low gas heating values (about
1000 Btu/scf dry gas) are mainly in Tarrant, Johnson,
Figure 8. Contour pattern of gas heating values (British thermal units per cubic foot) from Barnett Shale gas. The contour lines inHill and Bosque counties are estimated because of a lack of wells. The contour interval is 1000 Btu/scf.
Zhao et al. 547
western Dallas, and northwestern Hill counties. The
areas with high Btu values (about 1200 Btu/scf, wet gas
and oil) are in Parker, Hood, Jack, Palo Pinto, northern
Wise, and northwestern Denton counties.
Generally, the most favorable areas for Barnett
Shale gas production (sweet spots) are those with high
thermal maturity, greater effective thickness, higher ma-
trix porosity, and away from major faults and away
from areas with porous and wet Viola Limestone or
Ellenburger Limestone at the base. If all other factors are
the same, wells in areas with higher thermal maturity
will have better gas productivity and higher gas reserve
than those in an area with lower maturity in the gas-
generationwindow.Mostwells in Tarrant and Johnson
counties are examples of wells with high gas produc-
tivity and reserve.
CONCLUSIONS
Thermal maturity is the primary geological factor in
exploration and development for the Barnett Shale gas
of the Fort Worth Basin; thickness and TOC are im-
portant secondary geological factors. A log-derived MI
of the shale is a useful indicator of thermal maturity
and hydrocarbon phase because the Barnett Shale is a
self-sourced reservoir and has a complete maturity
spectrum from oil to dry gas. The Barnett Shale con-
tains mainly type II kerogen, and its thermal maturity
ranges from oil to dry gas. This provides an ideal op-
portunity formaturity studies from open-hole wire-line
logs and for their correlation with GOR. Good empir-
ical correlations exist between MI and GOR, further
supporting the utility of MI as a tool for predicting hy-
drocarbon phase (oil, condensate, wet gas, or dry gas)
in exploration and exploitation. Areas within the gas-
generation window are defined using MIs. Within the
gas-generation window, multiple levels of maturity
are delineated for the basin. Generally, the contour pat-
terns based on production of oil, wet gas with conden-
sate, or dry gas defined from MI are in good agreement
with those from mapping initial GORs and gas heating
values.
Patterns of thermal maturation for the Barnett
Shale from MI, GOR, and gas thermal values iden-
tify highly thermal mature areas located in Tarrant,
Johnson, northwestern Hill, and western Dallas coun-
ties as the core dry gas area. Furthermore, less ma-
ture areas away from the core area, as indicated by MI,
mainly produce high-Btu wet gas with oil or conden-
sate. All other key geological and engineering factors
being equal, the areaswith high thermalmaturity in the
Barnett Shale will have higher gas productivity and re-
serves per well.
REFERENCES CITED
Aguilera, R., 1974, Analysis of naturally fractured reservoirs fromsonic and resistivity logs: Journal of Petroleum Technology,v. 26, p. 1233–1238.
Archie, G. E., 1950, Introduction to petrophysics of reservoir rocks:AAPG Bulletin, v. 34, p. 943–961.
Bowker, K. A., 2003, Recent development of the Barnett Shale play,FortWorthBasin:WestTexasGeological SocietyBulletin, v. 42,no. 6, p. 4–11.
Curtis, J. B., 2002, Fractured shale-gas system:AAPGBulletin, v. 86,no. 11, p. 1921–1938.
Dunlap, H. F., and R. R. Hawthorne, 1951, The calculation of waterresistivity from chemical analyses: Journal of Petroleum Tech-nology, v. 3, p. 17.
Fertl,W.H., andG.V. Chilingar, 1988, Total organic carbon contentdetermined from well logs: Society of Petroleum EngineersFormation Evaluation, v. 3, no. 2, p. 407–419.
Flippin, J. W., 1982, The stratigraphic, structure, and economic as-pects of the Paleozoic strata in Erath County, north-centralTexas, in C. A. Martin, ed., Petroleum geology of the ForthWorth Basin and Bend arch area: Dallas Geological Society,p. 129–177.
Focke, J. W., and D. Munn, 1987, Cementation exponents in Mid-dle Eastern carbonate reservoirs: Society of Petroleum Engi-neers Formation Evaluation II, p. 155–167.
Givens, N., and H. Zhao, 2004, The Barnett Shale: Not so simpleafter all (abs.): AAPG Annual Meeting Program, v. 13, p. A52,complete article at: http://www.republicenergy.com/Articles/Barnett_Shale/Barnett.aspx.
Guidry, F. K., and J. W. Walsh, 1993, Well log interpretation of aDevonian gas shale: An example analysis (abs.): Society of Pe-troleum Engineers, SPE Paper 26932.
Henry, D. J., 1982, Stratigraphy of the Barnett Shale (Mississippian)and associated reefs in the northern Fort Worth Basin, in C. A.Martin, ed., Petroleum geology of the Forth Worth Basin andBend arch Area: Dallas Geological Society, p. 157–177.
Hill, D. G., and C. R. Nelson, 2000, Gas productive fractured shales:An overview and update: Gas Tips of Gas Research Institute,v. 6, no. 2, p. 4–13.
Jarvie, D. M., B. L. Claxton, F. Henk, and J. T. Breyer, 2001, Oil andshale gas from the Barnett Shale, Ft. Worth Basin, Texas (abs.):AAPG Annual Meeting Program, v. 10, p. A100.
Jarvie, D. M., R. J. Hill, T. E. Ruble, and R. M. Pollastro, 2007,Unconventional shale-gas systems: The Mississippian BarnettShale of north-central Texas as one model for thermogenicshale-gas assessment: AAPG Bulletin, v. 91, no. 4, p. 475–499.
King, E. E., and W. H. Fertl, 1979, Evaluating shale reservoir logs:Oil & Gas Journal, March 26, 1979, p. 166–168.
Kuuskraa, V. A., G. Koperna, J. W. Schmoker, and J. C. Quinn,1998, Barnett Shale rising star in Fort Worth Basin: Oil & GasJournal, May 25, 1998, p. 67–76.
Lancaster, D. E., S. F. McKetta, R. E. Hill, F. K. Guidry, and J. E.Jochen, 1992, Reservoir evaluation, completion techniques, andrecent results from Barnett Shale development in the Fort WorthBasin: Presented at the 1992 SPE Annual Technical Confer-ence and Exhibition, Washington, D.C., October 4–7, SPE Pa-per 24884, p. 225–236.
Meyer, B. L., andM.H.Nederlof, 1984, Identification of source rocks
548 Barnett Shale Thermal Maturity from Log Analysis
on wireline logs by density/resistivity and sonic transit time/resistivity crossplots: AAPG Bulletin, v. 68, no. 2, p. 121–129.
Montgomery, S. L., 2004, Barnett Shale: A new gas play in the FortWorth Basin: IHS Energy Petroleum Frontiers, v. 20, no. 1,p. 1–72.
Montgomery, S. L., D. Jarvie, K. A. Bowker, and R. M. Pollastro,2005, Mississippian Barnett Shale, Fort Worth Basin, north-central Texas: Gas-shale play with multi-trillion cubic footpotential: AAPG Bulletin, v. 89, no. 2, p. 155–175.
Passey, Q. R., S. Creaney, J. B. Kulla, F. J. Moretti, and J. D. Stroud,1990, A practical model for organic richness from porosityand resistivity logs: AAPG Bulletin, v. 74, no. 12, p. 1777–1794.
Pollastro, R. M., 2003, Geological and production characteristicsutilized in assessing the Barnett Shale continuous (unconven-tional) gas accumulation, Barnett –Paleozoic total petroleumsystem, Fort Worth Basin, Texas (abs.): Barnett Shale Sym-posium, Ellison Mile Geotechnology Institute at BrookhavenCollege,Dallas, Texas,November 12–13, 2003, p. 7, http://www.energyconnect.com/pttc/BSR/BSRpublications.htm.
Pollastro, R. M., R. J. Hill, D. M. Jarvie, and M. E. Henry, 2003,Assessing undiscovered resources of the Barnett–Paleozoictotal petroleum system, Bend arch–FortWorth Basin province,Texas (abs.): AAPG Southwest Section Convention, Fort Worth,Texas, March 1–5, 2003, 18 p., http://www.searchanddiscovery.com/documents/pollastro/index.htm.
Pollastro, R. M., R. J. Hill, D. M. Jarvie, and C. Adams, 2004, Geo-
logical and organic geochemical framework of the Barnett–Paleozoic total petroleum system, Bend arch–Fort WorthBasin, Texas (abs.): AAPG Annual Meeting Program, v. 13,p. A113.
Schlumberger Well Logging Survey Corporation, 1989, Log inter-pretation charts: Schlumberger Education Services, Resistivityof NaCl solution, p. 5.
Surdam, R. C., Z. S. Jiao, and R. S. Martinsen, 1994, The regionalpressure regime in Cretaceous sandstones and shales in thePowder River Basin, in P. Ortoleva, ed., Basin and seals: AAPGMemoir 61, p. 213–233.
Surdam, R. C., Z. S. Jiao, and H. P. Heasler, 1997, Anomalouslypressured gas compartment in Cretaceous rocks of the Lara-mide basins of Wyoming: A new class of hydrocarbon accumu-lation, in R. C. Surdam, ed., Seals, traps, and the petroleumsystem: AAPG Memoir 67, p. 199–222.
Wermund, E. G., and W. A. Jenkins, Jr., 1968, Late Pennsylvanianseries in north-central Texas, in Dallas Geological Society, ed.,Dallas Geological Society guidebook to the late Pennsylvaniansediments, north-central Texas: p. 1–11.
Zhao, H., 1996, Anomalous pressures in the Cretaceous sandstonesof the Denver and San Juan basins (Rocky Mountain Laramidebasins): Ph.D. dissertation, Geological Library, University ofWyoming, Laramie, Wyoming, 256 p.
Zhao, H., 2004, Thermal maturation and physical properties of Bar-nett Shale in the Fort Worth Basin, north Texas (abs.): AAPGAnnual Meeting Program, v. 13, p. A154.
Zhao et al. 549