barnett shale aapg

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).


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).


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


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.


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.


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.

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