57696139-Barnett-Shale(1)

Humble Geochemical Services
The Barnett Shale as a
Model for Unconventional
Shale Gas Exploration
©
Dan Jarvie
Humble Geochemical Services
Division of Humble Instruments & Services, Inc.
Copyright 2003 Humble Instruments & Services, Inc. All rights reserved.
Humble Geochemical Services
Humble, Texas
(Houston is our largest suburb)
Humble Geochemical Services
Petroleum Geochemistry
• Exploration
High-grading
plays/prospects for
likelihood of
hydrocarbon charge
– Source rocks
– Oil typing
– Correlations
– Inversions
• Production
Assessing reservoirs and
well plumbing
– Reservoir continuity
– Commingled allocation
– EOR assessment
– Well plumbing
Exploration / Production
Finding bypassed pay and predicting pre-test, pre-completion oil quality
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Fractured Shale Petroleum Systems
• An organic rich, black shale is the source of
hydrocarbons:
1. from bacterial decomposition of organic matter
2. from primary thermogenic decomposition of OM
3. from secondary thermogenic cracking of oil
• May be the reservoir or other horizons may be primary
or secondary reservoirs
• Have generation induced microfractures and perhaps
tectonic fractures
• Undergo episodic generation, expulsion, and venting
with maturation
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Fractured shales yield oil and gas in various basins:
there exist numerous similarities and differences among these systems
Biogenic gas
Oil
Oil
Oil
Oil and Gas
Gas
Gas and some oil
Oil
Oil and gas Oil and gas
Oil and some gas
Ref: USGS
Oil and gas
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USGS Data on Gas Bearing Shales
na na 1.6 - 1.9 1-2.5*
Lewis
Shale
San Juan
20**
(min.)
3.4 - 10 0.6 - 1.6*
1-12*
Ave. 4.5
Barnett
Shale
Ft. Worth
86 - 160 1.9 - 19.2 0.4 - 1.0 1-25
New
Albany
Shale
Illinois
35 - 76 11 - 19 0.4 - 0.6 1-20
Antrim
Shale
Michigan
225 -
248
14.5 - 27.5 0.4 - 1.3% 1-4.5*
Ohio
Shale
Appalachian
Shale
Gas
in place
(Tcf)
Estimated
Recoverable
Shale Gas
(Tcf)
Range of
Maturities
(%Ro)
T.O.C.
(wt.%)
Formation Basin
* modified from USGS ** author’s estimate
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Gas Production from Fractured Shales
Barnett
Shale
est. 2002
based on
97 BCF
in first half
of 2002
Ref: Hill, 2000; Bowker, 2002
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Petroleum System Definition:
Components and Processes
Source Rock
Source Rock
Migration Route
Migration Route
Reservoir Rock
Reservoir Rock
Seal Rock
Seal Rock
Trap
Trap
Components
Components
Generation
Generation
Migration
Migration
Accumulation
Accumulation
Preservation
Preservation
Processes
Processes
For high flow
rate gas
in fractured
shales,
must have oil
destruction !
Top
&
Bottom
Ref: Modified from Armentrout, 2001
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Distribution of Organic Matter in Rock Sample (low maturity)
Dispersed
Organic
Matter:
the “source”
of
oil + assoc. gas
Rock Sample
TOC
Live Carbon
Organic Matter (Kerogen) Oil
Gas
Total Organic Carbon (T.O.C.)
Dead Carbon
Dead Carbon
Oil Prone Gas Prone
S2 (and Tmax) S1 S4
Ref: Jarvie, 1991
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Compositional Yields from Primary
Cracking of Barnett Shale
CORRECTED MACT10 PY/GC YIELDS
*
22%
55%
13%
10%
C1
C2-C4
C5-C14
C15+
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Total Organic Carbon (TOC)
OM Oil Gas
Maturation of Organic Maturity
Total Organic Carbon (TOC)
O.M. Oil Gas
Dead
Carbon
Dead
Carbon
Dead Carbon
Dead
Carbon
Dead
Carbon
1. OM is converted to oil and gas; slight increased in dead carbon
2. 1 continues, but oil cracks to gas also
Total Organic Carbon (TOC)
OM Oil Dead Carbon
Gas
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Episodic expulsion also changes the mix
Total Organic Carbon (TOC)
OM Oil Gas
Total Organic Carbon (TOC)
Dead Carbon Oil Gas
Oil
Gas
Expulsion
Generation fracture
Dead Carbon
Dead Carbon
Dead Carbon
OM
TOC
OM Oil
Residual oil, OM, and DC in rock
Dead Carbon
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Residual Oil and Residual OM
are cracked to gas (if sufficient depth of burial)
TOC
OM Oil
Dead Carbon
Gas
Gas wetness is controlled
by thermal maturity and
perhaps physico chemical
interaction of oil with clays
in Barnett
Initially: Wet Gas
Dry Gas
at high
maturities
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FT. WORTH
BASIN
LLANO
UPLIFT
M
U
E
N
S
T
E
R

A
R
C
H
BEND
ARCH
R
E
D

R
IV
E
R
A
R
C
H
O
U
A
C
H
I
T
A

S
T
R
U
C
T
R
U
A
L

B
E
L
T
TEXAS
Study
Area
Ft. Worth
Basin
Location and
principal
geological
features
delimiting the
basin
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Barnett Shale Rock Characteristics
• Organic-rich, black shales
• Thickness up to 1000 ft., average 300 ft.
• Variable lithologic features
– calcareous shale predominates
– clay-rich shale intervals
– cherty intervals
– dolomitic intervals
• Microfractures present, but limited visible
fractures evident at surface
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Has expulsion of Barnett generated
hydrocarbons into younger or older
formations occurred?
• Low maturity oils in the western basin are all
Barnett (8 horizons fingerprinted including the
deeper Ellenburger) and are very high quality for
low maturity (ca. 40
o
API).
• Higher maturity oils in Wise County are also
Barnett sourced oils with similar properties
although color is slightly different.
Thus, expulsion is episodic (different times and maturities)
n.b. This also explains natural ground water contamination in the basin.
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In the Western Ft. Worth
Basin, oils from the:
•Barnett
•Caddo
•Canyon
•Chester
•Chappel
•Conglomerate
•Ellenburger
•Flippen
•Gardner
•Harry Key Ls
•Hodge Eagle
•Hope
•Moran
Are all Barnett-sourced
oils (43) based on oil
fingerprinting results
(Ref: Jarvie et al, 2001)
Stratigraphic Column: Courtesy of Rich Pollastro, USGS
Stratigraphic Column
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Barnett Shale:
Petroleum Potential and Maturity Trend
0
200
400
600
800
1000
1200
1400
380 430 480 530 580
THERMAL MATURITY (Tmax in
o
C)
B
O

/

A
F

(
b
a
s
e
d

o
n

S
2
)
Kerogen transformation
trend line
Lampasas
outcrops !
Gas Window
If high TOC
these are also gas window
despite low (unreliable)
Tmax values
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General Observations
• High TOC marine shales are more efficient
expellers of hydrocarbons
– 1% poor 3% fair 10% excellent
• High TOC and clay content aid retention of
hydrocarbons by adsorption
• Episodic expellers, a.k.a. pressure cookers:
Generate HCs, form vapor lock – critical
pressure exceeded, vent, and reseal;
repeated depending on burial history
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Generation of Oil and Gas
Organic Matter
Oil
Wet-Dry
Gas
Dead Carbon
Dry Gas
Biodegradation
Secondary
Cracking
Source of Gas
in Barnett Shale
• Gas from OM
Cracking
• Gas from
Oil Cracking
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0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
0 50 100 150 200 250 300
TEMPERATURE (
o
C)
C
A
L
.

T
R
A
N
S
F
O
R
M
A
T
I
O
N

R
A
T
I
O
(
T
R
)
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
1.80
2.00
2.20
C
A
L
.

V
I
T
R
I
N
I
T
E

R
E
F
L
E
C
T
A
N
C
E

(
%
R
o
)
KEROGEN-to-HYDROCARBONS HYDROCARBONS-to-GAS VITRINITE REFLECTANCE
CACULATED TRANSFORMATION RATES
for BARNET OM CRACKING and
OIL CRACKING to GAS
Primary
Kerogen
Cracking
Secondary
Oil-to-Gas
Cracking
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432
Tmax TOC S2 HI
5.21 19.80 380
435 4.53 13.45 297
437 4.11 10.27 250
443 3.77 5. 88 156
455 3.41 1.81 53
470 3.32 1.36 41
CONVERSION
TO OIL and
GAS
INCREASING
THERMAL
MATURITY
89%
36%
TOC
p
/ 0.64 = TOC
o
Remaining
potential
decreases
Tmax increases
TOC
HI
Original TOCs can be
back calculated on high maturity samples:
Experimental Conversion of Barnett Shale
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Barnett Shale - Ave. Values
• T. P. Sims #2
Newark East Field
(n=46)
– 4.45 TOC
– 0.60 S2
– 555 Tmax
– 44 HI
– 6 NOC
– 13 BO/AF
6.95%
TOC
orig
30.9
- or -
676 BO/AF
0.9 BBO
20 TCF
S2
orig
If across
Newark E.
Field
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Transformation Ratio
A measure of the extent of kerogen conversion
• to determine this with reasonable accuracy, the
original potential of the soruce rock must be
determined
• multiple formulas
S2
original
– S2
present
/ S2
original
HI
original
–HI
present
/ HI
original
Humble Geochemical Services
Newark East Field
T.P. Sims #2: Transformation Ratio
Original HI = 445
Present day HI = 44
TR = (445-44) / 445 x 100 = 89%
i.e., the Barnett Shale in the Sims well
has lost 89% of its original hydrocarbon potential
Note: HI = mg HC/g TOC
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Producibility and Gas Content
• Worst production comes from highly
fractured (naturally) Barnett (Bowker, 2002)
• Gas content is directly proportional to TOC
and maturity
• BTU content is inversely proportional to
thermal maturity (Bowker, 2002)
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Gas Yields Proportional
to TOC values
y = 66.59x + 60.154
R
2
= 0.7642
0
100
200
300
400
500
600
700
800
0 2 4 6 8 10 12
TOTAL ORGANC CARBON (TOC)
G
A
S

Y
I
E
L
D
Ref: Chattanooga Shale
Humble Geochemical Services
Volumetric Calculation Chart
1.E+06
1.E+07
1.E+08
1.E+09
1.E+10
1.E+11
1.E+12
1.E+13
1.E+09 1.E+10 1.E+11 1.E+12 1.E+13 1.E+14 1.E+15 1.E+16
MASS OF HYDROCARBONS (kg)
O
I
L

E
Q
U
I
V
A
L
E
N
T
,

3
0
o
A
P
I

(
b
b
l
)
1.E+11
1.E+12
1.E+13
1.E+14
1.E+15
1.E+16
1.E+17
G
A
S

E
Q
U
I
V
A
L
E
N
T

(
f
t
3
)
OIL EQUI.
GAS EQUI.
Schmoker, 1994
Requires:
TOC
HI original
HI present
Source thickness
Source areal extent
Source density
Schmoker’s chart for conversion
of hydrocarbon mass to volumes
of oil or gas equivalent
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Volumes Calculated for
Newark East Field only using the
assumptions shown above
1E+15 CF gas ~ 1000 TCF gas
50% conversion loss ~ 500 TCF
1% recoverable ~ 5 TCF
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JONES
F ISHER
EASTLAND
CALLAHAN
BROWN
COM ANCHE
ERATH
BOSQUE
HILL
M cLENNAN
HOOD
SOMER VILLE
JOHNSON
TARRANT PARKER
PALO P INTO
STEPHENS
SHACKEL FORD
THROCKM ORTON
YOUNG
JACK
W ISE DENTON
M ONTAGUE
HAM ILTON
0 10 20 30
Scale in Miles
N
Mills
San Saba
Lampasas
Coryell
Ft. Worth Basin
2000 PRODUCTION
GORs by county
GOR=1000
GOR=3000
GOR=5000+
Source: TRRC
Gas Composition
based on Production Results by County (ave.)
no production
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JONES
F ISHER
EASTLAND
CALLAHAN
BROWN
COM ANCHE
ERATH
BOSQUE
HILL
M cLENNAN
HOOD
SOMER VILLE
JOHNSON
TARRANT PARKER
PALO P INTO
STEPHENS
SHACKEL FORD
THROCKM ORTON
YOUNG
JACK
W ISE DENTON
M ONTAGUE
HAM ILTON
0 10 20 30
Scale in Miles
N
Mills
San Saba
Lampasas
Coryell
Generalized Maturity Map
based on TRCC production data (YTD 2000)
Oil
Gas w/Oil
Dry Gas
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Why is there gas in Wise and Johnson Counties?
Primary and secondary gas generation
DUAL
PHASE
SYSTEM
DUE TO GAS
GENERATION
FOLLOWED
by PRESSURE
and
TEMPERATURE
DROP IN LAST
50 ma
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Johnson County:
Calculated vs. Measured %Ro
Good match
between measured
and calculated
Ro
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Why is there oil in Montague County?
Burial History and Hydrocarbon Generation History
Maximum
burial
temperatures
yield only
oil
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Why wasn’t the ORYX GRANT #1
HORIZONTAL WELL COMMERCIAL FOR OIL?
0
50
100
150
200
7750 7800 7850 7900 7950 8000 8050
DEPTH (feet)
N
O
R
M
A
L
I
Z
E
D

O
I
L

C
O
N
T
E
N
T
Productive Oil or Gas Intervals
Oil stains - shows
Lean - no production potential
Only 1 zone shows oil
saturated Barnett
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Other wells have commercial oil
that is evident from simple tests
0
1 0 0 0
2 0 0 0
3 0 0 0
4 0 0 0
5 0 0 0
6 0 0 0
7 0 0 0
8 0 0 0
9 0 0 0
1 0 0 0 0
0 20 40 60 80 100 120 140 160 180 200
NORMALIZED OIL CONTENT (mg oil/g TOC)
Reservoir Zones
Shows
(hi gh maturi ty
source)
Lean
Mod.
oil
content
Zones yielding
about 100 BO/day
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Eastland County: Also in gas zone,
different burial history
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Viola
Marble Falls
Modified from Pallastro, 2002
The presence or
absence of top and
bottom seals has
impact on fracturing
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Risking Geochemical Data
• TOC – Quantity of Organic Matter
– proportional to the amount of oil and gas
generated
– impacts expulsion efficiency
0.0 to 1.0% : Poor risk for oil or gas
> 1.0 % : Good risk for oil or gas
Remember in the gas window,
TOC may be reduced 30-50%
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Risking Geochemical Data (cont.)
• Ro: 0.2%Ro to 4.0%Ro post mature
• 0.55%Ro = onset of oil generation
• 0.90%Ro = peak oil generation
• 1.10%Ro = wet gas generation window
• 1.40%Ro = dry gas generation window
• 2.10%Ro = dry gas only zone
• > 2.10 %Ro = reservoir destruction,
CO
2
risk
Poor Risk
for Gas
Good risk
for gas
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Risking Geochemical Data (cont.)
• TR: 0-100 % conversion of organic matter
– 0.0 to 50.0 % TR – primarily oil
– 50.0 to 75.0% TR – mixed oil and gas
– 75.0 to 90.0% TR – primarily gas
– > 90.0% TR – primarily dry gas
Poor Risk
for Gas
Good risk
for gas
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Risking Geochemical Data (cont.)
• Gas yields: gas wetness ratios (0-100%)
• gas flow gas yield
• desorbed gas yield
• macerated cuttings gas yield
– 0.00 to 50.0 : oil
– 50.0 to 75.0 : mixed oil and gas
– 75.0 to 90.0 : primarily gas
– > 90.0 : dry gas
Poor Risk
for Gas
Good risk
for gas
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Finding High BTU Gas:
Ft. Worth Basin
0%
20%
40%
60%
80%
100%
0 500 1000 1500 2000 2500 3000
GAS CALORIFIC VALUE (BTU)
D
R
Y
-
t
o
-
W
E
T

G
A
S

R
A
T
I
O
V. High
Maturity
High
Maturity
Mod.
Maturity
BTU content
is controlled by
wet gas content
(and nonhydrocarbon gases, if
present
BTU content
is inversely proportional
to maturity
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Risking Geochemical Data (cont.)
• Seals
– Top seal (Marble Falls)
– Middle seal (Forestburg)
– Lower seal (Viola)
Poor Risk
for Gas
Good risk
for gas
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Risking Geochemical Data (cont.)
• Timing of expulsion / Uplift
– No charge build-up
– Charge build-up and venting
– Charge build-up and no venting
Poor Risk
for Gas
Good risk
for gas
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Risking Geochemical Data (cont.)
• Thickness of shale
(must be considered jointly with TOC)
• Assume 4.5% TOC
– 10 ft.
– 50 ft.
– 100 ft.
– 250 ft
– 400 ft
– 500+ ft
Poor Risk
for Gas
Good risk
for gas
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Shale Gas Evaluation Criteria:
Geochemical Risk Factors
TOC [10]
Ro [2.2]
GAS [1000000] Tmax [600]
TR [1]
TOC < 1.00%
%Ro < 1.1
< 100,000 ppm
headspace gas
Tmax < 450
TR < 0.70
Minimum values
for gas prospects
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Shale Gas Evaluation Criteria:
Wise County Example
TOC [10]
Ro [2.2]
GAS [1000000] Tmax [600]
TR [1]
High maturity shale:
All risk factors favorable
for high BTU gas
Min. values
for gas prospects
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Shale Gas Evaluation Criteria:
Barnett Analog – Gas but Oil Window Maturity
TOC [10]
Ro [2.2]
GAS [1000000] Tmax [600]
TR [1]
Min. values
for gas prospects
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Antrim Shale:
Biogenic Petroleum System
TOC [10]
Ro [2.2]
GAS [1000000] Tmax [600]
TR [1]
Measured
Antrim data
Min. values
for gas prospects
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Know Petroleum System Character
1. Biogenic gas shale petroleum systems
2. Mixed biogenic/thermogenic gas shale systems
3. Thermogenic gas shale petroleum systems
A. source and reservoir not the same
i. timing of expulsion, migration, trap, and seal formation
ii. dependent upon source rock OM type, maturity
iii. could be primary or secondary gas expelled from source
B. source and reservoir the same
i. secondary gas generation (maturity/temperature)
ii. timing of oil decomposition, episode of expulsion
4. Tight gas sands
5. Coal bed methane (primary gas generation)
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What does it take for
a commercial gas discovery in the Barnett Shale?
• Thermal maturity at some point in the past to reach 150
o
C+ for
conversion of kerogen to oil/gas and oil to gas
– %Ro > 1.1% but less than 2.1% to avoid reservoir destruction and high
CO
2
yields
– TR > 0.80
– Tmax > 450
o
C
– TOC values > 4%
• Uplift prior to expulsion / venting
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Evaluation of Gas Potential
while drilling – sweet spot identification
• Gas samples from gas flow line – new technique –an
indication of “lost” gas (gas desorbed from the reservoir
into the mud)
• Canned cuttings samples (desorbed gas) – the amount of
gas (SCF/ton) that will be liberated from cuttings
• Cuttings gas analysis (gas liberated upon crushing cuttings
– an indication of “frac” yields)
• TOC, Rock-Eval, TEGC, and vitrinite reflectance analyses
(is it rich enough, converted enough (TR and Ro) to have
generated commercial amounts of hydrocarbons)
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Using Gas Composition and Isotopes
for sweet spot and maturity assessments
-70.00
-65.00
-60.00
-55.00
-50.00
-45.00
-40.00
-35.00
-30.00
-25.00
-20.00
-45.00 -40.00 -35.00 -30.00 -25.00 -20.00
δ
13
C Ethane (ppt)
δ
1
3
C

M
e
t
h
a
n
e
,

P
r
o
p
a
n
e

(
p
p
t
)
Methane vs. Ethane
Propane vs. Ethane
70%
50%
30%
20%
60%
40%
10%
B
a
c
t
e
r
i
a
l

M
e
t
h
a
n
e
3.00%
Ro=0.50%
1.20%
1.00%
0.70%
1.50%
2.00%
700
750
800
850
900
950
1000
1050
1100
0 20 40 60 80 100
GWRandLHROVERLAY
GWR
LHR
Well
Sweet
Spots
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CONCLUSIONS
• Barnett Shale has world-class petroleum
potential; limiting factors are
– thermal maturity
– episodic expulsion
– seals (leaky through time due to venting)
• Other unconventional resources have similar
characteristics, but also some unique twists
• Risks can be reduced by careful evaluation of
thermal maturity (kerogen conversion) and
timing of events (generation, expulsion)
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References
Armentrout, John The Quest for Energy: Rewarding Careers in Petroleum Exploration, AAPG website slide set, February 2000
(http://www.aapg.org/slide_bank/armentrout_john/index.shtml).
Bowker, K.A., 2002, Recent development of the Barnett Shale play, Fort Worth Basin, RMAG Innovative Gas Exploration
Concepts, Denver, CO October 1, 2002.
Burnham, A. K. and Robert L. Braun, 1990, Development of a detailed model of petroleum formation, destruction, and
expulsion from lacustrine and marine source rocks, Advances in Organic Geochemistry 1989, Org. Geochem., Vol. 16, Nos. 1-
3, pp. 27-39.
Claypool, G. E., and E. A. Mancini, 1989, Geochemical Relationships of Petroleum in Mesozoic Reservoirs to Carbonate
Source Rocks of Jurassic Smackover Formation, Southwestern Alabama : AAPG Bulletin, v. 73, p. 904-924.
Demaison, G. and B. J. Huizina, 1994, Genetic Classification of Petroleum Systems Using Three Factors: Charge, Migration,
and Entrapment, in: The Petroleum System – From Source to Trap, AAPG Memoir 60, L.B. Magoon and W.G. Dow, eds.,
AAPG, Tulsa, OK, 655 p.
Dembicki, Harry, 1986, Oil Show Detection by C5+ Hydrocarbon Mud Logging, SPE Formation Evaluation, pp. 331-334.
Jarvie, Daniel M.,
Jarvie, Daniel M., Jack D. Burgess, Alex Morelos, Robert K. Olson, Phil A. Mariotti, and Robert Lindsey, 2001, Permian Basin
Petroleum Systems Investigations: Inferences from Oil Geochemistry and Source Rocks, AAPG Mid-Continent Section
Meeting, Amarillo, Texas, September 30-October 2, 2001, AAPG Bull. Vol. 85, No.9, pp. 1693-1694, oral presentation.
Jarvie, Daniel M., Brenda L. Claxton, Floyd "Bo" Henk,and John T. Breyer, 2001, Oil and Shale Gas from the Barnett Shale, Ft.
Worth Basin, Texas, AAPG National Convention, June 3-6, 2001, Denver, CO, poster presentation.
Jarvie, Daniel M., 2001, Williston Basin Petroleum Systems: Inferences from Oil Geochemistry and Geology, The Mountain
Geologist, Vol. 38, No. 1, pp. 19-41
Jarvie, Daniel M., Ron Hill, and Frank Mango, 2001, Effect of inorganic constituents on light hydrocarbon composition and
compound distributions of crude oils, 20th International Meeting on Organic Geochemistry, Nancy, France, Sept. 10-14, 2001,
abstract.
Jarvie, D.M., 1991, Total Organic Carbon (TOC) Analysis, in Treatise of Petroleum Geology, Handbook of Petroleum Geology,
Source and Migration Processes and Evaluation Techniques, Ed. R.K. Merrill, AAPG Press, Tulsa, Ok.
Okui, A. and D. Waples, 1993, Relative permeabilities and hydrocarbon expulsion from source rocks, in: Basin Modelling:
Advances and Applications, A.G. Dore et al, eds., NPF Special Publication No. 3, Elsevier, London, 675 p.
Schmoker, James., W., 1994, Volumetric Calculation of Hydrocarbons Generated, AAPG Memoir 60 The Petroleum System –
From Source to Trap, L.B. Magoon and W.G. Dow, eds., pp. 323-326.
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Appendix
• Terms
• Other graphics and maturity/TR/temp correlation
table
• Barnett Shale: TOC and Rock-Eval values
• Solution to Schmoker’s oil and gas volume
calculation
• SPI calculations
• Identifying sweet spots
• Oil and water saturation curves for SS and Sh
• Using geochemistry in unconventional gas plays
Humble Geochemical Services
Terms
• TOC = total organic carbon (organic richness)
• %Ro = vitrinite reflectance (thermal maturity indicator)
• TR = transformation ratio (extent of conversion of kerogen where e.g.,
(HIo-Hip) / HIo
• Rock-Eval S1 = free oil content in rock
• Rock-Eval S2 = remaining kerogen content in rock
• Rock-Eval Tmax = temperature at maximum S2 yield; an indication of
thermal maturity
• Primary cracking kinetics = rate at which kerogen decomposes into
hydrocarbons (oil and gas)
• Secondary cracking kinetics = rate at which oil decomposes into gas
Humble Geochemical Services
Back-calculations of TOC
• At high maturity (85%+ Transformation Ratio (TR))
– TOC present day TOC original
• 4.50% 7.00%
• 2.00% 3.13%
• 8.00% 12.50%
• Different TOCs at high maturity, reflect
organofacies differences and impact
expulsion and gas yields
Humble Geochemical Services
Expulsion Efficiency is Related to TOC
(but is dependent upon heating rate)
Temperature
O
i
l

Y
i
e
l
d

(
m
g

O
i
l
/
g

T
O
C
)
10% TOC
3% TOC
1% TOC
Ref: Burnham and Braun, 1991
about 10
o
C
separation at
low heating
rates;
decreases
with higher
heating rates
Humble Geochemical Services
Derivation of HI
original
• From a database of samples of the same
organofacies of low thermal maturity
– average HI value
• From back calculation or estimation of original
– estimate the original potential from HI
present
, visual
kerogen, Tmax, and Ro data
{Organofacies is a single, mappable unit of organic
matter of the same type without regard to the
inorganic matrix}
Humble Geochemical Services
BAKKEN CONVERSION WITH INCREASING DEPTH OF
BURIAL
0
2000
4000
6000
8000
10000
12000
14000
380 400 420 440 460 480 500
Rock-Eval Tmax
D
E
P
T
H

(
f
t
.
)
Immature
Main
Oil
Zone
Wet
Gas
Zone
D
r
y

G
a
s

Z
o
n
e
Bakken
Maturity
Increases
with depth
of burial
Price et al., 1984
Tmax shows
a logarithmic
increase with
increasing depth
of burial
Humble Geochemical Services
0
100
200
300
400
500
600
700
800
900
1000
330 380 430 480 530 580
Tmax (
o
C)
H
Y
D
R
O
G
E
N

I
N
D
E
X

(
m
g

O
I
L
/
g

T
O
C
)
Type I
Oil Prone
Type II (usu. marine)
Oil Prone
Type III
Gas Prone
Type IV: Dry Gas Prone
Mixed Type II / III
Oil / Gas Prone
~0.60% Ro
~01.40% Ro
Ave. HI
Brown Cty
= 396
Ave. HI
Eastland Cty
= 68
TR(%) = (396-68)/396
x 100
= 83%
and
328 mg HC/g TOC
generated
Extent of Organic
Matter Conversion
Ref: Jarvie and Lundell, 1991
Humble Geochemical Services
Eastern Ft.
Worth Basin:
No
Relationship
between depth
of burial and
measured
vitrinite
reflectance
value
Immature Oil Zone Wet Gas Zone Dry Gas Zone
0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 2.0
Ro (%)
-11000
-9900
-8800
-7700
-6600
-5500
-4400
-3300
-2200
-1100
0
D
e
p
t
h

(
f
e
e
t
)
Vitrinite Reflectance - Depth Plot
Humble Geochemical Services Division
Humble Geochemical Services
Importance
of
Quality of
Organic
Matter –
Kerogen
Type:
Differences
in Organic
Matter
Types
by product
distribution
TYPE I: LACUSTRINE OIL PRONE SOURCE ROCKS
LABILE
60%
REFRACTORY
10%
INERT
20%
EOM
10%
TYPE II: MARINE OIL PRONE SOURCE ROCKS
LABILE
40%
REFRACTORY
10%
INERT
40%
EOM
10%
TYPE III: GAS PRONE SOURCE ROCKS
REFRACTORY
25% INERT
60%
LABILE
5%
EOM
10%
Oil Prone
Fractions
Gas Prone
Fractions
Type I
Type II
Type III
Humble Geochemical Services
Schematic Cross Section from
Brown to Eastland County
B
a
r
n
e
t
t

S
h
a
l
e
Mitcham #1 A.E.A. Heirs #1
TOC=4.67%
HI = 396
Ro = 0.60%
Tmax = 434
TOC=3.40%
HI = 68
Ro = 1.10%
Tmax = 454
B
r
o
w
n

C
t
y
E
a
s
t
l
a
n
d

C
t
y
Ref: Jarvie and Lundell, 1991
Humble Geochemical Services
Relative Correlation of Vitrinite
Reflectance to Rock-Eval Tmax
0.2
0.4
0.6
0.8
1
1.2
1.4
430 435 440 445 450 455 460 465 470
Rock-Eval Tmax (
o
C)
V
i
t
r
i
n
i
t
e

r
e
f
l
e
c
t
a
n
c
e

(
%
R
o
)
Humble Geochemical Services
General Relationship between
Transformation Ratio and %Ro
0.2
0.4
0.6
0.8
1
1.2
1.4
0 0.2 0.4 0.6 0.8 1
TRANSFORMATION RATIO (TR)
V
I
T
R
I
N
I
T
E

R
E
F
L
E
C
T
A
N
C
E

(
%
R
o
)
Humble Geochemical Services
Measured Oil Cracking in GOM at 3.0
o
C/my
y = 0.1196e
0.0141x
R
2
= 0.9997
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
2
2.2
100 120 140 160 180 200 220
TEMPERATURE (
o
C)
V
I
T
R
I
N
I
T
E

R
E
F
L
E
C
T
A
N
C
E

(
%
R
o
)
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Reservoir Temp.
Fraction Oil Cracked
Secondary
Cracking
of Oil to
Gas
Gulf of
Mexico
Case
Study
Claypool
and Mancini,
1989
Humble Geochemical Services
Relative Flow Rates vs. Thermal Maturity
in selected fields
0
200
400
600
800
1000
1200
1400
1600
1800
2000
0.2 0.7 1.2 1.7 2.2
VITRINITE REFLECTANCE (%Ro)
D
A
I
L
Y

R
A
T
E

(
M
C
F
)
For illustration
purposes only:
too many
variables to
be a universal
equation
Humble Geochemical Services
Hypothesized
Key
Correlations
Type II
(marine shale)
low sulfur
organic matter:
1. Thermal Maturity
2. Kerogen Transformation
3. Oil-to-Gas Transformation
4. Temperature
200 0.99 2.0 na 1.00 507
195 0.95 1.9 na 1.00 503
192 0.90 1.8 na 1.00 498
188 0.87 1.7 na 1.00 492
183 0.81 1.6 na 1.00 487
178 0.72 1.5 na 0.99 481
173 0.58 1.4 na 0.98 475
168 0.45 1.3 na 0.97 470
163 0.28 1.2 0.38 0.96 465
157 0.20 1.1 0.33 0.81 460
150 0.05 1.0 0.29 0.67 455
141 0.00 0.9 0.24 0.52 450
134 0.00 0.9 0.19 0.37 445
127 0.00 0.8 0.15 0.23 440
120 0.00 0.7 0.10 0.08 435
Est.
Temperature
(
o
C)
Est. Oil-
to-Gas
Cracking
Est.
%Ro
Est.
PI
Est.
TR
Rock-
Eval
Tmax
(
o
C)
Humble Geochemical Services
Calculate Transformation Ratio
TR (mg HC/g TOC) = HI
original
– HI
present /
HI
original
HI
present
= measured Hydrogen Index (HI) from
sample at depth (mature) = 150
HI
original
= measured Hydrogen Index (HI) from
immature sample = 380
TR = (380-150) / 380 = 0.61 or 61% conversion
Humble Geochemical Services
Barnett Shale - Ave. Values
• All Barnett
(n=540)
– 3.16 TOC
– 2.52 S2
– 449 Tmax
– 23 HI
– 21 NOC
– 55 BO/AF
• Low maturity Barnett
(n=36)
– 3.26 TOC
– 7.87 S2
– 432 Tmax
– 165 HI
– 33 NOC
– 172 BO/AF
(in both cases primarily cuttings analysis)
Humble Geochemical Services
Barnett Shale - Ave. Values
• Lampasas Outcrops
(n=3)
– 11.82 TOC
– 47.26 S2
– 426 Tmax
– 395 HI
– 31 NOC
– 1035 BO/AF
• Sims Core
(n=46)
– 4.45 TOC
– 0.60 S2
– 555 Tmax
– 44 HI
– 6 NOC
– 13 BO/AF
Humble Geochemical Services
Barnett Shale: Petroleum Yields
0
200
400
600
800
1000
1200
1400
Oil (BO/AF)
Min.
Ave.
Max.
Humble Geochemical Services
Newark East Field
Volumetric Calculation
• Calculate mass of organic carbon
• Assumptions
– 25 x 37 mi areal extent (2.395739e+13 cm
2
)
– 450 ft. thick (U. and L. Barnett) (13,716 cm)
– V = 3.2859956e+17 cm
3
– density at 2.4 g/cm
3
– TOC
present
= 4.50; TOC
original
= 6.95
– Mass (g TOC) = 3.6540271e+16 g TOC
Humble Geochemical Services
Calculation of Mass of HCs per
gram of TOC
• M = HIo – HI p
= 380 – 44
= 336 mg hydrocarbons / g TOC
Humble Geochemical Services
Calculate Hydrocarbons Generated
(HCG)
• HCG (kg HC) = R x M x 10
-6
kg/mg
R in mg HC/g TOC
M in g TOC
10
-6
kg/mg is a conversion from mg to kg
HCG = 336 mg HC/g TOC x 3.6540271e+16 g TOC
x 10
-6
kg/mg
= 1.2277531e+13 kg HC
Humble Geochemical Services
Schmoker’s Volumetric Calculation
Chart
1.E+06
1.E+07
1.E+08
1.E+09
1.E+10
1.E+11
1.E+12
1.E+13
1.E+09 1.E+10 1.E+11 1.E+12 1.E+13 1.E+14 1.E+15 1.E+16
MASS OF HYDROCARBONS (kg)
O
I
L

E
Q
U
I
V
A
L
E
N
T
,

3
0
o
A
P
I

(
b
b
l
)
1.E+11
1.E+12
1.E+13
1.E+14
1.E+15
1.E+16
1.E+17
G
A
S

E
Q
U
I
V
A
L
E
N
T

(
f
t
3
)
OIL EQUI.
GAS EQUI.
Schmoker, 1994
Humble Geochemical Services
Source Potential Index (SPI)
• A measure of the potential of a source rock to
generate hydrocarbons over a given areal extent
• SPI = h (S1+S2) p / 1000
– where h = thickness of source rock
– S1+S2 data from Rock-Eval (mg HC/g rock)
– p = density, assume 2.5 t/m
3
• Must also account for migration and entrapment
styles
Ref: Demaison and Huizinga, 1994
Humble Geochemical Services
SPI – Barnett Shale, Wise County
• Assumptions:
– h = 250 ft. or 76.2 m
– S1+S2 = 20.00 t/kg rock
– p = 2.50 t/m
3
• SPI = 76.2 x 20 x 2.5 / 1000
= 3.81 t / m
2
• Add U. Barnett (150 ft.)
= 6.10 t / m
2
• Increase S1+S2 (27.79 ave. per unit TOC) based on Lampasas
outcrop yields
= 8.34 t / m
2
• Maximum S1+S2 at Lampasas = 47.75
= 14.38 t / m
2
Humble Geochemical Services
EXAMPLES OF AVERAGE
SOURCE POTENTIAL INDICES
(tons HC/m
2
)
1. Junggar (China): 65
2. L. Congo (Cabinda): 46
3. Santa Barbara Channel (U.S.A.): 39
4. San Joaquin (U.S.A.): 38
5. Central Sumatra (Indonesia): 34
6. E. Venezuela fold and thrust belt: 27
7. Offshore Santa Maria (U.S.A): 21
Ref: Demaison and Huizinga, 1994
Humble Geochemical Services
EXAMPLES OF SPI (cont.)
(tons HC/m
2
)
8. Middle Magdalena (Colombia): 16
9. North Sea (U.K.): 15
10. Central Arabia (S. Arabia): 14
11. Niger Delta (Nigeria): 14
12. Gulf of Suez (Egypt): 14
13. San Joaquin - Eoc./Oligo. (U.S.A.): 14
14. Ft. Worth - Barnett (U.S.A.): 13
Reserves estimated at 10 TCF or ~ 1.67B BOE
Humble Geochemical Services
Finding High BTU Gas
0%
20%
40%
60%
80%
100%
0 500 1000 1500 2000 2500 3000
GAS CALORIFIC VALUE (BTU)
D
R
Y
-
t
o
-
W
E
T

G
A
S

R
A
T
I
O
V. High
Maturity
High
Maturity
Mod.
Maturity
BTU content
is controlled by
wet gas content
Humble Geochemical Services
Identification
of oil, wet or
dry gas
by
fingerprinting
directly from
cuttings or
core chips:
TEGC
Also useful
for GOR
prediction
Oil Prone
Gas Prone
min 0 2 4 6 8 10 12 14 16
pA
0
100
200
300
400
500
FID1 A, (C:\PROJECTS\MEC\H00-11~1\TEGC\31220000.D)
C
9
C
1
0
C
1
1 C
1
2
C
1
3
C
1
4
C
1
5
C
1
6
C
1
7
C
1
8
C
1
9
C
2
0
C
2
1
C
2
2
C
2
3
C
2
4
C
2
5
C
3
0
C
3
5
min 2 4 6 8 10 12 14 16 18
pA
0
50
100
150
200
250
300
350
400
450
FID1 A, (C:\PROJECTS\MEC\H00-11~2\H00-11~1\31560000.D)
C
9
C
1
0
C
1
1
C
1
2
C
1
3 C
1
4
C
1
5
C
1
6
C
1
7
C
1
8
C
1
9
C
2
0
Humble Geochemical Services
C
7
-determined Generation
Temperatures for Barnett Oils
1.00
1.20
1.40
1.60
1.80
2.00
2.20
80 90 100 110 120 130 140 150
AV ERAGE GENERATI ON TEM PERATURE (
o
C)
SPEARFISH
TYLER
CHARLES - M. CANYON
LODGEPOLE
BAKKEN
NISKU
DUPEROW
DAWSON BAY
WINNIPEGOSIS
INTERLAKE
RED RIVER
WINNIPEG
DEADWOOD
Barnett Oils
on trend line
with Bakken oils
Increasing
GOR
Humble Geochemical Services
GORs can be predicted with some degree of
accuracy from both vitrinite reflectance and
oil/condensate light hydrocarbons
Oil
Wet Gas
Dry
Gas
R
2
= 0.9233
0
1000
2000
3000
4000
5000
6000
7000
8000
0 0.5 1 1.5 2
CAL. VITRINITE REFLECTANCE (%Ro)
C
A
L
.

G
O
R
Humble Geochemical Services
TYPICAL SANDSTONE
RESERVOIR ROCK
WATER SATURATION (%)
R
E
L
A
T
I
V
E

P
E
R
M
E
A
B
I
L
I
T
Y
K
ro
K
rw
K
ro
max
K
rw
max
K
rx
S
wirr
S
wx
S
wc
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0.0
0 10 20 30 40 50 60 70 80 90 100
Humble Geochemical Services
TYPICAL SHALE RESERVOIR ROCK
is quite different from a conventional reservoir
WATER SATURATION (%)
R
E
L
A
T
I
V
E

P
E
R
M
E
A
B
I
L
I
T
Y
K
ro
K
rw
0 10 20 30 40 50 60 70 80 90 100
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0.0
Ref: Okui and Waples, 2000
Humble Geochemical Services
Using Geochemistry
in Unconventional Plays
• Construct maps
• Organic facies (maceral) maps
• Maturity and TR maps
• Composition (GOR) maps
• BTU maps
• Needs to construct maps
• Geological/geophysical information
• Geochemical data (TOC, RE, Ro, Compo.)
Humble Geochemical Services
Using Geochemistry
in Unconventional Plays
• Construct well and basin models
– Burial history curves
– Timing of generation and expulsion
• Evaluate amounts expelled (reduces
amount of oil to crack to gas)
• Timing of uplift impacts expulsion
• Optimize models using geochemical data
such as TOC, Ro, TR