Integration of Geochemistry &
Reservoir Fluid Properties
PTTC Workshop
June 25, 2003
Kevin Ferworn, John Zumberge, Stephen Brown
GeoMark Research, Inc.
Introduction
•
GeoMark has undertaken a number of projects integrating geochemistry
and reservoir fluid properties.
•
Presentation separated into two parts.
•
Part I. John Zumberge


•
Introduction to oil and gas geochemistry
Petroleum Systems studies
Part II. Kevin Ferworn

Results from interpretive studies (models, correlations and charts) used to
predict Reservoir Fluid and Flow Assurance properties .
Oil Quality Controlled by 4 Elements
•
Source Rock Type


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•
Thermal History of Source Rock


•
Depth of Burial
Timing of Generation
Post Generative Alteration

•
Marine Shales
Marine Carbonates
Lacustrine Shales
Biodegradation
Reservoir Mixing
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% Sulfur
0 - 0.4
0.4 - 1
1-2
>2
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Geochemistry Fundamentals
•
Predict depositional environments, thermal maturity, and geological ages
of petroleum source rocks from corresponding crude oils
•
Why use crude oils and not source rock extracts?

Oils are widely available, accessible, abundant, and carry the same
kind of evolutionary & environmental information that is buried in
source rocks
•
Molecular Fossils – a.k.a Biomarkers
•
Oils reflect the natural ‘average’ in source rock variation
•
The source rock type and age for many of the oils in GeoMark’s database
are known based on extensive integration of geology and geochemistry
Geochemical Approach
• Petroleum Systems Geochemistry – GOM Example





Crude Oil Geochemistry - Few Source Rocks Available in GOM
Unparalleled Oil Sample Collection
Comparison with Known Petroleum Systems Onshore
Homogeneous Data Set
Multivariate Statistics
• Production Geochemistry


Detailed comparison of samples from multiple formations or wells to
evaluate continuity
Often called “Fingerprinting”
Whole Crude Gas Chromatogram
FID1 A, (LA271.D)
C7
Sterane & Terpane
Biomarkers
000
abundance
000
C17
Pr
000
000
C27
0
5
10
15
20
time
25
30
35
min
GC/MS Mass Chromatograms
R
C27
C29
C28
50
55
60
65
Sterane Biomarkers m/z = 218
70
GC/MS Mass Chromatograms
C23
C23
Tet
C24
C19
25
C20
C25
C21
C22
30
35
40
45
C26
50
Tricyclic Terpane Biomarkers m/z = 191
Tricyclic Terpane Biomarker Ratios
1.3
1.1
Carbonate Source Rocks
carbonate
marl
shale
lacustrine
C22/C21
0.9
0.7
Shale Source Rocks
0.5
0.3
0.1
0.1
0.3
0.5
0.7
C24/C23
0.9
1.1
1.3
Terpane Biomarker Ratios
0.6
Carbonate Source Rocks
carbonate
marl
shale
lacustrine
C31R/H
0.5
Shale Source Rocks
0.4
Lacustrine Source Rocks
0.3
0.2
0.1
0.5
0.7
0.9
1.1
1.3
C26/C25
1.5
1.7
1.9
2.1
GC/MS Mass Chromatograms
OLEANANE
C30H
C29H
C31S
Tm
Ts
27T
60
OL
C29D
C30X
C28
65
C30M
70
C31R C32S
C35S
GA C32R C33S
C34S
C33R
C35R
C34R
75
80
Pentacyclic Terpane Biomarkers m/z = 191
(a.k.a. Hopanes)
Oleanane vs Source Rock Age
0.60
carbonate
marl
0.50
shale
Permian Ext
Cretaceous Ext
OL/H
0.40
0.30
0.20
0.10
0.00
0
100
200
300
Source Rock Age mybp
400
500
600
1.0
0.8
0.6
0.4
0.2
Family B-Tertiary Coaly-Resinous
Family A - Tertiary Paralic
Cluster Analysis
Dendrogram
Shales
Family C2 - Wilcox Distal
Family C1 - L. Cretaceous Shales
Family D - U. Cretaceous Shales
Family SE1 ?????????
0.63
Family SE2 - Tithonian Marls/
Carbonates
Family F -Oxfordian Smackover
Carbonates/
Marls
La Luna/Napo - Cretaceous
Marls/Carbonates
Cognac, Tahoe, Gemini
Petronius, Pompano,
Shasta, Popeye, Snapper
East Texas Field
Austin Chalk Trend
Mahogany, Agate, Teak,
Mars, Bullwinkle, Jolliet,
Baldpate, Auger, Tick
Europa, Lobster, Fuji,
Tampico, Salina,
Campeche (Cantarell)
Principal Component Analysis
Factor 2
%C29
C29/H
C22/C21
d13Cs
d13Ca
Factor 3
C31/H
C35/C34
C19/C23
Pr/Ph
OL/H
Factor 1
C24/C23
%C27
%C28
Ster/Hop
Principal Component Analysis
Factor 2
Tertiary Paralic
Shales
Oxfordian Smackover
Factor 3
Tithonian
Carbonates
/Marls
MIXED
Factor 1
Wilcox Distal
Shales
Cretaceous Shales
La Luna/Napo
Carbonates/Marls
Principal Component Analysis
Factor 2
d13Cs
d13Ca
Factor 3
Factor 1
Smackover
Gulf of Mexico Oil Source Rock Families
TERT
LK
MIX
EB
GB
MC
GC
AT
WR
LD
UJ
AC
KC
Family A: Tertiary Shales
Family C1: LK Shales
Family SE1: Mixed
Family SE2: UJ Marls
Factors Affecting Oil Quality
Oil Quality is affected by four elements.
1. Source Rock Depositional Environment and Age
2. Thermal Maturity
3. Biodegradation
4. In-situ Mixing
Biodegradation and Mixing in Oils
FID1 A, (LA919.D)
nC7
500000
Non degraded
400000
300000
200000
100000
0
5
10
15
20
25
30
35
min
FID1 A, (LA993.D)
30000
25000
20000
15000
10000
nC7
140000
Heavy biodegradation
5000
FID1 A, (LA1034.D)
0
5
120000
10
15
20
100000
‘Polyhistory’ Oil
80000
60000
40000
20000
0
5
10
15
20
25
30
35
min
25
30
35
min
“Polyhistory” Oils
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100 Miles
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Gas Geochemistry
•
No biomarkers present in Gases, therefore different markers used for
classification.
•
Composition & Stable Isotopes



C1 - C4
13C vs. 12C
2H vs. 1H
•
Origin of Gas: Thermogenic vs. Biogenic
•
Gas samples used for geochemical analyses may come from flashed PVT lab
samples or from Mud Gases (i.e., Isotubes)
•
Geochemical analyses also offer insight on quality of Deep Shelf gas
Location Map of Offshore Gas Samples
Well Gas
Seep Gas
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%C2+
Genetic Classification of GOM Gases
0.0
-70
10.0
20.0
30.0
40.0
-75.0
-70.0
-70
Biogenic
-65.0
d 13Cmethane /

-60
-60.0
-60
Mixed
-55.0
-50
-50
Oil Associated
-50.0
-45.0
-40
TEDSE
TEDSW
TEMS
LKMSE
LKMSE
UKMS
THMC
THLKM
SMMC
Piston Cores + Seeps
-40
Post
Mature
Dry Gas
-30
-30
-20
-20
0
10
20
30
Gas Wetness (%C2+)
GeoMark Research, Inc.
Houston, Texas
40
-40.0
-35.0
-30.0
-25.0
-20.0
0
10
20
30
40
Gas Wetness (%C2+)
(after Schoell, 1983)
Isotopic Cross Plots for GOM Gases
-10
TEDSE
TEDSW
2.0
and Propane
‰
dd 13
C Methane
d 13C Propane
‰
13C
(per mil)
Methane/
d 13C
TEMS
1.5
LKMSE
-20
3.0 Ro
LKMSW
UKMS
1.0
THMC
THLKM
-30
SEEPS
0.7 Ro
-40
Thermogenic
B
-50
Mixed
A
-60
Biogenic
-70
-42
-38
-34
-30
d 13CEthane
Ethane(per
‰ mil)
d13C
-26
-22
-18
Biogenic Methane Trends
Methane Carbon Isotope
# < -80
# -80 - -70
# -70 - -60
# -60 - -50
# -50 - -40
# -40 - -30
50
0
50 Miles
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Inorganic vs. Organic Origin of Carbon Dioxide
10.0
Inorganic CO2
0.0
-10.0
-20.0
13
d Carbon
C CO
2
Isotope
Ratios For CO2)
d 13C/12C CO2 (Stable
20.0
TEDSE
TEDSW
TEMS
UKMS
LKMSE
LKMSW
SMMC
THMC
THLKM
SEEPS
-30.0
Organic CO2
-40.0
-50.0
-60.0
0
1
2
3
4
5
6
7
Normalized Percent
CO2 (%CO2)
Normalized
Percent
CO2
8
9
10
5.0
% Carbon Dioxide vs. Reservoir Depth
13CO2 > -12 per mil
0.0
1.0
2.0
% CO2
3.0
4.0
13CO2 < -12 per mil
0
5,000
10,000
15,000
MD ft
20,000
25,000
Maturity Trends
50
Ethane Carbon Isotope
S -51 - -34
#
S -34 - -31
#
S -31 - -28
#
S -28 - -26
#
S -26 - -17
#
0
50 Miles
S
#
#
S
##
S
##
S
S
#
#
### #
#
S
#
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S#
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S #
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#
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S #
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#
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S
S#
S
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S
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S#
S
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S#
#
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S
S #
#
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#
S
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# #
# #
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S
#
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#
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##
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S S
#
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####
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#####
##
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##
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####
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S
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#
gEngineering Studies
•
gPVT study completed in Gulf of Mexico in 2000.
•
12 member companies contributed PVT reports and matching stock tank oil
samples for full geochemical analyses and interpretation.
•
Traditional PVT correlations were tested against the data set and then improve by
tuning against main Geochemical Parameters:



•
Source rock type / family
Thermal maturity
Level of biodegradation.
Importance of associated gas was discovered. In particular, the influence of
Biogenic Methane.
Gulf of Mexico Oil Source Rock Families
TERT
LK
MIX
EB
GB
MC
GC
AT
WR
LD
UJ
AC
KC
Family A: Tertiary Shales
Family C1: LK Shales
Family SE1: Mixed
Family SE2: UJ Marls
Sulfur Oil Quality Matrix
A
M1B0
0.09
B
0.07
0.07
0.04
C2
M2B0
0.08
46
9
0.19
0.11
0.17
SE1 Mix
SE2
0.29
57
0.51
62
F2
17
0.58
0.56
A
B
C2
D
C1
0.08
11
0.12
0.21
15
0.28
6
M2B2*
2
0.04
4
3
0.22
1
0.09
4
27
0.25
60
0.18
0.30
21
0.69
21
0.13
0.44
14
0.39
1
1.60
2
1.6
0.68
0.16
0.55
7
1.19
7
0.33
0.19
0.58
6
0.17
0.21
4
1.19
6
0.69
4
0.44
3
0.94
20
2.50
3
2.66
4
1
0.63
4
0.52
7
0.46
3
0.37
6
AVE
6
1.92
0.13
Family
0.09
4
M1B2*
0.14
0.48
6
0.12
0.17
0.48
8
0.12
M2B2
0.16
3.18
0.53
T2/AJB
0.38
6
1
2.22
2.12
1.52
0.15
0.09
M2B1
0.18
4
0.77
2.31
1.06
F3
5
0.27
0.20
1.11
F1
9
M1B2
0.22
0.03
0.38
0.3
0.99
1.0
2.30
2.3
0.04
M1B1
0.12
0.16
25
D
C1
8
0.21
0.15
0.10
0.06
M3B0
0.06
1
0.92
8
Source Rock Age/Character
Tertiary Paralic/Deltaic Shales
Tertiary Coaly/Resinous Shales
Tertiary Distal Wilcox Shales
UK Distal Eagle Ford/Tuscaloosa Shales
LK Distal Shales
0.37
n
17
Family
SE1 Mix
SE2
F1
F3
F2
T2/AJB
Source Rock Age/Character
Mixture of C1 and SE2
Tithonian Carbonates/Marls
Oxfordian Smackover Carbonates
Oxfordian Smackover Marls/Shales
LK Sunniland Carbonates
Tithonian Carbonates
Level of Thermal Maturity
M1 Low to Moderate
M2 Moderate
M3 Moderate to High
Degree of Biodegradation
B0
Nondegraded
B1
Mild
B2
Heavy
B2* Polyhistory Oils
Vasquez-Beggs Sat. Pressure Correlation
Vasquez-Beggs: Psat = f(GOR, Gas Gravity, Oil Gravity, Temperature)
Oil Family
Regression
Coefficient (R2)
Entire Data Set
(original constants)
0.6032
Entire Data Set
(updated constants)
0.8429
C1
0.9097
SE1
0.9194
SE2
0.8779
C1-Biodegraded
0.9969
SE1-Biodegraded
0.9248
SE2-Biodegraded
0.9816
GOR / Res. Fluid MW Relationship
Reservoir Fluid MW vs. Single Stage GOR
12000
Gases
Oils
C1 - Distal Lower Cretaceous Shales
10000
SE1 - Mixture of C1 and SE2
SE2 - Tithonian Carbonates/Marls
Single Stage GOR (scf/stb)
C1-B - Biodegraded C1
SE1-B - Biodegraded SE1
Curve Fit: R2 = 0.9959
8000
6000
4000
GOR-1 = -9.715E-5 + 1.2464E-6 MW 1.5
2000
0
0
50
100
150
Reservoir Fluid MW (lb/lbmole)
200
250
Gas Wetness vs. Res. Fluid MW
Reservoir Fluid MW vs. Reservoir Fluid % Wetness
40
C1 - Distal Lower Cretaceous Shales
35
SE1 - Mixture of C1 and SE2
SE2 - Tithonian Carbonates/Marls
C1-B - Biodegraded C1
Reservoir Fluid % Wetness
30
SE1-B - Biodegraded SE1
25
20
15
Biodegraded Samples
10
5
0
0
20
40
60
80
100
120
Reservoir Fluid MW (lb/lbmole)
140
160
180
200
Psat / Composition Relationship
Reservoir Fluid C1 / C5 Ratio vs. Adjusted Saturation Pressure
14000
C1 - Distal Lower Cretaceous Shales
SE1 - Mixture of C1 and SE2
SE2 - Tithonian Carbonates/Marls
12000
Adjusted Psat (psia @ 190°F)
C1-B - Biodegraded C1
SE1-B - Biodegraded SE1
SE2-B - Biodegraded SE2
10000
8000
6000
4000
2000
0
10
20
30
40
50
60
70
Reservoir Fluid C1 / C5 Ratio (mole%/mole%)
80
90
100
Predicting PVT from FT Gradients
•
Pressure Gradients from Wireline Formation Test Tools (e.g. RCI, MDT, RDT) can
be directly converted to Reservoir Fluid Densities:

i.e., Pressure Gradient P/z = rres . g
•
Pressure Gradient Densities are unaffected by Oil-Based Drilling Fluid.
•
Correlations have been developed to predict Downhole Petroleum Fluid PVT
Properties from Reservoir Fluid Densities and Geochemical Parameters derived
from GeoMark’s global database of oils and seeps.
•
Input requirements:




•
Pressure Gradient
Reservoir Pressure/Temperature
Three Geochemical Parameters: Source Rock, Maturity, Biodegradation
Mud Logging Dryness Factor: C1 / (C1 + C2 + C3)
Algorithms are used to predict PVT parameters real-time, prior to the availability
of physical samples.
GeoMark Research, Inc.
PVTMod Application
Pedigree Info
GOM
Example
Country
State/Province
Basin
Block/County
Field Name
Well/ST Number
Formation Name
MD
Input Parameters
USA
Louisiana
GOM
Reservoir Pressure
Reservoir Temperature
Pressure Gradient
Reservoir Fluid Density
Mud Logging Dryness Factor
Source Rock Aromaticity
Thermal Maturity
Biodegradation
Input Parameters
4000
125
0.320
0.739
0.92
0.23
0.24
0
Notes
Example is from the Deepwater Gulf of Mexico. Measured PVT data is compared to PVTMod Predictions
from a general GOM basin model and a further refined field model with additional weight given to
previously analyzed samples from the same field.
*Probable Range: 2/3rd of the data points used to develop the correlation fall within the probable range.
Variable
ReservoirFluid
Fluid MW MW
Reservoir
Single Stage GOR
Reservoir
Fluid GOR
Reservoir Fluid Density
Reservoir SS FVF
Reservoir Fluid Viscosity
Saturation Pressure
Saturated Fluid Density
Saturated SS FVF
Saturated Fluid Viscosity
API Gravity
STO Sulfur Content
Reservoir Fluid N2
Reservoir Fluid CO2
Reservoir Fluid C1
Reservoir Fluid C2
Reservoir Fluid C3
Reservoir Fluid iC4
Reservoir Fluid nC4
Reservoir Fluid iC5
Reservoir Fluid nC5
Reservoir Fluid C6
Reservoir Fluid C7+
Reservoir Fluid C7+ MW
Reservoir Fluid C7+ SG
Flash Gas Gravity
Units
g/mole
scf/stb
g/cc
vol/std vol
cP
psia
g/cc
vol/std vol
cP
°API
wt%
mole%
mole%
mole%
mole%
mole%
mole%
mole%
mole%
mole%
mole%
mole%
g/mole
Measured
102.9
102.9
639
639
0.739
1.329
0.87
3140
0.729
1.310
0.72
35.2
0.20
0.40
0.68
47.10
2.25
1.67
0.41
1.63
1.95
0.86
1.59
41.46
197.6
0.854
0.760
Field Tuned
103.7
677
Saturation Pressure
Reservoir Fluid Viscosity
3140
.87
3387
.81
Saturated FVF
1.310
1.314
Reservoir Fluid C1
(Air = 1.0)
47.10
Basin Tuned
103.7
105.4
677
672
Calculated from Gradient
1.325
1.292
0.81
0.75
3387
3435
0.732
0.735
1.314
1.357
0.73
0.65
35.9
32.9
0.21
0.27
0.30
0.22
1.69
0.48
45.06
44.59
4.30
2.68
3.07
2.85
1.05
1.07
1.92
1.74
1.50
1.10
1.31
1.73
2.12
2.40
37.68
41.14
202.2
239.4
0.857
0.868
0.801
0.744
45.06
psia
°F
psi/ft
g/cc
(0 - 1)
(0 - 1)
(0 or 1)
Flow Assurance Studies
•
In 2001 a study was undertaken to compare stock tank oil geochemical
analyses to wax and asphaltene stability measurements



Extended Compositions by HTGC
Cloud Points by CPM
Asphaltene stabilities by n-Heptane Titration
•
It was found that source rock type, thermal maturity and level of
biodegradation each had an influence on solids stability.
•
“Live oil” flow assurance data is beginning to appear in the Reservoir Fluid
Database.
•
Future work includes a new study to collect and interpret Live Oil flow
assurance data with geochemical analyses.
High Temperature GC Example
FID response
C40
15000
Expanded Scale
12000
9000
C50
6000
nC35
3000
UCM
retention time (min)
LA271
6
9
12
15
18
21
24
27
Example Cloud Point Trial (CPM)
Example Wax Cloud Point and Crystal Growth Graph
CPM Crystal Growth
Plot
7
Crystal Saturation (CPM % Whitespace)
6
5
Calculated Crystal Growth Slope = -0.210 %/°F
Calculated Intercept = 9.7%
4
3
Cooling Experiment
CPM Micrograph
2
Visual Cloud Point = 47°F
1
0
0
10
20
30
40
50
Temperature (°F)
60
70
80
90
Cloud Point vs. nC30+
Cloud Point vs. HTGC nC30+
200
180
Cloud Point (°F)
160
140
Marine Distal Shales
Marine Paralic Shales
Marine Carbonates
Marine Marls
Hypersaline
Coaly/Resinous
Lacustrine Fresh
Lacustrine Saline
LA952
120
100
80
60
40
RU115
20
500
1000
5000
10000
nC30+ (ppm)
50000 100000 200000
Distal Shale Sample Cloud Points
Sample RU115
Sample LA952
RU115: nParaffin and non n-Paraffin Distributions
LA952: nParaffin and non n-Paraffin Distributions
1000000
1000000
n-Paraffin
n-Paraffin
100000
Concentration (ppm)
100000
Concentration (ppm)
non n-Paraffin
non n-Paraffin
10000
1000
100
10000
1000
100
10
10
1
C15
6
11
16
21
26
Component
31
Cloud Point = 49°F
36
41
46
1
C60
C15
6
11
16
21
26
Component
31
Cloud Point = 115°F
36
41
46
C60
Cloud Point Histogram
CPM Cloud Point Histogram
Marine Distal Shales
Marine Paralic Shales
Marine Carbonates
Marine Marls
Hypersaline
Coaly/Resinous
Lacustrine Fresh
Lacustrine Saline
154
Number of Samples
150
100
58
58
50
34
CP < 40°F
40 < CP < 80°F
80 < CP < 120°F
CPM Cloud Point Ranges
CP > 120°F
Regional Cloud Point Maps
Larger Symbols Indicate
Higher Cloud Points
Symbol Colors by Source Rock Oil Type
Symbol Sizes by Paraffin Cloud Point Range
Southeast Asia
Middle East
'W
W
'
W
'
'W
'W
W
'
W
'
W
'
W
'W'W
'W
'W
'W 'W'W
'W
'W W
'
'W
'W
'W
'W
W
'
'W
1. M a rine D is ta l Sh ale
2. M a rine Pa ralic S ha le
'W 'W
3. M a rine C a rbo na te
'W
U
%
U
%
U
%
U
%
U
%
U
%
U
%
U
%
4.
5.
6.
7.
8.
M a rine M a rl
H y pe rsa line
C o a ly / R es ino u se
La c us trin e F r es h
La c us trin e S alin e
W
'
'W 'W 'W'
'W
'W
W
'
'W
Wax Cloud Point Symbols
'W CP < 40°F
'W 40°F < CP < 80°F
W
' 80°F < CP < 120°F
'W CP > 120°F
'W
'W'W
'W
'W
'W
'W
'W
'W 'W
'W 'W
'W
W
'
'W
'W
'W
'W
'W
'W
Example Asphaltene STO Onset Test
Example Asphaltene Titration Onset Graph
1.0E-01
Calculated Initial Slope = 2.21E-04 W /
mL/g
Calculated Initial Power = 3.98E-04 W
Transmitted Laser Power (W)
1.0E-02
Calculated Precipitation Slope = -1.99 W / mL/g
1.0E-03
1.0E-04
Final Power = 8.40E-06 W
Calculated Precipitation Onset = 0.9 mL/g
"Effective" Angle Between Initial and
Precipitation Slopes = 99.2°
1.0E-05
1.0E-06
0.0
0.5
1.0
1.5
Dilution Ratio (mL nC7 / g oil)
2.0
2.5
3.0
Asphaltene Stability Histogram
Asphaltene Stability Histogram
200
Marine Distal Shales
Marine Paralic Shales
Marine Carbonates
Marine Marls
Hypersaline
Coaly/Resinous
Lacustrine Fresh
Lacustrine Saline
202
Number of Samples
150
100
80
50
24
Stable Asphaltenes
Moderately Stable Asphaltenes
Asphaltene Onset Classes
Unstable Asphaltenes
Asphaltene Stability Histogram
High Thermal Maturity SamplesAsphaltene Stability Histogram
(High Thermal Maturity Samples)
Marine Distal Shales
Marine Paralic Shales
Marine Carbonates
Marine Marls
Hypersaline
Coaly/Resinous
Lacustrine Fresh
Lacustrine Saline
Number of Samples
200
150
106
100
60
50
11
Stable Asphaltenes
Moderately Stable Asphaltenes
Asphaltene Onset Classes
Unstable Asphaltenes
Regional Asphaltene Stability Maps
Larger Symbols Indicate More
Unstable Asphaltenes
Symbol Colors by Source Rock Oil Type
Symbol Sizes by Asphaltene Onset Titration Ratio
Middle East
Southeast Asia
'W
'W
'W
W
'
'W
'W 'W
'W 'W'W
'W
'W
'W
'W
'W
'W
'W
'W
'W
'W
'W
'W
'W
'W
''W
W
U
%
U
%
U
%
U
%
U
%
U
%
U
%
U
%
1.
2.
3.
4.
5.
6.
7.
8.
M a r ine D is ta l Sh ale
M a r ine Pa r alic S ha le
M a r ine C a r bo na te
M a r ine M a r l
Hy pe r sa line
Co a ly / R es ino u se
La c us trin e F res h
La c us trin e S alin e
'W
'W
'W
'W
'W
'W
'
W
'W 'W
W
'
'W
'W
'W
'W
'W
'W
'W'W'W'W
'W
'W
'W
'W
'W
'W
Asphaltene Onset Symbols
'W A.O. > 5 mL/g
'W A.O. > 3 mL/g
'W
'W
W
' 2 < A.O. < 3 mL/g
'W A.O. < 2 mL/g
'W
'W
“de Boer” Asphaltene
Stability
Plot
Asphaltene Stability
Plot
(De Boer Diagram)
12000
Marine Distal Shales
Marine Paralic Shales
Marine Carbonates
Marine Marls
Hypersaline
Coaly/Resinous
Lacustrine Fresh
Lacustrine Saline
Reservoir – Saturation Pressure (psia)
Fuji Samples
10000
Severe
Problems
8000
Magnolia
Samples
Slight
Problems
6000
No Problems
4000
2000
Saudi Arabian Samples
0
0.5
0.6
0.7
0.8
Reservoir Fluid Density (g/cc)
0.9
1
Conclusions
•
Oil Geochemical analyses are used to determine…





Source Rock Depositional environment and age
Thermal Maturity
Biodegradation
In-situ Mixing
Reservoir Continuity (i.e., Production Geochemistry)
•
Gas Geochemical analyses further provide estimations of Biogenic vs.
Thermogenic gas concentrations in Reservoir Fluids.
•
Oil and Gas PVT correlations are improved by introducing geochemical
factors.
•
Flow Assurance issues may be Forward Modeled with Geochemical
representations.