integration of geochemistry & reservoir fluid properties pttc workshop june 25, 2003 kevin...
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Integration of Geochemistry &Reservoir Fluid Properties
PTTC WorkshopJune 25, 2003
Kevin Ferworn, John Zumberge, Stephen BrownGeoMark Research, Inc.
• 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 .
Introduction
• Source Rock Type Marine Shales Marine Carbonates Lacustrine Shales
• Thermal History of Source Rock Depth of Burial Timing of Generation
• Post Generative Alteration Biodegradation
• Reservoir Mixing
Oil Quality Controlled by 4 Elements
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0.4 - 11 - 2
0 - 0.4
> 2
% Sulfur
• 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
Geochemistry Fundamentals
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
min5 10 15 20 25 30 35
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200000
300000
400000
FID1 A, (LA271.D)
C7
PrC27
C17
Sterane & TerpaneBiomarkers
time
ab
undance
Sterane Biomarkers m/z = 218
50 55 60 65 70
50 55 60 65 70
C27
C28
C29
GC/MS Mass Chromatograms
R
GC/MS Mass Chromatograms
25 30 35 40 45 50
C19C20 C21
C22
C23
C24
C25
Tet
C26
25 30 35 40 45 50
C19C20 C21
C22
C23
C24
C25
Tet
C26
Tricyclic Terpane Biomarkers m/z = 191
C23
Tricyclic Terpane Biomarker Ratios
0.1
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0.9
1.1
1.3
0.1 0.3 0.5 0.7 0.9 1.1 1.3
C24/C23
C22
/C21
carbonatemarlshalelacustrine
Carbonate Source Rocks
Shale Source Rocks
Terpane Biomarker Ratios
0.1
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C26/C25
C31
R/H
carbonatemarlshalelacustrine
Carbonate Source Rocks
Shale Source Rocks
Lacustrine Source Rocks
60 65 70 75 80
Ts
Tm
27TC28
C29H
C29DC30X
OL
C30H
C30M
C31S
C31RGA
C32S
C32R C33SC33R
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C35SC35R
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C29DC30X
OL
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C31RGA
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C32R C33SC33R
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Pentacyclic Terpane Biomarkers m/z = 191(a.k.a. Hopanes)
GC/MS Mass ChromatogramsOLEANANE
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Source Rock Age mybp
OL
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marl
shale
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Cretaceous Ext
Oleanane vs Source Rock Age
1.0 0.8 0.6 0.4 0.2
Family A - Tertiary Paralic
Family C2 - Wilcox Distal
Family B-Tertiary Coaly-Resinous
Family C1 - L. Cretaceous Shales
Family D - U. Cretaceous ShalesFamily SE1 ?????????
Family SE2 - Tithonian Marls/Family SE2 - Tithonian Marls/CarbonatesCarbonates
Family F -Oxfordian SmackoverFamily F -Oxfordian Smackover
La Luna/Napo - Cretaceous
Marls/Carbonates
Cognac, Tahoe, GeminiPetronius, Pompano,
Shasta, Popeye, Snapper
East Texas FieldAustin Chalk Trend
Mahogany, Agate, Teak, Mars, Bullwinkle, Jolliet,
Baldpate, Auger, Tick
Europa, Lobster, Fuji, Tampico, Salina,
Campeche (Cantarell)
Shales
Carbonates/Marls
0.63
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Pr/Ph
OL/H
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C29/HC22/C21
C35/C34C31/H
C24/C23
Ster/Hop
%C29
%C27
%C28
13Cs13Ca
Principal Component Analysis
Factor 2
Factor 3 Factor 1
Tertiary ParalicShales
Wilcox DistalWilcox DistalShalesShales
Cretaceous Shales
TithonianTithonianCarbonatesCarbonates
/Marls/Marls
Oxfordian SmackoverOxfordian Smackover
La Luna/NapoCarbonates/Marls
MIXEDMIXED
Principal Component AnalysisFactor 2
Factor 3 Factor 1
13Cs13Ca
Factor 2
Factor 3
Factor 1
Principal Component Analysis
SmackoverSmackover
GB GC AT
MC
EB
AC WRKC LD
Family A: Tertiary ShalesFamily C1: LK Shales
Family SE1: MixedFamily SE2: UJ Marls
UJ
LKTERT
MIX
Gulf of Mexico Oil Source Rock Families
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
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nC7
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nC7
Non degraded
Heavy biodegradation
‘Polyhistory’ Oil
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• 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
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Location Map of Offshore Gas Samples
(after Schoell, 1983)
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-50
-40
-30
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-60
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met
han
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Gas Wetness (%C2+)
Mixed
Oil Associated
Post MatureDry Gas
Conde
nsat
e
Biogenic
100 20 30 40
-20
-50
-40
-30
-70
-60
Gas Wetness (%C2+)
/
-75.0
-70.0
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0.0 10.0 20.0 30.0 40.0
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SMMC
Piston Cores + Seeps
Genetic Classification of GOM Gases
GeoMark Research, Inc.Houston, Texas
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-30
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13C Ethane (per mil)
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C M
etha
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13C
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pane
(pe
r m
il)
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TEDSW
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UKMS
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THLKM
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13C Ethane ‰
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C M
eth
ane
‰ a
nd
13
C P
rop
ane
‰
B
A
3.0 Ro1.5
2.0
0.7 Ro
1.0
Isotopic Cross Plots for GOM Gases
Thermogenic
Biogenic
Mixed
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#
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Biogenic Methane Trends
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Normalized Percent CO2 (%CO2)
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C/1
2C C
O2
(Sta
ble
Car
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Isot
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Rat
ios
For
CO
2)
TEDSE
TEDSW
TEMS
UKMS
LKMSE
LKMSW
SMMC
THMC
THLKM
SEEPS
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Organic CO2
13
C C
O2
Normalized Percent CO2
Inorganic vs. Organic Origin of Carbon Dioxide
% Carbon Dioxide vs. Reservoir Depth0
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MD ft
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O2
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13CO2 < -12 per mil
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50 0 50 Miles
Maturity Trends
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.
GB GC AT
MC
EB
AC WRKC LD
Family A: Tertiary ShalesFamily C1: LK Shales
Family SE1: MixedFamily SE2: UJ Marls
UJ
LKTERT
MIX
Gulf of Mexico Oil Source Rock Families
Sulfur Oil Quality Matrix
Degree of BiodegradationB0 NondegradedB1 MildB2 HeavyB2* Polyhistory Oils
Level of Thermal MaturityM1 Low to ModerateM2 ModerateM3 Moderate to High
Family Source Rock Age/Character
A Tertiary Paralic/Deltaic Shales
B Tertiary Coaly/Resinous Shales
C2 Tertiary Distal Wilcox Shales
D UK Distal Eagle Ford/Tuscaloosa Shales
C1 LK Distal Shales
Family Source Rock Age/Character
SE1 Mix Mixture of C1 and SE2
SE2 Tithonian Carbonates/Marls
F1 Oxfordian Smackover Carbonates
F3 Oxfordian Smackover Marls/Shales
F2 LK Sunniland Carbonates
T2/AJB Tithonian Carbonates
M1B0 M2B0 M3B0 M1B1 M1B2 M2B1 M2B2 M1B2* M2B2*A 0.09 0.08 0.06 0.12 0.22 0.16
0.07 46 0.06 8 0.04 9 0.09 6 0.12 4 2
B 0.07 0.21 0.03 0.18 0.09 0.210.04 9 0.19 5 1 0.12 15 0.04 4 3
C2 0.15 0.16 0.17 0.28 0.220.10 25 0.11 4 0.08 6 1 0.09 4
D 0.38 0.140.17 11 0.12 27
C1 0.29 0.27 0.25 0.30 0.44 0.39 0.55 0.58 0.210.20 57 0.15 60 0.18 21 0.13 14 1 0.16 7 0.19 6 0.17 4 3
SE1 Mix 0.99 0.77 0.69 1.60 1.19 1.19 0.940.51 62 0.38 21 2 0.68 7 0.33 6 0.69 20 3
SE2 2.30 2.22 2.50 2.661.11 17 0.58 4 0.44 4 1
F1 2.31 0.48 0.631.06 8 0.56 4 0.52 7
F3 2.12 0.48 0.461.52 6 3 0.37 6
F2 3.180.53 6 AVE
T2/AJB 1.92 0.92 1 n
0.13 8 0.37 17
0.3
2.31.0 1.6
Vasquez-Beggs Sat. Pressure Correlation
Vasquez-Beggs: Psat = f(GOR, Gas Gravity, Oil Gravity, Temperature)
Oil FamilyRegression
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
0
2000
4000
6000
8000
10000
12000
0 50 100 150 200 250
Reservoir Fluid MW (lb/lbmole)
Sin
gle
Sta
ge
GO
R (
scf/
stb
)
C1 - Distal Lower Cretaceous Shales
SE1 - Mixture of C1 and SE2
SE2 - Tithonian Carbonates/Marls
C1-B - Biodegraded C1
SE1-B - Biodegraded SE1
Curve Fit: R2 = 0.9959
GOR-1 = -9.715E-5 + 1.2464E-6 MW1.5
OilsGases
Gas Wetness vs. Res. Fluid MW
Reservoir Fluid MW vs. Reservoir Fluid % Wetness
0
5
10
15
20
25
30
35
40
0 20 40 60 80 100 120 140 160 180 200
Reservoir Fluid MW (lb/lbmole)
Re
serv
oir
Flu
id %
We
tne
ss
C1 - Distal Lower Cretaceous Shales
SE1 - Mixture of C1 and SE2
SE2 - Tithonian Carbonates/Marls
C1-B - Biodegraded C1
SE1-B - Biodegraded SE1
Biodegraded Samples
Psat / Composition Relationship
Reservoir Fluid C1 / C5 Ratio vs. Adjusted Saturation Pressure
0
2000
4000
6000
8000
10000
12000
14000
10 20 30 40 50 60 70 80 90 100
Reservoir Fluid C1 / C5 Ratio (mole%/mole%)
Ad
just
ed
Psa
t (p
sia
@ 1
90
°F)
C1 - Distal Lower Cretaceous Shales
SE1 - Mixture of C1 and SE2
SE2 - Tithonian Carbonates/Marls
C1-B - Biodegraded C1
SE1-B - Biodegraded SE1
SE2-B - Biodegraded SE2
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 = res . 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 Input ParametersCountry USA Reservoir Pressure 4000 psiaState/Province Louisiana Reservoir Temperature 125 °FBasin GOM Pressure Gradient 0.320 psi/ftBlock/County Reservoir Fluid Density 0.739 g/ccField Name 0.92Well/ST Number Source Rock Aromaticity 0.23 (0 - 1)Formation Name Thermal Maturity 0.24 (0 - 1)MD Biodegradation 0 (0 or 1)
Notes
Variable Units Measured Field Tuned Basin TunedReservoir Fluid MW g/mole 102.9 103.7 105.4Single Stage GOR scf/stb 639 677 672Reservoir Fluid Density g/cc 0.739Reservoir SS FVF vol/std vol 1.329 1.325 1.292Reservoir Fluid Viscosity cP 0.87 0.81 0.75Saturation Pressure psia 3140 3387 3435Saturated Fluid Density g/cc 0.729 0.732 0.735Saturated SS FVF vol/std vol 1.310 1.314 1.357Saturated Fluid Viscosity cP 0.72 0.73 0.65API Gravity °API 35.2 35.9 32.9STO Sulfur Content wt% 0.20 0.21 0.27Reservoir Fluid N2 mole% 0.40 0.30 0.22Reservoir Fluid CO2 mole% 0.68 1.69 0.48Reservoir Fluid C1 mole% 47.10 45.06 44.59Reservoir Fluid C2 mole% 2.25 4.30 2.68Reservoir Fluid C3 mole% 1.67 3.07 2.85Reservoir Fluid iC4 mole% 0.41 1.05 1.07Reservoir Fluid nC4 mole% 1.63 1.92 1.74Reservoir Fluid iC5 mole% 1.95 1.50 1.10Reservoir Fluid nC5 mole% 0.86 1.31 1.73Reservoir Fluid C6 mole% 1.59 2.12 2.40Reservoir Fluid C7+ mole% 41.46 37.68 41.14Reservoir Fluid C7+ MW g/mole 197.6 202.2 239.4Reservoir Fluid C7+ SG 0.854 0.857 0.868Flash Gas Gravity (Air = 1.0) 0.760 0.801 0.744
*Probable Range: 2/3rd of the data points used to develop the correlation fall within the probable range.
Calculated from Gradient
Mud Logging Dryness Factor
Example is from the Deepwater Gulf of Mexico. Measured PVT data is compared to PVTMod Predictionsfrom a general GOM basin model and a further refined field model with additional weight given to previously analyzed samples from the same field.
GOMExample
Reservoir Fluid MW
102.9 103.7Reservoir Fluid
GOR639
677
Reservoir Fluid Viscosity
.87 .81
Saturated FVF 1.310 1.314
Reservoir Fluid C1
47.10 45.06
Input Parameters
Saturation Pressure
3140 3387
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
6 9 12 15 18 21 24 27
3000
6000
9000
12000
15000
LA271
nC35
6 9 12 15 18 21 24 27
3000
6000
9000
12000
15000
LA271
nC35
UCM
Expanded Scale
retention time (min)
C40
C50
FID response
Example Cloud Point Trial (CPM)
0
1
2
3
4
5
6
7
0 10 20 30 40 50 60 70 80 90
Temperature (°F)
Cry
sta
l Sa
tura
tio
n (
CP
M %
Wh
ite
spa
ce
)
Calculated Crystal Growth Slope = -0.210 %/°FCalculated Intercept = 9.7%
Visual Cloud Point = 47°F
Cooling Experiment
CPM Crystal Growth Plot
CPM Micrograph
20
40
60
80
100
120
140
160
180
200
500 1000 5000 10000 50000 100000 200000
LA952
RU115
Cloud Point vs. HTGC nC30+
nC30+ (ppm)
Clo
ud P
oint
(°F
)
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
20
40
60
80
100
120
140
160
180
200
500 1000 5000 10000 50000 100000 200000
LA952
RU115
Cloud Point vs. HTGC nC30+
nC30+ (ppm)
Clo
ud P
oint
(°F
)
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Cloud Point vs. nC30+
Distal Shale Sample Cloud Points
RU115: nParaffin and non n-Paraffin Distributions
10
100
1000
10000
100000
1000000
1 6 11 16 21 26 31 36 41 46Component
Co
nc
en
tra
tio
n (
pp
m)
n-Paraffin
non n-Paraffin
C15 C60
LA952: nParaffin and non n-Paraffin Distributions
10
100
1000
10000
100000
1000000
1 6 11 16 21 26 31 36 41 46Component
Co
nc
en
tra
tio
n (
pp
m)
n-Paraffin
non n-Paraffin
C15 C60
Sample RU115 Sample LA952
Cloud Point = 49°F Cloud Point = 115°F
Cloud Point Histogram
CP < 40°F 40 < CP < 80°F 80 < CP < 120°F CP > 120°F
50
100
150
58
154
58
34
CPM Cloud Point Histogram
CPM Cloud Point Ranges
Num
ber o
f Sam
ples
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
CP < 40°F 40 < CP < 80°F 80 < CP < 120°F CP > 120°F
50
100
150
58
154
58
34
CPM Cloud Point Histogram
CPM Cloud Point Ranges
Num
ber o
f Sam
ples
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Regional Cloud Point Maps
'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'W
'W
%U 8. Lacustrine Saline%U 7. Lacustrine Fresh%U 6. Coaly / Resinouse%U 5. Hypersaline%U 4. Marine Marl%U 3. Marine Carbonate%U 2. Marine Paralic Shale%U 1. Marine Distal Shale
'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'W
'W
%U 8. Lacustrine Saline%U 7. Lacustrine Fresh%U 6. Coaly / Resinouse%U 5. Hypersaline%U 4. Marine Marl%U 3. Marine Carbonate%U 2. Marine Paralic Shale%U 1. Marine Distal Shale
%U 8. Lacustrine Saline%U 7. Lacustrine Fresh%U 6. Coaly / Resinouse%U 5. Hypersaline%U 4. Marine Marl%U 3. Marine Carbonate%U 2. Marine Paralic Shale%U 1. Marine Distal Shale
Southeast Asia Middle East
Symbol Colors by Source Rock Oil TypeSymbol Sizes by Paraffin Cloud Point Range
Larger Symbols IndicateHigher Cloud Points
'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
'W'W'W
'W
'W '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
'WCP > 120°F
Example Asphaltene STO Onset Test
1.0E-06
1.0E-05
1.0E-04
1.0E-03
1.0E-02
1.0E-01
0.0 0.5 1.0 1.5 2.0 2.5 3.0
Dilution Ratio (mL nC7 / g oil)
Tra
nsm
itted
Las
er P
ower
(W)
Calculated Initial Slope = 2.21E-04 W / mL/g
Calculated Initial Power = 3.98E-04 W
Calculated Precipitation Onset = 0.9 mL/g"Effective" Angle Between Initial and
Precipitation Slopes = 99.2°
Calculated Precipitation Slope = -1.99 W / mL/g
Final Power = 8.40E-06 W
Asphaltene Stability Histogram
Stable Asphaltenes Moderately Stable Asphaltenes Unstable Asphaltenes
50
100
150
200202
24
80
Asphaltene Stability Histogram
Asphaltene Onset Classes
Num
ber o
f Sam
ples
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Stable Asphaltenes Moderately Stable Asphaltenes Unstable Asphaltenes
50
100
150
200202
24
80
Asphaltene Stability Histogram
Asphaltene Onset Classes
Num
ber o
f Sam
ples
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Asphaltene Stability HistogramHigh Thermal Maturity Samples
Stable Asphaltenes Moderately Stable Asphaltenes Unstable Asphaltenes
50
100
150
200
106
11
60
Asphaltene Stability Histogram(High Thermal Maturity Samples)
Asphaltene Onset Classes
Num
ber o
f Sam
ples
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Stable Asphaltenes Moderately Stable Asphaltenes Unstable Asphaltenes
50
100
150
200
106
11
60
Asphaltene Stability Histogram(High Thermal Maturity Samples)
Asphaltene Onset Classes
Num
ber o
f Sam
ples
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Regional Asphaltene Stability Maps
'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'W
%U 8. Lacustrine Saline%U 7. Lacustrine Fresh%U 6. Coaly / Resinouse%U 5. Hypersaline%U 4. Marine Marl%U 3. Marine Carbonate%U 2. Marine Paralic Shale%U 1. Marine Distal Shale
'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'W
%U 8. Lacustrine Saline%U 7. Lacustrine Fresh%U 6. Coaly / Resinouse%U 5. Hypersaline%U 4. Marine Marl%U 3. Marine Carbonate%U 2. Marine Paralic Shale%U 1. Marine Distal Shale
%U 8. Lacustrine Saline%U 7. Lacustrine Fresh%U 6. Coaly / Resinouse%U 5. Hypersaline%U 4. Marine Marl%U 3. Marine Carbonate%U 2. Marine Paralic Shale%U 1. Marine Distal Shale
Southeast Asia Middle East
Symbol Colors by Source Rock Oil TypeSymbol Sizes by Asphaltene Onset Titration Ratio
Larger Symbols Indicate MoreUnstable Asphaltenes
'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'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 2 < A.O. < 3 mL/g
'W A.O. < 2 mL/g
“de Boer” Asphaltene Stability Plot
0
2000
4000
6000
8000
10000
12000
0.5 0.6 0.7 0.8 0.9 1
Asphaltene Stability Plot(De Boer Diagram)
Reservoir Fluid Density (g/cc)
Res
ervo
ir –
Sat
urat
ion
Pre
ssur
e (
psia
)
No Problems
SevereProblems
SlightProblems
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Fuji Samples
MagnoliaSamples
Saudi Arabian Samples0
2000
4000
6000
8000
10000
12000
0.5 0.6 0.7 0.8 0.9 1
Asphaltene Stability Plot(De Boer Diagram)
Reservoir Fluid Density (g/cc)
Res
ervo
ir –
Sat
urat
ion
Pre
ssur
e (
psia
)
No Problems
SevereProblems
SlightProblems
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Marine Distal ShalesMarine Paralic ShalesMarine CarbonatesMarine MarlsHypersalineCoaly/ResinousLacustrine FreshLacustrine Saline
Fuji Samples
MagnoliaSamples
Saudi Arabian Samples
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.
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