integration of geochemistry & reservoir fluid properties pttc workshop june 25, 2003 kevin...

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

0

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400000

FID1 A, (LA271.D)

C7

PrC27

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Sterane & TerpaneBiomarkers

time

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undance

Sterane Biomarkers m/z = 218

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50 55 60 65 70

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C29

GC/MS Mass Chromatograms

R

GC/MS Mass Chromatograms

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C26

25 30 35 40 45 50

C19C20 C21

C22

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C26

Tricyclic Terpane Biomarkers m/z = 191

C23

Tricyclic Terpane Biomarker Ratios

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1.3

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carbonatemarlshalelacustrine

Carbonate Source Rocks

Shale Source Rocks

Terpane Biomarker Ratios

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carbonatemarlshalelacustrine

Carbonate Source Rocks

Shale Source Rocks

Lacustrine Source Rocks

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C30M

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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

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marl

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Oleanane vs Source Rock Age

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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

Cluster AnalysisDendrogram

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

min5 10 15 20 25 30 35

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nC7

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nC7

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Heavy biodegradation

‘Polyhistory’ Oil

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“Polyhistory” Oils

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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

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Location Map of Offshore Gas Samples

(after Schoell, 1983)

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met

han

e

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Post MatureDry Gas

Conde

nsat

e

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Gas Wetness (%C2+)

/

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0.0 10.0 20.0 30.0 40.0

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Piston Cores + Seeps

Genetic Classification of GOM Gases

GeoMark Research, Inc.Houston, Texas

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13C Ethane (per mil)

13

C M

etha

ne/

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pane

(pe

r m

il)

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C M

eth

ane

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nd

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C P

rop

ane

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A

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1.0

Isotopic Cross Plots for GOM Gases

Thermogenic

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#

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Biogenic Methane Trends

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ope

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ios

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CO

2)

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13

C C

O2

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Inorganic vs. Organic Origin of Carbon Dioxide

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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






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)







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

)



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


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



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



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 Onset Classes

Num

ber o

f Sam

ples



50

100

150

200202

24

80



Num

ber o

f Sam

ples



Asphaltene Stability HistogramHigh Thermal Maturity Samples


50

100

150

200

106

11

60

Asphaltene Stability Histogram(High Thermal Maturity Samples)


Num

ber o

f Sam

ples



50

100

150

200

106

11

60

Asphaltene Stability Histogram(High Thermal Maturity Samples)


Num

ber o

f Sam

ples



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


'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



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


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



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.

integration of geochemistry & reservoir fluid properties pttc workshop june 25, 2003 kevin...

Documents

source rocks available

biomarkers oils

rock extracts

source rocks molecular

corresponding crude

oil qualityoil quality

tertiary shalesfamily

cretaceous shalesfamily