The Applications of Organic Geochemistry to Source...

GGG, PTT Exploration and Production Co. Ltd.GGG, PTT Exploration and Production Co. Ltd.Supaporn Supaporn PisuthaPisutha--ArnondArnond, Cambodia, 2004, Cambodia, 20049-Apr-04

Applications of Geochemistry to Source Rock Appraisals

The Applications of Organic Geochemistry to Source Rock Appraisal and Hydrocarbon Characteristics

By Supaporn Pisutha-Arnond



WEST EAST

WELL 2 WELL 1A B C

SHALE SOURCE

Hypothetical section across an area in the early stages of development (Barker, 1975)

(DRY) (SUCCESS)



Source Rock Appraisal-Identification of source rock layers-Assessment of their maturity stages

-To identify kitchen area-To determine the time of hydrocarbon generation-To trace migration path and entrapment process



Example of rift related environment (offshore SE, well A penetrated the post-rift Mioceneand to Basement, well B drilled the post-rift and the upper part of the syn-rift sequence)

(Bordenave, M.L., 1993, Applied Petroleum Geochemistry)



1. Does the rock have sufficient organic matter?2. Is the organic matter of the right type?3. Has this organic matter generated petroleum?4. Has the generated petroleum migrated out?

Source Rock Appraisal - Screening analysis



KEROGEN



Reference: M.L. Bordenave, 1993, Applied Petroleum Geochemistry

Green River Shales

Lower Toarcian Sediments

Miocene Sed, Mahakam Delta

Van Krevelen Diagramatomic O/C ratio VS

H/C ratio



KEROGENType I : Lacustrine planktonic debris intensively

reworked by bacteria

Type II : Marine plankton debris sedimented under anoxic conditions

Type III : Land-plant debris sedimented in terrestrial environment

Reference: M.L. Bordenave, 1993, Applied Petroleum Geochemistry





S1 S2 S3

Increasing temp.Of pyrolysis

Increasing temp.of trapped CO2

Time

VolatilizationOf existing

HC

PyrolysisOf

kerogen

S1 S2

Time

Tmax

Cooling

1000 3000

3900

5500

S3

Trapping CO2

Tem

pera

ture

Oil or gas shows

S1 (g/ton of rock)

Oil or gas showsTotal

Genetic potentialS1+S2 (kg/ton of rock)

Oil or gas shows

S2/org.C Hydrocarbon IndexS3/org.C Oxygen Index

Oil or gas showsTransformation ratio

S1/S1+S2

Analysis Cycle

Example of record

Application toPetroleum exploration

Peak temperature Tmax(*C)

Cycle of analysis andexample of record obtainedby the pyrolysis methodof Espitalie et al. 1977.(Ref: Milner, D. 1996)

Rock-Eval Pyrolysis


Applications of Geochemistry to Source Rock AppraisalsCompany : GOOD OILWell/Area : Success 1Sample Type : Unwashed Cuttings (Hubco Bags)File No. : GSI-01169

S1 S2 S31440.00 med gy Sh 0.96 0.07 1.39 0.95 436.00 0.05 1.46 144.79 98.961460.00 med gy Sh 0.71 0.04 0.78 0.59 429.00 0.05 0.82 109.86 83.101740.00 med gy Sh 0.66 0.02 0.63 0.26 433.00 0.03 0.65 95.45 39.391760.00 med gy Sh 0.62 0.05 0.76 0.28 434.00 0.06 0.81 122.58 45.161780.00 med gy Sh 0.511800.00 med gy Sh 0.501820.00 med gy Sh 0.56

S1 = Free Hydrocarbons S2 = Pyrolysable Hydrocarbons S3 = Organic CO2Oil Production Index = Transformation Ratio = S1/(S1+S2) Tmax = Temperature of Maximum S2 Oxygen Index = (S3/TOC) x 100* Pyrolysis by Rock Eval II; TOC content by Leco Analyzer Hydrogen Index = (S2/TOC) x 100

Sample Depth

(meters)

Tmax (°C)

Oil Production

Index

Potential Yield

(S1+S2)Lithology TOC (wt.%)

mg/gm rock Hydrogen Index

Oxygen Index

TABLE ROCK-EVAL PYROLYSIS AND TOC CONTENT*

Extracted 5 hours (DCM 80% + MeOH 20%)Extracted 48 hours (DCM 90% + MeOH 10%)



FIGURE 2Hydrogen Index v's Oxygen Index

(modified van Krevelen Diagram)

0.0 100.0 200.0 300.0 400.00

200

400

600

800

1000

Oxygen Index (OI)

Hdrogen

Inde(H

I)

II Oil Prone

I Highly Oil Prone

III Gas Prone

File No. : GSI-01167CompanyWellSample Type

: PTTEP: Arthit 14-1X: Unwashed Cuttings (Hubco Bags) & SWC

- Legend -

Interval 1149.0 - 1354.6 mTMDInterval 1354.6 - 1695.6 mTMDInterval 1695.6 - 1923.3 mTMDInterval 1923.3 - 2093.2 mTMDInterval 2093.2 - 2296.1 mTMDInterval 2296.1 - 2997.7 mTMDInterval 2997.7 - 3326.6 mTMD

Classification ofthe 3 main Types of kerogen

in a HI vs OI diagram



Organic Matter Type and Thermal Maturity(Hydrogen Index/Tmax Diagram)

FIGURE 1

400 420 440 460 480 500 520

Hydrogen Index (m

gHC

/g TOC

)

0

150

300

450

600

750

900

IMMATURE OIL ZONE GAS ZONE

0.5 % Ro

1.2 % Ro

Type II

Type I

Tmax (°C)

Type III


: PTTEP: Arthit 14-1X: Unwashed Cuttings (Hubco Bags) & SWC

- Legend -

Interval 1149.0 - 1354.6 mTMDInterval 1354.6 - 1695.6 mTMDInterval 1695.6 - 1923.3 mTMDInterval 1923.3 - 2093.2 mTMDInterval 2093.2 - 2296.1 mTMDInterval 2296.1 - 2997.7 mTMDInterval 2997.7 - 3326.6 mTMD

Kerogen type and thermal maturityIn a Tmax vs HI diagram


Applications of Geochemistry to Source Rock AppraisalsDUAL PETROLEUMSYSTEMS (Pattani)

Post rift: Coals and Coaly Shales (Fluvio-Deltaic), Type III Kerogen, Gas Condensate-Prone, Dominant System

Early Syn-Rift: LacustrineAlgal Shales, Type I Kerogen, Oil-Prone, Supplemental System

Oil: >500 MMBOGas: 15 TCFCondensate: 500 MMBO

KEROGEN TYPING IN THAILAND TERTIARY BASINS

0

100

200

300

400

500

600

700

800

900

1000

1100

0 20 40 60 80 100 120 140 160 180OXYGEN INDEX (mc CO 2/g Org. C)

HY

DR

OG

EN

IND

EX

(m

g H

C/g

Org

. C)

MAE MOHNONG YA PLONGLIMAE SOTPATTANI

TYPE I(Oil-Prone)

TYPE II

TYPE III(Gas-Prone)

(Rui Lin, 2002)



Optical Method to identify organic richness

Developed from Coal Petrology, the descriptionOf organic matter uses the maceral classification.

These techniques are still in their infacy and should beConsidered as aids to research rather than commonlyUsed tools. (Bordenave, M.L. 1993, Applied Petroleum Geochemistry)

VISUAL KEROGEN


Applications of Geochemistry to Source Rock AppraisalsCompany : GOOD OILWell Name : Success 1Area/Block : -Sample Type : Ditch CuttingsFile no. : GSI-01169

NF.A. %

F.A. %

A %

C %

S %

R %

SB %

L % F.A. Herb

1440 30 10 7 2 1 - - 2 22 43 5 tr M-G G 0.35 3/4 do o-do M SA-SR

1560 30 5 5 2 2 - 2 5 21 47 2 tr M-G G 0.44 4 do o-do M SA-SR

1620 50 - 3 2 2 - 1 7 15 33 2 tr P-M G 0.45 4 - o M SA-SR

1660 40 - 2 2 3 - 1 10 18 37 5 tr M-G G 0.46 4-4/5 - o M SA-SR

1740 61 - tr 2 3 - - 7 12 20 5 2 P-M G 0.51 4-4/5 - o G SA-SR

2790 20 - 1 2 3 3 - 7 16 57 5 2 P-M G 0.49 4/5 - o M SA-SR

2820 25 - 2 tr 2 tr - 5 9 56 5 5 P-M G 0.46 4/5 - o M SA-SR

NF.A : Non Fluorescent Amorphous OPK : Oil Prone Kerogen g : green G : GoodF.A : Fluorescing Amorphous TAS : Thermal Alteration Scale y : yellow Fr : Fair A : Angular

A : Alginite Herb : Herbaceous o : orange Pr : Poor SA : Sub-AngularC : Cutinite Tr : Trace do : dull orange Bn : Barren SR : Sub-RoundedS : Sporinite Srt : Sorting br : brown P : Poor R : RoundedR : Resinite Ang : Angularity dkbr : dark brown M : Moderate

SB : SuberiniteL : Liptodetrinite

NA : No AnalysisNDP : No Determination Possible.

KEROGEN DATA SUMMARY

Sample Depth (m)

Amorphinite (Type I-II/III)

Exinite (Type I/II) OPK

%Vitrinite

Type III %Semifusinite

Type IV %Inertinite Type IV %

Rec. of Organic Matter

Mean Ro % AngPreserv. TAS

Fluorescence Colour

Srt



0

10

20

30

40

50

60

70

80

90

100

Well 1 Well 2 Well 3 Well 4 Well 5 Well 6 Well 7

Non Flour AmorphOil Prone KerogenVitriniteSemi FusiniteInertinite



0

10

20

30

40

50

60

70

80

14-1X3110

14-5(ST)3770

14-6X3280

Visual Kerogen Type from Rift Section

Non Flour Amorph Oil Prone Kerogen Vitrinite *Inertinite

Well X Well Y Well Z



MATURITY



Recognition of Maturity Stages1. Optical Methods2. Chemical Methods

Optical Methods: Vitrinite Reflectance

Immature up to 0.5 %RoMature 0.5 to 2.0 %RoOvermature 2.0 to 16.0 %Ro


Applications of Geochemistry to Source Rock AppraisalsCompany : GOOD OILWell : Success 1Sample Type : Ditch cuttingsFile No. : GSI-01169

TABLE VITRINITE REFLECTANCE RESULTS

Plug Type SD

1 1440.0 WR 0.35 18 0.31 0.42 0.0272 1560.0 WR 0.44 18 0.31 0.60 0.0823 1620.0 WR 0.45 15 0.40 0.51 0.0374 1660.0 WR 0.46 18 0.35 0.54 0.0545 1740.0 WR 0.51 44 0.40 0.77 0.0886 2790.0 WR 0.49 21 0.41 0.67 0.0657 2820.0 WR 0.46 19 0.40 0.58 0.049

Maximum Reflectance (%)

Sample Depth (metres)

Mean Ro (%) No. of Readings Minimum

Reflectance (%)



0

250

500

750

1000

1250

1500

1750

2000

2250

2500

2750

3000

3250

Maturity ProfileFIGURE 5

DEPTH(metres) 0.3 1.00.6

%Ro Scale

M a t u r eImmature Post-mature

0.4 0.5 0.8


: PTTEP: Arthit 14-1X: Ditch Cuttings and SWC

Mean Vitrinite Reflectance (Indigenous)Mean Vitrinite Reflectance (Reworked/oxidised population)Mean Vitrinite Reflectance (Caving)

Top 'Oil Window'c. 1800 m

'best fit' VR gradient

Vitrinite Reflectance VR (Ro)

-Plot against depth (Log scale)



Depth vs Vitrinite Reflectance

-3500

-3000

-2500

-2000

-1500

-1000

-500

00 1 1 2

Vitrinite Reflectance(%)

Dep

th(m

)

Calculation

Observed


-4500

-4000

-3500

-3000

-2500

-2000

-1500

-1000

-500

00 1 1 2


Dep

th(m

)

Calculation

Observed

Maturity and VR – Depth Plot




-3500

-3000

-2500

-2000

-1500

-1000

-500

00 1 1 2


Dep

th(m

)

Calculation

Observed

Maturity and VR – Depth Plot



Temperature (C)0 50 100 150 200 250

Dep

th S

ubsu

rfac

e (m

)

0

1000

2000

3000

Maturity (%Ro)1 10

Fm3

Fm2E

Fm2D

Fm2C

Fm2B

Fm2A

Fm1

Fm

t = 0

MaturityTemperatureEarly Mature (oil)0.5 to 0.7 (%Ro)Mid Mature (oil)0.7 to 1 (%Ro)Late Mature (oil)1 to 1.3 (%Ro)Main Gas Generation1.3 to 2.6 (%Ro)%Ro BHT

Temperature (C)0 50 100 150 200 250

Dep

th S

ubsu

rfac

e (m

)

0

1000

2000

3000

Maturity (%Ro)1 10

Fm3

Fm2E

Fm2D

Fm2C

Fm2B

Fm2A

Fm1

Fm

t = 0

MaturityTemperatureEarly Mature (oil)0.5 to 0.7 (%Ro)Mid Mature (oil)0.7 to 1 (%Ro)Late Mature (oil)1 to 1.3 (%Ro)Main Gas Generation1.3 to 2.6 (%Ro)%Ro BHT

Early Mature (oil) 0.5 – 0.7 (%Ro)Mid Mature (oil) 0.7 – 1.0 (%Ro)Late Mature (oil) 1.0 – 1.3 (%Ro)

Main Gas Generation 1.3 – 2.6 (%Ro)



Hydrocarbon Volume Calculation



Reference from: Volumetric Calculation of Hydrocarbons Generated, page 323, AAPG Mem60

Volume of Hydrocarbon Generated

(M)Mass of Organic Carbon (g) x

(R)

HI mg HC/g

Gross Volume of Rock = 1.97 x 1014 cm3Density of Rock (shale) = 2.5 g/cm3TOC = 10 %

HI(present) = 200 mgHC/gHI (origin) = 500 mgHC/g

hydrocarbon generated = 500-200 = 300 mgHC/g



EXERCISEGiven:

1. Gross Volume of Rock of 1.55 x 109 x 3600 ft3

2. TOC = 10%

3. Density of shale = 2.5 gm/cm3

4. HI 200 mgHC/gReference: Volumetric Calculation of Hydrocarbons Generated, page323, AAPG Mem60



2300m

MASS HYDROCARBON GENERATION

Bulk Rock Volume 1,800,000 MMm3

TOC 1%Type II F(oil) 60%F(gas) 40%

Kerogen Characteristic



TOC 1%

Type II

F(oil) 60%

F(gas)40%

@ 2300m

Bulk Rock Volume 1,800,000 MMm3

MASS Hydrocarbon Generated

OIL 43,000 MMBBL

GAS 970 BCF

Expulsion efficiency for oil 65% for gas 80%

Migration efficiency for oil 8%for gas 80%

Mass HC generated (Oil) subjected to traps 2,300 MMBBL

Mass HC generated (Gas) subjected to traps 620 BCF



Oil 43,000 MMBBLGas 970 BCF

Expulsion Efficiency (OIL) 65%(GAS) 80%



Migration Efficiency (OIL) 8%(GAS) 80%

From 2300m

In source beds To carrier bedsReady for accumulation



GAS FIELD SIZE DISTRIBUTION



Oil Field Size DistributionOil Field Size Distribution



MIGRATION



GAS



GAS

Differential entrapment by Gussow (1954)



GAS

Differential entrapment by Gussow (1954)



HYDROCARBON FLUIDS

GAS

OIL/CONDENSATE



CO2


Applications of Geochemistry to Source Rock AppraisalsWell / Area : WELL SP1Sample Type : GasFile No. : GSI-01207

TABLE 10GAS STABLE ISOTOPE COMPOSITION DATA

° 13C ° 13C ° 13C ° 13C ° 13C ° 13C °DSample ID Depth methane ethane propane butanes carbon dioxide methane Gas(Cyl. No.) (mMD/mTMD-RT)* (C1) (C2) (C3) (iC4) (nC4) (CO2) (C1) Wetness

(‰) (‰) (‰) (‰) (‰) (‰) (‰) (%)

TST-3 (TS-)8412 1221.0 - 1238.0 -37.11 -29.93 -28.29 -30.15 -28.13 -10.49 -221 25.62RFT-4 (PTK-003) 1495.5 -33.80 -28.62 -28.33 -29.00 -29.35 -3.22 -195 8.63RFT-3 (PTK-001) 1598.0 -33.29 -28.40 -26.52 -27.59 -27.01 -7.18 -195 8.06RFT-4 (PT-120) 1683.0 -33.24 -26.94 -27.33 -28.81 -27.18 -5.39 -197 9.72

TST-2 (TS-)5815 2000.0 - 2012.0 -32.88 -27.57 -23.92 -22.35 -24.01 -7.64 -197 9.57TST-1 (TS-)3006 2335.5 - 2353.5 -36.20 -28.18 -24.89 -24.75 -23.56 -10.35 -199 27.08

* TST sample depth unit: mMD

RFT sample depth unit: mTMD-RT



Basement

Arthit-15-1X

Arthit-15-4X Arthit-15-6X

0 20 40 60 80 100-3,100

-3,000

-2,900

-2,800

-2,700

-2,600

-2,500

-2,400

-2,300

-2,200

-2,100

-2,000

-1,900

-1,800

-1,700

-1,600

-1,500

-1,400

-1,300

-1,200

-1,100

-1,000

0 20 40 60 80 100-3,100

-3,000

-2,900

-2,800

-2,700

-2,600

-2,500

-2,400

-2,300

-2,200

-2,100

-2,000

-1,900

-1,800

-1,700

-1,600

-1,500

-1,400

-1,300

-1,200

-1,100

-1,000

0 20 40 60 80 100-3,100

-3,000

-2,900

-2,800

-2,700

-2,600

-2,500

-2,400

-2,300

-2,200

-2,100

-2,000

-1,900

-1,800

-1,700

-1,600

-1,500

-1,400

-1,300

-1,200

-1,100

-1,000

FM3

2E

2D

2C

FM1

2A

2B

CO2 Distribution

WELL A WELL B WELL C

Inorganic CO2 migration relates Directly to distance from the basement ????

WELL CWELL A WELLB



A crossplot between CO2 content and stable carbon isotopePattani and North Malay Basins (Rui Lin, 2001)

-18.00

-16.00

-14.00

-12.00

-10.00

-8.00

-6.00

-4.00

0 10 20 30 40 50 60 70 80 90 100CO2 (mole%)

δ13C

CO 2

Nearby Area INearby Area IINearby Area III

INORGANIC

MIXING

ORGANIC



-100 -80 -60 -40 -20 0Solid Phase Marine

CarbonateDissolved Marine

Bicarbonate

Atmospheric CO2

Metamorphic CO2

Kerogen

Petroleum

Thermogenic CH4

Biogenic CH4

Increasing Maturity

δ13CPDB (%o)

TST#3, WELL SP2

Carbon isotope compositions of major carbon reservoirs

in sedimentary basin (modified from Emery & Robinson, 1993)



Three Possible CO2 ModelsThree Possible CO2 ModelsWELL SP1WELL SP1

36%

11%

85%22%

48%Seq 1

Seq 2

Seq 4 11.7

23.423.321.625.4

75.

8

48.4

46.5

36.2

11.7

23.423.321.625.4

75.2

85.8

48.4

46.5

36.2

0 100Content (%)

Arthit Arthit 1515--33XX

11.7

23.423.321.625.4

75.

8

48.4

46.5

36.2

11.7

23.423.321.625.4

75.2

85.8

48.4

46.5

36.2

0 100Content (%)

Arthit Arthit 1515--33XX

Seq3E

Seq3D

Seq3C

Seq3B

Seq3A

Seq2

Seq136%48%

85%

22%11%

δδ1313C=C=--77Group IGroup I

δδ1313C=C=--2121IIII

Sample analysed δ13C

WELL SP1WELL SP1



The generation of gases from organic matter with temperature(modified from Hunt, 1996)

Rift-source generated very low CO2

SapropelicSource

HumicSource

CO2 CO2

CH4 CH4

20

50

100

150

200

68

122

212

302

392

Tem

pera

ture

(o C) T

emperature ( oF)

Diagenesis

Catagenesis

Metagenesis

Relative yield of gas from organic matter in fine-grained sediments

C2H6+

C2H6+



HYDROCARBON FLUIDS

GAS

OIL/CONDENSATE



OIL/CONDENSATE

CUTTINGS

Extractable Organic Matter

Liquid Chromatography

SAT % ARO % RES % ASP %

Gas Chromatography (GC)

Gas Chromatography – Mass Spectrometry (GC-MS)

Stable Isotope


Applications of Geochemistry to Source Rock AppraisalsCompany : Success OilWell / Area : WELL SP1Sample Type : OilsFile No. : GSI-01207

TABLE 2

TST-1 TST-2 TST-3Component Cyl# TS-3006 Cyl# TS-5815 Cyl# TS-8412

nC5 2.80 1.06 9.41nC6 3.29 1.49 9.21nC7 4.11 2.30 11.00nC8 5.31 3.34 12.05nC9 6.41 4.53 11.22nC10 7.20 6.06 9.92nC11 7.65 7.98 9.78nC12 7.75 9.60 9.08nC13 7.82 10.81 7.27nC14 7.81 11.18 4.39

nC37 0.00 0.00 0.00nC38 0.00 0.00 0.00Total 100.00 100.00 100.00

Pris/Phy 5.95 5.35 3.53Pris/nC17 0.53 0.60 0.72Phy/nC18 0.11 0.17 0.35nC31/nC19 0.00 0.00 0.00CPI 1.39 1.53 2.90

GAS CHROMATOGRAPHY DATA(C5+ WHOLE OIL ANALYSIS: NORMALISED PERCENT)



10000

15000

20000

25000

30000

5 10 15 20 25 30 35 40

Arbitrary Y / Arbitrary X Paged Y-Zoom CURSORFile # 5 = TST4 Res=None

nC15

nC10

nC20

Arthit-15-1XDepth (m) : 2,338Test #4

nC25

nC30

Gas Chromatogram of an Condensate

(note the high pr/ph ratio and declining n-paraffin envelope to n-C30)

Pr

Ph

WELL SP1Condensate , TST #1



Company : Success OilWell / Area : WELL SP1Sample Type : OilFile No. : GSI-01207

13C 13CSample ID Depth Saturates Aromatics Cv(Cyl. No.) (mTMD-RT) ‰ ‰

TST-1 (TS-3006) 2335.5-2353.5 -27.98 -27.23 -1.31TST-2 (TS-5815) 2000.0-2012.0 -27.56 -27.42 -2.80TST-3 (TS-8412) 1221.0-1238.0 -27.76 -27.49 -2.45

TABLE 8CARBON ISOTOPE DATA *



Methane Carbon Isotope vs. Gas Wetnessin the North Malay Basin (Arthit and Nearby Area)

1

10

100

1000

10000

100000

-100.00 -90.00 -80.00 -70.00 -60.00 -50.00 -40.00 -30.00 -20.00

δ13C (o/oo)

C1/

(C2+

C3)

Arthit Nearby Area

BIOGENIC THERMOGENIC

CO2-REDUCTIONMEETHYL

FERMENTATION

Maturation

"Deep" Petroleum System(FM 0)

"Shallow" Petroleum System(FM 2 coals)

Biogenic mixing

Shallow Gas

2A-2C

2D

FM0&1

Methane Carbon Isotope vs. Gas Wetness in N. Malay Basin

Area I Area II



Condensate Source Typing in the Arthit FieldNorth Malay Basin

0

2

4

6

8

10

12

14

16

-34.00 -32.00 -30.00 -28.00 -26.00 -24.00 -22.00 -20.00 -18.00

δ13Coil (o/oo)

Pris

tane

/Phy

tane

Lacustrine Algal Oils

CoalyCondensates

OBM

Condensate Source Typing in North Malay Basin



-32.00 -30.00 -28.00 -26.00 -24.00 -22.00 -20.0013Cs

0

4

8

12

16

Pr/P

h

13Cs and Pr/Ph ratio

Northwestern Java

South Sumatra

Stable Carbon Isotope Composition of Saturate HC vs Pr/Ph

Coal and coaly shale Northwest Java

Lacustrine Northwest Java



Geochemical Correlation

Exploration no guessing



Oil to Oil Correlation

Source Rock – Crude Oil Correlation

Surface Seep – Oil Correlation

Correlation of Gasses

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