N° of Readings

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Petroleum System Modelling applied to the evaluation of HC in Place in

Unconventional Gas Shale prospects

Domenico Grigo 28 April, 2011

PSM PSM applied to Gas Shale Prospect characterisation

Why?

In the first phase of a non american gas shale prospect

evaluation the well data resolution is so large that the normal approach (quantification of well data only) is not enough to describe properly the properties distribution.

The estrapolation of well data to the entire prospect extension can be succesfully supported by the numerical simulation of the natural processes gouverning the properties distribution.

Petroleum System Modelling is the only methodology capable to reproduce natural processes starting from well data at basin scale

American Gas Shale (Barnett) Prospect well data

scale

Non American Gas Shale Prospect well data

250 km

PSM Methods for characterising a Gas Shale

The North American analog

Key characteristics noted about each system (where available)

Time equivalent system Total porosity (%)

Basin Matrix permeability

Age Relative thickness

TOC (%) Reservoir pressure (psi)

Kerogen type Bottom-hole temperature (°C) Kerogen type Bottom-hole temperature (°C) Thermal maturity (%R_o) Depositional setting*

Gas in place (bcf/section) Basin type/ tectonic setting*

Shale gas-in-place resource (tcf) Lithology notes

Absorbed gas (%) Other notes

* Hypothesized as potential common denominator

PSM Methods for characterising a Gas Shale

The North American analog

PSM Gas Shales: unconventional reservoir

Gas accumulation is continuous and not related to buoyancy

The formation is simultaneously source rock and reservoir

Gas presence is not associated to geological traps: the target is a portion of basin

Gas production achieved only with fracture stimulation

Not all the shale gas plays can commercially produce gas Key geological factors are:

Key geological factors are:

TOC >1% with %Ro>1,2

Quality of organic matter: type II kerogene is the most favourable

Vshale<40% → brittleness

Mechanical properties favorable for fracking

Presence of natural fractures that can be reactivated

No producible water

Sealing layers at top and bottom

No potential geological risks, namely faults, karst areas and tectonic complexity

Adequate depth and thikness of the producing play: if overpressured, depth >3500 m can be acceptable

PSM

Gas Shale Maturity

PSM

•Vitrinite Reflectance (Ro%)

records only the maximum temperature reached during burial

•Apatite Fission Track (AFTA)

records also other temperatures but only if Maturity Indicators

0 0.5 1 1.5 2

Vitrinite Reflectance (Ro%)

0 5 10 15 20

N° of Readings

Depth (m): 1892,5 Sample Type: BC Ro=0.60% - Std Dev. =0.06

records also other temperatures but only if younger than the maximun

•Fluid Inclusions (FI)

records all the temperatures

PSM Equivalent Vitrinite Reflectance (Ro %)

Derived by Bitume reflectance

Vitrinite is often scarse in carbonate source rocks. Bitumen can be present in this case, in particular when the maturity level is middle/high.

By the use of Jacob’s formula it is

5

(Jacob & Hiltmann, 1985) it is possible to convert the bitumen reflectance in equivalent vitrinite reflectance value:

Ro eq % = 0.618 R_BIT + 0.40

PSM Equivalent Vitrinite Reflectance (Ro %)

Derived by other organisns

From Suchy et Al. 2004 CAI = Conodont Alteration Index

PSM

This maturity parameter is derived by the Rock-Eval analysis (the analytical technique finalized to source rock evaluation).

Tmax is the temperature at which the maximum of residual petroleum potential (by kerogen pyrolysis) occurs.

T_max = 420 °C Immature sample

S2

Equivalent Vitrinite Reflectance (Ro %) Tmax by pyrolysis Rock-Eval

occurs.

It has not be confused with the maximum temperature (very lower) reached by sample during its burial

T_max = 450 °C

T_max not available

300 400 500

300 °C

Mature sample

Overmature sample

S1

PSM

SURFACE TEMPERATURE

20

70

120

170

220

270 0 50

100 150

Tim e (m a)

Temperature (°C)

H000 H100 H200 H300 H400 H500 H600 GS H800 H900

0

1000

2000

3000

4000

5000

6000 0 50 100 150 200 250

Tem perature (°C)

Depth (m)

Measured Computed

Petroleum System Modelling

Well Temperature & MaturityCalibration

0

1000

2000

3000

Depth (m)

H000 H100 H200 H300

WELL DATA

WELL BURIAL EVALUATION

TEMPERATURE HISTORY

TEMPERATURE MATCHING

HEAT FLOW

0.20

0.70

1.20

1.70

2.20

2.70

3.20 0 50

100

150 Tim e (m a)

Maturity (Ro%)

H000 H100 H200 H300 H400 H500 H600 GS H800 H900

0

1000

2000

3000

4000

5000

6000

0 1 2 3 4

Ro%

Depth (m)

Measured Computed 3000

4000

5000

6000

7000

0 50

100

150 Tim e (m a)

Depth (m)

H300 H400 H500 H600 GS H800 H900

MATURITY HISTORY MATURITY MATCHING

Maturity Computation & Potential Gas Shale definition PSM

1000 km

PSM

Gas Shale Properties

Kerogen PSM

ENVIRONMENT

KEROGEN TYPE

KEROGEN FORM [ MACERAL]

ORIGIN HC

POTENTIAL

Aquatic

I

alginite algal bodies

structureless debris of

GENETIC POTENTIAL

+ +

The potential to generate hydrocarbons and the quality of the products are affected by

On the basis of optical examination and physicochemical analyses, kerogens have been gathered into four main groups:

the quality of the initial kerogen, which is controlled by the quality of the organic input and by the evolution of diagenesis.

Aquatic

Terrestrial

II

III

amorphous organic

matter

exinite vitrinite

cuticle of leaves and herbaceous plants structureless debris of

algal bodies

structureless, planktonic material,

primarily of marine origin

skins of spores and pollen,

fibrous and woody plant fragments and strcturless

collidal humic matter

OIL

GAS AND SOME OIL

--

PSM

At the end of diagenesis,

the organic matter consists mainly of a policondensed structure which is the kerogen.

Steps of Organic Matter evolution

Diagenesis is strongly controlled by the biological activity (bacteria), and by the chemical environment (redox conditions, mineralogy).

-

MACROMOLECULES

INITIAL KEROGEN

early diagenesis

diagenesis

C,H,O,N

C,H,O

N

O

≅≅≅≅ 10 m

THERMAL KEROGENKEROGEN

EVOLUTION

is the kerogen.

Catagenesis and

Metagenesis, are controlled by thermal stress due to burial Both the absolute

temperatures and the heating rate govern the evolution of kerogen transformation.

RESIDUAL KEROGEN KEROGEN

DEGRADATION

catagenesis

metagenesis

C,H

C

H

(after Bordenave, 1993 modified)

THERMAL

+

KEROGEN KEROGEN

PSM

450

950

450

950 450

950

TOC HI TMAX

P F G VG III

S2

F

P G VG II I IMM M V M

FORMATION

MARNES DE MADINGO

DOLOMIE DE LOANGO

GRES DE TCHALA

CARBONATES DE SENDJI _TRACES

KEROGEN COMPOSITION

Source Rock Evaluation

Source rock Evaluation: Geochemical log

Quantitative analysis

Source potential Qualitative analysis

Thermal Maturity

1450

1950

2450

1450

1950

2450 1450

1950

2450

CARBONATES DE SENDJILIFERE DE LOEME

TRACES

TRACES

AOM MPH CHF CWF

Oil prone

PSM Microscope pictures of kerogens

Observation in transmitted white light

Some kerogen types are shown:

_________________

More or less 100 µ

Kerogen optical analyses

3. Kerogen constituted by

Amorphous Organic Matter

(unstructured, unrecognizable OM)

1. Humic Kerogen

(woody fragments, and then vitrinite and others coal macerals)

2. Sapropelic Kerogen

(spores and pollens)

The Seismic view of a Source Rock PSM

PSM

(80-90% shale) (50-80% shale)

Source rock lithological model

(90-100% shale)

PSM

OF-Mod 3D:

is a process-based software, which reproduce the development and the variation of organic facies in a 3D volume.

TOM supply

fluvial sediment and nutrient supply 11

primary productivity PP (g C·m^-2·a^-1) CO₂+ H₂O CH₂O + O₂

Organic matter deposition & preservation modelling

degradation

carbon flux Fc

water depth (m)

epibenthic respiration

* * *

*

*

* *

*

* *

* *

* *

*

* **

* *

* *

*

*

* * *

* *

* *

* **

*

*

** *

* *

*

erosion, bypass and sedimentation processes

* * * * ***

*

* *

* * * *

* *

Ctot: 7 wt%

OF: C - A Ctot: 10 wt%

OF: B PP = 250 - 300g C·m^-2·a^-1

PP = 50 – 60 g C·m^-2·a^-1 * PP = 100 - 250g C·m^-2·a^-1

Ctot: 0.3 wt%

OF: D

Ctot: 1-3 wt%

OF: BC-C MOC (oxic) = Fc · BE · dilution

22 22

33 44

55

66

* * *

* * ** *

**

* **

* *

* *

* *

*

* *

MOC (anoxic)= PP · PF · dilution

* *

* *

* * *

*

*

*

*

*

* *

* *

* * * * *

BFM burial efficiency BE

* *

*

*

* *

*

*

*

* *

** *

4 4

CO₂+ H₂O CH₂O + O₂

* *

* *

PSM Final Outcome:

Gas Shale Thickness & Original properties definition

Original TOC=15%

Original HI=350 mgHC/gTOC

1000 km

PSM Final outcome:

Gas Shale Depth & Burial Evolution

PSM

Gas Shale original Gas in place

PSM HC genaration simulation

Experimental Kinetic Parameters

The parameters defining the reaction scheme are determined experimentally degrading thermically the kerogen samples with the MSSV (Micro Scale Sealed Vessel) pyrolysys experiments

ACCORDING TO A KINETIC SCHEME ACCORDING TO A KINETIC SCHEME

OPTIMIZATION OF RESULTS OPTIMIZATION OF RESULTS

USE IN THE USE IN THE USE IN THE SIMULATION OF SIMULATION OF SIMULATION OF HC GENERATION HC GENERATION HC GENERATION AND EXPULSION AND EXPULSION AND EXPULSION

PSM Calibration of the Kinetic Model

Original properties definition

Av. Source Rock Maturity 1.6 Ro%

4400

4420

4440

0 1 10 100

TOC (%)

Depth (m)

Measured Computed

4400

4420

4440

1 10 100 1000

HI mgHC/gTOC

Depth (m)

Measured Computed

MODELLED GAS SHALE 15 % TOC – HI 350

mgHC/gTOC 38 m

4460

4480

4500

4520

Depth (m)

Computed

4460

4480

4500

4520

Depth (m)

Computed

PSM

GENERATED GAS EXPELLED GAS GENERATED GAS EXPELLED GAS

Expulsion Simulation Why ?

Between Generation and Expulsion of HC a time gap can exists but also a volume gap due to the un-expelled HC remaining in the

PSM Final outcome:

Gas Shale OGIIP Volumes by area

The same process of evaluation can be applied at any scale from the basin to the block following the maturation of the Gas

1000 km

maturation of the Gas Shale exploration

project