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Modelingsourcerockdistribution,thermalmaturation,petroleumretentionandexpulsion:TheCaseoftheWestern...

Poster·April2016

DOI:10.13140/RG.2.1.4506.9201

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Modeling source rock distribution, thermal maturation, petroleum retention and expulsion: The Case of the Western Canadian Sedimentary Basin (WCSB)

Geological settings of the WCSB Foreland basin limited to the East by the Precambrian Canadian

Shield and to the West by the Canadian Cordillera (Fig. 2).

3 major periods:

Paleozoic to early Mesozoic time: sedimentation on the western

margin of a stable craton dominated by carbonate deposits.

Jurassic to Paleocene: clastic sedimentary wedge induced by

the formation of the Cordillera and its associated foreland basin.

From Paleocene onward: Erosion and sediment by-pass

(Laramide Orogeny).

Focus on Montney and Doig Formations (Fig. 3):

Siliciclastic sediments of the Triassic succession.

They rest unconformably on the Permian Belloy Formation.

The Upper boundary of the Triassic is a major unconformity

related to the formation of the Canadian Cordillera.

In the Eastern part, they are capped by the organic-rich shale of

the Nordegg Formation.

In the Western part, they are overlaid by the proximal sandy

deposits of the Middle Triassic Halfway Formation.

Introduction Basin modeling is a multi-disciplinary approach

integrating varied sources of geological data.

Therefore, the main objective is to build models

consistent with the available information.

For instance, input parameters such as heat flow

and initial TOC must be first calibrated at the

location of wells and extrapolated on maps taking

into account available geological, biological or

geochemical concepts.

We present solutions that allow to produce

calibrated and geologically meaningful maps of

heat flow, initial TOC and hydrogen index based on

both well measurements and on the geological

information included in the basin model.

They are applied on a large scale basin model of

the WCSB (800km x 1300km) using TemisFlow®

(Fig. 1). A focus is done on the Montney and

Nordegg source rocks intervals and on the

unconventional petroleum system of the Montney

Formation.

Fig. 3: Cross section presenting the main stratigraphic intervals of the WCSB.

Fig. 1: 3D model of the Western Canadian Sedimentary Basin.

(34 stratigraphic units with a 5km cell resolution).

Fig. 2: Location of the simulated 3D and 2D models

in the Western Canadian Sedimentary Basin

Stanislas Pauthier1, Mathieu Ducros1, Benoit Chauveau1, Tristan Euzen2, William Sassi1 1 IFP Énergies nouvelles, Geosciences Division, Rueil Malmaison, France

2 IFP Technologies (Canada) Inc., Calgary, AB, Canada. Contact: mathieu.ducros@ifpen.fr

Methodology and modeling workflow

TOC0,HI0

Geological 4D model

(facies, bathymetry, thickness and

sedimentation rate, well data, …)

Source rock maturity

Petroleum retention (organic

porosity, adsorption)

and expulsion

Conventional and unconventional

petroleum systems analysis

Pressure , migration

and HC alteration

Uncertainty

and risk

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Very prolific basin Duvernay (Devonian, Type II)

Exshaw-Bakken (Devonian, Type II

Montney (Triassic, Type II)

Phosphatic Doig (Triassic, Type IIS)

Nordegg-Gordondale (Jurassic, Type IIS)

Poker Chip (Jurassic, Type II)

Mannville Coals (Cretaceous, Type III)

Estimation of initial SR potential Estimation of initial TOC (TOC0) and HI (HI0) maps of

marine organic matters is performed based on

geological and biological considerations (Fig. 5).

Inputs:

Modern TOC and HI measured at wells

Paleobathymetry

Sedimentation rate.

Outputs:

Estimated TOC0 and HI0 at well locations.

Maps of TOC0 and HI0 at basin scale.

Fig. 5: Forward model for estimation of TOC0 and HI0 of

from marine organic matter (MOM) as a result of

primary productivity (PP0) and degradation processes.

Degradation along the water column is estimated from

Martin’s law (1987): the effective organic flux of organic

matter (PPz) at the water/sediments interface is a

function of the bathymetry and of the primary

productivity (PP0). Finally, early diagenesis is estimated

from the burial efficiency (i.e. sedimentation rate and

redox conditions, Burdige , 2007)

Fig. 4: Estimation of TOC0 and HI0 maps consists in two main steps:

• An optimization of the biological (PP0) and chemical conditions

(Ox0) using well data.

• An extrapolation to basin scale based on the maps of bathymetry,

and sedimentation rate and on the optimized PP0 and Ox0.

Fig. 7: Initial source rock richness (TOC0 and HI0) of the Montney and

Nordegg Formations. Dilution processes strongly control The

Montney Formation initial richness (TOC0, top left), while the richness

of the Nordegg Formation is more strongly controlled by

paleobathymetry (bottom left).

Fig. 6: Geological settings associated to the deposition of the Nordegg

and Montney organic-rich Formations. The Montney Formation exhibits,

relatively to source rocks, high sedimentation rates (from 20m/My to

more than 60m/My, top left) whereas low sedimentation rates (<5m/My)

characterize the Nordegg Formation (bottom left).

Sedimentation rate

(m/My)

Bathymetry

(m)

TOC0

(%)

HI0

(mgHC/gC)

Mo

ntn

ey F

orm

ati

on

N

ord

eg

g F

orm

ati

on

Focusing on the Montney and Nordegg Formations

• Type II (low TOC and

oxic conditions)

• Calibration from 7 wells

• Type II/IIS (high TOC

and anoxic conditions)

• Calibration from 34

wells

Source rock richness at basin scale

TOCPD and HIPD

Chemical and biological conditions

(Ox0, PP0)

Simulation of TOC0 and HI0 at wells locations (TOC0S, HI0S) = function( sedimentation rate bathymetry biological conditions chemical conditions )

Computation of TOC0C

Computation of the error function Error = function(TOC0S – TOC0S)

Sedimentation rate and bathymetry

TOCOC

Optimization of (Ox0, PP0)

PP0: primary productivity Ox0: basin scale redox conditions TOCPD: present day TOC HIPD: present day HI TOCOS: simulated initial TOC HIOS: simulated initial HI TOCOC: computed initial TOC

Optimized (PP0, Ox0)

Sedimentation rate and bathymetry maps

Computation SR distribution and richness at basin scale

HIOs

TOCOC

References Burdige, D. J.(2007). Preservation of Organic Matter in Marine Sediments: Controls, Mechanisms, and an Imbalance in Sediment Organic Carbon Budgets? Chem. Rev., 107,

pp. 467-485 Crombez, V., PhD Thesis, 2016.

Ducros, M., Euzen, T., Crombez, V., Sassi, W. and Vially, R., 2016, 2-D basin modeling of the WCSB across the Montney-Doig system: implications for hydrocarbon migration

pathways and unconventional resources potential, AAPG Memoir.

Martin, J.H., Knauer, G.A., Karl, D.M., Broenkow, W.W., 1987, VERTEX: carbon cycling in the northeast Pacific. Deep-Sea Res. 34: 267-285.

Mossop, G.D. and Shetsen, I., 1994. Geological atlas of the Western Canada Sedimentary Basin. Canadian Society of Petroleum Geologists and Alberta Research Council

Romero-Sarmiento, M.F., Ducros, M., Carpentier, B., Lorant, F., Cacas, M.C., Pegaz-Fiornet, S., Wolf, S., Rohais, S. and Moretti, I., 2013, Quantitative evaluation of TOC,

organic porosity and gas retention distribution in a gas shale play using petroleum system modelling: Application to the Mississippian Barnett Shale. Marine and Petroleum

Geology, 45, 315-330.

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Thermal calibration method It aims at taking the best of the geological knowledge, synthetized in

the geological model, and of automated well calibration:

Fig. 9: Present day heat flow maps before (a) and after calibration (b).

a b

Cru

st

+ s

ed

ime

nts

3D simulation including the

sedimentary and crustal models

Heat flow in time and space

(Fig. 9a) representative of the

geology (heterogeneities,

blanketing and tectonic

effects…)

Automated

well calibration

Finally both information is

combined to provide

geologically constrained heat

flow maps calibrated at well

locations (Fig. 9b).

Petroleum System modeling

Source rock maturity, petroleum retention and expulsion

Organic porosity creation and compaction

Organic porosity can represent

as much as 28% of the porosity

in the Montney Fm. (Fig. 12 left).

Its compaction depends on

burial and maturity evolution.

The Nordegg Fm. (Type II/IIS),

more reactive, is more affected

than the Montney Fm. (Fig. 13).

Adsorption

Maturity

Fig. 10: Maturity maps (VRo%) of the Montney (left) and

Nordegg Formations (right)

Fig. 11: Fraction of adsorbed gas

in the Montney Formation

Fig. 12: Fraction of organic porosity in the Montney Formation (left).

Fraction of expelled oil resulting from organic porosity compaction (center)

and expelled oil mass (kg/m²) in the Nordegg Formation (right).

Fig. 8: Workflow of thermal calibration.

Fig. 13: Evotution of organic porosity as a function of SR maturity

Results show that, for both the Montney and Nordegg Formations,

maturity ranges from immature at the unconformity edge in the NE to

gas window in the deep basin close to deformation front in the SW (Fig.

10). A wide area of the Nordegg Formation, one of the main source of

conventional accumulations is in the oil window.

Adsorption plays a key role on gas retention into the source rock as

adsorbed gas represent more than 20% of gas in place even in deeper

and more mature areas of the Montney Fm. (Fig. 11).

Conclusions New methods were applied to better characterize and predict key controlling factors such as organic matter distribution, paleo-heat

flow and retention mechanisms.

Mechanisms specific to hydrocarbon retention (adsorption, organic porosity) were simulated and improved (organic porosity

compaction) for better petroleum systems analysis.

More predictive source rock and maturity distributions for a better analysis of sweet spots

Better HC expulsion towards conventional reservoirs (strong compaction of organic porosity in the Nordegg Fm.)

Strong contribution of organic porosity and adsorption on HC retention in the Montney Fm.

First 4D basin model of the WCSB covering both Alberta and British Columbia for assessment of conventional and unconventional

petroleum resources.

Perspectives Stratigraphic models including carbonates, silici-clastic and organic matter deposition

Migration and natural hydraulic fracturation (Fig. 14)

Hydrocarbon alterations (TSR, biodegradation…)

Mapping of sweet spots using cutting edge probabilistic techniques

All information available on the Joint Industry Project RAMPS on prospect analysis of the WCSB

(Contact: William.Sassi@ifpen.fr or Tristan.Euzen@ifp-canada.com) Fig. 14: HC saturation (%) pervasive gas accumulations

in the tight reservoirs of the Montney Fm.

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