U.S. Department of the Interior

U.S. Geological Survey

Petroleum System Modeling Capabilities

for Use in Oil and Gas Resource Assessments

Open-File Report 2006–1024

Present-day catchments on the 

N

Upper Cretaceous Viking 
Petroleum System Modeling Capabilities 

for Use in Oil and Gas Resource 

Assessments

By Debra K. Higley, Michael Lewan, Laura N.R. Roberts, and Mitchell E. Henry

Open-File Report 2006–1024

U.S. Department of the Interior

U.S. Geological Survey
U.S. Department of the Interior

Gale A. Norton, Secretary

U.S. Geological Survey

P. Patrick Leahy, Acting Director

U.S. Geological Survey, Reston, Virginia: 2006

Posted online March 2006

Version 1.0

This publication is only available online at

http://www.usgs.gov/of/2006/1024/

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Although this report is in the public domain, permission must be secured from the individual copyright owners to 

reproduce any copyrighted materials contained within this report.

Suggested citation:

Debra K. Higley, Michael Lewan, Laura N.R. Roberts, and Mitchell E. Henry, 2006, Petroleum System Modeling

Capabilities for Use in Oil and Gas Resource Assessments: U.S. Geological Survey Open-File Report 2006-1024
iii

Contents

Executive Summary.......................................................................................................................................1

Introduction.....................................................................................................................................................2

Computer Requirements...............................................................................................................................3

1-D Modeling ..................................................................................................................................................4

Background............................................................................................................................................4

Recommended Data.............................................................................................................................4

Time, Equipment, and Personnel Requirements..............................................................................5

Advantages of Using 1-D Models ......................................................................................................5

Limitations of 1-D Modeling ................................................................................................................5

2-D Modeling ..................................................................................................................................................9

Background............................................................................................................................................9

Recommended Data.............................................................................................................................9

Time and Personnel Requirements....................................................................................................9

Advantages of Using 2-D Models ......................................................................................................9

Limitations of 2-D Modeling ..............................................................................................................10

3-D Modeling ................................................................................................................................................11

Background..........................................................................................................................................11

Requirements for 3-D Modeling .......................................................................................................11

Time and Personnel Requirements..................................................................................................15

Advantages of 3-D Models................................................................................................................15

Requirements and Limitations of 3-D Modeling ............................................................................16

Conclusions...................................................................................................................................................17

Acknowledgements.....................................................................................................................................17

References....................................................................................................................................................17

Figures

1. Example of a template used for input to the PetroMod® one-dimensional

modeling program.........................................................................................................................6

2. Events chart showing petroleum systems elements of the Lower

Cretaceous Mannville Formation, Western Canada Sedimentary Basin............................7

3. Plots showing burial history of the Tomahawk 16-18 well, northern Alberta .....................8

4. Map showing two-dimensional flowpaths and accumulations of oil and gas

in the Lower Cretaceous Mannville Group.............................................................................10

5. Block diagram with a front-facing east-west cross section that depicts all

geologic intervals used in the three-dimensional model across northern Alberta.........12

6. Map view of early generation and emplacement of hydrocarbons into the

Lower Cretaceous Mannville Group to form tar sands ........................................................13

7. Three-dimensional diagram showing Jurassic Nordegg Member source rocks............14 
Executive Summary

Petroleum resource assessments are among the most highly 

visible and frequently cited scientific products of the U.S. Geological Survey. The assessments integrate diverse and extensive 

information on the geologic, geochemical, and petroleum production histories of provinces and regions of the United States 

and the World. Petroleum systems modeling incorporates these 

geoscience data in ways that strengthen the assessment process 

and results are presented visually and numerically. The purpose 

of this report is to outline the requirements, advantages, and limitations of one-dimensional (1-D), two-dimensional (2-D), and 

three-dimensional (3-D) petroleum systems modeling that can 

be applied to the assessment of oil and gas resources. Primary 

focus is on the application of the Integrated Exploration Systems (IES) PetroMod® software because of familiarity with that 

program as well as the emphasis by the USGS Energy Program 

on standardizing to one modeling application. The Western 

Canada Sedimentary Basin (WCSB) is used to demonstrate the 

use of the PetroMod® software.

Petroleum systems modeling quantitatively extends the 

“total petroleum systems” (TPS) concept (Magoon and Dow, 

1994; Magoon and Schmoker, 2000) that is employed in 

USGS resource assessments. Modeling allows integration of 

state-of-the-art analysis techniques, and provides the means 

to test and refine understanding of oil and gas generation, 

migration, and accumulation. Results of modeling are presented visually, numerically, and statistically, which enhances 

interpretation of the processes that affect TPSs through time. 

Modeling also provides a framework for the input and processing of many kinds of data essential in resource assessment, 

including (1) petroleum system elements such as reservoir, 

seal, and source rock intervals; (2) timing of depositional, 

hiatus, and erosional events and their influences on petroleum 

systems; (3) incorporation of vertical and lateral distribution 

and lithologies of strata that compose the petroleum systems; 

and (4) calculations of pressure-volume-temperature (PVT) 

histories. As digital data on petroleum systems continue 

to expand, the models can integrate these data into USGS 

resource assessments by building and displaying, through 

time, areas of petroleum generation, migration pathways, 

accumulations, and relative contributions of source rocks to 

the hydrocarbon components. 

IES PetroMod® 1-D, 2-D, and 3-D models are integrated 

such that each uses the same variables for petroleum systems 

modeling. 1-D burial history models are point locations, mainly 

wells. Maps and cross-sections model geologic information 

in two dimensions and can incorporate direct input of 2-D 

seismic data and interpretations using various formats. Both 

1-D and 2-D models use data essential for assessments and, 

following data compilation, they can be completed in hours and 

retested in minutes. Such models should be built early in the 

geologic assessment process, inasmuch as they incorporate the 

petroleum system elements of reservoir, source, and seal rock 

intervals with associated lithologies and depositional and erosional ages. The models can be used to delineate the petroleum 

systems. A number of 1-D and 2-D models can be constructed 

across a geologic province and used by the assessment geologists as a 3-D framework of processes that control petroleum 

generation, migration, and accumulation. The primary limitation of these models is that they only represent generation, 

migration, and accumulation in two dimensions. 

3-D models are generally built at reservoir to basin scales. 

They provide a much more detailed and realistic representation of petroleum systems than 1-D or 2-D models because 

they portray more fully the temporal and physical relations 

among (1) burial history; (2) lithologies and associated changes 

through burial in porosity, permeability, and compaction; (3) 

hydrodynamic effects; and (4) other parameters that influence 

petroleum generation, migration, and accumulation. Considerably more time, data, and computer resources are required than 

for 1-D or 2-D models. These factors are dependent upon data 

quality and quantity, and the size and complexity of the model. 

3-D models are built using structural and isopach surfaces that 

are selected based on criteria such as chronostratigraphic divisions, petroleum system boundaries, major tectonic events that 

influenced thermal history, or other criteria, with the data being 

derived from sources that include well databases, maps, and 

(or) cross sections. Upon completion of a 3-D model, geoscientists can apply the results to refining petroleum systems, 

evaluating timing of oil and (or) gas generation, migration, 

and accumulation relative to trap formation, and other factors 

important to resource assessments. Modifications of models 

can generally be done in minutes; however, rerunning the 

models with new parameters may take hours to days depending 

upon complexity and the computer platform(s) used.

Petroleum System Modeling Capabilities for Use in 

Oil and Gas Resource Assessments

By Debra K. Higley, Michael Lewan, Laura N.R. Roberts, and Mitchell E. Henry
Although not required, 1-D, 2-D, and 3-D models can be 

externally calibrated using information from maps and cross 

sections, vitrinite reflectance (Ro) and other thermal maturation data, and temperature and pressure data. Various default 

and user-defined kinetic algorithms can be assigned to source 

rock intervals to model primary oil and gas generation and 

secondary oil cracking. Normal and wrench faults can be open 

or closed for variable time periods. High-angle reverse faults, 

as along the eastern boundary of the Canadian Rockies in the 

WCSB, can be incorporated as a series of vertical faults that 

are horizontally connected across layer boundaries. Variable permeability, including shale-gouge properties, can be 

assigned to the fault systems to model the effects on hydrocarbon migration.

Following is a list of some variables integrated through 

time, as well as results from 3-D petroleum systems models 

and to a lesser extent 1-D and 2-D models. Many of these 

parameters can be risked using the IES PetroRisk® module. 

PetroRisk enables users to define boundaries and distributions 

of variables such as thickness and organic-matter richness of 

source rock, reservoir and trap geometry, porosity, permeability, seal integrity, and timing of oil and gas generation and 

migration. These distributions are then sampled using Monte 

Carlo, Latin Hypercube, and other methods, and multiple processing runs then enable statistical evaluations and correlations 

of the results to be made in order to assess the effects of the 

uncertainties of the data on the results of the modeling. Results 

then include some of the following:

1. Timing and extent of thermal maturation for each 

source rock interval. The 3-D model displays this 

information as map images, cross sections, or as point 

sources through 1-D extractions.

2. Migration flowpaths and vectors in 2-D or 3-D space, 

which show time increments of generation, directions 

of flow, and accumulations of oil and gas.

3. Percent contributions and volumes of generated 

hydrocarbons through time for each source rock unit. 

Results are tabulated and displayed at scales ranging 

from single accumulations to the entire model.

4. Percent transformation of kerogen in source rocks to 

oil and (or) gas. The extent of kerogen transformation 

is a record of the petroleum generation history that is 

displayed visually and in tabular form.

5. Coal rank through time can be evaluated using Sweeney and Burnham (1990) Easy%Ro

, adsorption mass, 

and other modeled calculations. Results could be 

used to assess coal and coalbed methane resources; 

amount of adsorbed methane commonly increases 

with coal rank.

6. PVT calculations for all intervals, including capillary, 

lithologic, and hydrodynamic pressure. These values 

can be used to predict the formation volume factor 

(FVF) for oil and gas, and possibly fluid composition, 

gas-oil ratios, condensate occurrences, and pressure history. Hydrocarbon composition and volumes 

are calculated by PetroMod® for both surface and 

subsurface conditions. This information is useful for 

assessing conventional as well as unconventional 

resources.

7. Compaction history using default values assigned by 

PetroMod® or user-defined porosity/permeability/

depth through time can be used for the lithologies. 

Analogs can be applied for this and numerous other 

parameters in the modeling.

8. Catchments are structural segmentation of layers in 

a model that are primarily used to show oil and gas 

migration pathways, spillpoints, and accumulations 

across these surfaces. 

9. Timing of hydrocarbon generation relative to trap 

formation. Also, effects on hydrocarbon migration of 

events such as faulting, basin uplift and tilting, salt 

movement, and intrusions.

Introduction

The methodology used by the U.S. Geological Survey 

(USGS) in assessing undiscovered conventional and unconventional hydrocarbon resources evolves with increased 

understanding of controls on petroleum generation, migration, 

accumulation, and production. One-dimensional (1-D), twodimensional (2-D), and three-dimensional (3-D) petroleum 

systems modeling are tools for the assessments. The modeling 

and the assessments both apply the petroleum systems concept 

(Magoon and Dow, 1994; Magoon and Schmoker, 2000) 

to vertically and laterally divide provinces into mappable 

volumes of rocks that share a common history of generation, migration, and accumulation of petroleum. Much of this 

information is analyzed by USGS geoscientists by integrating 

data at well-to-basin scales, review of publications on these 

and similar areas, and use of analogs for strata in frontier 

areas. USGS assessments are increasingly data intensive; it is 

therefore important to integrate these data in ways that best 

show the interconnection of petroleum system processes, 

with results that can be presented to a broad audience. These 

models allow geoscientists to evaluate the consistency of their 

interpreted and the simulated basin history.

Use of PetroMod® in USGS assessments is being evaluated in this report because it is currently being used in research 

studies of the Western Canada Sedimentary Basin (WCSB), as 

well as in resource assessments of provinces worldwide. Petroleum systems modeling software is used to reconstruct the 

geologic history at point, reservoir, and basin scales. Modeling 

uses the following data that contribute to assessment of oil and 

gas resources:

 Petroleum System Modeling
1. Locations, depths, and areal distribution of all strata 

can be derived from a number of sources that include 

well logs, databases, published maps and cross sections, and seismic surveys.

2. Ages and lithologies for all formation intervals 

within the study area. A spreadsheet that contains 

these data, time periods of erosion and tectonic 

events, and associated references is useful for subsequent grouping of these formations into intervals 

for the petroleum systems model. The modeling 

process does not require grouping of strata into 

petroleum systems or determination of petroleum 

system boundaries, although it is helpful to compare 

the expected boundaries to those interpreted from the 

modeling results.

3. In order to apply results of the modeling to relative 

contributions through time of source rock intervals 

to generated, migrated, and accumulated oil and (or) 

gas, required input data for source rocks includes 

kerogen types, total organic carbon (TOC), hydrocarbon indices (HI), and kinetic algorithms. It is best to 

have results of pyrolysis analyses on immature source 

rocks in each modeled province or area; however, 

analogs can be also used for these variables.

4. Time periods and areas of nondeposition, uplift, and 

erosion. Eroded thicknesses can be estimated using 

1-D and 2-D models, and 1-D extractions from the 

3-D model.

5. Vertical and lateral extent of faults, timing of onset of 

faulting, and assignment of whether faults or segments of faults are open or closed.

6. Surface and subsurface temperatures through time, 

including heat flow history. These values can also be 

generated using PetroMod®, but it is useful to have 

external sources of data to document and calibrate the 

1-D, 2-D, and 3-D models. 

7. Water depth through time.

8. These data are useful for external calibration of the 

models: corrected borehole or drillstem test temperatures, and vitrinite reflectance (Ro

), time-temperature 

indices, fission track, or other thermal maturation 

data.

Reservoir- to province-scale regions are divided on the 

2-D map and 3-D models into catchments; these are structurally-determined outlines of areas for oil and gas migration 

and accumulation. The accuracy of the area of each catchment depends partly on the grid spacing of the layers in a 

model, which can be changed by the user. Finer spaced grids 

in the generated model result in more detailed division of the 

catchments. Catchments in the Illinois Basin were mapped 

using an inverted hydrologic-flow algorithm using ESRI 

Arc® software (Lewan and others, 2002; Higley and others, 

2003). Use of the catchments can assist resource assessment 

by illustrating potential areas for hydrocarbon accumulation, 

based on whether (and when) oil and gas migrated through 

or were trapped within them. Maps and cross section models 

can incorporate 2-D flow of fluids. PetroMod® software, 

for example, models vertical and (or) lateral flow through 

strata and along faults and other surfaces. Vertical and lateral changes in lithology and associated physical properties 

can be assigned to geologic intervals, or layers, within the 

models.

PetroMod® has functions for generating, editing, and 

gridding maps and model intervals. These operations were 

conducted outside PetroMod® using ESRI® Arc® software 

or geologic mapping software, such as Dynamic Graphics®

EarthVision®. (Note: Dynamic Graphics and Earthvision® are 

registered trademarks of Dynamic Graphics, Inc.) Because 

these maps and associated data were used for other assessment purposes, as well as for building a 3-D geologic model, 

it was more efficient to generate and edit the layers for 2-D 

and 3-D petroleum systems models outside of PetroMod®. 

The resulting grids or the 3-D geologic Earthvision® model 

are then imported directly into the PetroMod® models. PetroMod® also has modules that allow for direct import of 2-D 

seismic data and interpretations, and allows for a number of 

seismic data formats. Grids need to be exported from Earthvision® in zmap format to be read using PetroMod®. Zmap is 

an ASCII file format that contains a header record, and grid 

node values in rows and columns 

Modifying and rerunning 1-D and 2-D models can be 

accomplished in minutes. It is also relatively easy to modify 

3-D model parameters, but considerable computer time is 

needed to run full 3-D models. This time can be minimized 

by selecting small areas of the model for separate runs, often 

individual catchment areas, which is useful for evaluating 

effects of the modifications. Deactivation of 2-D and 3-D 

hydrocarbon generation and migration results in a faster 

run-time for the 3-D model, which is useful for calibrating 

geologic and tectonic events and surfaces.

Computer Requirements

IES software is supported on Windows XP®, Linux®, 

and UNIX® operating systems on PC, Silicon Graphics 

Incorporated® (SGI), and Sun® computer platforms. The user 

interface and data formats are the same for all platforms. 

Relatively small amounts of disk space and computer time 

are needed to generate 1-D or 2-D models, which can be 

run on any of the computer platforms. Generation of 3-D 

models, on the other hand, requires considerable memory, 

processing time, and storage space; a petroleum systems 

model at a province scale is preferably generated using a 

Linux cluster of linked PCs because of the shorter computing and display time provided by multiple processors. The 

Computer Requirements 
Sun and SGI platforms can also be used to run 3-D models, 

but long processing time and memory limitations may 

require the model to be simulated at lower resolution. The 3-

D model of Iraq was simulated using one processor on a Sun 

Solaris computer (Pitman and others, 2003); the province 

was divided into 5 models so that 1-km grid spacing could 

be used. Computing capabilities may not be adequate to 

process or view the full 3-D PetroMod® models at very fine 

grid spacing. Options are multi-1-D processing for generation potential calculations, or full-scale models with coarser 

grids, such as 15-km spacing; smaller areas of interest can 

then be modeled by creating subsets within the province and 

saving them as new models. The advantages of the smaller 

area are faster modification and processing time, better grid 

resolution, the ability to use full 3-D processing, and (or) 

being better able to examine areas of interest within the large 

model. 

An additional cost of using the linked PCs and of the 

second parallel processor on the Sun and SGI systems is that 

IES requires additional parallel processor licenses for each 

additional processor. One issue with the use of multiple processors is additional maintenance by computer support. Also 

required are computer support personnel proficient in Linux 

or UNIX (Sun, SGI) systems and resolving software/hardware 

problems. Software upgrades and bug fixes are commonly 

available for download at the IES website.

1-D Modeling

Background

The primary purpose of 1-D, or burial history, models is 

to reconstruct the geologic history at one or more points in a 

region. The modeling should be incorporated into assessments 

of oil and gas resources. Essentially all of the information 

needed for 1-D burial history modeling is also required in the 

assessment process, and building 1-D models requires scientists to refine the stratigraphy within the province and to assign 

lithologies and age ranges to those intervals important in the 

assessments. Because burial history models are used to define 

petroleum systems, it is not necessary to first assign petroleum 

system elements and boundaries. Assignment of strata to overburden, seal, reservoir, and source intervals, however, is useful 

for a PetroMod®-generated total petroleum systems events 

chart and to tie the models to the assessments. 

The assessment of the Southwestern Wyoming Province 

(Roberts and others, 2004) is a good example of the use of 1-D 

modeling. The models resulted in dating peak oil and gas generation and the times of generation for a series of source rocks 

in the province. Temperature histories, Ro data, and deposition 

and erosional histories were integrated into a series of burial 

history plots and diagrams that illustrate the relative effects of 

these factors on hydrocarbon generation at individual points 

across the province. 

Recommended Data

1. Names of formation intervals. Examples are the name 

of the primary formation or stratigraphic interval 

within that layer, or assigned codes.

2. Well name and latitude-longitude or other map 

coordinate location. If the 1-D burial history models 

are used to calibrate 2-D or 3-D PetroMod® models, 

then all location data should use the same coordinate 

system and parameters.

3. Data sources for formation tops, and well and field 

name and locations include:

a. Publications, cross sections, seismic sections, 

outcrop descriptions.

b. Core descriptions, well logs.

c. State records of drilled water or oil and gas wells.

d. Commercial databases, such as IHS Energy Well 

History Control (U.S.), Accumap (Canada), and 

Petroconsultants well and field databases.

4. Strata depth or elevation relative to sea level. Units 

are meters or feet. Stratigraphic intervals should be 

subdivided if they are very thick and (or) were deposited over a long period of time, especially when there 

are numerous Ro and other thermal maturity data. 

They are best divided if the interval is very heterogeneous— for example, the upper portion is seal, the 

middle is reservoir, and the lower is the hydrocarbon source, or the lithologic variation is significant 

enough to influence model results.

5. Ages of intervals in millions of years before present 

(Ma). Intervals within PetroMod® models can be 

assigned based on chronostratigraphic, lithostratigraphic, major tectonic events, and other criteria.

6. Time periods (ages in terms of Ma) of nondeposition 

or erosion. Estimates of the thickness and lithology 

of eroded sections are useful for comparison to those 

determined using the modeling.

7. Paleowater depth, heat flow, and surface temperature 

through time. Options include using default or userdefined values for these parameters. PetroMod can 

also calculate surface temperature through time.

8. Corrected borehole/drillstem test (DST) temperature 

and Ro can be used for external calibration of the 

models, although it is not required to run the models. 

TOC and HI data are needed for source rock intervals 

if kinetic algorithms are used to model primary and 

secondary generation of oil and gas.

 Petroleum System Modeling
Time, Equipment, and Personnel Requirements

The PetroMod® 1-D software utilizes the same kinetics, 

pressure, lithologies, and other parameters that are used by 

2-D and 3-D modules. The PetroMod® 1-D Express freeware 

is different from the full version, in that default lithologic and 

kinetic parameters cannot be readily changed; it can be downloaded from the IES website (http://www.ies.de/) and used on 

numerous computer platforms. 1-D burial history modeling 

is relatively rapid, requiring several hours to learn and run 

for most people. The modeling could be done either by the 

province geologist, or by someone assigned to this task using 

a 1-D template (fig. 1) that is populated by a geoscientist. 

The primary time constraint in 1-D modeling is compiling the 

model data. Most of this information is needed for assessing 

total petroleum systems, as illustrated in figure 2. If several 

people are conducting 1-D modeling within a basin, it should 

be a coordinated effort with respect to methods used, so as to 

avoid differences in model results.

Advantages of Using 1-D Models

1-D modeling was used in the National Oil and Gas 

Assessment of the Raton Basin-Sierra Grande Uplift Province, 

Colorado and New Mexico (Higley and others, 2005). The 

burial history models showed that Paleozoic formations in the 

deepest part of the Raton Basin were overmature for petroleum generation due to high heat flow and the thermal-blanket 

effects of coal beds in the Cretaceous Vermejo and Cretaceous-Tertiary Raton Formations and thick shale sequences 

in deeper formations. Paleozoic formations were excluded 

as potential reservoir and source rocks largely because of 

the high levels of thermal maturity, combined with CO2 and 

helium production data and the absence of petroleum production. 1-D modeling of 38 wells across the WCSB was used 

to display the burial and temperature history of the basin, 

estimate the timing of oil and gas generation, create an isopach 

of Tertiary to present-day erosion, and calibrate the 3-D model 

(Higley and others, 2005); 1-D extractions from the 3-D model 

were compared to those generated using well data. Figure 3 is 

a burial history model of a well in the WCSB that shows burial 

depth, temperature, and levels of thermal maturation through 

time; Ro and temperature data were used to externally calibrate 

the temperature and thermal maturation. 1-D extractions at 

four well locations from the 3-D model of the San Joaquin 

Basin, California (Peters and others, in press) were used in 

the assessment of oil and gas resources. The models show 

(1) changes through time in burial temperature; (2) levels in 

source rocks of thermal maturation and of (3) transformation 

ratio of hydrocarbon generation; and (4) onset of oil generation and timing of peak generation, and (5) remaining potential 

of the source rock interval. As indicated earlier, 1-D modeling was used in the resource assessment of the Greater Green 

River Basin and Eastern Great Basin Provinces to evaluate 

and display the burial and thermal history, and to estimate the 

timing of oil and gas generation from potential hydrocarbon 

source rocks (Roberts and other, 2004). 

Some of the capabilities of and data needed for PetroMod® 1-D modeling are:

1. Burial histories can be constructed using formation 

contacts from wells, outcrops, seismic sections, publications, or 1-D extracts from 3-D models.

2. Porosity/permeability compaction histories are calculated for a wide range of lithologies. Minimum volume for lithologic components is 5 percent. Analogs 

can also be used for compaction history.

3. The full 1-D modeling package includes calculating 

PVT and providing a range of petroleum generation 

kinetic algorithms; user-defined activation energies 

and transformation ratios for kinetic algorithms can 

also be added.

4. Calculating effects on thermal maturation of processes such as tectonic events, and effects of igneous 

intrusions and salt movement through time.

5. Surface temperature through time can be input by 

users or calculated using the software. This influences levels of thermal maturation of petroleum 

source rocks, as do heat flow and water depth through 

time; these values can be default or user defined.

6. Generated graphics and statistics include depth versus 

Ro and numerous other variables, petroleum system 

events charts, and risked temperature and Ro through 

time and relative to burial depth.

Limitations of 1-D Modeling

The primary limitation to 1-D modeling is that it represents only a point source, and the associated calculations of 

temperature, pressure, and fluid flow are also one dimensional; 

there are no other dimensional controls on these variables as 

there are in 2-D and 3-D modeling. One issue is calibrating 

all petroleum systems models, regardless of the software used 

or whether the model is 1-D, 2-D, or 3-D. Deming (1994) 

attempted to balance temperatures, rates of erosion, thermal 

conductivities of lithologies, Ro, and other parameters for a 

well in the North Slope Basin of Alaska; the primary conclusion was that the burial history of the well could not be 

calibrated, largely because of uncertainty in the accuracy of 

measured values. Factors that influence the accuracy of 1-D 

burial histories in the WCSB include the following:

1. Lithologies are generalized for most intervals 

within 1-D, and particularly within the 2-D, and 

3-D models. This is partly because lithologic 

percentages are assigned for layers within the 

models, which does not allow for heterogeneity. 

1-D Modeling 
Present Deposition Age Erosion Age PetroSys

Essential

TOC[wt%]

Name Top Base Thickness

 ErodedThickness from to from to Lithology 

[meter] [meter] [meter] [meter] [Ma] [Ma] [Ma] [Ma] Elements 

Water depth 0 0 0 0 0Quaternary 20 0 20 1.6 0 SAND&SHAL Overburden Rock 0 Paskapoo 300 20 280 1200 67 57.8 57.8 1.6 SHALE Overburden Rock 0 Battle 740 300 440 72 67 SHALE Overburden Rock 0 Bearpaw 800 740 60 75 72 SHALE Source/Seal Rock 0 Belly River 1093 800 293 79 75 SAND&SHAL Source/Reservoir Rock 0 Lea Park 1210 1093 117 84 79 SHALEsilt Seal Rock 0 U Colorado Gp 1539 1210 329 91 84 SHALEsilt Source Rock 0 Second White Specks 1647 1539 108 96 91 SHALEsilt Source/Reservoir Rock 5.1 Fish Scale Zone 1671 1647 24 97 96 SHALE Source/Seal Rock 3.2 L Viking 1744 1671 73 104 97 SAND&SHAL Reservoir Rock 0 Blairmore 1925 1744 181 119 104 SHALE Source/Seal Rock 0 Jurassic-Miss 1925 1925 0 340 150 LIMEshaly Overburden Rock 0 Pekisko 1992 1925 67

400

345 340

150 119

LIMESTONE Reservoir Rock 0 

Banff 2145 1992 153 357 345 SHALE Source/Reservoir Rock 2 Exshaw 2148 2145 3 363 357 SHALE Source/Seal Rock 0 Wabamun 2348 2148 200 366 363 SHALEsilt Source/Reservoir Rock 0 Calmar 2349 2348 1 367.5 366 SHALE Source/Seal Rock 0 Nisku 2395 2349 46 369 367.5 LIMEshaly Source/Reservoir Rock 0 Ireton 2515 2395 120 371 369 SHALE Reservoir Rock 2.5 Duvernay 2600 2515 85 372 371 LIMEshaly Source/Seal Rock 0 Cooking Lake 2700 2600 100 373 372 LIMESTONE Underburden Rock 0 Beaverhill Lake 2850 2700 150 377 373 LIMEshaly Source/Reservoir Rock 0 Elk Point Gp 2900 2850 50 407 377 LIMEshaly Seal Rock 0 Basal Ss 3500 2900 600 570 407 SAND&SHAL Underburden Rock 0 

3500

Age Water Depth Age SWI [Ma] [meter] [Ma] [celsius

0 0 0 2

70 10 70 2

100 40 100 2570 50 570 

Figure 1. Example of a template used for input to the PetroMod® one-dimensional modeling program. Background grid shows parameters, such as name, depths in meters (or feet), ages in years or millions of years (Ma), lithologies, total organic carbon (TOC) in percent or mg/g of TOC, hydrocarbon name of petroleum kinetic algorithm. The yellow inset grid is a second template for the one-dimensional modeling that includes age ranges of surface feet, surface temperature through time (SWI) in degrees Celsius (or Kelvin, Fahrenheit), and of heat flow (HF) in watts or milliwatts per square meter (mSurface temperature through time can be calculated using the PetroMod® program; water depth, heat flow, and other parameters are supplied by the 
An example of this is the Missippian Exshaw 

Formation, a thin shale and siltstone in the WCSB 

(Lexicon of Canadian Stratigraphy, 1997) that is 

an important hydrocarbon source rock; a change in 

composition from 100 percent shale to 100 percent 

siltstone would influence modeling results and 

accuracy even more if this was a thick unit. In the 

absence of core, well cuttings, or other descriptions, rock compositions are generalized.

2. Accuracy of measured and assigned thermal conductivity of lithologies.

3. Accuracy of the Ro and other analyses used to 

externally calibrate the models to the Sweeney 

and Burnham (1990) Easy%Ro and other model 

calculations.

4. Quality of well temperature data must be evaluated. Borehole temperatures should be corrected and 

should be from deep intervals with longer circulation 

times. Drillstem test temperatures may not need correcting. Hydrologic and hydrothermal flow can also 

influence temperatures.

5. Influence of facies on modeled heat flow and thermal 

maturation. Coal and anhydrite, for example, have 

greater influence on temperatures of underlying formations than do sandstone or limestone.

6. Areas with minimal calibration data, such as Ro, may 

require multiple runs of thermal maturation and heat 

flow to get a best-fit of eroded thickness and levels 

of thermal maturation. The data and results in these 

areas can be risked to show levels of confidence.

0

400

300

200100

50

350250150

Permian

Triassic

Jurassic

Cretaceous

Paleogene

65.5

199.6

145.5

419

354

251

Silurian

Devonian

320

292

E

E

E

E

L

M

L

E

L

M

L

E

L

M

L

E

M

L

E

L

Mississippian

Pennsylvanian

Neogene

23

Pal

Eoc

Olig

Mio Plio

PRESERVATION

CRITICAL MOMENT

GENERATIONTRAP FORMATION

OVERBURDEN ROCK

RESERVOIR ROCK

SEAL ROCK

SOURCE ROCK

FORMATIONS

PETROLEUM

SYSTEM EVENTS

GEOLOGIC

TIME

SCALE

MIGRATION- ACCUMULATION

DUVY EXSH, BAK DOIG NORD MNVL COLO GP. 1 1,2 1 1

Figure 2. Events chart showing total petroleum system elements of the Lower Cretaceous Mannville Formation, Western Canada 

Sedimentary Basin. The critical moment is onset of the Laramide orogeny. The green box is the onset of hydrocarbon generation from 

Jurassic Nordegg Type IIS kerogen, based on hydrous pyrolysis kinetics using the three-dimensional model. The black generation 

onset is from 1-D models for all formations and from Cretaceous formations in the 3-D model. Superscripts refer to (1) Creaney and 

Allan (1990, 1992), and (2) Fowler and Riediger (2000). Abbreviations: COLO GP., Colorado Group; NORD, Nordegg Formation; DOIG, Doig 

Formation; BAK, Bakken Formation; EXSH, Exshaw Formation; and DUVY, Duvernay Formation.

1-D Modeling 
Percent vitrinite reflectance

0.4 – 0.6 1.2 – 1.40.6 – 0.8 1.4 – 1.60.8 – 1.0 1.6 – 1.81.0 – 1.2 1.8 – 2.0

 01,0002,0003,0004,0004,594

BURIAL DEPTH, IN METERS Temperature, in degrees Celsius

Sweeney and Burnham (1990) Easy%R %R

 01,0002,0003,000

AGE, IN MILLIONS OF YEARS

 01,0002,0003,000

DEPTH, IN METERS

0.10 1.00

o

DEPTH, IN METERS

5 80

o

TR

500 400 300 200 100 

Figure 3. Plots showing burial history from Cambrian to Holocene time, based on strata penetrated in the Tomahawk 16-18 well, northern Alberta. Cformations are thermally mature for oil generation; onset of oil generation is about 75 million years ago (Ma) for Devonian Woodbend Group source roCretaceous Mannville Group source rocks. Colors are estimated percent vitrinite reflectance (Ro) of rocks based on modeling using the Sweeney and kinetic algorithm. The red and blue dots on the upper left chart are Ro data from Stasiuk and Fowler, 2002, and Stasiuk and others (2002); these are an the calculated curve. Green dots on the lower left chart are temperatures determined from drillstem test or corrected borehole temperatures; these temperature versus depth calculation that is based largely on lithology, heat flow, and depth of burial.
2-D Modeling

Background

2-D modeling (maps and cross-sections) is used to reconstruct oil and (or) gas generation from source rocks, migration, 

and accumulation, and pressure history of formations. These 

can be used for assessments of conventional and unconventional resources. Also incorporated within 2-D modeling is 

the ability to assign faults as open or closed, influence of 

salt movement and igneous intrusions, and numerous other 

variables. Although the IES PetroFlow® 2-D includes flowpath and 3-phase migration modeling with Darcy and hybrid 

Darcy simulators, the maps and cross-sections are primarily 

in two dimensions. Facies and lithologies can be assigned for 

2-D models, as can source rock characteristics to simulate the 

generation of heavy oil, dry gas, wet gas, or other parameters. 

A number of other variables, such as HI, TOC, and kinetic 

algorithms are also available for the computations.

Figure 4 is a map view of a 2-D model on the top of the 

Lower Cretaceous Mannville Group; shown are flowpaths of 

oil and gas migration and accumulation. (Note: Names and 

lithologies of Canadian formations and groups are derived 

primarily from the Lexicon of Canadian Stratigraphy, 1997.) 

The accumulations are based on structure, however, because 

Mannville Group hydrocarbons are mostly stratigraphically 

trapped, not all accumulations are shown on the map but 

flowpaths through reservoir areas are displayed. Also illustrated are oil accumulations in the areas of the major tar sand 

deposits. Flowpaths across layers and relative contributions 

of oil and (or) gas from bounding source rocks can be modeled in 2-D. The 3-D model of this (Mannville Group) surface 

differs by incorporating through time the relative contributions 

of all source rocks for all petroleum accumulations. Provinces 

or areas that have inadequate data control or quality for 3-D 

modeling can benefit from multiple 2-D cross sections that are 

located within a 3-D space. These sections provide visual and 

numeric information on the 3-D framework of the petroleum 

systems, such as influence on lithofacies and faulting on the 

systems, and vertical and lateral changes in hydrocarbon 

migration and trapping. 

Recommended Data

Sources of information for generating 2-D models 

include well databases, 1-D burial history models, seismic sections, and maps and cross sections that can contain data such 

as geology, topography, temperature, and pressure. Minimal 

information to build the models includes (1) geographic, map 

coordinate, or other reference locations of all data; (2) names 

and age ranges all layers in the model; and (3) lithologic characteristics of facies within the layers. Areas that are thermally 

mature for oil and gas can be delineated based on results of 

1-D modeling and from available data. If the 2-D models 

are used to estimate the timing and amounts of hydrocarbon 

generation, then most of the information listed in the introductory section of this paper as being important to petroleum 

systems modeling is also required.

Time and Personnel Requirements

Time and personnel requirements for 2-D modeling are 

based on the time and levels of effort required to generate 

maps and (or) cross sections, process seismic sections, determine the location and timing of faults, and evaluate kitchen 

areas for source rocks; all of these tasks are also needed for 

assessments. Actual time to create the initial PetroMod® 

2-D models by an experienced user can be relatively short. 

However, the time required to edit the initial maps is highly 

variable, being dependent upon source, such as published 

maps or raw data, and data quality and distribution. Editing 

for modeling and assessment purposes can range from a day 

to weeks; some of this can be accomplished with GIS support 

staff overseen by geologists. In most cases, it probably takes 

less than a day to generate the edited map using EarthVision® 

or ARC® software, export the grid in zmap format, and create 

and run a 2-D map model using PetroMod®. 

Advantages of Using 2-D Models

Primary advantages are the following:

1. Existing structure contour map grids can be quickly 

converted to the IES zmap grid-file format and used 

as input for modeling with PetroMod®.

2. PetroMod® can directly input 2-D seismic data and 

interpretations from a number of formats, including sections and paleo-sections from widely-used 

structural modeling software packages. Travel-time 

conversions to depths in feet or meters should be done 

outside of PetroMod®. PetroMod® can also export 

2-D cross sections in formats readable by some structural modeling software.

3. Proprietary well data used to generate the structure 

and isopach maps generally cannot be published, 

but 2-D grid files generated from these data can be 

published in most cases. This has the advantage of 

allowing others to use the isopach and (or) structure 

grid files.

4. 2-D has all of the advantages of 1-D modeling, 

including seamless integration of 1-D and 3-D 

variables and parameters. Other advantages include 

modeling through time of PVT, salt movement, 

hydrodynamic flow, igneous intrusions, temperature, 

transformation ratios, and other factors important to 

hydrocarbon generation and migration.

2-D Modeling 
5. PetroMod® allows for rapid display of the composition of generated hydrocarbons at depth and surface 

conditions. Also displayed are the relative contributions of petroleum source rocks for each accumulation. These accumulations can be compared to known 

reservoirs to calibrate location, volumes of and relative percentages of hydrocarbons, and contributing 

source rocks; this also has the advantage of calibrating the model parameters for modeled accumulations 

in unexplored areas.

Limitations of 2-D Modeling

The main limitation to map and cross section flow-path 

modeling is that they are two-dimensional surfaces. Although 

this is adequate for areas in which oil and gas are structurally 

trapped, areas that contain stratigraphically trapped or continuous hydrocarbon accumulations may, instead, just show 

migration of hydrocarbons through or out of areas. Integrating 

1-D and 2-D modeling provides greater information about the 

petroleum system history of the province or reservoir. 

Sweetgrass Arch

0 300 Km

0 50 100 150 Mi

gas kitchen ALBERTA SASKATCHEWAN MANITOBA

oil kitchen Zero Edge of Phanerozoic Cover

BRITISH 

COLUMBIA

USA

Figure 4. Map showing two-dimensional flowpath lines and accumulation cells of oil (green) and gas (red) on the Lower 

Cretaceous Mannville Group. Elevations relative to sea level on the Mannville are indicated by blue (-3,000 m) under the 

Canadian Rockies grading through green and yellow, to red-orange (500 m) in the area of the Precambrian shield. Flowpath 

directions are primarily to the northeast in northern Alberta and variable easterly directions in the southern half of Alberta. 

Dashed lines are the axis of the Sweetgrass Arch, which approximately segregates the basin hydrologically and structurally, 

and the southwest edge of the Precambrian shield. Coarse blue lines outline deposits of tar sands, which primarily are in 

the Mannville Group, and this two-dimensional model shows migration and accumulation of hydrocarbons into the tar sands. 

Green polygons east of the tar sands are also located east of the Mannville Group subcrop/outcrop. The approximate 

eastern limits of kitchen areas for oil and gas by Mesozoic source rocks are shown by the white lines.

10 Petroleum System Modeling
3-D Modeling

Background

3-D modeling involves reconstructing the history of 

petroleum systems at reservoir to basin scales and includes 

the ability to display that information in 1-D, 2-D and 3-D 

space and through time. The models can be constructed as 

time-stratigraphic intervals, or delineated based on common 

formations or facies. Numerous variables are integrated and 

analyzed by the 3-D petroleum systems modeling software. 

These data and interpretations greatly augment the assessment 

of undiscovered oil and gas resources by showing the history 

of petroleum systems across provinces, and by analyzing the 

relative effects on these systems of vertical and lateral changes 

in lithology, heat flow, hydrodynamics, PVT behavior, and 

other processes. The use of 3-D petroleum systems modeling 

can also enhance the assessment process by providing another 

level of support for conclusions from the assessments. Examples of this support include exclusion of areas and petroleum 

systems from assessment because source rocks are immature 

or overmature for petroleum generation, including these formations and areas because the modeling shows migration of 

petroleum from mature areas, and timing onset of petroleum 

generation relative to trap formation.

Figure 5 is a cross section view (front face) from the 3-D 

PetroMod® model in northern Alberta. The sub-Mannville 

unconformity is noted by the irregular surface below the Mannville Group layers. Underlying formations, which include the 

Devonian through Lower Cretaceous source rock intervals, are 

truncated by the lower Mannville. This unconformity provides 

a ready conduit for hydrocarbon migration into the area of the 

tar sands (east half of fig. 5). The initial and primary petroleum source rock for the tar sands is the Jurassic Nordegg 

Member. Structure on the top of the upper Mannville Group is 

shown in figure 6. Because most of the traps in the WCSB are 

stratigraphic rather than structural, most oil and gas migrated 

toward the Precambrian shield in the northeastern part of the 

basin. Models for stratigraphic traps and those constrained by 

PVT history would require more detailed lithologic assignments than were used in the WCSB. 3-D modeling was used to 

assess undiscovered oil and gas resources for the San Joaquin 

Basin, California (Peters and others, in press); results included 

modeling through time of (1) the percent transformation, and 

remaining oil generative potential of hydrocarbon source 

rocks, (2) oil migration flowpaths and accumulations and the 

volumetric contributions from source rocks, and (3) comparison of modeled accumulations to locations of oil fields.

Figure 7 shows the percent transformation of kerogen 

to petroleum in the Nordegg Member superimposed on the 

overlying Mannville Group layer. The areas beneath and to the 

west of the Rocky Mountains had transformation ratios greater 

than 40 percent at 80 Ma. 

Known properties of strata (well-documented porosities, permeabilities, depositional environments, and lithologies) in other basins or reservoirs can be used as analogs in 

frontier areas or for intervals for which data are inadequate 

for modeling. Shallow formations may have been extensively drilled in some basins, but deeper formations may be 

underexplored. Analogs can also help in reconstructing the 

compaction histories. Because published lithologies for the 

WCSB are a mix for all facies within a formation or group of 

formations, modeled compaction and depth profiles reflect 

this homogeneity. A single reservoir interval consisting of 

100 m of sandstone and 200 m of shale would have a mix of 

33 percent sandstone and 67 percent shale with the associated 

lower-grade porosity and permeability. Analogs can be used 

to assign porosity/permeability through depth profiles that are 

more characteristic of a reservoir layer. The WCSB model, 

for example, incorporates porosity/permeability/depth profiles 

from core data of the Lower Cretaceous Muddy (J) Sandstone 

in the Denver Basin, Colorado (Higley, 1988) as an analog 

for the approximate time-equivalent and lithologically similar 

Mannville/Blairmore Group. In the same manner, properties of 

the Cardium and Viking Formations have been assigned based 

on core data from the Upper Cretaceous Sussex Sandstone in 

the Powder River Basin, Wyoming (Higley, 1994; Higley and 

others, 1997).

Requirements for 3-D Modeling

Procedures and data needs are:

1. Compile data and results of previous research on 

the province and areas to be modeled. In order to be 

used effectively within an assessment, the petroleum 

system elements of reservoir/source/seal need to be 

defined in the earliest stage of the project, and it is 

best if a preliminary model is completed before the 

geologic assessment.

2. Assign the primary petroleum system elements of 

reservoir, source, seal, overburden, or underburden 

for all stratigraphic intervals in the model; this is 

useful but not required at the initial stage. Petroleum 

system boundaries do not need to be assigned, as the 

modeling accomplishes this.

3. Compile data on:

a. Elevation and (or) isopach data for stratigraphic 

intervals composing the petroleum systems.

b. Age ranges for the stratigraphic and other intervals in the model, and for periods of tectonism, 

erosion, and nondeposition.

c. Paleowater depth, heat flow, and surface temperature through time. Options include using default 

values for these parameters and allowing the program to calculate surface temperature through time.

d. Corrected bottom-hole temperatures, drillstem test 

temperatures, and amounts of heat flow through time 

are useful for external calibration of the models.

3-D Modeling 11
Mannville and 

unconformity

Nordegg

Doig

Exshaw

Duvernay

2nd White Sp.

North

Figure 5. East-west cross section across northern Alberta includes all layers in the 3-D model. Location of section and association to 

tar sands of the Mannville Group are shown in figure 6. The Jurassic layer (blue) and included Nordegg Member are truncated by the 

Mannville Group layer. Nordegg high-sulfur type II kerogen shale is the initial source of hydrocarbons for the tar sands. Later contributors of 

hydrocarbons are the Triassic Doig and Mississippian Exshaw shales, and low-sulfur carbonates of the Duvernay Member of the Woodbend 

Group. The 2nd White Speckled Shale was isolated from the Mannville petroleum system by shales of the Joli Fou and lower Colorado Group.

e. Locations and ages of faulting; timing of when the 

faults and segments were open or closed.

f. Lateral and vertical distribution of depositional 

facies/lithology from maps, cross sections, and

written descriptions.

g. Information useful for modeling changes through 

time, such as (1) paleogeometry maps to show 

influence of depositional or tectonic effects on the 

geometry of the interval and model, (2) location of 

salt diapirs for determination of salt movement, (3) 

igneous intrusions, (4) hydrodynamic movement, (5) 

pressure-boundary conditions, and (6) gas hydrates. 

12  Petroleum System Modeling
0 200 KM

0 100 200 Mi

BC Alberta Saskatchewan

 USA

Area of figure 7

Figure 5 

cross section

N

Figure 6. Map view at 80 million years ago (Ma) of early generation and emplacement of petroleum into the Lower Cretaceous 

Mannville Group. Early generation and emplacement of oil into the tar sands (white lines) started more than 100 Ma from high-sulfur 

shale of the Jurassic Nordegg Member (yellow line), which is in direct contact with the Mannville in a portion of the northern Alberta 

Basin. The sub-Mannville angular unconformity is illustrated in Figure 5. Selby and Creaser (2005) dated accumulation of oil into the 

tar sands at 112 ±5.6 Ma.

4. Evaluate quality and vertical and lateral distribution 

of elevation and (or) isopach data for stratigraphic 

and other intervals across the study area. The better 

the data, the better the resulting model; data quality can be variable, even within mature basins. Well 

records commonly list those contacts that are easiest 

to identify, such as between sandstone and shale, as 

well as major markers that determine proximity to the 

targeted reservoir formation(s); however, they typically do not record information such as near-surface 

formation contacts or high-TOC intervals within 

source rocks, unless that is important to discovering 

petroleum reservoirs.

5. Determine ages for all intervals used in the modeling, 

for tectonic events that are important to hydrocarbon 

generation, migration, and accumulation, and for 

periods of nondeposition. The areal distribution and 

thickness of eroded section can be estimated using 

published estimates and maps, and by constructing 

1-D and 1-D extraction models.

3-D Modeling 13
6. Determine depositional environments and distribution of 

facies, which are critical for models that mainly involve 

stratigraphically trapped hydrocarbons. PetroMod® 

allows for contributions of 5 to 100 percent of a range of 

lithologies. Default lithologic characteristics are assigned 

using PetroMod® and are based on analogs from a 

generalized global literature database. It is easy to modify 

porosity/permeability and (or) pressure histories for 

lithologies, or to assign analogs from other formations.

7. Build and display normal and wrench faults using 

PetroMod®. PetroMod® 3-D does not allow for 

direct creation of reverse faults, but they can be created with a series of vertical faults that are offset in 

the stacked layers. The tops and bases of these faults 

can be connected across the layers. Fault properties through time include open or closed, adjusting 

permeability by setting the transmissibility along 

and across the faults, and using processes such as 

Transformation Ratio 

(percent)

Figure 7. Three-dimensional diagram showing Jurassic Nordegg Member petroleum source rocks transformation ratios and 

migration vectors superimposed on the overlying Lower Cretaceous lower Mannville Group at 80 million years ago; location of 

the area and extent of the Nordegg Member is shown in figure 6 and is also approximated by the green vectors. The vectors 

show vertical migration of oil into the Mannville from the Nordegg. Transformation ratios, which are the conversion of kerogen 

to hydrocarbons; range from about 10 to 100 percent in the southwestern third of this image

14  Petroleum System Modeling
assigning lithologic properties along the fault traces, 

or by direct assignment of shale-gouge ratio (SGR) 

maps to faults. Examples of lithologic assignments 

are shale for use as fault gouge, or anhydrite for a 

closed fault.

8. Compile data on TOC and HI for source intervals in the 

model; these are required sources of carbon and hydrogen that are needed for the model to generate oil and gas. 

Default values and analogs of these data can be used. 

9. Compile Ro data, useful for external calibration 

of 3-D models. The modeling software includes 

numerous algorithms for calculating and calibrating 

thermal maturation through time. The model can 

also be calibrated using 1-D burial histories of wells, 

and 1-D extractions of 3-D models.

10. Select kinetics algorithms for use in modeling the 

timing of hydrocarbon generation. The program 

allows for use of default or input of user-defined 

kinetic parameters for primary generation and secondary cracking of oil and gas. Necessary information 

on source rocks that contribute hydrocarbons to each 

petroleum system includes their lateral and vertical 

distribution, kerogen type, lithology, TOC, and HI. 

Timing of generation of hydrocarbons is dependent 

upon choice of petroleum kinetic algorithms. 

Time and Personnel Requirements

Building 3-D models of petroleum systems ideally 

requires staff with backgrounds in data management, geology, 

geophysics, organic geochemistry, and use of modeling software. If 3-D modeling is to be incorporated into an assessment, 

the province first needs to be evaluated based on whether the 

available data, in terms of type, quality, and distribution, are 

suitable for the modeling or whether analogs are necessary. The 

assessment may not require modeling the entire basin, but may 

instead benefit from one or more models in selected areas of 

the province; this requires that kitchen area(s) be located within 

the subsets. In any case, the modeling should start before 

initiating the geologic assessment itself, preferably soon following compilation of basic well, lithologic, map, and thermal 

maturation information. Even if the data collection, mapping, 

and model construction is completed within a year, it can take 

additional time to refine the model and its contained parts, and 

to evaluate all the results and apply them to the geologic assessment, which precedes assessment of undiscovered resources.

Models should be built by geoscientists that are fairly 

computer literate. The USGS Energy Team has geoscientists 

in both Denver and Menlo Park offices that have experience 

building 3-D models. However, IES PetroMod® 3-D currently 

has limited documentation and tutorials, so initial training was 

done using IES personnel; training is increasingly being given 

by Energy Team personnel. Much of the training in 3-D is 

hands-on and requires considerable time to learn the complex 

and extensive functions of the software. IES personnel have 

also helped in construction and review of the 3-D models. 

Advantages of 3-D Models

The primary advantages of 3-D modeling are:

1. Reservoir- to basin-scale reconstructions can show 

hydrocarbon migration into areas that are unexplored 

or underexplored. An example of this is the northern 

WCSB, where there is a migration and accumulation pathway across the Lower Cretaceous Mannville 

Sandstone into the Precambrian Shield area. Although 

potential reservoirs there are removed by erosion, Lloyd 

Snowdon (oral commun., June 10, 2004), formerly of 

the Canada Geological Survey, indicated that some 

Mannville outcrops along the pathway are saturated 

with bitumen. 

2. Oil and gas generation, migration, and accumulation 

are modeled through time. The volumes of in-place, 

generated, accumulated, and lost oil and gas can be 

calculated and displayed through time for each petroleum system. Flash calculation charts and numbers 

generated by the modeling software show these generated volumes at surface conditions. Flash numbers 

allow for a better comparison of modeled numbers to 

produced and in-place oil and gas. 

3. Numerous processes that affect petroleum system 

elements also change through time, and these changes 

can be integrated into the model, including those 

involving salt movement, open and closed normal 

faults, wrench and other types of faults, hydrodynamics, paleogeometry, igneous intrusions, permafrost, 

and clathrates. 

4. Multicomponent PVT analysis incorporates changes 

due to compaction, temperature, faulting, heating 

history, and other variables. Output includes PVT 

history, including fault and formation capillary, 

lithologic, and other types of pressure, shale gouge 

ratio, and various hydrocarbon and non-hydrocarbon 

components, such as carbon dioxide and nitrogen. 

Calculated are the volume, composition, density, and 

viscosity of liquid, vapor, and water phases. 

5. The PetroRisk risking module can be applied at 1-D, 

2-D, and 3-D scales. Risk analysis within the 3-D 

modeling allows uncertainties in the geologic/geochemical data to be assigned and the effects of these 

uncertainties can be analyzed and compared through 

multiple runs using Monte Carlo or Latin Hypercube 

sampling techniques and multiple simulations. The 

risking can be performed on the petroleum charge, 

generation, migration, and loss calculations.

3-D Modeling 15
6. PetroMod® calculates the relative percent and 

volumetric contribution of gas through heavy oil 

from each source rock at reservoir, interval, and basin 

scales. This identifies the primary source rocks and 

their relative contributions through time at accumulation to province scales. Mature basins allow better 

evaluations and calibrations of models by comparing the calculated volumes to known volumes of 

in-place and recoverable oil and gas and estimates of 

undiscovered resources. This type of analysis is both 

for training purposes and for later use of the models 

as analogs for other basins or reservoirs. Volumes 

of generated hydrocarbons can be calculated by the 

modeling software, although these numbers can differ 

considerably from estimated volumes of in-place, 

discovered, or undiscovered hydrocarbons. Instead 

of publishing volumes of generated and accumulated 

hydrocarbons, it is preferable to publish the percent 

contribution of each source rock for the because of; 

(a) Differences between the volumes of generated, 

migrated, and accumulated hydrocarbons; (b) the 

effects of grid resolution on the locations and volumes of accumulated hydrocarbons, especially since 

grid cells can be considerably larger than the sizes 

of modeled and real accumulations; (c) inadequate 

geologic/geochemical information about the vertical 

and lateral extent and richness of source rocks; (d) 

information regarding lithologic characteristics of 

reservoir, source, and seal are generalized; and (e) 

a number of other parameters are generalized in the 

modeling due to insufficient data. A primary parameter is the quality of the source rocks, which vary in 

organic richness vertically and laterally. Although 

TOC, Ro, and similar data may be available at point 

sources within study areas, the modeling involves 

extrapolating the TOC and other information over 

broad vertical and lateral areas. 

7. PetroReport® produces graphs and tables that display 

the temporal evolution of relative contributions of 

hydrocarbons from source rocks at both for in-place 

and flashed-to-surface conditions. Reported volumes 

are also divided into generated, inflow and outflow, 

adsorbed, and within the water phase. This calculation and display is done at accumulation to basin 

scales. Calculations of the total hydrocarbon volumes 

are suspect because they are influenced by so many 

variables; for this reason a risk analysis should be 

performed to assess the distribution ranges, probabilities, and sensitivities of the results. However the 

relative volume percentages from each source provide 

a check of the reliability of modeling factors such 

as kinetics, TOC and HI values, assigned lithologies 

and associated porosity/permeability characterizations, interval thickness and distribution, and pressure 

history. The graphs and tables can further be used 

to check against 1-D and published information on 

timing and sources of hydrocarbon generation for 

reservoir intervals.

8. 3-D modeling can incorporate Darcy (vertical), flowpath (lateral), or hybrid Darcy (vertical and lateral) 

fluid flow. 

9. Because of the data, time, and personnel requirements for full 3-D modeling, there is the option of 

using small sub-sets of areas within the models that 

have good seismic and (or) well coverage. Sub-sets 

can be processed at finer grid spacing that most basin 

models allow, and the resulting model can be used as 

on its own merit, or as an analog for other areas of the 

province. This is useful if there is an area of particular importance within a province. 

10. Modeling changes in pressure history both laterally 

and vertically is an effective research tool for unconventional resources. Modeled processes include effects 

on pressure due to mechanical and chemical compaction and fluid expansion. Influences through time 

on gas trapping and interplay of capillary pressure, 

changes in porosity and permeability for lithologies, 

and sealing capacities can be incorporated, and the 

effects of underpressured or overpressured zones on 

degree and timing of trapping can also be evaluated.

11. A 3-D model includes hydrocarbon phase behavior 

(liquid, vapor). PetroMod® further calculates and 

reports the gas-oil ratio (GOR), API gravity, and 

composition and relative percentage of these liquids 

and vapors, such as C3-C5, C15 plus aromatics, C15 

plus saturated hydrocarbons, and water. These values 

can also be flashed to surface conditions for comparison to produced volumes and compositions.

12. PetroMod® serves as an archive for assigned 

parameters because they are tabulated within each 

1-D, 2-D, and 3-D model. The 3-D model, and each 

contained 2-D grid file and associated metadata can 

be published for use by other scientists.

Requirements and Limitations of 3-D Modeling

The primary disadvantage of 3-D modeling is that it 

requires considerable data, personnel, training, time, and computer processing capabilities. One of the greatest deterrents 

within the USGS Energy Team is the limited number of geoscientists and support personnel trained in assessment methodology, petroleum systems, and the use of modeling software. 

Construction of a 3-D basin model can take a year or more 

to complete and evaluate for use in geologic and resource 

assessments. Most of this time is used for background research 

on the province, and compiling the geologic and geochemical 

data for the modeling; this information is also critical for the 

16  Petroleum System Modeling
assessments. Time can be saved by building smaller models 

for areas within the province for use as analogs. The following 

are requirements for the 3-D modeling.

1. Ample personnel and computer time and equipment 

need to be dedicated to build the models. Although 

models can run using PC, SUN, and IRIX platforms, 

compared to Linux clusters of PCs these tend to be 

very slow and more prone to crash due to memory 

handling and limitations. The models also require 

many gigabytes of storage space. Storage space, 

memory, and processing ability also determine the 

choice of resolution that can be processed and displayed of the models.

2. Considerable data are required for a full 3-D model, 

and data quality and distribution are critical.

3. Main disadvantage of risk analysis using the 

PetroRisk® software is it can require long processing 

times.

4. Modeling software can change significantly with new 

versions; generally these are improvements but updating the model can modify the results.

Conclusions

It is necessary to continually improve our methodology for 

assessing conventional and unconventional resources. 1-D, 2-D, 

and 3-D petroleum systems models within provinces are used 

to (1) build and evaluate the hydrocarbon history for potential 

source and reservoir rocks, and (2) document time periods of 

deposition, erosion, and tectonic events and assess their relative 

influences on petroleum generation, migration, and accumulation. Unconventional resources can also be evaluated using 

multicomponent pressure, volume, temperature (PVT) analysis that models changes in these variables through time based 

on thermal history, vertical and lateral changes in lithologies, 

changes in pressure associated with oil and gas generation and 

secondary cracking. PVT analysis incorporates various hydrocarbon components, and includes carbon dioxide and nitrogen. 

Models are powerful tools that assist in (1) defining 

petroleum system elements and boundaries, (2) determining the timing of hydrocarbon generation and migration 

and of trap formation, (3) displaying and documenting 2-D 

and 3-D flow of hydrocarbons within and across petroleum 

systems, (4) evaluating relative contributions of source 

rocks to reservoir intervals, and (5) modeling influences on 

hydrocarbon migration of open and closed fault systems, 

salt movement, and other variables. 1-D and 2-D petroleum 

systems models are relatively easy to learn and rapid to 

build. The required data are generally available for resource 

assessments, and the models are small enough to be built 

and saved on a variety of computer platforms and storage 

devices. 3-D models can be created at reservoir to basin 

scales; subsets within provinces can be built as separate 

models or dissected from the full 3-D model. In order to be 

used most effectively, the models should be built before the 

geologic and resource assessments. 

Acknowledgements

This paper was prepared as a white paper for Brenda 

Pierce, Program Coordinator for the Energy Resources Program of the U.S. Geological Survey for the purpose of evaluating the use of 1-D, 2-D, and 3-D petroleum systems modeling 

in the assessment of undiscovered oil and gas resources. We 

benefited greatly from the reviews and helpful comments by 

William Keefer, Allegra Hosford Scheirer, Janet Pitman, Mark 

Pawlewicz, Mahendra Verma, and Daniel Hayba of the U.S. 

Geological Survey, and Bjorn Wygrala of Integrated Exploration Systems (IES).

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18  Petroleum System Modeling