Mass Fraction Maturity — Next Generation Geochemical Constraint of Basin Models*
Haiping Huang1, Jingping Ma2, Ranya Algeer2, and Steve Larter2
Search and Discovery Article #41862 (2016)**
Posted August 15, 2016
*Adapted from oral presentation given at AAPG 2016 Annual Convention and Exhibition, Calgary, Alberta, Canada, June 19-22, 2016
**Datapages © 2016 Serial rights given by author. For all other rights contact author directly.
1
Geoscience, University of Calgary, Calgary, Alberta, Canada ([email protected])
Geoscience, University of Calgary, Calgary, Alberta, Canada
2
Abstract
Thermal maturity measurement on oil accumulations are crucial for resource assessment. However, the current concept of an oil maturity is
flawed and simplistic, as all oils are mixtures with different components charged from source rocks at different temperatures. With typical
geological heating rates of 1-10 °C/Ma at any location within a petroleum system, this means that source rocks are charging traps for timescales
on the order of a few million years, to a few tens of millions of years. During this period of time, the expelled and trapped petroleum shows a
progressive evolution of both bulk and molecular compositions. The concentrations of various components in oil vary greatly for a single facies
source rock of differing maturities nonetheless for the different facies. However, petroleum geochemists have continued to use relative
abundances of, in particular, saturated hydrocarbon and other biomarkers to a large degree in oil-source rock and oil-oil correlations and
maturity and facies assessment of reservoired oils, leading to many confusing and inconsistent approaches to characterizing maturity. We have
suggested an alternative approach is needed which tracks the maturity/ petroleum mass fraction relationships for a reservoired oil, in a more
complex but realistic manner and allows the more effective bracketing of source kitchen maturity. The maturity distribution of oil would then
represent the mass fraction versus source temperature at expulsion profile, for all the components in that reservoired fluid. This concept, called
Mass Fraction Maturity (MFM), aims to develop the tools, protocols, and calibration data sets to enable the assessment of the reservoired oil
mass fraction and source charge temperature interval relationship. Having this relationship, and knowing what a typical complete charge mass
fraction maturity profile would look like for a given source rock type, would enable estimation of any missing charge in the basin (validating
additional exploration activity), detection of complex multi-history charge scenarios, and also a much more robust and complete data set for
calibration of basin model charge history assessments. We will demonstrate the importance of MFM for understanding the properties of
reservoir fluids, post-burial uplift and petroleum mass loss, instantaneous versus cumulative charge events and exploration potential by using
case studies from Western Canada and elsewhere.
References Cited
Mackenzie A.S., S.C. Brassell, G. Egeinton, and J.R. Maxwell, 1982, Chemical Fossils - The Geological Fate of Steroids: Science, v. 217, p.
491-505.
Wilhelms, A., and S. Larter, 2004, Shaken But Not Always Stirred: Impact of Petroleum Charge Mixing on Reservoir Geochemistry:
Geological Society, London, Special Publications, v. 237/1, p. 27-35.
Mass Fraction Maturity — Next
Generation Geochemical Constraint
of Basin Models
Haiping Huang, Jingping Ma, Ranya
Algeer and Steve Larter
Department of Geoscience
University of Calgary
The oil window
80
Change in Color and Vitrinite Reflectivity
Correlation Chart
How to assess oil maturity?
4
1
8
5
2
9
3
14
2
6
7
3
7
10
12
6
5
4
1
11
8
10
13
9
I adamantane
II diamantane
Ranges of individual biomarker molecular
measurements for thermal maturation
Use several different parameters to define the stage
of maturation with respect to oil generation
(Modified from Mackenzie et al., 1982)
Oil maturity derived from biomarkers
0.7
Lunnan
C29 20S/(20S+20R)
Tahe
0.6
Halahatang
Yingmaili
Tazhong
0.5
0.4
0.3
0.3
0.4
0.5
0.6
C29 bb/ (aa+bb)
Estimated Ro ～0.6–0.7%
0.7
Oil maturity derived from PAHs
10
Lunnan
Tahe
8
MDR
Halahatang
Yingmaili
6
Tazhong
4
2
0
0.2
0.4
0.6
0.8
1.0
MPI1
Estimated Ro ～0.7–1.0%
1.2
Oil maturity derived from diamondoids
MDI=4DA/(1DA+3DA+4DA)*100%
70%
65%
Ro>1.7%
60%
55%
Ro=1.5%~1.7%
50%
45%
Ro=1.3%~1.5%
40%
50%
60%
70%
80%
MAI=1MA/(1MA+2MA)*100%
Estimated Ro >1.2%
90%
n-C17/Pr vs. n-C18/Ph
12
n-C18/Ph
10
8
6
4
2
0
0
2
4
6
n-C17/Pr
8
10
12
14
TMNr vs. TeMNr
1
TeMNr
0.9
0.8
0.7
0.6
0.5
0.4
0.4
0.5
0.6
0.7
TMNr
0.8
0.9
1
n-C18/Ph vs. TMNr
1
TMNr
0.9
0.8
0.7
0.6
0.5
0
2
4
6
n-C18/Ph
8
Almost no correlation!
10
12
Concentration effects on molecular ratios!
Total tricyclic terpanes (mg/g oil)
1000
The high concentrations
ratio is consistent facies
indicator
800
600
At low concentrations
coelution and concentration
errors result in erroneous
facies indicators.
400
200
ZG44C
0
0
0.5
1
C19TT/C20TT
1.5
Concentrations of major compound
classes in oils
(Wilhelms and Larter, 2004)
The distribution of fraction specific
maturity for the oils and condensates
(Wilhelms and Larter, 2004)
Summary of oil matuirty






Most commonly used maturity parameters have very
different correlations to measured vitrinite reflectance;
Biomarker parameters are sensitive at low to moderate
maturity range;
PAH parameters are sensitive at moderate to high maturity
range;
Light HCs and diamondoids are sensitive at high maturity
range;
Current oil maturity is a misconception as oil is mixture of
charges;
An alternative approach to track petroleum mass fraction
relationships for a reservoired oil (mass fraction maturity) is
needed.
Case History of MFM

Samples collected from the Second White Specks Formation
(SWS) in WCSB ranging from immature to high mature form a
natural evolution case history
Tmax increase with burial depth
Tmax (°C)
380
400
0
Depth (m)
500
1000
Immature
1500
2000
2500
Mature
3000
3500
Post mature
420
440
460
480
Ro is controlled by burial depth
Ro (%)
0.00
0
500
0.50
Immature
1.00
y = 10029x3 - 30366x2 + 31765x - 8829
R² = 0.9921
Depth (m)
1000
1500
2000
Mature
2500
3000
3500
1.50
Post mature
Representative total ion current show
systematic variation with increasing maturity
Representative sterane distributions in
different maturity samples
Representative TIC of aromatic fraction
in different maturity samples
MAS
520.96 m
Ro=0.49%
P
C2N
N
C3N
C4N
MP
C2P
1900.65 m
Ro=0.69%
C3P
MN
MN
2626.75 m
Ro=0.94%
n-Alkane concentration profile
0
C10-15 n-alkanes (mg/g EOM)
10000
20000
30000
40000
50000
0.4
0.5
Ro (%)
0.6
0.7
Core
0.8
Outcrop
0.9
1.0
1.1
1.2
1.3
Isoprenoids concentration profiles
1000
4000
0
5000
0.4
0.4
0.5
0.5
0.6
0.6
0.7
0.7
Ro (%)
Ro (%)
0
Pr (mg/g EOM)
2000
3000
0.8
0.8
0.9
0.9
1.0
1.0
1.1
1.1
1.2
Core
1.3
Outcrop
1.2
1.3
1000
Ph (mg/g EOM)
2000 3000 4000
5000
6000
7000
Core
Outcrop
Biomarkers concentration profiles
0
2000
PT (mg/g EOM)
4000
6000
8000
0
10000
0.4
0.4
0.5
0.5
0.7
Core
0.8
Outcrop
0.7
Ro (%)
Ro (%)
15000
20000
0.6
0.6
0.9
5000
ST (mg/g EOM)
10000
0.8
0.9
1.0
1.0
1.1
1.1
1.2
1.2
1.3
Core
Outcrop
Diamondoids concentration profiles
0
4000
0.4
0.4
0.5
0.5
0.6
0.6
0.7
Core
0.8
Outcrop
0.7
Ro (%)
Ro (%)
0
Total Adamantanes (mg/g EOM)
1000
2000
3000
0.8
0.9
0.9
1.0
1.0
1.1
1.1
1.2
1.2
1.3
1.3
Total Diamontanes (mg/g EOM)
100
200
300
400
500
Core
Outcrop
Concentration profiles of alkylnaphthalenes
C0-1N (mg/g EOM)
4000
8000
12000
16000
0
0.5
0.5
0.6
0.6
0.7
0.7
Ro (%)
0.4
0.8
5000
20000
Core
Outcrop
0.8
0.9
0.9
1.0
1.0
Core
1.1
1.1
Outcrop
1.2
1.2
1.3
1.3
C3N (mg/g EOM)
0
5000
10000
15000
0
0.4
2000
C4N (mg/g EOM)
4000
6000
0.4
0.5
0.5
Core
0.6
0.6
Outcrop
0.7
0.8
0.9
1.0
1.1
0.7
Ro (%)
Ro (%)
Ro (%)
0
0.4
C2N (mg/g EOM)
10000
15000
0.8
0.9
1.0
1.1
1.2
1.2
1.3
1.3
Core
Outcrop
Concentration profiles of alkylphenanthrenes
0
1000
P (mg/g EOM)
2000
3000
0
4000
0.5
Core
0.5
0.6
Outcrop
0.6
6000
8000
Core
Outcrop
0.7
Ro (%)
0.7
0.8
0.8
0.9
0.9
1.0
1.0
1.1
1.1
1.2
1.2
1.3
1.3
0
2000
C2P (mg/g EOM)
4000
6000
0
8000
1000
C3P (mg/g EOM)
2000
3000
4000
0.4
0.4
0.5
0.5
Core
0.6
0.6
Outcrop
0.7
0.8
0.9
0.7
Core
Outcrop
Ro (%)
Ro (%)
MP (mg/g EOM)
4000
0.4
0.4
Ro (%)
2000
0.8
0.9
1.0
1.0
1.1
1.1
1.2
1.2
1.3
1.3
Conceptual concentration profile of
various components
Concentration
Maturity
1,2 – Biomarkers
Concentration
Maturity
3,5 – Aromatic Hydrocarbons
Concentration
Maturity
6,7 – Light Hydrocarbons
8-10 – Diamondoids
Concept of mass fraction matuity
160
150
140
130
120
110
100
0
1
2
3
4
5
6
7
8
9
10
Both concentrations and molecular ratios
are applied for maturity constraints
Pentacyclic terpanes concentration (mg/g)
10000
741.7 m
50:50
1000
90:10
100
2602.5m
10
1
1
10
100
1000
Steranes concentration (mg/g)
10000
Mass fraction maturity in a trap
If this could be assessed, it would be a game changing tool!
Summary




Tracking petroleum mass fraction relationships
for reservoired oils.
Elucidation of complex charge histories.
Defining a quantitative approach to assess
kitchen maturity in oil and gas accumulations
basins.
If this could be assessed, it would be a game
changing tool!
Acknowledgement