25th International Meeting on Organic Geochemistry IMOG 2011

O-77
Fluid API gravity prediction in basin modelling
Rolando di Primio 1 , Eric Lehne 1 , Philipp Kuhn 1 , Friedemann Baur 2 , Brian Horsfield 1
1 GFZ German Research Centre for Geosciences, Potsdam, Germany, 2 RWTH Aachen, Aachen, Germany
(corresponding author:dipri@gfz-potsdam.de)
Kinetic models of petroleum generation are the
standard tool for the prediction of hydrocarbon
distribution and properties using basin modelling.
Such models are based on laboratory analysis of
hydrocarbon generation and extrapolation of the
reactions characterised to geologic heating rates. Our
compositional kinetic approach is termed
PhaseKinetics (di Primio, R., Horsfield, B. (2006)
AAPG Bull. 90, 1031-1058), and is based on a
combination of bulk kinetics and closed system
pyrolysis experiments to describe the compositional
evolution of generated fluids as a function of
increasing maturity. Due to the compositional
resolution used, which is based on that of PVT data
formats, the prediction of petroleum phase properties
is possible.
The prediction of phase properties of evolving
fluids, while successful with respect to GOR,
saturation pressures and phase state, lacked an API
gravity predictive capacity. Here we present results
from the GFZ project Predicting Petroleum Quality in
which this topic was addressed.
API gravity of petroleum fluids is generally assumed
to increase with increasing fluid maturity. Accordingly
trends of increasing fluid maturity, e.g. based on
biomarker parameters or physical properties such as
GOR, are expected to correlate to API gravity. Such
trends have been reported in the literature, however
they are only obvious in large data sets which include
a large variety of primary and secondary fluids. When
we exclude altered fluids from such trends, e.g. the
biodegraded fluids as well as the gas condensates
which usually contain gas generated by secondary
cracking processes, a correlation between API gravity
and maturity is very difficult to ascertain. For oilwindow
mature oils we generally observe only a very
vague correlation of API gravity and maturity, or none
at all. However, in genetically related fluids a range of
API gravities is common, usually showing a Gaussian
distribution.
Based on an extensive oil dataset, including fluids
generated by source rocks from distinctly different
depositional environments, we have been able to
identify characteristic API gravity ranges for
respective source rock types. By linking source rock
petroleum type organofacies and kerogen type, as
determined by open system PyGC, to generated fluid
API ranges we developed an approach for the
prediction of initial fluid API gravity using the
PhaseKinetic approach.
Our natural datasets indicated that typical
Paraffinic-Naphthenic-Aromatic (PNA) petroleums
show API gravity ranges between 32° and 46°,
centering around 39°API; Paraffinic-High-Wax (P-HW)
petroleums range from 35° to 50° and with a
maximum at 43°API, light oils range from 35 to 46 and
maximise at 42°API and sulphur-rich oils (PNA S-rich)
have the broadest API gravity range from 19 to 42
with a weak maximum at 29°API. Each of the
petroleum types described can be linked to a specific
source rock depositional environment using PyGC
analysis of the source rock.
Our PhaseKinetic approach uses a 14 compound
model of the generated petroleum which includes the
physical properties of each individual compound in
order to be able to calculate the phase behaviour of
the generated fluids. While the physical properties of
the compounds in original models were constant for
any fluid type, we have now generated liquid
compound physical property descriptions for four
different fluid types: PNA, PNA S-rich, P-HW and light
oils and gas condensates. In addition to the
characterisation of the primary fluid properties
generated by the respective source rocks during
maturation, the changes during maturation and
cracking were also characterised and included in the
model using compound specific secondary cracking
descriptions. This new approach was tested on a
variety of petroleum system models including a North
Sea area and the Williston Basin with excellent
results.
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