25th International Meeting on Organic Geochemistry IMOG 2011

O-42
Charge history and petroleum geochemistry of dual phase
accumulations on the Norwegian Continental Shelf using
comparative analysis of the liquid and vapour phase
Linda Schulz 1 , Michael Erdman 2 , Olaf Thießen 3
1 Statoil ASA, Exploration, Drammensveien 264, 0246 OSLO, Norway, 2 Statoil ASA, Exploration,
Sandsliveien 90, 5020 BERGEN, Norway, 3 Statoil ASA, Exploration, Grenseveien 21, 4035 STAVANGER,
Norway (corresponding author:lksc@statoil.com)
Understanding charge history of dual phase
accumulations may be challenging due to multiple source
contributions and phase separations. Identical gas data
of the oil associated gas and the non-associated gas
could indicate a single source rock whereas additional
data from the gasoline and biomarkers fraction results in
a different picture pointing towards multiple sources. The
main objective of this study has been to investigate
commonly applied geochemical parameters from all
hydrocarbon fractions in dual phase accumulations.
Additional PVT data and pyrolysis data from the main
sources have been considered to improve the
understanding of the charge history. Case studies from
the Norwegian Continental Shelf are used.
The first case shows a reservoir accumulation where the
petroleum most likely has been generated by a marine
source at peak to late-oil maturity. The gas isotope
profiles of oil associated gas and the gas-condensate are
identical (Fig.1, case 1). The maturity of the gasoline
fraction in the gas-condensate phase is slightly higher
than in the oil phase. The dual phase state appears best
explained by phase separation due to reduced pressure
and temperature conditions which is supported by
saturation pressures close to reservoir pressures. The
gas mass fraction of the discovery is about 0.44, while
pyrolysis experiments of marine source rock samples
indicate gas mass fractions of around 0.15 to 0.22 with
only minor increase at high maturity. Volumetric
recombination of both phases in PVTsim shows that the
charge fluid has a high GOR and possibly was an
undersaturated gas/ condensate. The high gas mass
fraction could be explained by liquid loss on the migration
pathway. Additional gas contributed from secondary
cracking is excluded from biomarker versus diamondoid
concentrations. Another explanation for the high gas
fraction could be that oil has been migrated up-flanks
whereas the gas has been efficiently trapped.
The second case shows accumulations in two reservoirs
which are separated by a pressure barrier at present day.
The oil associated gas in the lower reservoir shows a
very low gas mass fractions of about 0.07. The upper
reservoir contains a gas condensate with a gas mass
fraction of about 0.92. However, even volumetric
recombination of both phases will not increase the oil/gas
mass fraction above about 0.08 for the whole
accumulation. Thus, significant gas loss best explains the
observed ratios. At the same time the oil associated gas
and the gas-condensate do show similar isotope profiles
(Fig. 1, case 2). Moreover, gasoline and C15+ range
hydrocarbons indicate that the oil has been generated by
a source rock dominated by terrigenous organic matter,
while the gas-condensate has a marine origin. In spite of
partial loss of gas fraction, complex mixing and alteration
processes the gas isotope profiles appear similar in both
reservoirs. This observation appears to be ubiquitous,
pointing to homogenization of compositional differences
for gas being very fast in geologic time, also across
phase boundaries.
The conclusion is that lack of differences in isotopic
composition between the oil associated and nonassociated
gases not necessarily indicates that gas cap
and oil leg have the same origin. Consideration of all
petroleum fractions in both phases, ideally combined with
mass balance and PVT data, allows for a proper
interpretation of the charge history of dual phase
accumulations. This can contribute to a realistic
evaluation of the prospectivity of the areas adjacent to
discoveries.
� 13 C (‰) PDB
-30
-40
-50
Single-phase system
OIL (for comparison only)
Two-phase systems
1 - GAS_COND (GOR: 1900)
1 - OIL (GOR: 246)
2 - GAS_COND (GOR: 12585)
2 - OIL (GOR: 92)
Methane Ethane Propane i-Butane n-Butane
Fig.1. Compound specific carbon isotope profiles of oil-associated and free
gases/gas-condensates of two-phase systems. The grey shaded area represents
the carbon isotopic range of the gas generation index (GGI) according to Clayton
(1991).
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