Controls on reservoir quality in Early Cretaceous carbonate oil fields and implications for basin modelling
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Date
27/11/2014Author
Thorpe, Dean Timothy
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Abstract
Carbonate reservoirs hold more than 50 % of Earth’s remaining conventional
hydrocarbon. However, recovery from these reservoirs is notoriously difficult due to
the complex and multiple scales of porosity. This heterogeneity is a function of both
the depositional environment and of subsequent diagenetic processes. This thesis
examines the processes that have controlled the reservoir quality of three Early
Cretaceous carbonate oil fields (A, B, and C), in particular the role of deposition,
diagenesis and the timing of oil charge in controlling final properties. Results are
then used to help provide a theoretical basis for the modelling and prediction of
reservoir quality and to improve the calibration of basin models.
Field A and B are stacked and highly compartmentalised giant oil fields in the
U.A.E. that are dominated by muddy fabrics and have a highly variable porosity (0-
35 %) and permeability (0.01-830 mD). Although the depositional environment
strongly determines the location of reservoirs extensive diagenesis, through
cementation and dissolution, has greatly modified the porosity and permeability of
the reservoirs. Bulk δ13C values obtained from the main pore occluding calcite and
dolomite cements are similar to the δ13C values of bulk micrite for the reservoir
interval in which they are now present. This suggests that the cements that are
occluding the pore space in each stacked reservoir are locally sourced and implies
that each reservoir behaves as a relatively closed system during cement precipitation.
In-situ (SIMS) δ18OVPDB
values were obtained for the complete calcite
cementation history of multiple reservoirs in Field A and B. The δ18OVPDB
values for
the first (oldest) calcite cement zone in each reservoir can be related to the global
δ18OVPDB
marine curve during the Hauterivian-Aptian and to million-year scale major
climatic cooling events. The δ18OVPDB
values for successive cement zones then
progressively decrease, which is related to successive precipitation as a result of
increasing temperature during burial in a relatively closed system.
In-situ (SIMS) δ18OVPDB
data together with oil inclusion occurrence suggest
that initial oil charge (from the Dukhan Formation), at ~ 55-45 Million years ago
(Mya) in Field A, reduced the cementation rate in the oil reservoir and preserved
porosity. Whereas in the coeval aquifer a large volume of cement precipitated, after
oil entered the oil reservoir, that greatly reduced porosity. Furthermore, the most
reduced δ18OVPDB and mMg/mCa values are obtained from the cements in the
shallowest (youngest) reservoirs, suggesting that cementation ceased in the deepest
reservoirs first. This can be related to hydrocarbon stopping cementation or to the
complete occlusion of effective porosity in the older reservoirs prior to the younger.
After calcite and dolomite cementation ceased in the reservoirs of Field A
and B a large scale dissolution event has been identified which significantly
enhanced porosity. This dissolution event is then followed by the precipitation of
authigenic kaolinite. Basin modelling reveals that this dissolution event is likely to be
related to the thermal maturation of sedimentary organic matter that is present within
local intraformational seals and to the migration of organic acids prior to a second
hydrocarbon charging event (at ~ 45 Mya). The aluminium, that is required for the
formation of kaolinite, would then have been brought into the system by complexing
with the organic compounds derived from this maturation event.
Field C is an oil field located in offshore Brazil. The field is dominated by
high energy facies that have porosities which range from 5 % to 39 %, and
permeabilities from 0.1 mD to 8.1 D. The depositional poro-perm properties of the
oil reservoir have undergone little diagenetic alteration; however, the aquifer is
extensively cemented and the porosity is much reduced. All the cements identified,
by both petrography and stable isotopic analyses, in the oil reservoir are early and are
thought to have formed from a pore fluid similar to, or slightly evolved from, Early
Cretaceous seawater. Basin modelling suggests that oil may have entered the field
slightly after deposition (at ~105 Mya) and led to the preservation of high porosities
and permeabilities in the oil reservoir by stopping cementation.