The influence of wettability and carbon dioxide injection on hydrocarbon recovery
Author(s)
Al Sayari, Saif S
Type
Thesis
Abstract
This study can be divided into two sections. First, a detailed study of petrophysical
properties and the impact of wettability is performed on cores from a producing
heterogeneous carbonate reservoir from the Middle East. Second, a comparison
between different injection schemes (waterflooding, gas injection, WAG and CO2
injection) for enhanced oil recovery is made for another giant carbonate reservoir in
the Middle East.
Knowledge of the wettability of a reservoir rock and its influence on petrophysical
properties is a key factor for determining oil recovery mechanisms and making
estimates of recovery efficiency. A full suite of experiments on well-characterised
systems, including sandpacks, sandstones and carbonate cores, was performed to
measure capillary pressure, relative permeability, NMR response and resistivity
index. Cores aged in crude oil, with different wettability were studied.
As a preliminary step to investigate the effect of wettability on heterogeneous
carbonates from the Middle East, sandpack and sandstone samples were first tested
because: 1) these samples are known to be quite homogeneous and of a wettability
that can be controlled; 2) To test our experimental methods; and 3) to serve as a
dataset for modelling studies.
First, the static (porosity and permeability) and dynamic (initial water saturation and
residual oil saturation) properties of Leavenseat (LV60) and Ottawa (F-42) sandpacks
were measured. The formation factor and NMR response for these sandpacks were
also determined. These experimental measurements have served as a benchmark for
pore-modelling studies that have reproduced the experimental data.
Fontainebleau sandstones have also been used as a benchmark in the industry
because of its relatively simple pore structure. Mercury injection capillary pressure
(MICP) measurements were performed on this sandstone. The MICP experimental
measurements showed very low pore volume values, indicating very tight
(consolidated) samples. These samples had a diameter of less than 0.02 m which
made the experiments quite difficult.
Once we had confidence in the experimental methodology, five carbonate samples
from a typical Middle East reservoir were imaged and cleaned in order to render
them more water wet. Conventional and special core analyses were performed on all
the samples. The pore throat distribution from capillary pressure was successfully
compared with the pore size distribution inferred from the NMR T2 relaxation curve.
Formation resistivity factor and the formation resistivity index were also measured.
Capillary pressure and relative permeability curves were measured using refined oil
and synthetic formation brine. Then the samples were aged in crude oil from the same field at elevated temperature (120oC) and underwent the same experiments to
evaluate the influence of wettability changes on these properties.
The experimental data show that there is a significant difference in the relative
permeability and capillary pressure of the cleaned and aged samples; the results are
explained in terms of the pore-scale configurations of fluids. In contrast, electrical
resistivity did not encounter significant changes for different wettability, suggesting
that electrical properties in these carbonates are mainly affected by the porosity that
remains water-wet, or is only neutrally-wet. This conclusion is supported by the
significant displacement that is observed in the aged sample at capillary pressures
close to zero.
We show that wettability, imbibition capillary pressure and relative permeability
have major impact on the waterflood sweep efficiency and hence on the distribution
of remaining oil saturation. An incorrect understanding of the distribution of
remaining oil saturation may lead to ineffective reservoir management and IOR/EOR
decisions.
The second part of this thesis is to assess the efficacy of CO2 injection into carbonate
oil fields. The reservoir under study is a layered system. The reservoir consists of two
main units, i.e. a lower zone of generally low permeability layers and an upper zone
of high permeability layers inter-bedded with low permeability layers; the average
permeability of the upper zone is some 10-100 times higher than that of the Lower zone. Under waterflooding, the injected water tends to flow through the upper zone
along the high permeability layers and no or very slow cross flow of water into the
lower zone occurs, resulting in very poor sweep of the lower zone. There is
significant scope for improving oil recovery from such type of heterogeneous mixedwet
carbonate reservoirs. The apparent impediment to water invading the bottom
strata prompts suggests that a miscible fluid could be Injected into the lower zone.
We conducted a series of core-flood experiments to compare the performance of
different displacement process: waterflooding, hydrocarbon gas flooding and wateralternate
gas (WAG) and compared them with CO2 injection. We show that the local
displacement efficiency for CO2 flooding is approximately 97% - much higher than
that obtained from waterflooding or hydrocarbon gas injection, due to the
development of miscibility between CO2 and the oil. We use the results to discuss
the potential of CO2 injection for storage and enhanced oil recovery in the Middle
East carbonate reservoir discussed above, and proposes further research to develop
a fuller understanding of the subsurface behavior of CO2.
properties and the impact of wettability is performed on cores from a producing
heterogeneous carbonate reservoir from the Middle East. Second, a comparison
between different injection schemes (waterflooding, gas injection, WAG and CO2
injection) for enhanced oil recovery is made for another giant carbonate reservoir in
the Middle East.
Knowledge of the wettability of a reservoir rock and its influence on petrophysical
properties is a key factor for determining oil recovery mechanisms and making
estimates of recovery efficiency. A full suite of experiments on well-characterised
systems, including sandpacks, sandstones and carbonate cores, was performed to
measure capillary pressure, relative permeability, NMR response and resistivity
index. Cores aged in crude oil, with different wettability were studied.
As a preliminary step to investigate the effect of wettability on heterogeneous
carbonates from the Middle East, sandpack and sandstone samples were first tested
because: 1) these samples are known to be quite homogeneous and of a wettability
that can be controlled; 2) To test our experimental methods; and 3) to serve as a
dataset for modelling studies.
First, the static (porosity and permeability) and dynamic (initial water saturation and
residual oil saturation) properties of Leavenseat (LV60) and Ottawa (F-42) sandpacks
were measured. The formation factor and NMR response for these sandpacks were
also determined. These experimental measurements have served as a benchmark for
pore-modelling studies that have reproduced the experimental data.
Fontainebleau sandstones have also been used as a benchmark in the industry
because of its relatively simple pore structure. Mercury injection capillary pressure
(MICP) measurements were performed on this sandstone. The MICP experimental
measurements showed very low pore volume values, indicating very tight
(consolidated) samples. These samples had a diameter of less than 0.02 m which
made the experiments quite difficult.
Once we had confidence in the experimental methodology, five carbonate samples
from a typical Middle East reservoir were imaged and cleaned in order to render
them more water wet. Conventional and special core analyses were performed on all
the samples. The pore throat distribution from capillary pressure was successfully
compared with the pore size distribution inferred from the NMR T2 relaxation curve.
Formation resistivity factor and the formation resistivity index were also measured.
Capillary pressure and relative permeability curves were measured using refined oil
and synthetic formation brine. Then the samples were aged in crude oil from the same field at elevated temperature (120oC) and underwent the same experiments to
evaluate the influence of wettability changes on these properties.
The experimental data show that there is a significant difference in the relative
permeability and capillary pressure of the cleaned and aged samples; the results are
explained in terms of the pore-scale configurations of fluids. In contrast, electrical
resistivity did not encounter significant changes for different wettability, suggesting
that electrical properties in these carbonates are mainly affected by the porosity that
remains water-wet, or is only neutrally-wet. This conclusion is supported by the
significant displacement that is observed in the aged sample at capillary pressures
close to zero.
We show that wettability, imbibition capillary pressure and relative permeability
have major impact on the waterflood sweep efficiency and hence on the distribution
of remaining oil saturation. An incorrect understanding of the distribution of
remaining oil saturation may lead to ineffective reservoir management and IOR/EOR
decisions.
The second part of this thesis is to assess the efficacy of CO2 injection into carbonate
oil fields. The reservoir under study is a layered system. The reservoir consists of two
main units, i.e. a lower zone of generally low permeability layers and an upper zone
of high permeability layers inter-bedded with low permeability layers; the average
permeability of the upper zone is some 10-100 times higher than that of the Lower zone. Under waterflooding, the injected water tends to flow through the upper zone
along the high permeability layers and no or very slow cross flow of water into the
lower zone occurs, resulting in very poor sweep of the lower zone. There is
significant scope for improving oil recovery from such type of heterogeneous mixedwet
carbonate reservoirs. The apparent impediment to water invading the bottom
strata prompts suggests that a miscible fluid could be Injected into the lower zone.
We conducted a series of core-flood experiments to compare the performance of
different displacement process: waterflooding, hydrocarbon gas flooding and wateralternate
gas (WAG) and compared them with CO2 injection. We show that the local
displacement efficiency for CO2 flooding is approximately 97% - much higher than
that obtained from waterflooding or hydrocarbon gas injection, due to the
development of miscibility between CO2 and the oil. We use the results to discuss
the potential of CO2 injection for storage and enhanced oil recovery in the Middle
East carbonate reservoir discussed above, and proposes further research to develop
a fuller understanding of the subsurface behavior of CO2.
Date Issued
2009-09
Date Awarded
2009-10
Copyright Statement
Attribution NoDerivatives 4.0 International Licence (CC BY-ND)
Advisor
Blunt, Martin
Sponsor
ADNOC (Abu Dhabi National Oil Company)
Creator
Al Sayari, Saif S
Publisher Department
Earth Science and Engineering
Publisher Institution
Imperial College London
Qualification Level
Doctoral
Qualification Name
Doctor of Philosophy (PhD)