SPE-129645-MS-P

SPE 129645
Simultaneous Injection of Miscible Gas and Polymer (SIMGAP) to Improve Oil
Recovery and Sweep Efficiency from Layered Carbonate Reservoirs
Shehadeh K. Masalmeh SPE, H. Hillgartner, R. Al Mjeni, X.D. Jing SPE, Shell Technology Oman
Copyright 2010, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE EOR Conference at Oil & Gas West Asia held in Muscat, Oman, 11–13 April 2010.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed
by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or
members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is
restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract
This paper presents a method for improving oil recovery from heterogeneous mixed to oil-wet carbonate reservoirs. In reservoirs
where a high-permeability zone is above a low permeability zone, under water flooding the injected water tends to flow through
the upper zone along the high permeability layers with no or very slow cross flow of water into the lower zone, resulting in very
poor sweep of the lower zone. It has been demonstrated in earlier publications that this water override phenomenon is caused by
capillary forces which act as a vertical barrier and counteracts gravity force in cases where permeability varies between layers for
mixed to oil-wet reservoirs.
There is significant scope for improving oil recovery from such type of heterogeneous mixed to oil-wet carbonate reservoirs. Gas
injection is known to improve displacement efficiency by reducing residual oil saturation. However, for reservoirs of high
permeability contrast especially when the high permeable layers are in the upper part of the reservoir, conventional gas injection
(immiscible or miscible) becomes less effective because of gravity override and/or viscous fingering caused by unfavourable
mobility ratio compounded by geological heterogeneity. The main challenge to gas injection in such reservoirs is to confine the gas
into the low permeability zones and improve sweep efficiency. Therefore, for this type of carbonate reservoirs, mobility control is
required to enable gas/CO2 EOR due to the geological heterogeneity and gravity override.
This paper presents a new EOR scheme where mobility control of the injected gas is achieved by injecting viscosified water into
the upper zone while injecting miscible gas into the lower zone using vertical and/or horizontal wells. A key prerequisite is to have
a static model that captures the geological heterogeneity (e.g., vertical permeability contrast, all prevailing rock types) and a
dynamic model that incorporates the SCAL derived capillary pressure (both drainage and imbibition) and relative permeability
curves. Integrated geological, petrophysical and reservoir engineering effort was devoted to this EOR program that led to history
matched sector models which honours the waterflood remaining oil saturation distribution shown in cased hole time-lapse
saturation logs. The model forecasts show that significant sweep of the lower zone is achieved compared to both water or gas
injection and that the process is stable and robust to reservoir lateral and vertical heterogeneity.
This EOR process has the potential of recovering the oil that is by-passed by waterflood or conventional gas injection schemes. It
is particularly suited for layered oil reservoirs where there is an impediment for water to flow from the upper high permeable zone
to the lower reservoir due to e.g. (vertical) permeability reduction at the interface or a capillary pressure barrier. It is also
applicable for improving oil recovery from the low permeable layers inter-bedded within the more permeable reservoir unit.
Additional benefit of this process is to potentially enable economic EOR and CO2 storage in such kind of heterogeneous
reservoirs.
Introduction
In the past few years, we have been working on understanding waterflooding performance in heterogeneous oil-wet carbonate
reservoirs (Masalmeh et. el., 2004, 2007, 2008) with a focus on the impact of geological heterogeneity, imbibition capillary
pressure and relative permeability models. In these earlier publications we have focused on parameters affecting cross flow
between reservoir layers and hence sweep efficiency and field-wide remaining oil saturation distribution.
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SPE 129645
The reservoir under study is a highly heterogeneous and layered reservoir where strata measuring a few feet in thickness can be
correlated field wide, often over tens of kilometres. The overall permeability increases towards the top of the reservoir. The
reservoir can be described at a high level as consisting of two main bodies, i.e. an Upper zone (high permeable layers inter-bedded
between low permeable layers) and a Lower zone of low permeability layers of relatively uniform permeability distribution. The
STOIIP is split as 60% in the Lower zone and 40% in the Upper zone and the average permeability of the Upper zone is some 10100 times higher than that of the Lower zone.
The main recovery mechanism currently applied is water flooding. Field data shows that injected water tends to travel quickly
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 poor sweep of the Lower zone [Fig. 1]. This led to attempts to force flow through the Lower zone by completing wells
separately in the Upper and Lower zones. However, because the boundary between the Upper and Lower zones proved not to be a
barrier to fluid flow, even when both injectors and producers are completed in the Lower zone, injected fluids quickly cross
through the boundary to the Upper zone and oil in the Lower zone tends to be by-passed. The injected water cross-flow from the
Upper to the Lower zone occurs only in the vicinity of the producers due to pressure draw down. The traditional explanation for
this water hold-up phenomenon is reduced (vertical) permeability at the interface between the Upper and Lower zones. However,
field observations including MDT and RFT data show that pressure communication exists between the Upper and Lower zones.
This water override phenomenon has been the subject of detailed static geological and petrophysical modelling and dynamic flow
simulation studies supported by an extensive special core analysis program and field saturation monitoring. It has been
demonstrated in earlier publications (Masalmeh et. al. 2004) that this phenomenon is caused by capillary forces which act as a
barrier and results in water hold-up in cases where permeability varies between layers for mixed to oil-wet reservoirs. By assigning
appropriate and rock-type specific (negative or oil-wet) imbibition capillary pressures to the Upper and the Lower zones, this field
performance (including time-lapse saturation logs taken in observation wells) can be matched in simulation models.
This water hold-up phenomenon leaves behind significant volumes of oil in the Lower zone. Therefore, it is necessary to better
understand the physics of the displacements and identify improve oil recovery processes for this kind of reservoirs. This paper will
focus on one such EOR technique to improve the vertical sweep efficiency in highly heterogeneous reservoirs. We present the
results of a simulation study that was undertaken with the objective to compare different IOR/EOR techniques including water
flooding, gas injection and simultaneous injection of gas and water. The work included 1) a detailed review of field performance
with focus on the water injection and gas injection pilots, 2) history matching the water injection pilot and 3) investigation of
several EOR processes through performance prediction using dynamic reservoir simulation model built from the history matched
sector model, calibrated on data from a detailed and comprehensive laboratory research program.
Fluid Properties and Gas Displacement Mechanism
The reservoir initial pressure and temperature are about 4200 psi and 250 oF. Formation water is highly saline, with salinity of over
200,000 ppm. The reservoir oil is light (~0.16 cP) and was characterized by a set of PVT experiments and tuning the properties of
pseudo components in a PVT modelling package. An accurate match with experimental laboratory test data provides confidence
that the thermodynamic description of the reservoir oil is sufficient to the extent that it can be used to investigate interactions with
different injection gases. Because of industry experience with CO2 as injection gas and the likelihood of a CO2 source becoming
available, injection carbon dioxide was included in this evaluation. Acid gas, consisting predominantly of H2S, (75%H2S and 25%
CO2) potentially available in the vicinity of the reservoir under study, is also considered. A comparison between the properties of
CO2, acid gas, methane, water and oil at reservoir conditions is shown in Table 1.
For the relevant pressures and temperatures the mixing of acid gas and reservoir oil will always result in a single phase fluid, i.e.
the acid gas is first contact miscible with the oil. Injection of CO2 will result in a miscible displacement of reservoir oil after
continued mass exchange between the two phases (multi-contact miscible with combined condensing and vaporizing drive). As
shown in Table 1, the acid gas is denser and has higher viscosity compared to CO2. This shows that acid gas is a better injectant
from subsurface perspective and is likely to result in more efficient microscopic displacement. However, a numerical model with
necessary geological details is required to realistically assess the relative merits of the various injection processes. In comparison,
methane and the reservoir oil are immiscible, as demonstrated in the slim tube simulation (see Masalmeh and Wei 2009).
Simulation Model Description
Mechanistic sector models were constructed to evaluate the different IOR/EOR techniques and their impact on improving recovery
and sweep efficiency in heterogeneous oil-wet or mixed-wet reservoirs. The simulations were performed using both 2D and 3D
dynamic models based on detailed geological modelling and petrophysical characterisation. A high resolution 3D sector model
was cut-out from a much larger reservoir model that was history matched with more than 30 years of water flooding. This static
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model has a vertical resolution of one foot (160 layers). The model was upscaled to 80 and 48 simulation layers, respectively, to
test grid size sensitivity. Thin layers of low and high permeability were explicitly preserved in all simulation grids, and only blocks
with similar properties were merged, such that no geological details were lost. Simulation results show no significant impact
between the different grid schemes. All subsequent simulation work was performed using the 3D model of 48 layers (25x25x48).
The dynamic model grid cells are 20 x 20 m in area; the base dynamic model is therefore a square measuring 500 x 500 m.
The runs were performed using vertical and horizontal wells. The horizontal well configuration scenario used in the model is a line
drive with an injector and a producer placed in the bottom half of the Lower zone. A horizontal injector is placed in one side of the
model (X=1) and a horizontal producer is placed in the opposite side (X=25). The vertical well configuration scenario is an
inverted 5-spot model with a vertical injector placed in one corner of the model and a vertical producer was placed in the
diagonally opposite corner. Figure 2 shows the permeability profile as a function of depth through the middle of the model. Initial
fluid distributions were assigned to the model using drainage capillary pressure curves and switched to imbibition capillary
pressure when water flood started. The proper use of capillary pressure (both drainage and imbibition) on fluid distribution and
sweep efficiency was discussed previously (Masalmeh et. al. 2004, 2007). The water-oil relative permeability and capillary
pressure curves used in all simulation runs presented in this paper have been generated from a series of SCAL experiments as
presented in earlier publications [Masalmeh et. al. 2004, 2007, 2008). In this study, the simulation work addressed (in addition to
the waterflooding base case) lean gas, CO2 and acid gas injections. In the next section we will introduce the simultaneous injection
of miscible gas and polymer.
Waterflooding
We will first discuss the results of the horizontal well configuration scenario. Figures 3 and 4 show the results of the water
flooding simulation run. Saturation logs have been generated at a distance of 250 m from the injector as a function of pore volume
injected, see Figure 3. Figure 4 shows the waterflood recovery curves of the Upper zone, Lower zone, total recovery and the water
cut as a function of hydrocarbon pore volume injected. The recovery factors of the Lower and Upper zones are calculated based on
the initial oil in place of each zone. The water flooding results are similar to those published earlier where water quickly sweeps
the high permeability Upper zone while most of the oil in the Lower zone is bypassed as no cross flow takes place except near the
producer as water is pulled down due to pressure drawdown of the producer. The data shows the lack of sweep of the Lower zone.
Moreover, most of the oil is produced from the lower zone at high water cut. This water hold-up problem was discussed in detail in
(Masalmeh et al. 2004, 2007), where it was demonstrated that for mixed-wet/oil-wet heterogeneous reservoirs, imbibition capillary
pressure acts as a capillary barrier, preventing cross-flow between the different zones leading to poor vertical sweep efficiency.
Preserving both low- and high-permeability layers, as well as their capillarity contrasts, in the reservoir model has a significant
impact on the waterflood performance predictions because it controls gravity/capillary cross-flow and channelling of injected
water.
Gas Injection
Gas injection (especially carbon dioxide) is a proven enhanced oil recovery method especially for light oil reservoirs. The recovery
for gas injection is further improved when the process is operated under conditions where gas can become miscible with the oil in
the reservoir. In addition to pressure maintenance, the primary objective for gas injection is to improve the displacement efficiency
(or microscopic sweep efficiency) and reduce residual oil saturation below the values usually obtained in waterflooding. However,
the macroscopic sweep efficiency of gas injection (for both immiscible or miscible gas) is usually poor mainly due to the low
viscosity, gravity segregation, leading to unfavourable mobility ratio and premature gas breakthrough. The macroscopic sweep of
gas injection is further reduced for highly heterogeneous reservoirs.
Due to the favourable miscibility conditions both CO2 and acid gas injection have been considered as possible EOR options for the
reservoir under study. Figure 5 (a, b, c & d) shows the results of waterflooding and gas injection runs as a function of pore volume
injected. The results show that for the reservoir settings under study water flooding is better than gas injection irrespective of the
miscibility of the gas. Gas injection is much more sensitive to vertical heterogeneity. Acid gas and CO2 injection (Fig. 5a)
improves the recovery from the Upper zone due to the miscibility with the reservoir oil but the recovery from the Lower zone is
reduced (Fig. 5b) compared to water flooding and the total recovery is also reduced (Fig. 5c). In addition, an early gas breakthrough and a high GOR are evident in Fig. 5d.
Figure 5 also shows that there is a significant difference in recovery factors between immiscible gas (methane) and miscible gas
injection (CO2 or acid gas). Immiscible gas injection results in very poor recovery of both the Upper and Lower zone. This is
mainly caused by two reasons: Firstly, miscible gas injection reduces residual oil saturations to very low values (almost zero) in
the swept zones while residual oil saturation to immiscible gas is about 5%. Secondly, lean gas is much lighter and it has a factor
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SPE 129645
of 2-3 higher mobility (lower viscosity) compared to CO2 and acid gas. Therefore, lean gas segregates more rapidly upward and it
recovers oil from the top part of the reservoir (the top of the Upper zone) leaving behind significant volumes un-swept. On the
other hand, CO2 and acid gas, due to miscibility, lower mobility and higher density, sweep part of the Lower zone especially in the
vicinity of the injector, i.e., CO2 and acid gas penetrates deeper in the reservoir before segregating upward. This results in better
sweep of both the Upper and Lower zones.
Gas injection following water flooding for a number of years (5, 10, 15 years) was also considered in this study. Similar to the gas
injection, the results show that most of the injected gas enters the Upper zone, which was waterflooded by the time that gas
injection started. Consequently the main target of the gas (acid gas, CO2 or lean gas) is then the waterflood remaining oil saturation
in the Upper zone only. The total recovery was marginally improved compared to the continuous water flooding case, see Fig. 6.
Water alternating gas (WAG) was originally proposed to overcome the shortcomings and to improve the sweep efficiency of the
gas injection process. In a WAG scheme, water is mainly used to control the mobility of the displacement and stabilize the front.
Various WAG schemes have been considered in this study. However, the improvement to recovery compared to water flooding is
marginal with the same well spacing and depletion rates, see Fig. 6. The main reason for the poor sweep efficiency of WAG (either
miscible or immiscible) is that water is not providing the mobility control needed to contain the gas in the lower zone as gravity
causes the gas to migrate upwards while water is still held-up in the upper zone by capillary forces. Therefore, both gas and water
sweep mainly the Upper zone and poorly sweep the Lower zone.
For comparison the results (only the recovery from the Lower zone) for both horizontal and vertical well configuration scenarios
are shown in Figure 7. The figure shows that a much poorer recovery is obtained from the Lower zone especially for gas injection.
In this case there is very little difference between acid gas, CO2 or methane (not shown in the figure) performance as the gas
segregates upwards immediately and recovers hardly any oil from the Lower zone.
Simultaneous Injection of Gas and Water
In all the cases discussed so far the recovery from the low permeable Lower zone was poor due to both the capillary forces and/or
the high permeability contrast. The search is therefore for a process that will cause an appreciable fraction of the injected gas to
find its way to the Lower zone. There is no physical force to cause the injected gas to flow from the Upper zone to the Lower zone
as it has lower or similar density as oil. Therefore, a method is required that confines the injected gas to the Lower zone. A
possible way of achieving this is by keeping the Upper zone pressurized by continuous water injection and simultaneously
injecting gas into the Lower zone. A lateral pressure gradient is maintained in the Upper zone, providing Lower zone gas
confinement.
Simultaneous injection of water and gas has been proposed in the past for stratified water-wet reservoirs (Surguchev, et. al. 1996),
homogeneous reservoirs (Rossen, et. al. 2006) or reservoirs with higher permeability in the lower zones compared to the upper
zones (Stone, 2004). In these earlier studies the target is either to reduce the residual oil saturation from Sorw to Sorg or allow deeper
penetration of the gas into the lower part of the reservoir to maximise the benefit of gas injection before gas segregates upwards. In
oil-wet stratified reservoirs, significant volume of oil is left behind due to the capillary hold up problem which leaves all the unswept oil in the low permeable zone as EOR target. The objective, in this case, is to design an EOR process that results in
maximum contact between the gas and the oil in the un-swept zone by confining the injected gas in this zone.
We see an advantage if the gas is miscible with the oil which improves confinement of the gas in the Lower zone. As first contact
miscibility is not a prerequisite for a miscible drive to be successful, we will compare the process using CO2 and acid gas as
injectants. We will also compare miscible gas with immiscible gas by methane injection.
The process was examined in 2D and 3D models, in this paper we will only show the results of the 3D model. The simulation runs
are performed using methane, CO2 and acid gas, where water was injected in the Upper zone and gas was injected in the Lower
zone using horizontal wells. The results are shown in Figure 8. As can be seen, only acid gas results in reasonable improvement of
recovery from the Lower zone, CO2 improves the recovery from the Upper zone only and no improvement in sweeping the Lower
zone is observed. Compared to the water flooding case, the extra recovery obtained in the case of acid gas injection comes at
increased GOR. This shows that it is difficult to confine the gas in the Lower zone even in the 2D model. The water mobility in the
Upper zone is still much higher than the gas mobility in the Lower zone and the gas front lags behind the water front. Increasing
the injection rate of acid gas will only enhance the acid gas cross flow to the Upper zone and does not improve sweep of the Lower
zone. The same runs were performed in 3D and the improvement of sweeping the Lower zone is reduced. This shows that such a
displacement process is unstable and is very sensitive to permeability heterogeneity.
SPE 129645
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As shown in Figure 2, the Upper zone is on average 50-100 times more permeable than the Lower zone. The viscosity ratio
between water and acid gas is about a factor of 6, as water and acid gas viscosity are 0.4 cP and 0.066 cP, respectively. Together
with the relative permeability effects, this reduces the mobility contrast between water and acid gas by about a factor of 10. The
water in the Upper zone will still be a factor (up to) 10 times more mobile than the acid gas in the Lower zone. Because there is
vertical pressure communication, the difference in mobility causes cross-flow to occur where acid gas injected in the Lower zone
travels to the Upper zone, mixing with oil in the Upper zone and/or running in front of the injected water. Even in the case where
the recovery is increased, it will suffer from the disadvantage that is associated with high GOR with acid gas breakthrough.
Simultaneous Injection of Gas and Polymer (Viscosified Water)
In this section we will introduce a novel concept that results in confining the gas in the low permeable Lower zone and leads to
very efficient sweep of both the Upper and Lower zones. This process is particularly useful where there is an impediment for water
to flow from the Upper to the Lower zones due to either vertical permeability reduction at the boundary or capillary pressure
barrier.
The process was first described in GCC (Gulf Cooperation Council) patent (van Vark, 2009) and more recently in a European
patent (Masalmeh et. al. 2009). Figure 9 shows a schematic of the process in a two-layer system, in terms of a two dimensional
cross-section to illustrate the principle. Numerical simulation is then performed to quantify the merits of this process using the
same history-matched sector model described earlier.
From the results and discussion in previous section we see that we may confine the injected gas in the Lower zone if the mobility
of the gas and water (injected in the Upper zone) are made approximately equal. In principle, this can be achieved by increasing
the viscosity of the injected water. Then one can also control the frontal advance by tuning the miscible gas and polymer
(viscosified water) rates. There are two degrees of freedom (injection ratio and viscosity of the aqueous phase) and two features we
want to control (the pressure gradients and the frontal advance). In a perfect two layer system, in theory, one could choose the
process parameters such that the pressure gradients in the Upper and Lower zones are exactly the same and that also the two fronts
move forward at the same rates. However, in reality the system is never as simple as that due to geological heterogeneity, and
because the main aim is to prevent injected gas to cross-flow into the Upper zone leading to early breakthrough, one would in
practice mitigate the risk by “overshooting in the Upper zone”, both with respect to the pressure gradient (greater in the Upper
zone) and the injection rate (inject more in the Upper zone).
Therefore, the first requirement is that the pressure gradient in the Upper zone is larger than or equal to the pressure gradient in the
Lower zone. From Darcy’s law that relationship can be put as follows in an equation:
qg μ g
K l k rg hl
≤
qw μ w
K u k rw hu
[1]
where qg and qw are the injection rate of the gas and the viscosified water at reservoir conditions;
μg
and
μw
are the viscosity of
the gas and the viscosified water; Kl and Ku are the permeability of the Lower and Upper zones; krg and krw are the relative
permeability of gas and the aqueous phase and hl and hu are the thickness of the Upper and Lower zones of the layered oil
reservoir. This condition can also be written as:
⎛ qg ⎞
⎟⎟
q
w
⎝ ⎠
μ w ≥ μ g ⎜⎜
⎛ K u k rw hu
⎜
⎜Kk h
⎝ l rg l
⎞
⎟
⎟
⎠
[2]
The rate of advance of a fluid in a formation is proportional to the storage capacity of the formation. The rate of advance of the
polymer solution is approximated by the following equation:
vw =
qw
whuϕ u
[3]
where w is the width of the reservoir (or distance between injectors in a line drive configuration), ϕu is the porosity of the Upper
zone. The rate of advance of the gas is approximately:
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SPE 129645
vg =
qg
[4]
whl ϕ l
where ϕl is the porosity of the Lower section.
To avoid gas propagating through to the Upper zone, one needs to maintain the water front moving (slightly) faster than the gas
front, i.e., v w ≥ v g . With the two equations for the velocity, this condition can be written as:
qg
qw
≥
ϕ l hl
ϕ u hu
[5]
Substituting equation [5] in [2], the viscosity of the water can be calculated as
⎛ ϕ l K u k rw ⎞
⎟
⎟
ϕ
K
k
⎝ u l rg ⎠
μ w ≥ μ g ⎜⎜
[6]
In summary, in an ideal two-layer system, enforcing the equal signs in equations [5] or [6] will result in an optimal concurrent
flood.
As an example, we will illustrate the required water viscosity for the case of the reservoir under study in conjunction with acid gas
injection. As acid gas is first contact miscible, the “gas” and oil relative permeability end points are approximately the same (~1.0).
Based on our data set the water relative permeability end point is about 0.7. Acid gas viscosity is ~ 0.066 cP. For the case of a
permeability contrast of a factor of 100 and approximately equal porosity, a water viscosity higher than 3.5-4 cP will satisfy the
condition in eq. [6]. For CO2 the viscosity is 0.046 (see Table 1), a water viscosity of ~6 cP will satisfy the condition in eq. [6].
The water viscosity at reservoir conditions is ~ 0.4 cP, a small concentration of e.g. polymer is required to bring the viscosity to ~4
cP. The required increase in water viscosity depends on the actual permeability contrast, which may vary across the field.
The same process can be applied using CO2 instead of acid gas. This would make the operation much easier and cheaper because
of the HSE implications and the acid gas handling. However, acid gas is superior injectant to CO2 because of the better miscibility
with reservoir oil and higher density and viscosity, see Table 1, especially considering its potential availability at the location.
Simulation Results
The discussion above is based on an idealized two-layer system. In this section we present the results of the numerical simulation
which was performed to quantify the merits of this process using the same 3D history-matched sector model described earlier. The
runs were performed using vertical and horizontal well configurations. The horizontal well configuration scenario used in the
model is a line drive with two injectors (one in the Upper zone and one in the Lower zone) and a producer placed in the bottom
half of the Lower zone. The horizontal injectors are placed in one side of the model (X=1) and a horizontal producer is placed in
the opposite side (X=25). The simulation runs are performed where polymer was injected in the Upper zone and gas was injected
in the Lower zone. The model is constrained by bottom hole pressure of injectors and producer as well as the injection rate.
Simultaneous Injection of Acid Gas and Polymer
Figure 10 shows the results of a simulation run, where acid gas (75% H2S and 25% CO2) was injected in the Lower zone while a
polymer solution (viscosity is 4 cP) is injected in the Upper zone. The injection rates were constrained such that 40% of pore
volume of polymer is injected in the Upper zone and 60% of pore volume of acid gas is injected in the Lower zone in 25 years.
The figure shows the recovery curves of the Upper zone, Lower zone, total recovery, water cut and GOR. As shown in the figure
the total recovery factor (at 1 PV injected) for the pilot area simulated is about 87% and the recovery factor of the Upper and
Lower zones are about 92% and 85%, respectively. This shows a significant increase in recovery from both the Upper and Lower
zones indicating that the acid gas was indeed contained in the Lower zone. The increase in the Upper zone recovery compared to
normal water flooding indicates that some cross flow of acid gas into the Upper zone is unavoidable (and advantageous by
reducing remaining oil saturation and sweeping attic oil). A controlled cross flow of acid gas into the Upper zone will have
positive impact. The simulation shows a very efficient displacement process. The GOR increase occurs late and is manageable.
Figure 11 shows the water and acid gas mass accumulations at the end of the simulation run after injecting one pore volume. The
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figure demonstrates that acid gas was contained in the Lower zone, and it also helped sweeping oil from the low permeability
layers in the Upper zone.
Simultaneous Injection of CO2 and Polymer
The same process was modelled by injecting polymer solution in the Upper zone and CO2 in the Lower zone. To facilitate
comparison between acid gas and CO2, both the viscosity of the polymer solution (4 cP) and the injection rates (40/60 split
between polymer and gas) are kept the same as in the acid gas run shown in Figure 10. The results are shown in Figure 12a. As
expected the CO2 is not as efficient as acid gas but still a significant increase in the recovery is achieved compared to water
flooding or CO2 injection. The GOR increase occurs earlier compared to acid gas but handling CO2 is easier than handling acid
gas. The difference between CO2 and acid gas performance is explained by the viscosity and miscibility difference between the
two gases. The mobility of CO2 is higher than acid gas and therefore the CO2 can be confined in the Lower zone by either
increasing the viscosity of the polymer solution to satisfy eq. 6 above (~ 6 cP) or increasing the injection rate of polymer solution
in the upper zone. In both cases, the pressure drop in the upper zone will be increased which leads to better confinement of CO2 in
the lower zone. Figure 12b shows the results of injecting a polymer solution which has a viscosity of 6 cP and 50/50 split of
injection rates between polymer and CO2, i.e, 50% of pore volume of polymer is injected in the upper zone and 50% of pore
volume of CO2 is injected in the Lower zone. The results show a total recovery factor of 84% and a recovery factor of 91% and
80% from the Upper and the Lower zones, respectively at 1.2 pore volume injected for the pilot area simulated. The recovery is
still lower than that of acid gas (when compared at 1 pore volume injected) especially from the Lower zone as more cross flow of
CO2 to the Upper zone is encountered due to the higher mobility of CO2 and miscibility characteristics (multi-contact miscible
compared to first contact miscible) which leads to lower sweep efficiency of the Lower zone. The recovery factor of the Lower
zone can still be optimized by optimizing the injection rates in the upper and lower zones and the viscosity of the polymer solution.
Moreover, to contain the CO2 in the Lower zone, polymer flooding can start earlier so that pressure drop is created in the upper
zone and the water-front moves faster than CO2.
The use of CO2 instead of acid gas makes the operation much easier and cheaper because of the HSE implications and the gas
handling. However, acid gas is a superior injectant to CO2 because of the better miscibility with reservoir oil and higher density
and viscosity. This novel process has the potential to achieve very high recovery factors and significantly improves the sweep in
highly heterogeneous reservoirs, as well as the added benefit of CO2 sequestration. The choice between CO2 or acid gas as
injectant will, therefore, depend on several factors such as HSE, cost, availability of the gas, facilities for handling of break-though
gas, and recovery factor.
Discussion
Oil-wet or mixed-wet stratified reservoirs with high permeability contrasts make conventional recovery processes (water flooding,
gas injection and WAG) inefficient. The reservoirs under study have been the subject of a series of earlier publications, where it
was demonstrated that for such reservoirs capillary forces act as barriers and result in water hold-up in cases of high permeability
contrasts between layers. In such reservoirs both water flooding and gas injection (miscible or immiscible) preferentially sweep the
higher permeability layers in the upper part of the reservoir while large volume of the oil in the lower part with low permeability is
bypassed. We have presented in this paper a novel process that shows significant improvement in vertical sweep efficiency for this
type of reservoirs. The combination of injecting viscosified water in the Upper zone and miscible gas in the Lower zone provides a
very efficient solution to the water override problem. In this process the injected gas is maintained in the Lower zone due to:
1- The pressure gradient provided by polymer solution injected in the upper zone and
2- The miscibility of the gas with oil in Lower zone while it is immiscible with the water injected in the Upper zone.
As clear from the simulation results, the proposed EOR process (SIMGAP) leads to much higher recovery factor compared to
water flooding or conventional gas injection (both immiscible or miscible gas injection). Moreover the EOR process has also two
major improvements over waterflooding and gas injection, i.e., it leads to much lower water cut compared to water flooding and
much lower GOR compared to gas injection.
In the water flooding simulation runs, early water break through is encountered due to the high permeability streaks in the Upper
zone that results in early water cycling and by-passed oil reserves. A recovery factor of more than 50% is achievable but only if the
reservoir is produced at high water cut for a long time. In the conventional gas injection schemes (either miscible or immiscible),
early gas breakthrough is also encountered and to achieve high recovery factors, the field needs to be operated at a high GOR for a
long period. Injecting polymer in the Upper zone increases macroscopic sweep efficiency and acts to improve conformance of
waterflooding in heterogeneous layered reservoirs and reduces water cycling. It also acts to contain the injected gas (either acid gas
or CO2) in the lower zone. On the other hand, the simultaneous injection of gas acts to 1) sweeps the Lower zone and 2) improve
8
SPE 129645
microscopic displacement and reduces residual oil saturation in the upper zone as cross-flow of the injected gas (acid gas or CO2)
from the Lower zone to the Upper zone is inevitable.
To our knowledge this process has not been applied in any field. However, the industry has broad experience in polymer flooding
and miscible gas injection. The proposed EOR process combines these two processes into one feasible recovery mechanism.
Positive results are obtained with both acid gas and CO2. It is also likely to work with other miscible agents. Economic screening,
HSE and availability of the injection gas will influence the choice of gas. Technical challenges remain that will require further
laboratory and field tests. Before applying it in the field, it is necessary to perform detailed modelling and conduct field pilot to
understand and verify the robustness of this process to different parameters such as heterogeneity, well spacing, well configuration,
fluid viscosity, injection rates, etc. We have performed extensive sensitivity runs and generated model forecasts showing that the
process is stable with respect to both lateral and vertical heterogeneity of the reservoir. The viscosity of the polymer solution can
be adjusted in case of even higher permeability contrast between the upper and lower zones. A significant incremental recovery
over water flooding or gas injection is obtained for a wide range of injection rate ratios and polymer viscosity. For the acid gas
case applied to the EOR sector model, a factor of 3 increase in polymer viscosity leads to more than 50% extra recovery from the
lower zone compared to waterflooding. There is still scope for further optimisation, e.g., optimum injection rate ratios and well
configuration.
In the case of CO2, the recovery is more sensitive to injection rates, a higher gas injection rate leads to more CO2 to cross flow
into the Upper zone and hence lower recovery from the Lower zone. It also requires higher viscosity of the polymer compared to
the acid gas case.
The likely effect of polymer injection on effective water/polymer permeability in the upper zone is considered an upside. Further
research is in progress to assess the degree of polymer adsorption and its impact on polymer concentration requirement and
associated potential benefit in reducing polymer mobility in the upper zone.
Conclusions
This paper presents a new and novel EOR scheme to improve oil recovery and vertical sweep efficiency in highly heterogeneous
oil-wet or mixed-wet reservoirs following the concept in refs. (van Vark 2009; Masalmeh et. al. 2009). This has led to the
development of a new recovery process: co-injection of polymer solution into the high permeable Upper zone and miscible gas
into the low permeable Lower zone.
The main findings and conclusions are:
1- Water flooding and gas injection (miscible or immiscible) lead to poor sweep of the lower zone of this kind of reservoirs.
2- Simultaneous injection of gas in the low permeability Lower zone and water in the high permeability Upper zone has little
recovery advantage over water injection, it comes at a cost of high GOR and early gas break-through. This is not a stable
process for reservoirs of high permeability contrast between layers.
3- Simultaneous injection of miscible gas (acid gas or CO2) and polymer shows significant sweep of the Lower zone and
leads to high oil recovery compared to water flooding, miscible gas injection or WAG. It addition it has much lower water
cut and GOR compared to waterflooding and gas injection, respectively.
4- Simulation model forecasts show that this novel EOR process is robust to injection rates and lateral and vertical
heterogeneity. The EOR option is robust for a range of polymer viscosities or injection interruptions. The viscosity of the
polymer solution and injection rates can be adopted to sweep reservoirs of different heterogeneity levels.
5- This novel process has several elements of complexity (surface and subsurface). The nature and degree of geological
heterogeneity, chemicals properties under reservoir conditions require further research efforts and pilot testing. Such
testing has to be designed carefully and monitoring will be key for the successful execution of such a project.
Acknowledgements
We thank our colleagues in Shell Technology Oman for stimulating discussions. We would like to thank Shell management for
permission to publish this paper.
References
Masalmeh, S.K., Jing, X.D., van Vark, W., Christiansen, S., van der Weerd, H. and van Dorp, J.: “Impact of SCAL (Special Core
Analysis) on Carbonate Reservoirs: How Capillary Forces Can Affect Field Performance Predictions” Petrophysics, vol. 45,
no. 5, pp. 403 (2004)
SPE 129645
9
Masalmeh, S.K. and Jing, X.D.: “Improved Characterisation and Modelling of Carbonate Reservoirs for Predicting Waterflooding
Performance”, SPE paper 11722_PP, presented at the at the International Petroleum Technology Conference held in Dubai,
U.A.E., 4–6 December (2007).
Masalmeh, S.K. and Jing, X.D.: ‘The Importance of Special Core Analysis in Modelling Remaining Oil Saturation in Carbonate
Fields’, SCA 2008-3 presented at the SCA 2008 conference, Abu Dhabi, October (2008).
Masalmeh, S.K. and Wei, L.: “An EOR Option for Heterogeneous Carbonate Reservoirs with Complex Waterflood Performance”,
Presented at the IOR 15th European Symposium on Improved Oil Recovery, Paris, France, April 27-29 (2009).
Masalmeh, S.K., Wei, L., Jing, X.D., and van Dorp, J. 2009, “Improving the Oil-Productivity of a Layered Oil Reservoir”, EP
patent application no. EP 09 154794.3. Shell Technology Oman.
Rossen, W.R., van Duijn, C.J., Nguyen, Q.P. and Vikingstad, A.K.: “Injection Strategies To Overcome Gravity Segregation in
Simultaneous Gas and Liquid Injection Into Homogeneous Reservoirs”, SPE 99794, presented at the 2006 SPE/DOE
Symposium on Improved Oil Recovery, Tulsa, April 22-26.
Stone, H.L.: “A Simultaneous Water and Gas Flood design with Extraordinary Vertical Gas Sweep”, SPE 91724, presented at the
2004 SPE International Petroleum Conference in Mexico, Nov. 8-9 (2004).
Surguchev, L. M., Hanssen, J.E., Johannessen, H.M. and Sisk, C.D.: “Modelling Injection Strategies for a Reservoir with an
Extreme Permeability Contrast: IOR Qualification”, SPE paper 35504, presented at the European 3-D simulation modelling
conference, Stavanger, April 16-17, (1996).
Van Vark, V. 2009. GCC patent publication no. GC 0000813. Shell International E&P.
Table 1: Properties of reservoir fluids and injected gases at reservoir conditions of pressure and temperature
Fluid
Density
Viscosity
Miscibility
GOR
(kg/M3)
(cP)
MSCF/STB
Water
1130
0.4
Oil
585
0.16
1475
Acid Gas
640
0.066
First contact
CO2
540
0.046
MMP~ 3200 psi
Methane
135
0.021
MMP >5500 psi
10
SPE 129645
Upper
Zone
100 2000
Lower
Zo
ne
Water
0
0
50
50
Depth [ft]
Depth [ft]
Figure 1. Schematic drawing of the water front advance whereby water is injected into the Lower zone
(vertical and horizontal wells) travels quickly to the Upper zone and along the high permeability streaks
into the crestal part of the reservoir. Water remains in the Upper Reservoir unless it is drawn down by a
well completed directly below in the Lower reservoir.
100
150
100
150
200
200
1
10
100
Perm [md]
1000
Figure 2: Permeability profile at an
observation well location in the middle
of the model.
0 0.2 0.4 0.6 0.8 1
Sw
Figure 3: Saturation profile at an observation
well location in the middle of the model after
injecting 1 PV of water.
SPE 129645
11
1.0
Wcut
RFU
RFL
RFT
0.8
RF
0.6
0.4
0.2
0.0
0.0
0.2
0.4
0.6
0.8
1.0
PVInj
Figure 4: Water flooding recovery curves of the upper zone (RFU), lower zone
(RFL) and total (RFT) and water cut using horizontal wells.
1.0
1.0
WF_Low
Upper Zone
0.8
0.8
0.6
CO2_Low
C1_Low
0.6
RF
RF
Lower Zone
Acid Gas_Low
0.4
0.4
WF_Upp
Acid Gas_Upp
0.2
0.2
CO2_Upp
C1_Upp
0.0
0.0
0.0
0.2
0.4
0.6
0.8
1.0
0.0
0.2
0.4
100
WF_Tot
GOR [MSCF/STB
C1_Tot
RF
0.6
0.4
0.0
0
0.6
PVInj
0.6
0.8
1.0
40
20
0.4
0.8
1.0
C1_GOR
60
0.2
0.2
CO2_GOR
80
CO2_Tot
0.0
1.0
Acid Gas_GOR
Total
Acid Gas_Tot
0.8
0.8
PVInj
PVInj
1.0
0.6
0.0
0.2
0.4
PVInj
Figure 5: Recovery curves of a) upper zone, b) lower zone and c) total for water flooding, acid gas, CO2 and methane injection
using horizontal wells, d) GOR
12
SPE 129645
1.0
1.0
WF_Low
Upper Zone
0.8
Lower Zone
CO2_Low _5yWF
0.8
CO2_Low _10yWF
WAG_Low
0.6
RF
RF
0.6
WF_Upp
0.4
0.4
CO2_Upp_5yWF
CO2_Upp_10yWF
0.2
0.2
WAG_Upp
0.0
0.0
0.0
0.2
0.4
0.6
0.8
1.0
PVInj
0.0
0.2
0.4
0.6
0.8
PVInj
1.0
WF_Tot
Total
CO2_Tot_5yWF
0.8
CO2_Tot_10yWF
WAG_Tot
RF
0.6
0.4
0.2
0.0
0.0
0.2
0.4
0.6
0.8
1.0
PVInj
Figure 6: Recovery curves of a) upper zone, b) lower zone and c) total for water flooding, CO2 following 5 and 10 years of
waterflooding and CO2-WAG injection using horizontal wells
1.0
SPE 129645
13
0.5
WF
Acid Gas
0.4
CO2
0.3
RF
Hor. Wells
0.2
0.1
Vert. Wells
0.0
0.0
0.2
0.4
0.6
0.8
1.0
PVInj
Figure 7: Recovery curves of the lower zone for water flooding, acid gas
injection, CO2 injection using vertical and horizontal wells.
1.0
WF
Acid Gas_Water
0.8
CO2_Water
C1_Water
RF
0.6
0.4
0.2
0.0
0.0
0.2
0.4
0.6
0.8
1.0
PVInj
Figure 8: Total recovery curves for water flooding (WF), simultaneous injection of
water and acid gas (Acid Gas_Water), water and CO2 (CO2_Water) and water and
methane (C1_Water) using horizontal wells.
14
SPE 129645
100-1000 mD
2-4 cP
0.4 cP
Viscous
Water
0.2 cP
Acid Gas
Production
0.06 cP
1-10 mD
(or CO2)
Figure 9: Schematic of the process of simultaneous injection of viscosified
water in the upper and acid gas in the lower
1 .0
15
Wc ut
RF Upper
RF Low er
12
RF Total
RF, Wcut
GOR
0 .6
9
0 .4
6
0 .2
3
0 .0
0
0 .0
0.2
0 .4
0 .6
0 .8
GOR [MSCF/STB]
0 .8
1.0
PVIn j
Figure 10: Recovery curves of upper zone, lower zone, total, water cut and GOR for
simultaneous injection of acid gas and polymer solution in a 3D model. Water viscosity
was increased by a factor of 10.
Figure 11: Viscosified water (left) and acid gas (right) mass accumulation after injecting
1 PV. The figure shows uniform sweep of both Upper and Lower zones.
SPE 129645
15
a)
b)
1.0
1.0
15
Wcut
RF_Upp
RF_Upp
RF_Low
RF_Low
0.8
12
9
0.4
6
3
0.2
3
0
0.0
9
0.4
6
0.2
0.0
0.4
0.6
0.8
1.0
1.2
RF, Wcut
RF, Wcut
0.6
0.6
0.2
GOR [MSCF/STB]
GOR
GOR
0.0
12
RF_Tot
RF_Tot
0.0
0.2
0.4
0.6
0.8
1.0
PVInj
PVInj
Figure 12: Recovery curves of upper zone, lower zone, total, water cut and GOR for simultaneous injection of CO2
and polymer solution in a 3D model, a) using injection rate of 60/40 gas and water and water viscosity is 4 cP and b
using injection rate of 50/50 gas and water and water viscosity is 6 cP.
0
1.2
GOR [MSCF/STB
0.8
15
Wcut