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Numerical Simulation of SAGD Recovery
Process in Presence of Shale Barriers,
Thief Zones, and Fracture System
a

a

b

b

T. Q. C. Dang , Z. Chen , T. B. N. Nguyen , W. Bae & C. L. Mai
a

University of Calgary , Calgary , Alberta , Canada

b

Sejong University , Gwangjin-ku , Seoul , Korea

c

c

Ho Chi Minh City University of Technology , Ho Chi Minh , Viet Nam
Published online: 19 Jun 2013.

To cite this article: T. Q. C. Dang , Z. Chen , T. B. N. Nguyen , W. Bae & C. L. Mai (2013) Numerical
Simulation of SAGD Recovery Process in Presence of Shale Barriers, Thief Zones, and Fracture System,
Petroleum Science and Technology, 31:14, 1454-1470, DOI: 10.1080/10916466.2010.545792
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Petroleum Science and Technology, 31:1454–1470, 2013
Copyright © Taylor & Francis Group, LLC
ISSN: 1091-6466 print/1532-2459 online

DOI: 10.1080/10916466.2010.545792

Numerical Simulation of SAGD Recovery
Process in Presence of Shale Barriers,
Thief Zones, and Fracture System
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T. Q. C. Dang,1 Z. Chen,1 T. B. N. Nguyen,2 W. Bae,2 and C. L. Mai3
1

University of Calgary, Calgary, Alberta, Canada
2
Sejong University, Gwangjin-ku, Seoul, Korea
3
Ho Chi Minh City University of Technology, Ho Chi Minh, Viet Nam

This study presents a numerical investigation for evaluating the potential applicability of the steamassisted gravity drainage (SAGD) recovery process under complex reservoir conditions such as shale
barriers, thief zones with bottom and/or top water layers, overlying gas cap, and fracture systems in
the McMurray and Clearwater formation. The simulation results indicated that the near-well regions
were very sensitive to shale layers, and only long, continuous shale barriers (larger than 50 m or
25%) affect the SAGD performance in these well regions. In addition, the thief zones had a strongly
detrimental effect on SAGD. The results also showed that the SAGD recovery process was enhanced in
the presence of vertical fractures but horizontal fractures were harmful to recovery. Fracture spacing is
not an important parameter in the performance of a steam process in fractured reservoirs and extending
horizontal fractures will reduce ultimate oil recovery in the SAGD process. This article provides a
guideline for SAGD operations in complex geological reservoirs.
Keywords: fracture system, numerical simulation, SAGD, shale barriers, thief zones

INTRODUCTION
Alberta’s oil sands deposits, with estimated 1.7 trillion barrels of bitumen in place, account for

approximately 40% of the world’s bitumen resources (Figure 1). However, an extremely high
viscosity of bitumen at reservoir temperature is one of the greatest challenges in using a recovery
process. At a company with recent advances in horizontal well technology, steam-based in situ
recovery methods, aiming at a thermal viscosity reduction, have emerged for exploration of these
vast resources (Butler, 2001). The steam-assisted gravity drainage (SAGD) recovery process has
opened the door to producing a large number of bitumen reservoirs in Canada.
SAGD was first developed by Roger Butler and his colleagues in Imperial Oil in the late
1970s. It is a thermal oil recovery process that consists of a pair of two parallel horizontal wells
drilled near the bottom of the pay. The top horizontal well is used to inject steam, and the bottom
horizontal well is used to produce reservoir fluids (Figure 2). The heat from steam is transferred by
thermal conduction into the surrounding reservoir. The steam condenses and the heated oil flows
to the production well located below by gravity. Two types of flows exist during this process.
Address correspondence to Wisup Bae, Sejong University, 98 Gunja-dong, Gwangjin-ku, Seoul 143-747, Korea. E-mail:


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SAGD RECOVERY PROCESS

FIGURE 1

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Oil sands in Alberta, Canada. (color figure available online)

One is at the ceiling of a steam chamber and the other is along the slopes of the steam chamber.
The success of an SAGD project depends on some key factors such as an accurate reservoir

description, efficient utilization of heat injected into the reservoir, understanding of displacement
mechanisms, understanding of geomechanics, and overcoming various constrains (Doan et al.,
1999). Successful field tests have proven that SAGD is a viable technology for in situ recovery
of heavy oil and bitumen (Singhal et al., 1998; Butler, 2001; Boyle et al., 2003).
The SAGD technique has many advantages over other thermal methods such as conventional
steam flooding methods. SAGD overcomes the shortcomings of steam override by using only

FIGURE 2

Steam-assisted gravity drainage technology. (color figure available online)


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gravity as the driving mechanism, which leads to stable displacement of oil and potentially high
oil recovery. In addition, the heated oil remains hot and movable as it flows toward the production
well, whereas in conventional steam flooding, the oil displaced from the steam chamber cools down
and consequently the oil-phase viscosity increases as the oil flows to the production well (Chen
et al., 2008). The SAGD process is made more thermally efficient by maintaining a liquid pool that
surrounds the bottom production well and preventing the escape of steam from the steam chamber.
However, Farouq Ali (1997) and Singhal et al. (1998) pointed out some limitations of SAGD
as follows: (1) the theory pertains to the flow of a single fluid; (2) only steam flows in the steam
chamber, oil saturation being residual; (3) the heat transfer ahead of the steam chamber to cold
oil is by conduction only; (4) sand control may be necessary; (5) there is a hot effluent/high
water cut production; (6) frequent changes in operating regimes and high operating costs occur;
and (7) deterioration of production at late stages occurs. This article presents a comprehensive

evaluation of SAGD’s performance in presence of continuous shale barriers, discontinuous shale
barriers, bottom and top aquifers, and gas cap layers. In particular, the effect of a fracture system
on SAGD operation is also described.
STATEMENT OF THE PROBLEM
The success of SAGD has been mostly demonstrated by numerical simulation with homogeneous
reservoir models. However, this process is very sensitive to reservoir heterogeneity; therefore, it
is necessary to have a comprehensive understanding of the effects of reservoir heterogeneity on
SAGD performance for wider and more successful implementation.
The efficiency of the SAGD process is significantly decreased in the presence of shale barriers
or thief zones such as bottom and top aquifers, overlying gas caps, or fracture systems. Thus,
the first attempt of this research is motivated by the need for an improved SAGD process in
heterogeneous reservoirs. Such an improvement is crucial to broaden the applications of SAGD
and unlock vast discovered heavy oil/bitumen resources worldwide.
In addition, the performance of SAGD is compared in different geological areas including the
McMurray formation and the Clearwater formation. This comprehensive comparison will allow
us to fully evaluate the effect of reservoir properties on the SAGD process in hostile conditions.
DESCRIPTION OF A SYNTHETIC RESERVOIR MODEL
The advanced thermal reservoir simulator, STARS, developed by the Computer Modeling Group
Ltd. (Calgary, Alberta, Canada), was used to construct a reservoir model and evaluate the performance of the SAGD process. A synthetic reservoir model that represents two generic formations
in the Alberta oil sands was selected for this research. The main reservoir properties of two
formations are shown in Table 1.
In order to reflect the reservoir heterogeneity, the formation consisted of clean sands and shaly
sands that contained some thin shale lenses. The bitumen viscosity of the McMurray formation
was much higher than that of the Clearwater formation. The producers, with a length of 900 m,
were located at the bottom of the reservoir and the injectors were 5 m above the producers. The
horizontal spacing between well pairs was 50 m. The steam injection pressure was set at 2,500
kPa for the McMurray formation and 3,600 kPa for the Clearwater formation.
In the first 4 months, we specified a line heater in the grid cells that contained the wellbores
instead of using steam circulation through both the left and right injection and production wells.
The heat flux was determined by the amount of latent heat in which 400 m3 /day of 0.95 quality

steam was delivered to the reservoir. A steam trap control is important in SAGD as well as


SAGD RECOVERY PROCESS

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TABLE 1
Typical Reservoir Properties of McMurray and Clearwater Formations

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Reservoir Parameter
Reservoir depth, m
Porosity
Vertical permeability (Kv ), D
Permeability ration (Kv =Kh )
Oil saturation
Reservoir pressure, kPa
Reservoir temperature, ı C
Bitumen viscosity at reservoir temperature, cP
Rock compressibility, 1/kPa
Formation heat capacity, kJ/m3 .K
Rock thermal conductivity, J/m.d.C
Oil thermal conductivity, J/m.d.C
Water thermal conductivity, J/m.d.C
Gas thermal conductivity, J/m.d.C

McMurray
Formation

Clearwater
Formation

210
0.35
3
2
0.8
1,800
11
2,000,000
7E 06
2.39EC06
6.6EC05
1.15EC04
5.3496EC04
139.97

450
0.31
1.5
2
0.7
2,900
12
60,590
9.6E 06
2.35EC06
6.6EC05

1.15EC04
5.3496EC04
139.97

fast-SAGD to prevent or reduce steam production from the reservoir. This steam trap control
should result in keeping all of the latent heat generated by the steam inside the reservoir and
producing only bitumen and condensed hot water. In this study, the operating constraint at the
production wells imposed a maximum temperature difference between the saturation temperature
corresponding to the pressure of the fluids and the temperature in the wellbore equal to 5ıC.
RESULTS AND DISCUSSION
Shale Barriers
Heterogeneity plays a critical role in understanding steam chamber growth at the actual field
scale and within simulations. It is important and necessary to understand the factors determining
growth rates and areal propagation. Unfortunately, most numerical simulation investigations have
been conducted with homogeneous systems, so these studies cannot be applied directly to provide accurate, reliable predictions for a field-type system. During the last two decades, several
researchers have attempted to evaluate the effect of reservoir heterogeneity on steam chamber
development for the SAGD process. One of the first to present their research on this topic was
Joshi and Threlkeld (1985). Through experiments at the laboratory scale, Yang and Butler (1992)
studied the effect of a shale barrier length (short and long horizontal barriers) for both top steam
injection and bottom steam injection cases. With a top steam injection, the presence of a short
horizontal barrier has no effect on the general performance and a long horizontal barrier decreases
the production rate, though not as much as expected in some configurations. They also concluded
that the heated bitumen above the barrier may not be produced even though it is hot because
of the steam pressure holding up the oil at the bottlenecks to the flow. Additionally, Yang and
Butler (1992) showed that long shale barriers can cause a difference in the advancement velocity
of the interface above and below the barrier. This difference is reduced by the drainage of heated
bitumen through conduction above the barrier.
Pooladi-Darvish et al. (2002) proposed a better way to investigate the effect of shale barriers in
complex geological characterizations by using a stochastic model based on geostatistical methods
to represent the shale distribution. Chen et al. (2008) conducted a numerical simulation study on

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the stochastic of shale distribution near the well region and above the well region. They stated
in their conclusion that the SAGD performance was affected adversely only when the above-well
region contained long, continuous shales or a high fraction of shales.
Recently, Ipek et al. (2008) conducted numerical studies of interbedded shales in SAGD.
The purpose of this research was to determine the potential of pressure cycling as a method of
enhancing the reservoir permeability. Le Ravalec et al. (2009) conducted a numerical investigation
and showed that the influence of shale baffles depended upon their locations relative to the well
pairs. Shin and Choe (2009) constructed a two-dimensional homogeneous model and tested the
effect of shale barriers that were located in the above- and between-well pairs.
The effect of reservoir heterogeneity on SAGD performance was studied by including randomly distributed, discontinuous or continuous, thin shale lenses. Shale is characterized by low
permeability, typically in the range of 10 6 to 10 4 mD. The effects of shale barriers have been
investigated in many case studies (Yang and Butler, 1992; Pooladi-Darvish et al., 2002; Chen
et al., 2008) and different depending on the location, size, and volume of the shale layers.
Shale Barriers between Injector and Producer
First, the effect of discontinuous shale barriers in the horizontal direction was evaluated; the
size of shale barriers varied from 5 to 30 m. Steam cannot perfectly propagate in a reservoir when
a shale barriers exist; thus, the cumulative oil recovery continuously decreases as the size of the
shale barriers increases (Figures 3 and 4). The shale barriers had a great effect on the amount of
oil recovery in the Clearwater formation.
Figure 5 shows the effect of shale barrier orientation on cumulative oil recovery in the
McMurray formation. The numerical simulation indicated that the thermal efficiency would be
significantly decreased in the presence of vertical shale barriers due to the fact that a steam

chamber cannot perfectly develop in the sideway as shown in Figure 6. As a result, the SAGD
performance is higher in the case of horizontal shales as compared to vertical shale barriers. In

FIGURE 3 Effect of discontinuous shale barriers in the horizontal direction on cumulative oil recovery in the
McMurray formation. (color figure available online)


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FIGURE 4 Effect of discontinuous shale barriers in the horizontal direction on cumulative oil recovery in the
Clearwater formation. (color figure available online)

FIGURE 5
online)

Effect of discontinuous shale barrier orientation on cumulative oil recovery. (color figure available


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FIGURE 6

Effect of discontinuous shale barrier orientation on the steam chamber. (color figure available online)

addition, an increase in shale barriers in both cases led to an increase in cumulative steam-oil
ratios (CSOR; Figures 7 and 8).
The effect of continuous shale barriers in the horizontal and vertical directions was compared
and is shown in Figure 9. The existence of continuous shale barriers in the vertical direction is
the worst-case scenario for SAGD operation; it prevents the steam chamber from forming in the
sideway and, as a result, the CSOR is the highest and the cumulative oil recovery is the lowest
among three cases. Figures 10 and 11 indicate the dominant effect of continuous shale barriers
on the cumulative oil recovery in the McMurray and Clearwater formations. Oil recovery is much
lower in the presence of lengthy continuous shale barriers.

FIGURE 7
online)

Effect of discontinuous shale barriers in the horizontal direction on CSOR. (color figure available


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FIGURE 8
online)

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Effect of discontinuous shale barriers in the vertical direction on CSOR. (color figure available

FIGURE 9 Effect of continuous shale barriers in the horizontal and vertical directions on CSOR and cumulative

oil recovery in the McMurray formation. (color figure available online)


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FIGURE 10 Effect of continuous shale barrier size on cumulative oil recovery in the McMurray formation.
(color figure available online)

FIGURE 11 Effect of continuous shale barrier size on cumulative oil recovery in the Clearwater formation.
(color figure available online)


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FIGURE 12 Effect of shale volume (horizontal direction) on cumulative oil recovery in the McMurray formation.
(color figure available online)

The volume of shales is also a critical issue that strongly affects the SAGD performance.
Figures 12 and 13 indicate that the cumulative oil recovery largely decreased as the shale volume
increased in terms of shale barriers in the horizontal direction. Once it reached the shale layers,
steam chamber development and oil recovery did not increase much due to the restricted area
available for steam flow to pass the layers. However, the dependence of bitumen recovery on the

shale volume in the vertical direction was slight because steam could move up to the top of the
reservoir without any difficulty.
Shale Barriers Above-Well Pairs
Discontinuous shale barriers had a minor effect on the SAGD performance; the cumulative oil
recovery and CSOR were almost similar even when the length of the shale barriers increased from
10 to 40 m (Figures 14 and 15). However, there was a significant difference between continuous
and discontinuous shale barriers. The continuous shale layers that exceed 70 m in length were
detrimental (low cumulative oil recovery and high CSOR) to the SAGD process. In the Clearwater
formation, the CSOR sharply increased when the shale barrier extended from 30 to 70 m.
Figures 16 and 17 show the effect of the location of the shale barriers on cumulative oil
recovery and CSOR. The shale layers were located in three important positions: near the injection
well, in the middle of the reservoir, and at the top of the reservoir. The simulation results indicate
that the well pairs should not operate near a shale layer because those layers will prevent the
propagation of steam in the vertical direction.
As the volume of discontinuous shale barriers increased, the cumulative oil recovery slightly
decreased (Figure 18). On the contrary, the amount of bitumen recovery greatly decreased as the
volume of continuous shale barriers in the reservoir increased (Figure 19). It is important to note
that this phenomenon is immutable even when the shale layers are located near the injection well,
in the middle of the reservoir, or at the top of the reservoir.


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FIGURE 13 Effect of shale volume (vertical direction) on cumulative oil recovery in the McMurray formation.
(color figure available online)

FIGURE 14 Effect of discontinuous shale barrier size (above-well pair) on cumulative oil recovery in the
McMurray formation. (color figure available online)


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FIGURE 15 Effect of discontinuous shale barrier size (above-well pair) on cumulative oil recovery in the
Clearwater formation. (color figure available online)

FIGURE 16 Effect of shale barrier location (above-well pair) on cumulative oil recovery in the McMurray
formation. (color figure available online)


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FIGURE 17 Effect of shale barrier location (above-well pair) on CSOR in the McMurray formation. (color
figure available online)

FIGURE 18 Effect of shale volume (discontinuous shale barriers, above-well pair) on cumulative oil recovery
in the McMurray formation. (color figure available online)

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FIGURE 19 Effect of shale volume (continuous shale barriers, above-well pair) on cumulative oil recovery in
the McMurray formation. (color figure available online)

Thief Zone Layers
In order to investigate the effect of thief zones including a bottom water zone (BWZ), overlaying
water zone (OLWZ), and gas cap, another numerical simulation study was conducted. An active
aquifer, 10 m thick (either above or below bitumen zones), was added to the reservoir model.
The cumulative oil recovery in the case of OLWZ was much lower than in the BWZ because the
injected steam was diverted into the water zone (Figure 20). Another disadvantage of the OLWZ
is the moving of oil in the pay zone into the top water zone when a very small pressure gradient
exists between the steam chamber and the top of the water zone. The OLWZ acts as an absolute
thief zone in the SAGD process because it delays sweeping of the pay zone by the steam chamber.
These important features may significantly reduce the efficiency of the SAGD process.
However, Doan et al. (2003) found that as steam was continuously injected into the confined
overlying water sand, enough heat was available to flash water into steam and allow gravity to
drive oil from the top of the reservoir. In addition, simulation results indicated that the effect of
a gas cap on cumulative oil recovery and CSOR was slightly higher than BWZ and OLWZ. As
the steam chamber approached the gas cap, and if the steam pressure was kept higher than the
gas cap pressure, steam and possibly some oil were pushed into the gas cap (Pooladi-Darvish and
Matter, 2002).

Fractured Reservoir
The numerical simulation of the SAGD process was investigated in a fractured reservoir. A
dual-porosity model was applied to represent the fractured system. The fractured porosity and

permeability were 0.65 and 10 Darcy, respectively. From the simulation results, the formation of
a steam chamber in a fractured reservoir is faster than in a conventional reservoir due to the large


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FIGURE 20 Effect of BWZ and OLWZ on cumulative oil recovery and CSOR in the McMurray formation.
(color figure available online)

difference in permeability between the matrix and fracture systems. The steam spreads through
the fractures and then starts to heat up and diffuse into the matrix.
Figure 21 shows the effect of vertical fractures on cumulative oil recovery. High conductivity of
the vertical fractures helped steam to propagate deep into the reservoir, diffuse into a matrix block,
affect the matrix for more contact, and lead to higher ultimate oil recovery than in a conventional
reservoir. The simulation results also indicated that with a higher density of vertical fractures, the
final cumulative oil recovery increased.
An unexpected effect in the lateral expansion of the steam chamber was that only a small
amount of the injected steam could diffuse upward from the fractures to the top of the reservoir.
Thus, the cumulative oil recovery in the presence of horizontal fractures was greatly decreased
compared to a conventional reservoir (Figure 22). Moreover, increasing the horizontal fracture
density was detrimental to the operation of the SAGD process due to low bitumen recovery and
high CSOR.

CONCLUSIONS
A simulation study was conducted to examine the feasibility of bitumen recovery using the SAGD
process in hostile conditions such as shale barriers, thief zones, and fractured reservoirs of two

main formations in the Athabasca oil sand area. Following are the conclusions of this study:
1. The near-well regions were very sensitive to shale layers and only long, continuous shale
barriers (larger than 50 m or 25%) affected the SAGD performance at these well regions.
The location and direction of these shale barriers also played important roles in the SAGD
performance. The Clearwater formation was more sensitive to the degree of reservoir
heterogeneity than the McMurray formation.


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FIGURE 21 Effect of vertical fractures on cumulative oil recovery in the McMurray formation. (color figure
available online)

FIGURE 22 Effect of horizontal fractures on cumulative oil recovery in the McMurray formation. (color figure
available online)


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2. In both formations, the OLWZ acted as an absolute thief zone to the SAGD process because
it delayed the sweeping of the pay zone by the steam chamber, whereas the BWZ may be
useful for remaining the reservoir pressure.
3. Vertical fractures can sharply improve the performance of the SAGD process. However,
horizontal fractures can be detrimental to the SAGD process by significantly decreasing the

amount of bitumen produced as well as thermal efficiency.

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