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SPE-184976-MS
Application of Multiazimuth Vertical Planes MAVP to In-Situ Extraction of
Heavy Oil from Shallow and Stranded Oil Sands
Ali Jamali and Mohamed Y. Soliman, Texas Tech University; Mehdi Shahri and Travis Cavender, Halliburton
Copyright 2017, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Canada Heavy Oil Technical Conference held in Calgary, Alberta, Canada, 15-16 February 2017.
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
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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
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Abstract
Throughout the past five decades, the heavy oil industry has developed various in-situ techniques for oil
recovery from the vast global heavy oil reserves. The diversity of these techniques goes hand in hand
with the diversity of the world reserves in terms of viscosity, burial depth, and reservoir complexity.
Reservoirs exist, however, wherein the currently available commercial methods might not be technically
and economically feasible. In particular, reservoir quality and caprock integrity can impose significant
limitations on the feasibility of conventional methods, such as steam assisted gravity drainage (SAGD).
This paper summarizes the results of a series of field trials in weakly cemented formations based on the
creation of highly conductive multiazimuth vertical planes (MAVP) in soft formations. These planes are
mechanically initiated and hydraulically propagated and have typical dimensions of 0.03×5×30 m and can
be used in a new steam injection design. The potential application of this technique to enhanced oil recovery
is investigated using a thermal reservoir simulator.
Reservoir simulations show promising results in terms of cumulative steam oil ratio (CSOR) and oil
production rate. Stabilized production was observed immediately after the startup and CSOR dropped to
under 3.0 m3/m3 in less than two years. The overall performance is nearly comparable to that of conventional
SAGD, while it outperforms SAGD in certain conditions, including low vertical permeability and in the
presence of low permeable shale streaks. Simulation results show that the performance of MAVP is nearly
unimpaired when planes’ projection is discontinuous in either vertical or horizontal directions. The results
also showed that the presence of a confined top water zone does not have a detrimental impact on the
performance of MAVP; however, penetration into the top water zone must be avoided to achieve the best
results in terms of CSOR. While surface mining and variations of SAGD are respectively used for very
shallow and relatively deep reservoirs, the new methodology is applicable to reservoirs in the depth range
of 70 to 600 m, where weak caprock integrity can impose a significant challenge. In addition, complex
reservoir features, such as the presence of low permeable shale layers or low vertical permeability, have
minimal effect on the performance of this technique.
2 SPE-184976-MS
Introduction
After decades of research and feasibility studies that began upon the turn of the twentieth century, oil sands
production was finally commercialized in 1967 with the startup of Great Canadian Oil Sands project. During
this project, open pit mining was used and followed by the extraction of bitumen using a hot water process.
The extracted bitumen could be either sold as raw material or upgraded and sold as synthetic crude oil.
The success of Great Canadian Oil Sands paved the way for the operators of oil sands projects to plan and
initiate many succeeding surface mining ventures (Humphries 2008; Moss 1966; Teare et al. 2013).
The oil sands industry has and will always treasure the groundbreaking role of surface mining in allowing
the commercial production of oil sands. The fact that only by 2012 in-situ production exceeded surface
mining production is a testimony to the pioneering impact of this technique for the oil sands industry to
advance. Nevertheless, although suitable for partial development of oil sands deposits, this technique has
its own shortcomings. A great majority of Alberta's deposits, particularly those located in Peace River and
Cold Lake, lie under a thick overburden. Canadian oil sand surface mining projects demonstrate the impact
of the ratio of overburden thickness to oil sand thickness on successful development of those projects. For
economic success of such projects, this ratio should not exceed one. Another measure of potential successful
application of surface mining is that the overburden should be less than 75 m (Humphries 2008); however,
only 10% of Canada's bitumen deposits are surface minable (Nasr and Ayodele 2005). Based on the same
measures, it is estimated that only 15% of the US resource basin has a ratio of unity or less (Marchant
1987). This thwarts the wide-ranging application of surface mining and necessitates development of more
advanced techniques.
Another approach frequently used in oil sands production is in-situ extraction using thermal recovery
techniques. In-situ thermal operations hold potential as the ultimate solution to recover up to 80% of
Alberta's estimated reserves. Development of oil sands in-situ production techniques began with the Cold
Lake pilot production in 1970, and has steadily progressed from isolated experimental testing to major
commercial development (Sadler 1995). In a comparative study, Nasr and Ayodele (2005) provided an
overview of existing and potential in-situ thermal processes. The following is a summary of this study of
techniques already commercialized or currently being field-tested:
•Steam flooding: this technique has a potential recovery factor of 50%. Although this technique has
been successfully implemented in extraction of heavy crude oils in California and Venezuela heavy
oil fields, it has met limited success in Canadian oil sands deposits because the initial mobility of
the bitumen is relatively low.
•Cyclic steam stimulation (CSS): the primary advantage of this process is quick oil production while
it can only meet recovery factors lower than 20%, which is less than other thermal processes.
•In-situ combustion: the conventional in-situ combustion is plagued with many technical issues.
Variants of this process, such as toe to heel air injection (THAI) and catalytic THAI (CAPRI), were
proposed to overcome some of these issues but did not advance as planned.
•SAGD: this process and its variations are becoming dominant technologies used in oil sands
recovery. Combined steam-solvent injection processes such as Expanding Solvent-SAGD (ES-
SAGD) and solvent aided process (SAP) has shown promising results (Gupta and Gittins 2005;
Nasr et al. 2003).
•Vapor extraction (VAPEX): this is an in-situ nonthermal process similar to SAGD wherein
hydrocarbon solvent is injected in place of steam. This brings an additional advantage of partial
upgrading to this process; however, oil production rates are very low compared to SAGD.
In light of the complexity and diversity of Canada's oil fields, Nasr and Ayodele (2005) concluded
their work by underlining the importance of employing sophisticated and innovative technologies for the
economic development of such reservoirs.
SPE-184976-MS 3
The fact that most of oil sands deposits are not shallow enough for economic development by surface
mining is clearly reflected in the ratio of the numbers of in-situ crude bitumen projects to surface mined
bitumen projects—nearly 3 to 1. These data are reported in Alberta's Energy Reserves and Supply-Demand
Outlook (Teare et al. 2013). Furthermore, although SAGD has demonstrated a recovery factor up to 70%
of bitumen in place, its operations are limited to thick, vertically clean sand reservoirs. Also, natural gas
accounts for 60% of operating costs in SAGD in-situ production (Humphries 2008). This means there
is a great need and potential for improving in-situ techniques, such as SAGD. The question remains
regarding whether enhancements can be delivered to design and implement in-situ techniques to broaden
their applicability and overcome their technical and environmental issues.
Highly Permeable MAVP
During the 1990s, a series of field experiments in weakly cemented formations resulted in the construction
of vertical, continuous, and permeable planes. Numerous field trials have proved the practicality of vertical
highly permeable planes with controlled azimuth, extent, thickness, and coalescence. The low horizontal
stress contrast in soft formations helps ensure that the injected highly viscous fluid moves in the intended
azimuth. This cannot be achieved by injecting through perforations, but rather is feasible if an initiation
casing system is used. In this system, casing becomes dilated before or during the injection process. The
initiation casing system is used to enforce the uniform gradual growth of the planes in the desired direction.
The first application of this technology was during the construction of groundwater treatment walls, known
as permeable reactive barriers (PRBs). Originally, this system was designed to create single-azimuth vertical
planes. Multiple injection wells at the same horizon help ensure the creation of a continuous, extensive, and
thick planes to install full-scale iron permeable barriers for ground water remediation (Hocking and Wells
2002; Hocking et al. 2008).
The idea is extended to expandable casing systems designed to inject vertical planes at differing azimuths
from a single vertical wellbore. This available commercial casing system—referred to here as X-casing
—mechanically expands and splits along pre-aligned openings. Fig. 1 presents a vertical cutaway of the
deployed casing system both pre- and post-expansion. Fig. 2 illustrates a two-trip tool implemented to
trigger X-casings dilation and to execute the injection process. In Mode I, an array of inflatable packers is
lowered inside the casing string and hydraulically expand the X-casings. Fig. 3 shows evident marks left
on the expansion packer element after dilating X-casings. This expansion cracks the cement and initiates
four, six, or even eight wings with equal and constrained opening widths depending on the number and
arrangement of the slots. In Mode II, an injection assembly is used. Starting from the bottommost X-casing,
all apertures are propped in sequence using a highly viscous, clean-breaking fracturing fluid. The sand
proppant is transported into the formation creating multiazimuth highly permeable vertical planes, MAVP
(Fig. 4).
4 SPE-184976-MS
Figure 1—Cutaway of the casing system pre-expansion (left) and post-expansion (right).
Figure 2—Two-trip tool diagram.
SPE-184976-MS 5
Figure 3—Effect of casing dilation on the inflatable packer.
Figure 4—(a) Propped planes revealed after surface excavation; (b) deviations from
the ideal assumptions; noncoalescence and inconsistency in the propagated planes.
6 SPE-184976-MS
These planes can be created simultaneously or successively and under equal or different injection rates. In
some cases, propped planes were observed to be up to 40 m in length and 2.5 cm in width. As shown in Fig.
2, the centers of X-casings are typically located 5 m apart along the vertical borehole. This process has been
extended to depths as great as 500 m, confirming the technology is not limited by depth. However, based on
field observations, it is suggested that significant horizontal stress contrasts can hinder the applicability of
this technology. This is not the case in weakly cemented formations, such as oil sands wherein the horizontal
stress contrast disappears throughout geological time (Hocking et al. 2011 and 2012).
Hocking et al. (2012 and 2013) argued that the geometry, orientation, and connectivity of these planes
have been verified through excavation as well as through active resistivity monitoring and concluded that
propagation of the MAVP is continuous and uninterrupted and their hydraulic conductivity is not affected.
Nonetheless, the authors believe that, in reality, the vertical planes characteristics deviate from this ideal
assumption. This was demonstrated earlier in Fig. 4, wherein discontinuities are observed in the induced
planes. The effect of such deviations from the ideal assumptions will be later addressed in this work.
Application to Enhanced Oil Recovery
This work proposes several practical well configurations of MAVP, which can be used for enhanced oil
recovery. This is summarized in the following:
•It can be used as a single vertical injector/producer, operating in SAGD (or CSS) mode.
•It can be used as a single producer to assist the production of the stranded heated bitumen trapped
under an active SAGD pad. This is illustrated schematically in Fig. 5a.
•It can be used as a single steam injector to assist an ongoing SAGD operation to achieve a more
uniform steam distribution, particularly in highly heterogeneous formations and in the presence of
shale streaks. This is illustrated schematically in Fig. 5b.
Figure 5—(a) Stranded heated bitumen trapped under an active SAGD pad; (b) impaired steam
chamber growth attributed to high vertical heterogeneity and the presence of shale streaks.
This paper focuses on the first proposed application i.e. using MAVP as a single vertical injector/producer
while operating in SAGD mode. The proposed system involves six radially symmetrical permeable planes
originating from a single vertical wellbore (Fig. 6). This system creates ample conductive path from the
wellbore to the bitumen-rich sands in both radial and vertical directions. Superheated steam travels down
the annulus and towards the top of the reservoir. Either a liquid head must be maintained over the production
tubing or a phase-sensing valve should be used for steam trap control. This provides enough contact time to
mobilize the bitumen in place. Extracted liquids are produced at the bottom of the well. The application is
not limited to steam injection and other conventional techniques, such as VAPEX, have inspired variations
of this system (e.g., solvent injection).
SPE-184976-MS 7
Figure 6—Vertical well injecting steam and producing bitumen through the application of MAVP.
The proposed system has several advantages over SAGD, particularly in inconsistent geologies where
the performance of the conventional SAGD is impaired because of inefficient steam chamber growth.
These poor geological anomalies include the presence of a highly permeable zone, the presence of shale
barriers/mud plugs, and low vertical permeability. In shallow depths where the maximum allowable steam
injection pressure is a limiting factor, Shahri et al. (2014) also recommended MAVP as a potential solution.
They showed that, in environments with less caprock integrity, it is possible to make the steam injection
operations feasible at much lower pressures using the MAVP system. The remainder of this paper focuses
on the development of comprehensive numerical models in which both ideal and nonideal assumptions
are incorporated. Several simulation studies are performed to accurately assess the effectiveness of the
abovementioned technology in various scenarios.
Numerical Simulation
A commercial thermal reservoir simulator was used to examine the effectiveness of MAVP in terms of
improving the performance of a steam injection system as well as to compare its performance to that of
conventional SAGD.
Reservoir Description
The reservoir properties correspond to Athabasca oil sands and are described in Table 1. Note that the
maximum allowable operating pressure of 1500 kPa is implemented in this study to help ensure that the
caprock integrity is not violated. Figs. 7 and 8 present relative permeability curves and oil viscosity of
Athabasca oil sands collected from (Ashrafi et al. 2011). The reservoir is homogeneous in all properties
except for the permeability which is presented in Fig. 9.
Table 1—Reservoir rock, fluid, and thermal properties.
Depth 100 m Reference pressure 1000 kPa (at 100 m)
Thickness 40 m Maximum safe operating pressure 1500 kPa
Horizontal permeability 4 D Rock heat capacity 1.5×106 J/(m3.°C)
Porosity 0.33 Rock thermal conductivity 1.5×105 J/(m3.D.°C)
Temperature 13 °C Water thermal conductivity 1.5×105 J/(m3.D.°C)
Water Saturation 0.2 Oil thermal conductivity 1.5×105 J/(m3.D.°C)
Fluid Water, bitumen Gas thermal conductivity 1.5×105 J/(m3.°C)
8 SPE-184976-MS
Figure 7—(a) and (b) Relative permeability curves adopted from Ashrafi et al. (2011). There is considerable debate in
literature regarding relative permeability curves for heavy oil reservoirs primarily concerned with convexity of curves,
sensitivity to temperature, and level of water permeability. These curves are selected as a close approximation of
available data in the literature. Temperature effect is disregarded. The overall effect of relative permeability on the
performance of the cases presented here is beyond the scope of this study. (c) Relative permeability curves used for
the vertical planes. We tested both linear and nonlinear relative permeability curves for the highly permeable planes
and the simulation results were identical. This is attributed to the low volume and high permeability of these planes.
SPE-184976-MS 9
Figure 8—Bitumen viscosity as a function of temperature adopted from Ashrafi et al. (2011).
Figure 9—Permeability distribution in all directions adapted from Pooladi-Darvish and Mattar (2002).
Modeling Scheme and Grid System
Jamali (2014) showed that the optimum performance of the system is achieved when vertical planes have
a length of up to approximately two-thirds of the reservoir external radius. Based on the results from field
trials, a pessimistic value of 25 m is selected for the maximum achievable length of vertical planes. By
taking this number into account, it is proposed that MAVP can optimally drain a cylinder with a diameter
of 75 m through the application of several 25 m wings extended radially from the wellbore, as illustrated
in Fig. 10a. A cushion of 8 m is left at the top of the pay to ensure the thermal energy is confined to the
reservoir. 60-degrees-apart wings are used in all cases presented in this paper. By symmetry, a half-slice of
30° is modeled and the volumetric results are multiplied by the proper number to represent the full model.
The general shape of the system is a vertical conductive plane sitting on the side of a 30° slice, as shown in
Fig. 10b. The properties of the highly conductive vertical planes used in this study are described in Table 2.
Table 2—Vertical permeable planes properties.
Number of Planes 6 (60° spacing) Vertical permeability 600 D
Dimensions 0.02×30×26 m Porosity 0.33
Horizontal permeability 600 D Water saturation 0.6
10 SPE-184976-MS
Figure 10—MAVP modeling scheme and grid system for six wings of 25-m long.
Because the fluid flow is strictly controlled by these highly conductive planes, a proper grid refinement
is necessary around the planes’ face both in radial and angular directions. Cylindrical grids are the best
descriptors of the reservoir for the portion of the flow that is occurring from the reservoir toward the wellbore
in the radial direction. On the contrary, the wings have uniformly constant width, which inhibits the use of
cylindrical grids; therefore, the proper grid coordinates are generated in a corner-point grid system using
a computer code. A horizontal cross section of the 30° slice is shown in Fig. 10c. Note that unlike the
reservoir grids, plane grids maintain a constant width. Finally, Fig. 10d shows a 3D view of the full model
grid system. The authors cannot put more emphasis on the importance of using an appropriate grid system.
The previous simulation studies on this technique produced overly optimistic results because an incorrect
grid system was used.
Case One: Conventional SAGD vs. MAVP
To compare the performance of these two techniques, a generic Athabasca sandstone bed with the
dimensions of 40×600×600 m will be developed using (1) eight SAGD well pairs and (2) 64 MAVP systems,
as shown in Fig. 11. These two scenarios are illustrated and compared in this section.
SPE-184976-MS 11
Figure 11—Comparison between SAGD and MAVP development of the pay zone. MAVP drainage volume is simulated
using cylinders while, in reality, a square control volume exists. This difference is accounted for by use of a shape
factor. Dietz shape factor for a perfectly circular and square drainage patterns are 31.6 and 30.9, respectively;
therefore, the diameter of the simulated cylinder has to be 1.02 times greater than the diameter of the shown cylinders.
The first scenario describes a discretized well model of a dual well (injector/producer) SAGD process
based on the approach of Card et al. (1996). The reservoir grid is a 25×3×22 axis of symmetry. The reservoir
element is 40-m high with 5-m well spacing between the injector and the producer and 37.5-m half-well
spacing. The process includes high pressure steam circulation in both wells for initial communication
followed by pressure drawdown and several years of oil production by means of SAGD. Table 3 describes
these well operation stages.
Table 3—Well Operations for each SAGD well pair.
— Preheat Phase (5 months) High Pressure
SAGD (2 months)
Depressurization
Phase (2 months) SAGD Phase
Upper Well
Up to 800 m3/d 50% quality
steam, 250 °C through the
upper tubing. Production
from upper casing under
1400 kPa
Up to 800 m3/d 90% quality
steam, 250 °C through the
upper tubing. Shut in upper
casing
Up to 400 m3/d 90% quality
steam, 250 °C through the
upper tubing
Up to 400 m3/d of 90%
quality 200 °C steam
through the upper tubing
Lower Well
Up to 800 m3/d 50% quality
steam, 250 °C through the
lower tubing. Production
from lower casing under
1300 kPa
Maximum production of
100 m3/d from the lower
casing and 1200 m3/d from
the lower tubing both under
steam trap control
Maximum production of
200 m3/d from the lower
casing and 1200 m3/d from
the lower tubing both under
steam trap control
Production under steam trap
control
The second scenario describes an MAVP system located in the center of a cylindrical drainage area. This
cylindrical reservoir has a diameter of 75 m and is 40-m high. The highly permeable vertical planes are
extended 25 m radially as described previously. The injection/production scheme is described as injection
of 80 to 100% quality steam at 200°C on the top of the reservoir and immediate oil production at the bottom
of the wellbore under the steam trap control or through the sump.
Fig. 12 compares the performance of these two techniques. As evident from this figure, the MAVP
system has the advantage of immediate oil production owing to immediate gravity drainage while SAGD
oil production is negligible until the beginning of the SAGD phase (t = 9 months). According to Fig. 12a, in
short term SAGD outperforms the MAVP system in terms of recovery factor, whereas the ultimate recovery
factors for both methods are approximately 50%. Fig. 12b compares the CSOR wherein MAVP outperforms
12 SPE-184976-MS
SAGD. The ultimate CSOR for MAVP is approximately 0.5 m3/m3 less than that of SAGD (2.3 vs 2.8 m3/m3).
This is because MAVP benefits from a more effective steam chamber growth in the vertical direction. The
fact that initial CSOR for MAVP system is remarkably smaller than that of SAGD can also affect economic
aspects of the decision-making process. Nevertheless, the last case study illustrates how these assessment
factors are strong functions of key parameters (e.g., vertical planes’ dimensions). Therefore, the purpose of
this illustration is not to show that the performance of the MAVP system is superior to that of SAGD, but
rather to illustrate the potential application of this technique in special cases based on the promising results
presented. A quick discussion on the cost of MAVP is provided in Appendix A for the interested reader.
Figure 12—Case One: comparison of the performance of SAGD and
MAVP in terms of (a) oil production rate and recovery factor (b) CSOR.
MAVP Physics and Recovery Mechanism. Similar to SAGD, MAVP uses steam drive to enhance the
oil production; however, in theory, the highly conductive vertical planes should provide a much greater
contact area between the superheated steam and bitumen compared to that of SAGD. Fig. 13 shows the
temperature profile in the reservoir as a function of time. Fig. 14 shows the temperature variation in the
angular (J) direction after two years. Two important observations are suggested by these figures: (1) the
steam chamber growth in the radial direction is slow and therefore the distant regions of the reservoir are not
immediately exposed to high temperatures unlike what is expected in the presence of the highly conductive
vertical planes and (2) the steam chamber growth in the angular direction is almost immediate.
SPE-184976-MS 13
Figure 13—Temperature profile for MAVP as a function of time (°C).
Figure 14—Temperature variation in the angular (J) direction (°C).
Based on these two observations, the recovery mechanism of MAVP can be divided into (1) the radial
spreading and (2) the downward vertical sweeping. This is schematically shown in Fig. 15. During the
radial spreading (t < 6 years), the steam chamber penetrates outward and resembles a growing tornado at the
center of the cylindrical reservoir. This corresponds to a continuous increase in the oil production rate which
peaks after approximately six years (Figs. 12a and 13). The vertical downward sweep occurs after the steam
chamber reaches the outer boundary of the reservoir (t > 6 years). During this stage, the oil production rate
declines until the reservoir is entirely swept in the vertical direction.
Figure 15—Schematic of MAVP drainage mechanism. Mobilized oil flows
towards the bottom of the reservoir through both matrix and conductive planes.
14 SPE-184976-MS
Case Two: MAVP Performance in Low Vertical Permeability and in the Presence of Low Permeable
Shale Streaks
Because MAVP benefits from an effective steam chamber growth in vertical direction, the performance
of this technique is not greatly affected by reduced vertical permeability, a bottleneck that can affect the
effective application of conventional SAGD. In this case study, the vertical reservoir permeability is reduced
to one-half and one-fourth of their original values. The results are presented in Fig. 16. While SAGD shows
a significantly delayed peak of oil production, the performance of MAVP is much less affected and the
overall shape of oil production curve is preserved. More importantly, the ultimate CSOR is significantly
lower for MAVP compared to that of SAGD.
Figure 16—Case Two: comparison of the performance of SAGD and MAVP in terms of (a) oil production
rate and recovery factor, kv = one-half of the base case (b) CSOR, kv = one-half of the base case (c) oil
production rate and recovery factor, kv = one-fourth of the base case (d) CSOR, kv = one-fourth of the base case.
Another potential application of MAVP is in the presence of sealing shale streaks. This is investigated by
introducing a low-permeability shale layer to the system which separates the top 20% of the reservoir. The
results are shown in Fig. 17. For SAGD, steam cannot effectively access the top portion of the reservoir
in the presence of the sealing shale streak. This reduces the ultimate oil recovery, which renders SAGD
uneconomical in terms of both recovery factors and CSOR. While a low permeable barrier can impede the
vertical steam chamber growth in conventional SAGD, the highly conductive vertical planes provide an
effective path for the steam, and the performance of MAVP remains nearly intact.
SPE-184976-MS 15
Figure 17—Case Two: comparison of the performance of SAGD and MAVP in terms of (a) oil
production rate and recovery factor (b) CSOR in the presence of low permeable shale streaks.
Case Three: Effect of Noncoalescence and Discontinuities in Highly Permeable MAVP
The construction of a 30 m-high vertical plane is feasible only if vertical coalescence occurs. Furthermore,
highly conductive planes can contain discontinuities. This case study investigates the performance of
noncoalesced, partially coalesced, and discontinuous MAVP systems. These scenarios are schematically
illustrated in Fig. 18 and their performances are compared in Fig. 19. The results indicate that the
performance of MAVP is nearly identical for discontinuous and partially coalesced cases compared to the
base case presented in the first case study. For the noncoalesced case, the ultimate oil recovery is improved
about 3% at the expanse of a 0.8 m3/m3 increase in the ultimate CSOR. Nonetheless, the results show that
none of these situations are detrimental to the performance of the MAVP system.
Figure 18—(a) Noncoalesced highly permeable vertical planes; injection and production occurs
simultaneously in both planes under steam trap control (b) partially coalesced vertical planes (c)
presence of discontinuities in vertical planes modeled using reduced permeability (green) in those zones.
16 SPE-184976-MS
Figure 19—Case Three: comparison of the performance of SAGD and
MAVP in terms of (a) oil production rate and recovery factor (b) CSOR.
Case Four: Performance of MAVP in the Presence of a Top-Water Thief Zone
The existence of thief zones such as top water zones or gas caps has been a major concern and is discussed
in detail in the literature. For SAGD, it was shown that such thief zones can have negative effect on oil
recovery and CSOR (Law et al. 2003; Pooladi-Darvish and Mattar 2002). In this case study, the performance
of MAVP is assessed in the presence of confined and unconfined top water zones. An 8-m top water zone is
added to the system at the top of the reservoir. This is the case for a generic Athabasca oil sands formation
as reported by Law et al. (2003). The unconfined top water zone is modeled by adding a producer to the top
water zone operating under a minimum bottomhole pressure constraint. Two scenarios are also considered
for the vertical planes: (1) nonpenetrating MAVP in which the vertical planes are confined within the main
pay zone and (2) penetrating MAVP in which the vertical planes are penetrated into the top water zone.
The results for the unconfined top water zone are presented in Fig. 20. For SAGD, the presence of a
confined top water zone results in a pause in peak oil production, immediately after steam breaks into the
water zone, and an ultimate CSOR increase of approximately 0.5 m3/m3. This result corresponds to similar
studies in the literature (Law et al. 2003). Similar to SAGD, both nonpenetrating and penetrating MAVP
also experience a slight increase of 0.25 m3/m3 in the ultimate CSOR. Therefore, it is concluded that the
effect of a confined water zone is not highly detrimental, but rather unfavorable. Fig. 21 shows the results
for an unconfined top water zone. The results show that the presence of an unconfined top water zone has a
detrimental effect on the economics of SAGD as well as nonpenetrating and penetrating MAVP. The results
for SAGD correspond to other studies in the literature (Law et al. 2003). This effect is more prominent for
MAVP because the steam breaks into the top water zone in a much shorter time. The extreme steam and
loss into the unconfined top water zone renders all three methods uneconomical. In any case, it is explained
earlier that the permeable planes are created through sequential construction of coalescing planes. Therefore,
if necessary, penetration into the top water zone should be prevented by selecting a smaller number of plane
initiation sequences which reduces the ultimate coalesced height of the vertical planes.
SPE-184976-MS 17
Figure 20—Case Four: Comparison of the performance of the nonpenetrating MAVP, penetrating MAVP, and SAGD
in the presence of a confined top water zone in terms of (a) oil production rate and recovery factor (b) CSOR.
Figure 21—Case Four: Comparison of the performance of nonpenetrating MAVP, penetrating MAVP, and SAGD
in the presence of an unconfined top water zone in terms of (a) oil production rate and recovery factor (b) CSOR.
18 SPE-184976-MS
Case Five: Sensitivity Analysis
A sensitivity analysis to the key parameters affecting the performance of MAVP is of utmost importance.
This includes (1) number of wings (2) permeability contrast between the planes and the formation (3) vertical
planes’ width and (4) vertical planes’ length. Fig. 22 summarizes the oil recovery factor and CSOR as a
function of these four parameters after 10 years from the startup. Fig. 22a indicates that the most influential
parameter is the number of wings. On average, each additional wing adds 1 to 3% to the recovery factor,
while it has a slightly adverse effect on the CSOR (approximately 0.05 m3/m3 per wing). Fig. 22b shows
that increasing the length of the vertical planes can increase the recovery factor and decrease the CSOR,
but these two parameters reach plateaus after 60% of the formations’ external radius is penetrated. The
effects of permeability contrast and planes’ width are almost identical (Figs. 22c and 22d). Increasing both
parameters contributes to a higher recovery factor and a lower CSOR.
Figure 22—Case Five: Sensitivity analysis on the number of wings, permeability contrast, planes’ width and planes’ length.
Summary and Conclusions
The future of heavy oil plays greatly depends on more innovative techniques that help production from
zones that are currently uneconomical. In this study, a brief history of the development of highly permeable
MAVP was presented along with a detailed numerical study to investigate its performance compared to the
conventional SAGD in various scenarios. Major conclusions follow:
•MAVP technology is primarily applicable to zones of high permeability contrast attributed to the
presence of shale and mud plugs where SAGD steam chamber growth is adversely affected.
•The performance of MAVP is not as sensitive to formation vertical permeability as it is for SAGD.
While reduced vertical permeability only slightly affects the performance of MAVP, it can be
detrimental to the economics of SAGD.
SPE-184976-MS 19
•The ideal assumptions made about the geometry of the vertical planes, such as vertical coalescence
and continuous propagation, do not have remarkable effects on the performance of the MAVP
system.
•The presence of a confined top water zone does not have a detrimental effect on the performance
of MAVP; however, the penetration into the top water zone must be avoided to achieve the best
results in terms of CSOR.
•Sensitivity analysis showed the optimum performance of MAVP is a strong function of number
of wings, permeability contrast between the planes and the formation, vertical planes’ width, and
vertical planes’ length. The first parameter plays a key role and on average after ten years of
production each additional wing adds 1% to 3% to the recovery factor, while it has a slightly adverse
effect on the CSOR (approximately 0.05 m3/m3 per wing).
Acknowledgements
This work was funded through generous support of Halliburton. We thank Halliburton for their financial
support as well as technical and editorial comments during the preparation of this paper. The cost analysis
was prepared through personal communication with Mr. John Person, to whom we express our appreciation.
We acknowledge Computer Modeling Group for providing Texas Tech University with access to their
commercial software.
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SPE-184976-MS 21
Appendix A
A discussion on the cost comparison of SAGD and MAVP is presented here. Keep in mind that the
technology is not commercialized yet and accurate cost estimations are not plausible at this stage. A pilot
program to compare SAGD vs. MAVP would be beneficial to validate the model and understand the
economics benefits of accelerated production and increased recovery factor. Under the current oil sands
drilling environment, the cost to drill and complete a typical 800 m SAGD pair is approximately USD 3.5
MM (USD 1.75 MM per lateral). The MAVP pilot program would consist of eight vertical drilled wells
adjacent to the same SAGD reservoir. The MAVP wells would have six proppant filled wings with 60°
spacing extending out 25 to 30 m from the wellbore. The most cost effective well construction strategy
would be a two-phase approach. Phase 1 would mobilize a shallow depth drilling rig and drill each of
the wells back-to-back. The drilling operations would confirm the vertical geology, install the X-casing
sections based on the geology, and the assemblies would be cemented into position. Phase 2 would be the
completion phase. A completion rig would be brought in to install the proppant filled wings and to deploy
the injection/production completion assembly. Under this strategy, the wells could be completed back-to-
back or individually completed with several months of production between each well completion. The later
would allow for improvements to be made based on production data and learning curve. It is estimated that
the drilling and completion costs for the MAVP pilot program would be approximately USD 4.5 MM (John
Person, Sr. Tech Prof Leader at Halliburton, personal communication, April 2016).
