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Journal of Petroleum Science and Engineering 45 (2004) 213–231
Electrical-heating-assisted recovery for heavy oil
E.R. Rangel-Germana, J. Schembrea, C. Sandbergb, A.R. Kovsceka,*
aPetroleum Engineering Department, Stanford University, Stanford, CA 94305-2220, USAbTyco Thermal Controls, 300 Constitution Drive, Menlo Park, CA 94025, USA
Received 21 August 2003; accepted 9 June 2004
Abstract
Warming heavy oil (940–1000 kg/m3, 10j–20j API) reduces its viscosity substantially; however, conventional thermal
recovery by steam injection is not applicable to a number of heavy-oil reservoirs. This paper explores localized electric
resistance heating provided by mineral-insulated cable and a novel heater–well arrangement. Two-dimensional (2-D) and
heterogeneous three-dimensional (3-D) reservoir simulation models employing single- and dual-lateral completion horizontal
wells illustrate that an electric resistance heating element with a modest power output enhances recovery several fold. Important
parameters for improved recovery are (1) solution gas, (2) formation and fluid thermal conductivity that permits conductive
heating, and (3) the ability to achieve relatively low bottom-hole pressure in production wells. Economic analysis suggests that
the cost of electricity is about 1.25 USD per barrel of incremental oil.
D 2004 Elsevier B.V. All rights reserved.
Keywords: Thermal oil recovery; Thermal conduction; Heavy oil; Electric resistance heating
1. Introduction Consider the Alaskan North Slope field of Ugnu as
In excess of 4 billion bbl of oil have been recovered
in the United States alone as a result of thermal
recovery operations, chiefly steam injection (Moritis,
2002). The addition of heat reduces the viscosity of
heavy oil (densityz 940 kg/m3 or APIV 20j) substan-tially, thereby improving oil mobility and the produc-
tivity of wells. Nevertheless, conventional steam
injection candidates are limited to relatively shallow,
thick, permeable, and homogeneous sands that are
onshore.
0920-4105/$ - see front matter D 2004 Elsevier B.V. All rights reserved.
doi:10.1016/j.petrol.2004.06.005
* Corresponding author. Tel.: +1-650-723-1218; fax: +1-650-
725-2099.
E-mail address: [email protected] (A.R. Kovscek).
an example of a reservoir where the addition of heat
might enhance recovery greatly, but conventional steam
injection does not appear to be feasible. Oil viscosity at
reservoir conditions is estimated to range from 2 to 300
Pa-s (2,000–300,000 cP; Hallam et al., 1991; Islam et
al., 1991). The reservoir has permeable sands (100–
3000 md, 1 md = 10� 15 m2) that should allow reason-
able productivity if oil viscosity is reduced. The pres-
ence of hundreds of feet of permafrost, concerns about
permafrost disruption, and Arctic surface conditions
deters consideration of thermal recovery.
Use of electricity to enhance oil recovery is not a new
topic.Electrical heatingof reservoir formations employ-
ing alternating current was field tested as early as 1969
for enhanced oil recovery (Pizarro and Trevisan, 1990),
and a number of variants of the process patented in the
Fig. 1. The simple well model: the area of reduced oil viscosity
around the wellbore is shaded.
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231214
1970s (Gill, 1970; Crowson, 1971; Kern, 1974;
Hagedorn, 1976; Pritchett, 1976). Others have studied
the flow of direct current through a formation as a
means to increase fluid flux and the relative permeabil-
ity to oil (Chillingar et al., 1970). Some heating occurs
as a result. Most investigations have explored alternat-
ing current applications for in situ heating (Pizarro and
Trevisan, 1990). The mode of heating depends on the
frequency of the electrical current. In the radio frequen-
cy and microwave range (i.e., short wavelength) di-
electric heating prevails (cf. Sahni et al., 2000 for a
review). Polar molecules tend to align and relax with
the alternating electric field. The molecular movement
may result in significant heating. Unfortunately, it
appears difficult with available microwave antennae
to propagate this short wavelength radiation deep
within the formation (Sahni et al., 2000). When low-
frequency alternating current flows through a reservoir,
resistive or ohmic heating of the formation occurs
(Harvey et al., 1979; Hiebert et al., 1986; Pizarro and
Trevisan, 1990; Sierra et al., 2001). An electrical path
through the formation is provided by brine, and elec-
trical energy is dissipated as heat. Unfortunately, ohmic
heating is reduced as water saturation decreases or if a
majority of the water has been heated to form steam.
The resistive heating process was also combined with
water injection to overcome such problems (Harvey et
al., 1979; Harvey and Arnold, 1980).
Rather than rely on the reservoir to carry electrical
current or electromagnetic radiation, commercially
available mineral-insulated (MI) cables are self-
contained electric resistance heaters (Afkhampur,
1985). Formation brine need not be present to carry
electrical current or heat. Alternating current flows
between two conductors packed in a resistive core
composed of graphite and polymers. As heater tem-
perature increases, electrical resistance of the mineral
insulation increases. Thus, a self-regulating mecha-
nism is achieved that eliminates overheating of the
element and coking of the oil. An MI downhole heater
has a cross-section of 2.5 by 0.8 cm and is supplied in
lengths ranging from 300 to 1000 m, making them
practical for installation in horizontal wells. Heat
output varies between 48 and 288 W/m (50 and 300
BTU/h/ft). The device described by Afkhampur (1985)
operates with 480 VAC.
A simulation study is presented of alternative
thermal recovery employing MI cables. The intent is
to explore if the modest heating available with such
cables is sufficient to enhance oil recovery and to draw
out important oil and formation parameters that influ-
ence recovery. This heating process stimulates oil
recovery primarily by reducing oil viscosity around
the well bore and secondly by thermal expansion of
reservoir fluids. To illustrate the improvement of well
injectivity or productivity, we review the calculation of
the well index (WI) for a single well, with fixed well
bore pressure, single-phase flow at steady state, pro-
ducing or injecting in a finite domain with fixed
pressure boundaries:
WI ¼ 2pkh
lln rorw
� � ð1Þ
where k is permeability, l is viscosity, h is the
formation thickness, ro is the drainage radius, and rwis the well radius.
Fig. 1 shows that the well index is a composite of
heated and unheated regions (Dake, 1978). The heated
region, between rw and ra, is assumed to undergo a
constant temperature change, while the outer region is
unaffected. Enhanced production is described by the
ratio
WIV
WI¼
ln rorw
� �
lrlnrarw
� �þ ln ro
ra
� � ð2Þ
where lr is the ratio between the warm-oil viscosity and
the original viscosity. Thus, the enhancement of well
productivity is related directly to oil viscosity reduc-
tion; however, the size of the region where temperature
Table 1
Properties of components
Component Molecular
weight
kg/mol
Critical
temperature
Tc (K)
Critical
pressure
pc (kPa)
Water 0.01802 647.3 22.100
Heavy fraction 0.600 – –
Medium fraction 0.450 783.2 0.96500
Methane 0.016 190.6 4.5989
Propane 0.0443 369.8 4.2448
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231 215
is elevated modifies WI in a logarithmic fashion. The
latter implies relatively less sensitivity to heated zone
size.
Table 2
Coefficients in the correlation for gas–oil equilibrium ratios
Water Heavy Medium Methane Propane
A 0 0 3.14E+ 06 1.03E+ 06 2.12E+ 06
B 0 0 212 0 0
C 0 0 � 2777.8 � 1032.2 � 2222.22
D 0 0 266.5 0 � 0.1833
2. Model description
The reservoir simulation model approximates some
facets of the Ugnu and West Sak reservoirs (Werner,
1985; Panda et al., 1989; Sharma et al., 1989; Gon-
douin and Fox, 1991; Hallam et al., 1991; Foerster et
al., 1997). The oil is modeled compositionally as a live
oil. In the first section, simulations are conducted in a
two-dimensional (2-D) vertical cross-section. Second,
a three-dimensional (3-D) model incorporating hetero-
geneity is used.
All flow simulations were performed using the
commercial simulator Steam, Thermal, and Advanced
Processes Reservoir Simulator (STARS; CMG, 1998).
Details of the model for fluid properties as well as
grids used for computations are given below. Reser-
voir heating with MI cables occurs locally around well
bores, and the method does not rely on the formation
to carry electrical current. Accordingly, conventional
thermal reservoir simulators are capable of predicting
the effects of this type of electrical heating provided
that they allow the introduction of a heat source or
sink. STARS provides such an option. Hence, the
flow equations, mathematics, and solution procedure
are standard for thermal reservoir simulation and well
established (Aziz et al., 1987).
2.1. 2-D vertical section
The flow simulation grid is a two-dimensional
Cartesian vertical section. A vertical section captures
critical physical phenomena, such as gravity, thermal
conduction, and production mechanisms. The layer
studied is 29 m (95 ft) tall and 160 m (525 ft) in length.
Wells are assumed to be developed in multiple patterns,
and thus all boundaries are no flux (i.e., 160-m well
spacing). The gross formation volume is 4636 m3/m,
and the formation pore volume is 1626 m3/m. Initial
volumes of oil and water are 975 and 648 m3/m,
respectively.
A variety of grids were studied to minimize the run
time and numerical dispersion. The different grids
provided the same final oil recovery. Oil and gas rates
as a function of time displayed discrepancies. Block
boundaries in the horizontal direction were selected in
a pattern similar to that proposed by Aziz et al. (1987).
A locally refined grid of 15� 19 blocks was used with
the following dimensions: Dy = 42.7, 21.3, 9.10,
9� 1.52, 9.10, 21.3, 42.7 for 160 m (525 ft) total,
and Dz = 19� 1.52 m for a 29 m (95 ft) total. This grid
provided realistic performance by the simulator and
was also validated by replicating previous results of
Aziz et al. (1987). This adds confidence to the physical
correctness of the input data files used in this study.
The reservoir fluids are modeled compositionally
with five components, as detailed in Tables 1 and 2.
The initial oil phase is modeled using methane
( f1 = 0.35), medium ( f2 = 0.02), and heavy ( f3 = 0.63)
components, where f is the species mole fraction.Water
is assumed to be immiscible in the oil, and propane is
used as a solvent. The solution gas–oil ratio (GOR) is
about 21 m3/m3 (120 SCF/STB). This is a common
value for heavy-oil reservoirs (Jaubert et al., 2002). The
effect of the solution gas–oil ratio was examined for
four different initial molar concentrations of gas: 10%,
20%, 30%, and 35%, as presented later. A correlation
for the gas–oil equilibrium ratio, kij, is used to repre-
sent the gas–liquid phase behavior as a function of
temperature and pressure (CMG, 1998):
kij ¼A
pþ B
� �exp
C
T � D
� �ð3Þ
where T is temperature in K, p is pressure in kPa, A, B,
C, and D are coefficients summarized in Table 2.
E.R. Rangel-German et al. / Journal of Petroleum216
The initial pressure in the model is 8.96 MPa
(1300 psi), and the initial reservoir temperature is
14 jC (58 jF) at the formation top located at a depth
of 884 m (2900 ft). The sand porosity is 35%. It is
assumed that initially there is no free gas and, the
water saturation is 40%. The permeability is homo-
geneous, isotropic, and equal to 500 md. The water–
oil and gas–liquid relative permeability data shown in
Figs. 2 and 3 correspond to those for the Schrader
Bluff field, Alaska (Hallam et al., 1991). Rock and
reservoir properties are summarized in Table 3.
Fig. 4 shows viscosity as a function of temperature
for the medium and heavy components of the oil
phase. The viscosity of both components decreases
drastically with temperature. Oil-phase viscosity, lo, is
computed according to (CMG, 1998)
lnðloÞ ¼Xnci¼1
filnðliÞ ð4Þ
where li is the component viscosity and nc is the
number of components in the oil phase.
Fig. 2. Water–oil relative permeabil
2.2. 3-D model
In this case, a 3-D heterogeneousmodel is usedwith a
mean permeability of 500 md. Permeability is distribut-
ed within the model using sequential Gaussian simula-
tion (Deutsch and Journel, 1998; Fig. 5). There are
16� 8� 19 grids of variable size with grid refinement
of the y-direction in the area of the well: Dx= 16�30.5 m; Dy= 5� 1.52, 9.14, 21.34, 42.67 m; Dz= 16�1.52 m. The total dimensions are thus 488 m
long� 80.72 m wide� 29.0 m thick. The length of the
horizontal section of the well is 488 m (1600 ft). The
compositional description as well as the viscosity versus
temperature relationships are identical to the 2-D case.
Science and Engineering 45 (2004) 213–231
3. Results—two-dimensional model
First, the effect of continuous heating on depletion is
studied. The horizontal well is centered in the y-direction
and located vertically in themiddle of the formation. The
producer operates under a constant flowing bottom-hole
ity data (Hallam et al., 1991).
Fig. 3. Gas– liquid relative permeability data (Hallam et al., 1991).
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231 217
pressure (BHP), as described below. A heating device,
such as MI cable, is located in the production well. In
practice, the heater is placed outside the casing and
cemented in place, or inside the casing and adjacent to
any tubing. Eight cases are considered:
1. No heating (base case); BHP= 3.1 MPa (450 psi).
2. Continuous heat input of 300 BTU/(h/ft) and
BHP= 3.1 MPa (450 psi).
Table 3
Rock and reservoir properties
Porosity, / 0.35
Horizontal permeability, kh 500 md
Vertical permeability, kv 500 md
Initial pressure, pi 8.96 MPa
Initial temperature, Ti 14.4 jCInitial So 60%
Initial Sw 40%
API 11.3
Effective formation compress 0.0725 MPa� 1
Volumetric heat capacity 2.34� 106 J/m3/jCThermal conductivity 1.49� 105 J/m /day/jC
3. No heating; BHP= 0.69 MPa (100 psi).
4. Continuous heat input of 48 W/m [50 BTU/(h/ft)]
and BHP= 0.69 MPa (100 psi).
5. Continuous heat input of 96 W/M [100 BTU/(h/ft)]
and BHP= 0.69 MPa (100 psi).
6. Continuous heat input of 144W/m [150 BTU/(h/ft)]
and BHP= 0.69 MPa (100 psi).
7. Continuous heat input of 192W/m [200 BTU/(h/ft)]
and BHP= 0.69 MPa (100 psi).
8. Continuous heat input of 288W/m [300 BTU/(h/ft)]
and BHP= 0.69 MPa (100 psi).
Fig. 6(a) shows the cumulative oil recovery on a per
meter basis, and Fig. 6(b) presents the production rate
as a function of time for these eight cases. The worst
recoveries are obtained under cold conditions (no heat
input), and the best recovery is obtained with the
minimum bottom-hole pressure and maximum heat
input, case 8. Here, cumulative recovery relative to the
base case increased by over 100%. Fig. 6 also teaches
that the flowing bottom-hole pressure is a critical
parameter for maximizing oil recovery. Compare cases
Fig. 4. Viscosity of medium and heavy crude-oil components as a function of temperature.
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231218
1 and 3 that have no heating but differ in the bottom-
hole pressure. Cumulative recovery is increased by
more than 35% if the bottom-hole pressure is reduced
from 3.1 MPa (450 psi) to 0.79 MPa (100 psi).
Fig. 5. Pattern and permeability distribution
Fig. 7 compares the pressure distribution for case 1
and case 8 after 10 years of fluid production. Dark
shading represents lower pressure. The top image of
Fig. 7 shows that after 10 years of production without
used for the 3-D heterogeneous case.
Fig. 6. Effect of heating on oil recovery: (a) cumulative oil recovery and (b) oil rate.
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231 219
heating, areas far away from the producer do not ‘feel’
the effects of the well; these areas remain at the initial
reservoir pressure (9.0 MPa, 1300 psi). On the other
hand, a combination of heating and a small bottom-hole
pressure develops a pressure gradient extending through
the entire reservoir, as shown in the bottom image of
Fig. 7. Greater reservoir volumes are contacted by one
well when operated in a fashion similar to case 8.
Fig. 8 presents the temperature distribution for case
8. White shading represents temperatures of 54 jC
Fig. 7. Comparison of the pressure (mPa) distributions of cases 1 and 8 after 10 years of fluid production.
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231220
(130 jF) or greater. The extent of the heated region is
about 18.3 m (60 ft) in the horizontal direction and
covers practically the entire height of the layer. The
temperatures in the heated zone vary from 20 jC (68
jF) to more than 48 jC (120 jF) very close to the wellbore; this represents a considerable increment to the
initial reservoir temperature. Fig. 4 shows that an
increment in temperature of only 5.5 jC (10 jF)reduces the oil viscosity significantly, and therefore,
the resistance to flow is reduced in proportion to
heating.
Fig. 8. Temperature (jC) distribution for cas
3.1. GOR and recovery
The initial GOR of the oil was varied to test its effect
on recovery. Fig. 9 illustrates the cumulative oil recov-
ery for different gas (methane) mole fractions: 10%,
20%, 30%, and 35% (6, 12, 18, and 21 m3/m3,
respectively). The producer bottom-hole pressure is
constant at 3.1 MPa (450 psi). Cold-production results
indicate that oils with large GOR give greater oil
recoveries. For example, compare 10 mol% gas versus
35 mol% gas. This result is a function of increasing
e 8 after 10 years of fluid production.
Fig. 9. Effect of GOR on cumulative oil recovery.
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231 221
compressibility and decreasing oil-phase viscosity as
the gas content increases. When the production is
heated, oil recovery is greater as expected. The curve
for recovery of the heated GOR=21 m3/m3 case is
more than four times that of the case of the GOR= 6m3/
m3 case under cold production.
Fig. 10. Temperature (jC) distribution for different location
3.2. Well location
Additional simulations were performed placing the
producer in every cell (i.e., every 1.5 m) from the
lower limit to the upper limit of the reservoir and
the oil production evaluated. The producer was at a
s of the producer after 10 years of fluid production.
Fig. 11. Effect of location of producer on cumulative oil recovery. Distances are from the top of the reservoir.
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231222
constant bottom-hole pressure of 3.1 MPa (450 psi),
and the heat input was 288 W/m (300 BTU/h/ft). As in
the previous cases, the heater and producer were
located together. Fig. 10 shows the temperature distri-
bution for three different locations of the producer after
10 years of fluid production: top, middle, and bottom
of the formation, respectively. For a single-well pro-
Fig. 12. Temperature distribution for the best combination of locations o
BHP= 3.10 MPa, and heat input is 288.4 W/m.
cess, a large amount of heat is lost to the overburden or
underburden if the well is placed very close to the layer
boundary. Thus, the well is placed near the middle of
the layer. Fig. 11 shows the cumulative oil recovery for
9 of the 19 locations studied, that is every 3.0 m. The
recovery curve for cold production of a well placed
2.3 m from the bottom boundary is also included in
f producer–heater/injector after 10 years of fluid production (jC),
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231 223
Fig. 11. The greatest oil recovery is obtained when the
heater is placed near the middle of the formation. Exact
positioning of the heater is not critical. Results are
similar for a well placed 12.2 to 18.3 m (40 to 60 ft)
from the reservoir top.
Up to this point, the producer and heater/injector
have been located together. An arrangement of wells
similar to that used for steam-assisted gravity drainage
(SAGD) or vapor extraction (VAPEX) is also possible
(Butler, 1991). Here, the heater is placed some distance
above the producer and oriented parallel to the produc-
er. To study the best combination of a producer–heater/
injector pair, the producer was located 2.3 m above the
lower limit of the reservoir, working at constant bot-
tom-hole pressure conditions of 3.1MPa (450 psi). The
heater was placed sequentially at increasing vertical
separation above the producer. The heat input was set at
288 W/m (300 BTU/h/ft). This case is similar to the
previous (location of single producer), in the sense that
heat losses need to be minimized by placing the heater
near the center of the vertical layer. When the heater has
a location different from the producer, other factors need
to be taken into account. If the heater is too far from the
producer, the producer does not take full advantage of
Fig. 13. Effect of location of heater on cumulative oil recovery, B
the heat input. On the other hand, if the heater is placed
too close to the producer orwithin the producer, then part
of the heat provided by the heater is lost by the
immediate production of the hot oil. Fig. 12 illustrates
the temperature distribution for the best combination of
locations of the producer and heater after 10 years of
fluid production. Compared to Figs. 8 and 10, the region
of greatest temperature is noticeably larger.
Fig. 13 shows the cumulative oil recovery for 9 of
the 19 locations studied covering the layer every two
grid cells (i.e., 3 m). The optimal distance between
producer and heater is a function of the properties of the
reservoir. It depends strongly on thermal conductivity,
permeability, and oil viscosity. The optimum distance
between heater and producer, as gauged by oil produc-
tion, is around 4.8 to 6.2 m (15–20 ft). Similar to
Fig. 11, oil production is not especially sensitive to the
spacing. Spacings from 3 to 7.6 m give roughly the
same recovery.
3.3. Solvent injection
In this section, solvent (propane, C3) injection for
saturated conditions is presented. The object of
HP= 3.10 MPa. Distances are from the top of the reservoir.
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231224
propane injection is twofold: reestablish the pressure
of the reservoir (provide energy) by filling the void
space left by the produced oil and reduce the oil
viscosity by dissolving gas into the heavy oil. In
order to study propane injection with electrical heat-
ing, an arrangement similar to the position of the
injector/producer pair in the SAGD technique is
chosen. The producer is located 2.3 m (7.5 ft) above
the lower limit of the reservoir, working at constant
bottom-hole pressure conditions of 0.69 MPa (100
psi), as previously. The heater/injector is located 6.1
m (20 ft) above the producer. The heat input is set to
288 W/m (300 BTU/h/ft). The following cases were
studied:
S1. Cold production (single horizontal well). This
case corresponds to a single producer working at
a constant bottom-hole pressure of 0.69 MPa
(100 psi). Neither solvent nor heat is input into
the reservoir. The producer is always open.
S2. Heated production (single horizontal well).
Similar to case 1, but the producer is heated
continuously during the entire production. No
solvent is injected. The producer is always open.
S3. Solvent injection for 230 days followed by cold
production (two horizontal wells) followed by
heated production (and no injection) for 500
days. Then the producer is shut in, the heating
device is turned off, and C3 is injected at 4.1 MPa
(600 psi) for 230 days. Then, the injector is shut
in and the producer is open to constant bottom-
hole pressure cold production.
S4. Solvent injection for 230 days followed by heated
production (two horizontal wells). Heated pro-
duction (and no injection) for 500 days. Then, the
producer is shut in. The heating device is turned
off, and C3 is injected at 4.1 MPa (600 psi) for
230 days. Then the injector is shut in, and the
producer is open to constant bottom-hole pres-
sure heated production.
S5. Continuous solvent injection followed by cold
production (two horizontal wells). Heated pro-
duction (and no injection) for 500 days. Then,
the producer is shut in. The heating device is
turned off, and C3 is injected at 4.1 MPa (600
psi) continuously. After 230 days, the producer is
open to constant bottom-hole pressure cold
production.
S6. Propane injection (lower pressure) for 230 days
followed by heated production (two horizontal
wells). Heated production (and no injection) for
500 days. Then, the producer is shut in, the
heating device is turned off, and C3 is injected at
2.8 MPa (400 psi) for 230 days. Then, the
injector is shut in, and the producer is open to
constant bottom-hole pressure heated production.
S7. C3 injection (lower pressure) for 180 days
followed by heated production (two horizontal
wells). Heated production (and no injection) for
912 days. Then, the producer is shut in, the
heating device is turned off, and C3 is injected at
2.8 MPa (400 psi) for 180 days. Then, the injector
is shut in, and the producer is open to constant
bottom-hole pressure heated production.
S8. Cyclic solvent injection and heated production
(two horizontal wells). Heated production (and
no injection) for 500 days. Then, the producer is
shut in, the heating device is turned off, and C3 is
injected at 4.1 MPa (600 psi) for 100 days. Then,
the injector is shut in, and the producer is open to
constant bottom-hole pressure heated production
for 500 days. The 500 day producing and 100
day injecting cycles are repeated for 10 years.
S9. Huff and puff cyclic C3 injection heated
production (single well). Heated production
(and no injection) for 500 days. Then, the
production is shut in, the heating device is turned
off, and C3 is injected at 4.1 MPa (600 psi) for 100
days (from the same well). Then, the injection is
stopped, and the producer is open to constant
bottom-hole pressure heated production for 500
days. The 500 day producing and 100 day
injecting cycles are repeated for 10 years.
The first two cases are single-well schemes that
operate more or less continuously. Cases S3 to S8 are
various cyclic options employing dual horizontal wells.
Case S9 is a single-well cyclic scheme operated in a
fashion similar to a huff-n-puff steamed well. Fig. 14
displays the cumulative oil recovery for the different
cases. This plot shows that for this particular reservoir
and fluid and rock properties, the methods are bounded.
The worst oil recovery is obtained in case S1—cold
production with no injection; and the best oil recovery
is obtained in case S2—continuous heated production
with no injection.
Fig. 14. Cumulative oil recovery for different thermal methods.
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231 225
All methods (except case S1) were designed in
such a way that during the first 500 days, heat is input.
Cases S3 and S5 have similar behavior. The only
difference is that in case S5, propane is injected until
the end of the 10-year period. Case S5 has a smaller
cumulative oil recovery as compared to case S3. This
is because injecting solvent continuously causes early
breakthrough of solvent to the producer, because the
solvent has greater mobility relative to oil.
Cases S3 and S4 were designed to have the same
initial behavior: first 500 days are heated, 230 days of
propane injection, and then cold (case 13) and heated
(case 14) production. The slope of case S3 in Fig. 14
is similar to case S1 and case S5 that also correspond
to cold production conditions. On the other hand, the
slope of case S4 is similar to that of case S2
corresponding to heated production conditions. The
chief controlling factor for these heavy-oil recovery
schemes is the heat input.
Cases S4 and S6 are similar, the only difference
is the propane injection pressure from 500 to 730
days. Case S6 has a lower injection pressure. Case
S4 and case S6 almost overlie each other (Fig. 14).
Case S4 has a slightly larger oil recovery associated
with greater injection pressure; however, the injec-
tion of propane has no major effect on the oil drive.
Both of these cases employ a heated producing
condition that increases their recovery with respect
to other cases.
Case S7 is similar to case S6, except that propane
injection in case S7 is applied later and is of lesser
duration as compared to case S7. Case S7 exhibits
slightly greater recovery than case S6. Cumulative
oil production curves for these cases indicate that
both the starting time and the length of propane
injection have some effect on the oil production.
Ultimate oil recovery for any of these propane-
injection-assisted processes still lies under the curve
corresponding to case S2 (continuous heating with
no injection). In the section on economics, the
efficiency or incremental recovery per BTU input
is shown in terms of costs.
Cases S8 and S9 correspond to cyclic propane
injection. Case S8 uses two horizontal wells, and case
S9 uses a single well (huff-n-puff). Fig. 14 also
displays cumulative oil recovery for these two cases.
Their behavior is quite similar. This indicates that the
single well huff-n-puff may be more profitable, be-
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231226
cause it does not require the drilling, completion, and
maintenance/repairing of a second well. As in the
previous cases, case S8 and S9 have a cumulative oil
recovery below the best method (case S2).
3.4. Discussion
Results for the 2-D model make clear the important
effect of heating the region surrounding the well even
by only 5.6 jC (10 jF). In general, all scenarios
benefit from the addition of thermal energy. In the first
set of cases, focus was placed on the early stages of
recovery. For these cases, the conditions leading to the
largest recovery are to apply heat on the order of 288
W/m so that viscosity is reduced and at the same time
maintain the minimum possible bottom-hole pressure.
Fig. 6 shows, for example, that the best oil recovery is
obtained when both heating and a small bottom-hole
pressure are applied. Small bottom-hole pressures
allow a pressure gradient to propagate into the reser-
voir far from the well. The configuration of heater and
production well leading to the greatest propagation of
temperature into the reservoir is to place the heater
above the producer in a SAGD fashion. Warmed
fluids flow through the reservoir before being pro-
duced and transfer heat to the surrounding formation
and fluids.
Simulation results are quite sensitive to the solution
gas–oil ratio. The increased compressibility and the
release of substantial quantities of gas during heating
aid production considerably. These results mirror
qualitatively the unheated results where production
due to depletion is expected to be greatest from a
system with the largest GOR.
Heating the reservoir without injecting a fluid,
while enhancing production relative to the cold case,
eventually depletes the reservoir of drive energy. The
injection of a solvent such as propane would appear to
provide pressure maintenance as well as improved
recovery by reducing oil viscosity. Continuous gas
injection and heated production would seem to be an
additive method, whose production is greater than that
of either one alone; however, it was found to have a
negative effect on production. All of the scenarios
considered with solvent injection actually experienced
reduced production relative to an optimal case of large
heat input and minimum bottom-hole pressure. There
are several problems with solvent injection as imple-
mented here. Early breakthrough of solvent occurs.
Production is lost because the injected solvent short
circuits from the injector to the producer without
contacting an appreciable reservoir volume. The sol-
vent is heated but does not transfer this heat effec-
tively to the reservoir. Additionally, if heating is
switched off, production drops dramatically. Heating
continuously appears to be the best method. Econom-
ics will determine whether a single heater producer or
a SAGD-like orientation is best.
Simulation runs with propane injection were also
performed on this model with both cold and heated
production. The results showed that when the reser-
voir pressure is above the bubble-point pressure, gas
injection has little effect on oil production. As
injected gas dissolves in the oil the oil-phase vis-
cosity is reduced, but the solvent effect does not
reduce viscosity as effectively as heating. The incre-
mental oil production by means of gas injection
above the bubble-point pressure represented a small
percentage of the oil in place, and it was not studied
further.
4. Heterogeneity—three-dimensional model
In this section, the effects of heterogeneities and
the third dimension are examined in a depletion
mode. Note the position of the well. The horizontal
well and heater extend over the same total length. The
homogeneous, 3-D case, consists of the same well
and heater arrangement with a constant permeability
of 500 md used for the 2-D cases. The vertical
distance between the heater and producer is 4.6 m
(15 ft). Both, reservoir initial conditions and producer
operative conditions were the same as those used for
the 2-D cases. The heat input was set to 288 W/m
(300 BTU/h/ft) and the bottom-hole pressure to 3.1
MPa (450 psi).
Fig. 15 shows the cumulative oil recovered for the
homogeneous and heterogeneous cases, with and
without heat. Note that the heterogeneous unheated
case recovers slightly more oil than the homogeneous
case due to the presence of permeable paths and the
absence of a gas cap. Interestingly, once heat is
applied to the system, the heterogeneous and homo-
geneous case results virtually overlay one another.
Thermal conductivity is more or less distributed
Fig. 15. Cumulative oil recovery for 3-D homogeneous and heterogeneous cases.
Fig. 16. Incremental oil recovery versus energy input for 3-D homogeneous and heterogeneous cases.
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231 227
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231228
uniformly in the simulation model. Heat conduction
smoothes the effects of heterogeneities.
Fig. 16 compares the incremental recovery
obtained versus the energy input for the homogeneous
and heterogeneous cases. The slope of these curves
provides the efficiency or the ratio of incremental oil
recovered with respect to energy (kW/h) input. The
homogeneous case has an averaged efficiency of 62
kW/h (0.018 BTU) per incremental oil barrel recov-
ered, while the heterogeneous has an averaged effi-
ciency of 80 kW/h (0.023 BTU) per incremental oil
barrel recovered. Thus, heterogeneities do not signif-
icantly affect the overall efficiency, and this is an
advantage of this electrical heating method. In this
regard, electrical heating may be similar to steam
injection.
4.1. Heating distribution
Two of the parameters for electrical heating are the
total heating power and its distribution. The total
amount of heat that MI cables deliver is subject to
the lineal length of heating demanded. Therefore, the
effects of the heating power distribution were exam-
Fig. 17. Incremental oil recovery versus total ene
ined. All cases use the 3-D homogeneous permeabil-
ity field. In case (A), the heater is the same length as
the producer. In case (C), the heater is half as long as
the producer. It is centered over the length of the
producer and provides twice the heating density of
case (A), 576 W/m (600 BTU/h/ft). Case (B) is
intermediate between the two: the heater is three-
quarters of the length of the producer and delivers 1.5
times as much heat density as in case (A), 432 W/m
(450 BTU/h/ft). All three cases consume 140 kW
(4.8� 105 BTU/h).
Fig. 17 shows the incremental recovery obtained
as a function of the total energy input to the system.
Cases (A) and (B) have the same slope. In case (A),
the heater had greater contact with the reservoir and
incremental oil recovery began earlier. Case (C) had
the least efficiency as a result of the least contact of
the heater with the reservoir. Although this heater
arrangement heats oil to higher temperatures in the
vicinity of the well bore, most of this hot oil drains to
the producer below transferring little heat to the
adjacent formation. Fig. 4 shows that the initial
temperature increase reduces viscosity substantially.
Further increase in the temperature adds relatively
rgy input for 3-D cases (A), (B), and (C).
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231 229
less to oil mobility. In these examples, it was more
advantageous to have greater heater–reservoir contact
than it was to have greater temperature. In short, the
heating power and its distribution are parameters to
take into account during the optimization and design
of this process.
5. Economics
Case S2: heated production, no injection (single
well), gave excellent recovery. It might be argued that
heating the reservoir continuously is expensive in the
long term. Fig. 18 displays the incremental oil recov-
ery against the energy input to the 2-D system. The
results are on a per meter basis. In order to facilitate
discussion of Fig. 18, three different units systems are
used on the x-axis. They are (i) electrical energy input
to system in kWh/m, (ii) equivalent thermal energy
Fig. 18. Incremental oil recovery versus system energy input for
converted to barrels of oil consumed using a conver-
sion factor of 7.6� 109 J/m3 (5.6� 106 BTU/bbl) of
oil, (iii) equivalent thermal energy in standard cubic
feet of natural gas assuming 3.7� 107 J/m3 (1000
BTU/SCF) of natural gas. These three unit systems
help us to interpret the energy required for enhanced
recovery. Providing heat during the entire process is
inexpensive relative to the oil volumes recovered,
Fig. 18. For instance, 2 m3 of oil are consumed for
the production of more than 140 m3.
Fig. 6 shows the oil rate for the thermal methods
analyzed with the well in the middle of the forma-
tion. Cases 3 and 8 have identical bottom-hole
pressure but differ with respect to heating. Average
oil rates for these two cases differ by roughly a
factor of two. The average oil rates over 3500 days
were estimated for cases 3 and 8 as 0.039 m3/day m
(0.074 bbl/day ft) and 0.083 m3/day/m (0.16 bbl/day/
ft), respectively.
case S2: 288.5 W/m, 0.7 MPa BHP, no solvent injection.
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231230
Using these average rates and assuming a length of
reservoir/heating device of 152 m (500 ft), the reve-
nue per day for the heated and cold production is
qoil heated ¼ 0:083m3
day m152m� 20
USD
bbl
1 bbl
0:159 m3
¼ 1582USD
day
qoil cold ¼ 0:039m3
day m152 m� 20
USD
bbl
1 bbl
0:159 m3
¼ 743USD
day
Thus, the average incremental revenue is 839 USD/
day. To find the cost of the electricity consumed by
the MI cable heater, the energy input per day is
calculated first:
288J
s m8:64� 104
s
d
1 kWh
3:6� 106 J¼ 6:9
kWh
day m
The average cost of electricity for U.S. industrial
consumers between 1990 and 2003 was 0.05 USD/
kWh, whereas the average for 2003 was 0.053 USD/
kWh (Energy Information Administration, 2004). The
cost of electricity is estimated as
6:9kWh
day m152 m� 0:05
USD
kWh¼ 52
USD
day
The difference between the gross revenue and the
operating cost is 1530 USD/day, whereas the differ-
ence between the incremental revenue and the oper-
ating cost is 787 USD/day. The 1530 USD/day
difference corresponding to the heated production is
about 2.1 times larger than the 743 USD/day
corresponding to the cold production. The cost of
heating the reservoir to obtain such production is
3.4% of the gross revenue or 6.7% of the incremental
profit. Alternately, at 20 USD per barrel of oil, the
operating cost is about 1.25 USD per barrel for
heating the incremental oil produced.
Interestingly, the enhanced production rate is sig-
nificantly large so that the economics are favorable for
a wide range of electricity prices. If the price of
electricity increases by a factor of 5, the cost for
heating increases to 6.60 USD/BBL, and the cost of
heating relative to the incremental profit climbs to
50%. Thus, the process remains economic even at
0.25 USD/kWh.
6. Conclusions
(1) For heavy oils with appreciable solution gas (>18
m3/m3), electrical heating alone enhances deple-
tion significantly relative to the unheated case. In
cases with maximum heat input and minimum
bottom-hole pressure in the producers, oil pro-
duction rates more than doubled.
(2) The greatest recoveries were found for cases with
the addition of thermal energy but without any
solvent injection. Solvent injection was accom-
panied by rather rapid injector to producer linkup
and cycling of solvent. This frustrated any
additional oil recovery. Despite the success of
electric heating of producers with no accompa-
nying solvent injection, some form of pressure
maintenance or drive needs to be developed to
maintain recovery during the latter stages of
heating.
(3) Electrical heating using MI cables is an econom-
ical method for production of heavy oil.
Nomenclature
A, B, C, D
Coefficients in the correlation for gas–oil
equilibrium ratio
BHP Bottom-hole pressure
CMG Computer Modelling Group
f Mole fraction in a multicomponent mixture
GOR Gas oil ratio
h Formation thickness
k Permeability
K Equilibrium ratio
MI Mineral insulated
nc Number of components
p Pressure
r Radius
SAGD Steam assisted gravity drainage
STARS Steam, Thermal, and Advanced Processes
Reservoir Simulator
T Temperature
E.R. Rangel-German et al. / Journal of Petroleum Science and Engineering 45 (2004) 213–231 231
VAPEX Vapor extraction
WI Well index
l Viscosity
Subscripts and superscripts
a Heated zone radius
o Drainage radius
w Well radius
V Enhanced well index or oil viscosity
Acknowledgements
This work was prepared with the partial support of
the Stanford University Petroleum Research Institute
(SUPRI-A) Industrial Affiliates. This support is
gratefully acknowledged.
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