electrical heating assisted recovery for heavy oil

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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

Henrique

Realce

Henrique

Nota

chiefly = principalmente

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).


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)]


6. Continuous heat input of 144W/m [150 BTU/(h/ft)]






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.


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.


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.


(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.


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.


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),


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.


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.


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-


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.



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).


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.


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

Henrique

Nota

1) para óleo pesado com apreciavel solução de gás (>18m3/m3), o aquecimento elétrico sozinho significativamente a depletação comparado com o caso não aquecido. No caso de máximo aquecimento e minima BPH no produtor, a vazão da produção de óleo mais do que duplicou.

Henrique

Nota

As maiores recuperações foram alcançadas para casos com a adição de energia térmica mas sem alguma injeção de solvente. A injeção de solvente foi acompanhada pela mais rápida injeção


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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