Strategies of SAGD Start-Up by Downhole Electrical Heating

Abstract

The SAGD start-up process normally circulates steam in both the injector and producer, which consumes a large amount of steam, requires the high cost of high-temperature-produced liquid treatment, and unavoidably results in preferential communication in heterogeneous reservoirs. In order to achieve uniform preheat and full steam chamber development in SAGD wellpairs, downhole electrical heating to start up SAGD was proposed and investigated in this study using physical and numerical simulation approaches. Two 3-D scaled physical experiments were designed and implemented to investigate the feasibility and heating characteristics of such a method. Numerical simulation was conducted using an SAGD sector model with typical field properties to design the preheating process, optimize key operational parameters, and formulate the soak strategy to determine the SAGD conversion timing. The experimental results indicate that electrical heating outperforms steam circulation in achieving the uniform thermal communication in heterogeneous reservoirs, which is challenged in the conventional steam circulation process. The preheating process and operational parameters of electrical heating were formulated and optimized, which include wellbore pre-flush, wellbore saturation by heat conduction fluid, electrical heating, and replacement of heat conduction fluid periodically. Surveillance of temperature difference along the horizontal section while powering off electrical heating intermittently is optimized to be the SAGD conversion timing determination strategy. Based on the combination results of scaled physical simulation and pilot wellpair numerical simulation, full heat communication and steam chamber development are achieved along the horizontal length by electrical preheating, and the oil recovery factor of the pilot wellpair is enhanced by 14.8%, indicating encouraging potentials in heavy oil and bitumen development.

1. Introduction

As one of the most effective recovery methods of developing extra heavy oil and oil sand deposits, SAGD (steam-assisted gravity drainage), invented by R.G Butler in the 1980s [1,2,3,4], has been commercialized in Canada and China, and it has contributed an oil recovery factor of above 45%, which is much higher than other steam-based recovery methods, such as cyclic steam stimulation. In order to mobilize the oil and establish the flow path between the injector and producer in the SAGD wellpair, the steam circulation from long tubing to short tubing in the horizontal wellbore of both the injector and producer was conventionally implemented for several months to elevate the temperature in the interwell region and initiate production. With the expansion of the development scale, the deposits yet to be developed normally have stronger heterogeneity and the SAGD steam chamber conformance and production performance are highly challenged [5]. Moreover, the large consumption of steam and treatment of surface-produced liquid during the preheating phase leads to high capital investment and longer payback time.

In order to achieve uniform thermal communication in the SAGD preheating phase to achieve full steam chamber development along the horizontal length in the production phase, several alternatives have been proposed, and some of them have been implemented in the field with success and failure. One is called bullheading, in which the returned fluids are not produced and the injected steam is forced to enter the reservoir. By avoiding fluid returns, bullheading speeds up the heat transfer rate by forced mass transfer of steam with oil, shortens the preheating time, and reduces the steam injection, which improves the project operation cost effectively. Up to now, bullheading has been widely implemented in SAGD projects in Canada [6,7,8,9,10].

Well completion modification is equally worthy of investigation for the uniform SAGD start-ups [11]. Different well completion methods or wellbore configurations have a direct impact on temperature uniformity [12,13,14]. The concept of flow control devices (FCD) installation in SAGD horizontal length was proposed and the mechanisms and physics of FCD were investigated, which shows significant improvement in temperature conformance [13,14,15,16].

Operational parameters, such as steam circulation rate, bottom-hole pressure, the pressure differential between injector and producer, and the timing of imposing such pressure differential, etc., also impact the SAGD start-up performance [17].

Another start-up method aimed at shortening the preheating period was proposed by Bitcan, where the small scale of hydraulic dilation was introduced in two wells before the preheating begins. It introduces shear dilation to induce the mini-fractures between the injector and producer. The mass transfer rate of steam into the formation would be effectively enhanced through these mini-fractures, and the preheating period would be evidently reduced from 200–300 days to 100–150 days [18,19,20,21]. With the characteristics of water shear dilation and formation rock tensile parting, the high permeability sections would be preferentially communicated, leaving the low-permeability or interbedded sections poorly heated, which has been validated by SAGD field application in FC oilfield in Xinjiang.

As the oil viscosity is the chief factor for oil drainage, solvent-assisted start-up is also an effective method to reduce the oil viscosity in the interwell region and speed up the ramp-up of SAGD production, although the solvent cost cannot be negligible. Owning advantages of shortening the preheating time, the solvent also tends to enter the high permeability sections with less temperature conformance improvement in heterogeneous reservoirs [22,23]. Another concept aimed at further reducing oil viscosity is the emulsifier as the preliminary experimental results show that the circulation fluid with emulsifier additives can penetrate into low permeability zones to form uniform dilation in the SAGD inter-well region [24].

For heterogeneous reservoirs, extensive field experience has demonstrated that uniform temperature conformance during the SAGD production phase is more important than preheating time as it impacts the oil rate and final oil recovery factor. The objective of this study is to investigate the feasibility, mechanism, and operational parameters of SAGD assisted by downhole electrical heating in heterogeneous geological conditions. The method of downhole electrical heating was illustrated in detail in this study. Its feasibility was validated by 3-D scaled physical modelling, and the field-targeted integral operation parameters were optimized.

2. Experiments

2.1. Experimental Materials

The oil sample was obtained from a typical SAGD area in F block, Xinjiang oilfield. The water was prepared according to the formation water salinity, and rock lithology heterogeneity along horizontal section was determined based on the well logging result of a typical SAGD wellpair and multi-well coring in the target payzone. The rock particle size was analyzed according to the core data, which guided the sandpacking of the model.

2.2. Experimental Setup

As shown in Figure 1, the 3-D scaled experimental system is mainly comprised of 4 parts: (1) fluid injection system consisting of a steam generator to inject steam at predetermined pressure and temperature, a syringe pump, and intermediate containers, which are used to saturate formation water and oil. (2) High-temperature, high-pressure scaled model system, which includes a stainless-steel model with the size of 80 cm × 30 cm × 30 cm (length × width × height); 385 thermal couples in total were deployed inside with 11, 7, and 5 layers in I, J, and Z direction, respectively; 3 horizontal wellpairs were placed in the left border, middle, and right border of the model, respectively. Sixteen pressure gauges were evenly installed in the model to monitor the pressure changes. (3) Data acquisition and control system, which includes the temperature and pressure data acquisition modules and the software to interpolate the real-time temperature field and control the heater power and its surface temperature. (4) Production system, which includes the BPR valve, fluid-gathered bottles, a centrifuge to separate the oil and water, and the balance to meter the produced fluid. The model system and the well and heater placement are shown in Figure 2.

2.3. Experimental Schemes

In order to compare the preheating performance by conventional steam circulation and electrical heating, two cases of 3-D scaled physical experiment were designed [25]. Case 1 is preheating by electrical heating, in which two heaters parallel to the injector and producer, respectively, were heating simultaneously with the constant surface temperature of 300 °C and the maximal power of 500 W for each heater. Case 2 is preheating by steam circulation, in which the steam of 300 °C was circulated in both injector and producer wellbores.

The similarity criterion of 3-D scaled physical modelling was used to guide the design of the experimental parameters [26,27], in which the B₃ is required to be the same. The design result was listed in

Table 1. Design results of the reservoir and 3-D physical model.

Items	Reservoir	Lab
Geometry size (width × height)/m	70 × 18.5	0.30 × 0.30
SAGD wellspacing/m	5	0.057
Porosity/%	32	35
Permeability/10−3 μm2	1110	87,950
Initial oil saturation/%	76	87
Oil viscosity@50 °C/mPa.s	13,007	13,007
Oil density@50 °C/kg·m−3	1008	1008
m (function of oil viscosity, steam temperature T, and reservoir TR)	3.4	3.4
Geometry similarity coefficient: R	0.264	0.933
Property similarity coefficient: B3	1.57	1.57
Time similarity coefficient: tD	1.22 t	3.21 × 10−4 t
Velocity similarity coefficient: qs/m−3·d−1(cold water equivalent)	0.196	0.232

.

2.4. Experimental Procedures

The experimental procedures include the following 7 steps:

(1)

The injector and producer are positioned in the center of the model, and each heater is placed close to the injector and producer, respectively. The well is prepared based on the screen liner configurations and parameters in the field.

(2)

The model is prepared by testing the airtightness, the packing of the sand with quartz sand (20–60 mesh), the vacuum pumping, and the brine saturation.

(3)

The model is placed in the high-pressure heat insulation capsule, and the airtightness of the capsule is further tested.

(4)

The model is heated to 80 °C, and the experimental crude oil is heated to 100 °C. The model is saturated with oil at an injection rate of 5–30 mL/min, and the total injection volume is calculated according to the pump data. The oil saturation process continues until one hour after the water saturation from the outlet reduces close to 0%.

(5)

The temperature of the model is reset to the original reservoir temperature to allow the model aging for 48 h.

(6)

For case 1, the wellbores of both injector and producer are saturated with water initially, and then two heaters are powered on with the constant surface temperature (300 °C) control mode, and the maximal power for each heater is 500 W. For case 2, the steam is injected from the inlet and produced from the outlet of the wellpair. The outlet pressure is controlled by BPR valve for each well.

(7)

The real-time model temperature is monitored by thermocouples through the temperature data acquisition module and software, and the temperature field is mapped accordingly.

2.5. Results and Discussion

From the evolution of temperature fields, it is obvious that electrical preheating achieves more uniform temperature conformance along the horizontal length than traditional steam circulation, although case 1 needs one more hour to achieve similar temperature enhancement in the interwell region. It is noted that, in case 1, due to the close deployment of the temperature sensor of the thermal couple with horizontal heater, the high temperature of the heater surface was immediately acquired and mapped at the beginning of the heating, while the neighbor region close to the heater was still at a low temperature level of only 60–90 °C during the first half hour. As the heater did not cover the whole horizontal length of the wellpair, the uncovered horizontal section of the heater did not have the same temperature rise. As shown from Figure 3a–c, the formation temperature in the outer-heater region is enhanced slowly due to the heat conduction characteristics of the electrical resistance heater. Without the mass transfer of steam into the formation, the heat can only transfer through temperature difference according to Fick’s first law. On the contrary, Figure 4 shows that only 2 h are needed to reach the thermal communication by steam circulation, which is 33.3% (1 h) earlier to convert to SAGD production mode.

In addition, Figure 4 also indicates that the heterogeneity poses a direct impact on the preheating uniformity in the steam circulation process. As the model was sandpacked according to the real heterogeneous properties of the SAGD payzone, the permeability in the middle section is 62.7% and 37.9% higher than in the toe and heel sections, respectively, which leads to the preferential thermal communication in the middle section. Moreover, two high permeability spots in the horizontal section directly lead to the development of two hotspots, which become increasingly evident with time. In comparison with case 2, case 1 achieved uniform thermal communication with the same heterogeneous sandpack at the end of preheating, showing its better suitability in heterogeneous conditions.

Another difference in the two cases is that, in case 1, as no steam enters the payzone, no steam overriding was viewed. On the contrary, steam overriding above the two hotspots is apparent in Figure 4d, indicating early preferential steam chamber development in this region when converting to SAGD production mode. The early steam channeling is particularly adverse for steam conformance and the SAGD performance, which is hopefully addressed by electrical heating in the preheating phase and other operational strategies in the production phase.

3. Numerical Simulation

3.1. Grid Design

The CMG-Builder was used to build the numerical simulation model, which was based on practical reservoir properties of SAGD payzone in F block in Xinjiang oilfield, China. The basic parameters are listed in

Table 2. Parameters of typical numerical simulation model.

Items	Model Data
Horizontal permeability/mD	1110
Porosity/%	32
Oil saturation/%	76
Original oil viscosity/mPa·s (@50 °C)	13,007
Net pay thickness/m	18.5
TVD/m	350
Initial reservoir temperature/°C	28
Initial reservoir pressure/MPa	2.69

. The grid size is 10 m, 0.5–3 m, and 0.5 m in X, Y, and Z directions, respectively, and the grid number is 49 × 26 × 35 = 44,590.

3.2. Preheating Workflow

Unlike conventional preheating process by steam circulation, electrical preheating needs to transfer heat from the heater surface via the wellbore annulus to the reservoir. The heat conduction media between heater and wellbore should be optimized first. In addition, as the electric heating continues, the heated crude oil continues to enter the wellbore, resulting in increased oil saturation in the wellbore and high risk of oil coking; thus, the heater surface temperature should be carefully controlled and the wellbore oil should be replaced periodically. Moreover, the light component of crude oil volatilizes in the wellbore and overrides to the wellhead, posing serious safety risks. In order to guarantee safe, effective, and efficient electrical preheating, the preheating workflow is designed as follows: wellbore pre-flush and replacement of air with nitrogen, heat conduction fluid injection, electrical heating, periodical replacement of heat conduction fluid, and end preheating determination. The key operational strategies and parameters are optimized as follows.

3.3. Wellbore Pre-Flush

Normally, after completion of SAGD wellpairs, the wellbores are filled with air and the oxygen is the adverse factor of crude oil coking at a lower temperature. In addition, light components from the heated oil in the wellbore tend to flow upwards to the wellhead. Once they meet the air, they can easily explode at the wellhead, which would pose a high risk to the operators and well. Therefore, nitrogen is chosen to pre-flush the wellbore to replace the air, reduce the heat loss in the vertical section, and fill the wellbore above the horizontal section. The maximal volume of nitrogen should be calculated to fill the wellbore from the wellhead to the heel, while the horizontal section should be filled with the heat conduction fluid under reservoir pressure.

3.4. Heat-Conduction Fluid Injection

As the key media to transfer heat from the heater to the formation efficiently, the heat conduction fluid is crucial in electrical preheating. Heat conduction fluid could be water, conduction oil, or gas, in which the heat conduction oil has the best performance of heat conduction, while its cost and little heat convection mechanism limit its application. On the contrary, water is readily available and, once it is heated to be steam, it has both heat conduction and convection or mass transfer mechanisms, which would speed up the heat communication in the electrical heating process. For the above reasons, water is chosen to saturate the horizontal wellbore. According to the practice of bullheading in SAGD wellpairs in Canada, the maximum water injection amount should be less than 0.5–1 MPa below fracturing pressure of cap rock in the wellbore vicinity, and hydraulic communication would be ideally be generated between the wells to offset the mass transfer shortage of electrical heating. As high-pressure hot water would induce shear dilation and is conducive to the hydraulic communication, the hot water with 200 °C was determined.

The simulation results indicate that, after 50 m³ of water injection, there is no obvious hydraulic communication between wells and the dilation radius is small (Figure 5a). When the injected water reaches 100 m³, the dilation radius increases obviously and the communication between wells begins to be established (Figure 5b). When the injection of water is further increased to 150 m³, the dilation radius is further increased, and obvious hydraulic communication occurs between wells (Figure 5c). In the process of injection, it is not recommended to further inject water after initial hydraulic communication establishment in order to prevent pressure imbalance from causing preferential hydraulic breakthrough. Therefore, it is recommended that the water injection be 100–150 m³/well and the pressure in the wellbore vicinity be increased to 5 MPa at the end of the high-temperature hot water injection.

3.5. Electrical Heating Parameters

Considering the field operation, the coking temperature of the crude oil in F SAGD block was tested at different temperatures. It was found that the crude oil did not coke at 320 °C in the nitrogen environment, but the distillation process vaporized the light components, increased the viscosity of the crude oil, and significantly reduced the content of the crude oil. At 340 °C, the distillation effect increases obviously, the light components of crude oil vaporize by distillation, and the left crude oil tends to be solidified. When the temperature rises from 340 °C to 360 °C, coking begins and full coking occurs at 380 °C (Figure 6). According to the test results, the surface temperature of the designed heater should not exceed 340 °C, and the temperature control begins after the wellbore fluid temperature rises to 300–320 °C. At the early stage, constant-power heating mode of 1000 W/m was adopted to elevate the heat conduction fluid temperature in the wellbore annulus to a predetermined temperature of 300 °C. In the middle and late stage, constant heater-surface-temperature heating mode was adopted to vaporize the annulus fluid into saturated steam. With the increase in temperature near wellbore, the temperature difference between wellbore vicinity and heater gradually decreased, and the heater power gradually decreased correspondingly. Therefore, the electric heating control adopts the dual control mode of constant power at the early stage and constant heater-surface temperature at the middle and late stage.

3.6. Replacement Frequency of Heat-Conduction Fluid

It can be seen from changes of oil saturation near the producer wellbore that crude oil saturation increased from 0% to 38% in a week after water injection, oil saturation increased up to 54% after electric heating for a half month, and further up to 98% in a month (Figure 7), which suggests that the wellbore is entirely filled with hot oil at the end of a month and high-temperature vaporized steam has entered into the formation. Therefore, in order to prevent the safety risk caused by the accumulation of large amounts of crude oil in the wellbore, it is recommended to replace the wellbore fluid with water once a month. Since pressure fluctuation is easy to occur in the process of replacing wellbore fluid, especially for the high permeability section between wells after the initial thermal connection, it is not recommended to replace wellbore fluid too frequently. In addition, from the perspective of field operation, frequent fluid replacement operation is also not encouraged as it is not conducive to the stability of bottom-hole pressure, and it is easy to cause preferential hot oil flow outwards near the heel, resulting in preferential communication.

3.7. Replacement Method of Heat-Conduction Fluid

In the fluid replacement process by simultaneous circulation from long tubing to short tubing, the oil saturation of the wellbore and the wellbore vicinity region gradually decreases, and the fluid in the outer-well region is not easy to flow into the wellbore, so there is no preferential communication. Therefore, the oil saturation changes of the fluid replacement at different times were compared. From the results, the oil saturation in the wellbore decreases to 91% after 1 day of fluid replacement, 86% after 2 days of fluid replacement, and 56% after 3 days (Figure 8), indicating that the effect of wellbore crude oil replacement by water is obvious.

In addition, in order to prevent pressure fluctuation in the process of fluid replacement, the pressure balance control strategy has been optimized: the flowmeter and pressure gauge were integrally used to control the steam injection speed at approximately 100 m³/d for the long tubings at wellheads, and the flowmeter and pressure gauge were used to control the production speed at approximately 100 m³/d for the short tubings at wellheads. The injection and production pressure were modulated carefully to be the same for two wells in the wellpair to maintain a pressure balance between the injection well and production well.

The shortest fluid replacement time is determined as produced water-cut up to 98%. After reaching this level, the oil content of the wellbore is considered to be less than 2%, which meets the requirements of re-electric preheating. From the simulation results, when the production rate is 80–100 m³/d and the injection rate is 80–100 m³/d, the minimum fluid replacement time of 3–4 days is enough to reach the water-cut of 98% (Figure 9).

3.8. Preheating Time

Since it is empirically regarded that the full SAGD production timing is when the oil viscosity between I and P wells drops to less than 100 MPa.s, the viscosity of oil has the greatest impact on the preheating time [28]. Therefore, the time required for SAGD start-up by electric preheating with different initial crude oil viscosity (@50 °C) was simulated, and the oil viscosity in the inter-well region with time was plotted (Figure 10). From the results, it takes 6 months for the reservoir with initial oil viscosity of 13,007 mPa.s to be converted to SAGD production mode by electric preheating (Figure 10). Considering 3–4 days needed to replace the wellbore fluid each month, one additional month in total should be considered, which contributes to a total preheating time of 200 days. In addition, from Figure 10, it is clear that, the higher the viscosity, the longer it takes to convert to SAGD production mode. In general, the formation temperature enhancement rate of electric preheating is relatively slower than that of conventional steam circulation due to the fact that electric preheating mainly depends on heat conduction to mobilize the oil.

4. Strategy of SAGD Conversion Timing Determination

Operators normally use temperature-falloff data to predict successful conversion time. However, in field operations, the temperature-falloff data are evaluated qualitatively. Without the analytical/numerical framework to analyze or match such data, it is risky to make hasty judgement of conversion timing to full SAGD. Meanwhile, the preheating time also impacts the temperature conformance, which requires a longer time for heterogeneous reservoirs to achieve larger mobilized regions and more uniform temperature profiles along the horizontal length and avoid returning to circulation. It is necessary to study an approach to predict the right timing for conversion to full SAGD. In this study, the numerical framework was used to optimize the strategy.

Conventionally, in field operations, two approaches are used to determine the proper timing. One is partial-SAGD, and the other is soak. Partial-SAGD needs to convert the injector to steam injection mode and the producer to steam circulation mode [29], which is likely to form early steam channeling in this operation since the early introduced pressure differential between wells tends to form hot spots. On the contrary, the soak method is safer and easier to operate as it is required that the wellpair only needs to shut for a short period of time. By monitoring the temperature variance along the horizontal length, one can judge quickly which section is fully communicated and whether more time is needed for further preheating.

In preheating by electrical heating, the modified soak method is also suitable, which requires the heater to power off for a period of time. Using the numerical simulation model above, soak for preheating by electrical heating was simulated and the operation time was optimized.

As shown in Figure 10, the temperature variance along the horizontal length becomes increasingly evident with soak time after powering off the two heaters on the 180th preheating day. As the horizontal section close to the heel is a low permeability region with an average Kh of 697 mD, compared with 1389 mD in other sections, the rock lithology in this region is muddy sand with lower heat conductivity. After powering off the heaters from 1 day to 4 days, the temperature fall-off in this region is quicker than other sections, and, on the fourth day, the temperature difference has reached 8 °C (Figure 11), which is enough for the field operators to make a determination. The temperature difference with soak time at different times is shown in Figure 11, which indicates that, after preheating for 180 days, 3–4 days should be necessary for this determination considering the data precision of downhole thermocouples.

Moreover, it is noted from Figure 12 that the temperature fall-off is quicker when making an earlier judgement [30]. After preheating for 200 days, the temperature difference in the horizontal wellbore is only 3.3 °C when soaking for 5 days, which indicates that the preheating time is enough for interwell heat field establishment and oil mobilization for full SAGD production.

5. Field Performance Prediction

Based on the detailed description and statistics of petrophysical properties of newly deployed SAGD payzones in Xinjiang oilfield, a typical pilot wellpair A was selected to predict the SAGD production performance by electrical preheating and compared with that by conventional steam circulation (Figure 13). A low-permeability interlayer (avg. permeability: 476 mD) is located in the interwell region at the toe, with a continuous thickness of 1.2 m and a horizontal length and width of 121 m and 17 m, respectively. The simulation results demonstrate that the steam circulation requires 187 days to complete the SAGD circulation period, while, for downhole electrical heating, it needs 239 days. Although 52 more days are required for preheating, the horizontal section is fully communicated by electrical preheating. This finding is different from the previous study [31], in which only 74 days were needed for electrical heating and 200 days for steam circulation because electrical heating is mainly characterized by heat conduction, which elevates the formation temperature theoretically slower than the heat convection process with mass and heat transfer for steam circulation. By comparing with the conventional steam circulation, the section around the toe is poorly communicated and steam preferential channeling happens in the middle section with high permeability (avg. permeability: 2311 mD).

From the SAGD production curves by different preheating methods (Figure 14), the oil rate at the early stage of SAGD production is similar for both cases. The main reason is that both steam chambers are small, with a low steam injection rate at the early stage, which results in almost the same ramp-up of the oil production rate [31,32]. However, the oil rate difference increases steadily with time, and, after converting to SAGD production for two years, both cases reach the SAGD plateau period and the peak oil rate for the case of electrical heating is 35 m³/day, while the case of conventional steam circulation is only 30 m³/day. The oil rate difference remains stable at a level of 3–5 m³/day during the entire plateau period. Meanwhile, at the late stage of production, it is evident that the case by electrical heating has a longer plateau period and much higher oil rate in the SAGD wind-down period, which indicates that the electrical heating improved the temperature conformance along the horizontal length, and more oil deposits become recoverable. The final oil recovery factor of the case with electrical heating start-up is 66.9%, which is 14.8% higher than the steam circulation case (52.1%).

6. Conclusions

For heterogeneous SAGD reservoirs, the uniform thermal communication in the SAGD preheating phase has a far-reaching impact on the following SAGD wellpair production performance and economics. Among all the innovative preheating methods, the downhole electrical preheating, as has been validated by the 3-D scaled physical experiment, is a competitive alternative to conventional steam circulation.

The experiment results also show that the phenomenon of hot spots in conventional steam circulation can hardly be avoided in steam-based circulation operations due to the forced mass transfer and convection heating allowing the fluid to preferentially flow along the easiest channels under operational pressure differentials between the injector and producer. By introducing induction heating with less interaction of fluids in porous media at an early stage, despite the longer preheating time, uniform heat communication is able to be achieved.

Using the numerical simulation with typical reservoir and well completion properties, the preheating process and operational parameters of electrical heating were formulated and optimized, in which water is used in wellbore pre-flush and saturation, the maximal surface temperature of the heater is 300 °C, replacement of heat-conduction fluid is implemented for 3 days once a month, the preheating time is 200 days for targeted SAGD reservoirs in F block, and the temperature fall-off method is used to determine the SAGD conversion timing. The strategies above meet the field application requirements.

The prediction using a pilot SAGD wellpair indicates that the electrical preheating has a long-reaching impact on the SAGD performance due to the improved steam chamber conformance. The oil rate is improved by 3–5 m³/day and the oil recovery factor is enhanced from 52.1% to 66.9%, showing both production and economic potentials.