CA3142209A1

CA3142209A1 - Downhole preheating start-up method for super heavy oil reservoir developed for dual-horizontal-well sagd

Info

Publication number: CA3142209A1
Application number: CA3142209A
Authority: CA
Inventors: Xinmin Song; Yongbin WU; Linxiang SANG; Xiuluan Li; Rui Zhao
Original assignee: Petrochina Co Ltd
Current assignee: Petrochina Co Ltd
Priority date: 2020-02-11
Filing date: 2021-02-08
Publication date: 2021-08-19
Also published as: WO2021160083A9; WO2021160083A1; CN113250665A; CN113250665B

Abstract

Disclosed is a downhole preheating starting method for a super heavy oil reservoir developed by means of dual-horizontal-well SAGD, the method comprising: loading concentric preheating tubular columns into well I and well P, injecting high-temperature fluid into inner tubes (4) of the concentric preheating tubular columns, performing circulation preheating, and performing extraction on outer tubes (3) of the concentric preheating tubular columns, or loading concentric tubes and resistance heating cables into the well I and the well P and performing continuous preheating; discharging a well shaft annulus fluid after the inter-well oil layer reaches the preheating ending condition, and soaking the wells; and entering an SAGD production stage.

Description

DOWNHOLE PREHEATING STARTING METHOD FOR SUPER HEAVY
OIL RESERVOIR DEVELOPED BY MEANS OF
DUAL-HORIZONTAL-WELL SAGD
Technical Field The present invention relates to a method for exploitation of a heavy oil reservoir in an oil field, in particular to a downhole preheating start-up method for a super heavy oil reservoir developed for dual-horizontal-well SAGD, which belongs to the field of oil exploitation.
Background Steam-assisted gravity drainage technology (abbreviated as SAGD) was invented by the Bulter (Canada) in 1978, and was successfully applied in heavy oil reservoirs in oil sands mining areas in Canada as well as Liaohe Oilfield, Xinjiang Oilfield and others in China. Its principle lies in that a pair of superimposed horizontal wells are set up in the same oil formation and high-dryness steam is injected into the upper steam injection well, so that a steam cavity is formed as the steam elevates and overlays in the formation due to a much lower density of the steam than that of crude oil. With the steam being continuously injected, the steam cavity constantly expands upward and laterally and exchanges heat with the crude oil in the oil formation. The heated crude oil decreases in viscosity and flows downward with condensed water under the action of gravity, and is then recovered from a horizontal production well in the lower part of the oil formation. Up to now, large-scale developments have been carried out with the SAGD technology in heavy oil reservoirs in Liaohe, Xinjiang and other places in China.
"Study on SAGD Technology for Ultra Heavy Oil in Dual Horizontal Wells"
(Changfeng XI, Desheng MA et al.; Journal of Southwest Petroleum University (Science&Technology Edition), 2010, 32(4)) proposes an SAGD exploitation divided into two phases;
an SAGD
start-up phase and an SAGD production phase. In the SAGD start-up phase, there arc usually two methods for SAGD start-up: throughput preheating start-up and injected steam circulation preheating start-up, where the throughput preheating start-up has high injection pressure, high temperature and is prone to damage the completed well structure. The injected steam circulation preheating start-up preheats uniformly and starts smoothly, generally in three steps:
(I) steam is circulated in both wells and the reservoir transfers heat mainly through heat transfer; (2) an inter-well pressure difference is created between the two wells, with the pressure in the steam injection well being higher than that in the production well, causing crude oil between the wells to flow toward the production well to be ready for transitioning to full SAGD production; (3) fluid discharging is stopped in the annular space of the upper steam injection well, and steam injection is stopped in the lower production well, before transitioning to the full SAGD production phase.
Date Recue/Date Received 2021-11-29

2 Prior to SAGD production, the well must be started-up by thermal circulation.
The stage between injecting steam into the production well and the steam injection well and the beginning of the transition to SAGD production is called the start-up phase, or the preheating phase. The goal of the preheating phase is to achieve unifaiin heating of the oil formation in a minimum duration, so that the steam injection well and the production well are uniformly heated and communicated, and an oil drainage channel is established between the steam injection well and the production well.
Since the depositional environment of heavy oil reservoirs in Liaohe, Xinjiang and other places are fluvial facies with highly non-homogeneous reservoirs, in the conventional injected steam circulation preheating process as mentioned above, under high-speed steam injection conditions, a pressure difference is present between the horizontal sections of the steam injection well and the production well. Under the action of this pressure difference, the steam is prone to enter the intermediate oil formation between the steam injection well and the production well along the high permeability channel of the horizontal section and then enter the production wellbure, resulting in preferential thermal communication.
Statistically, less than 70% of SAGD horizontal sections are brought into communication by using the steam circulation preheating. The preferential thermally communicated section has a significant impact on the uniform steam injection for transitioning to the SAGD production phase, which can lead to the preferential development of the steam cavity in this section, thereby resulting in the incapacity of the horizontal section to be used uniformly and affecting the production yield and recovery efficiency. According to statistics, in the dual-horizontal-well SAGD with conventional injected steam circulation preheating, less than 50% of the horizontal section has developed a steam cavity.
Chinese invention patent application No. 201611187914.9 discloses a method and device for horizontal well steam-assisted gravity drainage start-up. The method comprises: placing two sets of horizontal well steam-assisted gravity drainage start-up devices in a steam injection well and a production well respectively, where the electric heating rod in the horizontal well steam-assisted gravity drainage start-up device has the same length as that of the horizontal section of the steam injection well or the horizontal section of the production well; carrying out heating with the electric heating rod in the horizontal well steam-assisted gravity drainage start-up device; monitoring an inter-well temperature between the steam injection well and the production well, and stopping the heating with the electric heating rod when the inter-well temperature between the steam injection well and the production well reaches a preset first temperature. SAGD quick preheating start-up can thus be realized.
However, the simple electric heating rod is highly susceptible to eon-osion under the environment of the steam, CO2 and H2S generated at high temperatures in the weilbore, resulting in insulation failure of the heater; meanwhile, welded joints of the electric heating rod are prone to deformation under continuous high temperature heating conditions, and cracks due to stress damage are generated, also resulting in failure of the heater. In addition, the regulation of the surface heating power of the electric heater necessarily relies on Date Recue/Date Received 2021-11-29

3 downhole temperature monitoring, but the downhole temperature measurement probe is highly susceptible to damage, which makes it difficult to effectively regulate the power of the heater, and is at a high risk of insulation failure due to the heater surface heating temperature surpassing the maximum withstand temperature. The fourth risk is that a commonly used commercial three-core heating cable is required to have a voltage at the heating inlet of 2000V or more, when it has a heating length of 400 meters or more, a diameter of only 1.5 inches, and a required power of 1000W/m or higher. The inlet of a three-core cable is extremely vulnerable to the risk of high-voltage electricity breakage through the insulation filler and consequent bursting of the heater. At present, there is no small-diameter three-core heating cable that can withstand such a voltage available in China, making it difficult for field applications.
Chinese invention patent application No. 201410586578.X discloses a method of solvent-assisted steam accelerated preheating communication. The specific steps include: (1) high-power electric heating the steam injection well and the production well;
(2) injecting 1 5 solvent into the long tubing and the short tubing of the steam injection well and the production well simultaneously; (3) injecting a mixture of solvent and steam into the long tubing and the short tubing of the steam injection well simultaneously, injecting a mixture of solvent and steam into the long tubing of the production well, and draining the short tubing of the production well; (4) turning off the electric heating, injecting pure steam into the long tubing and the short tubing of the steam injection well simultaneously, and draining the long tubing and the short tubing of the production well simultaneously. However, the solvents are expensive and require high temperature to be separated after they are discharged on the ground, which brings a high cost, and it is difficult to avoid the risk of preferential communication of high permeability sections occurring in highly non-homogeneous horizontal sections with the solvent-assisted steam start-up.
Summary of Invention To solve the above technical problems, an object of the present invention is to provide a preheating start-up method with downhole steam uniform thermal circulation for a super heavy oil reservoir developed for dual-horizontal-well SAGD. This method enables uniform preheating, avoids preferential connectivity, and promotes uniform development of steam cavity along the horizontal section during the SAGD production phase at low cost.
To achieve the above object, the present invention provides a downhole preheating start-up method for a super heavy oil reservoir developed for dual-horizontal-well SAGD, which comprises:
injecting a heat-conducting fluid into an oil well through a dual-horizontal-well SAGD
well set, and then injecting a gas;
continuously injecting a high-temperature fluid through an inner tubing of a concentric preheating tubing string, and discharging the fluid to the ground surface through the annular Date Recue/Date Received 2021-11-29

4 space between the inner tubing and outer tubing of the concentric preheating tubing string, while pressurizing the injected gas so that the difference between the gas pressure in the annular space at the wellhead and the discharge pressure of the high-temperature fluid at the wellhead is less than 0.5 MPa; the temperature of the high-temperature circulating fluid being

5 to 20 C lower than the initial coking temperature of the formation crude oil; or alternatively, inserting a resistance heating cable into an outer tubing of the concentric preheating tubing string, filling the annular space between the heating cable and the outer tubing in the horizontal section with a high-temperature fluid, and filling the annular space from the inclined section to the wellhead with an insulating gas; configuring an optical fiber temperature measurement point and/or a thermocouple temperature measurement point on the outer wall of and/or inside the cable, monitoring the surface temperature of the heating cable in the horizontal section, and achieving thermostatical control by automatic power adjustment;
the surface temperature of the heating cable in the horizontal section being 5-20 C lower than the initial coking temperature of the formation crude oil, with continuous heating;
stop injecting the high-temperature fluid when the temperature in the middle of the oil formation reaches 180 C or higher, or when the viscosity of the crude oil drops to 100 mPa.s or lower;
discharging the gas and liquid from the oil well;
removing the concentric preheating tubing from Well 1 and Well P, and injecting an oil-soluble visbreaker into Well I and Well P simultaneously, stop injecting when the pressure in the wellborc of the horizontal section at the bottom of the well rises to below the rupture pressure of the caprock above the oil foimation, and soaking the well for an appropriate period of time before the SAGD preheating phase is completed;
continuously injecting steam, and continuously recovering from Well P, and transitioning into the SAGD production phase.
The tubing string structure used in the dual-horizontal-well SAGD preheating start-up method for heavy oil reservoir of the present invention can be shown in Fig.
1. The concentric preheating tubing string comprises a easing 1, an outer tubing 3 of the concentric preheating tubing string (also known as the outer tubing) and an inner tubing 4 of the concentric preheating tubing string (also known as the inner tubing). At a distal end of the casing 1 is a sieve pipe 2, and a distal end of the outer tubing 3 of the concentric preheating tubing string is capped. Further, a temperature measurement tube 5 is provided between the casing 1 and the outer tubing 3 of the concentric preheating tubing string.
According to an embodiment of the present invention, the above method preferably comprises the following particular steps (with the particular procedure shown in Fig. 2):
(1) setting up at least two horizontal wells with superposed horizontal sections in the oil formation that consist of a SAGD well set, wherein the upper well is designated as Well I and the lower well is designated as Well P;
Date Recue/Date Received 2021-11-29 (2) inserting concentric preheating tubing strings into the horizontal sections of Well I
and Well P, and capping the distal end of the outer tubing of the concentric preheating tubing strings;
(3) injecting a heat-conducting fluid into the annular space between the concentric 5 preheating tubing string and a sieve pipe of Well I and Well P;
(4) injecting a gas into the annular space between the concentric preheating tubing string and the sieve pipe located above the heel in Well I and Well P;
(5) measuring the initial coking temperature of crude oil in the oil formation, and determining the temperatures corresponding to different coking rates of the crude oil;

(6) continuously injecting a high-temperature fluid into the inner tubing of the concentric preheating tubing string of Well I and Well P and discharging the fluid from the annular space between the inner tubing and outer tubing of the concentric preheating tubing string to the ground surface (i.e., heating by circulation with the high-temperature fluid);
simultaneously pressurizing the gas in the annular space between the concentric preheating tubing string and the sieve pipe located above the heel of Well I and Well P so that difference between the gas pressure in the annular space at the wellhead and the discharge pressure of the high-temperature fluid at the wellhead is less than 0.5 MPa;

(7) stop injecting the high-temperature fluid when the temperature in the middle of the oil formation between the horizontal sections of Well I and Well P reaches 180 C or higher, or when the viscosity of the crude oil drops to 100 inPa=s or lower;

(8) discharging the gas and liquid from the annular space between the concentric preheating tubing string and the sieve pipe;

(9) removing the concentric preheating tubings from Well I and Well P, and injecting an oil-soluble visbreaker into the wellbores of Well I and Well P, respectively, stop injecting when the pressure in the wellbore of the horizontal section at the bottom of the well rises to 0.1-1 MPa below the rupture pressure of the caprock above the oil formation, and soaking the well for 3-5 days;

(10) continuously injecting steam into Well I, and continuously recovering from Well P, thereby ending the SAGD preheating phase and transitioning to the SAGD
production phase.
According to an embodiment of the present invention, preferably, the above method is preferably directed to a super heavy oil reservoir that meets the following conditions:
(i) a thermal conductivity grade difference of the SAGD oil formation of less than 3;
(ii) oil saturation > 60%;
(iii) oil formation thickness >12m;
(iv) a vertical distance between the horizontal sections of Well I and Well P
of 4-7m.
In the above method, preferably, in step (1), the horizontal sections of both Well I and Date Recue/Date Received 2021-11-29 Well P are completed with a slotted sieve pipe.
In the above method, preferably, in step (2), the distance from the concentric preheating tubing string to the toe of the horizontal section is 20-60 m, preferably 50 m; an outlet of the inner tubing of the concentric preheating tubing string is 10-30 m from the distal end of the outer tubing of the concentric preheating tubing string; the cross-sectional area of the inner tubing of the concentric preheating tubing string is equal to the cross-sectional area of the annular space between the outer and inner tubings of the concentric preheating tubing string.
in the above method, preferably, in step (2), the heat-conducting fluid is at a liquid level of 1-10 in above the heel, preferably 10 in. The heat-conducting fluid is one or a combination of two or more of water, supercritical CO2, and a heat-conducting oil.
In the above method, preferably, in step (4), the gas comprises one or a combination of two or more of argon, helium, and nitrogen.
In the above method, preferably, in step (6), the high-temperature fluid comprises a high-temperature gas and/or a high-temperature liquid, wherein the high-temperature gas comprises one or a combination of two or more of high-temperature argon, high-temperature helium, high-temperature nitrogen, and high-temperature CO2; and the high-temperature liquidcomprises one or a combination of two or more of a high-temperature steam, a high-temperature oil and a molten salt; the high-temperature fluid has a temperature that is 5-20 C lower than the initial coking temperature of the crude oil; and the injection rate of the high-temperature fluid is 5-60 m3/day.
in the above method, preferably, in step (7), a temperature in the middle of the oil formation is determined by establishing a numerical model of the well set and performing tracked prediction of the inter-well temperature elevation. The numerical model of the well set is established by using a reservoir numerical simulation software. The reservoir numerical simulation software includes CMG-STAR from CMG Canada and/or ECLIPSE from Schlumberger USA.
In the above method, preferably, in step (8), the wellhead pressure when the gas and liquid are discharged from the annular space between the concentric preheating tubing and the sieve pipe is controlled to be 0.5-3 MPa lower than the original reservoir pressure.
In the above method, preferably, in step (9), the oil-soluble visbreaker is injected in an amount of 10-100 tons/well.
The downhole preheating start-up method for super heavy oil reservoir developed for dual-horizontal-well SAGD provided by the present invention may be carried out by using circulating heating with a high-temperature fluid or by means of in situ heating using electric heating together with a concentric tubing. A specific structure for the latter is shown in Fig. 3, with the particular procedure as follows.
injecting a heat-conducting fluid 72 into an oil well through a dual-horizontal-well SAGD well set, and then injecting a gas 71;
Date Recue/Date Received 2021-11-29 inserting a resistance heating cable 6 into an outer tubing of the concentric preheating tubing string, tilling the annular space between the heating cable and the outer tubing in the horizontal section with a high-temperature fluid 82, and filling the annular space from the inclined section to the wellhead with an insulating gas 81; configuring an optical fiber temperature measurement point and/or a thermocouple temperature measurement point on the outer wall of and/or inside the cable, connecting to a ground power control box, monitoring the surface temperature of the heating cable in the horizontal section, and achieving a thermostatical control function by automatic power adjustment;
setting the surface temperature of the heating cable in the horizontal section to be 5-20 C
lower than the initial coking temperature of the formation crude oil, and heating continuously;
adjusting the pressure of the gas inside the concentric preheating tubing during heating so that the difference between the pressure of the gas inside the concentric preheating tubing and the pressure of the gas outside the concentric preheating tubing and in the annular space of the casing is less than 0.5 MPa;
stop injecting the high-temperature fluid when the temperature in the middle of the oil formation reaches 180 C or higher, or when the viscosity of the crude oil drops to 100 mPa.s or lower;
discharging the gas and liquid from the oil well;
removing the concentric preheating tubing from Well 1 and Well P, and injecting an .. oil-soluble visbreaker into Well I and Well P simultaneously; stop injecting when the pressure in the wellbore of the horizontal section at the bottom of the well rises to below the rupture pressure of the caprock above the oil formation, and soaking the well for an appropriate period of time before the SAGD preheating phase is completed;
continuously injecting steam, and continuously recovering from Well P, and transitioning .. into the SAGD production phase.
According to an embodiment of the present invention, preferably, the downhole preheating start-up method by means of in situ heating using electric heating together with a concentric tubing comprises the following particular steps (with the particular procedure shown in Fig. 4).
(1) setting up at least two horizontal wells with superposed horizontal sections in the oil formation that consist of a SAGD well set, wherein the upper well is designated as Well I and the lower well is designated as Well P;
(2) inserting concentric preheating tubing strings into the horizontal sections of Well and Well P, and capping the distal end of the outer tubing of the concentric preheating tubing strings;
(3) injecting a heat-conducting fluid into the annular space between the concentric preheating tubing string and a sieve pipe of Well 1 and Well P;
(4) injecting a gas into the annular space between the concentric preheating tubing string Date Recue/Date Received 2021-11-29 and the sieve pipe located above the heel in Well I and Well P;
(5) measuring the initial coking temperature of crude oil in the oil formation, and determining the temperatures corresponding to different coking rates of the crude oil;
(6) inserting a resistance heating cable into an outer tubing of the concentric preheating tubing string, filling the annular space between the heating cable and the outer tubing in the horizontal section with a high-temperature fluid, and filling the annular space from the inclined section to the wellhead with an insulating gas; configuring an optical fiber /thermocouple temperature measurement point on the outer wall of/inside the cable, connecting to a ground power control box, monitoring the surface temperature of the heating cable in the horizontal section, and achieving a thermostatical control function by automatic power adjustment;
(7) setting the surface temperature of the heating cable in the horizontal section to be 5-20 C lower than the initial coking temperature of the formation crude oil, and heating continuously; adjusting the pressure of the gas inside the concentric preheating tubing during heating so that the difference between the pressure of the gas inside the concentric preheating tubing and the pressure of the gas outside the concentric preheating tubing and in the annular space of the casing is less than 0.5 MPa;
(8) stop electric heating when the temperature in the middle of the oil formation between the horizontal sections of Well I and Well P reaches 180"C or higher, or when the viscosity of the crude oil drops to 100 mPa=s or lower;
(9) discharging the gas and liquid from the annular space between the concentric preheating tubing string and the sieve pipe;
(10) removing the concentric preheating tubings from Well I and Well P after no fluid flows out of the wellbores of Well I and Well P, and injecting an oil-soluble visbreaker into the wellbores of Well I and Well I', respectively, stop injecting when the pressure in the wellbore of the horizontal section at the bottom of the well rises to 0.1-1 MPa below the rupture pressure of the caprock above the oil formation, and soaking the well for 3-5 days;

(11) continuously injecting steam into Well 1, and continuously recovering from Well P, thereby ending the SAGD preheating phase and transitioning to the SAGD
production phase.
In the above method, preferably, in step (6), the heating cable is a stainless steel-armored magnesium oxide insulated cable, and the electric heating power is 500-2000 W/m.
In the above method, preferably, in step (6), the insulating gas comprises one or a combination of two or more of argon, helium, and nitrogen.
In the above method, preferably, in step (6), the high-temperature fluid comprises a high-temperature gas and/or a high-temperature liquid, wherein the high-temperature gas comprises one or a combination of two or more of high-temperature argon, high-temperature helium, high-temperature nitrogen, and high-temperature CO2; the high-temperature liquid comprises one or a combination of two or more of a high-temperature steam, a Date Recue/Date Received 2021-11-29 high-temperature oil and a molten salt; and the high-temperature fluid has a temperature that is 5-20 C lower than the initial coking temperature of the crude oil.
The dual-horizontal-well SAGD downhole preheating start-up method provided by the present invention has the following technical effects.
(1) Compared with the existing SAGD steam injection preheating start-up method, the concentric tubing hot steam closed circulation provided by the present invention, together with operation under the same pressure between Well I and Well P. effectively prevents steam from prematurely breaking through the oil formation between injection and extraction wells and scurrying in from a high permeability section due to the presence of a pressure difference at an early stage during preheating, which is favorable for uniform heating start-up and promoting uniform development of steam cavities in horizontal sections in the SAGD
production phase, thereby effectively increasing oil production and recovery rate.
(2) With the method of the present invention, crude oil temperatures with different coking rates can be tested before preheating, and the wellbore annular space and the oil formation near the wellbore can be heated to a temperature 5-20 C lower than the initial coking temperature of the crude oil at an early stage of preheating, which helps to avoid coking problems.
(3) The present invention proposes discharging the fluid in the wellbore annular space before the completion of preheating and injecting an oil-soluble visbreaker with 100%
solubility to bitumen and residual oil, so that the crust formed mainly by bitumen and residual oil near the wellbore can be well dissolved and the percolation capacity near the wellbore can be improved, thus significantly increasing the steam injection capacity in the SAGD
production phase.
(4) An inert gas is injected at. an appropriate location (preferably 1-10 m annular space) in the upper part of the heel of the horizontal sections of Wells I and P, which is favorable to significantly reduce the heat loss from the wellhead to the annular space near the heel of the horizontal section and increase the heat utilization of the high-temperature circulating fluid by more than 10%; further, the high compressibility nature of the inert gas favors the buffering of the pressure build-up of the fluid in the annular space of the horizontal section upon the expansion of the fluid at high temperature and avoids large pressure fluctuation at the bottom of the well, which can reduce the pressure change of the fluid in the annular space at the bottom of the well at different temperatures to be I MPa or less, avoiding the problems of local scurrying and communication caused by excessive pressure difference between Well I
and Well P in the wellbore annular space of Wells I and P due to pressure fluctuation during the heating of the fluid, thereby ensuring a uniform preheating.
(5) Compared to the conventional SAGD steam circulation preheating, the uniform preheating method proposed by the present invention effectively prevents the preferential communication between horizontal high permeability sections in the conventional steam preheating phase and ensures that the uniformity of steam injection in the SAGD production Date Recue/Date Received 2021-11-29 phase reaches 95% or more.
(6) The present invention also provides an in situ heating method by inserting a resistance heating cable into the concentric tubing, which does not require the circulation of the fluid inside the concentric tubing to realize insitu heating and heat transfer, avoiding the heat loss above the heel in the wellbore during the circulation, and significantly improving the thermal efficiency.
Brief Description of Drawings Fig. 1 shows a schematic diagram of the structure of the concentric preheating tubing string used in the dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir according to the present invention.
Fig. 2 shows a schematic flowchart of the dual-horizontal-well SAGD preheating start-up for a heavy oil reservoir.
Fig. 3 shows a schematic diagram of the structure of the concentric preheating tubing string with electric heating used in the dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir according to the present invention.
Fig. 4 shows a schematic flowchart of the dual-horizontal-well SAGD preheating start-up for a heavy oil reservoir assisted by electric heating.
Description of symbols of main components:
1. casing; 2. sieve pipe; 3. outer tubing of concentric preheating tubing string; 4. inner tubing of concentric preheating tubing string; 5. temperature measurement tube; 6. resistance heating cable; 71. gas; 72. heat-conducting fluid; 81. insulating gas; 82.
high-temperature fluid.
Detailed Description of Invention For a better understanding of the technical features, objects and beneficial effects of the present invention, the technical solutions of the present invention will be described hereinafter in details, which cannot be construed as a limitation to the scope of implementing the present invention.
Example I
This example provides a dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir, where the oil formations between the horizontal sections of the injection and extraction wells of the dual-horizontal-well SAGD well set are all sand layers with the same thermal conductivity, an oil formation thickness of 13 meters, and an original oil content saturation of 70%, which meets the reservoir requirements for electric preheating.
The dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir Date Recue/Date Received 2021-11-29 I I
provided in this Example comprised the following specific steps:
(1) At least two horizontal wells with superposed horizontal sections were set up in the oil formation that consist of a SAGD well set, wherein the upper well was designated as Well I and the lower well was designated as Well P; the vertical distance between the horizontal sections of Well I and Well P was 4 in, both of which were completed with a conventional slotted sieve pipe.
(2) Concentric preheating tubing strings were inserted into the horizontal sections of Well I and Well P., and the distal end of the outer tubing of the concentric preheating tubing strings was capped; the distance from the concentric preheating tubing string to the toe of the horizontal section was 20 m, an outlet of the inner tubing- of the concentric preheating tubing string was 10 m from the distal end of the outer tubing of the concentric preheating tubing string, and the cross-sectional area of the inner tubing of the concentric preheating tubing string was equal to the cross-sectional area of the annular space between the outer and inner tubings of the concentric preheating tubing string.
(3) A heat-conducting fluid was injected into the annular space between the concentric preheating tubing string and a sieve pipe of Well I and Well P, the heat-conducting fluid was water, and the heat-conducting fluid was at a liquid level of 1 in above the heel.
(4) A gas was injected into the annular space between the concentric preheating tubing string and the sieve pipe located above the heel in Well I and Well P; wherein the gas comprises argon.
(5) The initial coking temperature of crude oil in the oil formation was measured, and the temperature corresponding to different coking rates of the crude oil was determined to be 320 C.
(6) A high-temperature fluid was continuously injected a into the inner tubing of the concentric preheating tubing string of Well I and Well P, and the fluid from the annular space between the inner tubing and outer tubing of the concentric preheating tubing string was discharged to the ground surface (i.e., heating by circulation with the high-temperature fluid);
the gas in the annular space between the concentric preheating tubing string and the sieve pipe located above the heel of Well 1 and Well P was simultaneously pressurized so that difference between the gas pressure in the annular space at the wellhead and the discharge pressure of the high-temperature fluid at the wellhead was 0.4 MPa.
The high-temperature fluid comprised a high-temperature gas, and the high-temperature gas comprised a combination of high-temperature argon and high-temperature helium (1:1 by volume); and wherein the high-temperature fluid had a temperature that was 5 C
lower than .. the initial coking temperature of the crude oil, and was injected at a rate of 5 m3/day.
(7) The temperature in the middle of the oil formation was determined by establishing a numerical model of the well set and performing tracked prediction of the inter-well temperature elevation, wherein the numerical model of the well set was established by using a Date Recue/Date Received 2021-11-29 reservoir numerical simulation software. The reservoir numerical simulation software was CMG-STAR from CMG Canada, When the temperature in the middle of the oil formation between the horizontal sections of Well I and Well P reached 190'C or higher, the injection of the high-temperature fluid was stopped.
(8) The gas and liquid were discharged from the annular space between the concentric preheating tubing string and the sieve pipe; the wellhead pressure when the gas and liquid were discharged from the annular space between the concentric preheating tubing and the sieve pipe was controlled to be 0.5 MPa lower than the original reservoir pressure.
(9) The concentric preheating tubings in Well I and Well P were removed, and an oil-soluble visbreaker was injected into the wellbores of Well I and Well p., respectively; the injection was stopped when the pressure in the wellbore of the horizontal section at the bottom of the well rose to 0.1 MPa below the rupture pressure of the caprock above the oil formation, and the well was soaked for 3 days; the oil-soluble visbreaker was injected in an amount of 10 tons/well.
(10) Steam was continuously injected into Well I, recovery from Well P was continuously carried out, and the SAGD preheating phase was completed and transitioned to the SAGD production phase.
Monitoring of the steam cavities after transitioning to SACiD production showed that by using the SAGD preheating start-up method of this Example, a uniform development of steam cavities throughout the horizontal section was achieved, with a steam cavity development along the horizontal section up to 98% (for an adjacent well set with conventional SAGD
preheating start-up: 49%) and an oil production rate of 80 tons/day (for an adjacent well set with conventional SAGD preheating start-up: 22 tons/day) compared to an adjacent SAGD
well set with conventional circulating preheating method.
Example 2 This example provides a dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir, where the oil formations between the horizontal sections of the injection and extraction wells of the dual-horizontal-well SAGD well set are all sand layers with a thermal conductivity grade difference of 2, an oil formation thickness of 15 meters, and an original oil content saturation of 75%, which meets the reservoir requirements for electric preheating.
The dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir provided in this Example comprised the following specific steps:
(1) At least two horizontal wells with superposed horizontal sections were set up in the oil formation that consist of a SAGD well set, wherein the upper well was designated as Well I and the lower well was designated as Well P; the vertical distance between the horizontal sections of Well I and Well P was 5 in, both of which were completed with a conventional slotted sieve pipe.
Date Recue/Date Received 2021-11-29 (2) Concentric preheating tubing strings were inserted into the horizontal sections of Well I and Well P, and the distal end of the outer tubing of the concentric preheating tubing strings was capped; the distance from the concentric preheating tubing string to the toe of the horizontal section was 40 in, an outlet of the inner tubing of the concentric preheating tubing string was 20 in from the distal end of the outer tubing of the concentric preheating tubing string, and the cross-sectional area of the inner tubing of the concentric preheating tubing string was equal to the cross-sectional area of the annular space between the outer and inner tubings of the concentric preheating tubing string.
(3) A heat-conducting fluid was injected into the annular space between the concentric preheating tubing string and a sieve pipe of Well I and Well P; the heat-conducting fluid was supercritical CO2, and the heat-conducting fluid was at a liquid level of 5 in above the heel.
(4) A gas was injected into the annular space between the concentric preheating tubing string and the sieve pipe located above the heel in Well I and Well P; wherein the gas comprises helium.
(5) The initial coking temperature of crude oil in the oil formation was measured, and the temperature corresponding to different coking rates of the crude oil was determined to be 350 C.
(6) A high-temperature fluid was continuously injected a into the inner tubing of the concentric preheating tubing string of Well I and Well P. and the fluid from the annular space between the inner tubing and outer tubing of the concentric preheating tubing string was discharged to the ground surface (i.e., heating by circulation with the high-temperature fluid);
the gas in the annular space between the concentric preheating tubing string and the sieve pipe located above the heel of Well I and Well P was simultaneously pressurized so that difference between the gas pressure in the annular space at the wellhead and the discharge pressure of the high-temperature fluid at the wellhead was 0.3 MPa.
The high-temperature fluid comprised a high-temperature gas, and the high-temperature gas comprised a combination of high-temperature helium and high-temperature CO2 (1:1 by volume); and wherein the high-temperature fluid had a temperature that was 10 C lower than the initial coking temperature of the crude oil, and was injected at a rate of 30 m3/day.
(7) Thc temperature in the middle of the oil formation was determined by establishing a numerical model of the well set and performing tracked prediction of the inter-well.
temperature elevation, wherein the numerical model of the well set was established by using a reservoir numerical simulation software. The reservoir numerical simulation software was ECLIPSE from Schlumberger USA. When the viscosity of the crude oil between the horizontal sections of Well 1 and Well P dropped to 100 mPa=s or lower, the injection of the high-temperature fluid was stopped_ (8) The gas and liquid were discharged from the annular space between the concentric preheating tubing string and the sieve pipe; the wellhead pressure when the gas and liquid were discharged from the annular space between the concentric preheating tubing and the Date Recue/Date Received 202 1-1 1-29 sieve pipe was controlled to be 2 MPa lower than the original reservoir pressure, (9) The concentric preheating tubings in Well I and Well P were removed, and an oil-soluble visbreaker was injected into the wellbores of Well I and Well P., respectively; the injection was stopped when the pressure in the wellbore of the horizontal section at the bottom of the well rose to 0.5 M.Pa below the rupture pressure of the caprock above the oil formation, and the well was soaked for 4 days; the oil-soluble visbreaker was injected in an amount of 50 tons/well, (10) Steam was continuously injected into Well 1, recovery from Well P was continuously carried out, and the SAGD preheating phase was completed and transitioned to the SAGD production phase.
Monitoring of the steam cavities after transitioning to SAGD production showed that by using the SAGD preheating start-up method of this Example, a uniform development of steam cavities throughout the horizontal section was achieved, with a steam cavity development along the horizontal section up to 94% (for an adjacent well set with conventional SAGD
preheating start-up: 51%) and an oil production rate of 76 tons/day (for an adjacent well set with conventional SAGD preheating start-up: 32 tons/day) compared to an adjacent SAGD
well set with conventional circulating preheating method.
Example 3 This example provides a dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir, where the oil formations between the horizontal sections of the injection and extraction wells of the dual-horizontal-well SAGD well set are all sand layers with the same thermal conductivity, an oil formation thickness of 20 meters, and an original oil content saturation of 76%, which meets the reservoir requirements for electric preheating.
The dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir provided in this Example comprised the following specific steps:
(1) At least two horizontal wells with superposed horizontal sections were set up in the oil formation that consist of a SAGD well set, wherein the upper well was designated as Well 1 and the lower well was designated as Well P; the vertical distance between the horizontal sections of Well I and Well P was 7 m, both of which were completed with a conventional slotted sieve pipe.
(2) Concentric preheating tubing strings were inserted into the horizontal sections of Well I and Well P, and the distal end of the outer tubing of the concentric preheating tubing strings was capped; the distance from the concentric preheating tubing string to the toe of the horizontal section was 60 m, an outlet of the inner tubing of the concentric preheating tubing string was 30 in from the distal end of the outer tubing of the concentric preheating tubing string, and the cross-sectional area of the inner tubing of the concentric preheating tubing string was equal to the cross-sectional area of the annular space between the outer and inner tubings of the concentric preheating tubing string.
Date Recue/Date Received 202 1-1 1-29 (3)A heat-conducting fluid was injected into the annular space between the concentric preheating tubing string and a sieve pipe of Well I and Well P; the heat-conducting fluid was heat-conducting oil, and the heat-conducting fluid was at a liquid level of 10 in above the heel.
5 (4)A gas was injected into the annular space between the concentric preheating tubing string and the sieve pipe located above the heel in Weill and Well P; wherein the gas comprises nitrogen.
(5) The initial coking temperature of crude oil in the oil formation was measured, and the temperature corresponding to different coking rates of the crude oil was determined to be 10 340 C.
(6)A high-temperature fluid was continuously injected a into the inner tubing of the concentric preheating tubing string of Well I and Well P, and the fluid from the annular space between the inner tubing and outer tubing of the concentric preheating tubing string was discharged to the ground surface (i.e., heating by circulation with the high-temperature fluid);
15 the gas in the annular space between the concentric preheating tubing string and the sieve pipe located above the heel of Well land Well P was simultaneously pressurized so that difference between the gas pressure in the annular space at the wellhead and the discharge pressure of the high-temperature fluid at the wellhead was 0.2 MPa.
The high-temperature fluid comprised a high-temperature liquid, and the high-temperature liquid was high-temperature steam (1:1 by volume); and wherein the high-temperature fluid had a temperature that was 20 C lower than the initial coking temperature of the crude oil, and was injected at a rate of 60 m3/day.
(7) The temperature in the middle of the oil formation was determined by establishing a numerical model of the well set and performing tracked prediction of the inter-well temperature elevation, wherein the numerical model of the well set was established by using a reservoir numerical simulation software. The reservoir numerical simulation software was ECLIPSE from Schlumberger USA. When the temperature in the middle of the oil formation between the horizontal sections of Well land Well P reached 180 C or higher, the injection of the high-temperature fluid was stopped.
(8) The gas and liquid were discharged from the annular space between the concentric preheating tubing string and the sieve pipe; the wellhead pressure when the gas and liquid were discharged from the annular space between the concentric preheating tubing and the sieve pipe was controlled to be 3 MPa lower than the original reservoir pressure.
(9) The concentric preheating tubings in Well I and Well P were removed, and an oil-soluble visbreaker was injected into the wellbores of Well I and Well P.
respectively; the injection was stopped when the pressure in the wellbore of the horizontal section at the bottom of the well rose to 1 MPa below the rupture pressure of the caprock above the oil formation, and the well was soaked for 5 days; the oil-soluble visbreaker was injected in an amount of 100 tons/well.
Date Recue/Date Received 202 1-1 1-29 (10) Steam was continuously injected into Well I, recovery from Well P was continuously carried out, and the SAGD preheating phase was completed and transitioned to the SAGD production phase.
Monitoring of the steam cavities after transition ing to SAGD production showed that by using the SAGD preheating start-up method of this Example, a uniform development of steam cavities throughout the horizontal section was achieved, with a steam cavity development along the horizontal section up to 95% (for an adjacent well set with conventional SAGD
preheating start-up: 43%) and an oil production rate of 76 tons/day (for an adjacent well set with conventional SAGD preheating start-up: 29 tons/day) compared to an adjacent SAGD
well set with conventional circulating preheating method.
Example 4 This example provides a dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir, where the oil formations between the horizontal sections of the injection and extraction wells of the dual-horizontal-well SAGD well set are all sand layers with the same thermal conductivity, an oil formation thickness of 22 meters, and an original oil content saturation of 78%, which meets the reservoir requirements for electric preheating.
The dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir provided in this Example comprised the following specific steps:
(1) At least two horizontal wells with superposed horizontal sections were set up in the oil formation that consist of a SAGD well set, wherein the upper well was designated as Well I and the lower well was designated as Well P; the vertical distance between the horizontal sections of Well I and Well P was 4 in, both of which were completed with a conventional slotted sieve pipe.
(2) Concentric preheating tubing strings were inserted into the horizontal sections of Well I and Well I', and the distal end of the outer tubing of the concentric preheating tubing strings was capped; the distal end of the outer tubing of the concentric preheating tubing strings was capped; the distance from the concentric preheating tubing string to the toe of the horizontal section was 20 m.
(3) A heat-conducting fluid was injected into the annular space between the concentric preheating tubing string and a sieve pipe of Well I and Well P; the heat-conducting fluid was heat-conducting oil, and the heat-conducting fluid was at a liquid level of 5 in above the heel.
(4) A gas was injected into the annular space between the concentric preheating tubing string and the sieve pipe located above the heel in Well I and Well P; the gas was nitrogen.
(5) The initial coking temperature of crude oil in the oil formation was measured, and the temperature corresponding to different coking rates of the crude oil was determined as 350 C.
(6) A resistance heating cable was inserted into an outer tubing of the concentric preheating tubing string, where the resistance heating cable was a stainless steel-armored magnesium oxide insulated cable and the electric heating power was 500 W/m.
The annular Date Recue/Date Received 2021-11-29 space between the heating cable and the outer tubing in the horizontal section was filled with a high-temperature fluid, and the annular space from the inclined section to the wellhead was filled with an insulating gas. Continuous temperature measurement was configured inside the cable with an optical fiber, which was connected to a ground power control box, to monitor the surface temperature of the heating cable in the horizontal section, and a thennostatical control function was achieved by automatic power adjustment. The high-temperature fluid was high-temperature steam, and the insulating gas was argon.
(7) The surface temperature of the heating cable in the horizontal section to be 5 C lower than the initial coking temperature of the formation crude oil, and heating was conducted continuously. The pressure of the gas inside the concentric preheating tubing during heating was adjusted so that the difference between the pressure of the gas inside the concentric preheating tubing and the pressure of the gas outside the concentric preheating tubing and in the annular space of the casing was less than 0.4 MPa.
(8) Electric heating was stopped when the temperature in the middle of the oil formation between the horizontal sections of Well I and Well P reaches 180 C or higher.
(9) The gas and liquid were discharged from the annular space between the concentric preheating tubing string and the sieve pipe.
(10) The concentric preheating tubings were removed from Well I and Well P
after no fluid flew out of the wellbores of Well I and Well P. and an oil-soluble visbreaker was injected into the wellbores of Well I and Well P, respectively; the injection was stopped when the pressure in the wellbore of the horizontal section at the bottom of the well rose to 0.1 MPa below the rupture pressure of the caprock above the oil formation, and the well was soaked for 3 days.
(11) Steam was continuously injected into Well I, recovery from Well P was continuously canied out, and the SAGD preheating phase was completed and transitioned to the SAGD
production phase.
Monitoring of the steam cavities after transitioning to SAG!) production showed that by using the SACiD preheating start-up method of this Example, a uniform development of steam cavities throughout the horizontal section was achieved, with a steam cavity development along the horizontal section up to 96% (for an adjacent well set with conventional SAGD
preheating start-up: 48%) and an oil production rate of 78 tons/day (for an adjacent well set with conventional SAGD preheating start-up: 31 tons/day) compared to an adjacent SAGD
well set with conventional circulating preheating method.
Example 5 This example provides a dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir, where the oil formations between the horizontal sections of the injection and extraction wells of the dual-horizontal-well SAGD well set are all sand layers with the same thermal conductivity, an oil formation thickness of 25 meters, and an original oil content Date Recue/Date Received 2021-11-29 saturation of 79%, which meets the reservoir requirements for electric preheating.
The dual-horizontal-well SAGD preheating start-up method for a heavy oil reservoir provided in this Example comprised the following specific steps:
(1) At least two horizontal wells with superposed horizontal sections were set up in the oil formation that consist of a SAGD well set, wherein the upper well was designated as Well and the lower well was designated as Well P; the vertical distance between the horizontal sections of Well I and Well P was 7 m, both of which were completed with a slotted sieve Pipe.
(2) Concentric preheating tubing strings were inserted into the horizontal sections of Well I and Well P. and the distal end of the outer tubing of the concentric preheating tubing strings was capped. The distal end of the outer tubing of the concentric preheating tubing strings was capped; the distance from the concentric preheating tubing string to the toe of the horizontal section was 60 m.
(3) A heat-conducting fluid was injected into the annular space between the concentric preheating tubing string and a sieve pipe of Well 1 and Well P; the heat-conducting fluid was heat-conducting oil, and the heat-conducting fluid was at a liquid level of 10 m above the heel.
(4) A gas was injected into the annular space between the concentric preheating tubing string and the sieve pipe located above the heel in Well I and Well P; the gas was nitrogen.
(5) The initial coking temperature of crude oil in the oil formation was measured, and the temperature corresponding to different coking rates of the crude oil was determined as 370 C.
(6) A resistance heating cable was inserted into an outer tubing of the concentric preheating tubing string, where the resistance heating cable was a stainless steel-armored magnesium oxide insulated cable and the electric heating power was 2000 W/m.
The annular space between the heating cable and the outer tubing in the horizontal section was filled with a high-temperature fluid, and the annular space from the inclined section to the wellhead was filled with an insulating gas. Six thermocouple temperature measurement points were configured at the same interval along the horizontal section on the outer wall of the cable, which was connected to a ground power control box, to monitor the surface temperature of the heating cable in the horizontal section, and a thermostatical control function was achieved by automatic power adjustment.
The high-temperature fluid was molten sodium nitrate, and the temperature of the high-temperature fluid was 20 C lower than the initial coking temperature of the crude oil.
The insulating gas was nitrogen.
(7) The surface temperature of the heating cable in the horizontal section to be 20 C
lower than the initial coking temperature of the formation crude oil, and heating was conducted continuously. The pressure of the gas inside the concentric preheating tubing during heating was adjusted so that the difference between the pressure of the gas inside the Date Recue/Date Received 2021-11-29 concentric preheating tubing and the pressure of the gas outside the concentric preheating tubing and in the annular space of the casing was less than 0.3 MPa.
(8) Electric heating was stopped when the temperature in the middle of the oil formation between the horizontal sections of Well I and Well P reaches 180 C or higher.
(9) The gas and liquid were discharged from the annular space between the concentric preheating tubing string and the sieve pipe.
(10) The concentric preheating tubings were removed from Well I and Well P
after no fluid flew out of the wellbores of Well I and Well P, and an oil-soluble visbreaker was injected into the wellbores of Well I and Well P, respectively; the injection was stopped when the pressure in the wellbore of the horizontal section at the bottom of the well rose to 1 MPa below the rupture pressure of the caprock above the oil formation, and the well was soaked for 5 days.
(11) Steam was continuously injected into Well 1, recovery from Well P was continuously carried out, and the SAGD preheating phase was completed and tmnsitioned to the SAGD
production phase.
Monitoring of the steam cavities after transitioning to SACID production showed that by using the SAGD preheating start-up method of this Example, a uniform development of steam cavities throughout the horizontal section was achieved, with a steam cavity development along the horizontal section up to 93% (for an adjacent well set with conventional SAGD
preheating start-up: 43%) and an oil production rate of 77 tons/day (for an adjacent well set with conventional SAGD preheating start-up: 33 tons/day) compared to an adjacent SAGD
well set with conventional circulating preheating method.
Date Recue/Date Received 2021-11-29

Claims

20

1. A downhole preheating start-up method for a super heavy oil reservoir developed for by dual-horizontal-well SAGD, which comprises the steps of:
injecting a heat-conducting fluid into an oil well through a dual-horizontal-well SAGD
well set, and then injecting a gas;
continuously injecting a high-temperature fluid through an inner tubing of a concentric preheating tubing string, and discharging the fluid to the ground surface through the annular space between the inner tubing and outer tubing of the concentric preheating tubing string, while adjusting the pressure of the gas during the heating process so that the difference between the gas pressure in the annular space at the wellhead and the discharge pressure of the high-temperature fluid at the wellhead is less than 0.5 MPa; the temperature of the high-tcmperaturc circulating fluid being 5 to 20 C lower than thc initial coking temperature of the formation crude oil; or alternatively, inserting a resistance heating cable into an outer tubing of the concentric preheating tubing string, filling the annular space between the heating cable and the outer tubing in the horizontal section with a high-temperature fluid, and filling the annular space from the inclined section to the wellhead with an insulating gas; configuring an optical fiber temperature measurement point and/or a thermocouple temperature measurement point on the outer wall of and/or inside the cable, monitoring the surface ternperature of the heating cable in the horizontal section, and achieving thermostatical control by automatic power adjustment;
the surface temperature of the heating cable in the horizontal section being 5-20 C lower than the initial coking temperature of the formation crude oil, with continuous heating;
stop injecting the high-temperature fluid when the temperature in the middle of the oil formation reaches 180C or higher, or when the viscosity of the crude oil drops to 100 mPa- s or lower;
discharging the gas and liquid frorn the oil well;
removing the concentric preheating tubing from Well I and Well I', and injecting an visbreaker into Well I and Well P simultaneously, stop injecting when the pressure in the wellbore of the horizontal section at the bottom of the well rises to below the rupture pressure of the caprock above the oil formation, and soaking the well for an appropriate period of time before the SAGD preheating phase is completed;
continuously injecting steam, and continuously recovering from Well P, and transitioning into the SAGD production phase.

2. The method according to claim 1, wherein the method comprises the following particular steps:
(1) setting up at least two horizontal wells with superposed horizontal sections in the oil formation that consist of a SAGD well set, wherein the upper well is designated as Well I and the lower well is designated as Well P;
(2) inserting concentric preheating tubing strings into the horizontal sections of Well I

and Well P, and capping the distal end of the outer tubing of the concentric preheating tubing strings;
(3) injecting a heat-conducting fluid into the annular space between the concentric preheating tubing string and a sieve pipe of Well I and Well P;
(4) injecting a gas into the annular space between the concentric preheating tubing string and the sieve pipe located above the heel in Well I and Well P;
(5) measuring the initial coking ternperature of crude oil in the oil fortnation, and determining the temperatures correspondthg to different coking rates of the crude oil;
(6) continuously injecting a high-temperature fluid into the inner tubing of the concentric preheating tubing string of Well I and Well P and discharging the fluid from the annular space between the inner tubing and outer tubing of the concentric preheating tubing string to the ground surface; sirnultaneously pressurizing the gas in the annular space between the concentric preheating tubing string and the sieve pipe located above the heel of Well I and Well P so that difference between the gas pressure in the annular space at the wellhead and the discharge pressure of the high-temperature fluid at the wellhead is less than 0.5 MPa;
(7) stop injecting the high-temperature fluid when the temperature in the middle of the oil formation between the horizontal sections of Well 1 and Well P reaches 180 C or higher, or when the viscosity of the crude oil drops to 100 mPa-s or lower;
(8) discharging the gas and liquid from the annular space between the concentric preheating tubing string and the sieve pipe;
(9) after no fluid discharges at the wellbores of Well 1 and Well P, removing the concentric preheating tubings from Well I and Well P, and injecting an oil-soluble visbreaker into the wellbores of Well I and Well P, respectively, stop injecting when the pressure in the wellbore of the horizontal section at the bottom of the well rises to 0.1-1 MPa below the rupture pressure of the caprock above the oil formation, and soaking the well for 3-5 days;
(10) continuously injecting steam into Well I, and continuously recovering from Well p., thereby ending the SAGD preheating phase and transitioning to the SAGD
production phase.

3. The method according to claim 1 or 2, wherein the method is directed to a super heavy oil reservoir that meets the following conditions:
(i) a thermal conductivity grade difference of the SAGD oil formation of less than 3;
(ii) oil saturation > 60%;
(iii) oil formation thickness >12rn;
(iv) a vertical distance between the horizontal sections of Well 1 and Well P
of 4-7m.

4. The method according to claim 2, wherein in step (1), the horizontal sections of both Well 1 and Well P are completed with a slotted sieve pipe.

5. The method according to claim 2, wherein in step (2), the distance from the concentric preheating tubing string to the toe of the horizontal section is 20-60 in; an outlet of the inner tubing of the concentric preheating tubing string is 10-30 rn from the distal end of the outer tubing of the concentric preheating tubing string; the cross-sectional area of the inner tubing of the concentric preheating tubing string is equal to the cross-sectional area of the annular space between the outer and inner tubings of the concentric preheating tubing string.

6. The method according to claim 5, wherein in step (2), the distance from the concentric preheating tubing string to the toe of the horizontal section is 50 m.

7. The method according to claim 2, wherein in step (2), the heat-conducting fluid is at a liquid level of 1-10 m above the heel.

8. The method according to claim 2 or claim 7, wherein in step (2), the heat-conducting fluid is at a liquid level of 10 m above the heel.

9. The method according to any one of claims 2 and 7-8, wherein in step (2), the heat-conducting fluid is one or a combination of two or more of water, supercritical CO2, and a heat-conducting oil.

10. The method according to claim 2, wherein in step (4), the gas comprises one or a combination of two or rnore of argon, helium, and nitrogen.

11. The method according to clairn 2, wherein in step (6), the high-temperature fluid comprises a high-temperature gas and/or a high-temperature liquid, wherein the high-ternperature gas comprises one or a combination of two or rnore of high-temperature argon, high-temperature helium, high-temperature nitrogen, and high-temperature CO2; and the high-temperature liquid comprises one or a cornbination of two or more of a high-temperature steam, a high-temperature oil and a molten salt.

12. The method according to claim 2 or claim 11, wherein in step (6), the high-temperature fluid has a temperature that is 5-20 C lower than the initial coking temperature of the crude oil.

13. The method according to any one of claims 2 and 11-12, wherein in step (6), the injection rate of the high-temperature fluid is 5-60 m3/day.

14. The method according to claim 2, wherein in step (7), a ternperature in the middle of the oil formation is determined by establishing a numerical model of the well set and performing tracked prediction of the inter-well temperature elevation.

15. The method according to claim 14, wherein in step (7), the numerical model of the well set is established by using a reservoir numerical simulation software.

16, The method according to claim 15, wherein in step (7), the reservoir numerical simulation software includes CMG-STAR from CMG Canada and/or ECLIPSE from Schlumberger USA.

17. The method according to clairn 2, wherein in step (8), the wellhead pressure when the gas and liquid are discharged from the annular space between the concentric preheating tubing and the sieve pipe is controlled to be 0.5-3 MPa lower than the original reservoir pressure.

18. The method according to claim 2, wherein in step (9), the oil-soluble visbreaker is injected in an arnount of 10-100 tons/well.

19. The method according to clairn 1, wherein the method comprises the specific steps of (1) setting up at least two horizontal wells with superposed horizontal sections in the oil formation that consist of a SAGD well set, wherein the upper well is designated as Well 1 and the lower well is desitmated as Well P;
(2) inserting concentric preheating tubing strings into the horizontal sections of Well 1 and Well P, and capping the distal end of the outer tubing of the concentric preheating tubing strings;
(3) injecting a heat-conducting fluid into the annular space between the concentric preheating tubing string and a sieve pipe of Well 1 and Well P;
(4) injecting a gas into the annular space between the concentric preheating tubing string and the sieve pipe located above the heel in Well I and Well P;
(5) measuring the initial coking temperature of crude oil in the oil formation, and determining the ternperatures con-esponcling to different coking rates of the crude oil;
(6) inserting a resistance heating cable into an outer tubing of the concentric preheating tubing string, filling the annular space between the heating cable and the outer tubing in the horizontal section with a high-temperature fluid, and filling the annular space from the inclined section to the wellhead with an insulating gas; setting an optical fiber temperature measurement point and/or a therrnocouple temperature measurement point on the outer wall of and/or inside the cable, connecting to a ground power control box, monitoring the surface temperature of the heating cable in the horizontal section, and achieving a thermostatical control fimction by automatic power adjustment;
(7) setting the surface ternperature of the heating cable in the horizontal section to be 5-20 C lower than the initial coking ternperature of the formation crude oil, and heating continuously; adjusting the pressure of the gas inside the concentric preheating tubing during heating so that the difference between the pressure of the gas inside the concentric preheating tubing and the pressure of the gas outside the concentric preheating tubing and in the annular space of the casing is less than 0.5 MPa;
(8) stop electric heating when the temperature in the middle of the oil formation between the horizontal sections of Well I and Well P reaches 180 C or higher, or when the viscosity of the crude oil drops to 100 rnPa-s or lower;
(9) discharging the gas and liquid from the annular space between the concentric preheating tubinu string and the sieve pipe;
(10) removing the concentric preheating tubings from Well I and Well P after no fluid flows out of the wellbores of Well I and Well P, and injecting an oil-soluble visbreaker into the wellbores of Well 1 and Well P. respectively, stop injecting when the pressure in the wellbore of the horizontal section at the bottorn of the well rises to 0.1-1 MPa below the rupture pressure of the caprock above the oil formation, and soaking the well for 3-5 days;
(11) continuously injecting stearn into Well I, and continuously recovering frorn Well P, thereby ending the SAGD preheating phase and transitioning to the SAGD
production phase.

20. The rnethod according to clairn 19, wherein the heating cable is a stainless steel-armored magnesium oxide insulated cable, and the electric heating power is 500-2000 W/m.

21. The rnethod according to claim 19, wherein in step (6), the insulating gas cornprises one or a cornbination of two or more of argon, helium, and nitrogen.

22. The method according to claim 19, wherein in step (6), the high-temperature fluid comprises a high-temperature gas and/or a high-temperature liquid, wherein the high-temperature gas cornprises one or a cornbination of two or more of high-temperature argon, high-temperature helium, high-ternperature nitrogen, and high-temperature CO2; and the high-temperature liquid comprises one or a combination of two or more of a high-temperature steam, a high-temperature oil and a molten salt.

23. The inethod according to 19 or 22, wherein in step (6), the high-tetnperature fluid has a temperature that is 5-20 C lower than the initial coking temperature of the crude oil.