A method for downhole electrical heating to extract crude oil from a gas-bearing heavy oil reservoir

Abstract

The present invention provides a method for downhole electric heating to extract crude oil from a gas-bearing heavy oil reservoir, comprising the following steps: (1) performing CO2 energy storage volume fracturing operation on a horizontal well in the gas-bearing heavy oil reservoir to enable a hydraulic fracturing fracture network to develop uniformly in the horizontal section; (2) laying thermosensitive proppants in the fracturing fractures of the horizontal section to form a heat transfer network; (3) lowering a heating cable into the wellbore of the horizontal section to electrically heat the oil layer in the horizontal section to reach a preset wellbore temperature; (4) opening the well for production and controlling the daily liquid production volume within a preset range; (5) when the daily oil production volume is less than a preset value, injecting a viscosity reducer, a gas, and a foam triggering system into the bottom hole and shutting in the well; (6) opening the well for production and controlling the daily liquid production volume within a preset range; (7) repeating steps (5) and (6) for at least 2 rounds of huff and puff production, and stopping production when the oil production volume in a single round is less than the lower limit value. The method improves the fluidity and recovery rate of crude oil and improves the huff and puff production effect.

Description

Technical Field

[0001] The present invention belongs to the technical field of crude oil exploitation, and relates to a method for exploiting a gas-bearing heavy oil reservoir, in particular to a method for downhole electrothermal exploitation of crude oil in a gas-bearing heavy oil reservoir. Background Art

[0002] A gas-bearing heavy oil reservoir refers to a heavy oil reservoir that naturally contains dissolved gas. During the natural depletion cold production process, as the reservoir pressure drops, the dissolved gas separates from the crude oil, thereby forming a dissolved gas drive. Given that the viscosity of the crude oil in a gas-bearing heavy oil reservoir rises rapidly after degassing, the recovery factor of natural energy depletion cold production is extremely low, usually estimated to be 5%-8%; and the viscosity of the degassed crude oil is usually as high as 1000-50000 mPa·s, with extremely high flow resistance, making it difficult for the injected fluid to enter the deep part of the reservoir, and the development effect is poor.

[0003] For heavy oil with extremely high viscosity and flow resistance, methods such as water flooding, chemical flooding, or gas flooding cannot be used for exploitation or have poor exploitation effects. Those skilled in the art mainly adopt thermal oil recovery methods. Steam injection methods such as steam stimulation, steam flooding, and steam assisted gravity drainage are the most widely used thermal oil recovery methods at present, and approximately 80% of heavy oil is produced by steam injection. However, the steam injection thermal oil recovery method mainly has the following problems: (1) High ground and wellbore heat losses, usually up to more than 10%-30%; (2) The two-phase flow of oil and water after steam condensation will affect the heavy oil production, and the condensed hot water will absorb a large amount of heat; (3) Steam phase separation and steam override in the bottom hole and formation will reduce the heat utilization rate and sweep efficiency; (4) It is not suitable for deep, offshore, desert, and strongly water-sensitive reservoirs; (5) The production in the middle and late stages of exploitation is low, the oil-steam ratio is low, and the economic benefit is poor, and the development method needs to be converted. In particular, it is difficult to implement steam injection thermal recovery for offshore heavy oil reservoirs with limited space on the oil production platform, desert heavy oil reservoirs with water resource shortages, and deep heavy oil reservoirs. At present, they are mainly exploited by conventional cold production methods, with low oil production rate and recovery factor, and there is an urgent need to adopt effective new heavy oil development methods.

[0004] In addition, the in-situ combustion technology is another important heavy oil thermal recovery technology. After igniting the oil reservoir through an injection well, air is continuously injected into the oil reservoir to support combustion, forming a moving combustion zone. Ahead of the combustion front, the crude oil is heated and its viscosity is reduced, and distillation occurs. The light oil, steam, and flue gases such as carbon dioxide generated by combustion move towards the production well under the action of heat. The heavy components that are not distilled are cracked and decomposed under high-temperature conditions and finally become coke, which becomes the fuel to maintain the continuous forward combustion of the oil reservoir. Under the action of high temperature, the bound water in the oil reservoir and the water generated by combustion become water vapor, carry a large amount of heat and move forward, displacing the crude oil again, forming a complex process with multiple driving forces to drive the crude oil towards the production well. The cracked residue burned is only 10 - 15% of the original oil reserves, which has the advantage of high oil displacement efficiency compared with other oil production methods, and the average recovery rate can reach more than 50%. However, the oil displacement mechanism of this method is complex, the operation is quite difficult, and it is not conducive to the exploitation of fractured reservoirs.

[0005] CN101161987A discloses a technology for in-situ combustion huff and puff of heavy oil, which uses ignition technologies such as electric heater ignition, natural gas ignition or spontaneous ignition to heat the oil layer of the oil (water) well to a temperature above 450°C, continuously injects air (oxygen-enriched) into the oil (water) well with an air compressor for 15 - 25 days and then stops ignition, soaks the well for 5 - 10 days, and then opens the well for production (water injection) to achieve the purpose of increasing production and injection. It is mainly for high-rounds huff and puff production wells, and is also applicable to oil (water) wells that have not implemented steam huff and puff. The technology for in-situ combustion huff and puff of heavy oil provided by the invention does not mention the process of circulating the wellbore before ignition, and without circulating the wellbore, it is easy to cause uneven ignition and there is a risk of explosion and backfire in the wellbore. In addition, in the process provided by the invention, it is necessary to stop ignition, soak the well and then open the well for production (water injection), and the water injection refers to water injection for oil displacement in an injection well, and no water injection is carried out during or after injecting air (oxygen-enriched). In this way, during in-situ combustion huff and puff, the oil well is in a high-temperature environment during soaking and oil production, and the tubing of the oil well is prone to high-temperature damage, and the temperature of the produced fluid is too high.

[0006] Therefore, how to provide a method for exploiting a gas-bearing heavy oil reservoir, improving the fluidity of high-viscosity crude oil, improving the huff and puff production effect, and thus increasing the crude oil recovery rate has become an urgent problem to be solved by those skilled in the art currently. Summary of the Invention

[0007] The purpose of the present invention is to provide a method for downhole electric heating to exploit crude oil from a gas-bearing heavy oil reservoir, which improves the fluidity of high-viscosity crude oil, improves the huff and puff production effect, and thus increases the crude oil recovery rate.

[0008] To achieve the purpose of this invention, the following technical solutions are adopted:

[0009] The present invention provides a method for downhole electric heating to extract crude oil from a gas-bearing heavy oil reservoir. The method comprises the following steps:

[0010] (1) Perform CO2 energy storage volume fracturing operation on the horizontal well in the gas-bearing heavy oil reservoir, so that a hydraulic fracturing fracture network is evenly developed in the horizontal section;

[0011] (2) Lay thermosensitive proppants in the fracturing fractures of the horizontal section obtained in step (1) to form a heat transfer network;

[0012] (3) Lower a heating cable into the horizontal section wellbore to electrically heat the oil layer in the horizontal section to reach a preset wellbore temperature;

[0013] (4) Open the well for production and control the daily liquid production volume within a preset range;

[0014] (5) When the daily oil production is less than a preset value, inject a viscosity reducer, gas and foam triggering system into the bottom of the well and shut in the well;

[0015] (6) Open the well for production and control the daily liquid production volume within a preset range;

[0016] (7) Repeat steps (5) and (6) for at least 2 rounds of huff and puff production. When the oil production in a single round is less than the lower limit value, stop production.

[0017] Among them, steps (5) and (6) continuously perform electric heating, and the power control method is the same as that in step (3).

[0018] The method provided by the present invention combines CO2 energy storage volume fracturing and electric heating to assist natural depletion production, generates a large number of distributed fracture networks in the reservoir, and greatly improves the production during natural depletion; promotes the balanced utilization of the horizontal section through uniform electric heating of the horizontal section; accelerates the heat transfer and temperature rise of the oil layer by laying thermosensitive proppants in the fracturing fractures, improves the fluidity and production of crude oil; adopts the method of electric heating-assisted huff and puff for production after natural depletion. The injected foam oil triggering system expands the action range of the foam oil system in the oil layer, and electric heating greatly reduces the viscosity of the crude oil near the wellbore and the flow resistance of the crude oil entering the well, improves the huff and puff production effect, and thus improves the crude oil recovery rate.

[0019] Preferably, the CO2 energy storage volume fracturing operation in step (1) is carried out in multiple segments and multiple clusters on the horizontal well, with 2-3 clusters per segment, and the length of each segment is 40-60 m. For example, it can be 40 m, 42 m, 44 m, 46 m, 48 m, 50 m, 52 m, 54 m, 56 m, 58 m or 60 m, but is not limited to the listed values. Other unlisted values within this numerical range are equally applicable.

[0020] Preferably, the specific process of the CO2 energy storage volume fracturing operation in step (1) is as follows: liquid CO2 and a preflush fluid are successively injected into the gas-bearing heavy oil reservoir from the wellhead of the horizontal well to initiate the fracture.

[0021] Preferably, the injection volume of the liquid CO2 per unit length of the horizontal section is 1 - 3 m 3 / m. For example, it can be 1 m 3 / m, 1.2 m 3 / m, 1.4 m 3 / m, 1.6 m 3 / m, 1.8 m 3 / m, 2 m 3 / m, 2.2 m 3 / m, 2.4 m 3 / m, 2.6 m 3 / m, 2.8 m 3 / m or 3 m 3 / m, but is not limited to the listed values, and other unlisted values within this range are equally applicable.

[0022] Preferably, the judgment criterion for the end of the preflush fluid injection is that the reservoir pressure reaches 5 - 10 MPa above the reservoir fracture pressure. For example, it can be 5 MPa, 5.5 MPa, 6 MPa, 6.5 MPa, 7 MPa, 7.5 MPa, 8 MPa, 8.5 MPa, 9 MPa, 9.5 MPa or 10 MPa, but is not limited to the listed values, and other unlisted values within this range are equally applicable.

[0023] Preferably, the specific process of laying the thermosensitive proppant in step (2) is as follows: a sand-carrying fluid and a displacement fluid are successively injected into the reservoir, and the well is shut in and then flowed back.

[0024] Preferably, the proppant in the sand-carrying fluid is a mixture of any one or at least two combinations of carbon fiber, alumina, magnesia, zinc oxide, aluminum nitride, boron nitride or silicon carbide and ceramic particles. Typical but non-limiting combinations include the combination of carbon fiber and alumina, the combination of alumina and magnesia, the combination of magnesia and zinc oxide, the combination of zinc oxide and aluminum nitride, the combination of aluminum nitride and boron nitride, the combination of boron nitride and silicon carbide, the combination of carbon fiber, alumina and magnesia, the combination of alumina, magnesia and zinc oxide, the combination of magnesia, zinc oxide and aluminum nitride, the combination of zinc oxide, aluminum nitride and boron nitride, or the combination of aluminum nitride, boron nitride and silicon carbide.

[0025] Preferably, the ceramsite accounts for 25-50% of the mass of the proppant, for example, it can be 25%, 26%, 28%, 30%, 32%, 34%, 36%, 38%, 40%, 42%, 44%, 46%, 48% or 50%, but is not limited to the listed values, and other unlisted values within this numerical range are equally applicable.

[0026] Preferably, the judgment criterion for the end of the displacement fluid injection is that the reservoir pressure reaches 10-20 MPa above the reservoir fracture pressure, for example, it can be 10 MPa, 11 MPa, 12 MPa, 13 MPa, 14 MPa, 15 MPa, 16 MPa, 17 MPa, 18 MPa, 19 MPa or 20 MPa, but is not limited to the listed values, and other unlisted values within this numerical range are equally applicable.

[0027] Preferably, the soaking time is 40-60 days, for example, it can be 40 days, 42 days, 44 days, 46 days, 48 days, 50 days, 52 days, 54 days, 56 days, 58 days or 60 days, but is not limited to the listed values, and other unlisted values within this numerical range are equally applicable.

[0028] Preferably, the heating cable in step (3) is a constant temperature heating cable.

[0029] Preferably, a temperature measuring optical fiber is laid inside the constant temperature heating cable for monitoring the surface temperature of the heating cable in the horizontal section and feeding it back to the ground power control cabinet for intelligent power adjustment.

[0030] Preferably, the heating power per meter of the constant temperature heating optical cable is 400-2500 W, for example, it can be 400 W, 800 W, 1000 W, 1200 W, 1400 W, 1600 W, 1800 W, 2000 W, 2200 W, 2400 W or 2500 W, but is not limited to the listed values, and other unlisted values within this numerical range are equally applicable.

[0031] Preferably, the preset wellbore temperature in step (3) is 100-250 °C, for example, it can be 100 °C, 120 °C, 140 °C, 160 °C, 180 °C, 200 °C, 220 °C, 240 °C or 250 °C, but is not limited to the listed values, and other unlisted values within this numerical range are equally applicable.

[0032] Preferably, the daily liquid production in steps (4) and (6) is set within a range based on a constant bottom hole pressure difference.

[0033] Preferably, the bottom-hole pressure differential is controlled within 0.5 - 3 MPa. For example, it can be 0.5 MPa, 0.6 MPa, 0.8 MPa, 1 MPa, 1.2 MPa, 1.4 MPa, 1.6 MPa, 1.8 MPa, 2 MPa, 2.2 MPa, 2.4 MPa, 2.6 MPa, 2.8 MPa or 3 MPa. However, it is not limited to the listed values, and other unlisted values within this numerical range are equally applicable.

[0034] Preferably, the formula for calculating the maximum value of the daily liquid production is:

[0035]

[0036] In the formula, μ o (T) is the viscosity of the gas-containing heavy oil within 1 m near the electrically heated wellbore, mPa·s; B o is the formation volume factor of the crude oil, dimensionless; C w is the water cut, dimensionless; h is the thickness of the oil layer, m; K h is the vertical permeability of the oil layer, μm 2 ; L is the length of the horizontal section, m; ΔP is the bottom-hole pressure differential, 10 -1 MPa; r eh is the supply radius of the horizontal section, m; r w is the wellbore radius, m.

[0037] In the present invention, μ o (T) is the viscosity of the gas-containing heavy oil within 1 m near the electrically heated wellbore, which is related to the heating temperature. The gas-containing viscosities at different temperatures are obtained by testing with a ground rheometer.

[0038] Preferably, the preset value of the daily oil production in step (5) is 2 - 5 m 3 , for example, it can be 2 m 3 , 2.5 m 3 , 3 m 3 , 3.5 m 3 , 4 m 3 , 4.5 m 3 or 5 m 3 , but it is not limited to the listed values, and other unlisted values within this numerical range are equally applicable.

[0039] Preferably, the viscosity reducer in step (5) includes naphtha and / or condensate.

[0040] Preferably, the gas in step (5) includes any one or a combination of at least two of CO2, N2, methane, natural gas, air, or water vapor. Typical but non-limiting combinations include the combination of CO2 and N2, the combination of N2 and methane, the combination of methane and natural gas, the combination of natural gas and air, the combination of air and water vapor, the combination of CO2, N2, and methane, the combination of N2, methane, and natural gas, the combination of methane, natural gas, and air, or the combination of natural gas, air, and water vapor.

[0041] Preferably, the foam triggering system in step (5) includes a highly oil-resistant foaming agent and a foam stabilizer.

[0042] Preferably, the oil saturation of the highly oil-resistant foaming agent is ≥40%, for example, it can be 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, or 80%, and the foaming height is ≥2 times, for example, it can be 2 times, 2.5 times, 3 times, 3.5 times, 4 times, 4.5 times, or 5 times, but is not limited to the listed values. Other unlisted values within this numerical range are equally applicable.

[0043] Preferably, the concentration of the highly oil-resistant foaming agent in the foam triggering system is 0.5 - 3 wt%, for example, it can be 0.5 wt%, 1 wt%, 1.5 wt%, 2 wt%, 2.5 wt%, or 3 wt%, but is not limited to the listed values. Other unlisted values within this numerical range are equally applicable.

[0044] Preferably, the concentration of the foam stabilizer in the foam triggering system is 0.1 - 1.5 wt%, for example, it can be 0.1 wt%, 0.2 wt%, 0.4 wt%, 0.6 wt%, 0.8 wt%, 1 wt%, 1.2 wt%, 1.4 wt%, or 1.5 wt%, but is not limited to the listed values. Other unlisted values within this numerical range are equally applicable.

[0045] Preferably, the specific process of the injection in step (5) is: first inject a viscosity reducer slug, and then alternately inject the gas and the foam triggering system into the bottom hole in small slugs of 0.01 - 0.03 PV, for example, it can be 0.01 PV, 0.012 PV, 0.014 PV, 0.016 PV, 0.018 PV, 0.02 PV, 0.022 PV, 0.024 PV, 0.026 PV, 0.028 PV, or 0.03 PV, but is not limited to the listed values. Other unlisted values within this numerical range are equally applicable.

[0046] Preferably, the injection volume of the viscosity reducer slug is 0.01 - 0.05 PV. For example, it can be 0.01 PV, 0.02 PV, 0.03 PV, 0.04 PV, or 0.05 PV. However, it is not limited to the listed values, and other unlisted values within this range are equally applicable.

[0047] Preferably, the injection volume of the gas and foam triggering system is 0.2 - 0.3 PV. For example, it can be 0.2 PV, 0.21 PV, 0.22 PV, 0.23 PV, 0.24 PV, 0.25 PV, 0.26 PV, 0.27 PV, 0.28 PV, 0.29 PV, or 0.3 PV. However, it is not limited to the listed values, and other unlisted values within this range are equally applicable.

[0048] Preferably, the soaking time in step (5) is 20 - 30 days. For example, it can be 20 days, 21 days, 22 days, 23 days, 24 days, 25 days, 26 days, 27 days, 28 days, 29 days, or 30 days. However, it is not limited to the listed values, and other unlisted values within this range are equally applicable.

[0049] Preferably, the lower limit value of the oil production per single cycle in step (7) is dynamically related to the oil price: when the calculated profit is 0, the corresponding oil production is the lower limit value of the oil production per single cycle.

[0050] As a preferred technical solution of the present invention, the method includes the following steps:

[0051] (1) Perform multi - stage and multi - cluster CO2 energy - storage volume fracturing operation on the horizontal well in the gas - containing heavy - oil reservoir, with 2 - 3 clusters per stage and the length of each stage being 40 - 60 m, so that a hydraulic fracturing fracture network is evenly developed in the horizontal section; the specific process of the CO2 energy - storage volume fracturing operation is: inject liquid CO2 and pre - flush fluid into the gas - containing heavy - oil reservoir in sequence from the wellhead of the horizontal well to open the fractures; the injection volume of the liquid CO2 per unit length of the horizontal section is 1 - 3 m 3 / m, and the judgment criterion for the end of the pre - flush fluid injection is that the reservoir pressure reaches 5 - 10 MPa above the reservoir fracture pressure;

[0052] (2) Lay heat - sensitive proppants in the fracturing fractures of the horizontal section obtained in step (1) to form a heat - transfer network; the specific process of laying the heat - sensitive proppants is: inject sand - carrying fluid and displacement fluid into the reservoir in sequence, soak for 40 - 60 days and then drain the fluid; the proppants in the sand - carrying fluid include a mixture of any one or at least two combinations of carbon fiber, alumina, magnesia, zinc oxide, aluminum nitride, boron nitride, or silicon carbide and ceramsite, and the ceramsite accounts for 25 - 50% of the mass of the proppants; the judgment criterion for the end of the displacement fluid injection is that the reservoir pressure reaches 10 - 20 MPa above the reservoir fracture pressure;

[0053] (3) Lower a constant-temperature heating cable into the horizontal-section wellbore to electrically heat the horizontal-section oil reservoir to a preset wellbore temperature of 100 - 250 °C; a temperature-measuring optical fiber is laid inside the constant-temperature heating cable, and the heating power per meter is 400 - 2500 W;

[0054] (4) Open the well for production and control the daily liquid production volume within a preset range. The daily liquid production volume is set within a range based on a constant bottom-hole pressure difference, and the bottom-hole pressure difference is controlled at 0.5 - 3 MPa; the calculation formula for the maximum value of the daily liquid production volume is:

[0055]

[0056] In the formula, μ o (T) is the viscosity of the gas-containing viscous oil within 1 m near the electrically heated wellbore, mPa·s; B o is the crude oil volume factor, dimensionless; C w is the water cut, dimensionless; h is the oil reservoir thickness, m; K h is the vertical permeability of the oil reservoir, μm 2 ; L is the length of the horizontal section, m; ΔP is the bottom-hole pressure difference, 10 -1 MPa; r eh is the supply radius of the horizontal section, m; r w is the wellbore radius, m;

[0057] (5) When the daily oil production is less than the preset value of 2 - 5 m 3 , first inject a slug of viscosity reducer with an injection volume of 0.01 - 0.05 PV, and then alternately inject a small slug of gas and a foam-promoting system into the bottom hole with an injection volume of 0.01 - 0.03 PV and an injection amount of 0.2 - 0.3 PV, and soak the well for 20 - 30 days; the viscosity reducer includes naphtha and / or condensate, the gas includes any one or at least two combinations of CO2, N2, methane, natural gas, air, or water vapor, and the foam-promoting system includes a highly oil-resistant foaming agent with a concentration of 0.5 - 3 wt% and a foam stabilizer with a concentration of 0.1 - 1.5 wt%; the oil saturation resistance of the highly oil-resistant foaming agent is ≥ 40%, and the foaming height is ≥ 2 times;

[0058] (6) Open the well for production and control the daily liquid production volume within a preset range. The specific process is the same as that in step (4);

[0059] (7) Repeat steps (5) and (6) for at least 2 rounds of huff and puff production. When the oil production in a single round is less than the lower limit value, stop production; the lower limit value of the oil production in a single round is dynamically related to the oil price: when the calculated profit is 0, the corresponding oil production is the lower limit value of the oil production in a single round.

[0060] Among them, steps (5) and (6) continuously perform electric heating, and the power control method is the same as that in step (3).

[0061] Compared with the prior art, the present invention has the following beneficial effects:

[0062] The method provided by the present invention combines CO2 energy storage volume fracturing and electric heating-assisted natural depletion production, generating a large number of distributed fracture networks in the reservoir, significantly increasing the production during natural depletion; promoting the balanced utilization of the horizontal section through uniform electric heating of the horizontal section; accelerating the heat transfer and temperature rise of the oil layer by laying thermosensitive proppants in the fracturing fractures, improving the fluidity and production of crude oil; after natural depletion, electric heating-assisted huff and puff production is adopted. The injected foam oil triggering system expands the action range of the foam oil system in the reservoir, and electric heating significantly reduces the viscosity of crude oil near the wellbore and the flow resistance of the crude oil entering the well, improving the huff and puff production effect. The crude oil recovery rate is increased by 19 - 24% compared with the conventional natural depletion recovery rate. Description of the Drawings

[0063] Figure 1 It is a flow chart of the method for downhole electric heating to produce crude oil in a gas-bearing heavy oil reservoir provided by the present invention. Detailed Embodiments

[0064] The technical solutions of the present invention will be further described below through specific embodiments. Those skilled in the art should understand that the embodiments are only for helping to understand the present invention and should not be regarded as specific limitations on the present invention.

[0065] Embodiment 1

[0066] This embodiment provides a method for downhole electric heating to produce crude oil in a gas-bearing heavy oil reservoir. The conditions of the target gas-bearing heavy oil reservoir A are as follows: original gas-bearing reservoir, dissolved gas-oil ratio of 5m 3 / m 3 , oil layer thickness of 7m, oil saturation of 80%, porosity of 23%, and permeability of 500mD; horizontal well development is adopted, and the length of the horizontal section is 1000m, and the well spacing is 100m.

[0067] As Figure 1 shown, the method provided by this embodiment includes the following steps:

[0068] (1) Perform multi-stage and multi-cluster CO2 energy storage volume fracturing operations on the horizontal well in the gas-bearing heavy oil reservoir, with 2 clusters per stage and a length of 40m per stage, so that a hydraulic fracturing fracture network is evenly developed in the horizontal section; the specific process of the CO2 energy storage volume fracturing operation is as follows: inject liquid CO2 and preflush fluid into the gas-bearing heavy oil reservoir in sequence from the wellhead of the horizontal well to open the fractures; the injection volume of the liquid CO2 per unit length of the horizontal section is 1m 3 / m, the judgment criterion for the end of the injection of the preflush fluid is that the reservoir pressure reaches 10 MPa above the reservoir fracture pressure;

[0069] (2) Lay thermosensitive proppants in the horizontal section fracture obtained in step (1) to form a heat transfer network; the specific process of laying the thermosensitive proppants is as follows: inject the sand-carrying fluid and the displacement fluid into the reservoir in sequence, shut in the well for 40 days and then drain the fluid; the proppants in the sand-carrying fluid include a mixture of carbon fiber and ceramsite, and the ceramsite accounts for 50% of the mass of the proppants; the judgment criterion for the end of the injection of the displacement fluid is that the reservoir pressure reaches 20 MPa above the reservoir fracture pressure;

[0070] (3) Lower a constant-temperature heating cable into the horizontal section wellbore to electrically heat the horizontal section oil layer to reach a preset wellbore temperature of 100 °C; a temperature-measuring optical fiber is laid inside the constant-temperature heating cable to monitor the surface temperature of the heating cable in the horizontal section and feedback it to the ground power control cabinet for intelligent power adjustment, and the heating power per meter of the heating cable is 400 W;

[0071] (4) Open the well for production and control the daily liquid production volume within a preset range. The daily liquid production volume is set within a range based on a constant bottom-hole pressure difference, and the bottom-hole pressure difference is controlled at 1 MPa; the calculation formula for the maximum value of the daily liquid production volume is:

[0072]

[0073] In the formula, μ o (T) is the viscosity of the gas-containing heavy oil at 80 °C within 1 m near the electrically heated wellbore, 30 mPa·s; B o is the formation volume factor of the crude oil, 1.2, dimensionless; C w is the water cut, 0.27, dimensionless; h is the oil layer thickness, 7 m; K h is the vertical permeability of the oil layer, 0.5 μm 2 ; L is the length of the horizontal section, 1000 m; ΔP is the bottom-hole pressure difference, 1 MPa; r eh is the supply radius of the horizontal section, 50 m; r w is the wellbore radius, 0.0809 m;

[0074] Substitute the above parameters into the formula, and the calculated maximum value of the daily liquid production volume is 47.69 m 3 / d;

[0075] (5) When the daily oil production is less than 2 m 3When the preset value is reached, first inject a slug of naphtha viscosity reducer with an injection volume of 0.01 PV, and then alternately inject CO2 gas and foam triggering system into the bottom hole in small slugs of 0.01 PV, with an injection volume of 0.2 PV, and shut in the well for 20 days; the foam triggering system includes a high oil-resistant foaming agent with a concentration of 0.5 wt% and a foam stabilizer with a concentration of 0.1 wt%; the oil-resistant saturation of the high oil-resistant foaming agent is 45%, and the foaming height reaches 2.5 times;

[0076] (6) Open the well for production and control the daily liquid production within the preset range. The specific process is the same as that in step (4);

[0077] (7) Repeat steps (5) and (6) for at least 2 rounds of huff and puff production. When the oil production per round is less than the economic limit production of 500 m 3 stop production;

[0078] Among them, in steps (5) and (6), electric heating is continuously carried out, and the electric control method is the same as that in step (3).

[0079] After the crude oil is produced from the target gas-bearing heavy oil reservoir A in this embodiment, the statistical data shows that the ultimate crude oil recovery rate of the horizontal well in the target gas-bearing heavy oil reservoir A reaches 29%, which is 24% higher than the conventional natural depletion recovery rate.

[0080] Example 2

[0081] This embodiment provides a method for downhole electric heating to produce crude oil from a gas-bearing heavy oil reservoir. The conditions of the target gas-bearing heavy oil reservoir B are: original gas-bearing oil reservoir, dissolved gas-oil ratio of 5 m 3 / m 3 , oil layer thickness of 5 m, oil saturation of 80%, porosity of 23%, permeability of 800 mD; developed by horizontal well, and the horizontal section length is 1000 m, and the well spacing is 100 m.

[0082] As Figure 1 shown, the method provided in this embodiment includes the following steps:

[0083] (1) Perform multi-stage and multi-cluster CO2 energy storage volume fracturing operation on the horizontal well in the gas-bearing heavy oil reservoir, with 3 clusters per stage and each stage length of 60 m, so that a hydraulic fracturing fracture network is evenly developed in the horizontal section; the specific process of the CO2 energy storage volume fracturing operation is: inject liquid CO2 and preflush fluid into the gas-bearing heavy oil reservoir in sequence from the wellhead of the horizontal well to open the fracture; the injection volume of the liquid CO2 per unit length of the horizontal section is 2 m 3 / m, and the judgment criterion for the end of the preflush fluid injection is that the reservoir pressure reaches 7 MPa above the reservoir fracture pressure;

[0084] (2) Lay heat-sensitive proppants into the horizontal-section fracturing fractures obtained in step (1) to form a heat transfer network. The specific process of laying the heat-sensitive proppants is as follows: inject the sand-carrying fluid and the displacement fluid into the reservoir in sequence, shut in the well for 50 days and then drain the fluid. The proppants in the sand-carrying fluid include a mixture of silicon carbide and ceramsite, and the ceramsite accounts for 35% of the mass of the proppants. The judgment criterion for the end of the injection of the displacement fluid is that the reservoir pressure reaches 15 MPa above the reservoir fracture pressure.

[0085] (3) Lower a constant-temperature heating cable into the horizontal-section wellbore to electrically heat the horizontal-section oil layer to reach a preset wellbore temperature of 150 °C. A temperature-measuring optical fiber is laid inside the constant-temperature heating cable, which is used to monitor the surface temperature of the horizontal-section heating cable and feedback it to the ground power control cabinet for intelligent power adjustment. The heating power per meter of the heating cable is 1000 W.

[0086] (4) Open the well for production and control the daily liquid production volume within a preset range. The daily liquid production volume is set within a range based on a constant bottom-hole pressure difference, and the bottom-hole pressure difference is controlled at 2 MPa. The calculation formula for the maximum value of the daily liquid production volume is:

[0087]

[0088] In the formula, μ o (T) is the viscosity of the gas-containing heavy oil at 110 °C within 1 m near the electrically heated wellbore, which is 55 mPa·s; B o is the crude oil volume factor, which is 1.2, dimensionless; C w is the water cut, which is 0.27, dimensionless; h is the oil layer thickness, which is 5 m; K h is the vertical permeability of the oil layer, which is 0.8 μm 2 ; L is the length of the horizontal section, which is 1000 m; ΔP is the bottom-hole pressure difference, which is 2 MPa; r eh is the supply radius of the horizontal section, which is 50 m; r w is the wellbore radius, which is 0.0809 m;

[0089] Substitute the above parameters into the formula, and the calculated maximum value of the daily liquid production volume is 61.9 m 3 / d;

[0090] (5) When the daily oil production is less than the preset value of 3 m 3 , first inject a slug of condensate oil viscosity reducer with an injection volume of 0.03 PV, and then alternately inject N2 gas and a foam triggering system into the bottom hole in small slugs of 0.02 PV, with an injection volume of 0.25 PV, and shut in the well for 20 days. The foam triggering system includes a highly oil-resistant foaming agent with a concentration of 1 wt% and a foam stabilizer with a concentration of 1 wt%. The oil saturation resistance of the highly oil-resistant foaming agent is 50%, and the foaming height reaches 2.9 times.

[0091] (6) Open the well for production and control the daily liquid production within a preset range. The specific process is the same as that in step (4).

[0092] (7) Repeat steps (5) and (6) for at least two rounds of huff and puff production. When the oil production in a single round is less than the economic limit production of 600 m 3 , stop production.

[0093] Among them, steps (5) and (6) continuously perform electric heating, and the power control method is the same as that in step (3).

[0094] After the crude oil in the target gas-bearing heavy oil reservoir B is exploited in this embodiment, the statistical data shows that the ultimate crude oil recovery rate of the horizontal wells in the target gas-bearing heavy oil reservoir B reaches 24%, which is 19% higher than the conventional natural depletion recovery rate.

[0095] Example 3

[0096] This embodiment provides a method for downhole electric heating to exploit crude oil in a gas-bearing heavy oil reservoir. The conditions of the target gas-bearing heavy oil reservoir C are as follows: the original gas-bearing oil reservoir, the dissolved gas-oil ratio is 10 m 3 / m 3 , the oil layer thickness is 5 m, the oil saturation is 80%, the porosity is 28%, and the permeability is 200 mD; horizontal wells are used for development, and the horizontal section length is 1200 m, and the well spacing is 200 m.

[0097] As Figure 1 shown, the method provided in this embodiment includes the following steps:

[0098] (1) Perform multi-stage and multi-cluster CO2 energy storage volume fracturing operation on the horizontal wells in the gas-bearing heavy oil reservoir. Each stage has 3 clusters, and the length of each stage is 60 m, so that a hydraulic fracturing fracture network is evenly developed in the horizontal section; the specific process of the CO2 energy storage volume fracturing operation is as follows: inject liquid CO2 and preflush fluid into the gas-bearing heavy oil reservoir in sequence from the wellhead of the horizontal well to open the fractures; the injection volume of the liquid CO2 per unit length of the horizontal section is 3 m 3 / m, and the judgment criterion for the end of the preflush fluid injection is that the reservoir pressure reaches 10 MPa above the reservoir fracture pressure;

[0099] (2) Lay heat-sensitive proppants in the fracturing fractures of the horizontal section obtained in step (1) to form a heat transfer network; the specific process of laying the heat-sensitive proppants is as follows: inject sand-carrying fluid and displacement fluid into the reservoir in sequence, soak the well for 60 days and then drain the fluid; the proppants in the sand-carrying fluid include a mixture of alumina and ceramsite, and the ceramsite accounts for 25% of the mass of the proppants; the judgment criterion for the end of the displacement fluid injection is that the reservoir pressure reaches 20 MPa above the reservoir fracture pressure;

[0100] (3) Lower the constant-temperature heating cable into the horizontal section of the wellbore to electrically heat the reservoir in the horizontal section to reach the preset wellbore temperature of 250 °C. A temperature-measuring optical fiber is laid inside the constant-temperature heating cable to monitor the surface temperature of the heating cable in the horizontal section and feed it back to the ground power control cabinet for intelligent power adjustment. The heating power per meter of the heating cable is 2500 W.

[0101] (4) Open the well for production and control the daily liquid production volume within the preset range. The daily liquid production volume is set within a range based on a constant bottom-hole pressure difference, and the bottom-hole pressure difference is controlled at 0.5 MPa. The formula for calculating the maximum value of the daily liquid production volume is:

[0102]

[0103] where μ o (T) is the viscosity of the gas-containing heavy oil at 200 °C within 1 m near the electrically heated wellbore, 41 mPa·s; B o is the formation volume factor of the crude oil, 1.2, dimensionless; C w is the water cut, 0.27, dimensionless; h is the reservoir thickness, 5 m; K h is the vertical permeability of the reservoir, 0.2 μm 2 ; L is the length of the horizontal section, 1200 m; ΔP is the bottom-hole pressure difference, 0.5 MPa; r eh is the supply radius of the horizontal section, 100 m; r w is the wellbore radius, 0.0809 m.

[0104] Substitute the above parameters into the formula, and the calculated maximum value of the daily liquid production volume is 32.23 m 3 / d.

[0105] (5) When the daily oil production is less than the preset value of 5 m 3 , first inject a viscosity reducer slug of an equal-volume mixture of naphtha and condensate with an injection volume of 0.05 PV, and then alternately inject methane gas and a foam-promoting system into the bottom hole in small slugs of 0.03 PV with a total injection volume of 0.3 PV, and soak the well for 30 days. The foam-promoting system includes a highly oil-resistant foaming agent with a concentration of 3 wt% and a foam stabilizer with a concentration of 1.5 wt%. The oil saturation resistance of the highly oil-resistant foaming agent is 50%, and the foaming height reaches 3 times.

[0106] (6) Open the well for production and control the daily liquid production volume within the preset range. The specific process is the same as that in step (4).

[0107] (7) Repeat steps (5) and (6) for at least 2 rounds of huff and puff production. When the oil production in a single round is less than the economic limit production of 700 m 3 , stop production.

[0108] Among them, steps (5) and (6) continuously perform electric heating, and the power control method is the same as that in step (3).

[0109] After the crude oil is exploited from the target gas-bearing heavy oil reservoir C in this embodiment, the statistical data shows that the ultimate crude oil recovery rate of the horizontal wells in the target gas-bearing heavy oil reservoir C has reached 26%, which is 20% higher than the conventional natural depletion recovery rate.

[0110] Comparative Example 1

[0111] This comparative example provides a method for downhole electric heating to exploit crude oil from a gas-bearing heavy oil reservoir. In this method, except for removing steps (1) and (2), that is, simply performing electric heating to assist natural depletion production, the rest of the steps and conditions are the same as those in Example 1, so they will not be elaborated here.

[0112] After the crude oil is exploited from the target gas-bearing heavy oil reservoir A in this comparative example, the statistical data shows that the ultimate crude oil recovery rate of the horizontal wells in the target gas-bearing heavy oil reservoir A is only 5%, far lower than 29% in Example 1.

[0113] Thus, it can be seen that the method provided by the present invention combines CO2 energy storage volume fracturing and electric heating-assisted natural depletion production, generates a large number of distributed fracture networks in the reservoir, and greatly improves the production during natural depletion; promotes the balanced utilization of the horizontal section through uniform electric heating in the horizontal section; accelerates the heat transfer and temperature rise of the oil layer by laying thermosensitive proppants in the fracturing fractures, improving the fluidity and production of crude oil; after natural depletion, it adopts the method of electric heating-assisted huff and puff production. The injected foam oil triggering system expands the action range of the foam oil system in the oil layer, and electric heating greatly reduces the viscosity of the crude oil near the wellbore and the flow resistance of the crude oil entering the well, improving the huff and puff production effect. The crude oil recovery rate is 19 - 24% higher than the conventional natural depletion recovery rate.

[0114] The applicant declares that the above description is only the specific implementation manner of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily thought of by those skilled in the art within the technical scope disclosed by the present invention fall within the protection scope and the disclosure scope of the present invention.

Claims

1. A method for downhole electrical heating to extract crude oil from a gas-bearing heavy oil reservoir, characterized in that, The method comprises the following steps: (1) Conduct CO2 energy storage volume fracturing operation on the horizontal well in the gas-bearing heavy oil reservoir, so that a hydraulic fracturing fracture network is evenly developed in the horizontal section; (2) Lay heat-sensitive proppants in the fracturing fractures of the horizontal section obtained in step (1) to form a heat transfer network; the specific process of laying the heat-sensitive proppants is as follows: successively inject sand-carrying fluid and displacement fluid into the reservoir, soak the well for 40 - 60 days and then drain the fluid; the proppants in the sand-carrying fluid include a mixture of any one or at least two combinations of carbon fiber, alumina, magnesia, zinc oxide, aluminum nitride, boron nitride or silicon carbide and ceramsite, and the ceramsite accounts for 25 - 50% of the mass of the proppants; the judgment criterion for the end of the injection of the displacement fluid is that the reservoir pressure reaches 10 - 20 MPa above the reservoir fracture pressure; (3) Lower a heating cable into the horizontal section wellbore to electrically heat the oil layer in the horizontal section to reach a preset wellbore temperature; (4) Open the well for production and control the daily liquid production volume within a preset range; When the daily oil production is less than the preset value of 2-5 m 3 , first inject a viscosity reducer slug with an injection volume of 0.01-0.05 PV, and then alternately inject a small slug of gas and foam triggering system into the bottom of the well at 0.01-0.03 PV, with an injection volume of 0.2-0.3 PV, and shut in the well for 20-30 days; the viscosity reducer includes naphtha and / or condensate, the gas includes any one or a combination of at least two of CO2, N2, methane, natural gas, air or steam, and the foam triggering system includes a high oil-resistant foaming agent with a concentration of 0.5-3 wt% and a foam stabilizer with a concentration of 0.1-1.5 wt%; the oil-resistant saturation of the high oil-resistant foaming agent is ≥40%, and the foaming height is ≥2 times; (6) Open the well for production and control the daily liquid production volume within a preset range; (7) Repeat steps (5) and (6) to carry out at least 2 rounds of huff and puff production. When the oil production volume in a single round is less than the lower limit value, stop production; Among them, steps (5) and (6) continuously carry out electrical heating, and the power control method is the same as that in step (3); The calculation formula for the maximum value of the daily liquid production volume described in steps (4) and (6) is: ； Wherein, is the viscosity of gas-containing heavy oil within 1 m near the electrically heated wellbore, mPa·s; is the formation volume factor of crude oil, dimensionless; is the water cut, dimensionless; is the reservoir thickness, m; is the vertical permeability of the reservoir, μm 2 ; is the length of the horizontal section, m; is the bottom-hole pressure differential, 10 -1 MPa; is the supply radius of the horizontal section, m; is the wellbore radius, m.

2. The method according to claim 1, wherein The CO2 energy storage volume fracturing operation described in step (1) is carried out in multiple segments and multiple clusters on the horizontal well, with 2 - 3 clusters in each segment and the length of each segment being 40 - 60 m.

3. The method according to claim 1, wherein The specific process of the CO2 energy storage volume fracturing operation described in step (1) is: successively inject liquid CO2 and preflush fluid from the wellhead of the horizontal well into the gas-bearing heavy oil reservoir to open the fractures.

4. The method according to claim 3, characterized in that, The injection amount of the liquid CO2 per unit length of the horizontal section is 1-3 m 3 / m.

5. The method according to claim 3, wherein The judgment criterion for the end of the injection of the preflush fluid is that the reservoir pressure reaches 5 - 10 MPa above the reservoir fracture pressure.

6. The method according to claim 1, characterized in that, The heating cable described in step (3) is a constant temperature heating cable.

7. The method according to claim 6, characterized in that, A temperature measurement optical fiber is laid inside the constant temperature heating cable.

8. The method according to claim 6, characterized in that The heating power per meter of the constant temperature heating cable is 400 - 2500 W.

9. The method according to claim 1, wherein The preset wellbore temperature described in step (3) is 100 - 250 °C.

10. The method according to claim 1, wherein The daily liquid production volume described in steps (4) and (6) is set within a range based on a constant bottom hole pressure difference.

11. The method according to claim 10, wherein The bottom hole pressure difference is controlled at 0.5 - 3 MPa.

12. The method according to claim 1, wherein The lower limit value of the oil production volume in a single round described in step (7) is dynamically related to the oil price: when the calculated profit is 0, the corresponding oil production volume is the lower limit value of the oil production volume in a single round.

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