A method for recovering crude oil from a gas-containing heavy oil reservoir

Abstract

This invention relates to the field of crude oil extraction technology, specifically to a method for extracting crude oil from gas-bearing heavy oil reservoirs. The method includes CO2 composite medium energy storage volumetric fracturing combined with electrically heated assisted natural depletion production in the gas-bearing heavy oil reservoir. This generates a large number of distributed volumetric fracture networks within the reservoir, significantly increasing production during natural depletion. After natural depletion production ends, viscosity reducers, gas, and foam promoters are injected into the reservoir in multiple rounds of huff and puff to form secondary foam oil, significantly improving huff and puff production and recovery rate after natural depletion.

Description

Technical Field

[0001] This invention relates to the field of crude oil extraction technology, and more specifically to a method for extracting crude oil from gas-bearing heavy oil reservoirs. Background Technology

[0002] Gas-bearing heavy oil reservoirs refer to heavy oil reservoirs that naturally contain dissolved gas. During natural depletion cold production, as the reservoir pressure decreases, the dissolved gas separates from the crude oil, thus forming dissolved gas drive. However, given the rapid increase in crude oil viscosity after degassing in gas-bearing heavy oil reservoirs, the recovery rate of natural energy depletion cold production is extremely low. Furthermore, the viscosity of degassed crude oil is typically as high as 1000–50000 mPa·s, resulting in extremely high flow resistance and making it difficult for injected fluids to penetrate deep into the reservoir, leading to poor development results. Therefore, how to improve the recovery rate of gas-bearing heavy oil reservoirs is an urgent technical challenge that needs to be addressed. Summary of the Invention

[0003] The purpose of this invention is to overcome the shortcomings of existing technologies and provide a crude oil extraction method for gas-bearing heavy oil reservoirs with high recovery rates, solving the technical problems of efficient development and enhanced oil recovery in mid-deep gas-bearing, high-viscosity oil reservoirs. The crude oil extraction method for gas-bearing heavy oil reservoirs provided by this invention involves CO2-storage volumetric fracturing combined with electrically heated assisted natural depletion production. This generates a large number of distributed volumetric fracture networks in the reservoir, significantly increasing production during natural depletion. Uniform heating of the horizontal section promotes balanced utilization of that section; high thermal conductivity proppant accelerates heat transfer and temperature rise in the reservoir; controlling the degassing rate by adjusting the discharge rate and production pressure differential slows down degassing, prolongs the gas's presence time in the crude oil, and improves crude oil fluidity and production; after natural depletion, electrically heated assisted huff and puff production is employed. The injected foam oil initiation system increases the effective range of the foam oil system in the reservoir, while electrical heating significantly reduces the viscosity of crude oil near the wellbore and the flow resistance of the injected crude oil, improving huff and puff production efficiency and thus increasing crude oil recovery.

[0004] This invention is achieved through the following technical solutions:

[0005] A method for extracting crude oil from a gas-bearing heavy oil reservoir includes the following steps:

[0006] (1) Perform fracturing operations on horizontal wells in gas-bearing heavy oil reservoirs to form a network of fracturing fractures;

[0007] (2) Lay heat-sensitive proppant into the horizontal section of the hydraulic fracturing fracture to form a heat transfer network;

[0008] (3) A heating cable is run into the horizontal section of the wellbore to electrically heat the oil layer in the horizontal section and reach the preset wellbore temperature;

[0009] (4) Open wells for recovery and control the daily fluid production to exceed the preset value;

[0010] (5) When the daily oil production reaches below the preset value, inject viscosity reducer, gas and foaming system into the bottom of the well;

[0011] (6) Stop injection and shut down the well;

[0012] (7) Open wells for recovery and control the daily fluid production to exceed the preset value;

[0013] (8) Repeat steps (5) to (7) to carry out multiple rounds of throughput production. When the daily oil production of a single round cannot reach the preset value, stop production.

[0014] Preferably, in step (1), a multi-stage, multi-cluster CO2 composite medium energy storage volume fracturing operation is performed on the horizontal well in the gas-bearing heavy oil reservoir to make the horizontal section uniformly develop a hydraulic fracturing fracture network.

[0015] More preferably, the multi-segment, multi-cluster CO2 composite medium energy storage volumetric fracturing operation in step (1) includes:

[0016] The horizontal section is fractured in stages from the tip to the heel, with 2 to 3 clusters per section and a distance of 40 to 60 meters between each section. Liquid CO2 composite medium is injected into the gas-bearing heavy oil reservoir from the horizontal wellhead, followed by the injection of pre-fracturing fluid to open the fractures.

[0017] More preferably, the liquid CO2 composite medium is a mixture of CO2, non-condensable gas, dimethyl ether, and additives.

[0018] More preferably, the non-condensable gas includes one or more of flue gas, N2, methane, and air.

[0019] More preferably, the volume ratio of CO2 to non-condensable gas under standard conditions is 10:1 to 1:1.

[0020] More preferably, the auxiliary agent is ethanol with a mass concentration of 10%-90%.

[0021] More preferably, the volume ratio of the dimethyl ether to the auxiliary agent is 5:1 to 9:1.

[0022] More preferably, the volume ratio of CO2 to dimethyl ether is 90:10 to 99:1.

[0023] More preferably, in step (1), the injection volume of CO2 composite medium per unit length of horizontal section under underground temperature and pressure conditions is 1-3 m³. 3 / m; the criterion for the completion of the pre-fluid injection is reaching 5-10 MPa above the reservoir fracture pressure.

[0024] More preferably, the pretreatment solution is a combination of slippery water and hydrochloric acid in a mass ratio of 5:1 to 9:1, and the hydrochloric acid mass concentration is 25-50%.

[0025] Preferably, the heat-sensitive proppant in step (2) includes a sand-carrying liquid.

[0026] More preferably, the sand-carrying liquid comprises a mixture of at least one of carbon fiber, alumina, magnesium oxide, zinc oxide, aluminum nitride, boron nitride, and silicon carbide with ceramsite.

[0027] More preferably, the mass ratio of at least one of carbon fiber, alumina, magnesium oxide, zinc oxide, aluminum nitride, boron nitride and silicon carbide to ceramsite is 1:1 to 3:1.

[0028] Preferably, in step (2), after laying the heat-sensitive proppant into the horizontal section of the fracturing fracture, the displacement fluid is injected into the reservoir until the reservoir pressure reaches a preset value, which is 10-20 MPa above the reservoir fracturing pressure. After the injection is completed, the well is shut in for 40-60 days before the fluid is drained.

[0029] More preferably, the displacement fluid is thickened water with a viscosity of 20-50 mPa·s at 50°C.

[0030] Preferably, the heating cable in step (3) is a constant temperature heating cable with a surface temperature of 100-250°C.

[0031] More preferably, in step (3), a temperature-measuring optical fiber is laid inside the heating cable to monitor the surface temperature of the horizontal section of the heating cable and feed it back to the ground control cabinet for intelligent power adjustment; the heating power per meter is 400-2500W and the surface temperature is 100-250℃.

[0032] Preferably, the preset wellbore temperature in step (3) is 100-250°C.

[0033] The preset value of daily liquid production in step (4) is determined based on a constant bottom hole pressure differential.

[0034] To limit excessive degassing, the bottom hole pressure differential is controlled between 1 and 3 MPa; the preset value for daily fluid production is calculated using the following formula:

[0035]

[0036] Where μ o (T) represents the viscosity of gas-bearing crude oil within a 1-meter radius of the electrically heated wellbore, in mPa·s; it is related to the heating temperature, and the gas-bearing viscosity at different temperatures is obtained by testing with a surface rheometer.

[0037] B o This is the crude oil volume coefficient, dimensionless;

[0038] C w The value represents the moisture content, which is dimensionless.

[0039] h is the oil layer thickness, in meters;

[0040] K h The vertical permeability of the oil reservoir is expressed in μm. 2 ;

[0041] L is the length of the horizontal segment, in meters;

[0042] ΔP is the bottom hole pressure difference, 10 -1 MPa;

[0043] r eh Provide the radius, in meters, for the horizontal segment;

[0044] r w Let be the radius of the wellbore, in meters (m).

[0045] More preferably, the bottom hole pressure difference ΔP is 1–3 MPa.

[0046] Preferably, the preset value for daily oil production in step (5) is 2-5 m³. 3 / d.

[0047] Preferably, the viscosity reducer in step (5) is an oil-soluble viscosity reducer.

[0048] More preferably, the viscosity reducer is a composition of one or more oil-soluble viscosity reducers.

[0049] More preferably, the viscosity reducer includes at least one of diesel oil, naphtha, and condensate oil.

[0050] Preferably, the gas in step (5) includes one or more of CO2, N2, methane, flue gas, natural gas, LNG, air, and water vapor.

[0051] Preferably, the foam-inducing system in step (5) consists of a foaming agent and a foam stabilizer, wherein the concentration of the foaming agent is 0.5-3 wt% and the concentration of the foam stabilizer is 0.1-1.5 wt%.

[0052] More preferably, the foaming agent is a high oil-resistant foaming agent with an oil saturation of over 40% and a foaming height of over 2 times.

[0053] Preferably, the injection method in step (5) is to first inject a viscosity reducer slug with an injection amount of 0.01 to 0.05 PV, and then inject the gas and foam activating system alternately with small slugs of 0.01 to 0.03 PV, with a total injection amount of 0.2 to 0.3 PV for the gas and foam activating system.

[0054] Preferably, during steps (4) to (7), electric heating continues, the power control method is the same as in step (3), and the cable surface temperature is the same as in step (3).

[0055] The method for controlling the daily liquid production in step (7) is the same as that in step (4).

[0056] The lower limit of daily oil production in each cycle of step (8) is dynamically related to the oil price. When the calculated profit is 0, the corresponding oil production is the lower limit of daily oil production for that well's throughput cycle.

[0057] The beneficial effects of this invention are:

[0058] This invention deploys horizontal wells in gas-bearing heavy oil reservoirs, performs CO2 composite medium energy storage volumetric fracturing, and runs heating cables into the horizontal section of the wellbore to carry out electrically heated assisted natural depletion production. Preliminary evaluations show that it increases production by 1.2 times and improves natural depletion recovery rate by 4.3% compared to conventional natural depletion production. After natural depletion production is completed, viscosity reducers, gas, and foam promoters are injected into the reservoir for multiple rounds of electrically heated assisted huff and puff to form secondary foam oil, which significantly improves huff and puff production and recovery rate after natural depletion.

[0059] Adding composite media to CO2 for energy storage volumetric fracturing can effectively overcome the defect that pure CO2 is difficult to vaporize during fracturing and flowback. By injecting composite media, CO2 can be vaporized and allowed to penetrate deep into the formation. Furthermore, during the recovery process, the compressibility of the gas can accumulate elastic energy, improve the fracturing effect, and extend the time of depletion recovery.

[0060] Adding non-condensable gas, dimethyl ether, and additives to a liquid CO2 composite medium can significantly improve its miscibility, as dimethyl ether is completely soluble in both water and liquid CO2. This miscible multi-component composite medium can achieve unexpected effects compared to single-component media, enhancing fracturing efficiency and post-fracturing depletion production. Attached Figure Description

[0061] Figure 1 This is a schematic flowchart of the crude oil extraction method for gas-bearing heavy oil reservoirs provided by the present invention. Detailed Implementation

[0062] The present invention will be further described below with reference to specific embodiments, and the advantages and features of the present invention will become clearer as a result. However, these embodiments are merely exemplary and do not constitute any limitation on the scope of the present invention. Those skilled in the art should understand that modifications or substitutions can be made to the details and form of the technical solutions of the present invention without departing from the spirit and scope of the present invention, but all such modifications and substitutions fall within the protection scope of the present invention.

[0063] The pretreatment liquid used in step (2) of each embodiment of the present invention is a combination of slippery water (Xinxiang Jinghong Chemical, JH113) and 25% hydrochloric acid, with a mass ratio of 7:1.

[0064] The displacement liquid used in step (2) of each embodiment of the present invention is thickened water with a viscosity of 35 mPa·s at 50°C.

[0065] The foaming agent used in step (5) of each embodiment of the present invention is a combination of AES (general type) and fluorocarbon surfactant (3M Company, model FS500) in a mass ratio of 95:5; the foam stabilizer is a combination of 30wt% carbomer + 30wt% dodecanol + 40wt% xanthan gum.

[0066] Example 1

[0067] The purpose of this invention is to provide a method for extracting crude oil from gas-bearing heavy oil reservoirs. This method can generate a volumetric fracture network in the oil layer, significantly reduce the flow resistance of crude oil into the well, achieve uniform crude oil production in the horizontal section through electric heating, and improve production and recovery rate through huff and puff.

[0068] The crude oil extraction method for gas-bearing heavy oil reservoirs provided in Embodiment 1 of this invention is for heavy oil reservoirs that meet the following conditions:

[0069] (1) Original gas-bearing oil reservoir with a dissolved gas-oil ratio of 5m 3 / m 3 ;

[0070] (2) The oil layer thickness is 7m, the oil saturation is 80%, the porosity is 23%, and the permeability is 500 millidarcy;

[0071] (3) Horizontal well development is adopted, with a horizontal section length of 1000m and a well spacing of 100m.

[0072] A schematic flowchart of the crude oil extraction method for gas-bearing heavy oil reservoirs provided in Embodiment 1 of the present invention is shown below. Figure 1 As shown in the embodiment of the present invention, the crude oil extraction method for gas-bearing heavy oil reservoirs includes:

[0073] (1) Perform multi-stage, multi-cluster CO2 composite medium energy storage volume fracturing operation on horizontal wells in gas-bearing heavy oil reservoirs to make the horizontal section uniformly develop hydraulic fracturing fracture network.

[0074] The fracturing process proceeds in stages from the tip to the heel of the horizontal section, with two clusters per section and a distance of 40 meters between each section. A CO2 composite medium, composed of liquid CO2, non-condensable N2, dimethyl ether, and additives, is injected into the gas-bearing heavy oil reservoir through the horizontal wellhead. The volume ratio of CO2 to N2 under standard conditions is 10:1. The additive is ethanol with a mass concentration of 90%. The volume ratio of dimethyl ether to the additive is 9:1; the volume ratio of CO2 to dimethyl ether is 90:10. Then, a pre-fracturing fluid is injected to open the fractures.

[0075] The CO2 composite medium injection volume per unit length horizontal segment is 1m. 3 (Subsurface volume) / m; The criterion for the completion of pre-flush injection is reaching 10MPa above the reservoir fracture pressure;

[0076] (2) Lay heat-sensitive proppant into the horizontal section of the hydraulic fracturing fracture to form a heat transfer network;

[0077] The heat-sensitive proppant is a mixture of carbon fiber and ceramic particles, which has high thermal conductivity, with a mass ratio of 1:1.

[0078] After laying heat-sensitive proppant into the horizontal fracture zone, displacement fluid is injected into the reservoir until the reservoir pressure reaches a preset value, which is 20 MPa above the reservoir fracture pressure. After injection, the well is shut in for 40 days before fluid discharge begins.

[0079] (3) Run heating cables into the horizontal section of the wellbore to electrically heat the oil layer in the horizontal section and reach the preset wellbore temperature of 100℃;

[0080] The heating cable is a constant temperature heating cable with a temperature-measuring optical fiber laid inside to monitor the surface temperature of the horizontal section of the heating cable and feed it back to the ground control cabinet for intelligent power adjustment; the heating power per meter is 400W; the surface temperature is 100℃.

[0081] (4) Open wells for recovery and control the daily fluid production to exceed the preset value;

[0082] The preset value for the daily fluid production during well opening and recovery is determined based on a constant bottom hole pressure differential.

[0083] To limit excessive degassing, the bottom hole pressure differential is controlled at 1 MPa; the preset value for daily fluid production is calculated using the following formula:

[0084]

[0085] Where μ o(T) represents the viscosity of gas-bearing crude oil within 1 meter of the electrically heated wellbore, which is related to the heating temperature. The viscosity of gas-bearing crude oil at different temperatures was tested by a ground rheometer and found to be 30 mPa·s at 80°C within 1 meter of the wellbore.

[0086] B o The crude oil volume coefficient is 1.2, dimensionless;

[0087] C w The moisture content is 0.27, dimensionless;

[0088] h represents the oil layer thickness, which is 7m.

[0089] K h The vertical permeability of the oil reservoir is 0.5 μm. 2 ;

[0090] L is the length of the horizontal section, 1000m;

[0091] ΔP is the bottom hole pressure difference, 1 MPa;

[0092] r eh The radius for the horizontal section is 50m;

[0093] r w The radius of the wellbore is 0.0809m.

[0094] Substituting the above parameters into the above formula, the daily liquid production is calculated to be 47.69 m³. 3 / d.

[0095] (5) When the daily oil production reaches below the preset value, inject viscosity reducer, gas and foaming system into the bottom of the well;

[0096] The preset daily oil production value is 2m. 3 / d; The viscosity reducer is naphtha; The gas is CO2; The foaming system is composed of a high oil-resistant (oil saturation reaches 45%, foaming height reaches 2.5 times) foaming agent and a foam stabilizer, wherein the foaming agent concentration is 0.5% and the foam stabilizer concentration is 0.1%; The injection method is as follows: first, the viscosity reducer slug is injected at a volume of 0.01 PV, and then the gas and foaming system are injected alternately with 0.01 PV small slugs, with a total injection volume of 0.2 PV for the gas and foaming system;

[0097] (6) Stop injection and shut the well for 20 days;

[0098] (7) Open the well and recover the fluid and control the daily fluid production to exceed the preset value; the method for controlling the daily fluid production is the same as step (4);

[0099] (8) Repeat steps (5) to (7) to perform multiple rounds of throughput production. When the oil production of a single round cannot reach the economic limit of 500m³, 3 Production will cease at that time.

[0100] During steps (4) to (7), electric heating continues, and the power control method is the same as in step (3).

[0101] After implementing the crude oil extraction method for gas-bearing heavy oil reservoirs provided in this embodiment of the invention on target heavy oil reservoir A, statistical data shows that the final crude oil recovery rate of the horizontal wells in target heavy oil reservoir A reached 29%, which is 24% higher than the recovery rate of conventional natural depletion. The crude oil extraction method for gas-bearing heavy oil reservoirs provided in this embodiment of the invention improves the recovery rate of target heavy oil reservoir A.

[0102] Example 2

[0103] The purpose of this invention is to provide a method for extracting crude oil from gas-bearing heavy oil reservoirs. This method can generate a volumetric fracture network in the oil layer, significantly reduce the flow resistance of crude oil into the well, achieve uniform crude oil production in the horizontal section through electric heating, and improve production and recovery rate through huff and puff.

[0104] The crude oil extraction method for gas-bearing heavy oil reservoirs provided in Embodiment 2 of the present invention is for heavy oil reservoirs that meet the following conditions:

[0105] (1) Original gas-bearing oil reservoir with a dissolved gas-oil ratio of 5m 3 / m 3 ;

[0106] (2) The oil layer thickness is 5m, the oil saturation is 80%, the porosity is 23%, and the permeability is 800 millidarcy;

[0107] (3) Horizontal well development is adopted, with a horizontal section length of 1000m and a well spacing of 100m.

[0108] The crude oil extraction method for gas-bearing heavy oil reservoirs provided in Embodiment 2 of the present invention includes:

[0109] (1) Perform multi-stage, multi-cluster CO2 composite medium energy storage volume fracturing operation on horizontal wells in gas-bearing heavy oil reservoirs to make the horizontal section uniformly develop hydraulic fracturing fracture network.

[0110] The fracturing process proceeds in stages from the tip to the heel of the horizontal section, with three clusters per section and a distance of 60 meters between each section. A liquid CO2 composite medium is injected into the gas-bearing heavy oil reservoir through the horizontal wellhead. This CO2 composite medium is a composition of liquid CO2, non-condensable gas, dimethyl ether, and additives. The non-condensable gas is methane. The volume ratio of CO2 to non-condensable gas under standard conditions is 5:1. The additive is ethanol with a mass concentration of 90%. The volume ratio of dimethyl ether to the additive is 5:1. Under the specified underground temperature and pressure conditions, the volume ratio of CO2 to dimethyl ether is 90:10. Then, a pre-fracturing fluid is injected to open the fractures.

[0111] The CO2 composite medium injection volume per unit length horizontal segment is 2m. 3 (Subsurface volume) / m; The criterion for the completion of pre-flush injection is reaching a pressure 7 MPa above the reservoir fracture pressure;

[0112] (2) Lay heat-sensitive proppant into the horizontal section of the hydraulic fracturing fracture to form a heat transfer network;

[0113] The heat-sensitive proppant has excellent thermal conductivity and heat transfer properties; it is a mixture of silicon carbide and ceramic particles, which has high thermal conductivity, with a mass ratio of 2:1.

[0114] After laying heat-sensitive proppant into the horizontal fracture zone, displacement fluid is injected into the reservoir until the reservoir pressure reaches a preset value, which is 15 MPa above the reservoir fracture pressure. After injection, the well is shut in for 50 days before fluid discharge begins.

[0115] (3) A heating cable is run into the horizontal section of the wellbore to electrically heat the oil layer in the horizontal section and reach the preset wellbore temperature of 150°C.

[0116] Furthermore, the heating cable in step (3) is a constant temperature heating cable with a temperature measuring optical fiber laid inside to monitor the surface temperature of the horizontal section of the heating cable and feed it back to the ground control cabinet for intelligent power adjustment; the heating power per meter is 1000W; the surface temperature is 150℃.

[0117] (4) Open wells for recovery and control the daily fluid production to exceed the preset value;

[0118] The preset value for the daily fluid production during well opening and recovery is determined based on a constant bottom hole pressure differential.

[0119] To limit excessive degassing, the bottom hole pressure differential is controlled at 2 MPa; the preset value for daily fluid production is calculated using the following formula:

[0120]

[0121] Where μ o(T) represents the viscosity of gas-bearing crude oil within 1 meter of the electrically heated wellbore, which is related to the heating temperature. The viscosity of gas-bearing crude oil at different temperatures was tested by a ground rheometer and found to be 55 mPa·s at 110°C within 1 meter of the wellbore.

[0122] B o The crude oil volume coefficient is 1.2, dimensionless;

[0123] C w The moisture content is 0.27, dimensionless;

[0124] h represents the oil layer thickness, which is 5m.

[0125] K h The vertical permeability of the oil reservoir is 0.8 μm. 2 ;

[0126] L is the length of the horizontal section, 1000m;

[0127] ΔP is the bottom hole pressure difference, 2 MPa;

[0128] r eh The radius for the horizontal section is 50m;

[0129] r w The radius of the wellbore is 0.0809m.

[0130] Substituting the above parameters into the above formula, the daily liquid production is calculated to be 61.9 m³. 3 / d.

[0131] (5) When the daily oil production reaches below the preset value, inject viscosity reducer, gas and foaming system into the bottom of the well;

[0132] The preset daily oil production value is 3m³. 3 / d; the viscosity reducer is condensate oil; the gas is N2; the foaming system is composed of a high oil-resistant (oil saturation reaches 50%, foaming height reaches 2.9 times) foaming agent and a foam stabilizer, wherein the foaming agent concentration is 1% and the foam stabilizer concentration is 1%; the injection method is to first inject the viscosity reducer slug at a volume of 0.03 PV, and then alternately inject the gas and foaming system with small slugs of 0.02 PV, the total injection volume of the gas and foaming system is 0.25 PV;

[0133] (6) Stop injection and shut the well for 20 days;

[0134] (7) Open the well and recover the fluid and control the daily fluid production to exceed the preset value; the method for controlling the daily fluid production is the same as step (4);

[0135] (8) Repeat steps (5) to (7) to perform multiple rounds of throughput production. When the oil production of a single round cannot reach the preset lower limit of 600m³, 3 Production will cease at that time.

[0136] During steps (4) to (7), electric heating continues, and the power control method is the same as in step (3).

[0137] After implementing the crude oil extraction method for gas-bearing heavy oil reservoirs provided in this embodiment of the invention on target heavy oil reservoir B, statistical data shows that the final crude oil recovery rate of the horizontal wells in target heavy oil reservoir B increased by 19% compared to conventional natural depletion, reaching 24%. The crude oil extraction method for gas-bearing heavy oil reservoirs provided in this embodiment of the invention improves the recovery rate of target heavy oil reservoir B.

[0138] Example 3

[0139] The purpose of this invention is to provide a method for extracting crude oil from gas-bearing heavy oil reservoirs. This method can generate a volumetric fracture network in the oil layer, significantly reduce the flow resistance of crude oil into the well, achieve uniform crude oil production in the horizontal section through electric heating, and improve production and recovery rate through huff and puff.

[0140] The crude oil extraction method for gas-bearing heavy oil reservoirs provided in Embodiment 3 of this invention is for heavy oil reservoirs that meet the following conditions:

[0141] (1) Original gas-bearing oil reservoir with a dissolved gas-oil ratio of 10m 3 / m 3 ;

[0142] (2) The oil layer thickness is 5m, the oil saturation is 80%, the porosity is 28%, and the permeability is 200 Darcy;

[0143] (3) Horizontal well development is adopted, with a horizontal section length of 1200m and a well spacing of 200m.

[0144] The crude oil extraction method for gas-bearing heavy oil reservoirs provided in Embodiment 3 of the present invention includes:

[0145] (1) Perform multi-stage, multi-cluster CO2 composite medium energy storage volume fracturing operation on horizontal wells in gas-bearing heavy oil reservoirs to make the horizontal section uniformly develop hydraulic fracturing fracture network.

[0146] The fracturing process proceeds in stages from the tip to the heel of the horizontal section, with three clusters per section and a distance of 60m between each section. A CO2 composite medium is injected into the gas-bearing heavy oil reservoir through the horizontal wellhead. This CO2 composite medium consists of liquid CO2, non-condensable gas, dimethyl ether, and its additives. The non-condensable gas is flue gas. The volume ratio of CO2 to non-condensable gas under standard conditions is 1:1. The additive is ethanol with a mass concentration of 10%. The volume ratio of dimethyl ether to the additive is 5:1. Under the specified underground temperature and pressure conditions, the volume ratio of CO2 to dimethyl ether is 99:1. Then, a pre-fracturing fluid is injected to open the fractures.

[0147] The CO2 injection volume per unit length horizontal segment is 3m³. 3 (Subsurface volume) / m; The criterion for the completion of pre-flush injection is reaching 10MPa above the reservoir fracture pressure;

[0148] (2) Lay heat-sensitive proppant into the horizontal section of the hydraulic fracturing fracture to form a heat transfer network;

[0149] The heat-sensitive proppant is a mixture of alumina and ceramsite, which has high thermal conductivity, with a mass ratio of 3:1.

[0150] After laying heat-sensitive proppant into the horizontal fracture zone, displacement fluid is injected into the reservoir until the reservoir pressure reaches a preset value, which is 20 MPa above the reservoir fracture pressure. After injection, the well is shut in for 60 days before fluid discharge begins.

[0151] (3) Run heating cables into the horizontal section of the wellbore to electrically heat the oil layer in the horizontal section and reach the preset wellbore temperature of 250℃;

[0152] The heating cable is a constant temperature heating cable with a temperature-sensing optical fiber laid inside to monitor the surface temperature of the horizontal section of the heating cable and feed it back to the ground control cabinet for intelligent power adjustment; the heating power per meter is 2500W; the surface temperature is 250℃.

[0153] (4) Open wells for recovery and control the daily fluid production to exceed the preset value;

[0154] The preset value for the daily fluid production during well opening and recovery is determined based on a constant bottom hole pressure differential.

[0155] To limit excessive degassing, the bottom hole pressure differential is controlled at 0.5 MPa; the preset value for daily fluid production is calculated according to the following formula:

[0156]

[0157] Where μ o(T) represents the viscosity of gas-bearing crude oil within 1 meter of the electrically heated wellbore, which is related to the heating temperature. The viscosity of gas-bearing crude oil at different temperatures was tested by a ground rheometer and found to be 4.1 mPa·s within 1 meter of the wellbore at a temperature of 200℃.

[0158] B o The crude oil volume coefficient is 1.2, dimensionless;

[0159] C w The moisture content is 0.27, dimensionless;

[0160] h represents the oil layer thickness, which is 5m.

[0161] K h The vertical permeability of the oil reservoir is 0.2 μm. 2 ;

[0162] L is the length of the horizontal section, 1200m;

[0163] ΔP is the bottom hole pressure difference, 0.5 MPa;

[0164] r eh Provide a radius of 100m for the horizontal section;

[0165] r w The radius of the wellbore is 0.0809m.

[0166] Substituting the above parameters into the above formula, the daily liquid production is calculated to be 32.23 m³. 3 / d.

[0167] (5) When the daily oil production reaches below the preset value, inject viscosity reducer, gas and foaming system into the bottom of the well;

[0168] The preset daily oil production value is 5m. 3 / d; the viscosity reducer is diesel oil; the gas is methane; the foaming system is composed of a high oil-resistant (oil saturation reaches 50%, foaming height reaches 3 times) foaming agent and a foam stabilizer, wherein the foaming agent concentration is 3% and the foam stabilizer concentration is 1.5%; the injection method is to first inject the viscosity reducer slug at a volume of 0.05PV, and then alternately inject the gas and foaming system with small slugs of 0.03PV, the total injection volume of the gas and foaming system is 0.3PV;

[0169] (6) Stop injection and shut the well for 30 days;

[0170] (7) Open the well and recover the fluid and control the daily fluid production to exceed the preset value; the method for controlling the daily fluid production is the same as step (4);

[0171] (8) Repeat steps (5) to (7) to perform multiple rounds of throughput production. When the oil production of a single round cannot reach the preset lower limit of 700m³, 3 Production will cease at that time.

[0172] During steps (4) to (7), electric heating continues, and the power control method is the same as in step (3).

[0173] After implementing the crude oil extraction method for gas-bearing heavy oil reservoirs provided in this embodiment of the invention on target heavy oil reservoir C, statistical data shows that the final crude oil recovery rate of horizontal wells in target heavy oil reservoir C increased by 20% to 26% compared to cold extraction. The crude oil extraction method for gas-bearing heavy oil reservoirs provided in this embodiment of the invention improves the recovery rate of target heavy oil reservoir C.

[0174] Comparative Example 1

[0175] Compared with the effect of Example 3 of the present invention, another well in the target heavy oil reservoir C adopted the same well layout method, but without fracturing (i.e., without using steps (1) and (2)), only a simple electric heating cable was installed to assist production, and the remaining steps were the same as in Example 3, with a final recovery rate of 5%.

[0176] Comparative Example 2

[0177] Compared with the effect of Example 3 of the present invention, another well in the target heavy oil reservoir C adopts the same well layout method, but step (1) only adopts conventional CO2 energy storage volume fracturing and depletion production, that is, step (1) uses liquid CO2 instead of CO2 composite medium, keeping the total amount unchanged, and the rest of the steps are the same as in Example 3, and the final recovery rate is only 6%.

[0178] The above detailed description is a specific description of one of the feasible embodiments of the present invention. This embodiment is not intended to limit the patent scope of the present invention. All equivalent implementations or modifications that do not depart from the present invention should be included within the scope of the technical solution of the present invention.

Claims

1. A method of producing crude oil from a gas- and heavy oil-bearing reservoir, characterized by, Includes the following steps: (1) Perform fracturing operations on horizontal wells in gas-bearing heavy oil reservoirs to form a network of fracturing fractures; (2) Lay heat-sensitive proppant into the horizontal section of the hydraulic fracturing fracture to form a heat transfer network; (3) A heating cable is lowered into the horizontal section of the wellbore to electrically heat the oil layer in the horizontal section and reach the preset wellbore temperature; (4) Well opening and recovery, and controlling the daily fluid production to exceed the preset value; (5) When the daily oil production reaches below the preset value, inject viscosity reducer, gas and foaming system into the bottom of the well; (6) Stop injection and shut down the well; (7) Well opening and recovery, and controlling the daily fluid production to exceed the preset value; (8) Repeat steps (5) to (7) to carry out multiple rounds of throughput production. When the daily oil production of a single round cannot reach the preset value, stop production. in The preset value of the daily liquid production in step (4) is calculated according to the following formula: wherein Vp is the viscosity of the gas-containing crude oil in the vicinity of the electrically heated wellbore, mPa.s; VOC, volume oil coefficient, dimensionless; For water content, dimensionless; h Let the oil layer thickness be m; For the vertical permeability of the oil layer, um 2 ; L is the length of the horizontal section, m; for the well bottom pressure difference, 10 -1 MPa; supply the horizontal section with a radius, m; Let be the radius of the wellbore, in meters (m).

2. The method of recovering crude oil according to claim 1, characterized by, In step (1), multi-stage and multi-cluster CO2 composite medium energy storage volume fracturing operation is carried out on the horizontal well in the gas-bearing heavy oil reservoir to make the horizontal section uniformly develop a hydraulic fracturing fracture network.

3. The method of claim 2, wherein, The multi-stage, multi-cluster CO2 composite medium energy storage volumetric fracturing operation described in step (1) includes: The horizontal section is fractured in stages from the tip to the heel, with 2-3 clusters per section and a distance of 40-60m between each section; liquid CO2 composite medium is injected into the gas-bearing heavy oil reservoir from the horizontal wellhead, followed by the injection of pre-fracturing fluid to open the fractures; The liquid CO2 composite medium is a mixture of CO2, non-condensable gas, dimethyl ether, and additives; the non-condensable gas includes one or more of flue gas, N2, methane, and air; the volume ratio of CO2 to non-condensable gas is 10:1 to 1:1; the additive is ethanol with a mass concentration of 10%-90%; the volume ratio of dimethyl ether to additive is 5:1 to 9:1; and the volume ratio of CO2 to dimethyl ether is 90:10 to 99:

1.

4. The method of claim 3, wherein, The injection amount of the CO2 composite medium of the unit length horizontal section in step (1) is 1-3 m 3 / m under the underground temperature and pressure conditions; and the judgment mark for the end of the preflush injection is 5-10 MPa above the reservoir fracturing pressure.

5. The method of claim 1, wherein, The heat-sensitive proppant mentioned in step (2) includes a sand-carrying liquid, which is a mixture of at least one of carbon fiber, alumina, magnesium oxide, zinc oxide, aluminum nitride, boron nitride and silicon carbide with ceramsite in a mass ratio of 1:1 to 3:

1.

6. The method of recovering crude oil according to claim 1, wherein, The heating cable mentioned in step (3) is a constant temperature heating cable with a surface temperature of 100~250℃.

7. The method of recovering crude oil according to claim 1, wherein Wellhead differential pressure is 1-3 MPa.

8. The method of recovering crude oil according to claim 1, wherein, The preset value for daily oil production in step (5) is 2~5m³. 3 / d; The viscosity reducer mentioned in step (5) is an oil-soluble viscosity reducer; The oil-soluble viscosity reducer includes at least one of diesel, naphtha and condensate; The gas includes one or more of CO2, N2, methane, flue gas, natural gas, LNG, air and water vapor; The foam promoting system is composed of a foaming agent and a foam stabilizing agent, wherein the foaming agent concentration is 0.5~3wt% and the foam stabilizing agent concentration is 0.1~1.5wt%; The injection method mentioned in step (5) is to first inject a viscosity reducer slug, with an injection volume of 0.01~0.05PV, and then the gas and foam promoting system are injected alternately with small slugs of 0.01~0.03PV, and the total injection volume of the gas and foam promoting system is 0.2~0.3PV.

9. The method of recovering crude oil according to claim 1, wherein, In step (2), after the thermally sensitive proppant is laid into the horizontal section of the fracturing fracture, the displacement fluid is injected into the reservoir until the reservoir pressure reaches the preset value, which is 10-20 MPa above the reservoir fracturing pressure. After the injection is completed, the well is shut in for 40-60 days before the fluid is drained. During the process of steps (4) to (7), electric heating is continuously carried out, and the surface temperature of the cable is the same as in step (3).

Images