Method for exploiting deep heavy oil reservoir

Abstract

The invention provides a method for exploiting a deep heavy oil reservoir, which comprises the following steps of: (1) injecting a pre-solution slug into an oil layer, and then fracturing; (2) a front gas slug is injected into an oil layer, and then sand-carrying fluid and displacing fluid are sequentially injected; (3) extracting oil by supercritical steam huff and puff; the front gas slug in the step (2) comprises a combination of non-condensate gas, CO2 and a CO2 auxiliary agent. According to the exploiting method, oil is exploited through the pressure and supercritical steam huff and puff method, cracks are generated in the stratum corresponding to the deep heavy oil reservoir, the injection capacity of water vapor is improved, and the pressure of injected steam is reduced; moreover, according to the mining method provided by the invention, the pre-solvent slug is injected before fracturing, so that the viscosity is greatly reduced, and a flow channel is provided for subsequent injection of the pre-gas slug; and the front gas slug can provide energy by means of gas expansion in the exploitation and pressure relief process, and the steam huff and puff period is greatly prolonged.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas exploitation, and relates to an exploitation method for an oil reservoir, and in particular to an exploitation method for a deep-layer heavy oil reservoir. Background Art

[0002] Heavy oil is crude oil with high asphaltene and colloid content and high viscosity. The recovery technology of heavy oil reservoirs includes cold recovery technology and thermal recovery technology. Due to the high viscosity of heavy oil, the recovery rate of cold recovery technology is generally low. Steam huff and puff is one of the main methods of thermal recovery technology. It injects a certain amount of high-temperature and high-pressure saturated wet steam into the oil layer, shuts down the well for a period of time, and then opens the well for production after the heat of the steam diffuses into the oil layer.

[0003] For heavy oil reservoirs with a burial depth of more than 1,500 meters, the permeability of the oil layer is below 500mD, and the pressure of the overlying bottom layer is high, making steam injection extremely difficult. Conventional steam injection pressure is difficult to enter the oil layer to drive oil. In addition, the reservoir of heavy oil reservoirs with a burial depth of more than 1,500 meters is water-sensitive, and conventional water injection or steam injection will further reduce the permeability of the oil layer.

[0004] In order to realize the exploitation of such heavy oil reservoirs, the existing technology uses supercritical steam injection to drive oil. When the temperature and pressure of water rise above the critical point, the properties of water change, and it has extremely high permeability, solubility and reactivity. However, due to the influence of reservoir water sensitivity of heavy oil reservoirs with a burial depth of more than 1,500 meters, clay minerals expand, which leads to high injection pressure and it is difficult to achieve multiple rounds of gas injection to effectively reduce the injection pressure.

[0005] In addition, due to the limitation of injection capacity, the injection volume of each round is limited, and the energy provided to the formation is also limited. During the steam throughput process, the energy is rapidly depleted, resulting in a short effective production time of the cycle, a small range of steam throughput, low cycle oil production, and a recovery rate generally not exceeding 20%.

[0006] Therefore, it is necessary to provide a method for exploiting deep heavy oil reservoirs with a burial depth of more than 1500 meters. Summary of the invention

[0007] In view of the deficiencies in the prior art, the purpose of the present invention is to provide a method for exploiting deep heavy oil reservoirs, which can exploit heavy oil reservoirs with a burial depth of more than 1,500 meters, significantly improve the injection capacity, extend the cycle exploitation time of steam throughput, improve the recovery rate of steam throughput, and realize the effective development of heavy oil reservoirs.

[0008] To achieve this object, the present invention adopts the following technical solutions:

[0009] The present invention provides a method for exploiting a deep heavy oil reservoir, the method comprising the following steps:

[0010] (1) Injecting a pre-fill solution plug into the oil layer and then fracturing it;

[0011] (2) Injecting a pre-gas slug into the oil layer, followed by injecting sand-carrying fluid and displacement fluid in sequence;

[0012] (3) Supercritical steam huff and puff for oil recovery;

[0013] The pre-gas slug in step (2) comprises a combination of non-condensable gas, CO2 and a CO2 additive.

[0014] The extraction method provided by the present invention adopts the method of pressure and supercritical steam throughput to produce oil, generates cracks in the stratum corresponding to the deep heavy oil reservoir, expands the injection capacity of water vapor, and reduces the pressure of injected steam; moreover, the extraction method provided by the present invention injects a pre-solvent plug before fracturing, achieves a significant viscosity reduction, and provides a flow channel for the injection of subsequent pre-gas plugs; and the pre-gas plug can provide energy by relying on the expansion of the gas during the extraction pressure relief process, thereby greatly extending the steam throughput cycle; in addition, the present invention adds non-condensable gas to the pre-gas plug, which can avoid the inability of CO2 to release energy under high pressure, relies on the high compressibility of the non-condensable gas to provide energy, plays an energy storage role, and increases the steam throughput cycle.

[0015] The fracturing in step (1) of the present invention is to perform unconventional oil and gas reservoir volume fracturing on the oil layer in a multi-stage and multi-cluster manner. The method of performing conventional oil and gas volume fracturing on the oil layer in a multi-stage and multi-cluster manner is a conventional method of fracturing in the art, and the present invention does not make any specific limitation here.

[0016] Preferably, the pre-solution slug in step (1) comprises any one of alkanes, aromatics, naphtha, petroleum ether, diesel, dimethyl ether or ethanol, or a combination of at least two thereof. Typical but non-limiting combinations include a combination of alkanes and aromatics, a combination of aromatics and naphtha, a combination of naphtha and petroleum ether, a combination of petroleum ether and diesel, a combination of dimethyl ether and ethanol, a combination of alkanes, aromatics and naphtha, a combination of naphtha, petroleum ether and diesel, a combination of diesel, dimethyl ether and ethanol, a combination of alkanes, aromatics, naphtha, petroleum ether and dimethyl ether, or a combination of alkanes, aromatics, naphtha, petroleum ether, diesel, dimethyl ether and ethanol.

[0017] Preferably, the carbon number of the alkane is 3-15, for example, 3, 5, 6, 8, 10, 12 or 15, but is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable.

[0018] Preferably, the non-condensable gas comprises any one of N2, natural gas, methane or flue gas or a combination of at least two thereof, typical but non-limiting combinations comprising a combination of N2 and natural gas, a combination of natural gas and methane, a combination of methane and flue gas, a combination of N2, natural gas and methane, a combination of natural gas, methane and flue gas, or a combination of N2, natural gas, methane and flue gas.

[0019] Preferably, the CO2 auxiliary agent includes a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer.

[0020] The present invention improves the solubility of CO2 in the oil layer and the injection capacity of CO2 by using a CO2 additive. At the same time, by generating CO2 foam, the removal of gases such as CO2 is inhibited, the retention time of CO2 in crude oil is increased, the flowability of crude oil is greatly improved, and thus the cyclic oil production of steam throughput is increased.

[0021] Preferably, the CO2 solubilizing agent includes any one of ethanol, urea, ethane, ethylene glycol or dimethyl ether, or a combination of at least two of them. Typical but non-limiting combinations include a combination of ethanol and urea, a combination of urea and ethane, a combination of ethylene glycol and dimethyl ether, a combination of ethane, ethylene glycol and dimethyl ether, a combination of ethanol, urea, ethane and dimethyl ether, and a combination of ethanol, urea, ethane, ethylene glycol and dimethyl ether.

[0022] Preferably, the CO2 foaming agent comprises anionic surfactants and / or nonionic surfactants.

[0023] Exemplarily, the anionic surfactant includes any one of a sulfate surfactant, a sulfonate surfactant, a phosphate surfactant or a carboxylate surfactant, or a combination of at least two thereof.

[0024] Preferably, the anionic surfactant in the CO2 foam agent of the present invention includes any one of ammonium dodecyl sulfate, sodium dodecyl sulfate, sodium lauryl ether sulfate, dioctyl sodium sulfosuccinate, perfluorooctane sulfonic acid, perfluorobutane sulfonic acid, alkyl aromatic ether phosphate or alkyl ether phosphate, or a combination of at least two thereof.

[0025] Exemplarily, the nonionic surfactant includes any one or a combination of at least two of fatty alcohols, polyoxyethylene glycol alkyl ethers, octyl glycol monododecyl ether, pentaethylene glycol monododecyl ether, polyoxypropylene glycol alkyl ethers, glucoside alkyl ethers, decyl glucoside, dodecyl glucoside, octyl glucoside, polyoxyethylene glycol octylphenol ether, polyoxyethylene glycol alkylphenol ether, polyoxyethylene glycol alkylphenol ether, glycerol alkyl ester, glycerol laurate, polysorbate, sorbitan alkyl ester, dodecyldimethylamine oxide or block copolymers.

[0026] The fatty alcohol includes any one of cetyl alcohol, stearyl alcohol, cetylstearyl alcohol or oleyl alcohol, or a combination of at least two thereof.

[0027] The block copolymers include poloxamers and / or polyoxylated lipid amines.

[0028] Preferably, the CO2 foam stabilizer comprises anionic polymer electrolyte powder and cationic polymer electrolyte powder.

[0029] Exemplarily, the material of the cationic polymer dielectric powder includes any one of polyethyleneimine, polyallylamine or deacetylated chitosan or a combination of at least two thereof. Typical but non-limiting combinations include a combination of polyethyleneimine and polyallylamine, a combination of polyallylamine and deacetylated chitosan, a combination of polyethyleneimine and deacetylated chitosan, or a combination of polyethyleneimine, polyallylamine and deacetylated chitosan.

[0030] Exemplarily, the material of the anionic polymer electrolyte powder includes dextran sulfate.

[0031] The present invention uses a CO2 foam stabilizer to form nanoparticles through electrostatic interaction between anionic polymer electrolyte powder and cationic polymer dielectric powder, thereby playing a role in stabilizing foam. The present invention does not specifically limit the specific materials of cationic polymer dielectric powder and anionic polymer electrolyte powder. As long as the CO2 foam stabilizer has both anionic polymer electrolyte powder and cationic polymer dielectric powder, and the average particle size meets the process requirements, the existence time of the foam can be effectively prolonged.

[0032] Preferably, the average particle size of the CO2 foam stabilizer is 50-150 nm, for example, 50 nm, 60 nm, 80 nm, 90 nm, 100 nm, 120 nm or 150 nm, but is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable.

[0033] Preferably, the amount of the CO2 solubilizer used is 0.1-0.5wt% of the amount of the CO2 system, for example, it can be 0.1wt%, 0.2wt%, 0.3wt%, 0.4wt% or 0.5wt%, but is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable. The CO2 system is a combination of CO2 and a CO2 additive.

[0034] Preferably, the amount of the CO2 foaming agent used is 0.1-0.5wt% of the amount of the CO2 system, for example, it can be 0.1wt%, 0.2wt%, 0.3wt%, 0.4wt% or 0.5wt%, but is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable. The CO2 system is a combination of CO2 and a CO2 auxiliary agent.

[0035] Preferably, the amount of the CO2 foam stabilizer is 0.1-0.3wt% of the amount of the CO2 system, for example, it can be 0.1wt%, 0.2wt% or 0.3wt%, but is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable. The CO2 system is a combination of CO2 and a CO2 additive.

[0036] Preferably, the volume ratio of the non-condensable gas to CO2 is 1:10 to 10:1; for example, it can be 1:10, 2:9, 3:8, 4:7, 5:6, 6:5, 7:4, 8:3, 9:2 or 10:1, but is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable.

[0037] Preferably, the injection amount of the front gas slug in step (2) is 0.05-0.1PV, for example, it can be 0.05PV, 0.06PV, 0.07PV, 0.08PV, 0.09PV or 0.1PV, but is not limited to the listed values, and other values ​​not listed within the numerical range are also applicable.

[0038] The sand-carrying liquid in step (2) of the present invention is a conventional sand-carrying liquid in the art, and the present invention does not specifically limit it, as long as it can play the role of the sand-carrying liquid.

[0039] Preferably, the displacement fluid in step (2) is a combination of supercritical CO2 and a thickener aqueous solution.

[0040] Preferably, the volume ratio of the supercritical CO2 to the viscosified solution is 0.01:1 to 1:1, for example, it can be 0.01:1, 0.1:1, 0.2:1, 0.3:1, 0.4:1, 0.5:1, 0.6:1, 0.8:1 or 1:1, but is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable.

[0041] Preferably, the thickener in the aqueous thickener solution is any one of xanthan gum, cellulose or a polymer, or a combination of at least two of them. Typical but non-limiting combinations include a combination of xanthan gum and cellulose, a combination of cellulose and a polymer, or a combination of xanthan gum, cellulose and a polymer.

[0042] Preferably, the number average molecular weight of the thickener is 1 million to 25 million, for example, 1 million, 3 million, 5 million, 8 million, 10 million, 12 million, 15 million, 16 million, 18 million, 20 million, 21 million or 25 million, but is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable.

[0043] Preferably, the concentration of the aqueous thickener solution is 400-1500 ppm, for example, 400 ppm, 500 ppm, 600 ppm, 800 ppm, 1000 ppm, 1200 ppm or 1500 ppm, but is not limited to the listed values, and other values ​​not listed within the numerical range are also applicable.

[0044] Preferably, a single round of supercritical steam throughput in step (3) includes sequentially injecting supercritical water vapor, blocking the well and opening the well for production. When the daily oil production drops below 0.5 t / d, a new round of supercritical steam throughput is started.

[0045] Exemplarily, the injection amount of the supercritical water vapor is 0.1-0.3 PV, for example, 0.1 PV, 0.2 PV or 0.3 PV, but is not limited to the listed values, and other values ​​not listed within the numerical range are also applicable.

[0046] Preferably, a combination of non-condensable gas, CO2, CO2 auxiliary agent and water vapor is injected every 3-5 rounds.

[0047] The present invention significantly increases the action range of the steam injection medium in the reservoir and improves the recovery rate of the injection by injecting a combination of non-condensable gas, CO2, CO2 additive and water vapor at intervals of 3-5 rounds.

[0048] Preferably, the volume ratio of the non-condensable gas to CO2 is 1:(1-5), for example, it can be 1:1, 1:2, 1:3, 1:4 or 1:5, but is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable.

[0049] In the present invention, the volume ratio of non-condensable gas to CO2 is the volume ratio at normal temperature and pressure.

[0050] Preferably, the volume ratio of the non-condensable gas to supercritical water vapor is 1:(5-10), for example, it can be 1:5, 1:6, 1:7, 1:8, 1:9 or 1:10, but is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable.

[0051] In the present invention, the volume ratio of non-condensable gas to supercritical water vapor is the volume ratio of non-condensable gas to water vapor at normal temperature and pressure.

[0052] The composition of the non-condensable gas is the same as that of the non-condensable gas in the preceding gas slug, including any one of N2, natural gas, methane or flue gas or a combination of at least two thereof. Typical but non-limiting combinations include a combination of N2 and natural gas, a combination of natural gas and methane, a combination of methane and flue gas, a combination of N2, natural gas and methane, a combination of natural gas, methane and flue gas, or a combination of N2, natural gas, methane and flue gas.

[0053] Preferably, the dosage of the CO2 auxiliary agent is 1-10% of the volume of the liquefied CO2, for example, it can be 1%, 3%, 5%, 8% or 10%, but it is not limited to the listed values, and other unlisted values ​​within the numerical range are also applicable.

[0054] The composition of the CO2 additive is the same as that of the CO2 additive in the front gas slug.

[0055] Exemplarily, the usage ratio of CO2 solubilizer, CO2 foaming agent and CO2 foam stabilizer is (1-5):(1-5):(1-3).

[0056] The numerical range described in the present invention not only includes the point values ​​listed above, but also includes any point values ​​between the above numerical ranges that are not listed. Due to space limitations and for the sake of simplicity, the present invention no longer exhaustively lists the specific point values ​​included in the range.

[0057] Compared with the prior art, the present invention has the following beneficial effects:

[0058] The extraction method provided by the present invention adopts the method of pressure and supercritical steam throughput to produce oil, generates cracks in the stratum corresponding to the deep heavy oil reservoir, expands the injection capacity of water vapor, and reduces the pressure of injected steam; moreover, the extraction method provided by the present invention injects a pre-solvent plug before fracturing, achieves a significant viscosity reduction, and provides a flow channel for the injection of subsequent pre-gas plugs; and the pre-gas plug can provide energy by relying on the expansion of the gas during the extraction pressure relief process, thereby greatly extending the steam throughput cycle; in addition, the present invention adds non-condensable gas to the pre-gas plug, which can avoid the inability of CO2 to release energy under high pressure, relies on the high compressibility of the non-condensable gas to provide energy, plays an energy storage role, and increases the steam throughput cycle. DETAILED DESCRIPTION

[0059] The technical solution of the present invention is further illustrated below through specific implementation methods.

[0060] Example 1-1

[0061] This embodiment provides a method for exploiting a deep heavy oil reservoir. The deep heavy oil reservoir has a burial depth of 1500 meters, an average permeability of 200 mD, and a viscosity of crude oil of 4788 mPa·s at 50° C. The reservoir is a heavy oil reservoir with high viscosity and low permeability. It is necessary to adopt an exploitation method of injecting supercritical steam for exploitation. The exploitation method comprises the following steps:

[0062] (1) injecting a pre-fill solution slug into the oil layer, and then performing volume fracturing of the unconventional oil and gas reservoir in a multi-stage and multi-cluster manner; the pre-fill solution slug is dimethyl ether;

[0063] (2) A 0.08 PV pre-gas plug is injected into the oil layer, followed by displacement fluid and conventional sand-carrying fluid (a 2% polyacrylamide solution with a number average molecular weight of 24 million);

[0064] The front gas slug is a combination of non-condensable gas, CO2 and CO2 additive; the non-condensable gas is N2;

[0065] The CO2 auxiliary agent includes a combination of a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer; the CO2 solubilizer is ethylene glycol; the CO2 foaming agent is an anionic surfactant sodium lauryl sulfate; the CO2 foam stabilizer is a combination of polyethyleneimine and dextran sulfate, and the average particle size is 100nm;

[0066] The volume ratio of the non-condensable gas to CO2 is 1:1, the amount of CO2 solubilizer is 0.3wt% of the amount of CO2 system, the amount of CO2 foaming agent is 0.3wt% of the amount of CO2 system, the amount of CO2 foam stabilizer is 0.2wt% of the amount of CO2 system, and the CO2 system is a combination of CO2 and CO2 auxiliary agent;

[0067] The displacement fluid is a combination of supercritical CO2 and a thickener aqueous solution in a volume ratio of 0.5:1; the concentration of the thickener aqueous solution is 400 ppm, wherein the thickener is xanthan gum, and the number average molecular weight of the xanthan gum is 1 million;

[0068] (3) Supercritical steam huff and puff for oil recovery;

[0069] A single round of supercritical steam huff and puff includes sequentially injecting supercritical steam 0.2 PV, blocking the well and opening the well for production. When the daily oil production drops to 0.5 t / d, a new round of supercritical steam huff and puff is started;

[0070] A combination of non-condensable gas, CO2, CO2 additive and water vapor is injected every 4 rounds; the volume ratio of non-condensable gas to CO2 is 1:3, the volume ratio of non-condensable gas to supercritical water vapor is 1:8, and the amount of CO2 additive is 5% of the volume of CO2 after liquefaction.

[0071] In this embodiment, the composition of the non-condensable gas is the same, and the composition of the CO2 auxiliary agent is the same.

[0072] Example 1-2

[0073] This embodiment provides a method for exploiting a deep heavy oil reservoir. The deep heavy oil reservoir has a burial depth of 1500 meters, an average permeability of 200 mD, and a viscosity of crude oil of 4788 mPa·s at 50° C. The reservoir is a heavy oil reservoir with high viscosity and low permeability. It is necessary to adopt an exploitation method of injecting supercritical steam for exploitation. The exploitation method comprises the following steps:

[0074] (1) injecting a pre-fill solution slug into the oil layer, and then performing volume fracturing of the unconventional oil and gas reservoir in a multi-stage and multi-cluster manner; the pre-fill solution slug is dimethyl ether;

[0075] (2) A 0.05 PV pre-gas plug is injected into the oil layer, followed by displacement fluid and conventional sand-carrying fluid (a 2% polyacrylamide solution with a number average molecular weight of 24 million);

[0076] The front gas slug is a combination of non-condensable gas, CO2 and CO2 additive; the non-condensable gas is N2;

[0077] The CO2 auxiliary agent includes a combination of a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer; the CO2 solubilizer is ethylene glycol; the CO2 foaming agent is an anionic surfactant, sodium lauryl sulfate; the CO2 foam stabilizer is a combination of polyethyleneimine and dextran sulfate, with an average particle size of 50nm;

[0078] The volume ratio of the non-condensable gas to CO2 is 1:10, the amount of CO2 solubilizer is 0.1wt% of the amount of CO2 system, the amount of CO2 foaming agent is 0.1wt% of the amount of CO2 system, the amount of CO2 foam stabilizer is 0.1wt% of the amount of CO2 system, and the CO2 system is a combination of CO2 and CO2 auxiliary agent;

[0079] The displacement fluid is a combination of supercritical CO2 and a thickener aqueous solution in a volume ratio of 0.01:1; the concentration of the thickener aqueous solution is 400 ppm, wherein the thickener is xanthan gum, and the number average molecular weight of the xanthan gum is 1 million;

[0080] (3) Supercritical steam huff and puff for oil recovery;

[0081] A single round of supercritical steam huff and puff includes sequentially injecting supercritical steam 0.1 PV, blocking the well and opening the well for production. When the daily oil production drops to 0.5 t / d, a new round of supercritical steam huff and puff is started;

[0082] A combination of non-condensable gas, CO2, CO2 additive and water vapor is injected every three rounds; the volume ratio of non-condensable gas to CO2 is 1:1, the volume ratio of non-condensable gas to supercritical water vapor is 1:5, and the amount of CO2 additive is 1% of the volume of CO2 after liquefaction.

[0083] In this embodiment, the composition of the non-condensable gas is the same, and the composition of the CO2 auxiliary agent is the same.

[0084] Examples 1-3

[0085] This embodiment provides a method for exploiting a deep heavy oil reservoir. The deep heavy oil reservoir has a burial depth of 1500 meters, an average permeability of 200 mD, and a viscosity of crude oil of 4788 mPa·s at 50° C. The reservoir is a heavy oil reservoir with high viscosity and low permeability. It is necessary to adopt an exploitation method of injecting supercritical steam for exploitation. The exploitation method comprises the following steps:

[0086] (1) injecting a pre-fill solution slug into the oil layer, and then performing volume fracturing of the unconventional oil and gas reservoir in a multi-stage and multi-cluster manner; the pre-fill solution slug is dimethyl ether;

[0087] (2) A 0.1 PV pre-gas plug is injected into the oil layer, followed by displacement fluid and conventional sand-carrying fluid (a 2% polyacrylamide solution with a number average molecular weight of 24 million);

[0088] The front gas slug is a combination of non-condensable gas, CO2 and CO2 additive; the non-condensable gas is N2;

[0089] The CO2 auxiliary agent includes a combination of a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer; the CO2 solubilizer is ethylene glycol; the CO2 foaming agent is an anionic surfactant sodium lauryl sulfate; the CO2 foam stabilizer is a combination of polyethyleneimine and dextran sulfate, and the average particle size is 150nm;

[0090] The volume ratio of the non-condensable gas to CO2 is 10:1, the amount of CO2 solubilizer is 0.5wt% of the amount of CO2 system, the amount of CO2 foaming agent is 0.5wt% of the amount of CO2 system, the amount of CO2 foam stabilizer is 0.3wt% of the amount of CO2 system, and the CO2 system is a combination of CO2 and CO2 auxiliary agent;

[0091] The displacement fluid is a combination of supercritical CO2 and a thickener aqueous solution in a volume ratio of 1:1; the concentration of the thickener aqueous solution is 400 ppm, wherein the thickener is xanthan gum, and the number average molecular weight of the xanthan gum is 1 million;

[0092] (3) Supercritical steam huff and puff for oil recovery;

[0093] A single round of supercritical steam huff and puff includes sequentially injecting supercritical steam 0.3 PV, blocking the well and opening the well for production. When the daily oil production drops to 0.5 t / d, a new round of supercritical steam huff and puff is started;

[0094] A combination of non-condensable gas, CO2, CO2 additive and water vapor is injected every 5 rounds; the volume ratio of non-condensable gas to CO2 is 1:5, the volume ratio of non-condensable gas to supercritical water vapor is 1:10, and the amount of CO2 additive is 10% of the volume of CO2 after liquefaction.

[0095] In this embodiment, the composition of the non-condensable gas is the same, and the composition of the CO2 auxiliary agent is the same.

[0096] Comparative Example 1-1

[0097] This comparative example provides a method for exploiting a deep heavy oil reservoir, which is the same as Example 1-1 except that the front gas slug does not include non-condensable gas.

[0098] Example 2-1

[0099] This embodiment provides a method for exploiting a deep heavy oil reservoir. The deep heavy oil reservoir has a burial depth of 1800 meters, an average permeability of 250 mD, and a viscosity of crude oil of 6890 mPa·s at 50° C. The reservoir is a heavy oil reservoir with high viscosity and low permeability. It is necessary to adopt an exploitation method of injecting supercritical steam for exploitation. The exploitation method comprises the following steps:

[0100] (1) injecting a pre-fill solution slug into the oil layer, and then performing volume fracturing of the unconventional oil and gas reservoir in a multi-stage and multi-cluster manner; the pre-fill solution slug is propane;

[0101] (2) A 0.08 PV pre-gas plug is injected into the oil layer, followed by displacement fluid and conventional sand-carrying fluid (a 2% polyacrylamide solution with a number average molecular weight of 24 million);

[0102] The front gas slug is a combination of non-condensable gas, CO2 and CO2 additive; the non-condensable gas is methane;

[0103] The CO2 auxiliary agent includes a combination of a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer; the CO2 solubilizer is ethanol; the CO2 foaming agent is a nonionic surfactant polyoxyethylene glycol alkyl ether; the CO2 foam stabilizer is a combination of polyethyleneimine and dextran sulfate, and the average particle size is 100nm;

[0104] The volume ratio of the non-condensable gas to CO2 is 1:1, the amount of CO2 solubilizer is 0.3wt% of the amount of CO2 system, the amount of CO2 foaming agent is 0.3wt% of the amount of CO2 system, the amount of CO2 foam stabilizer is 0.2wt% of the amount of CO2 system, and the CO2 system is a combination of CO2 and CO2 auxiliary agent;

[0105] The displacement fluid is a combination of supercritical CO2 and a thickener aqueous solution in a volume ratio of 0.5:1; the concentration of the thickener aqueous solution is 1000 ppm, wherein the thickener is carboxymethyl cellulose, and the number average molecular weight of the carboxymethyl cellulose is 10 million;

[0106] (3) Supercritical steam huff and puff for oil recovery;

[0107] A single round of supercritical steam huff and puff includes sequentially injecting supercritical steam 0.2 PV, blocking the well and opening the well for production. When the daily oil production drops to 0.5 t / d, a new round of supercritical steam huff and puff is started;

[0108] A combination of non-condensable gas, CO2, CO2 additive and water vapor is injected every 4 rounds; the volume ratio of non-condensable gas to CO2 is 1:3, the volume ratio of non-condensable gas to supercritical water vapor is 1:8, and the amount of CO2 additive is 5% of the volume of CO2 after liquefaction.

[0109] In this embodiment, the composition of the non-condensable gas is the same, and the composition of the CO2 auxiliary agent is the same.

[0110] Example 2-2

[0111] This embodiment provides a method for exploiting a deep heavy oil reservoir. The deep heavy oil reservoir has a burial depth of 1800 meters, an average permeability of 250 mD, and a viscosity of crude oil of 6890 mPa·s at 50° C. The reservoir is a heavy oil reservoir with high viscosity and low permeability. It is necessary to adopt an exploitation method of injecting supercritical steam for exploitation. The exploitation method comprises the following steps:

[0112] (1) injecting a pre-fill solution slug into the oil layer, and then performing volume fracturing of the unconventional oil and gas reservoir in a multi-stage and multi-cluster manner; the pre-fill solution slug is propane;

[0113] (2) A 0.05 PV pre-gas plug is injected into the oil layer, followed by displacement fluid and conventional sand-carrying fluid (a 2% polyacrylamide solution with a number average molecular weight of 24 million);

[0114] The front gas slug is a combination of non-condensable gas, CO2 and CO2 additive; the non-condensable gas is N2;

[0115] The CO2 auxiliary agent includes a combination of a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer; the CO2 solubilizer is ethanol; the CO2 foaming agent is a nonionic surfactant polyoxyethylene glycol alkyl ether; the CO2 foam stabilizer is a combination of polyethyleneimine and dextran sulfate, and the average particle size is 50nm;

[0116] The volume ratio of the non-condensable gas to CO2 is 1:10, the amount of CO2 solubilizer is 0.1wt% of the amount of CO2, the amount of CO2 foaming agent is 0.1wt% of the amount of CO2, the amount of CO2 foam stabilizer is 0.1wt% of the amount of CO2, and the CO2 system is a combination of CO2 and CO2 auxiliary agent;

[0117] The displacement fluid is a combination of supercritical CO2 and a thickener aqueous solution in a volume ratio of 0.01:1; the concentration of the thickener aqueous solution is 1000 ppm, wherein the thickener is carboxymethyl cellulose, and the number average molecular weight of the carboxymethyl cellulose is 10 million;

[0118] (3) Supercritical steam huff and puff for oil recovery;

[0119] A single round of supercritical steam huff and puff includes sequentially injecting supercritical steam 0.1 PV, blocking the well and opening the well for production. When the daily oil production drops to 0.5 t / d, a new round of supercritical steam huff and puff is started;

[0120] A combination of non-condensable gas, CO2, CO2 additive and water vapor is injected every three rounds; the volume ratio of non-condensable gas to CO2 is 1:1, the volume ratio of non-condensable gas to supercritical water vapor is 1:5, and the amount of CO2 additive is 1% of the volume of CO2 after liquefaction.

[0121] In this embodiment, the composition of the non-condensable gas is the same, and the composition of the CO2 auxiliary agent is the same.

[0122] Example 2-3

[0123] This embodiment provides a method for exploiting a deep heavy oil reservoir. The deep heavy oil reservoir has a burial depth of 1800 meters, an average permeability of 250 mD, and a viscosity of crude oil of 6890 mPa·s at 50° C. The reservoir is a heavy oil reservoir with high viscosity and low permeability. It is necessary to adopt an exploitation method of injecting supercritical steam for exploitation. The exploitation method comprises the following steps:

[0124] (1) injecting a pre-fill solution slug into the oil layer, and then performing volume fracturing of the unconventional oil and gas reservoir in a multi-stage and multi-cluster manner; the pre-fill solution slug is propane;

[0125] (2) A 0.1 PV pre-gas plug is injected into the oil layer, followed by displacement fluid and conventional sand-carrying fluid (a 2% polyacrylamide solution with a number average molecular weight of 24 million);

[0126] The front gas slug is a combination of non-condensable gas, CO2 and CO2 additive; the non-condensable gas is N2;

[0127] The CO2 auxiliary agent includes a combination of a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer; the CO2 solubilizer is ethanol; the CO2 foaming agent is a nonionic surfactant polyoxyethylene glycol alkyl ether; the CO2 foam stabilizer is a combination of polyethyleneimine and dextran sulfate, and the average particle size is 150nm;

[0128] The volume ratio of the non-condensable gas to CO2 is 10:1, the amount of CO2 solubilizer is 0.5wt% of the amount of CO2, the amount of CO2 foaming agent is 0.5wt% of the amount of CO2, the amount of CO2 foam stabilizer is 0.3wt% of the amount of CO2, and the CO2 system is a combination of CO2 and CO2 auxiliary agent;

[0129] The displacement fluid is a combination of supercritical CO2 and a thickener aqueous solution in a volume ratio of 1:1; the concentration of the thickener aqueous solution is 1000 ppm, wherein the thickener is carboxymethyl cellulose, and the number average molecular weight of the carboxymethyl cellulose is 10 million;

[0130] (3) Supercritical steam huff and puff for oil recovery;

[0131] A single round of supercritical steam huff and puff includes sequentially injecting supercritical steam 0.3 PV, blocking the well and opening the well for production. When the daily oil production drops to 0.5 t / d, a new round of supercritical steam huff and puff is started;

[0132] A combination of non-condensable gas, CO2, CO2 additive and water vapor is injected every 5 rounds; the volume ratio of non-condensable gas to CO2 is 1:5, the volume ratio of non-condensable gas to supercritical water vapor is 1:10, and the amount of CO2 additive is 10% of the volume of CO2 after liquefaction.

[0133] In this embodiment, the composition of the non-condensable gas is the same, and the composition of the CO2 auxiliary agent is the same.

[0134] Comparative Example 2-1

[0135] This comparative example provides a method for exploiting a deep heavy oil reservoir, which is the same as Example 2-1 except that the front gas slug does not include non-condensable gas.

[0136] Example 3-1

[0137] This embodiment provides a method for exploiting a deep heavy oil reservoir. The deep heavy oil reservoir has a burial depth of 2000 meters, an average permeability of 300 mD, and a viscosity of crude oil of 8799 mPa·s at 50° C. The reservoir is a heavy oil reservoir with high viscosity and low permeability. It is necessary to adopt an exploitation method of injecting supercritical steam for exploitation. The exploitation method comprises the following steps:

[0138] (1) injecting a pre-filled solution slug into the oil layer, and then performing volume fracturing of the unconventional oil and gas reservoir in a multi-stage and multi-cluster manner; the pre-filled solution slug is naphtha;

[0139] (2) A 0.08 PV pre-gas plug is injected into the oil layer, followed by displacement fluid and conventional sand-carrying fluid (a 2% polyacrylamide solution with a number average molecular weight of 24 million);

[0140] The front gas slug is a combination of non-condensable gas, CO2 and CO2 additive; the non-condensable gas is a combination of N2 and natural gas (volume ratio is 1:1);

[0141] The CO2 auxiliary agent includes a combination of a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer; the CO2 solubilizer is acetone; the CO2 foaming agent is dioctyl sodium sulfosuccinate; the CO2 foam stabilizer is a combination of polyethyleneimine and dextran sulfate, and the average particle size is 100 nm;

[0142] The volume ratio of the non-condensable gas to CO2 is 1:1, the amount of CO2 solubilizer is 0.3wt% of the amount of CO2 system, the amount of CO2 foaming agent is 0.3wt% of the amount of CO2 system, the amount of CO2 foam stabilizer is 0.2wt% of the amount of CO2 system, and the CO2 system is a combination of CO2 and CO2 auxiliary agent;

[0143] The displacement fluid is a combination of supercritical CO2 and a thickener aqueous solution at a volume ratio of 0.5:1; the concentration of the thickener aqueous solution is 1500 ppm, wherein the thickener is polyacrylamide, and the number average molecular weight of the polyacrylamide is 15 million;

[0144] (3) Supercritical steam huff and puff for oil recovery;

[0145] A single round of supercritical steam huff and puff includes sequentially injecting supercritical steam 0.2 PV, blocking the well and opening the well for production. When the daily oil production drops to 0.5 t / d, a new round of supercritical steam huff and puff is started;

[0146] A combination of non-condensable gas, CO2, CO2 additive and water vapor is injected every 4 rounds; the volume ratio of non-condensable gas to CO2 is 1:3, the volume ratio of non-condensable gas to supercritical water vapor is 1:8, and the amount of CO2 additive is 5% of the volume of CO2 after liquefaction.

[0147] In this embodiment, the composition of the non-condensable gas is the same, and the composition of the CO2 auxiliary agent is the same.

[0148] Example 3-2

[0149] This embodiment provides a method for exploiting a deep heavy oil reservoir. The deep heavy oil reservoir has a burial depth of 2000 meters, an average permeability of 300 mD, and a viscosity of crude oil of 8799 mPa·s at 50° C. The reservoir is a heavy oil reservoir with high viscosity and low permeability. It is necessary to adopt an exploitation method of injecting supercritical steam for exploitation. The exploitation method comprises the following steps:

[0150] (1) injecting a pre-filled solution slug into the oil layer, and then performing volume fracturing of the unconventional oil and gas reservoir in a multi-stage and multi-cluster manner; the pre-filled solution slug is naphtha;

[0151] (2) A 0.05 PV pre-gas plug is injected into the oil layer, followed by displacement fluid and conventional sand-carrying fluid (a 2% polyacrylamide solution with a number average molecular weight of 24 million);

[0152] The front gas slug is a combination of non-condensable gas, CO2 and CO2 additive; the non-condensable gas is a combination of N2 and natural gas (volume ratio is 1:1);

[0153] The CO2 auxiliary agent includes a combination of a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer; the CO2 solubilizer is acetone; the CO2 foaming agent is dioctyl sodium sulfosuccinate; the CO2 foam stabilizer is a combination of polyethyleneimine and dextran sulfate, with an average particle size of 50 nm;

[0154] The volume ratio of the non-condensable gas to CO2 is 1:10, the amount of CO2 solubilizer is 0.1wt% of the amount of CO2 system, the amount of CO2 foaming agent is 0.1wt% of the amount of CO2 system, the amount of CO2 foam stabilizer is 0.1wt% of the amount of CO2 system, and the CO2 system is a combination of CO2 and CO2 auxiliary agent;

[0155] The displacement fluid is a combination of supercritical CO2 and a thickener aqueous solution in a volume ratio of 0.01:1; the concentration of the thickener aqueous solution is 1500 ppm, wherein the thickener is polyacrylamide, and the number average molecular weight of the polyacrylamide is 15 million;

[0156] (3) Supercritical steam huff and puff for oil recovery;

[0157] A single round of supercritical steam huff and puff includes sequentially injecting supercritical steam 0.1 PV, blocking the well and opening the well for production. When the daily oil production drops to 0.5 t / d, a new round of supercritical steam huff and puff is started;

[0158] A combination of non-condensable gas, CO2, CO2 additive and water vapor is injected every three rounds; the volume ratio of non-condensable gas to CO2 is 1:1, the volume ratio of non-condensable gas to supercritical water vapor is 1:5, and the amount of CO2 additive is 1% of the volume of CO2 after liquefaction.

[0159] In this embodiment, the composition of the non-condensable gas is the same, and the composition of the CO2 auxiliary agent is the same.

[0160] Example 3-3

[0161] This embodiment provides a method for exploiting a deep heavy oil reservoir. The deep heavy oil reservoir has a burial depth of 2000 meters, an average permeability of 300 mD, and a viscosity of crude oil of 8799 mPa·s at 50° C. The reservoir is a heavy oil reservoir with high viscosity and low permeability. It is necessary to adopt an exploitation method of injecting supercritical steam for exploitation. The exploitation method comprises the following steps:

[0162] (1) injecting a pre-filled solution slug into the oil layer, and then performing volume fracturing of the unconventional oil and gas reservoir in a multi-stage and multi-cluster manner; the pre-filled solution slug is naphtha;

[0163] (2) A 0.1 PV pre-gas plug is injected into the oil layer, followed by displacement fluid and conventional sand-carrying fluid (a 2% polyacrylamide solution with a number average molecular weight of 24 million);

[0164] The front gas slug is a combination of non-condensable gas, CO2 and CO2 additive; the non-condensable gas is a combination of N2 and natural gas (volume ratio is 1:1);

[0165] The CO2 auxiliary agent includes a combination of a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer; the CO2 solubilizer is acetone; the CO2 foaming agent is dioctyl sodium sulfosuccinate; the CO2 foam stabilizer is a combination of polyethyleneimine and dextran sulfate, with an average particle size of 150nm;

[0166] The volume ratio of the non-condensable gas to CO2 is 10:1, the amount of CO2 solubilizer is 0.5wt% of the amount of CO2 system, the amount of CO2 foaming agent is 0.5wt% of the amount of CO2 system, the amount of CO2 foam stabilizer is 0.3wt% of the amount of CO2 system, and the CO2 system is a combination of CO2 and CO2 auxiliary agent;

[0167] The displacement fluid is a combination of supercritical CO2 and a thickener aqueous solution in a volume ratio of 1:1; the concentration of the thickener aqueous solution is 1500 ppm, wherein the thickener is polyacrylamide, and the number average molecular weight of the polyacrylamide is 15 million;

[0168] (3) Supercritical steam huff and puff for oil recovery;

[0169] A single round of supercritical steam huff and puff includes sequentially injecting supercritical steam 0.3 PV, blocking the well and opening the well for production. When the daily oil production drops to 0.5 t / d, a new round of supercritical steam huff and puff is started;

[0170] A combination of non-condensable gas, CO2, CO2 additive and water vapor is injected every 5 rounds; the volume ratio of non-condensable gas to CO2 is 1:5, the volume ratio of non-condensable gas to supercritical water vapor is 1:10, and the amount of CO2 additive is 10% of the volume of CO2 after liquefaction.

[0171] In this embodiment, the composition of the non-condensable gas is the same, and the composition of the CO2 auxiliary agent is the same.

[0172] Comparative Example 3-1

[0173] This comparative example provides a method for exploiting a deep heavy oil reservoir, which is the same as Example 3-1 except that the front gas slug does not include non-condensable gas.

[0174] The periodic oil production and recovery rate provided by the above embodiments and comparative examples were statistically analyzed, and the results are shown in Table 1.

[0175] Table 1

[0176] Oil production per cycle (tons) Recovery rate (%) Example 1-1 1200 27.8 Example 1-2 1400 28.3 Examples 1-3 1300 28.1 Comparative Example 1-1 380 21 Example 2-1 1350 28.9 Example 2-2 1530 27.8 Example 2-3 1700 28.3 Comparative Example 2-1 550 20 Example 3-1 1089 29.3 Example 3-2 1099 28.9 Example 3-3 1054 29.1 Comparative Example 3-1 444 24

[0177] In summary, the extraction method provided by the present invention adopts the method of pressure and supercritical steam throughput to produce oil, generates cracks in the strata corresponding to the deep heavy oil reservoir, expands the injection capacity of water vapor, and reduces the pressure of injected steam; moreover, the extraction method provided by the present invention injects a pre-solvent plug before fracturing, thereby achieving a significant viscosity reduction and providing a flow channel for the subsequent injection of a pre-gas plug; and the pre-gas plug can provide energy by relying on the expansion of the gas during the extraction pressure relief process, thereby greatly extending the steam throughput cycle; in addition, the present invention adds non-condensable gas to the pre-gas plug, thereby avoiding the inability of CO2 to release energy under high pressure, relying on the high compressibility of the non-condensable gas to provide energy, playing an energy storage role, and extending the steam throughput cycle.

[0178] The specific embodiments described above further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above description is only a specific embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the protection scope of the present invention.

Claims

1. A method for exploiting deep heavy oil reservoirs, characterized in that: The mining method comprises the following steps: (1) Injecting a pre-fill solution plug into the oil layer and then fracturing it; (2) Injecting a pre-gas slug into the oil layer, followed by injecting sand-carrying fluid and displacement fluid in sequence; (3) Supercritical steam huff and puff for oil recovery; The pre-gas slug in step (2) comprises a combination of non-condensable gas, CO2 and a CO2 additive.

2. The mining method according to claim 1, characterized in that: The pre-solution slug in step (1) comprises any one or a combination of at least two of alkanes, aromatic hydrocarbons, naphtha, petroleum ether, diesel, dimethyl ether or ethanol; Preferably, the alkane has 3-15 carbon atoms.

3. The mining method according to claim 1 or 2, characterized in that: The non-condensable gas includes any one of N2, natural gas, methane or flue gas, or a combination of at least two of them.

4. The mining method according to any one of claims 1 to 3, characterized in that: The CO2 auxiliary agent includes a CO2 solubilizer, a CO2 foaming agent and a CO2 foam stabilizer; Preferably, the CO2 solubilizing agent comprises any one of ethanol, urea, ethane, ethylene glycol or dimethyl ether, or a combination of at least two thereof; Preferably, the CO2 foaming agent comprises anionic surfactants and / or nonionic surfactants; Preferably, the CO2 foam stabilizer comprises anionic polymer electrolyte powder and cationic polymer dielectric powder; Preferably, the average particle size of the CO2 foam stabilizer is 50-150 nm.

5. The mining method according to claim 4, characterized in that: The amount of the CO2 solubilizer used is 0.1-0.5wt% of the amount of the CO2 system, and the CO2 system is a combination of CO2 and a CO2 auxiliary agent; Preferably, the amount of the CO2 foaming agent is 0.1-0.5wt% of the amount of the CO2 system, and the CO2 system is a combination of CO2 and a CO2 auxiliary agent; Preferably, the amount of the CO2 foam stabilizer is 0.1-0.3 wt % of the amount of the CO2 system, and the CO2 system is a combination of CO2 and a CO2 auxiliary agent.

6. The mining method according to any one of claims 1 to 5, characterized in that: The volume ratio of the non-condensable gas to CO2 is 1:10 to 10:1; Preferably, the injection amount of the pre-gas slug in step (2) is 0.05-0.1 PV.

7. The mining method according to any one of claims 1 to 6, characterized in that: The displacement fluid in step (2) is a combination of supercritical CO2 and a thickener aqueous solution; Preferably, the volume ratio of the supercritical CO2 to the viscosified solution is 0.01:1 to 1:1; Preferably, the thickener in the aqueous thickener solution is any one of xanthan gum, cellulose or a polymer, or a combination of at least two thereof; Preferably, the number average molecular weight of the thickener is 1 million to 25 million; Preferably, the concentration of the aqueous thickener solution is 400-1500 ppm.

8. The mining method according to any one of claims 1 to 7, characterized in that: A single round of supercritical steam throughput in step (3) includes sequentially injecting supercritical steam, blocking the well and opening the well for production. When the daily oil production drops below 0.5 t / d, a new round of supercritical steam throughput is started.

9. The mining method according to claim 8, characterized in that: A combination of non-condensable gas, CO2, CO2 auxiliary agent and water vapor is injected every 3-5 rounds.

10. The mining method according to claim 9, characterized in that: The volume ratio of the non-condensable gas to CO2 is 1:(1-5); Preferably, the volume ratio of the non-condensable gas to the supercritical water vapor is 1:(5-10); Preferably, the amount of the CO2 auxiliary agent used is 1-10% of the volume of the liquefied CO2.