Method for improving recovery efficiency through multi-round throughput horizontal well multi-element thermal fluid pressure control and oil drainage

Abstract

The invention provides a multi-round huff and puff horizontal well multi-element thermal fluid pressure control oil drainage recovery ratio improving method. The multi-round huff and puff horizontal well multi-element thermal fluid pressure control oil drainage recovery ratio improving method comprises the steps that 1, a viscosity reducer is injected into an oil reservoir; 2, foam or gas is injected into the oil reservoir; 3, a high-temperature-resistant oil displacement agent is injected into the oil reservoir; 4, high dry steam is injected into the oil reservoir; and 5, opening the well for production after soaking. According to the multi-round huff and puff horizontal well multi-element thermal fluid pressure control oil drainage recovery efficiency improving method, the viscosity reduction and oil washing efficiency is enhanced, the development effect is improved, the recovery efficiency of a heavy oil reservoir after multi-round huff and puff can be effectively improved, and the horizontal well pressure control oil drainage huff and puff technology is adopted, so that the multi-round huff and puff horizontal well multi-element thermal fluid pressure control oil drainage recovery efficiency improving method is formed.

Description

Technical Field

[0001] The invention relates to the technical field of oilfield development, and in particular to a method for improving oil recovery by controlling pressure and draining oil from multi-element thermal fluids in a multi-round throughput horizontal well. Background Art

[0002] Shengli heavy oil is mainly developed by steam huff and puff, with an average huff and puff cycle of 6.8, and is in the multi-cycle huff and puff stage. Affected by factors such as low reservoir pressure and serious steam channeling, it has low thermal efficiency of injected steam and poor development effect. Horizontal wells have become an important means of increasing and stabilizing production due to their advantages such as high well-controlled reserves and large oil drainage area.

[0003] Horizontal well development mainly includes horizontal well throughput, horizontal well steam drive, HDCS, HDNS, SAGD technology, etc. Affected by factors such as reservoir heterogeneity, conventional horizontal well throughput and steam drive mainly have serious steam channeling problems and uneven use of horizontal well sections; HDCS and HDNS are mainly used in super-heavy oil reservoirs due to their high investment costs, and due to the high steam injection pressure, the steam chamber will not develop upward, but more likely to develop on both sides of the horizontal well; SAGD technology has a high recovery rate, but has high requirements for reservoirs, especially the reservoir thickness needs to be greater than 15 meters, but Shengli oil reservoirs have poor physical properties, most of which are less than 15 meters or have interlayers, and the economic benefits of carrying out SAGD are poor.

[0004] Horizontal well multi-element thermal fluid controlled pressure drainage oil huff and puff is a new efficiency-enhancing technology for heavy oil reservoirs after multiple rounds of huff and puff: During the steam injection stage, a combination of high-dryness steam, viscosity reducer (oil-soluble or water-soluble), high-temperature oil displacement agent, and foam (nitrogen, carbon dioxide, or nitrogen + carbon dioxide) is injected into the reservoir through a horizontal well at a pressure slightly higher than the reservoir pressure. A high-temperature steam chamber is constructed above the horizontal well, and the crude oil after viscosity reduction flows from the edge of the steam chamber to the lower part of the reservoir by gravity, and is then produced by the horizontal well during the production stage, thereby improving the recovery rate of the reservoir after multiple rounds of steam huff and puff. The main function of high-dry steam is to heat and reduce viscosity, and at the same time, construct a cavity with low oil saturation above the horizontal well to form an oil leakage space; the function of the viscosity reducer is to strengthen viscosity reduction, reduce the starting pressure, reduce the difficulty of subsequent steam injection, and expand the range of the steam cavity; the main function of the oil displacement agent is to improve the oil washing efficiency and improve the development effect; the main function of the foam is to adjust the development of the steam cavity, and slowly release the gas at the same time, inhibit steam channeling while maintaining the formation energy, and ensure the integrity of the steam cavity. Among them, nitrogen focuses on maintaining the formation pressure and reducing the heat loss at the bottom of the reservoir, and carbon dioxide focuses on maintaining the formation pressure and assisting in reducing the viscosity of crude oil. According to the reservoir properties and development needs, different fluids can be combined and optimized. When the throughput cycle is small, the combination mode of oil-soluble viscosity reducer + steam + nitrogen (shallow layer) or carbon dioxide (deep layer) is used to increase the cycle oil production. When the throughput cycle is large, the combination mode of water-soluble viscosity reducer + steam + high temperature resistant oil displacement agent + foam is used to increase the cycle oil production.

[0005] Compared with conventional horizontal well development, the advantages of horizontal well controlled pressure drainage and oil throughput are: low investment cost, no need to drill new wells, only the existing single horizontal well is needed, and throughput is a mode of intermittent steam injection, assisted by the injection of gases such as nitrogen and carbon dioxide, which further reduces the amount of steam injection and reduces the steam cost; high thermal efficiency, due to the injection at a pressure slightly higher than the reservoir pressure, the steam chamber develops upward, the influence of reservoir heterogeneity is weakened, the steam channeling problem is alleviated, and the foam or nitrogen and carbon dioxide gases are located at the top of the reservoir, reducing heat loss and improving development efficiency; high recovery rate, the combined injection of steam, viscosity reducer and oil displacement agent can effectively reduce the viscosity of crude oil, reduce the residual oil saturation in the steam chamber, and improve the steam throughput development effect.

[0006] In the Chinese patent application with application number: 201210432484, a method for late-stage production of thin-layer heavy oil reservoirs with multiple rounds of huff and puff is involved. The method comprises: step 1, injecting steam into the well; step 2, injecting nitrogen and microemulsion viscosity reducer while injecting steam; step 3, shutting the well; and step 4, lifting the steam injection pipe string, lowering the production pipe string, and switching to pumping production. The method for late-stage production of thin-layer heavy oil reservoirs with multiple rounds of huff and puff aims at the contradiction that the production of thin-layer heavy oil in the late stage of multiple rounds of huff and puff is fast decreasing, the water content is fast increasing, and the energy is reduced, resulting in poor production effect. Before the conditions for switching to steam drive are reached, "nitrogen + microemulsion viscosity reducer" is used to assist steam enhanced thermal recovery, supplement the energy of the oil layer, improve the steam sweep coefficient and thermal efficiency and displacement efficiency, thereby improving the effect of multiple rounds of huff and puff production of thin-layer heavy oil. This method is still conventional steam huff and puff, without the concept of constructing a steam chamber, and the type and function of the injected fluid are also different.

[0007] In the Chinese patent application with application number: CN202010846747.4, a method for increasing the throughput radius after high-cycle throughput is involved. The method comprises: step 1. steam injection, well shut-in, and well opening for production in the target oil reservoir production vertical wells; step 2. determining the throughput rounds and corresponding mobilization radius of the target oil reservoir at which the utilization radius slows down; step 3. after the throughput cycle reaches the rounds at which the utilization radius slows down as determined above, stop steam throughput and perform water jet perforation; step 4. for the throughput wells that have completed water jet perforation, steam injection, well shut-in, and well opening for production are performed. This inventive method effectively increases the scope of steam injection, reduces heat loss caused by repeated heating, effectively increases the utilization radius in the later stage of throughput, and increases the cumulative oil production of a single well. The steam injection concept in this method is still based on conventional steam throughput.

[0008] In the Chinese patent application with application number: CN201910547116.X, a system and method for improving the recovery rate of heavy oil reservoirs by hot nitrogen foam in the late stage of multiple rounds of steam stimulation are involved. The method comprises the following steps: (1) pretreatment slug: injecting pressurized and heated nitrogen into the formation; (2) foam solution slug: injecting a foaming agent aqueous solution into the formation; (3) steam hot nitrogen slug: injecting hot nitrogen mixed with steam into the formation, wherein the volume ratio of hot nitrogen to steam is (20-50):1; (4) well soaking: after the injection of step (3), the well is soaked for 2-4 days; (5) well opening for production: after the completion of step (4), the well is opened for production. The method described in the invention can increase the energy of the formation, reduce the viscosity of crude oil, reduce the water saturation of the oil layer, reduce the drainage period, and increase the oil recovery of multiple rounds of steam stimulation. The method targets the two problems of low reservoir pressure and large heat loss at the top, without changing the steam injection method, and at the same time, no measures for enhanced viscosity reduction and enhanced oil washing are carried out.

[0009] In the Chinese patent application with application number: 202010235430.7, a quantitative allocation method for the targeted steam injection amount of horizontal well segments after multiple rounds of huff-and-puff is involved, including: performing well temperature test and residual oil saturation test on the horizontal well; drawing the well temperature curve and the residual oil saturation curve on the same horizontal axis; experimentally testing the critical temperature of the heavy oil non-Newtonian fluid to Newtonian fluid; dividing the high temperature zone and the low temperature zone on the well temperature test curve; determining the high residual oil saturation zone and the low residual oil saturation zone on the residual oil saturation curve, and dividing several segmented curves; obtaining the fitting function; performing area integration on the polygon composed of the segmented curve and the horizontal axis to obtain the area of ​​the polygon; calculating the area ratio of each polygon; determining the steam injection amount of the horizontal well segment, and realizing the quantitative allocation of the steam injection amount of the horizontal well segment. This method is a targeted quantitative steam injection allocation method for optimizing the steam injection amount in the horizontal well segment by segmented quantitative injection, improving the thermal utilization rate of steam injection, and improving the development effect within the layer. This method improves the balanced steam injection method for horizontal wells and realizes quantitative allocation, but both the injected fluid and the steam injection method use conventional steam huff and puff.

[0010] There is no precedent for controlled pressure drainage and oil throughput technology in horizontal wells at home and abroad, and there is a lack of theoretical and practical guidance. For this reason, we have invented a multi-round horizontal well multi-element thermal fluid controlled pressure drainage and oil recovery method to solve the above technical problems. Summary of the invention

[0011] The purpose of the present invention is to provide a method for improving the development effect and effectively improving the recovery rate of heavy oil reservoirs after multiple rounds of throughput by multi-component thermal fluid controlled pressure drainage in horizontal wells.

[0012] The object of the present invention can be achieved by the following technical measures: A method for improving oil recovery by multi-component thermal fluid controlled pressure drainage of a horizontal well with multiple rounds of throughput, comprising:

[0013] Step 1, injecting a viscosity reducer into the oil reservoir;

[0014] Step 2, injecting foam or gas into the reservoir;

[0015] Step 3, injecting a high temperature resistant oil displacement agent into the oil reservoir;

[0016] Step 4, injecting high-dry steam into the oil reservoir;

[0017] Step 5, start production after wellbore maintenance.

[0018] The purpose of the present invention can also be achieved by the following technical measures:

[0019] In step 1, the development status of the target block is collected, and the type of viscosity reducer is selected according to the main development contradictions. For wells with fewer throughput cycles, the demand for viscosity reduction is higher, and oil-soluble viscosity reducers are used; for wells with more throughput cycles, the demand for expansion is higher, and water-soluble viscosity reducers are used; the injection volume of the viscosity reducer is optimized using numerical simulation software.

[0020] In step 2, the injection fluid type is selected according to the reservoir properties. For wells with more serious steam channeling, foam can be injected, with nitrogen foam injected into the shallow layer and carbon dioxide foam injected into the deep layer. For wells with less steam channeling, nitrogen or carbon dioxide can be injected, with nitrogen injected into the shallow layer and carbon dioxide injected into the deep layer. Numerical simulation software is used to optimize the injection amounts of nitrogen and carbon dioxide.

[0021] In step 3, the injection of oil displacement agent is determined according to the needs of reservoir development. If the throughput cycle is short, no oil displacement agent is required; if the throughput cycle is long, high-temperature resistant oil displacement agent is injected; numerical simulation software is used to optimize the injection amount of oil displacement agent.

[0022] In step 4, the oil production at different steam chamber inclination angles is calculated to determine the optimal oil leakage angle, thereby guiding the steam injection amount.

[0023] In step 4, the heat exchange in the direction perpendicular to the steam chamber interface can be expressed by the following formula:

[0024]

[0025] Where x is the horizontal distance; K is the thermal conductivity of the reservoir; T is the temperature distribution at the edge of the steam chamber; x is the distance; V c is the convection velocity in the direction perpendicular to the steam chamber; ρ c is the density of the condensate; c pc is the heat capacity of the condensate; ρ r is the reservoir density; c pr is the reservoir heat capacity; t is the production time;

[0026] The coordinate axis distance x is transformed into the distance ξ from the steam chamber interface, and the steam chamber interface migration velocity U is introduced x ; The following is the relationship between x and ξ:

[0027]

[0028] According to formula (2), the derivative in formula (1) can be transformed:

[0029]

[0030]

[0031]

[0032] Substituting the above three equations into equation (1), we can get:

[0033]

[0034] After sorting:

[0035]

[0036] The edge of the steam chamber can be assumed to be a quasi-steady-state heat conduction, so:

[0037]

[0038] Substituting formula (8) into formula (7) yields the heat exchange formula at the edge of the steam chamber during the production process:

[0039]

[0040] In step 4, when convection is neglected, the velocity of the fluid in the direction perpendicular to the steam chamber interface is zero:

[0041] V c =0 (10)

[0042] Substituting into equation (9) yields the Butler temperature distribution model:

[0043]

[0044] The above equation can be solved using the substitution integration method:

[0045]

[0046]

[0047] Where T* is the dimensionless temperature; T r is the crude oil reservoir temperature; T st is the injection steam temperature; α is the thermal diffusion coefficient of the reservoir.

[0048] In step 4, the convection velocity at the edge of the steam chamber perpendicular to the steam chamber interface can be calculated using the following formula:

[0049] V c =V cp +V cg (14)

[0050] Among them, V cp V is the convection velocity in the direction perpendicular to the steam chamber caused by the pressure difference; cg is the convection velocity in the direction perpendicular to the steam chamber caused by the gravity component;

[0051] Based on the knowledge of fluid mechanics, the convection velocity caused by pressure difference and gravity component can be calculated:

[0052]

[0053] V cg =λgcosθ (16)

[0054]

[0055] Where θ is the angle between the steam chamber interface and the horizontal direction; P is the pressure; λ is the fluidity of the convective phase at different positions; g is the gravitational acceleration; k is the absolute permeability at any position; k rw is the relative permeability of water phase at any position; k ro is the relative permeability of the oil phase at any position; μ o is the dynamic viscosity of the oil phase; μ w is the dynamic viscosity of the water phase;

[0056] The oil saturation distribution equation at the edge of the steam chamber is:

[0057] S o =S or +(S io -S or )(1-T * ) (18)

[0058] According to Corey's formula, the relative permeability of water phase and oil phase can be calculated by the following formula:

[0059] k rw =k rwro (S wD ) b (19)

[0060]

[0061] k ro =k rocw S oD a (1-T * ) a (twenty one)

[0062]

[0063] Among them, a is the Corey coefficient; b is the Corey coefficient; k rwro is the relative permeability of water phase under residual oil saturation; S wD is the dimensionless water saturation; S w is water saturation; S wc is the bound water saturation; S or is the residual oil saturation, k rocwis the relative permeability of the oil phase at irreducible water saturation; S oD is the dimensionless oil saturation;

[0064] From the definition, we can see that there is the following relationship between dimensionless oil saturation and dimensionless water saturation:

[0065] S wD =1-S oD (1-T * ) (twenty three)

[0066] Substituting into equation (19), the relative permeability of water phase is obtained as follows:

[0067] k rw =k rwro [1-S oD (1-T * )] b (twenty four).

[0068] In step 4, the properties of the convective phase are an important factor affecting the strength of convection, and density and heat capacity are the two parameters with the greatest influence. In previous studies, simplifying the convective phase to a pure water phase also simplified the properties of the convective phase. When considering the influence of two-phase flow on heat exchange, the calculation of the properties of the convective phase also becomes more complicated. Based on existing research results, the density and heat capacity of the convective phase can be calculated by the following formula:

[0069]

[0070]

[0071] Among them, ρ c is the density of the convective phase; ρ o is the density of the oil phase; ρ w is the density of water phase; c pc is the heat capacity of the convective phase; c o is the heat capacity of the oil phase; c w is the heat capacity of water phase;

[0072] Substituting equation (16) into the above two equations, we can obtain the distribution functions of the convective phase density and heat capacity at the edge of the steam chamber:

[0073] ρ c =ρ o S oD (1-T * )+ρ w [1-S oD (1-T * )] (27)

[0074] c pc =c o S oD(1-T * )+c w [1-S oD (1-T * )] (28)

[0075] The density and heat capacity of the oil phase and the water phase are also affected by temperature. The research in this area is relatively mature and can be obtained by consulting the literature:

[0076] ρ o =1024-0.645T (29)

[0077] ρ w =1001.7-0.1616T-0.00262T 2 (30)

[0078] c o =1.605+0.004361T-4.046×10 -6 T 2 (31)

[0079] c w =4.182-1.5×10 -4 T+3.44×10 -7 T 2 +4.26×10 -8 T 3 (32)

[0080] According to the research of Butler and Reid, the relationship between oil phase viscosity and water phase viscosity and temperature distribution can be obtained:

[0081]

[0082]

[0083] Where, m is the viscosity-temperature index;

[0084] Substituting equations (21), (24), (33) and (34) into equation (17), we can obtain:

[0085]

[0086] According to the research, the relationship between oil phase viscosity and water phase viscosity and temperature distribution can be obtained:

[0087]

[0088] The formula for the convection velocity caused by pressure difference also includes the derivative of pressure. Based on the relationship between viscosity and temperature distribution (33), it can be assumed that the following relationship exists between crude oil viscosity and pressure distribution:

[0089]

[0090] Among them, ν st is the kinematic viscosity of the oil phase at the steam temperature; ν o is the kinematic viscosity of the oil phase at different positions on the edge of the steam chamber; n is the pressure-temperature index;

[0091] From equations (33) and (37), we can get the relationship between the pressure distribution and temperature distribution at the edge of the steam chamber:

[0092]

[0093] By differentiating both sides of the above equation with respect to the distance ξ, we can obtain the derivative of pressure:

[0094]

[0095] Substituting formula (12) into the above formula, we can get:

[0096]

[0097] From this, the calculation formula for the convection velocity caused by pressure difference can be obtained:

[0098]

[0099] To solve the model, the apparent thermal diffusion coefficient α* is introduced,

[0100]

[0101] The flow rate calculation formula is:

[0102]

[0103] The liquid and oil production during the production process are:

[0104] q liq =∫λρ c gsinθdξ (44)

[0105] q o =∫λρ c gsinθS oD (1-T * )dξ (45).

[0106] In step 5, the well is shut down for 1 to 2 days to ensure that the crude oil at the front edge of the steam chamber is sufficiently reduced in viscosity, and the crude oil in the upper part of the horizontal well flows to the lower part of the reservoir under the action of gravity. The horizontal well is started for production, and the bottom hole flow pressure of the horizontal well cannot be too low to ensure stable pressure production as much as possible.

[0107] The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage of horizontal wells with multiple rounds of throughput also includes, after step 5, step 6, performing round-trip development with daily oil production as a cutoff condition.

[0108] In step 6, when the daily oil production drops to 1t / d, the development is switched to ensure a certain production capacity while maintaining the formation temperature to provide a basis for subsequent cavity creation.

[0109] The multi-round huff-and-puff horizontal well multi-element thermal fluid pressure-controlled oil drainage method of the present invention injects high-dry steam (more than 90%), viscosity reducer (oil-soluble or water-soluble, 10-40t), high-temperature resistant oil displacement agent (10-30t of stock solution), foam (nitrogen, carbon dioxide or nitrogen + carbon dioxide, nitrogen is 100,000-150,000Nm 3 , carbon dioxide is 100-200t) of combined fluid, a high-temperature steam chamber is constructed above the horizontal well, and the reduced-viscosity crude oil flows from the edge of the steam chamber to the lower part of the reservoir by gravity, and then is produced by the horizontal well during the production stage, thereby improving the recovery rate of the reservoir after multiple rounds of steam stimulation. The beneficial effects of the present invention are:

[0110] Through quantitative calculation and injection of a combination fluid of viscosity reducer (oil-soluble, water-soluble), foam (nitrogen, carbon dioxide), high-temperature resistant oil displacement agent, and steam, a steam chamber is constructed above the horizontal well, an oil drainage channel is formed at the front edge of the steam chamber, and the oil flows to the lower part of the reservoir under the action of gravity and is produced by the horizontal well, thereby enhancing the viscosity reduction and oil washing efficiency and improving the development effect. The present invention can effectively improve the recovery rate of heavy oil reservoirs after multiple rounds of throughput, and the horizontal well controlled pressure drainage throughput technology forms a method for improving the recovery rate of multi-element thermal fluid controlled pressure drainage of horizontal wells with multiple rounds of throughput. BRIEF DESCRIPTION OF THE DRAWINGS

[0111] Figure 1 It is a flow chart of a specific embodiment of the method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of huff and puff of the present invention;

[0112] Figure 2 It is a schematic diagram of controlled pressure oil drainage and steam injection in a horizontal well in a specific embodiment of the present invention;

[0113] Figure 3 It is a schematic diagram of controlled pressure drainage throughput production of a horizontal well in a specific embodiment of the present invention;

[0114] Figure 4 It is a horizontal well controlled pressure drainage production angle influence curve in a specific embodiment of the present invention;

[0115] Figure 5 It is a schematic diagram of a recovery degree improvement curve in a specific embodiment 1 of the present invention;

[0116] Figure 6 It is a schematic diagram of a recovery degree improvement curve in a specific embodiment 2 of the present invention;

[0117] Figure 7 It is a schematic diagram of a recovery degree improvement curve in a specific embodiment 3 of the present invention;

[0118] Figure 8 It is a schematic diagram of a recovery degree improvement curve in a specific embodiment 4 of the present invention. DETAILED DESCRIPTION

[0119] It should be noted that the following detailed descriptions are exemplary and are intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meanings as those commonly understood by those skilled in the art to which the present invention belongs.

[0120] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, it should be understood that when the terms "comprising" and / or "including" are used in this specification, it indicates the presence of features, steps, operations and / or combinations thereof.

[0121] The multi-round huff-and-puff horizontal well multi-element thermal fluid pressure-controlled oil drainage method of the present invention adopts different combinations of viscosity reducer (oil-soluble + water-soluble) + steam + (high-temperature viscosity reducer, oil-displacing agent) or foam (nitrogen + carbon dioxide, or nitrogen, carbon dioxide) to increase the periodic oil production. Steam heating reduces viscosity and creates a cavity to form an oil drainage space, which is strengthened by using a high-temperature viscosity reducer and an oil-displacing agent; gas insulation and (carbon dioxide) reduce viscosity and form continuous energy replenishment; viscosity reducer (oil-soluble + water-soluble) reduces viscosity, oil-soluble reduces the difficulty of cavity creation, reduces the starting pressure, and expands the cavity creation range, and water-soluble forms a far-end low-temperature field to reduce viscosity; for example: when the cycle is small, the combination of viscosity reducer (oil-soluble) + steam + nitrogen (shallow layer) or carbon dioxide (deep layer) is used to increase the periodic oil production. When the cycle is long, different combinations of viscosity reducer (water-soluble) + steam + (high-temperature viscosity reducer, oil-displacing agent) + foam (nitrogen + carbon dioxide, or nitrogen, carbon dioxide) increase the periodic oil production.

[0122] The ultra-heavy oil is a combination of HDNCS. It is demonstrated with different cavity-making schematic diagrams. From the perspective of the reservoir, the optimization process of the stripping cavity of the steam cavity is explored, and how to create the optimal steam cavity inclination angle, and strengthen the control of pressure and oil drainage, which is the core key point of the present invention. The optimal angle calculation process is demonstrated with mathematical formulas to support the invention point.

[0123] like Figure 1 As shown, Figure 1The flowchart of the method for improving oil recovery by controlling pressure and draining oil of multi-component thermal fluids in horizontal wells with multiple rounds of throughput of the present invention is as follows. The method for improving oil recovery by controlling pressure and draining oil of multi-component thermal fluids in horizontal wells with multiple rounds of throughput of the present invention comprises the following steps:

[0124] Step 1: Inject viscosity reducer into the reservoir; collect the development status of the target block, select the viscosity reducer type according to the main development contradictions, and use oil-soluble viscosity reducer for wells with fewer throughput cycles and higher viscosity reduction requirements; use water-soluble viscosity reducer for wells with more throughput cycles and higher requirements for expansion; and use numerical simulation software to optimize the injection volume of the viscosity reducer.

[0125] Step 2, inject foam or gas into the oil reservoir; the type of injected fluid is selected according to the reservoir properties. Foam can be injected into wells with more serious steam channeling, with nitrogen foam injected into the shallow layer and carbon dioxide foam injected into the deep layer. For wells with weaker steam channeling, nitrogen or carbon dioxide can be injected, with nitrogen injected into the shallow layer and carbon dioxide injected into the deep layer. Numerical simulation software is used to optimize the injection amount of nitrogen and carbon dioxide.

[0126] Step 3, injecting a high temperature resistant oil displacement agent into the reservoir; judging the injection of the oil displacement agent according to the reservoir development needs, if the throughput cycle is short, no oil displacement agent may be injected, if the throughput cycle is long, injecting a high temperature resistant oil displacement agent, and using numerical simulation software to optimize the injection amount of the oil displacement agent.

[0127] Step 4, inject high-dry steam into the reservoir; by calculating the oil production at different steam chamber inclination angles, determine the optimal oil leakage angle, and thus guide the steam injection amount.

[0128] like Figure 2 , Figure 3 As shown, Figure 2 It is a schematic diagram of controlled pressure oil drainage and steam injection in a horizontal well in a specific embodiment of the present invention. Figure 3 This is a schematic diagram of controlled pressure drainage and oil throughput production of horizontal wells in a specific embodiment of the present invention. Figure 2 , Figure 3 It can be seen that steam, nitrogen and carbon dioxide migrate upward under the action of gravity difference and are distributed in the high-temperature cavity above the horizontal well; the viscosity reducer, condensed water and reduced-viscosity crude oil are located in the transition area between the high-temperature cavity and the original oil reservoir, and flow to the vicinity of the horizontal well under the action of gravity.

[0129] The optimal oil leakage angle can be calculated in the following way.

[0130] The heat exchange in the direction perpendicular to the steam chamber interface can be expressed by the following formula:

[0131]

[0132] Where x is the horizontal distance; K is the thermal conductivity of the reservoir; T is the temperature distribution at the edge of the steam chamber; x is the distance; Vc is the convection velocity in the direction perpendicular to the steam chamber; ρ c is the density of the condensate; c pc is the heat capacity of the condensate; ρ r is the reservoir density; c pr is the reservoir heat capacity; t is the production time.

[0133] The coordinate axis distance x is transformed into the distance ξ from the steam chamber interface, and the steam chamber interface migration velocity U is introduced x The following equation is the relationship between x and ξ:

[0134]

[0135] According to formula (2), the derivative in formula (1) can be transformed:

[0136]

[0137]

[0138]

[0139] Substituting the above three equations into equation (1), we can get:

[0140]

[0141] After sorting:

[0142]

[0143] The edge of the steam chamber can be assumed to be a quasi-steady-state heat conduction, so:

[0144]

[0145] Substituting formula (8) into formula (7) yields the heat exchange formula at the edge of the steam chamber during the production process:

[0146]

[0147] When convection is neglected, the velocity of the fluid in the direction perpendicular to the steam chamber interface is zero:

[0148] V c =0 (10)

[0149] Substituting into equation (9) yields the Butler temperature distribution model:

[0150]

[0151] The above equation can be solved using the substitution integration method:

[0152]

[0153]

[0154] Where T* is the dimensionless temperature; T r is the crude oil reservoir temperature; T st is the injection steam temperature; α is the thermal diffusion coefficient of the reservoir.

[0155] The convection velocity at the edge of the steam chamber perpendicular to the steam chamber interface can be calculated using the following formula:

[0156] V c =V cp +V cg (14)

[0157] Among them, V cp V is the convection velocity in the direction perpendicular to the steam chamber caused by the pressure difference; cg It is the convection velocity in the direction perpendicular to the steam chamber caused by the gravity component.

[0158] Based on the knowledge of fluid mechanics, the convection velocity caused by pressure difference and gravity component can be calculated:

[0159]

[0160] V cg =λgcosθ (16)

[0161]

[0162] Where θ is the angle between the steam chamber interface and the horizontal direction; λ is the fluidity of the convective phase at different positions; k ro is the relative permeability of the oil phase at any position; μ o is the dynamic viscosity of the oil phase; μ w is the dynamic viscosity of the water phase.

[0163] The oil saturation distribution equation at the edge of the steam chamber is:

[0164] S o =S or +(S io -S or )(1-T * ) (18)

[0165] According to Corey's formula, the relative permeability of water phase and oil phase can be calculated by the following formula:

[0166] k rw =k rwro (S wD ) b (19)

[0167]

[0168] k ro =k rocw S oD a (1-T * ) a (twenty one)

[0169]

[0170] Among them, a is the Corey coefficient; b is the Corey coefficient; k rwro is the relative permeability of water phase under residual oil saturation; S wD is the dimensionless water saturation; S w is water saturation; S wc is the bound water saturation; S or is the residual oil saturation, k rocw is the relative permeability of the oil phase at irreducible water saturation; S oD is the dimensionless oil saturation.

[0171] From the definition, we can see that there is the following relationship between dimensionless oil saturation and dimensionless water saturation:

[0172] S wD =1-S oD (1-T * ) (twenty three)

[0173] Substituting into equation (19), the relative permeability of water phase is obtained as follows:

[0174] k rw =k rwro [1-S oD (1-T * )] b (twenty four)

[0175] The properties of the convective phase are an important factor affecting the strength of convection, and density and heat capacity are the two parameters with the greatest impact. In previous studies, simplifying the convective phase to a pure water phase also simplified the properties of the convective phase. When considering the influence of two-phase flow on heat exchange, the calculation of the properties of the convective phase also becomes more complicated. Based on existing research results, the density and heat capacity of the convective phase can be calculated by the following formula:

[0176]

[0177]

[0178] Among them, ρ c is the density of the convective phase; ρ ois the density of the oil phase; ρ w is the density of water phase; c pc is the heat capacity of the convective phase; c o is the heat capacity of the oil phase; c w is the water phase heat capacity.

[0179] Substituting equation (16) into the above two equations, we can obtain the distribution functions of the convective phase density and heat capacity at the edge of the steam chamber:

[0180] ρ c =ρ o S oD (1-T * )+ρ w [1-S oD (1-T * )] (27)

[0181] c pc =c o S oD (1-T * )+c w [1-S oD (1-T * )] (28)

[0182] The density and heat capacity of the oil phase and the water phase are also affected by temperature. The research in this area is relatively mature and can be obtained by consulting the literature:

[0183] ρ o =1024-0.645T (29)

[0184] ρ w =1001.7-0.1616T-0.00262T 2 (30)

[0185] c o =1.605+0.004361T-4.046×10 -6 T 2 (31)

[0186] c w =4.182-1.5×10 -4 T+3.44×10 -7 T 2 +4.26×10 -8 T 3 (32)

[0187] According to the research of Butler and Reid, the relationship between oil phase viscosity and water phase viscosity and temperature distribution can be obtained:

[0188]

[0189]

[0190] Substituting equations (21), (24), (33) and (34) into equation (17), we can obtain:

[0191]

[0192] According to the research, the relationship between oil phase viscosity and water phase viscosity and temperature distribution can be obtained:

[0193]

[0194] The formula for the convection velocity caused by pressure difference also includes the derivative of pressure. Based on the relationship between viscosity and temperature distribution (33), it can be assumed that the following relationship exists between crude oil viscosity and pressure distribution:

[0195]

[0196] Among them, ν st is the kinematic viscosity of the oil phase at the steam temperature; ν o is the kinematic viscosity of the oil phase at different positions on the edge of the steam chamber; n is the pressure-temperature index.

[0197] From equations (33) and (37), we can get the relationship between the pressure distribution and temperature distribution at the edge of the steam chamber:

[0198]

[0199] By differentiating both sides of the above equation with respect to the distance ξ, we can obtain the derivative of pressure:

[0200]

[0201] Substituting formula (12) into the above formula, we can get:

[0202]

[0203] From this, the calculation formula for the convection velocity caused by pressure difference can be obtained:

[0204]

[0205] To solve the model, the apparent thermal diffusion coefficient α* is introduced,

[0206]

[0207] The flow rate calculation formula is:

[0208]

[0209] The liquid and oil production during the production process are:

[0210] q liq =∫λρ c gsinθdξ (44)

[0211] q o =∫λρ c gsinθS oD (1-T * )dξ (45)

[0212] like Figure 4 As shown, Figure 4 This is a curve of production angle influence of controlled pressure drainage of horizontal wells in a specific embodiment of the present invention. The optimal drainage angle is 60% to 80%, which can achieve a higher oil production rate and a smaller steam injection amount.

[0213] Step 5, start the well for production after shutting down the well; shut down the well for 1 to 2 days to ensure that the crude oil at the front edge of the steam chamber is sufficiently reduced in viscosity, and the crude oil in the upper part of the horizontal well flows to the lower part of the reservoir under the action of gravity. The horizontal well is started for production, and the bottom hole flow pressure of the horizontal well cannot be too low to ensure stable pressure production as much as possible.

[0214] Step 6: Take the daily oil production as the cut-off condition and carry out the development of the rotation cycle. When the daily oil production drops to 1t / d, the development of the rotation cycle is carried out to ensure a certain production capacity while maintaining the formation temperature to provide a basis for subsequent cavity creation.

[0215] Based on the development status of the target block, the present invention optimizes the type of viscosity reducer, strengthens viscosity reduction, reduces the difficulty of cavity making, injects foam or nitrogen, carbon dioxide, maintains the formation energy while reducing the heat loss of the top cap rock, assists in injecting high-temperature resistant oil displacement agent, strengthens the oil washing effect, optimizes the steam injection amount according to the requirements of the steam chamber oil leakage inclination angle, and ultimately solves the problems of poor development effect, serious steam channeling, low reservoir pressure, etc. after multiple rounds of huff and puff in heavy oil reservoirs.

[0216] The features and performance of the present invention are further described in detail below in conjunction with specific embodiments.

[0217] Embodiment 1

[0218] Taking the huff-and-puff well A as an example, the present invention carries out the horizontal well controlled pressure drainage huff-and-puff development, including the following steps:

[0219] Step 1: Well A has a perforation depth of 491 to 518 meters and has been through 7 cycles. It mainly faces problems such as shallow reservoir depth, large heat loss, and low thermal efficiency. The well has a good material foundation around it, so an oil-soluble viscosity reducer is selected to enhance the viscosity reduction effect. The optimized injection amount of the oil-soluble viscosity reducer is 25 tons.

[0220] Step 2: Auxiliary nitrogen injection to increase formation energy, maintain reservoir pressure, and reduce heat loss at the top of the reservoir. The optimized nitrogen injection rate is 30,000 Nm3 ;

[0221] Step 3: Due to the high oil saturation near the huff-and-puff well, the oil displacement agent is not injected for the time being based on the principle of reducing costs;

[0222] Step 4: Calculate and optimize the steam chamber inclination angle to about 63° and the injected steam volume to 1700t;

[0223] Step 5: After the well is soaked for 1 to 2 days, the well is opened for production;

[0224] Step 6: After the oil production drops to 1t / d, re-inject the viscosity reducer to start the turnaround development. Figure 5 It can be seen that compared with conventional throughput, three cycles of controlled pressure drainage throughput can increase the recovery degree by 2.6, and the recovery factor within the well control range is expected to be 47%.

[0225] Embodiment 2

[0226] Taking the huff-and-puff well B as an example, the present invention carries out the horizontal well controlled pressure drainage huff-and-puff development, including the following steps:

[0227] Step 1: Well B has a perforation depth of 517-532 meters and has been through 19 cycles. It is mainly faced with problems such as severe steam channeling temperature, low reservoir pressure, and low thermal efficiency. The oil saturation near the wellbore is low, so a water-soluble viscosity reducer is preferred to expand the oil leakage area. The optimized injection amount of the water-soluble viscosity reducer is 15t;

[0228] Step 2: Assisted injection of nitrogen foam to adjust the reservoir consistency, increase formation energy, maintain reservoir pressure, and reduce heat loss at the top of the reservoir. The optimized nitrogen injection volume is 50,000 Nm 3 ;

[0229] Step 3: Due to the low oil saturation, a high temperature resistant oil displacement agent is injected to improve the oil washing efficiency and development effect. The optimized injection amount of the oil displacement agent is 10t;

[0230] Step 4: Calculate and optimize the steam chamber inclination angle to about 71° and the injected steam volume to 2300t;

[0231] Step 5: After the well is soaked for 1 to 2 days, the well is opened for production;

[0232] Step 6: After the oil production drops to 1t / d, re-inject the viscosity reducer to start the turnaround development. Figure 6 It can be seen that compared with conventional throughput, three cycles of controlled pressure drainage throughput can increase the recovery degree by 3.3, and the recovery factor within the well control range is expected to be 52%.

[0233] Embodiment 3

[0234] Taking the huff-and-puff well C as an example, the present invention carries out the horizontal well controlled pressure drainage huff-and-puff development, including the following steps:

[0235] Step 1: Well C has a perforation depth of 1030-1080 meters and has been through 6 cycles. It is mainly faced with problems such as large heat loss along the way and low bottom hole dryness. The well has a good material foundation around it, so oil-soluble viscosity reducer is preferred to enhance the viscosity reduction effect. The optimized injection amount of oil-soluble viscosity reducer is 20t;

[0236] Step 2: Auxiliary injection of carbon dioxide to increase formation energy, reduce top heat loss, and enhance viscosity reduction effect, and optimize the carbon dioxide injection amount to 170t;

[0237] Step 3: Due to the high oil saturation near the huff-and-puff well, the oil displacement agent is not injected for the time being based on the principle of reducing costs;

[0238] Step 4: Calculate and optimize the steam chamber inclination angle to about 58° and the injected steam volume to 2300t;

[0239] Step 5: After the well is soaked for 2 to 3 days, the well is opened for production;

[0240] Step 6: After the oil production drops to 1t / d, re-inject the viscosity reducer to start the turnaround development. Figure 7 It can be seen that compared with conventional throughput, 4 cycles of controlled pressure drainage throughput can increase the recovery degree by 2.8, and the recovery factor within the well control range is expected to be 46%.

[0241] Embodiment 4

[0242] The present invention takes the huff-and-puff well D as an example to carry out horizontal well controlled pressure drainage huff-and-puff development, including the following steps:

[0243] Step 1: Well D has a perforation depth of 1170-1210 meters and has been through 10 cycles. It is mainly faced with serious steam channeling and low reservoir pressure. The oil saturation near the wellbore is low. Therefore, a water-soluble viscosity reducer is preferred to expand the oil leakage area. The optimized injection amount of the water-soluble viscosity reducer is 10t.

[0244] Step 2: Assisted injection of carbon dioxide foam, adjust the steam absorption profile, increase formation energy, maintain reservoir pressure, and reduce crude oil viscosity, optimizing the carbon dioxide injection volume to 120t;

[0245] Step 3: Due to the low oil saturation, a high temperature resistant oil displacement agent is injected to improve the oil washing efficiency and development effect. The optimized injection amount of the oil displacement agent is 17t;

[0246] Step 4: Calculate and optimize the steam chamber inclination angle to about 61° and the injected steam volume to 3100t;

[0247] Step 5: After the well is soaked for 2 to 3 days, the well is opened for production;

[0248] Step 6: After the oil production drops to 1t / d, re-inject the oil-soluble viscosity reducer to start the turnaround development. Figure 8 It can be seen that compared with conventional throughput, three cycles of controlled pressure drainage throughput can increase the degree of recovery by 3.5, and the recovery factor within the well control range is expected to be 52%.

[0249] Finally, it should be noted that the above is only a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art can still modify the technical solutions recorded in the aforementioned embodiments or replace some of the technical features therein with equivalents. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

[0250] Except for the technical features described in the specification, all other technical features are known technologies to those skilled in the art.

Claims

1. A method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of huff and puff, characterized in that: The multi-round huff-and-puff horizontal well multi-element thermal fluid controlled pressure drainage method for improving oil recovery includes: Step 1, injecting a viscosity reducer into the oil reservoir; Step 2, injecting foam or gas into the reservoir; Step 3, injecting a high temperature resistant oil displacement agent into the oil reservoir; Step 4, injecting high-dry steam into the oil reservoir; Step 5, start production after wellbore maintenance.

2. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage of horizontal wells with multiple rounds of throughput according to claim 1, characterized in that: In step 1, the development status of the target block is collected, and the type of viscosity reducer is selected according to the main development contradictions. For wells with fewer throughput cycles, the demand for viscosity reduction is higher, and oil-soluble viscosity reducers are used; for wells with more throughput cycles, the demand for expansion is higher, and water-soluble viscosity reducers are used; the injection volume of the viscosity reducer is optimized using numerical simulation software.

3. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of throughput according to claim 1, characterized in that: In step 2, the injection fluid type is selected according to the reservoir properties. For wells with more serious steam channeling, foam can be injected, with nitrogen foam injected into the shallow layer and carbon dioxide foam injected into the deep layer. For wells with less steam channeling, nitrogen or carbon dioxide can be injected, with nitrogen injected into the shallow layer and carbon dioxide injected into the deep layer. Numerical simulation software is used to optimize the injection amounts of nitrogen and carbon dioxide.

4. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of throughput according to claim 1, characterized in that: In step 3, the injection of oil displacement agent is determined according to the needs of reservoir development. If the throughput cycle is short, no oil displacement agent is required; if the throughput cycle is long, high-temperature resistant oil displacement agent is injected; numerical simulation software is used to optimize the injection amount of oil displacement agent.

5. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of throughput according to claim 1, characterized in that: In step 4, the oil production at different steam chamber inclination angles is calculated to determine the optimal oil leakage angle, thereby guiding the steam injection amount.

6. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of throughput according to claim 5, characterized in that: In step 4, the heat exchange in the direction perpendicular to the steam chamber interface can be expressed by the following formula: Where x is the horizontal distance; K is the thermal conductivity of the reservoir; T is the temperature distribution at the edge of the steam chamber; x is the distance; V c is the convection velocity in the direction perpendicular to the steam chamber; ρ c is the density of the condensate; c pc is the heat capacity of the condensate; ρ r is the reservoir density; c pr is the reservoir heat capacity; t is the production time; The coordinate axis distance x is transformed into the distance ξ from the steam chamber interface, and the steam chamber interface migration velocity U is introduced x ; The following is the relationship between x and ξ: According to formula (2), the derivative in formula (1) can be transformed: Substituting the above three equations into equation (1), we can get: After sorting: The edge of the steam chamber can be assumed to be a quasi-steady-state heat conduction, so: Substituting formula (8) into formula (7) yields the heat exchange formula at the edge of the steam chamber during the production process:

7. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of throughput according to claim 6, characterized in that: In step 4, when convection is neglected, the velocity of the fluid in the direction perpendicular to the steam chamber interface is zero: V c ＝0 (10) Substituting into equation (9) yields the Butler temperature distribution model: The above equation can be solved using the substitution integration method: Where T* is the dimensionless temperature; T r is the crude oil reservoir temperature; T st is the injection steam temperature; α is the thermal diffusion coefficient of the reservoir.

8. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of throughput according to claim 7, characterized in that: In step 4, the convection velocity at the edge of the steam chamber perpendicular to the steam chamber interface can be calculated using the following formula: V c =V cp +V cg (14) Among them, V cp V is the convection velocity in the direction perpendicular to the steam chamber caused by the pressure difference; cg is the convection velocity in the direction perpendicular to the steam chamber caused by the gravity component; Based on the knowledge of fluid mechanics, the convection velocity caused by pressure difference and gravity component can be calculated: V cg =λgcosθ (16) Where θ is the angle between the steam chamber interface and the horizontal direction; P is the pressure; λ is the fluidity of the convective phase at different positions; g is the gravitational acceleration; k is the absolute permeability at any position; k rw is the relative permeability of water phase at any position; k ro is the relative permeability of the oil phase at any position; μ o is the dynamic viscosity of the oil phase; μ w is the dynamic viscosity of the water phase; The oil saturation distribution equation at the edge of the steam chamber is: S o =S or +(S io -S or )(1-T * ) (18) According to Corey's formula, the relative permeability of water phase and oil phase can be calculated by the following formula: k rw =k rwro (S wD ) b (19) k ro =k rocw S oD a (1-T * ) a (21) Among them, a is the Corey coefficient; b is the Corey coefficient; k rwro is the relative permeability of water phase under residual oil saturation; S wD is the dimensionless water saturation; S w is water saturation; S wc is the bound water saturation; S or is the residual oil saturation, k rocw is the relative permeability of the oil phase at irreducible water saturation; S oD is the dimensionless oil saturation; From the definition, we can see that there is the following relationship between dimensionless oil saturation and dimensionless water saturation: S wD =1-S oD (1-T * ) (23) Substituting into equation (19), the relative permeability of water phase is obtained as follows: k rw =k rwro [1-S oD (1-T * )] b (24)。 9. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of throughput according to claim 8, characterized in that: In step 4, the properties of the convective phase are an important factor affecting the strength of convection, and density and heat capacity are the two parameters with the greatest influence. In previous studies, simplifying the convective phase to a pure water phase also simplified the properties of the convective phase. When considering the influence of two-phase flow on heat exchange, the calculation of the properties of the convective phase also becomes more complicated. Based on existing research results, the density and heat capacity of the convective phase can be calculated by the following formula: Among them, ρ c is the density of the convective phase; ρ o is the density of the oil phase; ρ w is the density of water phase; c pc is the heat capacity of the convective phase; c o is the heat capacity of the oil phase; c w is the heat capacity of water phase; Substituting equation (16) into the above two equations, we can obtain the distribution functions of the convective phase density and heat capacity at the edge of the steam chamber: r c =ρ o S oD (1-T * )+r w [1-S oD (1-T * )] (27) c pc =c o S oD (1-T * )+c w [1-S oD (1-T * )] (28) The density and heat capacity of the oil phase and the water phase are also affected by temperature. The research in this area is relatively mature and can be obtained by consulting the literature: r o =1024-0.645T (29) r w =1001.7-0.1616T-0.00262T 2 (30) c o =1.605+0.004361T-4.046×10 -6 T 2 (31) c w =4.182-1.5×10 -4 T+3.44×10 -7 T 2 +4.26×10 -8 T 3 (32) According to the research of Butler and Reid, the relationship between oil phase viscosity and water phase viscosity and temperature distribution can be obtained: Wherein, m is the viscosity-temperature index; Substituting equations (21), (24), (33) and (34) into equation (17), we can obtain: According to the research, the relationship between oil phase viscosity and water phase viscosity and temperature distribution can be obtained: The formula for the convection velocity caused by pressure difference also includes the derivative of pressure. Based on the relationship between viscosity and temperature distribution (33), it can be assumed that the following relationship exists between crude oil viscosity and pressure distribution: Among them, ν st is the kinematic viscosity of the oil phase at the steam temperature; ν o is the kinematic viscosity of the oil phase at different positions on the edge of the steam chamber; n is the pressure-temperature index; From equations (33) and (37), we can get the relationship between the pressure distribution and temperature distribution at the edge of the steam chamber: By differentiating both sides of the above equation with respect to the distance ξ, we can obtain the derivative of pressure: Substituting formula (12) into the above formula, we can get: From this, the calculation formula for the convection velocity caused by pressure difference can be obtained: To solve the model, the apparent thermal diffusion coefficient α* is introduced, The flow rate calculation formula is: The liquid and oil production during the production process are: q liq =∫λρ c gsinθdξ (44) q o =∫λρ c gsinθS oD (1-T * )dξ (45)。 10. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of throughput according to claim 1, characterized in that: In step 5, the well is shut down for 1 to 2 days to ensure that the crude oil at the front edge of the steam chamber is sufficiently reduced in viscosity, and the crude oil in the upper part of the horizontal well flows to the lower part of the reservoir under the action of gravity. The horizontal well is started for production, and the bottom hole flow pressure of the horizontal well cannot be too low to ensure stable pressure production as much as possible.

11. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of throughput according to claim 1, characterized in that: The method for improving oil recovery by controlling pressure and draining oil by multi-element thermal fluids in multiple rounds of throughput horizontal wells also includes, after step 5, step 6, performing cycle development with daily oil production as a cutoff condition.

12. The method for improving oil recovery by multi-component thermal fluid controlled pressure drainage in horizontal wells with multiple rounds of throughput according to claim 11, characterized in that: In step 6, when the daily oil production drops to 1t / d, the development is switched to ensure a certain production capacity while maintaining the formation temperature to provide a basis for subsequent cavity creation.

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