Method for enhancing recovery by controlling pressure and releasing oil in multi-well throughput horizontal well by using multi-component thermal fluid

Abstract

The present application provides a kind of multi-round throughput horizontal well multi-element thermal fluid pressure control oil discharge enhanced recovery method, the multi-round throughput horizontal well multi-element thermal fluid pressure control oil discharge enhanced recovery method includes: step 1, inject viscosity reducer into reservoir;Step 2, inject foam or gas into reservoir;Step 3, inject high-temperature oil displacement agent into reservoir;Step 4, inject high dry steam into reservoir;Step 5, after soaking well, open well production.The multi-round throughput horizontal well multi-element thermal fluid pressure control oil discharge enhanced recovery method strengthens viscosity reduction and oil washing efficiency, improves development effect, can effectively improve the recovery of heavy oil reservoir after multi-round throughput, horizontal well pressure control oil discharge throughput technology, form a kind of multi-round throughput horizontal well multi-element thermal fluid pressure control oil discharge enhanced recovery method.

Description

Technical Field

[0001] This invention relates to the field of oilfield development technology, and in particular to a method for improving oil recovery by controlling pressure drainage of multi-element thermal fluids in horizontal wells through multiple rounds of huff and puff. Background Technology

[0002] The Shengli heavy oil field is primarily developed using steam injection, with an average injection cycle of 6.8, indicating it is in a multi-cycle injection phase. However, due to factors such as low reservoir pressure and severe steam channeling, it exhibits low steam injection thermal efficiency and poor development results. Horizontal wells, with their advantages of high well-controlled reserves and large drainage area, have become an important means of increasing and stabilizing production.

[0003] Horizontal well development mainly includes horizontal well huff and puff, horizontal well steam drive, HDCS, HDNS, and SAGD technologies. Due to reservoir heterogeneity and other factors, conventional horizontal well huff and puff and steam drive suffer from severe steam channeling and uneven utilization of the horizontal well section. HDCS and HDNS, due to their high investment costs, are mainly applied to extra-heavy oil reservoirs. Furthermore, because of the high steam injection pressure, steam chambers do not develop upwards but are more likely to develop to the sides of the horizontal well. SAGD technology offers high recovery rates, but it has high requirements for the reservoir, especially requiring a reservoir thickness greater than 15 meters. However, the Shengli oil reservoir has poor physical properties, with most reservoirs less than 15 meters thick or having interlayered formations, making SAGD less economically viable.

[0004] Horizontal well multi-element thermofluid controlled pressure relief oil injection is a novel efficiency-enhancing technology for heavy oil reservoirs after multiple rounds of steam injection. During the steam injection stage, a combination of high-dry steam, viscosity reducer (oil-soluble or water-soluble), high-temperature 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. The crude oil with reduced viscosity flows from the edge of the steam chamber to the lower part of the reservoir by gravity, and is then extracted by the horizontal well during the production stage, thereby improving the recovery rate of the reservoir after multiple rounds of steam injection. The main function of high-temperature steam is to heat and reduce viscosity, while simultaneously creating a low-oil-saturation cavity above the horizontal well, forming an oil drainage space. Viscosity reducers enhance viscosity reduction, lower start-up pressure, reduce the difficulty of subsequent steam injection, and expand the steam cavity range. Oil displacement agents primarily improve oil washing efficiency and development performance. Foam mainly adjusts the development of the steam cavity, while slowly releasing gas, suppressing steam channeling, maintaining formation energy, and ensuring the integrity of the steam cavity. Nitrogen focuses on maintaining formation pressure and reducing heat loss at the reservoir bottom, while carbon dioxide focuses on maintaining formation pressure and assisting in reducing crude oil viscosity. Different fluids can be combined and optimized according to reservoir properties and development needs. When there are fewer huff-and-puff cycles, a combination of oil-soluble viscosity reducers + steam + nitrogen (shallow) or carbon dioxide (deep) can be used to increase cycle production. When there are more huff-and-puff cycles, a combination of water-soluble viscosity reducers + steam + high-temperature resistant oil displacement agents + foam can be used to increase cycle production.

[0005] Compared to conventional horizontal well development, the advantages of horizontal well controlled pressure relief huff and puff are: lower investment costs, no need to drill new wells, only the existing single horizontal well is required, and huff and puff is an intermittent steam injection mode, further reducing the amount of steam injected and lowering steam costs by injecting nitrogen, carbon dioxide and other gases; higher thermal efficiency, because the steam chamber develops upward due to injection at a pressure slightly higher than the reservoir pressure, 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; and higher recovery rate, the combined injection of steam, viscosity reducer and oil displacement agent can effectively reduce crude oil viscosity, reduce the residual oil saturation in the steam chamber, and improve the development effect of steam huff and puff.

[0006] Chinese patent application No. 201210432484 discloses a method for late-stage development of thin-layer heavy oil reservoirs through multiple rounds of huff and puff. This method includes: Step 1, injecting steam into the well; Step 2, simultaneously injecting nitrogen and a microemulsion viscosity reducer; Step 3, shutting down the well; and Step 4, setting up the steam injection tubing, setting up the production tubing, and switching to pumping production. This method addresses the contradiction of rapid production decline, rapid water cut increase, and energy decrease leading to poorer development performance in the later stages of multiple rounds of huff and puff in thin-layer heavy oil reservoirs. Before reaching the conditions for steam drive, it utilizes nitrogen + microemulsion viscosity reducer to assist steam in enhanced thermal recovery, replenishing reservoir energy, improving steam sweep efficiency, thermal efficiency, and displacement efficiency, thereby improving the development effect of multiple rounds of huff and puff in thin-layer heavy oil reservoirs. However, this method still uses 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] Chinese patent application CN202010846747.4 discloses a method for increasing the operational radius of a high-cycle huff and puff. The method includes: Step 1. Injecting steam, shutting down the well, and then starting production in a target reservoir production well; Step 2. Determining the huff and puff cycle at which the operational radius of the target reservoir slows down and the corresponding operational radius; Step 3. After the huff and puff cycle reaches the determined cycle at which the operational radius slows down, stopping steam huff and puff and performing water jet perforation; Step 4. For the huff and puff well that has completed water jet perforation, injecting steam, shutting down the well, and then starting production. This invention effectively increases the sweep range of injected steam, reduces heat loss due to repeated heating, effectively increases the operational radius in the later stages of huff and puff, and increases the cumulative oil production of a single well. The steam injection concept in this method is still based on conventional steam huff and puff.

[0008] Chinese patent application CN201910547116.X describes a system and method for improving the recovery rate of heavy oil reservoirs using hot nitrogen foam in the later stages of multiple steam huff and puff. The method includes 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 a mixture of hot nitrogen and steam into the formation, wherein the volume ratio of hot nitrogen to steam is (20-50):1; (4) Well shut-in: after step (3) injection, the well is shut-in for 2-4 days; (5) Well production: after step (4) is completed, the well is started for production. This invention can increase formation energy, reduce crude oil viscosity, reduce the water saturation of the oil reservoir, shorten the drainage period, and increase the oil recovery rate of multiple steam huff and puff. This method addresses the two problems of low reservoir pressure and high top heat loss, but it does not change the steam injection method, nor does it implement enhanced viscosity reduction and enhanced oil washing measures.

[0009] Chinese patent application No. 202010235430.7 discloses a method for quantitatively allocating segmented targeted steam injection volume in horizontal wells after multiple rounds of huff and puff. The method includes: testing the well temperature and remaining oil saturation of the horizontal well; plotting the well temperature curve and the remaining oil saturation curve on the same abscissa; experimentally determining the critical temperature at which heavy oil non-Newtonian fluids convert to Newtonian fluids; dividing the well temperature curve into high-temperature and low-temperature zones; determining the high and low remaining oil saturation zones on the remaining oil saturation curve and dividing it into several segmented curves; obtaining a fitting function; performing area integration on the polygon formed by the segmented curves and the abscissa to obtain the polygon area; calculating the area ratio of each polygon; and determining the segmented steam injection volume in the horizontal well to achieve quantitative allocation of the segmented steam injection volume. This method optimizes the segmented quantitative allocation of steam injection volume within the horizontal well section, improving the steam injection heat utilization rate and enhancing the development effect within the formation. This method improves upon the horizontal well balanced steam injection method, achieving quantitative allocation, but both the injected fluid and the steam injection method use conventional steam huff and puff.

[0010] There are currently no precedents for horizontal well pressure-controlled drainage and oil recovery technology at home and abroad, and there is a lack of theoretical and practical guidance. To address this, we have invented a multi-round horizontal well multi-element thermal fluid pressure-controlled drainage method to improve oil recovery, which solves the above-mentioned technical problems. Summary of the Invention

[0011] The purpose of this invention is to provide a method for improving the recovery rate of heavy oil reservoirs by controlling pressure drainage of multi-element thermal fluid in horizontal wells after multiple rounds of huff and puff, thereby improving the development effect.

[0012] The objective of this invention can be achieved through the following technical measures: a method for enhancing oil recovery through multi-stage huff and puff horizontal well multi-element thermal fluid pressure control and drainage, comprising:

[0013] Step 1: Inject a viscosity reducer into the reservoir;

[0014] Step 2: Inject foam or gas into the reservoir;

[0015] Step 3: Inject a high-temperature resistant oil displacement agent into the reservoir;

[0016] Step 4: Inject high-temperature steam into the reservoir;

[0017] Step 5: After the well is sealed, it is opened for production.

[0018] The objective of this invention can also be achieved through the following technical measures:

[0019] In step 1, the current 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 short huff and puff cycles, the viscosity reduction requirement is higher, so oil-soluble viscosity reducers are used; for wells with long huff and puff cycles, the requirement to expand the impact is higher, so water-soluble viscosity reducers are used; the injection volume of viscosity reducers is optimized using numerical simulation software.

[0020] In step 2, the injection fluid type is selected based on the reservoir properties. Wells with severe gas channeling can be injected with foam, with nitrogen foam injected in the shallow layer and carbon dioxide foam injected in the deep layer. For wells with weaker gas channeling, nitrogen or carbon dioxide can be injected, with nitrogen injected in the shallow layer and carbon dioxide injected in the deep layer. The injection volume of nitrogen and carbon dioxide is optimized using numerical simulation software.

[0021] In step 3, the injection of oil displacement agent is determined based on the reservoir development needs. If the huff and puff cycle is short, no oil displacement agent needs to be injected; if the huff and puff cycle is long, a high-temperature resistant oil displacement agent is injected. The injection amount of oil displacement agent is optimized using numerical simulation software.

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

[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 reservoir thermal conductivity; T is the temperature distribution at the edge of the steam chamber; x is the distance; V c ρ is the convection velocity perpendicular to the steam chamber direction. c c is the density of the condensate. pc ρ is the heat capacity of the condensate; r c is the reservoir density; pr t represents the reservoir heat capacity; t represents 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 formula represents the relationship between x and ξ:

[0027]

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

[0029]

[0030]

[0031]

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

[0033]

[0034] After sorting, we get:

[0035]

[0036] The edge of the steam cavity can be assumed to have quasi-steady-state heat conduction, therefore:

[0037]

[0038] Substituting equation (8) into equation (7), we can obtain the heat exchange formula at the edge of the steam chamber during the production process:

[0039]

[0040] In step 4, when convection is ignored, that is, the fluid velocity 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 integral method:

[0045]

[0046]

[0047] Where T* is the dimensionless temperature; T r T represents the temperature of the crude oil reservoir. st α represents the injected steam temperature; α is the reservoir thermal diffusivity.

[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 represents the convection velocity perpendicular to the steam chamber caused by the pressure difference. cg The convection velocity perpendicular to the steam cavity caused by the gravitational component;

[0051] Based on fluid mechanics, the convective velocity caused by pressure difference and gravitational 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 mobility of the convective phase at different locations; g is the acceleration due to gravity; k is the absolute permeability at any location; k rw k represents the relative permeability of the water phase at any location. ro The relative permeability of the oil phase at any location; μ o The dynamic viscosity of the oil phase; μ w The dynamic viscosity of the aqueous phase;

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

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

[0058] According to the Corey formula, the relative permeability of the aqueous and oil phases can be calculated using 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] Where a is the Corey coefficient; b is the Corey coefficient; k rwro S represents the relative permeability of the aqueous phase at residual oil saturation. wD S is the dimensionless water saturation. w Water saturation; S wc S represents the bound water saturation. or k represents the residual oil saturation. rocwS represents the relative permeability of the oil phase at bound water saturation. oD The oil saturation is dimensionless.

[0064] As defined, the dimensionless oil saturation and the dimensionless water saturation have the following relationship:

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

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

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

[0068] In step 4, the properties of the convective phase are a crucial factor influencing the strength of convection, with density and heat capacity being the two most influential parameters. Previous studies simplified the convective phase to a pure aqueous phase, which also simplified its properties. Considering the impact of two-phase flow on heat exchange, the calculation of the convective phase properties becomes more complex. Based on existing research, the density and heat capacity of the convective phase can be calculated using the following formulas:

[0069]

[0070]

[0071] Where, ρ c ρ is the density of the convective phase. o ρ is the density of the oil phase; w c is the density of the aqueous phase. pc c is the heat capacity of the convective phase; o c is the heat capacity of the oil phase; w The heat capacity of the aqueous phase;

[0072] Substituting equation (16) into the two equations above, we can obtain the distribution functions of the flow 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 and water phases are also affected by temperature. Research on this topic 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] Based on the research of Butler and Reid, the relationships between oil phase viscosity, 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 get:

[0085]

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

[0087]

[0088] The formula for the convection velocity caused by pressure difference also includes the derivative of pressure; referring to the relationship between viscosity and temperature distribution (33), we can assume that there is the following relationship between crude oil viscosity and pressure distribution:

[0089]

[0090] Where, ν st ν is the kinematic viscosity of the oil phase at steam temperature; o The viscosity of the oil phase at different locations on the edge of the steam chamber is denoted as n; n is the pressure-temperature index.

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

[0092]

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

[0094]

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

[0096]

[0097] Therefore, the formula for calculating the convection velocity caused by pressure difference can be obtained:

[0098]

[0099] To solve this model, the apparent thermal diffusivity α* is introduced.

[0100]

[0101] The formula for calculating flow rate is:

[0102]

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

[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 in 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 that 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 then put into production. The bottom flow pressure of the horizontal well should not be too low, and stable pressure production should be ensured as much as possible.

[0107] The multi-round churn-and-purge horizontal well multi-element thermal fluid pressure control and oil drainage method for enhancing oil recovery also includes, after step 5, step 6, conducting a cycle development based on daily oil production as the cutoff condition.

[0108] In step 6, once the daily oil production drops to 1 t / d, a cycle development is carried out to ensure a certain production capacity while maintaining the formation temperature, thus providing a foundation for subsequent cavity creation.

[0109] The multi-stage injection-pump horizontal well multi-element thermal fluid pressure control and drainage method for enhancing oil recovery in this invention injects high-dry steam (over 90%), viscosity reducer (oil-soluble or water-soluble, 10-40t), high-temperature resistant oil displacement agent (10-30t of concentrate), and foam (nitrogen, carbon dioxide, or nitrogen + carbon dioxide, with nitrogen at 10-150,000 Nm³) into the reservoir through a horizontal well at a pressure slightly higher than the reservoir pressure. 3 A combined fluid (containing 100-200 t of carbon dioxide) is used. A high-temperature steam chamber is constructed above the horizontal well. 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 extracted from the horizontal well during the production stage, thereby improving the reservoir recovery rate after multiple rounds of steam huff and puff. The beneficial effects of this invention are:

[0110] By quantitatively calculating and injecting a combination of viscosity reducer (oil-soluble, water-soluble), foam (nitrogen, carbon dioxide), high-temperature oil displacement agent, and steam, a steam chamber is constructed above the horizontal well. An oil drainage channel is formed at the leading edge of the steam chamber, and the oil flows to the lower part of the reservoir under gravity and is extracted by the horizontal well. This enhances viscosity reduction and oil washing efficiency, and improves development results. This invention can effectively improve the recovery rate of heavy oil reservoirs after multiple rounds of huff and puff. The horizontal well pressure-controlled drainage huff and puff technology forms a method for improving the recovery rate by controlling the pressure of multiple rounds of horizontal well huff and puff using multi-element thermal fluid. Attached Figure Description

[0111] Figure 1 A flowchart of a specific embodiment of the multi-round huff-and-puff horizontal well multi-element thermal fluid pressure control and oil recovery enhancement method of the present invention;

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

[0113] Figure 3 This is a schematic diagram of horizontal well controlled pressure relief and oil injection production in a specific embodiment of the present invention;

[0114] Figure 4 This is a curve showing the influence of the horizontal well pressure control and drainage production angle in a specific embodiment of the present invention;

[0115] Figure 5 This is a schematic diagram of the extraction rate improvement curve in a specific embodiment of the present invention;

[0116] Figure 6 This is a schematic diagram of the extraction degree improvement curve in a specific embodiment two of the present invention;

[0117] Figure 7 This is a schematic diagram of the extraction rate improvement curve in a specific embodiment three of the present invention;

[0118] Figure 8 This is a schematic diagram of the extraction degree improvement curve in a specific embodiment four of the present invention. Detailed Implementation

[0119] It should be noted that the following detailed descriptions are exemplary and intended to provide further illustration of the invention. Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

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

[0121] This invention relates to a multi-stage, multi-element thermal fluid controlled pressure drainage method for enhancing oil recovery in horizontal wells. This method utilizes different combinations of viscosity reducers (oil-soluble + water-soluble) + steam + (high-temperature viscosity reducer, oil displacement agent) or foam (nitrogen + carbon dioxide, or nitrogen, carbon dioxide) to increase cycle production. Steam heating reduces viscosity and creates cavities, forming drainage spaces, which are enhanced by high-temperature viscosity reducers and oil displacement agents. Gas insulation and (carbon dioxide) viscosity reduction provide continuous energy replenishment. The viscosity reducer (oil-soluble + water-soluble) reduces viscosity; the oil-soluble component lowers the difficulty of cavity creation, reduces the starting pressure, and expands the cavity creation range; the water-soluble component creates a low-temperature field at the distal end for viscosity reduction. For example, with fewer cycles, a combination of viscosity reducer (oil-soluble) + steam + nitrogen (shallow layer) or carbon dioxide (deep layer) is used to increase cycle production. With more cycles, different combinations of viscosity reducer (water-soluble) + steam + (high-temperature viscosity reducer, oil displacement agent) + foam (nitrogen + carbon dioxide, or nitrogen, carbon dioxide) are used to increase cycle production.

[0122] Extra-heavy oil is produced using a combination of HDNCS (High-Density Non-Solid Gas Cavities). Different cavity-building diagrams are used to illustrate this. From a reservoir perspective, the optimization process of cavity stripping and cavity building is explored, with the optimal cavity tilt angle and enhanced pressure control and oil drainage being the core key points of this invention. Mathematical formulas are used to demonstrate the calculation process for the optimal angle, supporting the invention's points.

[0123] like Figure 1 As shown, Figure 1This is a flowchart of the multi-stage huff-and-puff horizontal well multi-element thermal fluid pressure-controlled drainage method for enhanced oil recovery according to the present invention. The method includes the following steps:

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

[0125] Step 2: Inject foam or gas into the reservoir. Select the injection fluid type according to the reservoir properties. Wells with severe gas channeling can be injected with foam, with nitrogen foam injected in shallow layers and carbon dioxide foam injected in deep layers. For wells with weak gas channeling, nitrogen or carbon dioxide can be injected, with nitrogen injected in shallow layers and carbon dioxide injected in deep layers. Optimize the injection volume of nitrogen and carbon dioxide using numerical simulation software.

[0126] Step 3: Inject high-temperature resistant oil displacement agent into the reservoir. The injection of oil displacement agent is determined according to the reservoir development needs. If the huff and puff cycle is short, oil displacement agent may not be injected. If the huff and puff cycle is long, high-temperature resistant oil displacement agent is injected. The injection amount of oil displacement agent is optimized using numerical simulation software.

[0127] Step 4: Inject high-temperature steam into the reservoir; calculate the oil production at different steam chamber inclination angles to determine the optimal oil drainage angle, thereby guiding the steam injection rate.

[0128] like Figure 2 , Figure 3 As shown, Figure 2 This is a schematic diagram of horizontal well pressure control, oil drainage, steam injection, and steam injection in a specific embodiment of the present invention. Figure 3 This is a schematic diagram of horizontal well controlled pressure relief and oil injection production in a specific embodiment of the present invention. Figure 2 , Figure 3 It can be seen that steam, nitrogen, and carbon dioxide move upward under the influence of gravity and are distributed in the high-temperature cavity above the horizontal well; viscosity reducer, condensate, and viscosity-reducing crude oil are located in the transition zone between the high-temperature cavity and the original reservoir, and flow to the vicinity of the horizontal well under the influence of gravity.

[0129] The optimal oil drain 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 reservoir thermal conductivity; T is the temperature distribution at the edge of the steam chamber; x is the distance; Vc ρ is the convection velocity perpendicular to the steam chamber direction. c c is the density of the condensate. pc ρ is the heat capacity of the condensate; r c is the reservoir density; pr t represents the reservoir heat capacity; t represents 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 formula represents the relationship between x and ξ:

[0134]

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

[0136]

[0137]

[0138]

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

[0140]

[0141] After sorting, we get:

[0142]

[0143] The edge of the steam cavity can be assumed to have quasi-steady-state heat conduction, therefore:

[0144]

[0145] Substituting equation (8) into equation (7), we can obtain the heat exchange formula at the edge of the steam chamber during the production process:

[0146]

[0147] When convection is ignored, that is, the fluid velocity 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 integral method:

[0152]

[0153]

[0154] Where T* is the dimensionless temperature; T r T represents the temperature of the crude oil reservoir. st α represents the injected steam temperature; α is the reservoir thermal diffusivity.

[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 represents the convection velocity perpendicular to the steam chamber caused by the pressure difference. cg This represents the convection velocity perpendicular to the steam cavity caused by the gravitational component.

[0158] Based on fluid mechanics, the convective velocity caused by pressure difference and gravitational 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 mobility of the convective phase at different locations; k ro The relative permeability of the oil phase at any location; μ o The dynamic viscosity of the oil phase; μ w This represents the dynamic viscosity of the aqueous phase.

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

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

[0165] According to the Corey formula, the relative permeability of the aqueous and oil phases can be calculated using 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] Where a is the Corey coefficient; b is the Corey coefficient; k rwro S represents the relative permeability of the aqueous phase at residual oil saturation. wD S is the dimensionless water saturation. w Water saturation; S wc S represents the bound water saturation. or k represents the residual oil saturation. rocw S represents the relative permeability of the oil phase at bound water saturation. oD It represents the dimensionless oil saturation.

[0171] As defined, the dimensionless oil saturation and the dimensionless water saturation have the following relationship:

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

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

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

[0175] The properties of the convective phase are a crucial factor influencing the strength of convection, with density and heat capacity being the two most influential parameters. Previous studies simplified the convective phase to a pure aqueous phase, which also simplified its properties. However, calculating the properties of the convective phase becomes more complex when considering the influence of two-phase flow on heat exchange. Based on existing research, the density and heat capacity of the convective phase can be calculated using the following formulas:

[0176]

[0177]

[0178] Where, ρ c ρ is the density of the convective phase. oρ is the density of the oil phase; w c is the density of the aqueous phase. pc c is the heat capacity of the convective phase; o c is the heat capacity of the oil phase; w This refers to the heat capacity of the aqueous phase.

[0179] Substituting equation (16) into the two equations above, we can obtain the distribution functions of the flow 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 and water phases are also affected by temperature. Research on this topic 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] Based on the research of Butler and Reid, the relationships between oil phase viscosity, water phase viscosity, and temperature distribution can be obtained:

[0188]

[0189]

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

[0191]

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

[0193]

[0194] The formula for the convection velocity caused by pressure difference also includes the derivative of pressure. Referring to the relationship between viscosity and temperature distribution (33), we can assume the following relationship exists between crude oil viscosity and pressure distribution:

[0195]

[0196] Where, ν st ν is the kinematic viscosity of the oil phase at steam temperature; o denoted as η, where n is the kinematic viscosity of the oil phase at different locations on the edge of the steam chamber; and η is the pressure-temperature index.

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

[0198]

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

[0200]

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

[0202]

[0203] Therefore, the formula for calculating the convection velocity caused by pressure difference can be obtained:

[0204]

[0205] To solve this model, the apparent thermal diffusivity α* is introduced.

[0206]

[0207] The formula for calculating flow rate is:

[0208]

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

[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 The curve showing the influence of the horizontal well pressure control and drainage production angle in a specific embodiment of the present invention indicates that the optimal drainage angle is between 60% and 80%, which can achieve a higher oil production rate and a smaller amount of steam injection.

[0213] Step 5: After steaming the well, start production. Steam the well for 1-2 days to ensure that the crude oil at the front edge of the steam chamber is sufficiently reduced in viscosity, and that the crude oil in the upper part of the horizontal well flows to the lower part of the reservoir under the action of gravity. Start production in the horizontal well. The bottom flow pressure of the horizontal well should not be too low, and stable pressure production should be ensured as much as possible.

[0214] Step 6: Use daily oil production as the cutoff condition for transitional development. Once daily oil production drops to 1 t / d, transitional development will commence to ensure a certain production capacity while maintaining formation temperature, thus providing a foundation for subsequent cavity creation.

[0215] Based on the current development status of the target block, this invention optimizes the type of viscosity reducer, enhances viscosity reduction, reduces the difficulty of cavity creation, injects foam or nitrogen and carbon dioxide to maintain formation energy while reducing heat loss from the top cap layer, and assists in the injection of high-temperature resistant oil displacement agents to enhance the oil washing effect. According to the requirements of the steam cavity drainage angle, the steam injection volume is optimized, ultimately solving the problems of poor development effect, serious steam channeling, and low reservoir pressure after multiple rounds of huff and puff in heavy oil reservoirs.

[0216] The features and performance of the present invention will be further described in detail below with reference to specific embodiments.

[0217] Example 1

[0218] This invention takes well A as an example to carry out the development of horizontal well controlled pressure relief oil injection, including the following steps:

[0219] Step 1: Well A has a perforation depth of 491-518 meters and has completed 7 cycles of injection and discharge. The main problems it faces are shallow reservoir burial depth, large heat loss and low thermal efficiency. The well has a good material foundation, so an oil-soluble viscosity reducer is preferred to enhance the viscosity reduction effect. The optimized injection amount of oil-soluble viscosity reducer is 25t.

[0220] Step 2: Nitrogen injection is used 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 Nm³.3 ;

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

[0222] Step 4: Calculate and optimize the steam chamber inclination angle to approximately 63°, with an injection steam volume of 1700t;

[0223] Step 5: After the well has been sealed for 1-2 days, start production.

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

[0225] Example 2

[0226] This invention takes well B as an example to carry out the development of horizontal well controlled pressure relief and oil release through huff and puff, including the following steps:

[0227] Step 1: Well B has a perforation depth of 517-532 meters and has completed 19 cycles of injection and drainage. The main problems it faces are severe gas channeling temperature, low reservoir pressure, and low thermal efficiency. The oil saturation in the near-wellbore zone is low. Therefore, a water-soluble viscosity reducer is preferred to expand the oil drainage area. The optimized injection amount of the water-soluble viscosity reducer is 15t.

[0228] Step 2: Nitrogen foam injection is used to adjust reservoir consistency, increase formation energy, maintain reservoir pressure, and reduce heat loss at the top of the reservoir. The optimized nitrogen injection rate is 50,000 Nm³. 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 oil displacement agent injection amount is 10t.

[0230] Step 4: Calculate and optimize the steam chamber inclination angle to approximately 71°, with an injection steam volume of 2300t;

[0231] Step 5: After the well has been sealed for 1-2 days, start production.

[0232] Step 6: After oil production drops to 1 t / d, re-inject viscosity reducers and begin cycle-shifting development. Figure 6 It can be seen that, compared with conventional huff and puff, three cycles of controlled pressure drainage huff and puff can increase the recovery rate by 3.3%, and the recovery rate within the well control range is expected to be 52%.

[0233] Example 3

[0234] This invention takes well C as an example to carry out the development of horizontal well controlled pressure relief and oil release through huff and puff, including the following steps:

[0235] Step 1: Well C has a perforation depth of 1030-1080 meters and has completed 6 cycles of injection and discharge. The main problems it faces are large heat loss along the well and low dryness at the bottom of the well. The well has a good material foundation, so an oil-soluble viscosity reducer is preferred to enhance the viscosity reduction effect. The optimized injection amount of the oil-soluble viscosity reducer is 20t.

[0236] Step 2: Assisted carbon dioxide injection to increase formation energy, reduce top heat loss, and enhance viscosity reduction effect. The optimized carbon dioxide injection volume is 170t.

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

[0238] Step 4: Calculate and optimize the steam chamber inclination angle to approximately 58°, with an injection steam volume of 2300t;

[0239] Step 5: After the well has been sealed for 2-3 days, production can begin.

[0240] Step 6: After oil production drops to 1 t / d, re-inject viscosity reducers and begin cycle-shifting development. Figure 7 It can be seen that, compared with conventional huff and puff, four cycles of controlled pressure drainage huff and puff can increase the recovery rate by 2.8, and the recovery rate within the well control range is expected to be 46%.

[0241] Example 4

[0242] This invention takes well D as an example to carry out the development of horizontal well controlled pressure relief and oil release through huff and puff, including the following steps:

[0243] Step 1: Well D has a perforation depth of 1170-1210 meters and has completed 10 cycles of injection and drainage. The main problems it faces are severe gas channeling and low reservoir pressure. The oil saturation in the near-wellbore zone is low. Therefore, a water-soluble viscosity reducer is preferred to expand the drainage area. The optimized injection amount of the water-soluble viscosity reducer is 10t.

[0244] Step 2: Assist in injecting carbon dioxide foam to adjust the steam absorption profile, increase formation energy, maintain reservoir pressure, and at the same time reduce crude oil viscosity, thereby 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 oil displacement agent injection amount is 17t.

[0246] Step 4: Calculate and optimize the steam chamber inclination angle to approximately 61°, with an injection steam volume of 3100t;

[0247] Step 5: After the well has been sealed for 2-3 days, production can begin.

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

[0249] Finally, it should be noted that the above description is merely 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 foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or make equivalent substitutions for some of the technical features. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

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

Claims

1. A method for enhancing oil recovery through multi-stage huff-and-puff horizontal wells using multi-element thermal fluid pressure control and drainage, characterized in that: The multi-stage, multi-element thermal fluid pressure-controlled drainage method for enhancing oil recovery in horizontal wells includes: Step 1: Inject a viscosity reducer into the reservoir; Step 2: Inject foam or gas into the reservoir; Step 3: Inject a high-temperature resistant oil displacement agent into the reservoir; Step 4: Inject high-temperature steam into the reservoir; Step 5: After the well is sealed, it is opened for production; In step 2, the injection fluid type is selected based on the reservoir properties. Wells with severe gas channeling are injected with foam, with nitrogen foam injected in the shallow layer and carbon dioxide foam injected in the deep layer. For wells with weak gas channeling, nitrogen or carbon dioxide is injected, with nitrogen injected in the shallow layer and carbon dioxide injected in the deep layer. The injection volume of nitrogen and carbon dioxide is optimized using numerical simulation software. In step 4, the oil production rate at different steam chamber inclination angles is calculated to determine the optimal oil discharge angle, thereby guiding the steam injection rate.

2. The method for enhancing oil recovery in multi-stage horizontal wells with multi-element thermal fluid pressure control and drainage according to claim 1, characterized in that, In step 1, the current 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 short huff and puff cycles, the viscosity reduction requirement is higher, so oil-soluble viscosity reducers are used; for wells with long huff and puff cycles, the requirement to expand the impact is higher, so water-soluble viscosity reducers are used; the injection volume of viscosity reducers is optimized using numerical simulation software.

3. The method for enhancing oil recovery in multi-stage horizontal wells with multi-element thermal fluid pressure control and drainage according to claim 1, characterized in that, In step 3, the injection of oil displacement agent is determined according to the reservoir development needs. If the huff and puff cycle is short, no oil displacement agent is injected; if the huff and puff cycle is long, a high-temperature resistant oil displacement agent is injected. The injection amount of oil displacement agent is optimized using numerical simulation software.

4. The method for enhancing oil recovery in multi-stage horizontal wells with multi-element thermal fluid pressure control and drainage according to claim 1, characterized in that: In step 4, The heat exchange in the direction perpendicular to the steam chamber interface is expressed by the following formula: Where x is the horizontal distance; K is the reservoir thermal conductivity; T is the temperature distribution at the edge of the steam chamber; and V is the distance. c ρ is the convection velocity perpendicular to the steam chamber direction. c c is the density of the condensate. pc ρ is the heat capacity of the condensate; r c is the reservoir density; pr t represents the reservoir heat capacity; t represents 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 formula represents the relationship between x and ξ: Transform the derivative in equation (1) according to equation (2): Substituting the above three equations into equation (1), we get: After sorting, we get: Assuming quasi-steady-state heat conduction at the edge of the steam cavity, therefore: Substituting equation (8) into equation (7), we can obtain the heat exchange formula at the edge of the steam chamber during the production process: When convection is ignored, that is, the fluid velocity 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: Solve the above equation using the substitution integration method: Where T* is the dimensionless temperature; T r T represents the temperature of the crude oil reservoir. st α is the steam injection temperature; α is the reservoir thermal diffusivity. The convection velocity at the edge of the steam chamber perpendicular to the steam chamber interface is calculated using the following formula: V c =V cp +V cg (14) Among them, V cp V represents the convection velocity perpendicular to the steam chamber caused by the pressure difference. cg The convection velocity perpendicular to the steam cavity caused by the gravitational component; Calculate the convective velocity caused by pressure difference and gravitational component based on fluid mechanics principles: 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 mobility of the convective phase at different locations; g is the acceleration due to gravity; k is the absolute permeability at any location; k rw k represents the relative permeability of the water phase at any location. ro μo is the relative permeability of the oil phase at any location; μo is the dynamic viscosity of the oil phase; ... w The dynamic viscosity of the aqueous phase; The equation for the oil saturation distribution at the edge of the steam chamber is as follows: S o =S or +(S io -S or )(1-T * ) (18) According to the Corey formula, the relative permeability of the aqueous and oil phases is calculated using the following formula: k rw =k rwro (S wD ) b (19) k ro =k rocw S oD a (1-T * ) a (21) Where a is the Corey coefficient; b is the Corey coefficient; k rwro S represents the relative permeability of the aqueous phase at residual oil saturation. wD S is the dimensionless water saturation. w Water saturation; S wc S represents the bound water saturation. or k represents the residual oil saturation. rocw S represents the relative permeability of the oil phase at bound water saturation. oD The oil saturation is dimensionless. The following relationship exists between dimensionless oil saturation and dimensionless water saturation: S wD =1-S oD (1-T * ) (23) Substituting into equation (19), the relative permeability of the water phase is: k rw =k rwro [1-S oD (1-T * )] b (24); The density and heat capacity of the convective phase are calculated using the following formulas: Where, ρ c ρ is the density of the convective phase. o ρ is the density of the oil phase; w c is the density of the aqueous phase. pc c is the heat capacity of the convective phase; o c is the heat capacity of the oil phase; w The heat capacity of the aqueous phase; Substituting equation (16) into the two equations above, we can obtain the distribution functions of the flow 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, as shown in the following formula: 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) The relationships between oil phase viscosity and water phase viscosity and temperature distribution are obtained as follows: Where m is the viscosity-temperature index; Substituting equations (21), (24), (33), and (34) into equation (17), we get: The relationship between oil phase viscosity, water phase viscosity, and temperature distribution was obtained from the research: The formula for the convection velocity caused by pressure difference also includes the derivative of pressure; drawing on the relationship between viscosity and temperature distribution (33), it is assumed that the following relationship exists between crude oil viscosity and pressure distribution: Where, ν st ν is the kinematic viscosity of the oil phase at steam temperature; o The viscosity of the oil phase at different locations on the edge of the steam chamber is denoted as n; n is the pressure-temperature index. From equations (33) and (37), the relationship between the pressure distribution and temperature distribution at the edge of the steam chamber can be obtained: Differentiating both sides of the above equation with respect to distance ξ, we can obtain the derivative of pressure: Substituting equation (12) into the above equation, we get: Therefore, the formula for calculating the convection velocity caused by pressure difference can be obtained: To solve this model, the apparent thermal diffusivity α* is introduced. The formula for calculating flow rate is: The liquid and oil production rates during the production process are as follows: q liq =∫λρ c gsinθdξ (44) q o =∫λρ c gsinθS oD (1-T * )dξ (45)。 5. The method for enhancing oil recovery in multi-stage horizontal wells with multi-element thermal fluid pressure control and drainage according to claim 1, characterized in that, In step 5, the well is shut in 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 that 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 then put into production. The bottom flow pressure of the horizontal well should not be too low, and stable pressure production should be ensured as much as possible.

6. The method for enhancing oil recovery in multi-stage horizontal wells with multi-element thermal fluid pressure control and drainage according to claim 1, characterized in that, The multi-round churn-and-purge horizontal well multi-element thermal fluid pressure control and oil drainage method for enhancing oil recovery also includes, after step 5, step 6, which uses daily oil production as the cutoff condition for cycle development.

7. The method for enhancing oil recovery in multi-stage horizontal wells with multi-element thermal fluid pressure control and drainage according to claim 5, characterized in that, In step 6, once the daily oil production drops to 1 t / d, a cycle development is carried out to ensure a certain production capacity while maintaining the formation temperature, thus providing a foundation for subsequent cavity creation.

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