Method for improving seepage and heat transfer capabilities of oil sand reservoir by using hydrophobic carbon nanotubes

Abstract

The invention discloses a method for improving seepage and heat transfer capacity of an oil sand reservoir by using hydrophobic carbon nanotubes. The method comprises the following steps: configuring any combination of M carbon nanotubes and N carbon nanotubes with different concentrations; drilling an underground rock core of a reservoir section on site in an oil field, obtaining a standard rock core column indoors, and testing the heat conduction coefficient of the standard rock core; the standard rock core columns are soaked in the carbon nano tube nanofluid, fluid pressure is set through a supercharger, and the heat conduction coefficient of the soaked rock core columns is tested; calculating the heat conduction strengthening coefficient of each rock core column soaked by the carbon nanotube nanofluid, and drawing a scatter diagram; on the premise that the heat conduction strengthening effect and economical efficiency are comprehensively considered, the optimal type and concentration of the carbon nano tubes matched with a construction stratum are screened and determined, and a large number of carbon nano tube nanofluids of the type are configured according to site requirements; and reasonably controlling the wellhead pressure of the well I and the well P to gradually and slowly squeeze the carbon nanotube nanofluid into the oil sand reservoir. The problem that in an existing oil sand liquid squeezing technology, the heat convection effect of a reservoir is poor is solved.

Description

Technical Field

[0001] The present invention belongs to the technical field of unconventional oil and gas reservoir transformation and oil and gas development, and specifically relates to a method for improving the seepage and heat transfer capacity of oil sand reservoirs by utilizing hydrophobic carbon nanotubes. Background Art

[0002] Oil sands are a type of rock containing extremely high-viscosity hydrocarbons that cannot be recovered using traditional oil well production methods under pristine reservoir conditions. The hydrocarbons in oil sands are typically bitumen, a diverse range of reddish-brown to black semi-solid, viscous to brittle materials. Asphalt is often found filling the pores and cracks of sandstone, limestone, and mudstone sediments, hence the name rock asphalt. Natural asphalt reservoirs generally have low permeability and are completely non-free-flowing at pristine reservoir temperatures, necessitating extreme methods such as steam stimulation, steam flooding, and steam-assisted gravity drainage to recover the bitumen.

[0003] Currently, most of the world's oil sands resources are extracted through steam-assisted gravity drainage (SAGD). During SAGD construction, two parallel horizontal wells are drilled into the oil sands reservoir, with the gas injection well located directly above the production well. High-temperature steam is injected through the gas injection well to heat the asphalt, causing it to flow toward the production well under the influence of gravity. SAGD technology has a high oil recovery rate and is currently widely used both domestically and internationally. Reservoir heat transfer during the SAGD process involves two processes: conduction and convection. The reservoir's heat transfer capacity is a combined result of these two effects. SAGD technology consists of two phases: preheating and production. During the preheating phase, steam is typically injected simultaneously through two horizontal wells, or electric heating techniques are used, to create uniform thermal connectivity between the wells. During the production phase, gas injection into the production well is stopped, while the gas injection well continues, creating a uniform steam chamber along the wellbore. The heated crude oil and condensed water flow along the steam chamber boundary into the production well for extraction.

[0004] During the SAGD preheating phase, the reservoir heat transfer rate determines the preheating time; during the production phase, the reservoir heat transfer rate determines the rate of steam chamber development, ultimately affecting crude oil production. Insufficient reservoir heat transfer capacity will result in high preheated output fluid processing pressure, long preheating times, slow production, a low oil-gas ratio, and low production. To shorten the SAGD preheating time and increase production, a dual-horizontal well circulation water injection method is currently used on-site to squeeze fluid into the formation in order to induce a large number of microfractures near the wellbore, increase permeability, porosity, and water saturation, enhance the convective heat transfer capacity of the reservoir, and shorten the preheating time. At the same time, hydrophobic nanofluids can change the wettability of the reservoir, reduce the thickness of the bound water film, and increase the effective permeability of water at the interfacial chemical level.

[0005] However, during the squeeze process, the reservoir absorbs little water, the pore fluid flow rate is slow, and most reservoirs, especially those far from the wellbore, experience minimal changes in water saturation. This results in a low fluid pressure gradient and a minimal increase in convective heat transfer capacity. Furthermore, continental oil sands have low expansion potential and poor in-situ stress conditions, resulting in poor expansion and an even smaller increase in thermal convection capacity. Therefore, to address this issue of poor thermal convection during the squeeze process, there is an urgent need to develop a method to improve the thermal conductivity of oil sands reservoirs and enhance their overall heat transfer capacity.

[0006] In addition to SAGD technology, the heat transfer capacity of the reservoir also directly affects the distribution of temperature and viscosity fields in processes such as steam stimulation and steam flooding, and thus affects crude oil production. Therefore, it is necessary to utilize the enhanced heat transfer mechanism of carbon nanotube nanofluids to improve the thermal conductivity of oil sands reservoirs and the heat transfer coefficient at the solid-liquid interface between fluid and particles. Summary of the Invention

[0007] In order to overcome the deficiencies of the above-mentioned prior art, the purpose of the present invention is to provide a method for improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes, thereby solving the problem of poor reservoir thermal convection in existing oil sand squeezing technology. Without affecting the squeezing expansion effect, the enhanced permeability, ultra-high thermal conductivity and enhanced heat transfer mechanism of hydrophobic carbon nanotubes are used to improve the thermal conductivity and solid-liquid interface heat transfer coefficient of the oil sand reservoir, thereby improving the comprehensive heat transfer capacity of the oil sand reservoir, shortening the SAGD preheating cycle and increasing crude oil production.

[0008] In order to achieve the above object, the technical solution adopted by the present invention is:

[0009] A method for improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes, characterized by comprising the following steps:

[0010] Step 1: Prepare 500 mL of each of M×N nanofluids with any combination of M carbon nanotube types and N carbon nanotube concentrations, numbered n1, n2…n M×N ;

[0011] Step 2: Drill downhole cores from the reservoir section at the oil field site, obtain M×N standard core columns indoors, and test the thermal conductivity coefficients of the standard cores, which are recorded as α1, α2…α M×N ;

[0012] Step 3: Soak M×N standard core columns in M×N carbon nanotube nanofluids for 2.5 days respectively, and set the fluid pressure to P through the booster. max井底 , the thermal conductivity coefficients of the core column after immersion are measured and recorded as α'1, α'2…α' M×N ;

[0013] Step 4: Calculate the thermal conductivity enhancement coefficient of each core column after soaking in carbon nanotube nanofluid, that is, the ratio of the thermal conductivity coefficient after soaking to the initial thermal conductivity coefficient, which are recorded as I1, I2…I M×N , a scatter plot is drawn with the types of carbon nanotubes as different legends, the concentration of nanofluid as the horizontal axis, and the thermal conductivity enhancement coefficient as the vertical axis;

[0014] Step 5: Taking into account the heat conduction enhancement effect and economic efficiency, screen and determine the optimal carbon nanotube type and concentration suitable for the construction stratum, and configure a large amount of such carbon nanotube nanofluid according to site needs;

[0015] Step 6: Reasonably control the wellhead pressure of Well I and Well P to gradually and slowly squeeze the carbon nanotube nanofluid into the oil sand reservoir.

[0016] In the step 1, the carbon nanotube nanoparticles refer to particles having at least one dimension smaller than 100 nanometers.

[0017] In the step 1, the base fluid of the carbon nanotube nanofluid is a brine solution that matches the formation production fluid.

[0018] The solutes in the brine solution mainly include Na + , K + , Ca + Mg + Isocations and Cl - 、SO4 2- 、HCO3 - 、CO3 2- Anions.

[0019] The brine solution can be directly formed from formation water treated with crude oil, or can be prepared from brine in indoor experiments.

[0020] In the step 1, the concentration of carbon nanotube nanoparticles refers to the mass percentage of carbon nanotube nanoparticles, specifically refers to the ratio of the mass of carbon nanotube nanoparticles to the total mass of carbon nanotube nanofluid.

[0021] In the step 1, the upper critical value of the carbon nanotube nanoparticle concentration is set to C max , the lower critical value is set to 0.

[0022] In the step 1, the concentrations of the N types of carbon nanotube nanoparticles are set according to the isogradient rule, that is, the difference between each two adjacent concentrations is C max / (N-1).

[0023] In the step 1, the carbon nanotube nanofluid is prepared by a two-step method, wherein the prepared carbon nanotube nanoparticles are dispersed into the base liquid by some means, and the preparation and dispersion process are carried out in two steps.

[0024] The two-step method specifically refers to combining carbon nanotube nanopowder and liquid in a predetermined ratio, mixing them with a magnetic stirrer for 15 minutes, then dispersing them with ultrasound for 15 minutes, and finally stirring them with magnetic stirring for 15 minutes to make the suspension form a uniform and well-dispersed carbon nanotube nanofluid.

[0025] In the step 2, the downhole core of the reservoir section is the core taken up by the coring drill bit.

[0026] In step 2, coring into standard cores indoors means that the cores taken out by the coring drill bit are processed into standard cylinders with a diameter of 25 mm and a length of 50 mm by manual or mechanical methods.

[0027] The standard cores need to be sealed in a sealed bag and stored in a refrigerator at -20°C.

[0028] In the step 2, the test method of the thermal conductivity includes two methods: a steady-state method and a non-steady-state method.

[0029] In the step 3, in P max井底 The purpose of soaking under pressure is to simulate the actual pore pressure of the downhole reservoir and fully saturate the core with the carbon nanotube nanofluid.

[0030] In the step 3, P max井底 The maximum bottom hole pressure for squeezing operation is set to a value 0.5 MPa less than the formation fracture pressure.

[0031] In the step 4, the horizontal and vertical coordinate axes are both conventional linear coordinate axes.

[0032] In step 5, the quantitative evaluation method of the heat conduction enhancement effect is as follows: when the heat conduction enhancement coefficient is less than 5%, the heat conduction enhancement effect is poor; when the heat conduction enhancement coefficient is greater than 5% and less than 25%, the heat conduction enhancement effect is good; when the heat conduction enhancement coefficient is greater than 25%, the heat conduction enhancement effect is very good.

[0033] In step 5, the economic evaluation criteria for the types of carbon nanotube nanoparticles are: at the same concentration, when the thermal conductivity enhancement coefficient is less than 5%, the carbon nanotube nanoparticles with low prices are preferred; otherwise, the carbon nanotube nanoparticles with good or very good thermal conductivity enhancement effects are selected.

[0034] In step 5, the economic evaluation criteria for the carbon nanotube nanoparticle concentration are: when the heat conduction enhancement coefficient is less than 5% under the same type of carbon nanotube nanoparticles, a low concentration of carbon nanotube nanofluid is preferably selected; otherwise, a carbon nanotube nanofluid concentration with good or very good heat conduction enhancement effect is selected.

[0035] In step 6, the formation fracture pressure at the vertical depth of well P needs to be calculated as P b , the hydrostatic pressure at the vertical depth of well P is P w The maximum bottom hole pressure calculated for squeezing operation is 0.5 MPa less than the formation fracture pressure, that is, P max井底 =P b -0.5; the maximum wellhead pressure for squeezing operation is calculated as the difference between the maximum bottom hole pressure and the static liquid column pressure, that is, P max井口 =P max井底 -P w .

[0036] In step 6, after calculating the key parameters, the SAGD well is cleaned, and then the wellhead pressures of wells P and I are controlled simultaneously to keep the wellhead pressures of the two wells consistent; the pressure is increased step by step in four stages until the maximum wellhead pressure is reached, and the pressure increase amplitude of each stage is ΔP = P max井口 / 4, the completion time of each level of pressure increase is 30-60min; after the first three stages of pressure increase, the constant pressure is maintained for 12h, and after the fourth stage of pressure increase, the constant pressure is maintained for 24h, and the transformation is completed.

[0037] The beneficial effects of the present invention are:

[0038] Starting from improving the thermal conductivity and thermal convection coefficients of the oil sand reservoir, the comprehensive heat transfer capacity of the reservoir can be improved. Among them, the way to improve the thermal conductivity of the reservoir is to effectively increase the thermal conductivity of the pore fluid under the premise of ensuring economic efficiency; the way to improve the thermal convection capacity of the reservoir is to squeeze carbon nanotube nanofluid into the formation, such as Figure 3 As shown, under certain geostress conditions, shear and tensile microcracks develop in the reservoir, effectively increasing the reservoir's porosity, permeability, and water saturation, thereby improving convective heat transfer capacity. Furthermore, carbon nanotube nanofluids can increase the density and bulk modulus of liquids, reduce their compressibility, and enhance their squeeze capacity. They can also increase the convective heat transfer coefficient between the fluid and solid particles, enabling the porous fluid to rapidly heat the rock matrix and increase the overall heat transfer rate of the reservoir. They can also weaken and reduce the wettability of rocks, shifting from oil-wet to water-wet, thereby enhancing oil recovery. Residual carbon nanotube nanofluids in the formation can also increase the thermal conductivity and convection capacity of the reservoir outside the steam chamber, increasing crude oil production.

[0039] The construction sequence involved in this invention precedes various thermal oil recovery methods and can be successfully completed using existing well types, surface and downhole tubing. This method can significantly improve the thermal conductivity and convection capacity of oil sand reservoirs, is low-cost, and has rapid results, making it applicable to various thermal oil recovery technologies. BRIEF DESCRIPTION OF THE DRAWINGS

[0040] Figure 1It is a flow chart of the present invention.

[0041] Figure 2 This is a graph of the types and concentrations of nanoparticles of the present invention.

[0042] Figure 3 This is a schematic diagram of downhole core drilling of a reservoir section in an oil field according to an embodiment of the present invention.

[0043] Figure 4 This is a schematic diagram of a vertical core according to the present invention.

[0044] Figure 5 Schematic diagram of nanofluid concentration and thermal conductivity enhancement coefficient of the present invention.

[0045] Figure 6 This is a schematic diagram of the pressure pipeline of an embodiment of the present invention.

[0046] Figure 7 Flowchart for quantitative evaluation of the heat conduction enhancement effect according to an embodiment of the present invention.

[0047] Figure 8 Schematic diagram of economic evaluation of nanoparticle concentration in an embodiment of the present invention.

[0048] Figure 9 Schematic diagram of economic evaluation of nanoparticle concentration in an embodiment of the present invention.

[0049] Figure 10 This is a graph showing the time variation of the inlet pressure of an embodiment of the present invention. DETAILED DESCRIPTION

[0050] The present invention will be further described below with reference to the accompanying drawings and embodiments.

[0051] Example 1:

[0052] like Figure 1 As shown, according to an embodiment of the method of improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes of the present invention, the method includes the following steps in order:

[0053] Step 1: If Figure 2 As shown in the figure, M×N nanofluids with arbitrary combinations of M nanoparticle types and N nanoparticle concentrations are configured, each 500 mL, numbered n1, n2…n M× N;

[0054] Step 2: If Figure 3 As shown, the reservoir section downhole core is drilled on site in the oil field, and M×N standard core columns are obtained indoors. The thermal conductivity coefficients of the standard cores are tested and recorded as α1, α2…α M×N ;

[0055] Step 3: Soak M×N standard core columns in M×N nanofluids for 2.5 days respectively. Figure 6 As shown, the fluid pressure is set to P by the intensifier. max井底 , the thermal conductivity coefficients of the core column after immersion are measured and recorded as α'1, α'2…α' M×N ;

[0056] Step 4: Calculate the thermal conductivity enhancement coefficient of each core column after being soaked in nanofluid, that is, the ratio of the thermal conductivity coefficient after soaking to the initial thermal conductivity coefficient, which are recorded as I1, I2…I M×N ;like Figure 5 As shown, a scatter plot is drawn with the types of nanoparticles as different legends, the concentration of nanofluid as the horizontal axis, and the thermal conductivity enhancement coefficient as the vertical axis;

[0057] Step 5: Taking into account the heat conduction enhancement effect and economic efficiency, screen and determine the optimal nanoparticle type and concentration suitable for the construction stratum, and configure a large amount of such nanofluid according to site needs;

[0058] Step 6: If Figure 10 As shown in Figure 3, the wellhead pressures of Wells I and P are properly controlled to gradually and slowly squeeze the nanofluid into the oil sand reservoir.

[0059] In the step 1, the carbon nanotube nanoparticles refer to particles having at least one dimension smaller than 100 nanometers.

[0060] In the step 1, the base fluid of the nanofluid is a brine solution that matches the formation production fluid.

[0061] The solutes in the brine solution mainly include Na + , K + , Ca + Mg + Isocations and Cl - 、SO4 2- 、HCO3 - 、CO3 2- Anions.

[0062] The brine solution can be directly formed from formation water treated with crude oil, or can be prepared from brine in indoor experiments.

[0063] In the step 1, the nanoparticle concentration refers to the mass percentage of the nanoparticles, specifically the ratio of the mass of the nanoparticles to the total mass of the nanofluid.

[0064] In step 1, the upper critical value of the nanoparticle concentration is set to C max , the lower critical value is set to 0.

[0065] In the step 1, the concentrations of the N nanoparticles are set according to the isogradient rule, that is, the difference between each two adjacent concentrations is C max / (N-1).

[0066] In the step 1, the nanofluid is prepared in a two-step method, wherein the prepared nanoparticles are dispersed into the base liquid by some means, and the preparation and dispersion process is carried out in two steps.

[0067] The two-step method specifically refers to combining the nanopowder and liquid in a predetermined ratio, mixing them with a magnetic stirrer for 15 minutes, then dispersing them with ultrasound for 15 minutes, and finally stirring them with magnetic stirring for 15 minutes to form a uniform and well-dispersed nanofluid suspension.

[0068] In the step 2, the downhole core of the reservoir section is the core taken up by the coring drill bit.

[0069] In step 2, coring into standard cores indoors means that the cores taken out by the coring drill bit are processed into standard cylinders with a diameter of 25 mm and a length of 50 mm by manual or mechanical methods.

[0070] The standard cores need to be sealed in a sealed bag and stored in a refrigerator at -20°C.

[0071] In the step 2, the test method of the thermal conductivity includes two methods: a steady-state method and a non-steady-state method.

[0072] In the step 3, in P max井底 The purpose of immersion under pressure is to simulate the actual pore pressure of the downhole reservoir and fully saturate the core with nanofluid.

[0073] In the step 3, P max井底 The maximum bottom hole pressure for squeezing operation is set to a value 0.5 MPa less than the formation fracture pressure.

[0074] In the step 4, the horizontal and vertical coordinate axes are both conventional linear coordinate axes.

[0075] In step 5, the quantitative evaluation method of the heat conduction enhancement effect is as follows: when the heat conduction enhancement coefficient is less than 5%, the heat conduction enhancement effect is poor; when the heat conduction enhancement coefficient is greater than 5% and less than 25%, the heat conduction enhancement effect is good; when the heat conduction enhancement coefficient is greater than 25%, the heat conduction enhancement effect is very good.

[0076] In step 5, the economic evaluation criteria of the nanoparticle types are: at the same concentration, when the heat conduction enhancement coefficient is less than 5%, the nanoparticle types with low prices are preferred; otherwise, the nanoparticle types with good or very good heat conduction enhancement effects are selected.

[0077] In step 5, the economic evaluation criteria for the nanoparticle concentration are: when the heat conduction enhancement coefficient is less than 5% under the same nanoparticle type, a low concentration of nanofluid is preferred; otherwise, a nanofluid concentration with good or very good heat conduction enhancement effect is selected.

[0078] In step 6, the formation fracture pressure at the vertical depth of well P needs to be calculated as P b , the hydrostatic pressure at the vertical depth of well P is P w The maximum bottom hole pressure calculated for squeezing operation is 0.5 MPa less than the formation fracture pressure, that is, P max井底 =P b -0.5; the maximum wellhead pressure for squeezing operation is calculated as the difference between the maximum bottom hole pressure and the static liquid column pressure, that is, P max井口 =P max井底 -P w .

[0079] In step 6, after calculating the key parameters, the SAGD well is cleaned, and then the wellhead pressures of wells P and I are controlled simultaneously to keep the wellhead pressures of the two wells consistent; the pressure is increased step by step in four stages until the maximum wellhead pressure is reached, and the pressure increase amplitude of each stage is ΔP = P max井口 / 4, the completion time of each level of pressure increase is 30-60min; after the first three stages of pressure increase, the constant pressure is maintained for 12h, and after the fourth stage of pressure increase, the constant pressure is maintained for 24h, and the transformation is completed.

[0080] This example is a SAGD well in the Fengcheng Oilfield, Xinjiang. The vertical depth of well I is 372 m, the vertical depth of well P is 377 m, and the reservoir formation fracture pressure gradient is 0.016 MPa / m. M=5 and N=4 are selected, that is, 20 nanofluids with 500 mL each of 5 combinations of 5 nanoparticle types and 4 nanoparticle concentrations are prepared, numbered n1, n2, ..., n 20 ; Drill downhole cores from the reservoir section at the oil field site, obtain 20 standard core columns indoors, and test the thermal conductivity coefficients of the standard cores, which are recorded as α1, α2…α 20 ; 20 standard core columns were immersed in 20 nanofluids for 2.5 days respectively; the fluid pressure was set to P by the intensifier max井底 =5.5MPa, the thermal conductivity coefficient of the core column after immersion is tested and recorded as α'1, α'2...α' 20 ; Calculate the thermal conductivity enhancement coefficient of each core column after nanofluid immersion, that is, the ratio of the core soaked to the initial thermal conductivity coefficient, which are recorded as I1, I2…I 20 .

[0081] In this embodiment, the five types of nanoparticles are five different types of carbon nanotubes, and the particle size of the nanoparticles is between 20-30nm. The base fluid of the nanofluid is a brine solution that matches the formation production fluid, wherein the solute composition is: HCO3 - The concentration is 1496.15 mg / L, Cl - The concentration is 1950.53 mg / L, Ca + The concentration is 7.33 mg / L, Na + and K + The concentration is 2003.16 mg / L and the total mineralization is 4970.24 mg / L.

[0082] In this embodiment, the nanoparticle concentration refers to the ratio of the mass of the nanoparticles to the total mass of the nanofluid. The upper critical value of the nanoparticle concentration is set to 9%, and the lower critical value is set to 0. The four nanoparticle concentrations are set according to the isogradient rule, that is, the difference between each two adjacent concentrations is 9% / (4-1)=3%; the nanofluid is configured using a two-step method, in which the nanopowder and liquid are combined in a predetermined ratio, mixed with a magnetic stirrer for 15 minutes, then ultrasonically dispersed for 15 minutes, and finally magnetically stirred for 15 minutes to form a uniform and well-dispersed nanofluid suspension.

[0083] like Figure 4 As shown, in this embodiment, according to Figure 3 , take four vertical cores. Use manual or mechanical methods to process the cores taken out by the coring drill into standard cylinders with a diameter of 25mm and a length of 50mm. The standard cores need to be sealed in a sealed bag and stored in a refrigerator at -20℃.

[0084] In this embodiment, the thermal conductivity is tested using a steady-state method.

[0085] In this embodiment, according to Figure 7 The process shown here uses a quantitative evaluation method for heat conduction enhancement: a heat conduction enhancement coefficient less than 5% indicates poor heat conduction enhancement; a heat conduction enhancement coefficient greater than 5% and less than 25% indicates good heat conduction enhancement; and a heat conduction enhancement coefficient greater than 25% indicates excellent heat conduction enhancement. Taking armchair nanotube nanofluid as an example, four vertical rock cores were saturated with armchair nanotube nanofluid concentrations of 0, 3%, 6%, and 9%, respectively. Assuming the heat conduction enhancement coefficients are 0, 10%, 26%, and 30%, respectively, the heat conduction enhancement effects of the four different armchair nanotube nanofluid concentrations are ranked as poor, good, very good, and excellent.

[0086] In this embodiment, according to Figure 8In the process shown, the economical evaluation criteria for nanoparticle types is that, at the same concentration, if the difference in thermal conductivity enhancement coefficient is less than 5%, the less expensive nanoparticle type is preferred; otherwise, the nanoparticle type with good or very good thermal conductivity enhancement is selected. Taking a 3% concentration as an example, four vertical cores were saturated with five carbon nanotube nanofluids at 3% concentration, assuming thermal conductivity enhancement coefficients of 0, 10%, 26%, and 30%, respectively. Since the difference in thermal conductivity enhancement coefficients between the carbon nanofluid and the copper oxide nanofluid is less than 5%, and carbon nanotube nanoparticles are cheaper than copper oxide nanoparticles, the carbon nanotube nanofluid is preferred at a 3% concentration.

[0087] In this embodiment, according to Figure 9 In the process shown, the economical evaluation criteria for nanoparticle concentration are: when the difference in thermal conductivity enhancement coefficients for the same nanoparticle type is less than 5%, a lower nanofluid concentration is preferred; otherwise, a nanofluid concentration with good or very good thermal conductivity enhancement is selected. Taking armchair nanotube nanofluid as an example, four vertical cores were saturated with molybdenum sulfide nanofluids at concentrations of 0, 3%, 6%, and 9%, respectively, assuming thermal conductivity enhancement coefficients of 0, 10%, 26%, and 30%, respectively. Since the difference in thermal conductivity enhancement coefficients between the 9% and 6% armchair nanotube nanofluids is less than 5%, the 6% concentration is preferred for armchair nanotube nanoparticles.

[0088] In this example, the maximum wellhead pressure P during the squeezing operation is calculated. max出口 =1.8MPa. Wells I and P were squeezed in four stages: In the first stage, the wellhead pressure of all three wells was increased from 0 to 0.45MPa within 60 minutes and maintained at 0.45MPa for 12 hours; in the second stage, the wellhead pressure of all three wells was increased from 0.45MPa to 0.9MPa and maintained at 0.9MPa for 12 hours; in the third stage, the wellhead pressure of all three wells was increased from 0.9MPa to 1.35MPa and maintained at 1.35MPa for 12 hours; in the fourth stage, the wellhead pressure of all three wells was increased from 1.35MPa to 1.8MPa and maintained at 1.8MPa for 24 hours, completing the stimulation.

[0089] Example 2:

[0090] According to another embodiment of the method for improving the seepage and heat transfer capacity of oil sand reservoirs by using hydrophobic carbon nanotubes of the present invention, the modification steps, working principle, beneficial effects, etc. are the same as those of the first embodiment, except that the coring direction of the standard core column is as follows: Figure 3Four longitudinal cores were taken. This embodiment can reflect the horizontal heat transfer capacity of the oil sand reservoir before and after nanofluid saturation.

[0091] Example 3:

[0092] According to another embodiment of the method for improving the seepage and heat transfer capacity of oil sand reservoirs by using hydrophobic carbon nanotubes of the present invention, the modification steps, working principle, beneficial effects, etc. are the same as those of the first embodiment, except that the coring direction of the standard core column is as follows: Figure 3 Two longitudinal cores and two transverse cores were taken. This embodiment can reflect the heat transfer capacity of the oil sand reservoir in the vertical and horizontal directions before and after nanofluid saturation.

[0093] Example 4:

[0094] According to another embodiment of the method for improving the heat transfer capacity of oil sand reservoirs using nanofluids of the present invention, the transformation steps, working principles, and beneficial effects are the same as those of the first embodiment, except for the matching relationship between the various parameters in the transformation steps:

[0095] This example is a SAGD well in Fengcheng Oilfield, Xinjiang. The vertical depth of well I is 372m, the vertical depth of well P is 377m, and the reservoir formation fracture pressure gradient is 0.017MPa / m. The maximum wellhead pressure P during the squeeze operation is calculated. max出口 =2.2MPa. Wells I and P were squeezed in four stages: In the first stage, the wellhead pressure of all three wells was increased from 0 to 0.55MPa within 50 minutes and maintained at 0.55MPa for 12 hours; in the second stage, the wellhead pressure of all three wells was increased from 0.55MPa to 1.1MPa and maintained at 1.1MPa for 12 hours; in the third stage, the wellhead pressure of all three wells was increased from 1.1MPa to 1.65MPa and maintained at 1.65MPa for 12 hours; in the fourth stage, the wellhead pressure of all three wells was increased from 1.65MPa to 2.2MPa and maintained at 2.2MPa for 24 hours, completing the stimulation.

Claims

1. A method for improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes, characterized in that: The following steps are involved: Step 1: Prepare 500 mL of each of M×N nanofluids with any combination of M carbon nanotube types and N carbon nanotube concentrations, numbered n1, n2…n M×N ; Step 2: Drill downhole cores from the reservoir section at the oil field site, obtain M×N standard core columns indoors, and test the thermal conductivity coefficients of the standard cores, which are recorded as α1, α2…α M×N ; Step 3: Soak M×N standard core columns in M×N carbon nanotube nanofluids for 2.5 days respectively, and set the fluid pressure to P through the booster. max井底 , the thermal conductivity coefficients of the core column after immersion are measured and recorded as α'1, α'2…α' M×N ; Step 4: Calculate the thermal conductivity enhancement coefficient of each core column after soaking in carbon nanotube nanofluid, that is, the ratio of the thermal conductivity coefficient after soaking to the initial thermal conductivity coefficient, which are recorded as I1, I2…I M×N , a scatter plot is drawn with the types of carbon nanotubes as different legends, the concentration of nanofluid as the horizontal axis, and the thermal conductivity enhancement coefficient as the vertical axis; Step 5: Taking into account the heat conduction enhancement effect and economic efficiency, screen and determine the optimal carbon nanotube type and concentration suitable for the construction stratum, and configure a large amount of such carbon nanotube nanofluid according to site needs; Step 6: Reasonably control the wellhead pressure of Well I and Well P to gradually and slowly squeeze the carbon nanotube nanofluid into the oil sand reservoir.

2. The method of improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes according to claim 1, characterized in that: In the step 1, the carbon nanotube nanoparticles refer to particles smaller than 100 nanometers in at least one dimension; in the step 1, the base fluid of the carbon nanotube nanofluid is a brine solution that matches the formation production fluid; in the step 1, the concentration of the carbon nanotube nanoparticles refers to the mass percentage of the carbon nanotube nanoparticles, specifically the ratio of the mass of the carbon nanotube nanoparticles to the total mass of the carbon nanotube nanofluid; in the step 1, the upper critical value of the carbon nanotube nanoparticle concentration is set to C max , the lower critical value is set to 0; in step 1, the concentrations of N carbon nanotube nanoparticles are set according to the equal gradient rule, that is, the difference between each two adjacent concentrations is C max / (N-1); In the step 1, the configuration method of the carbon nanotube nanofluid adopts a two-step method, the prepared carbon nanotube nanoparticles are dispersed into the base liquid by some means, and the preparation and dispersion process is carried out in two steps.

3. The method of improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes according to claim 1, characterized in that: The solutes in the brine solution mainly include Na + , K + , Ca + Mg + Isocations and Cl - 、SO4 2- 、HCO3 - 、CO3 2- Anions.

4. The method of improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes according to claim 2, characterized in that: The two-step method specifically refers to combining carbon nanotube nanopowder and liquid in a predetermined ratio, mixing them with a magnetic stirrer for 15 minutes, then dispersing them with ultrasound for 15 minutes, and finally stirring them with magnetic stirring for 15 minutes to make the suspension form a uniform and well-dispersed carbon nanotube nanofluid.

5. The method of improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes according to claim 1, characterized in that: In the step 2, the downhole core of the reservoir section is the core taken up by the coring drill bit; in the step 2, coring into a standard core indoors is to process the core taken up by the coring drill bit into a standard cylinder with a diameter of 25 mm and a length of 50 mm by manual or mechanical methods; the test method of the thermal conductivity coefficient includes two methods: steady-state method and non-steady-state method.

6. The method of improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes according to claim 5, characterized in that: The standard cores need to be sealed in a sealed bag and stored in a refrigerator at -20°C.

7. The method of improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes according to claim 1, characterized in that: In the step 3, in P max井底 The purpose of soaking under pressure is to simulate the actual pore pressure of the downhole reservoir and make the carbon nanotube nanofluid fully saturate the core; in step three, P max井底 The maximum bottom hole pressure for squeezing operation is set to a value 0.5 MPa less than the formation fracture pressure.

8. The method of improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes according to claim 1, characterized in that: In the above-mentioned step 4, the horizontal and vertical coordinate axes are both conventional linear coordinate axes.

9. The method of improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes according to claim 1, characterized in that: In the step 5, the quantitative evaluation method for the thermal conductivity enhancement effect is as follows: when the thermal conductivity enhancement coefficient is less than 5%, the thermal conductivity enhancement effect is poor; when the thermal conductivity enhancement coefficient is greater than 5% and less than 25%, the thermal conductivity enhancement effect is good; when the thermal conductivity enhancement coefficient is greater than 25%; in the step 5, the economic evaluation standard of the carbon nanotube nanoparticle type is that at the same concentration, when the thermal conductivity enhancement coefficient is less than 5%, the carbon nanotube nanoparticle type with a lower price is preferably selected; Otherwise, select a type of carbon nanotube nanoparticles with good or very good thermal conductivity enhancement effect; in step five, the evaluation standard for the economic efficiency of the carbon nanotube nanoparticle concentration is that, under the same type of carbon nanotube nanoparticles, when the thermal conductivity enhancement coefficient is less than 5%, a low concentration of carbon nanotube nanofluid is preferably selected; otherwise, select a carbon nanotube nanofluid concentration with good or very good thermal conductivity enhancement effect.

10. The method of improving the seepage and heat transfer capacity of oil sand reservoirs using hydrophobic carbon nanotubes according to claim 1, characterized in that: In step 6, the formation fracture pressure at the vertical depth of well P needs to be calculated as P b , the hydrostatic pressure at the vertical depth of well P is P w The maximum bottom hole pressure calculated for squeezing operation is 0.5 MPa less than the formation fracture pressure, that is, P max井底 =P b -0.5; the maximum wellhead pressure for squeezing operation is calculated as the difference between the maximum bottom hole pressure and the static liquid column pressure, that is, P max井口 =P max井底 -P w In step 6, after calculating the key parameters, the SAGD well is cleaned, and then the wellhead pressures of wells P and I are controlled simultaneously to keep the wellhead pressures of the two wells consistent; the pressure is increased step by step in four stages until the maximum wellhead pressure is reached, and the pressure increase amplitude of each stage is ΔP = P max井口 / 4, the completion time of each level of pressure increase is 30-60min; after the first three stages of pressure increase, the constant pressure is maintained for 12h, and after the fourth stage of pressure increase, the constant pressure is maintained for 24h, and the transformation is completed.

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