Shale gas recovery rate testing method based on gas agent-water multi-medium nanometer displacement

Abstract

The invention discloses a shale gas recovery rate testing method based on gas agent water multi-medium nano-displacement, and relates to the technical field of shale gas recovery rate testing, a gas phase component containing controlled-release gas nano-micelles, surface modified nanoparticles and a water phase are mixed, and a multi-medium displacement system is obtained; injecting the multi-medium displacement system into the inlet end of the component-based shale core sample; in the displacement process, the controlled gas release nano-micelles trigger gas release in a grading manner when reaching a set temperature or pressure threshold value, and the controlled gas release nano-micelles and a water phase cooperatively permeate into a shale pore net; monitoring the displacement progress in real time and dynamically adjusting the composition of a displacement system according to the pore pressure, the seepage rate and the nanoprobe signal before and after displacement; and the shale gas recovery ratio is calculated through gas and residual gas after collection and displacement. By designing the controlled-release gas nano-micelles, precise and continuous gas phase release and water phase co-permeation are achieved, the problems of traditional gas flooding short circuit and non-uniform displacement are solved, gas phase short circuit is inhibited, the displacement depth is increased, and the recovery efficiency is improved.

Description

Technical Field

[0001] The present invention relates to the technical field of shale gas recovery rate testing, and in particular to a shale gas recovery rate testing method based on gas-agent-water multi-media nano displacement. Background Art

[0002] Traditional shale gas recovery tests often use a single medium, pure water or pure gas, for displacement. This can lead to macropore short-circuiting, water slippage, and insufficient displacement of micropores, resulting in low recovery rates and significant discrepancies between test results and field reality. Nanomaterials have been explored to improve oil and gas displacement efficiency, but a systematic approach that balances gas-liquid synergy, porous structure adaptability, and real-time, controllable feedback is lacking.

[0003] Patent CN114991734B discloses a method for optimizing on-site drainage testing of shale gas wells based on matrix flowback capacity. The patent converts the on-site developed reservoir into a capillary cluster model based on the porosity distribution of rock samples. Based on the capillary cluster model and combined with the on-site bottomhole pressure, the bottomhole flowback capacity under the current conditions is predicted, thereby determining the production capacity of the shale gas well. Based on the production capacity, an appropriate choke is selected for pressure-controlled production, thereby achieving the goal of improving the ultimate recovery rate of the shale gas well.

[0004] The above patent quantifies the reservoir production capacity by testing on-site rock samples and develops a set of appropriate pressure-controlled production methods to guide on-site production, but it cannot accurately and continuously release the gas phase and inhibit the occurrence of gas phase short circuits.

[0005] To this end, this application proposes a shale gas recovery rate testing method based on gas-agent-water multi-media nanodisplacement that can accurately and continuously release the gas phase. Summary of the Invention

[0006] The purpose of the present invention is to provide a shale gas recovery rate testing method based on gas-agent-water multi-media nanodisplacement to solve the technical problem raised in the above background technology that the gas phase cannot be accurately and continuously released, resulting in gas drive short circuit and uneven displacement.

[0007] To achieve the above object, the present invention provides the following technical solution: a shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding, the testing method comprising the following steps:

[0008] A multi-media displacement system is obtained by mixing a gas phase component including controlled gas-releasing nanomicelles, surface-modified nanoparticles and an aqueous phase;

[0009] Injecting the multi-media displacement system into the inlet end of the structured shale core sample to establish a preset pressure gradient;

[0010] During the displacement process, the controllable gas-releasing nano-micelles trigger gas release in stages when a set temperature or pressure threshold is reached, and penetrate into the shale pore network in coordination with the water phase;

[0011] The surface-modified nanoparticles are simultaneously used to dynamically regulate the distribution of pore seepage channels and inhibit the "short-circuit" flow in large pores;

[0012] Based on the pore pressure, seepage rate and nanoprobe signals before and after displacement, the displacement progress is monitored in real time and the displacement system composition is dynamically adjusted;

[0013] The shale gas recovery rate is calculated by collecting the gas and residual gas volumes after displacement.

[0014] Preferably, the controlled gas-releasing nanomicelles adopt a microencapsulation design, and the microcapsule shell is composed of a thermosensitive and pressure-sensitive dual-responsive polymer. When the pore pressure or temperature reaches a set value, the microcapsule shell generates controllable microcracks to release the internal gas in stages.

[0015] Preferably, the thermosensitive polymer is selected from poly (N-isopropylacrylamide) copolymer, and the pressure-sensitive polymer is selected from degradable polymers containing thioether bonds or urethane bonds.

[0016] Preferably, the surface-modified nanoparticles are silica nanoparticles modified with a silane coupling agent, and the coupling agent is selected from aminopropyltriethoxysilane or aminopropyltriethoxysilane copolymer to adjust the surface charge and hydrophilic-hydrophobic balance of the nanoparticles.

[0017] Preferably, the surface Zeta potential of the nanoparticles is +20 to +40 mV, and can be controlled within the range of -10 to +60 mV by changing the amount of coupling agent.

[0018] Preferably, cross-linked intelligent polymer segments are added to the multi-media displacement system, and a viscosity network structure with a gradient change from micropores to macropores is formed by controlling the concentration of the cross-linking agent. The cross-linking degree of the polymer segments is increased in the high-pressure area to improve the support, and the cross-linking degree is reduced in the low-pressure area to enhance the permeability.

[0019] Preferably, the smart polymer segment is a copolymer containing acrylamide and N,N'-methylenebisacrylamide units, the crosslinking agent is N-vinylcyclohexane diimide, and the crosslinking degree can be controlled within the range of 0.5%-2%.

[0020] Preferably, the real-time monitoring feedback system in the testing method includes:

[0021] Responsive fluorescent nanoprobes and magnetic nanoprobes whose emission signals can change with the displacement fluid composition or pore filling state;

[0022] The microfluidic chip replicates the shale pore network structure and is placed in a transmission or magnetic resonance detection device;

[0023] Compare the detection signal with the preset standard curve and output the displacement rate, pore saturation and local barrier distribution;

[0024] The injection pressure, controlled gas release rate, and nanoparticle concentration were adjusted based on the feedback results.

[0025] Preferably, the fluorescent nanoprobe is a carboxyl functionalized quantum dot encapsulated in a nanomicelle shell, with an excitation wavelength of 365 nm and an emission wavelength in the range of 520 nm-560 nm.

[0026] Preferably, the porosity of the shale core sample is 5%-15%, the permeability is 0.01mD-0.1mD, the displacement pressure gradient range is 1MPa / m-10MPa / m, and the displacement temperature range is 40°C-80°C;

[0027] The recovery factor calculation formula is:

[0028] R=(V 驱替回收气量 -V 残余背景气量 ) / V 初始孔隙气量 ×100%;

[0029] Among them, V 驱替回收气量 is the volume of gas produced during displacement, V 残余背景气量 is the baseline gas volume remaining in the pores before injection, V 初始孔隙气量 Calculated based on porosity and pore volume distribution.

[0030] Compared with the prior art, the present invention has the following beneficial effects:

[0031] 1. The present invention is designed with controlled gas-release nano-micelles to achieve precise and continuous release of gas phase, which infiltrates with the water phase, solving the problems of short-circuiting and uneven displacement of traditional gas drive, suppressing gas phase short-circuiting, increasing displacement depth, and improving recovery rate;

[0032] 2. This invention uses surface-modified nanoparticles to dynamically block macropores and divert flow to micro- and mesopores, solving the problems of nanoparticle aggregation and blockage and uneven flow channels, balancing seepage distribution, reducing "water sliding" and improving pore utilization.

[0033] 3. The present invention adopts a gradient cross-linked viscosity network to achieve viscosity-enhancing support in high-pressure areas, macropore collapse prevention, and low-viscosity permeable micropores in low-pressure areas. This solves the problem of mismatch between displacement fluid viscosity and pore size, provides graded support and penetration, and achieves simultaneous and effective displacement of micropores and macropores.

[0034] 4. The present invention is designed with a real-time monitoring and feedback system to achieve online acquisition of saturation and barrier distribution, and intelligently adjust injection parameters, thus solving the problems of invisible and difficult optimization of the testing process, improving test accuracy and repeatability, and enhancing recovery rate. DETAILED DESCRIPTION

[0035] The following is a clear and complete description of the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making any creative efforts are within the scope of protection of the present invention.

[0036] An embodiment of the present invention provides a shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding, the testing method comprising the following steps:

[0037] A multi-media displacement system is obtained by mixing a gas phase component including controlled gas-releasing nanomicelles, surface-modified nanoparticles and an aqueous phase;

[0038] Injecting the multi-media displacement system into the inlet end of the structured shale core sample to establish a preset pressure gradient;

[0039] During the displacement process, the controllable gas-releasing nano-micelles trigger gas release in stages when a set temperature or pressure threshold is reached, and penetrate into the shale pore network in coordination with the water phase;

[0040] The surface-modified nanoparticles are simultaneously used to dynamically regulate the distribution of pore seepage channels and inhibit the "short-circuit" flow in large pores;

[0041] Based on the pore pressure, seepage rate and nanoprobe signals before and after displacement, the displacement progress is monitored in real time and the displacement system composition is dynamically adjusted;

[0042] The shale gas recovery rate is calculated by collecting the gas and residual gas volumes after displacement;

[0043] Furthermore, the shale core sample has dimensions of 25 mm in diameter and 50 mm in length, a porosity of 10%, and a permeability of 0.05 mD. The controlled gas-release nanomicelles consist of microcapsules with an average diameter of 200 nm, nitrogen gas sealed inside, and a triggering threshold of 60°C and 5 MPa. The surface-modified nanoparticles have an average particle size of 50 nm, a cross-linking degree of 1.0% for the smart polymer segments, and fluorescent nanoprobes coated with quantum dots: carboxyl-functionalized CdSe / ZnS, with excitation / emission at 365 nm and 540 nm, respectively. The equipment includes a high-pressure syringe pump, a pressure sensor, a constant-temperature water bath, a spectral detection device, and a gas volume meter.

[0044] Take 100 mL of deionized water, add controlled gas-releasing nanomicelles to 0.5 wt%, stir evenly, then add surface-modified nanoparticles to 0.1 wt%, ultrasonically disperse for 30 min, add 0.2 wt% of smart polymer segments to the above solution, and add a cross-linking agent to achieve a cross-linking degree of 1.0%. Cross-link at room temperature for 2 h, and finally add 0.05 wt% of fluorescent nanoprobes to obtain the final multi-media displacement system;

[0045] The shale core sample was fixed in the core flow unit, and the front and rear pressure sensors were connected. The multi-media displacement system was loaded into the high-pressure injection pump and connected to the inlet of the core flow unit. The core flow unit was placed in a constant temperature water bath, and the temperature was set at 60°C.

[0046] The preset pressure gradient is 5 MPa / m, the injection rate is 0.1 mL / min, and the multi-media displacement system is injected. The inlet and outlet pressures are recorded in real time to monitor the pressure difference. When the system temperature or local pressure reaches the trigger threshold, the nanocapsules release gas in stages, and nitrogen and water phase enter the pore network together. Synchronously, the surface-modified nanoparticles preferentially accumulate in large pores, inhibiting "short-circuit" flow and guiding the liquid phase into the low-permeability zone. During this period, the fluorescent nanoprobe signal is monitored by a spectral detection device to obtain the pore saturation and the difference between before and after displacement.

[0047] Recovery factor calculation: initial pore gas volume V 初始 :Based on a porosity of 10% and a core volume of 24.5cm 3 Calculated to be 2.45cm 3 ; Displacement recovery gas volume V 回收 : Gas recovered during the test is 2.00cm 3 ; Residual background gas volume V 残余 :The residual gas was measured by the pure water injection exhaust method at 0.20cm 3 ; Recovery factor: R = (V 回收 -V 残余 ) / V 初始 ×100%≈73.5%.

[0048] An embodiment provided by the present invention is a shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding. The controlled gas-release nanomicelles are microencapsulated, and the microcapsule shell is composed of a thermosensitive and pressure-sensitive dual-responsive polymer. When the pore pressure or temperature reaches a set value, the microcapsule shell generates controllable microcracks, releasing the internal gas in stages.

[0049] The thermosensitive polymer is selected from poly (N-isopropylacrylamide) copolymer, and the pressure-sensitive polymer is selected from degradable polymers containing thioether bonds or urethane bonds;

[0050] Furthermore, the core gas phase: high-purity nitrogen, gas source pressure 0.6MPa; thermal sensitive monomer: N-isopropylacrylamide NIPAM; pressure sensitive monomer: diblock polymer A: polydimethylsiloxane segment PDMS-S-PDMS containing thioether bond, diblock polymer B: degradable polycaprolactone-urethane copolymer PCL-urethane containing urethane bond; crosslinker: N,N'0 methylenebisacrylamide MBA; initiator: ammonium persulfate APS; surfactant: polyethylene glycol-fatty acid ester Tween; solvent: deionized water; others: sulfuric acid (to adjust pH), nitrogen protection;

[0051] In a four-necked round-bottom flask, 100 mL of deionized water was added, and 0.50 g of Tween 80 was dissolved. The mixture was adjusted to pH 7.0 with sulfuric acid and incubated with nitrogen for 30 minutes to exclude oxygen. 5.0 g of NIPAM, 2.0 g of PDMS-S-PDMS, 2.0 g of PCL-urethane, and 0.1 g of MBA were mixed in 20 mL of ethanol and sonicated for 10 minutes to prepare a homogeneous monomer solution. The monomer solution was slowly added to the aqueous phase and stirred at 600 rpm to form an O / W solution. The temperature was raised to 70°C and stirred at 300 rpm. APS solution was introduced to initiate polymerization. The polymerization reaction lasted for 4 hours. After the reaction was completed, the mixture was cooled to room temperature and centrifuged at 10,000 rpm for 10 minutes to remove unreacted molecules. The resulting microemulsion was placed in a high-pressure reactor, filled with nitrogen to 5 MPa, allowed to stand for 1 hour, and then slowly reduced to atmospheric pressure to allow some nitrogen to be encapsulated in the polymer shell. The mixture was then centrifuged and washed three times to obtain a controlled gas-release nanomicelle dispersion.

[0052] Trigger gas release performance test:

[0053] Temperature trigger experiment: Conditions: Heating rate 2°C / min, heating from room temperature to 80°C, monitoring the amount of packaged gas released (online mass spectrometry monitoring); Results: The gas release rate increased rapidly in the 60-65°C range, with a maximum release rate of 0.8 mL·min -1 ;

[0054] Pressure trigger experiment: Conditions: Placed in a high-pressure reactor, the pressure was increased from 0 MPa to 10 MPa at a rate of 0.5 MPa / s, and the gas release was monitored. Results: Initial microcrack gas release occurred at 5.0 MPa, and the gas release was stable above 6.0 MPa, with a cumulative gas release of 0.25 mL.

[0055] Microcrack imaging: Method: Environmental SEM was used to compare the morphology of micelles before and after high pressure; Results: After high pressure, multiple cracks of 10-20 nm were visible in the shell.

[0056] An embodiment provided by the present invention is a shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding, wherein the surface-modified nanoparticles are silica nanoparticles modified with a silane coupling agent, and the coupling agent is selected from aminopropyltriethoxysilane or aminopropyltriethoxysilane copolymer to adjust the surface charge and hydrophilic-hydrophobic balance of the nanoparticles;

[0057] The surface Zeta potential of the nanoparticles is between +20 and +40 mV, and can be adjusted within the range of -10 to +60 mV by changing the amount of coupling agent used;

[0058] Furthermore, silica nanoparticles were purchased from a chemical company with an average particle size of 50 nm and a specific surface area of ​​200 m 2 / g; coupling agents: aminopropyltriethoxysilane (APTES), aminopropyltriethoxysilane-acrylic acid copolymer (APTES-AA copolymer); solvents and additives: ethanol, deionized water, ammonia water, hydrochloric acid; characterization instruments: zeta potential meter, Fourier transform infrared spectrometer (FT-IR), transmission electron microscope (TEM), contact angle meter;

[0059] 1.0 g of silica nanoparticles was added to 100 mL of a mixture of ethanol and water (volume ratio 4:1), and ultrasonically dispersed for 30 min to obtain a homogeneous suspension; the pH was adjusted to 4.5 to activate the silanol groups; APTES or APTES-AA copolymer was weighed in proportion and added to the above suspension respectively, and ammonia water was slowly added dropwise to pH = 9.0, and the mixture was stirred at 60°C for 4 h. After the reaction was completed, the mixture was cooled to room temperature, centrifuged to remove the supernatant, and washed three times with ethanol and deionized water respectively. The product was vacuum dried for 12 h to obtain surface-modified nanoparticle powder; the modified powder was dispersed in deionized water at 0.1 wt%, and the zeta potential was measured by ultrasonication for 10 min. The characteristic peaks of Si-O-Si and -NH2 were verified by FT-IR, the particle size and shell were detected by TEM, and the water droplet contact angle was measured to evaluate the hydrophilicity and hydrophobicity;

[0060] The experimental ratio and results are shown in Table 1. Effect of coupling agent dosage on the surface characteristics of nanoparticles

[0061] Table 1 Effect of coupling agent dosage on surface characteristics of nanoparticles

[0062]

[0063]

[0064] Zeta potential regulation: controllable over a wide range from -10mV to +60mV, and stable dispersion is easily achieved in the +20-+40mV range; hydrophilic-hydrophobic balance: the contact angle increases with increasing coupling agent dosage, proving that the coupling layer changes the surface energy.

[0065] An embodiment of the present invention provides a shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding. Cross-linked intelligent polymer segments are added to the multi-media flooding system. By controlling the concentration of the cross-linking agent, a viscosity network structure with a gradient change from micropores to macropores is formed. The cross-linking degree of the polymer segments increases in high-pressure areas to improve support, and decreases in low-pressure areas to enhance permeability.

[0066] The smart polymer chain segment is a copolymer containing acrylamide and N,N'-methylenebisacrylamide units, the crosslinking agent is N-vinylcyclohexane diimide, and the crosslinking degree can be controlled within the range of 0.5%-2%;

[0067] Furthermore, monomers and crosslinkers include acrylamide (AAm), N,N'-methylenebisacrylamide (MBA), and N-vinylcyclohexanediimide (VCHDI); initiator system includes 0.1 wt% ammonium persulfate (APS) and TEMED; solvents and additives include deionized water and an appropriate amount of NaCl (0.5 wt%) to simulate the ionic strength in the pores; and testing instruments include a high-pressure rheometer, a core flow cell, a pressure sensor, and a syringe pump.

[0068] Preparation of cross-linked smart polymer solutions: Prepare three polymer solutions with different cross-linking degrees according to the three cross-linking polymer solution formulas in Table 2, with the other conditions being identical:

[0069] Table 2 Formulas of three cross-linked polymer solutions

[0070]

[0071] Preparation steps: AAm was dissolved in deionized water and 0.5 wt% NaCl was added. The mixture was stirred until completely dissolved. MBA and VCHDI were added in sequence. APS and TEMED were then added under nitrogen. The polymerization was initiated for 20 min. After standing at room temperature for 1 h, transparent viscous solutions were obtained, which were designated as P1-P3.

[0072] High-pressure rheological properties characterization: Using a high-pressure rheometer, the pressure drop of each sample was measured at 1 MPa (simulating micropore area) and 10 MPa (simulating macropore area) for 100 s. -1 Viscosity under shear rate, the results are shown in Table 3 Rheological properties of polymers with different cross-linking degrees under different pressures:

[0073] Table 3 Rheological properties of polymers with different crosslinking degrees under different pressures

[0074]

[0075]

[0076] Low pressure area (1MPa): The viscosity increases from P1 to P3, but the absolute viscosity is moderate to ensure unimpeded penetration into the microporous area;

[0077] High-pressure area (10MPa): The higher the degree of cross-linking, the greater the viscosity increase. P3 forms a strong support network in the large pore area, effectively preventing pore collapse and channel series connection.

[0078] Core displacement experiment verification: P2 (1.0 wt% MBA) solution was added to the multi-media displacement system and mixed with the aforementioned controlled gas release micelles, surface-modified nanoparticles, and water. The system was operated in a shale core sample at an injection rate of 0.1 mL / min, a pressure gradient of 5 MPa / m, and a temperature of 60°C. The inlet and outlet pressures, outflow liquid volume, and recovered gas volume were recorded. The results are compared in Table 4 below: Core displacement experiment verification results:

[0079] Table 4 Core displacement experimental verification results

[0080]

[0081] Effect description: The three levels of cross-linking degree P1-P3 show a viscosity distribution of "micropores are easy to permeate - macropores are strongly supported" under different pressures, providing an adaptive network for gas-liquid synergistic displacement in porous structures. Compared with the system without polymer, the comprehensive displacement recovery rate using P2 is increased from 58% to 75%. The formula and steps are simple, and the error of three repeated experiments is less than ±3%.

[0082] An embodiment of the present invention provides a shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding, wherein the real-time monitoring feedback system in the testing method includes:

[0083] Responsive fluorescent nanoprobes and magnetic nanoprobes whose emission signals can change with the displacement fluid composition or pore filling state;

[0084] The microfluidic chip replicates the shale pore network structure and is placed in a transmission or magnetic resonance detection device;

[0085] Compare the detection signal with the preset standard curve and output the displacement rate, pore saturation and local barrier distribution;

[0086] Adjust the injection pressure, controlled gas release rate, and nanoparticle concentration based on the feedback results;

[0087] The fluorescent nanoprobes are carboxyl functionalized quantum dots encapsulated in nanomicelle shells, with an excitation wavelength of 365 nm and an emission wavelength in the range of 520 nm to 560 nm;

[0088] The shale core sample has a porosity of 5%-15%, a permeability of 0.01mD-0.1mD, a displacement pressure gradient range of 1MPa / m-10MPa / m, and a displacement temperature range of 40°C-80°C;

[0089] The recovery factor calculation formula is:

[0090] R=(V 驱替回收气量 -V 残余背景气量 ) / V 初始孔隙气量 ×100%;

[0091] Among them, V 驱替回收气量 is the volume of gas produced during displacement, V 残余背景气量 is the baseline gas volume remaining in the pores before injection, V 初始孔隙气量 Calculated based on porosity and pore volume distribution;

[0092] Further, experimental materials and equipment: shale core sample source: a deep shale reservoir, diameter 25×50mm, porosity: 10%, permeability: 0.05mD; responsive nanoprobe: fluorescent quantum dot probe: carboxyl functionalized CdSe / ZnS coated in nanomicelle shell, excitation wavelength 365nm, emission wavelength 540nm; magnetic nanoparticles: Fe3O4 nanoparticles, coated with silane coupling agent, with -COOH group on the surface, used for magnetic resonance signal change detection; microfluidic chip: material: PDMS and glass composite, pores The mesh structure was photolithographically fabricated based on the actual shale pore distribution. The detection equipment included a transmission spectrometer and a small-animal MRI system. The multi-media displacement system consisted of controlled-gas-release nanomicelles with a shell composed of a PNIPAM-PDMS-PCL copolymer, a trigger threshold of 60°C / 5 MPa, surface-modified SiO2 nanoparticles with a zeta of +30 mV, cross-linked smart polymer segments with a cross-linking degree of 1.0%, and deionized water as the aqueous phase. The injection and measurement system consisted of a high-pressure syringe pump with an initial pressure gradient of 5 MPa / m and a constant temperature chamber at 60°C.

[0093] The microfluidic chip was docked with a detection device, and a mixed solution of fluorescent and magnetic probes with known saturation was injected. The fluorescence intensity I and MRI signal attenuation value T2 at each saturation level were recorded to establish a dual standard curve of fluorescence intensity-pore saturation and MRI T2-pore saturation. The shale core sample was placed in a core flow unit, the temperature was set at 60°C, and the pressure gradient was 5 MPa / m. A multi-media displacement system containing fluorescent and magnetic probes was injected at a rate of 0.1 mL / min. The transmitted fluorescence intensity and MRI T2 intensity were collected in real time and converted into the current pore saturation (S) and local barrier distribution (expressed as the saturation gradient ΔS) using a calibration curve.

[0094] After the initial stage (injection of 5 mL): the average pore saturation S1 = 65%, the saturation of the large pore area is high (S≈80%), and the saturation of the small pore area is low (S≈50%), ΔS = 30%. According to the rules, the injection pressure gradient is increased to 7 MPa / m, and the controlled gas release trigger rate is adjusted from the original 0.5 mL / h to 0.7 mL / h;

[0095] In the middle stage (after injecting another 5 mL), the average saturation S2 was measured to be 78%, ΔS decreased to 15%, the permeation of the aqueous and gas phases became more uniform, and the localized barrier areas were significantly reduced. The nanoparticle concentration was evaluated: if the high-pore short-circuiting trend still existed, the nanoparticle concentration was increased from 0.1 wt% to 0.15 wt%.

[0096] After the displacement is completed, the recovered gas V 回收 =2.10cm 3 , the residual background gas V is measured by pure water exhaust 残余 =0.15cm 3 , initial pore gas volume V 初始 =2.45cm 3 , recovery factor R = (2.10-0.15) / 2.45×100%≈80.0%;

[0097] The dual fluorescence and MRI signals can accurately reflect changes in pore saturation, with an error of less than ±3% compared to the standard curve. Based on the online ΔS and S data, the pressure gradient and gas trigger rate are adjusted in a timely manner, significantly improving the uniformity of displacement. Through feedback optimization, the final recovery factor is increased from 73.5% to 80.0%, an increase of approximately 22% compared to the process without feedback.

[0098] Working principle: When the pore pressure or temperature reaches the trigger threshold, the controlled-release gas nano-micelles release trace amounts of gas phase in stages, which infiltrates into the complex pore network together with the water phase. The gas phase forms microbubbles, increases the pore pressure, and promotes the diffusion of the water phase to the low-permeability area.

[0099] Surface-modified nanoparticles preferentially aggregate in large pores, dynamically blocking high-speed channels using charge repulsion and interfacial tension gradients, forcing the displacing fluid into micropores and small and medium pores to achieve seepage balance.

[0100] Smart polymer segments form a viscosity gradient network from micropores to macropores under different pressures. Cross-linking is increased in high-pressure areas to improve support and prevent collapse, while cross-linking is reduced in low-pressure areas to enhance penetration. Combined with fluorescence, magnetic nanoprobes and microfluidic chip online monitoring, real-time parameter optimization is achieved.

[0101] It will be apparent to those skilled in the art that the present invention is not limited to the details of the exemplary embodiments described above and that the invention can be embodied in other specific forms without departing from the spirit or essential characteristics of the invention. Therefore, the embodiments should be considered in all respects as illustrative and non-restrictive, and the scope of the invention is defined by the appended claims rather than the foregoing description, and it is intended that all variations that come within the meaning and range of equivalents of the claims be embraced therein.

Claims

1. A shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding, characterized by: The test method comprises the following steps: A multi-media displacement system is obtained by mixing a gas phase component including controlled gas-releasing nanomicelles, surface-modified nanoparticles and an aqueous phase; Injecting the multi-media displacement system into the inlet end of the structured shale core sample to establish a preset pressure gradient; During the displacement process, the controllable gas-releasing nano-micelles trigger gas release in stages when a set temperature or pressure threshold is reached, and penetrate into the shale pore network in coordination with the water phase; The surface-modified nanoparticles are simultaneously used to dynamically regulate the distribution of pore seepage channels and inhibit "short-circuit" flow in large pores; Based on the pore pressure, seepage rate and nanoprobe signals before and after displacement, the displacement progress is monitored in real time and the displacement system composition is dynamically adjusted; The shale gas recovery rate is calculated by collecting the gas and residual gas volumes after displacement.

2. The shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding according to claim 1 is characterized by: The controlled gas-releasing nanomicelles adopt a microencapsulation design, and the microcapsule shell is composed of a thermosensitive and pressure-sensitive dual-responsive polymer. When the pore pressure or temperature reaches a set value, the microcapsule shell generates controllable microcracks to release the internal gas in stages.

3. The shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding according to claim 2 is characterized in that: The thermosensitive polymer is selected from poly (N-isopropylacrylamide) copolymer, and the pressure-sensitive polymer is selected from degradable polymers containing thioether bonds or urethane bonds.

4. The shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding according to claim 1 is characterized in that: The surface-modified nanoparticles are silica nanoparticles modified with a silane coupling agent, wherein the coupling agent is selected from aminopropyltriethoxysilane or aminopropyltriethoxysilane copolymer to adjust the surface charge and hydrophilic-hydrophobic balance of the nanoparticles.

5. The shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding according to claim 4 is characterized in that: The surface Zeta potential of the nanoparticles is between +20 and +40 mV, and can be adjusted within the range of -10 to +60 mV by changing the amount of the coupling agent.

6. The shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding according to claim 1 is characterized in that: Cross-linked intelligent polymer segments are added to the multi-media displacement system, and a viscosity network structure with a gradient change from micropores to macropores is formed by controlling the concentration of the cross-linking agent. The cross-linking degree of the polymer segments is increased in the high-pressure area to improve the support, and the cross-linking degree is reduced in the low-pressure area to enhance the permeability.

7. The shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding according to claim 6 is characterized in that: The intelligent polymer chain segment is a copolymer containing acrylamide and N,N'-methylenebisacrylamide units, the crosslinking agent is N-vinylcyclohexane diimide, and the crosslinking degree can be controlled within the range of 0.5%-2%.

8. The shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding according to claim 1 is characterized in that: The real-time monitoring feedback system in the test method includes: Responsive fluorescent nanoprobes and magnetic nanoprobes whose emission signals can change with the displacement fluid composition or pore filling state; The microfluidic chip replicates the shale pore network structure and is placed in a transmission or magnetic resonance detection device; Compare the detection signal with the preset standard curve and output the displacement rate, pore saturation and local barrier distribution; The injection pressure, controlled gas release rate, and nanoparticle concentration were adjusted based on the feedback results.

9. The shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding according to claim 8, characterized in that: The fluorescent nanoprobe is a carboxyl functionalized quantum dot coated in a nanomicelle shell, with an excitation wavelength of 365 nm and an emission wavelength in the range of 520 nm to 560 nm.

10. The shale gas recovery rate testing method based on gas-agent-water multi-media nanoflooding according to claim 1, characterized in that: The shale core sample has a porosity of 5%-15%, a permeability of 0.01mD-0.1mD, a displacement pressure gradient range of 1MPa / m-10MPa / m, and a displacement temperature range of 40°C-80°C; The recovery factor calculation formula is: R=(V 驱替回收气量 -V 残余背景气量 ) / V 初始孔隙气量 ×100%; Among them, V 驱替回收气量 is the volume of gas produced during displacement, V 残余背景气量 is the baseline gas volume remaining in the pores before injection, V 初始孔隙气量 Calculated based on porosity and pore volume distribution.

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