CO2 and water-based fluid collaborative energy complementation parameter optimization method after shale oil reservoir depletion development

Abstract

The invention relates to a CO2 and water-based fluid collaborative energy supplement parameter optimization method after shale oil reservoir depletion development. The method comprises the steps that shale oil reservoir key parameters are obtained; preparing shale oil and a rock core sample; performing mercury injection test on each rock sample to obtain pore size distribution data of the shale samples at two different layers; performing two-dimensional nuclear magnetic resonance testing on shale dry samples at different layers; reducing initial conditions of the reservoir, and performing two-dimensional nuclear magnetic resonance testing on shale oil states at different layers under the initial conditions of the reservoir; carrying out two-dimensional nuclear magnetic resonance testing after shale exhaustion development at different layers; simulating a CO2 and water-based fluid synergistic energy complementing process, and carrying out two-dimensional nuclear magnetic resonance testing after energy complementing development of different layers of shale; evaluating the synergistic energy supplement development effect of CO2 and water-based fluid at different layers of the shale oil reservoir; and performing CO2 and water-based fluid collaborative energy supplement parameter optimization by using a weighted sum method. The method can evaluate the overall development effect of the oil reservoir with different energy supplement parameters under the reservoir conditions.

Description

Technical field:

[0001] The present invention relates to the technical field of shale oil development, and in particular to a method for producing CO2 after depletion of a shale oil reservoir. 2 Parameter optimization method for synergistic energy replenishment with water-based fluids. Background technology:

[0002] my country has abundant shale oil reserves. Its exploration and development can increase the diversity of the country's energy supply and improve the level of energy security, which is of great significance. The development of shale oil generally adopts the staged horizontal well volume fracturing technology, but the low porosity and low permeability characteristics of my country's continental shale reservoirs make the natural elastic energy of the reservoirs consume quickly during fracturing production, the production declines quickly, and it is difficult to obtain economically effective long-term production capacity. Therefore, improving the recovery rate of shale oil reservoirs is the current technical difficulty. Studies have shown that the water-based fracturing-imbibition agent system commonly used in oil and gas field development has a good degree of utilization of nano-pores and small-pore shale oil between clay layers, while CO 2 The main shale oil is produced in medium and large pores. If the synergistic effect of different types of injection media can be brought into play and the shale oil in all-scale pores can be effectively used, its recovery rate will be greatly improved. At present, the energy replenishment technology for shale oil reservoirs is still in the exploratory stage. 2 The optimization method of energy replenishment parameters in coordination with water-based fluids is of great significance for facilitating the efficient development of shale oil.

[0003] The current research on the energy replenishment effect of shale oil reservoirs is mainly based on indoor experiments using mass method, CT scanning, and online nuclear magnetic resonance testing technology. Prior art CN 118211505 A is a method for determining carbon dioxide throughput injection parameters, which uses indoor simulation experiments of carbon dioxide throughput and theoretical calculation formulas to determine the injection volume, maximum injection pressure, injection rate, shut-in time, and flowback rate. The indoor experiments conducted are only for a single core and can only give the overall recovery rate of the core. The experimental and numerical calculation formula assumptions are inconsistent with the actual complex reservoir conditions, and the calculation error is large. Prior art CN 114965540A is a method and device for carbon dioxide throughput experiment on shale oil reservoir cores. Nuclear magnetic resonance T 2 Spectrum detection, comparison of saturated oil and oil components in the huff and puff process, nano CT scanning of the core after the simulated huff and puff process, so as to analyze the distribution of the remaining oil after the huff and puff. This method fails to provide a quantitative evaluation method and parameter optimization method for the effect of carbon dioxide huff and puff. CN 115788373 A is a CO 2 Compared with the evaluation method of oil-gas replacement law in shale oil reservoirs, the experiment simulates the initial state of the core in the formation by saturating the core with formation water and then displacing it with simulated crude oil until no water is produced at the outlet. This is a simulation method for conventional oil reservoirs and is not suitable for shale oil reservoirs with the characteristics of "source generation and source storage". 2When evaluating the oil recovery efficiency of different pore throats in the core, the pore throat size is divided according to the distribution range of relaxation time in the spectrum, and the specific value of the pore throat radius is not given; the influence of displacement is studied by changing the injection pressure, constant flow rate, injection volume and action time experimentally, but no specific parameter optimization method is given. In the actual production process, the reservoir is first depleted and then mostly CO 2 Co-injection with water-based fluids, while the above methods only involve CO 2 injection. Summary of the invention:

[0004] The purpose of the present invention is to provide a CO 2 The optimization method of energy replenishment parameters in coordination with water-based fluid is a method for CO 2 The parameter optimization method of energy replenishment in coordination with water-based fluid is used to solve the problems of single evaluation method of energy replenishment effect in shale oil reservoirs and lack of parameter optimization method.

[0005] The technical solution adopted by the present invention to solve the technical problem is: after the shale oil reservoir is depleted and developed, CO 2 The method for optimizing parameters of energy replenishment in coordination with water-based fluids comprises the following steps:

[0006] Step 1: Obtain key reservoir parameters of shale oil reservoirs, including reservoir pressure, temperature, and overburden pressure at different layers;

[0007] Step 2, preparing shale oil and core samples: Shale oil has the same viscosity as formation crude oil at reservoir temperature. Cylindrical core samples are drilled from full-size cores of two different layers, 1# and 2#, in the shale oil reservoir, and are marked as 1# and 2# core samples, respectively. 11# and 12# rock samples are cut from the 1# core sample, and 21# and 22# rock samples are cut from the 2# core sample.

[0008] Step 3: Dry each rock sample at 110°C to a constant weight, then perform mercury injection testing on rock samples 12# and 22# to obtain pore size distribution data of shale rock samples 1# and 2# at two different layers;

[0009] Step 4: Two-dimensional NMR test of dry samples of shale at different layers, recording the NMR signal of dry samples of 11# and 21# rock samples respectively. 10 and NMR 20 ;

[0010] Step 5: restore the initial reservoir conditions and conduct two-dimensional nuclear magnetic resonance tests on the shale oil state in different layers under the initial reservoir conditions. The nuclear magnetic resonance signals of the 11# rock sample and the 21# initial saturated oil are recorded as NMR 11 and NMR 21 ;

[0011] Step 6: Simulate the depletion development process of shale reservoirs and conduct two-dimensional nuclear magnetic resonance tests after depletion development of shale in different layers. Record the NMR signals of shale oil in rock samples 11# and 21# respectively. 12 and NMR 22 ;

[0012] Step 7: Simulate CO 2 In the process of synergistic energy replenishment with water-based fluid, two-dimensional nuclear magnetic resonance tests were carried out on shale in different layers after energy replenishment development. Through diffusion-relaxation nuclear magnetic resonance data processing, the nuclear magnetic resonance signal quantities of shale oil were obtained as NMR 13 and NMR 23 ;

[0013] Step 8: CO2 in different layers of shale reservoirs 2 Evaluation of the effect of synergistic energy development with water-based fluids;

[0014] Step 9: Comprehensively consider the shale oil recovery rate of the reservoir as a whole, different layers, and different pore sizes, and use the weighted sum method to calculate the CO 2 Synergistic energy replenishment parameter optimization with water-based fluids.

[0015] Step 1 in the above scheme is specifically: through comprehensive analysis of geological data, geophysical data, logging data, and well test data, key parameters of shale oil reservoirs are obtained, including reservoir pressure, temperature, and overlying rock pressure at different levels.

[0016] Step 2 in the above scheme is specifically as follows: shale oil is prepared by using ground dehydrated and degassed crude oil and kerosene to make the shale oil have the same viscosity as the formation crude oil at the reservoir temperature; cylindrical core samples with a diameter of 2.5 cm and a length of 6 cm are drilled from the full-size core cores of two different layers of the shale oil reservoir 1# and 2#, and are marked as 1# and 2# rock samples respectively; the 1# core sample is cut into cores with a length of approximately 5 cm and 1 cm, respectively, and are marked as 11# and 12# rock samples; the 2# core sample is cut into cores with a length of approximately 5 cm and 1 cm, respectively, and are marked as 21# and 22# rock samples; the 12# and 22# rock samples are used for high-pressure mercury injection testing, and the 11# and 21# rock samples are used for CO2 injection testing after the depletion of shale oil reservoirs. 2 Experiment on optimization of energy replenishment parameters with water-based fluids.

[0017] Step 4 in the above scheme is as follows: 11# and 21# rock samples are placed in the middle position of two online nuclear magnetic resonance core holders respectively, the two holders are connected in parallel to the online nuclear magnetic resonance core test system, fluorine oil is used to increase the confining pressure to 2MPa and the temperature of the fluorine oil is increased to the reservoir temperature of the 1# and 2# layers of the shale reservoir respectively; the inlet and outlet ends of the holder are closed, and the 11# and 21# rock samples are vacuumed for 48 hours, and then the 11# and 21# rock samples are subjected to dry sample nuclear magnetic resonance T 1 -T2 Spectrum test, record the nuclear magnetic signal of 11# and 21# rock samples respectively 10 and NMR 20 .

[0018] Step 5 in the above scheme is as follows: The overburden pressure P of the 1# layer 10 , initial reservoir pore pressure P p10 ; Overburden pressure P of 2# layer 20 , initial reservoir pore pressure P p20 ; The initial effective stresses of 1# and 2# layers are P e10 and P e20 . ; In the core of the 1# layer, the fluorine oil confining pressure is gradually increased to the overburden pressure P 10 During the process, the outlet of the holder is closed and shale oil is injected into the holder until the initial pore pressure of the reservoir reaches P p10 , always make the difference between the confining pressure and the pore pressure equal to the initial effective stress value P e10 , until the flow rate at the inlet of the holder is zero for 4 hours. At this time, the conditions of the 11# rock sample are the reservoir temperature and initial pressure of the 1# layer. The saturated oil state NMR T of the 11# rock sample under the initial reservoir conditions is carried out. 1 -T 2 Spectrum test, record the initial saturated oil nuclear magnetic signal as NMR 11 ; In the 2# layer core, the fluorine oil confining pressure is gradually increased to the overburden pressure P 20 During the process, the outlet of the holder is closed and shale oil is injected into the holder until the initial pore pressure of the reservoir reaches P p20 , always make the difference between the confining pressure and the pore pressure equal to the initial effective stress value P e20 , until the flow rate at the inlet of the holder is zero for 4 hours. At this time, the conditions of the 21# rock sample are the reservoir temperature and initial pressure of the 2# layer. The saturated oil state NMR T of the 21# rock sample under the initial reservoir conditions is carried out. 1 -T 2 Spectrum test, record the initial saturated oil nuclear magnetic signal as NMR 21 .

[0019] Step 6 in the above scheme is as follows: keep the outlet ends of the two clamps closed, close the inlet end of the clamp at the same time, and set the pressure of the back pressure valve at the emptying end to the bottom flow pressure of the production well P f11 , P f11 <P p10 And P f11 <P p20 , slowly open the two clamp drain valves, the rock sample pore pressure decreases, the effective stress increases, and the shale oil flows out until the drain flow is zero for 4 consecutive hours, realizing the simulation of the shale reservoir depletion development process; perform nuclear magnetic resonance t 1-T 2 Spectrum test, recording shale oil nuclear magnetic signal quantity is NMR 12 and NMR 22 .

[0020] Step 7 in the above scheme is as follows: close the valves at the two holder exhaust ends, open the injection end, and inject pressure P i11 , P i11 >P f11 , inject CO into both holders 2 , until the injection flow rate is zero for 4 consecutive hours; the injection pressure P i21 , P i21 >P i11 , inject water-based fluid into the two holders until the injection flow rate is zero for 4 consecutive hours, and then close the injection end; soak the well for a period of time t 1 After that, set the back pressure valve pressure at the emptying end to the bottom flow pressure of the production well P f21 , P f21 <P i11 , slowly open the two clamps to empty the ends, shale oil, CO 2 and water-based fluids flow outward until the flow at the drain end is zero for 4 consecutive hours, realizing the simulation of the shale reservoir energy replenishment and post-energy replenishment development process; nuclear magnetic resonance t 1 -T 2 Spectrum test, through diffusion-relaxation NMR data processing, the shale oil NMR signal quantities are obtained as NMR 13 and NMR 23 .

[0021] Step eight in the above scheme is specifically as follows:

[0022] ① Using the saturated oil NMR signal under the initial reservoir conditions in step 5 minus the dry sample NMR signal in step 4, the distribution curve of the shale oil NMR signal on different relaxation time coordinate axes is obtained, and compared with the pore size distribution data of the shale rock sample in step 3, the conversion relationship between the NMR relaxation time and the mercury injection pore radius is obtained; according to the peak distribution interval of the shale oil NMR signal, the multi-scale pores of the rock sample are divided into micro-nano pores, small pores, medium pores and large pores, and the radius values ​​and relaxation time values ​​corresponding to the different scale pores of the 11# rock sample and the 21# rock sample are determined according to the above conversion relationship;

[0023] ② According to step 4, the NMR signal quantities of dry samples of different pore sizes of rock samples 11# and 21# are determined as follows: N10 , NMR S10 , NMR M10 , NMR L10 and NMR N20 , NMR S20 , NMR M20 , NMRL20 According to step 5, the oil NMR signals of different pore sizes of rock samples 11# and 21# under initial reservoir conditions are determined as follows: N11 , NMR S11 , NMR M11 , NMR L11 and NMR N21 , NMR S21 , NMR M21 , NMR L21 ;

[0024] ③ Calculation of recovery factor of shale reservoir depletion development: According to step 6, the oil NMR signals of different scales of pores in 11# and 21# samples after depletion development are respectively N12 , NMR S12 , NMR M12 , NMR L12 and NMR N22 , NMR S22 , NMR M22 , NMR L22 ; Determine the total recovery factor η of the 1# layer rock sample depletion development according to formula 1 11 , according to formula 2-formula 5, the micro-nanopore recovery factor η is determined respectively N11 , small hole recovery factor η S11 , medium pore recovery factor η M11 and macropore recovery factor η L11 Similarly, determine the total recovery factor η of the 2# layer rock sample depletion development 21 , micro-nanopore recovery factor η N21 , small hole recovery factor η S21 , medium pore recovery factor η M21 and macropore recovery factor η L21 The overall recovery factor η of shale reservoir depletion development is determined according to formula 6 1 ;

[0025]

[0026] ④CO 2 Calculation of recovery factor for synergistic energy recovery with water-based fluids: Determine the CO 2 After the coordinated energy supplementation development with water-based fluid, the NMR signals of oil in pores of different scales in 11# and 21# rock samples are respectively N13 , NMR S13 , NMR M13 , NMR L13 and NMR N23 , NMR S23 , NMR M23 , NMR L23 ; Determine the CO of the rock sample in the 1# layer according to formula 72 Total recovery factor η of synergistic energy development with water-based fluid 12 According to formula 8-formula 11, the micro-nanopore recovery factor η is determined respectively N12 , small hole recovery factor η S12 , medium pore recovery factor η M12 and macropore recovery factor η L12 Similarly, determine the CO of the 2# layer sample 2 Total recovery factor η of synergistic energy development with water-based fluid 22 , micro-nanopore recovery factor η N22 , small hole recovery factor η S22 , medium pore recovery factor η M22 and macropore recovery factor η L22 ; Determine the CO of the entire shale reservoir according to Formula 12 2 Overall recovery factor η of synergistic energy development with water-based fluid 2 ;

[0027]

[0028]

[0029] Step 9 in the above scheme is specifically: the overall recovery rate of the reservoir synergistic energy replenishment η 2 、Total recovery factor η of 1# layer 12 , micro-nanopore recovery factor η N12 , small hole recovery factor η S12 , medium pore recovery factor η M12 and macropore recovery factor η L12 、Total recovery factor of 2# layer η 22 , micro-nanopore recovery factor η N22 , small hole recovery factor η S22 , medium pore recovery factor η M22 and macropore recovery factor η L22 The corresponding weight coefficients are W 2 , W 12 , W N12 , W S12 , W M12 , W L12 , W 22 , W N22 , W S22 , W M22 , W L22 ; The optimization objective function f(x) is shown in Formula 13, and the sum of the weight coefficients of each parameter is 1, as shown in Formula 14; Taking f(x) as the objective function, the energy replenishment timing, energy replenishment pressure, energy replenishment injection speed, energy replenishment injection amount, CO 2 The CO 2Optimize the parameters of energy replenishment in coordination with water-based fluids; the specific method is:

[0030]

[0031] ① Optimization of energy replenishment timing: Select parallel shale core samples and reduce the bottom flow pressure of the production well to P in step 6. f11 , P f12 , P f13 ...P f1n Corresponding time point T 1 , T 2 , T 3 ……T n Start CO 2 Synergistic energy replenishment with water-based fluids, T 1 , T 2 , T 3 ……T n That is the corresponding energy replenishment opportunity; for different energy replenishment opportunities, the objective function f(x) is calculated respectively, and the energy replenishment opportunity T corresponding to the maximum f(x) x This is the optimized energy replenishment opportunity;

[0032] ② Energy replenishment pressure optimization: At the optimal energy replenishment time T x Inject CO 2 and water-based fluid to different energy injection pressures P i11 , P i12 , P i13 ...P i1n and P i21 , P i22 , P i23 ...P i2n For different energy replenishment pressures, the objective function f(x) is calculated respectively, and the CO corresponding to the maximum f(x) is 2 and water-based fluid recharge pressure P i1x and P i2x The optimized CO 2 and water-based fluid recharge pressure;

[0033] ③ Optimization of energy injection speed: At the optimal energy injection time T x Different CO 2 and water-based fluid energy injection rate q i11 ,q i12 ,q i13 ……q i1n and q i21 ,q i22 ,q i23 ……q i2n Add energy until the pressure reaches P i1x and P i2xFor different energy injection rates, the objective function f(x) is calculated respectively, and the CO corresponding to the maximum f(x) is 2 and water-based fluid energy injection rate q i1x and q i2x The optimized CO 2 and water-based fluid energy replenishment injection rate;

[0034] ④CO 2 Optimization of injection ratio with water-based fluid: At the optimal energy replenishment time T x Different CO 2 and water-based fluid injection ratio 3:1, 2:1, 1:1, 1:2, 1:3 injection speed q i1x and q i2x Add energy until the pressure finally reaches P i2x ; For different injection ratios, the objective function f(x) is calculated respectively, and the injection ratio corresponding to the maximum f(x) is the optimized CO 2 and water-based fluid energy injection ratio;

[0035] ⑤CO 2 Optimization of injection sequence with water-based fluid: At the optimal energy replenishment time T x First CO 2 / Water-based fluids first / CO second 2 Use the optimized injection rate and injection ratio to replenish energy until the pressure reaches P i2x ; For different injection sequences, the objective function f(x) is calculated respectively, and the injection sequence corresponding to the maximum f(x) is the optimized CO 2 and water-based fluid recharge injection sequence;

[0036] ⑥ Optimization of energy replenishment and well soaking time: At the optimal energy replenishment time T x After optimization, CO 2 and water-based fluid energy injection rate q i1x and q i2x Add energy until the final pressure reaches P i2x , respectively at different soaking times t 1 ,t 2 ,t 3 ……t n After that, the post-energy replenishment development begins; for different shut-in times, the objective function f(x) is calculated respectively, and the shut-in time corresponding to the maximum f(x) is the optimized CO 2 and the time for water-based fluid to replenish the well;

[0037] ⑦ Optimization of return flow rate after energy replenishment: At the optimal energy replenishment time T x With optimal CO 2 The injection ratio of water-based fluid and the injection speed q i1x and qi2x Add energy until the pressure finally reaches P i2x , during the soaking time t x Then, different return speeds q f1 ,q f2 ,q f3 ……q fn Carry out post-energy development; for different return flow rates, calculate the objective function f(x) respectively, and the return flow rate corresponding to the maximum f(x) is the optimized CO 2 and the return flow rate of water-based fluid after recharging.

[0038] Beneficial effects:

[0039] 1. In the test process of the present invention, there is no need to repeatedly take out rock samples, so that the rock samples are always in the high temperature and high pressure state of the reservoir, and the whole process of depletion mining-energy replenishment-mining of different layers under the conditions of shale oil reservoirs is truly reflected, avoiding interference from human factors and achieving high measurement results.

[0040] 2. The present invention can not only evaluate the overall development effect of oil reservoirs under different energy replenishment parameters under reservoir conditions, but also study the multi-scale pore development effect of shale in different layers and its contribution to the total recovery rate from a microscopic perspective, optimize the energy replenishment parameters, and analyze the CO 2 The process and mechanism of synergistic energy replenishment with water-based fluids.

[0041] 3. The present invention can conduct parallel experiments on multiple cores of different layers in parallel to simulate the energy replenishment effect of the entire reservoir, while optimizing the energy replenishment parameters of the entire reservoir and different layers, further improving the comprehensiveness and accuracy of the method. If it is necessary to focus on the development of shale oil in a certain layer or a certain scale of pores, this can be achieved by changing the weight coefficients in formulas 13 and 14.

[0042] 4. CO determined by the present invention 2 The parameter optimization method of synergistic energy replenishment with water-based fluid can be used for designing shale oil field development plans and optimizing reasonable CO 2 Energy replenishment construction parameters provide important experimental data and method support. Description of the drawings:

[0043] Figure 1 It is a flow chart of the present invention;

[0044] Figure 2 Schematic diagram of the online nuclear magnetic resonance testing system for shale oil reservoirs provided for this application;

[0045] Figure 3 For the 11# rock sample, dry sample NMR T 1 -T 2 Spectrum test result diagram;

[0046] Figure 4For the 11# rock sample, the oil saturated NMR T 1 -T 2 Spectrum test result diagram;

[0047] Figure 5 The NMR T of the 11# rock sample after depletion development in step 6 1 -T 2 Spectrum test result diagram;

[0048] Figure 6 For the 11# rock sample, in step 7, CO 2 Nuclear magnetic resonance T in the state after synergistic energy replenishment with water-based fluid 1 -T 2 Spectrum test result diagram.

[0049] In the figure: 1 constant speed constant pressure pump, 2 first valve, 3 first intermediate container, 4 second valve, 5 second intermediate container, 6 third valve, 7 third intermediate container, 8 fourth valve, 9 fifth valve, 10 first fluid preheater, 11 second fluid preheater, 12 sixth valve, 13 seventh valve, 14 first back pressure valve, 15 second back pressure valve, 16 first fluid collecting container, 17 second fluid collecting container, 18 fluorine oil, 19 non-magnetic clamp plug, 20 nuclear magnetic resonance special core clamp, 21 shale rock sample, 22 nuclear magnetic control and data acquisition system, 23 pipeline, 24 eighth valve, 25 ninth valve, 26 third fluid preheater, 27 fourth fluid preheater, 28 first constant pressure pump, 29 second constant pressure pump, 30 tenth valve, 31 eleventh valve, 32 first vacuum pump, 33 second vacuum pump. Specific implementation method:

[0050] The present invention will be further described below:

[0051] See also Figure 1 After the depletion of shale oil reservoirs, CO 2 The method for optimizing parameters of energy replenishment in coordination with water-based fluids comprises the following steps:

[0052] Step 1: Obtain key parameters of shale oil reservoir: Through comprehensive analysis of geological, geophysical, logging, well testing and other data, the reservoir pressure, temperature and overburden pressure of the 1# layer of the shale oil reservoir are obtained to be 31.2MPa, 115℃ and 47MPa respectively, and the reservoir pressure, temperature and overburden pressure of the 2# layer are 30.5MPa, 105℃ and 45MPa respectively.

[0053] Step 2: Prepare shale oil and core samples: simulate shale oil by mixing dehydrated and degassed crude oil and kerosene in a volume ratio of 1:1, and obtain simulated shale oil with the same viscosity (0.64 mPa·s) as formation crude oil at a reservoir temperature of 110°C. Drill cylindrical core samples with a diameter of 2.5 cm and a length of 6 cm from full-size core cores of two different layers of the shale reservoir 1# and 2#, and mark them as 1# and 2# samples respectively. Cut the 1# core sample into cores with lengths of 5 cm and 1 cm, respectively, and mark them as 11# and 12# samples. Cut the 2# core sample into cores with lengths of 5 cm and 1 cm, respectively, and mark them as 21# and 22# samples. Samples 12# and 22# are used for high-pressure mercury injection testing, and samples 11# and 21# are used for CO2 injection after depletion development of shale reservoirs. 2 Experiment on optimization of energy replenishment parameters with water-based fluids.

[0054] Step 3: Dry the 11#, 12#, 21# and 22# rock samples at 110°C to constant weight. Then, mercury injection testing was performed on the 12# and 22# rock samples to obtain the pore size distribution data of the 1# and 2# shale rock samples at two different layers.

[0055] Step 4: Use the non-magnetic clamp plug 19 to place the 11# and 21# rock samples 21 in the middle position of two online nuclear magnetic resonance dedicated core clamps 20, and use the pipeline 23 to connect the two clamps in parallel to the online nuclear magnetic resonance core test system 22. Open the eighth valve 24 and the ninth valve 25, the first constant pressure pump 28 and the second constant pressure pump 29, use the fluorine oil 18 to increase the confining pressure to 2MPa, and use the third fluid preheaters 26 and 27 to increase the temperature of the fluorine oil 18 to the reservoir temperature of 115°C and 105°C of the 1# and 2# layers of the shale oil reservoir, respectively. Close the valves 10, 11, the sixth valve 12, and the seventh valve 13 at the inlet and outlet of the clamp, open the tenth valve 30 and the eleventh valve 31, use the first vacuum pump 32 and the second vacuum pump 33 to evacuate the 11# and 21# rock samples for 48 hours, and use the nuclear magnetic resonance control and data acquisition system 22 to perform nuclear magnetic resonance T of the 11# and 21# rock samples in dry state. 1 -T 2 Spectrum test, 11# rock sample dry sample 2D NMR test results are as follows Figure 3 As shown, record the NMR signal of 11# and 21# rock samples 10 and NMR 20 They are 0.4654[PU] and 1.1313[PU] respectively.

[0056] Step 5: Restore the initial reservoir conditions: Overburden pressure P of layer 1# 10 is 47MPa, and the initial pore pressure of the reservoir P p10 The overburden pressure of the 2# layer is 31.2MPa. 20is 45MPa, and the initial pore pressure of the reservoir P p20 The initial effective stress P of the 1# and 2# layers is 30.5MPa. e10 and P e20 15.8MPa and 14.5MPa respectively. Open the first fluid preheater 10 and set the temperature to 115°C. In the process of gradually increasing the confining pressure of fluorine oil 18 to the overburden pressure of 15.8MPa at the 1# layer core, close the tenth valve 30 at the outlet of the clamp, open the first valve 2 and the fourth valve 8 at the inlet, and use the constant speed and constant pressure pump 1 to inject shale oil in the first intermediate container 3 into the clamp to the initial reservoir pore pressure of 31.2MPa (always make the difference between the confining pressure and the pore pressure equal to the initial effective stress value of 15.8MPa), until the flow rate at the inlet of the clamp is zero for 4 hours, close the fourth valve 8, and the conditions of the 11# rock sample are 1# layer reservoir temperature of 115°C and initial pressure of 31.2MPa. Perform oil-saturated state nuclear magnetic resonance (T) of the 11# rock sample under initial reservoir conditions. 1 -T 2 Spectrum test, record the initial saturated oil NMR signal 11 is 8.4096 [PU]. Open the second fluid preheater 11 and set the temperature to 105°C. In the process of gradually increasing the confining pressure of fluorine oil 18 to the overburden pressure of 14.5 MPa at the 2# layer core, close the eleventh valve 31 at the outlet of the clamp, open the fifth valve 9 at the inlet, and use the constant speed and constant pressure pump 1 to inject shale oil in the first intermediate container 3 into the clamp to the initial reservoir pore pressure of 30.5 MPa (always make the difference between the confining pressure and the pore pressure equal to the initial effective stress value of 14.5 MPa), until the flow rate at the inlet of the clamp is zero for 4 hours, close the first valve 2 and the fifth valve 9, and the conditions of the 21# rock sample are 105°C and 30.5 MPa at the 2# layer reservoir temperature. Perform the saturated oil state NMR T of the 21# rock sample under the initial reservoir conditions. 1 -T 2 Spectrum test, 2D NMR test results of 11# rock sample saturated with oil Figure 4 As shown, the initial saturated oil NMR signal is recorded 21 The value is 6.9168 [PU]. Steps 3-5 obtain the differences in the size distribution of micro-nano pores, small pores, medium pores and large pores in shale at different layers.

[0057] Step 6, shale oil reservoir depletion development process: the fourth valve 8, the fifth valve 9, the tenth valve 30 and the eleventh valve 31 at the inlet and outlet ends of the two clamps remain closed, and the pressure of the first back pressure valve 14 and the second back pressure valve 15 at the emptying end (the bottom flow pressure of the production well P f11) is 24MPa, slowly open the sixth valve 12 and the seventh valve 13 at the two clamps' emptying ends, the rock sample pore pressure decreases, the effective stress increases, and the shale oil flows out. Use the first fluid collection container 16 and the second fluid collection container 17 to collect the produced fluid until the flow at the emptying end is zero for 4 consecutive hours, close the sixth valve 12 and the seventh valve 13, and simulate the depletion development process of the shale reservoir. Nuclear magnetic resonance T 1 -T 2 Spectrum test, 2D NMR test results after depletion development of 11# rock sample are as follows Figure 5 As shown, the shale oil nuclear magnetic signal NMR is recorded 12 and NMR 22 They are 7.7022[PU] and 6.5308[PU] respectively. The overall recovery factor of shale oil reservoir depletion development and the multi-scale pore recovery factor of different layers can be obtained.

[0058] Step 7, CO 2 Energy replenishment process with water-based fluid: close the sixth valve 12 and the seventh valve 13 at the emptying end of the two clamps, open the fourth valve 8 and the fifth valve 9 at the injection end, open the third valve 6, and use the constant speed and constant pressure pump 1 to inject pressure P i11 The CO in the third intermediate container 7 is injected into the two holders at 30 MPa. 2 , until the injection flow rate is zero for 4 consecutive hours, close the third valve 6. Open the second valve 4 to inject pressure P i21 The water-based fluid in the second intermediate container 5 is injected into the two holders at 40 MPa until the injection flow rate is zero for 4 consecutive hours, and the fourth valve 8 and the fifth valve 9 at the injection end are closed, and the second valve 4 is closed. 1 After 10 days, set the pressure of the first back pressure valve 14 and 15 back pressure valve at the emptying end (the bottom flow pressure of the production well P f21 ) is 24 MPa, slowly open the sixth valve 12 and the seventh valve 13 at the two clamp drain ends, shale oil, CO 2 and water-based fluids flow outward until the flow at the drain end is zero for 4 consecutive hours, thus simulating the energy replenishment and post-energy replenishment development process of shale oil reservoirs. 1 -T 2 Spectrum test, the results of 2D NMR test of 11# rock sample after energy supplementation development are as follows Figure 6 As shown, the shale oil NMR signal quantity NMR is obtained through diffusion-relaxation NMR data processing. 13 and NMR 23 The overall recovery rate of shale oil reservoirs after energy replenishment at different layers and the multi-scale pore recovery rate at different layers are obtained to facilitate CO 2Synergistic energy replenishment parameter optimization with water-based fluids.

[0059] Step 8: CO2 in different layers of shale reservoirs 2 Evaluation of the effect of synergistic energy replenishment development with water-based fluids:

[0060] ① The saturated oil NMR signal under the initial reservoir conditions in step 5 was subtracted from the dry sample NMR signal in step 4 to obtain the distribution curve of shale oil NMR signal at different relaxation time axes. This curve was compared with the pore size distribution data of shale samples in step 3. The maximum T 2 The relaxation time of 158.49 ms corresponds to the maximum pore size of 45.21 μm, which is the minimum T 2 The relaxation time of 0.251ms corresponds to the minimum pore size of 3.02nm, and the conversion relationship between the NMR relaxation time and the mercury injection pore radius is obtained. According to the peak distribution interval of the shale oil NMR signal, the multi-scale pores of the rock sample are divided into micro-nano pores, small pores, medium pores and large pores. According to the above conversion relationship, the micro-nano pores T of the 11# and 21# rock samples are determined. 2 The relaxation time range is 0.251-1.259 ms, the pore diameter distribution range is 3.02-33.43 nm, and the small pore T 2 The relaxation time range is 0.398-1.585 ms, the pore diameter distribution range is 6.01-47.13 nm, and the mesopore T 2 The relaxation time range is 1.585-12.589ms, the pore diameter distribution range is 47.13nm-1.04μm, and the macropore T 2 The relaxation time range is 12.589-158.49ms and the pore diameter distribution range is 1.04-45.21nm.

[0061] ② Further determine the NMR signal of the dry sample of pores of different scales in the 11# rock sample according to step 4 N10 , NMR S10 , NMR M10 , NMR L10 They are 0.3146, 0.0558, 0.0951, 0 [PU], 21# rock sample and NMR N20 , NMR S20 , NMR M20 , NMR L20 The oil NMR signals of different pore sizes of rock sample 11 under initial reservoir conditions were further determined according to step 5. N11 , NMR S11 , NMR M11 , NMR L11They are 4.8744, 0.8363, 2.4467, 0.2522 [PU], respectively, and NMR of rock sample 21# N21 , NMR S21 , NMR M21 , NMR L21 They are 4.8168, 0.7382, 1.1791 and 0.1827 [PU] respectively.

[0062] ③ Calculation of recovery factor of shale reservoir depletion development: According to step 6, determine the NMR signal of oil in pores of different scales in 11# rock sample after depletion development N12 , NMR S12 , NMR M12 , NMR L12 The NMR signals of oil in pores of different scales in rock sample 21 are 4.5332, 0.7652, 2.2021, and 0.2018 [PU], respectively. N22 , NMR S22 , NMR M22 , NMR L22 They are 4.5877, 0.6886, 1.0932, and 0.1613 [PU] respectively. The total recovery factor η of the 1# layer rock sample depletion development is determined according to formula 1 11 The micro-nanopore recovery factor η is 8.9% and is determined according to Formula 2-Formula 5. N11 , small hole recovery factor η S11 , medium pore recovery factor η M11 and macropore recovery factor η L11 They are 7.5%, 9.1%, 10.4% and 20.0% respectively. Similarly, the total recovery factor η of the depletion development of the 2# layer rock sample is determined 21 , micro-nanopore recovery factor η N21 , small hole recovery factor η S21 , medium pore recovery factor η M21 and macropore recovery factor η L21 They are 6.7%, 5.7%, 7.7%, 8.8% and 13.3% respectively. The overall recovery factor η of the depletion development of the entire shale oil reservoir (including different layers) is determined according to Formula 6 1 It is 8.0%.

[0063]

[0064] ④CO 2 Calculation of recovery factor for synergistic energy recovery with water-based fluids: Determine the CO 2 NMR of oil signals in pores of different scales in 11# rock sample after synergistic energy supplementation with water-based fluid N13 , NMR S13 , NMR M13 , NMRL13 They are 3.5475, 0.6217, 1.5458, 0.0912 [PU], respectively, 21# rock sample NMR N23 , NMR S23 , NMR M23 , NMR L23 The values ​​of CO in the 1# layer are 3.3.6162, 0.6082, 0.9155, and 0.1048 [PU] respectively. 2 Total recovery factor η of synergistic energy development with water-based fluid 12 The micro-nanopore recovery factor η is 32.8% and is determined according to formula 8-11. N12 , small hole recovery factor η S12 , medium pore recovery factor η M12 and macropore recovery factor η L12 They are 29.1%, 27.5%, 38.3% and 63.8% respectively. Similarly, the CO 2 Total recovery factor η of synergistic energy development with water-based fluid 22 , micro-nanopore recovery factor η N22 , small hole recovery factor η S22 , medium pore recovery factor η M22 and macropore recovery factor η L22 The CO2 content of the entire shale reservoir is determined according to Formula 12. 2 Overall recovery factor η of synergistic energy development with water-based fluid 2 It is 31.1%. The calculation process is shown in Table 1.

[0065]

[0066] Table 1 NMR test and recovery calculation results of shale oil reservoirs

[0067]

[0068] Step 9: Comprehensively consider the shale oil recovery rate of the reservoir as a whole, different layers, and different pore sizes using the weighted sum method to calculate CO 2 Optimization of parameters for synergistic energy replenishment with water-based fluids. Overall recovery factor η of reservoir synergistic energy replenishment 2 、Total recovery factor η of 1# layer 12 , micro-nanopore recovery factor η N12 , small hole recovery factor η S12 , medium pore recovery factor η M12 and macropore recovery factor η L12 、Total recovery factor of 2# layer η 22 , micro-nanopore recovery factor η N22 , small hole recovery factor η S22 , medium pore recovery factor ηM22 and macropore recovery factor η L22 Corresponding weight coefficient W 2 , W 12 , W N12 , W S12 , W M12 , W L12 , W 22 , W N22 , W S22 , W M22 , W L22 They are 0.4, 0.1, 0.05, 0.05, 0.05, 0.05, 0.1, 0.05, 0.05, 0.05, 0.05. The sum of the weight coefficients of each parameter is 1, as shown in Formula 14. The optimization objective function f(x) calculated according to Formula 13 is equal to 32.8%. Taking f(x) as the objective function, the energy replenishment timing, energy replenishment pressure, energy replenishment injection speed, energy replenishment injection amount, CO 2 The CO 2 Optimize the energy replenishment parameters in coordination with water-based fluids. The specific method is:

[0069]

[0070] ①Optimize the timing of energy replenishment. Select parallel shale core samples, and in step 6, the bottom flow pressure of the production well drops to 24MPa, 20MPa, 16MPa, and 12MPa at the corresponding time points of 6d, 12d, 20d, and 30d, respectively, and then start CO 2 Recharge energy in coordination with water-based fluid. 6d, 12d, 20d, and 30d are the corresponding energy replenishment opportunities. For different energy replenishment opportunities, the objective function f(x) is calculated to be 32.8%, 36.2%, 37.9%, and 37.6%, respectively. The energy replenishment opportunity 20d corresponding to the maximum f(x) of 37.9% is the optimal energy replenishment opportunity.

[0071] ② Optimize the energy replenishment pressure. At the optimal energy replenishment time of 20 days, CO 2 and water-based fluid to different energy injection pressures of 30MPa, 32MPa, 34MPa, 36MPa, 38MPa and 40MPa, 42MPa, 44MPa, 46MPa, 48MPa. For different energy injection pressures, the objective function f(x) is calculated to be 32.8%, 34.7%, 35.4%, 35.6%, 35.3%, respectively. The maximum f(x) is 35.6% corresponding to CO 2 The water-based fluid energy replenishment pressure is 36MPa and 46MPa, which is CO 2 The optimal charging pressure corresponding to water-based fluids.

[0072] ③ Optimize the energy injection speed. At the optimal energy injection time 20 days, different CO 2 The water-based fluid energy injection rate is 0.0001ml / min, 0.0002ml / min, 0.0003ml / min and 0.0001ml / min, 0.0002ml / min, 0.0003ml / min to replenish the energy until the pressure reaches 36MPa and 46MPa. For different energy injection rates, the objective function f(x) is calculated to be 35.1%, 35.6%, and 35.4%, respectively. The maximum f(x) is 35.6% corresponding to CO 2 The injection rate of water-based fluid is 0.0002ml / min and 0.0002ml / min, which is CO 2 and the optimal energy replenishment injection rate of water-based fluids.

[0073] ④CO 2 The injection ratio of water-based fluid was optimized. At the optimal energy replenishment time 20 days, different CO 2 The injection ratio of water-based fluid is 3:1, 2:1, 1:1, 1:2, 1:3, and the injection rate is 0.0002ml / min. The energy is replenished until the pressure finally reaches 46MPa. For different injection ratios, the objective function f(x) is calculated to be 39.8%, 40.2%, 36.5%, 33.2%, and 29.2%, respectively. The maximum f(x) is 40.2%, corresponding to the injection ratio of 2:1, which is CO 2 and the optimal injection ratio for water-based fluid energy replenishment.

[0074] ⑤CO 2 The injection sequence of water-based fluid was optimized. At the optimal energy replenishment time 20 days, CO 2 / Water-based fluids first / CO second 2 The injection rate was 0.0002 ml / min and the injection ratio was 2:1. The pressure was increased to 46 MPa. 2 / Water-based fluids first / CO second 2 The calculated objective functions f(x) are 40.2% and 37.8% respectively. The injection order corresponding to the maximum f(x) of 40.2% is CO first. 2 / Then the water-based fluid is the optimal injection sequence for energy replenishment.

[0075] ⑥ Optimization of energy replenishment and well soaking time. At the optimal energy replenishment time of 20 days, the injection rate was 0.0002ml / min to replenish energy until the final pressure reached 46MPa, and the post-energy replenishment development was started after different well soaking times of 1d, 5d, 10d, 15d, 20d, 25d, and 30d. For different well soaking times, the objective function f(x) was calculated to be 30.2%, 36.5%, 40.2%, 40.8%, 41.2%, 41.0%, and 40.7%, respectively. The maximum f(x) was 41.2%, and the corresponding well soaking time of 20d was CO 2 and the optimal soaking time for water-based fluid energy replenishment.

[0076] ⑦ Optimization of flowback rate after energy replenishment. At the optimal energy replenishment time, 20 days later, the injection rate was 0.0002ml / min to replenish the energy until the final pressure reached 46MPa. After 20 days of well soaking, different flowback rates of 0.00001ml / min, 0.00002ml / min, 0.00003ml / min, and 0.00004ml / min were used for post-energy replenishment development. For different flowback rates, the objective function f(x) was calculated to be 40.2%, 41.2%, 41.8%, and 41.5%, respectively. The maximum f(x) was 41.8%, corresponding to a flowback rate of 0.00003ml / min, which is CO 2 and the optimal flowback velocity after recharging with water-based fluid.

[0077] Steps 4 to 7 of the present invention are performed using an online nuclear magnetic resonance testing system for shale oil reservoirs. The online nuclear magnetic resonance testing system for shale oil reservoirs includes a constant speed and constant pressure pump 1, a first intermediate container 3, a second intermediate container 5, a third intermediate container 7, a nuclear magnetic resonance dedicated core clamp 20, and a nuclear magnetic control and data acquisition system 22. The constant speed and constant pressure pump 1 is connected to the first intermediate container 3, the second intermediate container 5, and the third intermediate container 7 in parallel. The first intermediate container 3, the second intermediate container 5, and the third intermediate container 7 are connected to the first fluid preheater 10 and the second fluid preheater 11 in parallel. Each fluid preheater is respectively connected to a nuclear magnetic resonance dedicated core clamp 20. The outlet end of a nuclear magnetic resonance dedicated core clamp is connected to an eighth valve 24, a third fluid preheater 26, a first constant pressure pump, and a second fluid preheater. 28, the outlet end is also connected to the tenth valve 30 and the first vacuum pump 32; the outlet end of another nuclear magnetic resonance dedicated core clamp is connected to the ninth valve 25, the fourth fluid preheater 27, and the second constant pressure pump 29, and the outlet end is also connected to the eleventh valve 31 and the second vacuum pump 33; a shale sample 21 is placed in each nuclear magnetic resonance dedicated core clamp, and the shale sample 21 is blocked by the non-magnetic clamp plugs 19 at both ends, and the annular space between the nuclear magnetic resonance dedicated core clamp 20 and the shale sample 21 is filled with fluorine oil 18, and the inlet end of each nuclear magnetic resonance dedicated core clamp is also provided with a valve, a back pressure valve and a fluid collection container; the first intermediate container 3 contains shale oil, the second intermediate container 5 contains water-based fluid, and the third intermediate container 7 contains carbon dioxide.

[0078] Step 3: According to the standard GB / T 21650.1-2008, Mercury injection and gas adsorption method for determination of pore size distribution and porosity of solid materials Part 1: Mercury injection method, high pressure mercury injection test is performed on parallel rock samples to obtain the pore size distribution data of rock samples; Step 4-Step 7: According to the standard SY / T 6490-2014 Laboratory measurement specification for nuclear magnetic resonance parameters of rock samples, nuclear magnetic resonance (NMR) parameters of rock samples are measured by NMR. 1 -T 2 Spectrum test to obtain shale nuclear magnetic T 1 -T 2 Spectral data.

[0079] If there are multiple layers in the shale reservoir, the number of core holders can be increased to perform coring at the corresponding layers. 2 The weight coefficients in this embodiment are obtained by expert estimation. If the actual production process focuses on the development of shale oil in a certain layer or a certain scale of pores, it can be achieved by changing the weight coefficients in formulas 13 and 14. In addition, CO 2 Optimization sequence of parameters for synergistic energy replenishment with water-based fluids.

[0080] During the implementation of this method, the whole process of depletion mining-energy replenishment-mining under different strata conditions in shale reservoirs is truly reflected. During the experiment, there is no need to remove the core, eliminating human interference, and the measurement results are highly accurate. The overall macro-reservoir and multi-scale pore energy replenishment development effects of different micro-strata are comprehensively considered, and the CO2 recovery rate after depletion development of shale reservoirs is realized by using a multi-objective optimization method. 2 Synergistic energy replenishment parameter optimization with water-based fluids.

[0081] The present invention provides a CO2-based shale oil reservoir after depletion development. 2 The optimization method of water-based fluid energy replenishment parameters was first used to simulate the depletion development of shale reservoirs under reservoir temperature and pressure conditions, and then CO injection was performed on the shale core. 2 The online nuclear magnetic resonance joint measurement technology was used to observe and identify the oil recovery efficiency and remaining oil volume and distribution of pores of different scales in shale cores at different layers before and after depletion development and water-based fluid synergistic energy replenishment experiments, and analyze the energy replenishment timing, energy replenishment pressure, energy replenishment injection speed, CO 2 According to the influence of water-based fluid injection ratio, injection sequence, well shut-in time and flowback speed on the energy replenishment effect, an energy replenishment parameter optimization process and method are proposed based on multi-objective optimization.

Claims

1. A method for optimizing parameters of synergistic energy replenishment of CO2 and water-based fluid after depletion development of shale oil reservoirs, characterized in that The steps include: Step 1: Obtain key reservoir parameters of shale oil reservoirs, including reservoir pressure, temperature, and overburden pressure at different layers; Step 2, preparing shale oil and core samples: Shale oil has the same viscosity as formation crude oil at reservoir temperature. Cylindrical core samples are drilled from full-size cores of two different layers, 1# and 2#, in the shale oil reservoir, and are marked as 1# and 2# core samples, respectively. 11# and 12# rock samples are cut from the 1# core sample, and 21# and 22# rock samples are cut from the 2# core sample. Step 3: Dry each rock sample at 110°C to a constant weight, then perform mercury injection testing on rock samples 12# and 22# to obtain pore size distribution data of shale rock samples 1# and 2# at two different layers; Step 4: Two-dimensional NMR test of dry samples of shale at different layers, recording the NMR signal of dry samples of 11# and 21# rock samples respectively. 10 and NMR 20 ; Step 5: restore the initial reservoir conditions and conduct two-dimensional nuclear magnetic resonance tests on the shale oil state in different layers under the initial reservoir conditions. The nuclear magnetic resonance signals of the 11# rock sample and the 21# initial saturated oil are recorded as NMR 11 and NMR 21 ; Step 6: Simulate the depletion development process of shale reservoirs and conduct two-dimensional nuclear magnetic resonance tests after depletion development of shale in different layers. Record the NMR signals of shale oil in rock samples 11# and 21# respectively. 12 and NMR 22 ; Step 7: Simulate the synergistic energy replenishment process of CO2 and water-based fluids, conduct two-dimensional nuclear magnetic resonance tests on shale in different layers after energy replenishment development, and obtain the shale oil nuclear magnetic resonance signal quantities through diffusion-relaxation nuclear magnetic resonance data processing. 13 and NMR 23 ; Step 8: Evaluation of the effect of synergistic energy supplementation development of CO2 and water-based fluids in different layers of shale oil reservoirs; Step nine, comprehensively consider the shale oil recovery rate of the entire reservoir, different layers, and different pore scales, and use the weighted sum method to optimize the synergistic energy replenishment parameters of CO2 and water-based fluids.

2. The method for optimizing parameters of synergistic energy replenishment of CO2 and water-based fluid after depletion development of shale oil reservoirs according to claim 1 is characterized by: The step 1 is specifically as follows: by comprehensively analyzing geological data, geophysical data, logging data, and well test data, key parameters of shale oil reservoirs are obtained, including reservoir pressure, temperature, and overburden pressure at different levels.

3. The method for optimizing parameters of synergistic energy replenishment of CO2 and water-based fluid after depletion development of shale oil reservoirs according to claim 2 is characterized by: The step 2 is specifically as follows: shale oil is prepared by using ground dehydrated and degassed crude oil and kerosene so that the shale oil has the same viscosity as the formation crude oil at the reservoir temperature; cylindrical core samples with a diameter of 2.5 cm and a length of 6 cm are drilled from full-size coring cores of two different layers 1# and 2# of the shale oil reservoir, and are marked as 1# and 2# rock samples respectively; the 1# core sample is cut into cores with a length of approximately 5 cm and 1 cm respectively, and are marked as 11# and 12# rock samples; the 2# core sample is cut into cores with a length of approximately 5 cm and 1 cm respectively, and are marked as 21# and 22# rock samples; the 12# and 22# rock samples are used for high-pressure mercury injection testing, and the 11# and 21# rock samples are used for the optimization experiment of the synergistic energy replenishment parameters of CO2 and water-based fluids after the depletion development of shale oil reservoirs.

4. The method for optimizing parameters of synergistic energy replenishment of CO2 and water-based fluid after depletion development of shale oil reservoirs according to claim 3 is characterized by: The step 4 is specifically as follows: placing the 11# and 21# rock samples in the middle position of two online nuclear magnetic resonance dedicated core holders, respectively, the two holders are connected in parallel to the online nuclear magnetic resonance core test system, using fluorine oil to increase the confining pressure to 2MPa and increase the fluorine oil temperature to the reservoir temperature of the 1# and 2# layers of the shale reservoir respectively; closing the inlet and outlet ends of the holder, vacuuming the 11# and 21# rock samples for 48 hours, and then performing the nuclear magnetic resonance T1-T2 spectrum test of the dry sample state of the 11# and 21# rock samples, and recording the nuclear magnetic resonance signal quantities of the dry samples of the 11# and 21# rock samples, respectively. 10 and NMR 20 .

5. The method for optimizing parameters of synergistic energy replenishment of CO2 and water-based fluid after depletion development of shale oil reservoirs according to claim 4 is characterized by: The step 5 is specifically as follows: the overburden pressure P of the 1# layer 10 , initial reservoir pore pressure P p10 ; Overburden pressure P of 2# layer 20 , initial reservoir pore pressure P p20 ; The initial effective stresses of 1# and 2# layers are P e10 and P e20 . ; In the core of the 1# layer, the fluorine oil confining pressure is gradually increased to the overburden pressure P 10 During the process, the outlet of the holder is closed and shale oil is injected into the holder until the initial pore pressure of the reservoir reaches P p10 , always make the difference between the confining pressure and the pore pressure equal to the initial effective stress value P e10 , until the flow rate at the inlet end of the holder is zero for 4 hours. At this time, the conditions of the 11# rock sample are the reservoir temperature and initial pressure of the 1# layer; the saturated oil state nuclear magnetic resonance T1-T2 spectrum test of the 11# rock sample under the initial reservoir conditions is carried out, and the initial saturated oil nuclear magnetic resonance signal is recorded as NMR 11 ; In the 2# layer core, the fluorine oil confining pressure is gradually increased to the overburden pressure P 20 During the process, the outlet of the holder is closed and shale oil is injected into the holder until the initial pore pressure of the reservoir reaches P p20 , always make the difference between the confining pressure and the pore pressure equal to the initial effective stress value P e20 , until the flow rate at the inlet end of the holder is zero for 4 hours. At this time, the conditions of the 21# rock sample are the reservoir temperature and initial pressure of the 2# layer; the saturated oil state nuclear magnetic resonance T1-T2 spectrum test of the 21# rock sample under the initial reservoir conditions is carried out, and the initial saturated oil nuclear magnetic resonance signal is recorded as NMR 21 .

6. The method for optimizing parameters of synergistic energy replenishment of CO2 and water-based fluid after depletion development of shale oil reservoirs according to claim 5 is characterized by: The specific step six is: keep the outlet ends of the two clamps closed, close the inlet end of the clamp at the same time, set the pressure of the back pressure valve at the emptying end to the bottom flow pressure P of the production well f11 , P f11 <P p10 And P f11 <P p20 , slowly open the two clamp drain valves, the rock sample pore pressure decreases, the effective stress increases, and the shale oil flows out until the drain flow is zero for 4 consecutive hours, realizing the simulation of shale reservoir depletion development process; perform nuclear magnetic resonance T1-T2 spectrum tests on 11# and 21# rock samples after depletion development, and record the shale oil nuclear magnetic resonance signal quantities, respectively. 12 and NMR 22 .

7. The method for optimizing parameters of synergistic energy replenishment of CO2 and water-based fluid after depletion development of shale oil reservoirs according to claim 6 is characterized by: The step 7 is as follows: close the two valves at the discharge end of the clamp and open the injection end to inject pressure P i11 , P i11 >P f11 , inject CO2 into the two holders until the injection flow rate is zero for 4 consecutive hours; the injection pressure P i21 , P i21 >P i11 , inject water-based fluid into the two holders until the injection flow rate is zero for 4 consecutive hours, and then close the injection end; After the well is shut down for a period of time t1, the pressure of the back pressure valve at the drain end is set to the bottom flow pressure P of the production well. f21 , P f21 <P i11 , slowly open the two clamps emptying ends, shale oil, CO2 and water-based fluids flow out until the flow at the emptying end is zero for 4 consecutive hours, realizing the simulation of shale oil reservoir energy replenishment and post-energy replenishment development process; perform nuclear magnetic resonance T1-T2 spectrum test on 11# and 21# rock samples after energy replenishment development, and obtain shale oil nuclear magnetic resonance signal quantities of NMR by diffusion-relaxation nuclear magnetic resonance data processing. 13 and NMR 23 .

8. The method for optimizing parameters of synergistic energy replenishment of CO2 and water-based fluid after depletion development of shale oil reservoirs according to claim 7 is characterized by: The step eight is specifically as follows: ① Using the saturated oil NMR signal under the initial reservoir conditions in step 5 minus the dry sample NMR signal in step 4, the distribution curve of the shale oil NMR signal on different relaxation time coordinate axes is obtained, and compared with the pore size distribution data of the shale rock sample in step 3, the conversion relationship between the NMR relaxation time and the mercury injection pore radius is obtained; according to the peak distribution interval of the shale oil NMR signal, the multi-scale pores of the rock sample are divided into micro-nano pores, small pores, medium pores and large pores, and the radius values ​​and relaxation time values ​​corresponding to the different scale pores of the 11# rock sample and the 21# rock sample are determined according to the above conversion relationship; ② According to step 4, the NMR signal quantities of dry samples of different pore sizes of rock samples 11# and 21# are determined as follows: N10 , NMR S10 , NMR M10 , NMR L10 and NMR N20 , NMR S20 , NMR M20 , NMR L20 According to step 5, the oil NMR signals of different pore sizes of rock samples 11# and 21# under initial reservoir conditions are determined as follows: N11 , NMR S11 , NMR M11 , NMR L11 and NMR N21 , NMR S21 , NMR M21 , NMR L21 ; ③ Calculation of recovery factor of shale reservoir depletion development: According to step 6, the oil NMR signals of different scales of pores in 11# and 21# samples after depletion development are respectively N12 , NMR S12 , NMR M12 , NMR L12 and NMR N22 , NMR S22 , NMR M22 , NMR L22 ; Determine the total recovery factor η of the 1# layer rock sample depletion development according to formula 1 11 , according to formula 2-formula 5, the micro-nanopore recovery factor η is determined respectively N11 , small hole recovery factor η S11 , medium pore recovery factor η M11 and macropore recovery factor η L11 Similarly, determine the total recovery factor η of the 2# layer rock sample depletion development 21 , micro-nanopore recovery factor η N21 , small hole recovery factor η S21 , medium pore recovery factor η M21 and macropore recovery factor η L21 The overall recovery factor η1 of shale reservoir depletion development is determined according to Formula 6; ④ Calculation of recovery factor of synergistic energy supplementation development of CO2 and water-based fluid: According to step 7, the NMR signals of oil in pores of different scales in 11# and 21# rock samples after synergistic energy supplementation development of CO2 and water-based fluid are determined as follows: N13 , NMR S13 , NMR M13 , NMR L13 and NMR N23 , NMR S23 , NMR M23 , NMR L23 ; Determine the total recovery factor η of the 1# layer rock sample CO2 and water-based fluid synergistic energy development 12 According to formula 8-formula 11, the micro-nanopore recovery factor η is determined respectively N12 , small hole recovery factor η S12 , medium pore recovery factor η M12 and macropore recovery factor η L12 Similarly, the total recovery factor η of the 2# layer rock sample CO2 and water-based fluid synergistic energy development is determined 22 , micro-nanopore recovery factor η N22 , small hole recovery factor η S22 , medium pore recovery factor η M22 and macropore recovery factor η L22 ; Determine the overall recovery factor η2 of the synergistic energy supplement development of CO2 and water-based fluid in the entire shale oil reservoir according to formula 12; 9. The method for optimizing parameters of synergistic energy replenishment of CO2 and water-based fluid after depletion development of shale oil reservoirs according to claim 8, characterized in that: The step nine is specifically as follows: the overall recovery rate of the reservoir synergistic energy replenishment η2, the total recovery rate of the 1# layer η 12 、Micro-nanopore recovery rate n N12 、Small hole recovery factor n S12 , medium pore recovery factor n M12 and macropore recovery factor η L12 、Total recovery factor of 2# layer η 22 , micro-nanopore recovery factor η N22 , small hole recovery factor η S22 , medium pore recovery factor η M22 and macropore recovery factor η L22 The corresponding weight coefficients are W2, W 12 , W N12 , W S12 , W M12 , W L12 , W 22 , W N22 , W S22 , W M22 , W L22 ; The optimization objective function f(x) is shown in Formula 13, and the sum of the weight coefficients of each parameter is 1, as shown in Formula 14; Taking f(x) as the objective function, and taking the energy replenishment timing, energy replenishment pressure, energy replenishment injection speed, energy replenishment injection volume, CO2 and water-based fluid injection ratio, injection sequence, well soaking time, and flowback speed as variables, the CO2 and water-based fluid synergistic energy replenishment parameters are optimized; the specific method is: ① Optimization of energy replenishment timing: Select parallel shale core samples and reduce the bottom flow pressure of the production well to P in step 6. f11 , P f12 , P f13 ...P fln Corresponding time points T1, T2, T3...T n Start to use CO2 and water-based fluid to replenish energy, T1, T2, T3...T n That is the corresponding energy replenishment opportunity; for different energy replenishment opportunities, the objective function f(x) is calculated respectively, and the energy replenishment opportunity T corresponding to the maximum f(x) x This is the optimized energy replenishment opportunity; ② Energy replenishment pressure optimization: Inject CO2 and water-based fluid to different energy replenishment injection pressures P at the optimal energy replenishment time Tx. i11 , P i12 , P i13 ...P i1n and P i21 , P i22 , P i23 ...P i2n For different recharging pressures, the objective function f(x) is calculated respectively, and the CO2 and water-based fluid recharging pressure P corresponding to the maximum f(x) is i1x and P i2x That is the optimized CO2 and water-based fluid recharge pressure; ③ Optimization of energy injection speed: At the optimal energy injection time T x Different CO2 and water-based fluid injection rates q i11 ,q i12 ,q i13 ……q i1n and q i21 ,q i22 ,q i23 ……q i2n Add energy until the pressure reaches P i1x and P i2x For different energy injection rates, the objective function f(x) is calculated, and the CO2 and water-based fluid energy injection rates q corresponding to the maximum f(x) are calculated. i1x and q i2x That is, the optimized CO2 and water-based fluid energy injection rate; ④ Optimization of the injection ratio of CO2 and water-based fluid: At the optimal energy replenishment time T x The injection speed q was 3:1, 2:1, 1:1, 1:2 and 1:3 with different CO2 and water-based fluid injection ratios. i1x and q i2x Add energy until the pressure finally reaches P i2x ; For different injection ratios, the objective function f(x) is calculated respectively, and the injection ratio corresponding to the maximum f(x) is the optimized CO2 and water-based fluid energy replenishment injection ratio; ⑤ Optimization of CO2 and water-based fluid injection sequence: At the optimal energy replenishment time T x The injection rate and injection ratio of CO2 and water-based fluid are optimized to replenish the pressure until the pressure reaches P. i2x ; For different injection sequences, the objective function f(x) is calculated respectively, and the injection sequence corresponding to the maximum f(x) is the optimized CO2 and water-based fluid energy replenishment injection sequence; ⑥ Optimization of energy replenishment and well soaking time: At the optimal energy replenishment time T x The optimized CO2 and water-based fluid injection rate q i1x and q i2x Add energy until the final pressure reaches P i2x , respectively at different soaking times t1, t2, t3...t n Then, the post-energy replenishment development is started; for different well-shutdown times, the objective function f(x) is calculated respectively, and the well-shutdown time corresponding to the maximum f(x) is the optimized CO2 and water-based fluid energy replenishment well-shutdown time; ⑦ Optimization of return flow rate after energy replenishment: At the optimal energy replenishment time T x With the optimal CO2 and water-based fluid injection ratio and energy injection rate q i1x and q i2x Add energy until the pressure finally reaches P i2x , during the soaking time t x Then, different return speeds q f1 ,q f2 ,q f3 ……q fn Carry out post-energy replenishment development; for different return flow rates, calculate the objective function f(x) respectively, and the return flow rate corresponding to the maximum f(x) is the optimized CO2 and water-based fluid return flow rate after energy replenishment.

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