Quantitative design method for conversion timing of multi-section combination profile control and flooding section

Abstract

The application belongs to the technical field of oil and gas field development, and particularly discloses a quantitative design method for conversion timing of multi-section slug combination profile control and flooding slug, which comprises the following steps: firstly, core pretreatment; secondly, constant speed oil displacement experiment; and finally, data processing; wherein, the data processing process comprises the following steps: firstly, obtaining the water drive end stage shunt rate, water cut and recovery rate of each layer core, and the chemical flooding stage shunt rate, water cut and recovery rate of each layer core; secondly, calculating the profile improvement rate, oil production increase rate and recovery rate balance degree; then, calculating the displacement balance degree, obtaining the displacement balance degree change curve of each group of experiment, and reading the maximum value; again, calculating the variation coefficient of each group of experiment parallel core utilization limit, and drawing the scatter diagram of the maximum value of each group of experiment displacement balance degree; finally, determining the inflection point value as the timing of injecting the next profile control and flooding system slug. The application can quantitatively guide the conversion timing of each profile control and flooding system slug in real time, maximize the effect of each system slug, and further improve the recovery rate.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, specifically relating to a device and method for quantitatively designing the timing of multi-segment plug combination drive segment plug switching. Background Technology

[0002] In oil extraction, displacement experiments are used to verify the development effect. Due to the influence of multiple factors such as reservoir heterogeneity, injected fluid, crude oil properties, and reservoir wettability, waterflooding exhibits significant channeling, greatly reducing the swept area and affecting the final recovery rate. Polymer flooding can effectively improve the mobility ratio and expand the swept volume by increasing the viscosity of the injected fluid; laboratory experiments show that it can increase the recovery rate by 10%-12% compared to waterflooding. However, profile reversal is common in the later stages of polymer injection, with the injected fluid further circulating ineffectively and inefficiently along high-permeability layers. Combining slugs in a moderating flooding system such as polymers, polymer microspheres, and PPG can effectively improve the oil displacement effect, further expand the swept volume, and achieve deep moderating flooding of the reservoir.

[0003] Chinese invention patent CN111611670B discloses a method, equipment, and system for multi-stage plug-based deep reservoir regulation and displacement. This system, constructed by screening elastic creep particles, viscoelastic colloid agents, and a washing agent, effectively improves reservoir permeability gradients, alters the flow direction of subsequent fluids, and increases displacement efficiency. It also reduces oil-water interfacial tension, thus achieving the dual benefits of expanding sweep efficiency and improving washing efficiency. However, while the method disclosed in this patent is systematic and focuses on the entire process of multi-stage plug deep reservoir regulation and displacement, it neglects the crucial issue of the timing of multi-stage plug combination.

[0004] In December 2019, Zhao Chunsen published an academic paper titled "Indoor Experimental Study on Optimal Slug Combination for Heterogeneous Flooding" in the journal *Modern Chemical Industry*. The paper used orthogonal experimental design to conduct nine groups of displacement experiments with different slug combinations. The optimized slug combination was found to be 1000 mg / L PPG concentration + 1800 mg / L polymer concentration, with an optimal slug size of 0.4 PV, ultimately increasing the oil recovery to 70.63%. Three injection rate parameters (0.3 PV, 0.35 PV, and 0.4 PV) were set using orthogonal experiments. The optimal slug size was obtained through limited experimental results comparison to guide the timing of transitions in the modulated flooding system. However, this method suffers from limitations, including bias and subjectivity in parameter selection. Summary of the Invention

[0005] To address the aforementioned shortcomings in the prior art, this invention aims to provide a device and method for quantitatively designing the switching timing of multi-segment plug combination drive segments, so as to achieve real-time quantitative guidance on the switching timing of each system segment.

[0006] To achieve the above objectives, the technical solution adopted by the present invention is as follows:

[0007] A quantitative design method for the timing of multi-stage plunger combination-driven sluice gate switching includes the following steps performed sequentially: S1, core pretreatment; S2, constant-rate oil displacement experiment; S3, data processing.

[0008] In step S2, the constant-rate oil displacement experiment is conducted using a displacement experimental device, which includes a constant-temperature chamber, a piston container, a constant-rate pump connected to the feed end of the piston container, and a pressure acquisition system for collecting the pressure at the core injection end. The piston container is connected to the core injection end via a pipeline. In step S2, the constant-rate oil displacement experiment requires selecting n core samples from the pretreated cores, where n ≥ 3 core samples are connected in parallel to the displacement experimental device. The selected core samples are then analyzed according to the water phase permeability K. i The experiment was divided into three groups to simulate the high-permeability, medium-permeability, and low-permeability layers of the reservoir, and the experimental data were recorded.

[0009] The data processing in step S3 includes the following steps performed sequentially:

[0010] a1) Based on the recorded experimental data, calculate the comprehensive diversion rate, comprehensive water cut, and comprehensive recovery rate at the end of the first water flooding of each infiltration layer, as well as the comprehensive diversion rate, comprehensive water cut, and comprehensive recovery rate at a certain moment during the chemical flooding stage of each infiltration layer.

[0011] a2) Based on the calculation results in step a1), calculate the profile improvement rate λ, the oil recovery rate ξ, and the recovery rate equilibrium θ.

[0012] The formula for calculating the profile improvement rate λ is:

[0013] Among them, Q wH Q represents the overall diversion rate at the end of the first waterflooding of the high-permeability layer. wM Q represents the overall diversion rate at the end of the first waterflooding in the intermediate-permeability layer. wL Q represents the overall diversion rate at the end of the first waterflooding operation in the low-permeability layer. cHt Q represents the overall diversion rate at time t during the chemical flooding stage of the high-permeability layer. cMt Q represents the overall diversion rate at time t during the chemical flooding stage in the intermediate permeability layer. cLt The total diversion rate at time t represents the chemical flooding stage of the low-permeability layer.

[0014] The formula for calculating the oil recovery rate ξ is:

[0015]

[0016] Among them, f cMt f represents the overall water cut at time t during the chemical flooding stage of the intermediate infiltration layer.wM f represents the overall water cut at the end of the first waterflooding of the intermediate-permeability layer. cLt f represents the overall water cut at time t during the chemical flooding stage of the low-permeability layer. wL f represents the overall water cut at the end of the first waterflooding of the low-permeability layer. cHt The total water content at time t during the chemical flooding stage of the high-permeability layer;

[0017] The formula for calculating the oil recovery equilibrium degree θ is:

[0018]

[0019] Where, η wM η represents the overall recovery rate at the end of the first waterflooding operation in the intermediate-permeability layer. wM η represents the overall recovery rate at the end of the first waterflooding operation in the high-permeability layer. wL η represents the overall recovery rate at the end of the first waterflooding operation in the low-permeability layer. cMt η represents the overall oil recovery rate at time t during the chemical flooding stage in the intermediate-permeability layer. cHt η represents the overall oil recovery rate at time t during the chemical flooding stage of the high-permeability layer. cLt The overall recovery rate at time t represents the chemical flooding stage in the low-permeability layer.

[0020] a3) Based on the profile improvement rate λ, oil recovery rate ξ, and recovery balance θ obtained in step a2), calculate the displacement balance, which is expressed as:

[0021] Φ = (x × λ + y × ξ + z × θ), Equation ④

[0022] Where x is the weighted contribution rate of profile improvement rate λ, y is the weighted contribution rate of oil recovery rate ξ, and z is the weighted contribution rate of recovery rate balance θ.

[0023] a4) Replace the pretreated core obtained in step S1 with a different water phase permeability K. i The core samples were connected in parallel to the displacement experimental device. The chemical flooding system was replaced, and step a3) in steps S1 to S3 was repeated. No less than twenty sets of experiments were conducted, and the displacement equilibrium change curve of each set of experiments was calculated and the maximum value was read.

[0024] a5) Define the utilization limit of a certain permeable layer as: the overall recovery rate at the end of the second waterflooding / the oil displacement efficiency × 100%, and calculate the utilization limit of each permeable layer;

[0025] a6) Calculate the coefficient of variation of the utilization limit of each infiltration layer in each group of experiments based on the utilization limit of each infiltration layer;

[0026] a7) Plot a scatter plot of the coefficient of variation of the mobilization limit of each infiltration layer and the maximum value of the displacement equilibrium degree of each experimental group;

[0027] a8) Based on the scatter plot in step a7), determine the inflection point value. The inflection point value is the timing for transferring the next section of the drive system.

[0028] As a limitation, step S1 includes the following steps performed sequentially:

[0029] b1) Select A cores, where A ≥ n. After drying and cementing, vacuum the cores and treat them with saturated water to obtain the volume of self-absorbed saturated water in each core. Calculate the porosity of each core.

[0030] φ i =V ci / V wi ×100%, Formula ⑤

[0031] Among them, V ci V is the core volume. wi This represents the volume of self-priming saturated water.

[0032] b2) Connect the core samples in parallel to the constant-rate water displacement experimental setup, use a constant-rate pump for constant-rate water displacement, and calculate the water phase permeability of each core sample using Darcy's law.

[0033] K i =(qμL) i ) / (A i ΔP i )×100%, Formula ⑥

[0034] Where q is the injection rate in mL / s, μ is the injection water viscosity in mPa·s, and L i Let A be the length of the i-th core sample in cm. i The cross-sectional area of ​​the i-th core sample is expressed in cm². 2 ΔP i The pressure difference at which the i-th core reaches displacement stability is expressed in atm.

[0035] b3) Using a constant-speed pump, crude oil was injected into the cores of each seepage layer until no water was produced, and the volume of water produced from each core, V, was recorded. oi The volume of produced water is the same as the volume of saturated oil. The oil saturation of each core sample is then calculated.

[0036] S oi =V oi / V wi ×100% Formula ⑦

[0037] b4) The core from step b3) is placed in a constant temperature chamber and aged at the reservoir temperature to obtain a pretreated core.

[0038] As a second limitation, in step S2, each core sample is classified according to its aqueous permeability K.i The method of dividing the reservoir into three groups to simulate the high-permeability, medium-permeability, and low-permeability layers is as follows:

[0039] The core samples selected in step S2 are divided into three groups based on the number of cores. The first group is used to simulate high-permeability layers, the second group is used to simulate medium-permeability layers, and the third group is used to simulate low-permeability layers. The integer quotient obtained by dividing the number of core samples by three is used as the core sample count for high-permeability and low-permeability layers, respectively. The remaining core sample count is used as the core sample count for medium-permeability layers. Based on the core sample count for high-permeability, medium-permeability, and low-permeability layers, the core samples are then categorized according to the water phase permeability K. i They are distributed in descending order of permeability to the high-permeability layer, medium-permeability layer, and low-permeability layer.

[0040] As a third limitation, the constant-rate oil displacement experiment process in step S2 includes: firstly, water flooding is carried out until the overall water content of the core contained in each permeable layer reaches a first set value, then chemical flooding is carried out, and then water flooding is carried out a second time until the overall water content of the core contained in each permeable layer reaches a second set value.

[0041] As a fourth limitation, the core displacement efficiency in step a5) can be calculated in any step from after step a1) to before step a5), and the displacement efficiency is: produced oil / saturated oil × 100%, and the displacement efficiency is the displacement efficiency of a certain permeable layer.

[0042] By adopting the above-described technical solution, the beneficial effects achieved by this invention compared to the prior art are as follows:

[0043] (1) The method of the present invention establishes the displacement equilibrium parameter during the displacement process of heterogeneous reservoirs, and guides the evaluation of the effect of each system sluice plug through its dynamic changes, so as to realize real-time quantitative guidance on the switching timing of each displacement system sluice plug.

[0044] (2) The method of the present invention evaluates the changes in the oil displacement effect of each sluice by establishing reservoir displacement equilibrium, and guides the switching timing of each sluice in reverse, so as to maximize the effect of each system sluice and further improve the recovery rate.

[0045] (3) The method of the present invention can be adjusted and optimized according to the reservoir physical properties, actual application parameters and the actual contribution of each parameter in the mine, and has strong reservoir adaptability.

[0046] In summary, this invention can provide real-time quantitative guidance on the switching timing of slugs in each control and drive system, maximizing the effectiveness of each slug and further improving oil recovery. Attached Figure Description

[0047] The present invention will now be described in further detail with reference to the accompanying drawings and specific embodiments.

[0048] Figure 1This is a schematic diagram of the connection of the displacement experimental apparatus according to an embodiment of the present invention;

[0049] Figure 2 The figures show the variation curves of polymer flooding efficiency in core samples with different permeability according to embodiments of the present invention.

[0050] Figure 3 This is a scatter plot of the coefficient of variation between displacement equilibrium and parallel core utilization limit in an embodiment of the present invention.

[0051] Figure 4 This is a schematic diagram of the connection of the five-tube parallel displacement experimental device according to an embodiment of the present invention;

[0052] Figure 5 The specified slug volume combination is used to adjust the recovery rate and water cut curves;

[0053] Figure 6 The standard segmental flow rate curve is the flow rate curve for the combination of different flow rates.

[0054] Figure 7 This is the displacement balance curve of the multi-segment plug combination adjustment process in an embodiment of the present invention;

[0055] Figure 8 The recovery rate and water cut curves of the multi-segment plug combined controlled-drive system in this embodiment of the invention are shown.

[0056] Figure 9 The flow rate curve is shown for the multi-segment plug combination adjustment drive in an embodiment of the present invention. Detailed Implementation

[0057] To better explain and facilitate understanding of the present invention, the preferred embodiments of the present invention will be described in detail below with reference to the accompanying drawings and specific implementation methods.

[0058] Example 1: Quantitative Design Method for Multi-Segment Plug Combination Drive Segment Switching Timing

[0059] This embodiment provides a quantitative design method for the timing of multi-segment plug combination drive segment switching, including the following steps performed sequentially:

[0060] S1, Core pretreatment; S2, Constant-rate oil displacement experiment; S3, Data processing.

[0061] In this embodiment, step S1 includes the following steps performed sequentially:

[0062] b1) Twelve square cemented rock cores, each 4.5cm × 4.5cm × 30cm, were selected. Their water permeability was 300mD, 500mD, 700mD, 800mD, 1000mD, 1500mD, 2000mD, 3500mD, 4000mD, 4500mD, 5000mD, and 7500mD, respectively. After drying the cores and evacuating them under vacuum for two hours, the cores were allowed to self-absorb saturated water for four hours. The volume of self-absorbed saturated water was obtained, and the porosity φ of each core was calculated. i Where i represents the i-th core sample;

[0063] b2) The core samples were connected to the constant-rate water displacement experimental setup and subjected to constant-rate water displacement using a constant-rate pump. The pressure acquisition system recorded the pressure at the core injection end, and the injection rate was 1 ml / min. The water phase permeability K of each core sample was calculated using Darcy's law. i ;

[0064] b3) Using a constant-speed pump, crude oil with a viscosity of 58 cP was injected into the water-saturated core until no water was produced, and the volume of water produced in each core, V, was recorded. oi The volume of produced water is equal to the volume of saturated oil. Calculate the oil saturation S of each core sample. oi ;

[0065] b4) The core from step b3) is aged in a constant temperature chamber at 55°C to obtain a pretreated core.

[0066] like Figure 2 As shown, the constant-rate oil displacement experiment in step S2 is conducted using a displacement experimental device. This device includes a constant-temperature chamber, a piston container, a constant-rate pump connected to the feed end of the piston container, and a pressure acquisition system for collecting the pressure at the core injection end. The piston container is connected to the core injection end via pipelines. The piston container includes an oil reactor, a water reactor, and a chemical reactor. n cores, where n ≥ 3, are selected and connected in parallel to the displacement experimental device. The selected cores are divided into three groups according to the following method to simulate the high-permeability, medium-permeability, and low-permeability layers of the reservoir, respectively.

[0067] The integer quotient obtained by dividing the core sample count by three is used as the core sample count for the high-permeability and low-permeability layers, respectively. The remaining core sample count is used as the core sample count for the medium-permeability layer. Based on the core sample counts for the high-permeability, medium-permeability, and low-permeability layers, the core samples are then sorted according to the water phase permeability K. i They are distributed in descending order of permeability to the high-permeability layer, medium-permeability layer, and low-permeability layer.

[0068] The constant-rate flooding experiment in step S2 includes: first, water flooding until the overall water cut of the core contained in each permeable layer reaches the first set value of 90%, then switching to chemical flooding; then, water flooding again until the overall water cut of the core contained in each permeable layer reaches the second set value of 98%, and recording the experimental data.

[0069] In this embodiment, three core samples were selected for each group of experiments and connected in parallel to the displacement experimental device, based on the water phase permeability K. i The size of K1 was used to simulate a low-permeability layer, K2 as a medium-permeability layer, and K3 as a high-permeability layer. In the first group of experiments, K1 = 300 mD, K2 = 800 mD, and K3 = 1500 mD. The four chemical flooding systems used in the first group of experiments were AP-P4 hydrophobic associative polymer with a concentration of 1000 mg / L, SMG polymer microspheres with a particle size of 8.3 μm, high-concentration 3640D with a concentration of 45.02 mPa·s, and low-concentration 3640D with a concentration of 27.60 mPa·s.

[0070] The data processing in step S3 includes the following steps performed sequentially:

[0071] a1) Based on the recorded experimental data, calculate the comprehensive diversion rate, comprehensive water cut, and comprehensive recovery rate at the end of the first water flooding of each infiltration layer, as well as the comprehensive diversion rate, comprehensive water cut, and comprehensive recovery rate at a certain moment during the chemical flooding stage of each infiltration layer.

[0072] a2) Based on the calculation results in step a1), calculate the profile improvement rate λ, the oil recovery rate ξ, and the recovery rate equilibrium θ.

[0073] The formula for calculating the profile improvement rate λ is:

[0074] Among them, Q wH Q represents the overall diversion rate at the end of the first waterflooding of the high-permeability layer. wM Q represents the overall diversion rate at the end of the first waterflooding in the intermediate-permeability layer. wL Q represents the overall diversion rate at the end of the first waterflooding operation in the low-permeability layer. cHt Q represents the overall diversion rate at time t during the chemical flooding stage of the high-permeability layer. cMt Q represents the overall diversion rate at time t during the chemical flooding stage in the intermediate permeability layer. cLt The total diversion rate at time t represents the chemical flooding stage of the low-permeability layer.

[0075] The formula for calculating the oil recovery rate ξ is:

[0076]

[0077] Among them, f cMt f represents the overall water cut at time t during the chemical flooding stage of the intermediate infiltration layer. wM f represents the overall water cut at the end of the first waterflooding of the intermediate-permeability layer. cLt f represents the overall water cut at time t during the chemical flooding stage of the low-permeability layer. wL f represents the overall water cut at the end of the first waterflooding of the low-permeability layer. cHtThe total water content at time t during the chemical flooding stage of the high-permeability layer;

[0078] The formula for calculating the oil recovery equilibrium degree θ is:

[0079]

[0080] Where, η wM η represents the overall recovery rate at the end of the first waterflooding operation in the intermediate-permeability layer. wM η represents the overall recovery rate at the end of the first waterflooding operation in the high-permeability layer. wL η represents the overall recovery rate at the end of the first waterflooding operation in the low-permeability layer. cMt η represents the overall oil recovery rate at time t during the chemical flooding stage in the intermediate-permeability layer. cHt η represents the overall oil recovery rate at time t during the chemical flooding stage of the high-permeability layer. cLt The overall recovery rate at time t represents the chemical flooding stage in the low-permeability layer.

[0081] a3) Based on the profile improvement rate λ, oil recovery rate ξ, and recovery balance θ obtained in step a2), calculate the displacement balance, which is expressed as:

[0082] Φ = (x × λ + y × ξ + z × θ), Equation ④

[0083] Where x is the weighted contribution rate of profile improvement rate λ, y is the weighted contribution rate of oil recovery rate ξ, and z is the weighted contribution rate of recovery rate balance θ; in this embodiment, x, y and z are all 1 / 3.

[0084] a4) Replace the pretreated core obtained in step S1 with a different water phase permeability K. i The core samples were connected in parallel to the displacement experimental device. The chemical flooding system was replaced, and step a3) in steps S1 to S3 was repeated. No less than twenty sets of experiments were conducted, and the displacement equilibrium change curve of each set of experiments was calculated and the maximum value was read.

[0085] Table 1 shows six core permeability combinations, and Table 2 shows the specific constant-rate flooding test schemes. In this embodiment, a total of twenty-four sets of three-tube parallel flooding experiments were conducted under six core permeability combinations and four chemical flooding systems.

[0086] Table 1 Six combinations of core permeability

[0087]

[0088]

[0089] Table 2 Experimental Scheme for Chemical Flooding After the First Waterflooding in Three Heterogeneous Reservoirs

[0090]

[0091] a5) Define the exploitation limit of a certain permeable layer as: (Comprehensive oil recovery rate / Oil displacement efficiency at the end of the second waterflood) × 100%, and calculate the exploitation limit of each permeable layer. The comprehensive oil recovery rate and oil displacement efficiency at the end of the second waterflood correspond to the same permeable layer, i.e., the same permeability core.

[0092] The oil displacement efficiency was calculated for core samples with aqueous phase permeability of 300 mD, 500 mD, 700 mD, 800 mD, 1000 mD, 1500 mD, 2000 mD, 3500 mD, 4000 mD, 4500 mD, 5000 mD, and 7500 mD, respectively. The oil displacement efficiency was calculated as: produced oil / saturated oil volume × 100%.

[0093] Figure 2 The figure shows the variation curves of polymer flooding efficiency in core samples with different permeabilities. It can be observed that as the permeability of the water phase in the core increases, the flooding efficiency first increases significantly and then tends to stabilize, exhibiting an overall logarithmic function curve. This trend is consistent with the empirical formula for waterflooding efficiency derived by Yu Qitai et al. in their study, "Study on Waterflooding Efficiency and Sweep Coefficient in Water-Driven Sandstone Oilfields," based on data from 25 oilfields in my country.

[0094] a6) Calculate the coefficient of variation of the utilization limit of each infiltration layer in each group of experiments based on the utilization limit of each infiltration layer.

[0095] a7) Plot a scatter plot of the coefficient of variation of the mobilization limit of each infiltration layer and the maximum value of the displacement equilibrium degree of each experimental group.

[0096] like Figure 3 The figure shows a scatter plot of the coefficient of variation (COP) for displacement isostatics and the utilization limit of parallel core samples from twenty-four experimental groups. The displacement isostatics generally ranged from 35% to 65%, while the COP ranged from 0.1 to 0.8. As the displacement isostatics decreased from 65% to 50%, the COP increased slowly; however, as the displacement isostatics continued to decrease, the COP increased rapidly. This indicates that when the displacement isostatics decrease to a certain range, the overall oil displacement effect of heterogeneous reservoirs significantly decreases, at which point the development mode should be adjusted, i.e., the injection system should be changed. Linear regression analysis revealed that a displacement isostatics of 45% represents the inflection point of the COP change, corresponding to the optimal injection timing for each sluice gate in the displacement system.

[0097] a8) Based on the scatter plot in step a7), determine the inflection point value as 45%. When the displacement balance is 45%, it is the time to transfer the next displacement system segment.

[0098] The formula for calculating the porosity of each core sample in step b1) is:

[0099] φi =V ci / V wi ×100%, Formula ⑤

[0100] Among them, V ci V is the core volume. wi This represents the volume of self-priming saturated water.

[0101] The formula for calculating the water phase permeability of each core sample in step b2) is:

[0102] K i =(qμL) i ) / (A i ΔP i )×100%, Formula ⑥

[0103] Where q is the injection rate in mL / s, μ is the injection water viscosity in mPa·s, and L i Let A be the length of the i-th core sample in cm. i The cross-sectional area of ​​the i-th core sample is expressed in cm². 2 ΔP i The pressure difference at which the i-th core reaches displacement stability is expressed in atm.

[0104] The formula for calculating the oil saturation of each core sample in step b3) is:

[0105] S oi =V oi / V wi ×100%, Formula ⑦

[0106] To verify the effectiveness of the quantitative design method for slug switching timing of multi-slug combination adjustment and drive provided in this embodiment, two groups of five-pipe parallel oil displacement experiments were conducted, as shown in Table 3. One group served as the control group, which underwent the first water drive, fixed injection volume AP-P4 drive, PPG drive, 3640D drive, and the second water drive. The other group served as the experimental group, which underwent multi-slug combination adjustment and drive, and the dynamic change of displacement balance was calculated throughout the process. The standard for slug switching was that the slug balance was less than 45%.

[0107] Table 3. Experimental Scheme for Five-Pipe Parallel Oil Displacement

[0108]

[0109]

[0110] like Figure 4As shown, the control and experimental groups used a three-layer heterogeneous parallel model with cores of five different water phase permeabilities: 500 mD, 1500 mD, 3000 mD, 7500 mD, and 10000 mD. Cores with a water phase permeability of 500 mD simulated a low-permeability layer; cores with water phase permeabilities of 1500 mD, 3000 mD, and 7500 mD simulated a medium-permeability layer (1500 mD, 3000 mD, and 7500 mD were considered the first, 3000 mD, and 7500 mD respectively); and cores with a water phase permeability of 10000 mD simulated a high-permeability layer. The specific experimental steps were as follows: core pretreatment was performed according to step S1; then, a five-pipe parallel oil displacement experiment was conducted according to Table 2; water flooding was performed until the overall water cut reached 90%; then, a chemical system was injected; finally, a second water flooding was performed until the overall water cut reached 98% to conclude the experiment. All experiments were conducted in a constant temperature chamber at 55℃, with an injection rate of 1.5 ml / min.

[0111] Figures 5 to 6 The figure shows the recovery rate and water cut curves and the diversion rate curve of the conventional fixed-section plug volume combination water drive. As can be seen from the figure, the water cut rises rapidly in the first water drive stage of the five-pipe parallel displacement system. The high water cut stage begins with an injection volume of approximately 0.3 PV, and the diversion rate of the high-permeability layer stabilizes at around 95%, with only the high-permeability layer and the first intermediate-permeability layer producing fluid. After injecting AP-P4 hydrophobic associating polymer, the water cut decreases rapidly, significantly improving the recovery rate. Simultaneously, the diversion rate of the high-permeability layer decreases significantly, and fluid is produced in all five core samples. After injecting approximately 0.2 PV of AP-P4 hydrophobic associating polymer, the overall water cut and the diversion rate of the high-permeability layer begin to recover, but the increase in recovery rate slows down, and the high-permeability layer once again becomes the dominant channel. During the PPG solution injection stage, the rapidly rising overall water cut curve stabilized at around 90%, the high-permeability layer diversion rate decreased again, and the increase in diversion rate of the low-permeability layer and the third intermediate-permeability layer was greater than that during the AP-P4 hydrophobic polymer injection stage. Simultaneously, the recovery curve rose again, indicating that the PPG solution played a role in expanding the swept volume and improving the recovery rate. In the subsequent 3640D flooding stage, the water cut and high-permeability layer diversion rate remained stable and slowly recovered, indicating that the plugging effect of the PPG solution had a certain degree of sustainability, while the recovery rate also maintained a steady increase. In the second waterflooding stage, the water cut and high-permeability layer diversion rate increased rapidly, and the final recovery rate stabilized at 44.65%, which can increase the recovery rate by 8.11% after AP-P4 hydrophobic polymer flooding.

[0112] Figure 7The figure shows the displacement equilibrium curve obtained using this implementation guideline for the multi-segment plug combination displacement control process. It can be seen that after injecting AP-P4 hydrophobic associative polymer, the displacement equilibrium initially increases gradually, then decreases slowly, and finally decreases rapidly. When the injection volume reaches 0.7 PV, the displacement equilibrium decreases to 40.49%, at which point SMG polymer microspheres are injected. After the injection, the displacement equilibrium rapidly rises to over 70% and remains stable. At this point, the profile improvement rate plays a dominant role. When the SMG polymer microsphere injection volume is approximately 0.25 PV, the displacement equilibrium decreases rapidly. At this point, the profile improvement rate and the oil recovery rate jointly determine the change in displacement equilibrium. After injecting 0.35 PV of SMG polymer microspheres, the displacement isostatics decreased to 39.32%, and the injection of 3640D solution exerted an oil displacement effect. After the injection, the displacement isostatics stabilized at around 50%. At this point, although the oil recovery rate improved, the decrease in profile improvement rate resulted in a small increase in displacement isostatics. After injecting approximately 0.25 PV of 3640D, the displacement isostatics decreased to 26.77%, and the injection of PPG solution further blocked the high-permeability layer. After the injection, the displacement isostatics rose again to around 70%, and its trend mainly depended on the oil recovery rate. After injecting PPG solution, the profile improvement rate increased and remained stable, while the oil recovery rate first increased significantly, reached a peak, and then rapidly decreased. PPG solution is a particulate dispersion system, mainly used to adjust the profile, therefore the period for improving the oil recovery rate is limited. After injecting 0.5 PV of PPG solution, the displacement isostatics decreased to 39.08%. 3640D solution was then injected again to leverage the improved oil displacement effect after profile adjustment. After the injection, the displacement isostatics recovered to around 50%, although this period was also short-lived. However, the overall value was higher than the displacement isostatics during the 3640D flooding stage after injecting SMG polymer microspheres, indicating that the PPG solution's modulating effect was significantly better than that of SMG polymer microspheres. After injecting 0.4 PV of 3640D solution, the displacement isostatics decreased to 43.77%, prompting a second waterflooding phase. During the second waterflooding phase, both the profile improvement rate and the oil recovery rate decreased significantly; therefore, displacement isostatics were not calculated.

[0113] Figure 8 The figure shows the recovery rate and water cut curves of the multi-segment plug combined controlled displacement obtained using the guidance of this embodiment. Figure 9The diagram shows the flow rate curves of the multi-slug combined flooding system obtained using the methods described in this embodiment. It can be seen that the variation patterns of the displacement characteristic parameters in the water drive stage and the AP-P4 hydrophobic associated polymer flooding stage are basically consistent with conventional flooding experiments. In the subsequent elastic dispersed fluid combined flooding stage, when SMG polymer microspheres and PPG slugs are injected, both the overall water cut and the flow rate of the high-permeability layer decrease significantly before rebounding, exhibiting a funnel shape. The polymer slugs in the multi-slug combined flooding system can delay the upward trend of water cut, utilize crude oil from reservoirs with lower permeability, improve the efficiency of each system's slug injection stage, and reduce ineffective and inefficient circulation. The final recovery rate stabilized at 54.83%, which can increase the recovery rate by 17.79% after AP-P4 hydrophobic associated polymer flooding, and is 9.69% higher than the conventional slug quantity flooding method.

Claims

1. A quantitative design method for the timing of multi-segment plug combination displacement segment switching, comprising the following steps performed sequentially: S1, core pretreatment; S2, constant-rate displacement experiment; S3, data processing; The constant-rate oil displacement experiment in step S2 is conducted using a displacement experimental device, which includes a constant-temperature chamber, a piston container, a constant-rate pump connected to the feed end of the piston container, and a pressure acquisition system for collecting the pressure at the core injection end; the piston container is connected to the core injection end via a pipeline; characterized in that... In step S2, the constant-rate oil displacement experiment requires selecting n core samples from the pretreated core samples, where n ≥ 3 core samples are connected in parallel to the displacement experimental device. The selected core samples are then analyzed according to their water phase permeability. The reservoir was divided into three groups in descending order of permeability, simulating high-permeability, medium-permeability, and low-permeability layers respectively, and the experimental data were recorded. The constant-rate flooding experiment in step S2 includes: first, water flooding is carried out until the overall water content of the core contained in each permeable layer is at a first set value, then chemical flooding is carried out, and then water flooding is carried out a second time until the overall water content of the core contained in each permeable layer is at a second set value. The data processing in step S3 includes the following steps performed sequentially: a1) Based on the recorded experimental data, calculate the comprehensive diversion rate, comprehensive water cut, and comprehensive recovery rate at the end of the first water flooding of each infiltration layer, as well as the comprehensive diversion rate, comprehensive water cut, and comprehensive recovery rate at a certain moment during the chemical flooding stage of each infiltration layer. a2) Calculate the profile improvement rate based on the calculation results in step a1). Oil production increase rate and recovery rate balance ; Profile improvement rate The calculation formula is: Formula ① Among them, Q wH Q represents the overall diversion rate at the end of the first waterflooding of the high-permeability layer. wM Q represents the overall diversion rate at the end of the first waterflooding in the intermediate-permeability layer. wL Q represents the overall diversion rate at the end of the first waterflooding operation in the low-permeability layer. cHt Q represents the overall diversion rate at time t during the chemical flooding stage of the high-permeability layer. cMt Q represents the overall diversion rate at time t during the chemical flooding stage in the intermediate permeability layer. cLt The total diversion rate at time t represents the chemical flooding stage of the low-permeability layer. Oil production increase rate The calculation formula is: Formula ② Among them, f cMt f represents the overall water cut at time t during the chemical flooding stage of the intermediate infiltration layer. wM f represents the overall water cut at the end of the first waterflooding of the intermediate-permeability layer. cLt f represents the overall water cut at time t during the chemical flooding stage of the low-permeability layer. wL f represents the overall water cut at the end of the first waterflooding of the low-permeability layer. cHt The total water content at time t during the chemical flooding stage of the high-permeability layer; Recovery rate equilibrium The calculation formula is: Formula ③ Where, η wM η represents the overall recovery rate at the end of the first waterflooding operation in the intermediate-permeability layer. wM η represents the overall recovery rate at the end of the first waterflooding operation in the high-permeability layer. wL η represents the overall recovery rate at the end of the first waterflooding operation in the low-permeability layer. cMt η represents the overall oil recovery rate at time t during the chemical flooding stage in the intermediate-permeability layer. cHt η represents the overall oil recovery rate at time t during the chemical flooding stage of the high-permeability layer. cLt The overall recovery rate at time t represents the chemical flooding stage in the low-permeability layer. a3) Based on the profile improvement rate obtained in step a2) Oil production increase rate and recovery rate balance Calculate the displacement balance degree, which is expressed as: Formula ④ Where x is the weighted contribution rate of profile improvement rate λ, y is the weighted contribution rate of oil recovery rate ξ, and z is the weighted contribution rate of recovery rate balance θ. a4) Replace the pretreated core obtained in step S1 with different water phase permeability The core samples were connected in parallel to the displacement experimental device. The chemical flooding system was replaced, and step a3 in steps S1 to S3 was repeated. No less than twenty sets of experiments were conducted, and the displacement equilibrium change curve of each set of experiments was calculated and the maximum value was read. a5) Define the utilization limit of a certain permeable layer as: the overall recovery rate at the end of the second waterflooding / the oil displacement efficiency × 100%, and calculate the utilization limit of each permeable layer; a6) Calculate the coefficient of variation of the utilization limit of each infiltration layer in each group of experiments based on the utilization limit of each infiltration layer; a7) Plot a scatter plot of the coefficient of variation of the mobilization limit of each infiltration layer and the maximum value of the displacement equilibrium degree of each experimental group; a8) Based on the scatter plot in step a7), determine the inflection point value. The inflection point value is the timing for transferring the next section of the drive system.

2. The quantitative design method for the timing of multi-stage piston combination drive sluice switching according to claim 1, characterized in that, Step S1 includes the following steps performed sequentially: b1) Select A cores, where A≥n. After drying and cementing, vacuum the cores and treat them with saturated water to obtain the self-absorbed saturated water volume of each core. Calculate the porosity of each core: Formula 5 in, For the core volume, The volume of the self-absorbed saturated water is represented by i, where i represents the i-th core. b2) Connect the core samples in parallel to the constant-rate water displacement experimental setup, use a constant-rate pump for constant-rate water displacement, and calculate the water phase permeability of each core sample using Darcy's law. Formula 6 in, Injection rate, in mL / s. The viscosity of the injected water is expressed in mPa·s. The length of the i-th core sample is in cm. The cross-sectional area of ​​the i-th core sample is expressed in cm². 2 , The pressure difference at which the i-th core reaches displacement stability is expressed in atm. b3) Using a constant-speed pump, crude oil was injected into the cores of each seepage layer until no water was produced, and the volume of water produced from each core was recorded. The volume of produced water is the same as the volume of saturated oil. The oil saturation of each core sample is then calculated. Formula ⑦ b4) The core from step b3) is placed in a constant temperature chamber and aged at the reservoir temperature to obtain a pretreated core.

3. The quantitative design method for the timing of multi-stage piston combination adjustment and drive sluice switching according to claim 2, characterized in that, In step S2, each core sample is sorted according to its water phase permeability K. i The method of dividing the reservoir into three groups to simulate the high-permeability, medium-permeability, and low-permeability layers is as follows: The core samples selected in step S2 are divided into three groups based on the number of cores. The first group is used to simulate high-permeability layers, the second group is used to simulate medium-permeability layers, and the third group is used to simulate low-permeability layers. The integer quotient obtained by dividing the number of core samples by three is used as the core sample count for high-permeability and low-permeability layers, respectively. The remaining core sample count is used as the core sample count for medium-permeability layers. Based on the core sample count for high-permeability, medium-permeability, and low-permeability layers, the core samples are then sorted according to their water phase permeability. They are distributed in descending order of permeability to the high-permeability layer, medium-permeability layer, and low-permeability layer.

4. The quantitative design method for the timing of multi-stage piston combination drive sluice switching according to any one of claims 1-3, characterized in that, The core displacement efficiency in step a5) can be calculated in any step from after step a1) to before step a5). The displacement efficiency is: produced oil / saturated oil × 100%. The displacement efficiency is the displacement efficiency of a certain permeable layer.

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