Method for testing and evaluating plug removal and oil displacement capacity of biological source composite system

Abstract

The invention belongs to the technical field of petroleum engineering, and particularly relates to a method for testing and evaluating the plug removal and oil displacement capacity of a biological source composite system, which comprises the following steps of: injecting the biological source composite system into a preferable offshore oilfield core to carry out a plug removal and oil displacement experiment, t2 map testing and micrometer rock core CT scanning are carried out on the crude oil saturated rock core, the stratum water pollution rock core, the rock core injected with the biological source composite system for plug removal and oil displacement and the rock core subjected to secondary water displacement in the plug removal and oil displacement experiment; by taking the relaxation time as an abscissa and the nuclear magnetic resonance signal intensity as an ordinate, drawing a point-line diagram for a T2 atlas test result to obtain an integral area and peak signal intensity of the T2 atlas; according to a micron core CT scanning result, characteristic parameters are calculated, the occurrence state of the residual oil is defined through the characteristic parameters, and an imaging result is obtained. According to the method, the plug removal and oil displacement effects of the biological source composite system are verified from multiple dimensions, evaluation indexes are specific and quantifiable, and the method has the advantages of being visual, simple, convenient, high in resolution ratio and high in pertinence.

Description

Technical Field

[0001] The invention belongs to the technical field of petroleum engineering, and in particular relates to a method for testing and evaluating the plugging removal and oil displacement capabilities of a bio-source composite system. Background Art

[0002] As global energy demand continues to grow, the extraction and utilization of oil, a key traditional energy source, plays a crucial role in economic development. However, oil extraction faces numerous technical challenges, with well blockage and low crude oil recovery rates being two key issues hindering the development of the oil industry. To effectively address these challenges, researchers are constantly exploring and developing new technologies to improve oil well production efficiency, reduce extraction costs, and minimize negative environmental impacts.

[0003] In recent years, the application of biotechnology in the petroleum industry has gradually attracted attention. Biotechnology utilizes microorganisms and their metabolites to improve the physical and chemical properties of oil reservoirs, offering advantages such as environmental friendliness, low cost, and long-lasting effects. Against this backdrop, plugging removal and oil recovery agents based on bio-derived composite systems have emerged and gradually become a research hotspot. Bio-derived composite systems screen and cultivate specific microorganisms and utilize their metabolites, such as biosurfactants and biopolymers, to improve the physical and chemical properties of reservoirs, thereby achieving the goal of plugging removal and oil recovery. Through systematic testing and evaluation of the plugging removal and oil recovery capabilities of bio-derived composite systems, this technology can be further optimized, its application in actual oil fields can be enhanced, and new technical support can be provided for increasing oilfield recovery and promoting the sustainable development of the petroleum industry.

[0004] Therefore, scientifically and systematically testing and evaluating the plugging removal and oil recovery performance of biogenic composite systems, so that they can be effectively applied in oilfield production, is crucial for stabilizing and increasing oilfield production. However, conventional evaluation of plugging removal and oil recovery technologies is based on laboratory core flooding experiments. The resulting technical indicators include plugging removal rate, damage coefficient, crude oil recovery rate, and water content of produced fluids. These evaluation indicators are limited and lack observation of the reservoir core and the changes in the crude oil within the layer. Summary of the Invention

[0005] In view of the shortcomings of the prior art, the present invention provides a method for testing and evaluating the plugging removal and oil displacement capabilities of a bio-source composite system.

[0006] Specifically, the present invention is achieved through the following technical solutions:

[0007] A method for testing and evaluating the plugging removal and oil displacement capabilities of a bio-source composite system, comprising:

[0008] S1: Dry the offshore oilfield core and then flood it with crude oil until it is saturated to obtain the crude oil-saturated core. Perform T2 mapping test and micron core CT scanning on the crude oil-saturated core to measure the initial permeability k0 of the core and the integral area A0 of the T2 curve;

[0009] S2 uses formation water to reversely displace the crude oil saturated core to cause core blockage, obtaining a formation water contaminated core, performing a T2 map test and a micron core CT scan on the formation water contaminated core, and measuring the permeability k1 and the integral area A1 of the T2 curve at the time of blockage;

[0010] S3: forwardly injecting the biogenic composite system into the formation water-contaminated core to conduct a plugging and oil displacement experiment, obtaining a core after plugging and oil displacement by the biogenic composite system, performing a T2 map test and a micron core CT scan on the core after plugging and oil displacement by the biogenic composite system; and measuring the permeability k2 and the integral area A2 of the T2 curve after plugging removal;

[0011] S4 calculates the damage coefficient and unblocking rate of the core during and after blockage according to the unblocking rate and damage coefficient formula;

[0012] S5: injecting formation water into the core after the injection of the biogenic composite system to remove plugging and flood the oil, until the water content reaches 98% or more, to obtain a core after secondary water flooding, and performing T2 mapping test and micron core CT scanning on the core after secondary water flooding;

[0013] S6 uses relaxation time as the horizontal axis and nuclear magnetic resonance signal intensity as the vertical axis to draw a dot-line graph of the T2 spectrum test results to obtain the integral area and peak signal intensity of the T2 spectrum;

[0014] S7 calculates characteristic parameters based on the results of the micron core CT scan, defines the occurrence state of the residual oil through the characteristic parameters, and obtains an image result.

[0015] In the above-mentioned test and evaluation method for the plugging removal and oil displacement capability of the biosource composite system, the formation water contains 2.8-3.5 mg / L of oil, 0.2-0.5 mg / L of iron ions, and 20-25 num / mL of sulfate-reducing bacteria.

[0016] In the above-mentioned test and evaluation method for the plugging removal and oil displacement capability of the biogenic composite system, in step S2, the criteria for judging whether the core is plugged are: the water content at the core inlet reaches above 98% and the injection pressure increases significantly.

[0017] The above-mentioned test and evaluation method for the plugging removal and oil displacement ability of the biosource composite system is a compound of bio-acid, rhamnolipid surfactant and lipopeptide surfactant, with a slug ratio of 1:1:2 to 2:1:1 and a concentration of 500-2000 mg / L.

[0018] In the above-mentioned test and evaluation method for the plugging removal and oil displacement capability of the biogenic composite system, the T2 spectrum test is performed using a nuclear magnetic resonance analyzer, and the micron core CT scan is performed using a micro-nano dual-ray tube core CT scanning system.

[0019] In the above-mentioned test and evaluation method for the plugging removal and oil displacement capability of the biogenic composite system, the setting parameters of the nuclear magnetic resonance instrument are: using a CPMG sequence, an echo time TE of 0.1-0.5 ms, a waiting time TW of 4000-12000 ms, and an echo number of 100-5000.

[0020] In the above-mentioned test and evaluation method for the plugging removal and oil displacement capability of the biogenic composite system, the characteristic parameters include area coefficient, overlap, and Euler number.

[0021] In the above-mentioned test and evaluation method for the plugging removal and oil displacement capability of the biogenic composite system, the occurrence states include cluster, sieve, drop, column, and sheet.

[0022] In the above-mentioned test and evaluation method for the plugging removal and oil displacement capability of the biogenic composite system, the resolution of the micron core CT scan is 4 μm, and the sample diameter is 10 mm.

[0023] In the above-mentioned testing and evaluation method for the plugging removal and oil recovery capability of the biogenic composite system, the offshore oilfield core is one of a low permeability core, a medium permeability core, and a high permeability core; wherein the permeability of the low permeability core is less than 10mD, the permeability of the medium permeability core is 10-100mD, and the permeability of the high permeability core is greater than 100mD.

[0024] The technical solution of the present invention has the following beneficial effects compared with the prior art:

[0025] (1) The test and evaluation method for the plugging removal and oil displacement ability of the biosource composite system of the present invention is mainly aimed at the biosource composite system, and verifies the plugging removal and oil displacement effects of the system from multiple dimensions. The evaluation indicators are specific and quantifiable, and are intuitive, simple, high-resolution, and highly targeted. It can serve as an important reference for evaluating the adaptability of reagents and improving the efficiency of oilfield development and extraction;

[0026] (2) The testing and evaluation method of the biogenic composite system's plugging removal and oil displacement ability of the present invention can intuitively reflect the oil displacement effect of the biogenic composite system on the core and its mechanism of action by testing the one-dimensional model of the biogenic composite system's plugging removal and oil displacement effect through nuclear magnetic resonance testing of the T2 spectrum of offshore oil field cores. It has the characteristics of non-destructive testing, convenient and efficient process, and quantifiable evaluation indicators;

[0027] (3) The test and evaluation method of the biogenic composite system's ability to remove blockages and displace oil in the present invention uses a three-dimensional model to evaluate the oil displacement effect of the biogenic composite system. It has the characteristics of high resolution, rich data information, accurate fluid characteristics, and an intuitive model. BRIEF DESCRIPTION OF THE DRAWINGS

[0028] Various other advantages and benefits will become apparent to those skilled in the art by reading the following detailed description of the preferred embodiment.The accompanying drawings are only for the purpose of illustrating the preferred embodiment and are not to be considered as limiting the present invention.

[0029] Figure 1 This is a flow chart of a method for testing and evaluating the plugging removal and oil displacement capabilities of the bio-source composite system of the present invention;

[0030] Figure 2 This is the T2 spectrum of the crude oil saturated core in Example 1;

[0031] Figure 3 This is the T2 spectrum of the formation water contaminated core in Example 1;

[0032] Figure 4 This is the T2 spectrum of the core after the biogenic composite system was injected to remove blockage and flood the oil field in Example 1;

[0033] Figure 5 This is the T2 spectrum of the core after the secondary water flooding in Example 1;

[0034] Figure 6 This is a curve showing the changes in injection pressure and recovery rate with the amount of injected chemicals in Example 1;

[0035] Figure 7 The T2 spectrum of the core measured after injection of the biogenic composite system at different times in Example 1;

[0036] Figure 8 The micron CT scanning results of the core of the oil displacement experiment carried out by the bio-source composite system in Example 1;

[0037] Figure 9 This is a histogram of the residual oil distribution in the core after the oil displacement experiment with the biosource composite system in Example 1;

[0038] Figure 10 This is the T2 spectrum after the biogenic composite system was injected into the medium permeability core in Example 2;

[0039] Figure 11 The micron CT scanning results of the core of the oil displacement experiment carried out by the bio-source composite system in Example 2;

[0040] Figure 12 This is a histogram of the residual oil distribution in the core after the oil displacement experiment was carried out with the biosource composite system in Example 2. DETAILED DESCRIPTION

[0041] In order to fully understand the purpose, features and effects of the present invention, the present invention is described in detail through the following specific embodiments. Except for the following contents, the process of the present invention adopts conventional methods or devices in the art. Unless otherwise specified, the following terms have the meanings commonly understood by those skilled in the art.

[0042] When a numerical range is disclosed herein, the range is considered continuous and includes the minimum and maximum values ​​of the range, as well as every value between such minimum and maximum values. Further, when a range refers to an integer, every integer between the minimum and maximum values ​​of the range is included. In addition, when multiple ranges are provided to describe a feature or characteristic, the ranges can be combined. In other words, unless otherwise indicated, all ranges disclosed herein are understood to include any and all subranges subsumed therein.

[0043] The inventive concept and principle of the present invention are as follows: on the one hand, nuclear magnetic resonance technology can be used to quantitatively describe the distribution of the relative content of residual oil in pores as a function of pore size, which can be reflected in a graph to make a simple judgment on the pore blockage and reservoir distribution, thereby evaluating the deblocking and oil displacement capabilities of the biogenic composite system; on the other hand, X-CT scanning technology can be used to accurately describe and construct the internal pore distribution of the reservoir core and the flow characteristics of the fluid in the core. Water-flooded oil cores under different displacement ratios are scanned at different angles to obtain the microscopic pore structure and fluid saturation distribution of the reservoir core. Combined with computer tomographic image processing, slice reconstruction interpolation and pore structure construction technology, the reservoir core is converted into a three-dimensional data volume model, and the required pore and oil-water distribution information in the core is reconstructed and extracted, thereby realizing the spatial display of the three-dimensional form of the residual oil in the reservoir micro-core, which is used for evaluating the recovery efficiency of the biogenic composite system and ensuring that targeted recovery efficiency measures are obtained for the oil reservoir.

[0044] Specifically, such as Figure 1 As shown, the test and evaluation method of the bio-source composite system's plugging removal and oil displacement capability of the present invention comprises:

[0045] S1: Dry the offshore oilfield core and then flood it with crude oil until it is saturated to obtain the crude oil-saturated core. Perform T2 mapping test and micron core CT scanning on the crude oil-saturated core to measure the initial permeability k0 of the core and the integral area A0 of the T2 curve;

[0046] S2 uses formation water to reversely displace the crude oil saturated core to cause core blockage, obtaining a formation water contaminated core, performing a T2 map test and a micron core CT scan on the formation water contaminated core, and measuring the permeability k1 and the integral area A1 of the T2 curve at the time of blockage;

[0047] S3: forwardly injecting the biogenic composite system into the formation water-contaminated core to conduct a plugging and oil displacement experiment, obtaining a core after plugging and oil displacement by the biogenic composite system, performing a T2 map test and a micron core CT scan on the core after plugging and oil displacement by the biogenic composite system; and measuring the permeability k2 and the integral area A2 of the T2 curve after plugging removal;

[0048] S4 calculates the damage coefficient and unblocking rate of the core during and after blockage according to the unblocking rate and damage coefficient formula;

[0049] S5: injecting formation water into the core after the injection of the biogenic composite system to remove plugging and flood the oil, until the water content reaches 98% or more, to obtain a core after secondary water flooding, and performing T2 mapping test and micron core CT scanning on the core after secondary water flooding;

[0050] S6 uses relaxation time as the horizontal axis and nuclear magnetic resonance signal intensity as the vertical axis to draw a dot-line graph of the T2 spectrum test results to obtain the integral area and peak signal intensity of the T2 spectrum;

[0051] S7 calculates characteristic parameters based on the results of the micron core CT scan, defines the occurrence state of the residual oil through the characteristic parameters, and obtains an image result.

[0052] The present invention's method for testing and evaluating the plugging removal and oil displacement capabilities of a biogenic composite system primarily includes a one-dimensional model for evaluating the plugging removal and oil displacement effectiveness of the biogenic composite system and a three-dimensional model for evaluating its effectiveness. The one-dimensional model primarily relies on the T2 spectrum provided by a nuclear magnetic resonance (NMR) instrument, which can reveal the distribution of residual oil along the pore size of the oilfield core. The three-dimensional model primarily relies on data on core pore conditions, fluid seepage mechanics, and residual oil distribution provided by a micron core CT scanning system. Through data analysis and model construction, a three-dimensional dynamic visualization of the relative content and occurrence of residual oil in the core can be created.

[0053] The calculation formula for the congestion relief rate is:

[0054]

[0055] Where k0 is the initial permeability of the crude oil saturated core, mD;

[0056] A0 is the integrated area of ​​the T2 curve of the crude oil saturated core, dimensionless;

[0057] k1 is the permeability of the core contaminated by formation water, mD;

[0058] A1 is the integral area of ​​the T2 curve of the core contaminated by formation water, dimensionless;

[0059] k2 is the permeability of the core after the injection of the biogenic composite system to remove plugging and flood oil, mD;

[0060] A2 is the integrated area of ​​the T2 curve, dimensionless;

[0061] t is the correction factor, and its value depends on the core state and the unblocking situation.

[0062] The damage coefficient calculation formula is:

[0063]

[0064] In the formula, k takes the values ​​of k1 and k2 to calculate the damage coefficient when the core is blocked and after unblocking.

[0065] The unblocking rate and damage coefficient are dimensionless variables used to quantitatively analyze core damage. When calculating the unblocking rate, the influence of changes in core permeability and the integrated area of ​​the T2 spectrum are fully considered. The calculation combines these two factors and introduces a correction factor to ensure the rationality of the formula. The damage coefficient reflects the recovery of permeability during the unblocking process. The higher the permeability recovery, the lower the damage coefficient.

[0066] The large amount of metal inorganic salt ions, light organic matter and abundant microorganisms contained in the formation water of offshore oil fields are important factors causing core blockage.

[0067] In some preferred embodiments, the offshore oilfield formation water used in the present invention contains 2.8-3.5 mg / L of oil, 0.2-0.5 mg / L of iron ions, and 20-25 num / mL of sulfate-reducing bacteria.

[0068] In some preferred embodiments, the temperature of the plugging removal and oil recovery experiment is 20-100° C., the pH of the formation water is 1-10, and the salinity of the formation water is 3000-15000 mg / L.

[0069] In some preferred embodiments, the criterion for judging whether the core is blocked is as follows: using formation water to reversely displace the core from the outlet end of the core column, observing that the water content at the inlet end reaches more than 98%, and the core injection pressure increases significantly, the core is determined to be contaminated and blocked by formation water.

[0070] In some preferred embodiments, the biosource composite system is a mixture of bioacid, rhamnolipid surfactant and lipopeptide surfactant, with a slug ratio of 1:1:2 to 2:1:1 and a concentration of 500-2000 mg / L.

[0071] The types and ratios of the bioacid, rhamnolipid surfactant and lipopeptide surfactant in the biosource composite system can be selected according to actual needs, and the present invention does not impose any specific restrictions on this.

[0072] In the present invention, the T2 spectrum test is performed using a nuclear magnetic resonance instrument. The nuclear magnetic resonance T2 spectrum is essentially a signal of protons being magnetized in a magnetic field, with their transverse magnetization component varying with relaxation time. Because the proton polarization process in the core solid is relatively slow, the T2 relaxation time is difficult to capture and can be ignored. Therefore, the spectrum only represents the magnetization component signal of the fluid in the core pores. The relaxation time of the fluid is negatively correlated with the specific surface area and relaxation rate of the core pores. The longer the relaxation time, the smaller the specific surface area of ​​the core pores, and it can be roughly considered that the core pores are larger.

[0073] Therefore, the present invention proposes that the integrated area of ​​the T2 spectrum can, to a certain extent, reflect the relative content of the remaining oil reservoir in the core, the overall state of the pores, and the degree of crude oil displacement. The peak signal intensity of the T2 spectrum can, to a certain extent, reflect the relative content of the remaining oil reservoir in the core distributed among different pore sizes.

[0074] In some preferred embodiments, the setting parameters of the nuclear magnetic resonance instrument are: using a CPMG sequence, an echo time (TE) of 0.1-0.5 ms, a waiting time (TW) of 4000-12000 ms, and an echo number of about 100-5000.

[0075] Among them, the relaxation time reflects the size of the core pores to a certain extent. As the relaxation time increases, the nuclear magnetic resonance signals from small pores to large pores in the core are detected in sequence.

[0076] In some preferred embodiments, the relaxation time ranges from 0.001 to 10000 ms.

[0077] In the present invention, the micron core CT scanning is performed using a micro-nano dual-ray tube core CT scanning system.

[0078] In some preferred embodiments, the resolution of the micron core CT scan is 4 μm, and the sample diameter is 10 mm.

[0079] In some preferred embodiments, the characteristic parameters include area coefficient (S), overlap (C), and Euler number (E).

[0080] Where, area coefficient = surface area 3 / (36π×volume 2 ), overlap = contact area between oil and rock / surface area of ​​oil, Euler number = 1-connected body + closed loop body.

[0081] In some preferred embodiments, the occurrence states include cluster, sieve, drop, column, and sheet.

[0082] In some preferred embodiments, the occurrence state is defined by area coefficient, overlap degree and Euler number, and the specific definitions are shown in Table 2.

[0083] The permeability of the offshore oilfield core used in the present invention is one of low permeability core, medium permeability core, and high permeability core. The low permeability core has a permeability of less than 10 mD, the medium permeability core has a permeability of 10-100 mD, and the high permeability core has a permeability of greater than 100 mD.

[0084] The testing and evaluation method for the blockage removal and oil displacement capabilities of a biosource composite system of the present invention is mainly targeted at the biosource composite system, verifying the blockage removal and oil displacement effects of the system from multiple dimensions. The evaluation indicators are specific and quantifiable, and are intuitive, simple, high-resolution, and highly targeted. It can serve as an important reference for evaluating the adaptability of agents and improving the efficiency of oilfield development and extraction.

[0085] Example

[0086] The present invention is further illustrated by way of examples below, but the invention is not limited to the scope of the examples. The experimental methods in the following examples where specific conditions are not specified were based on conventional methods and conditions. The raw materials used in the following examples were all commercially available.

[0087] Example 1

[0088] S1 completely dried an offshore oilfield core with a permeability of 800-1000 mD. Crude oil was then injected into the core until the core oil saturation reached the initial formation oil saturation, simulating a real formation core. The crude oil-saturated core was then subjected to T2 mapping and micron core CT scanning to determine the initial core permeability, k0, and the integrated area of ​​the T2 curve, A0 (results shown in Table 1). The NMR instrument settings included a CPMG sequence, an echo time (TE) of 0.3 ms, a wait time (TW) of 6000 ms, and approximately 300 echoes. The micron core CT scan had a resolution of 4 μm and a sample diameter of 10 mm.

[0089] In step S2, formation water with a salinity of 8000 mg / L and a pH of 6.5 was used to reversely displace the core from the core column outlet at 30°C. When the water content at the inlet reached above 98% and the injection pressure increased significantly, the core was deemed to be contaminated and blocked by formation water, resulting in a formation water-contaminated core. The formation water-contaminated core was then subjected to a T2 mapping test and micron core CT scan to determine the permeability k1 at the time of core blockage. The integrated area of ​​the T2 curve was A1 (results shown in Table 1). The parameters for the T2 mapping test and micron core CT scan were the same as those in step S1.

[0090] In step S3, the biogenic composite system was injected forward into the formation water-contaminated core until the water content at the core outlet reached 98%, thereby obtaining a core after the injection of the biogenic composite system for blockage removal and oil displacement. T2 mapping and micron core CT scanning were then performed on the core after blockage removal and oil displacement by injection of the biogenic composite system to determine the post-blockage permeability k2, with the integrated area of ​​the T2 curve being A2 (results shown in Table 1). The biogenic composite system consisted of a bioacid, a rhamnolipid surfactant, and a lipopeptide surfactant, with a slug ratio of 1:1:1 and a concentration of 1500 mg / L. The parameters for the T2 mapping and micron core CT scanning were the same as those in step S1.

[0091] S4 calculates the damage coefficient and unblocking rate of the core during and after blockage according to the unblocking rate and damage coefficient formula. The calculation results are shown in Table 1. The calculation formula is as follows:

[0092] Unblocking rate Wherein t is a correction factor. In this embodiment, the value of t is 3.

[0093] Damage coefficient

[0094] S5: A second injection of formation water into the core after the injection of the biogenic composite system to remove blockage and flood oil is performed forward to a water content of 98% or greater, thereby obtaining a core after secondary water flooding. The core after secondary water flooding is then subjected to a T2 mapping test and a micron core CT scan. The parameters for the T2 mapping test and the micron core CT scan are the same as those for step S1.

[0095] S6 uses relaxation time as the horizontal axis and nuclear magnetic resonance signal intensity as the vertical axis to draw a dot-line graph of the T2 spectrum test results to obtain the integral area and peak signal intensity of the T2 spectrum.

[0096] S7 Based on the results of micron core CT scanning, the characteristic parameters area coefficient (S), coincidence (C), and Euler number (E) are calculated. The results are shown in Table 2; the occurrence state of residual oil is defined by the characteristic parameters and the results are visualized.

[0097] Table 1

[0098]

[0099] Among them, the T2 spectrum of crude oil saturated core, such as Figure 2 As shown; T2 spectrum of formation water contaminated core, such as Figure 3 As shown in the figure; T2 spectrum of the core after injecting the biogenic composite system to deblock and flood the oil, as shown in the figure Figure 4 As shown; T2 spectrum of the core after secondary water flooding, as shown Figure 5 shown.

[0100] Figure 2The peak of the unblocked core is around 300ms, indicating that there are a large number of macropores, and the T2 map area is 167068.2. Figure 3 After the plugging, two peaks appeared in the core. The left peak was around 1ms, indicating that the number of small pores increased significantly; the right peak was around 100ms, which was consistent with the Figure 2 Compared with the original core, the right peak obviously moves toward the direction of decreasing relaxation time, and the T2 spectrum area is 110416.7. Figure 3 Compared with the core map after plugging, Figure 4 The middle left peak still exists, but both the left and right peaks shift toward the direction of increasing relaxation time, indicating that the number of macropores increases and the pore diameter increases. The integrated area of ​​the T2 spectrum is 146995.1; Figure 5 The right peak shifts slightly toward the direction of increasing relaxation time, and the integral area of ​​the T2 spectrum is 153089.6, which is consistent with Figure 4 No significant difference, but Figure 3 The above test results show that the biogenic composite system has a good deblocking effect. The deblocking ability of the biogenic composite system is consistent with the changes in the core T2 spectrum during the deblocking experiment. Therefore, the one-dimensional effect evaluation model of the biogenic composite system based on the nuclear magnetic resonance T2 spectrum can serve as an important basis for analyzing reservoir status and blockage conditions and evaluating the deblocking ability of the system.

[0101] Figure 6 The pressure and recovery curves during the displacement process show a significant decrease in displacement pressure after injection of the biogenic composite system, demonstrating its macroscopic effectiveness in removing plugs from the core. The recovery curve shows the extent of crude oil recovery. After the biogenic composite system was completed, the recovery increased from 60% at the end of water flooding to 78.42%.

[0102] Figure 7 The following are core T2 spectra measured at different times after injection of the biogenic composite system. Within 24 hours of biogenic composite system injection, the pore fluid signal intensity decreases significantly and the peak relaxation time shortens, demonstrating the biogenic composite system's excellent plugging removal and oil washing effectiveness. The integrated area of ​​the T2 spectra continues to decrease from 24 to 96 hours after injection, indicating the biogenic composite system's sustained effect.

[0103] The calculation results of characteristic parameters are shown in Table 2. The core of the oil displacement experiment of 1500 mg / L bio-source composite system was scanned by micron CT. The results are as follows: Figure 8 As shown in the figure; the bar chart of the residual oil distribution in the core after the displacement experiment is as follows: Figure 9 shown.

[0104] Table 2

[0105] Existence state Number of pore throats occupied Area coefficient (S) Coincidence (C) Euler number (E) Flake 8％ 2.9 0.35 0.15 Drop-shaped 2％ 1.3 0 0.3 Columnar 6％ 2.1 0.48 0.05 sieve-like 18％ 2.4 0.47 -0.5 clustered 65％ 2.2 0.43 -2.2

[0106] When the concentration of the biogenic composite system is 1500 mg / L, the distribution morphology of residual oil in water flooding is divided into clustered residual oil, sieve-like residual oil, columnar residual oil, drop-like residual oil and sheet-like residual oil. As the water flooding ends and the oil is converted to the biogenic composite system flooding, the proportion of clustered continuous phase continues to decrease from 75% to 65%. Compared with water flooding, the recovery rate increases by 13.3%.

[0107] Example 2

[0108] The displacement experiment, T2 map test, and CT scanning process of Example 2 are exactly the same as those of Example 1, except that the high permeability core of 800-1000 mD is replaced with the medium permeability core of 50-100 mD, and the biogenic composite system is changed from 1500 mg / L to 2000 mg / L.

[0109] T2 spectrum test results are as follows Figure 10 As shown, the biogenic composite system has the ability to reduce injection pressure and improve oil recovery. The state of crude oil in pores can affect the pore response at different relaxation times. In low-permeability cores, the integrated area of ​​the T2 spectrum of the bionanodisplacement agent system decreases in the small pore distribution region, indicating that the residual oil in the low-permeability reservoir after water displacement is mainly distributed in small pores and the biogenic composite system is able to displace this oil. In medium-permeability cores, crude oil is mainly stored in the large pore spaces of the reservoir. After injection of the biogenic composite system, the integrated area of ​​the T2 spectrum decreases, and the core recovery rate increases by 20.06%. These test results show that the ability of the biogenic composite system to improve oil recovery is consistent with the changes in the core T2 spectrum during the oil displacement experiment. Therefore, the one-dimensional effect evaluation model of the biogenic composite system based on the nuclear magnetic resonance T2 spectrum can serve as an important basis for analyzing reservoir conditions and evaluating the oil displacement capacity of the system.

[0110] The definition of crude oil occurrence state based on characteristic parameters is shown in Table 3. Micron CT scanning was performed on the core of the oil displacement experiment with 2000 mg / L bio-source composite system. The results are as follows Figure 11 As shown in the figure; the bar chart of the residual oil distribution in the core after the displacement experiment is as follows: Figure 12 shown.

[0111] Table 3

[0112] Existence state Number of pore throats occupied Area coefficient (S) Coincidence (C) Euler number (E) Flake 6％ 2.8 0.3 0.2 Drop-shaped 4％ 1.2 0 0.1 Columnar 9％ 2.1 0.48 0.05 sieve-like 28％ 2.5 0.45 -0.5 clustered 49％ 2.2 0.46 -2.5

[0113] At a concentration of 2000 mg / L, the residual oil distribution after water flooding was characterized by clusters, sieves, columns, drops, and flakes. As water flooding transitioned to the biomass-based system, the proportion of the continuous cluster phase decreased from 71% to 49%. The biomass-based system exhibited excellent crude oil emulsification and dispersion capabilities. At a concentration of 2000 mg / L, the residual oil saturation after flooding reached 39.8%, increasing the recovery factor by 10.5% compared to water flooding.

[0114] The above test results demonstrate that micron CT scans can quantitatively analyze the relative content and distribution of residual oil in reservoirs, contributing to targeted analysis and development of oil production process plans and improving crude oil recovery. After the biogenic composite system is injected into the core, it changes the wettability of the rock surface and reduces the structural separation pressure between the rock and the crude oil. This reservoir transformation effect corresponds to a change in the distribution of residual oil, and the increase in crude oil recovery corresponds to a decrease in the relative content of residual oil in different forms. Therefore, the three-dimensional evaluation model of the biogenic composite system based on micron core CT scanning technology can serve as an important basis for studying reservoir geological characteristics and fluid seepage characteristics, analyzing and simulating reservoir distribution, and evaluating the oil displacement capacity of the biogenic composite system.

[0115] The present invention has been disclosed above with reference to preferred embodiments. However, those skilled in the art will appreciate that these embodiments are intended only to illustrate the present invention and are not to be construed as limiting the scope of the present invention. It should be noted that any equivalent variations and substitutions to these embodiments are to be considered encompassed within the scope of the claims of the present invention. Therefore, the scope of protection of the present invention shall be subject to the scope defined in the claims.

Claims

1. A method for testing and evaluating the plugging removal and oil displacement capabilities of a bio-source composite system, characterized in that: include: S1: Dry the offshore oilfield core and then flood it with crude oil until it is saturated to obtain the crude oil-saturated core. Perform T2 mapping test and micron core CT scanning on the crude oil-saturated core to measure the initial permeability k0 of the core and the integral area A0 of the T2 curve; S2 uses formation water to reversely displace the crude oil saturated core to cause core blockage, obtaining a formation water contaminated core, performing a T2 map test and a micron core CT scan on the formation water contaminated core, and measuring the permeability k1 and the integral area A1 of the T2 curve at the time of blockage; S3: forwardly injecting the biogenic composite system into the formation water-contaminated core to conduct a plugging and oil displacement experiment, obtaining a core after plugging and oil displacement by the biogenic composite system, performing a T2 map test and a micron core CT scan on the core after plugging and oil displacement by the biogenic composite system; and measuring the permeability k2 and the integral area A2 of the T2 curve after plugging removal; S4 calculates the damage coefficient and unblocking rate of the core during and after blockage according to the unblocking rate and damage coefficient formula; S5: injecting formation water into the core after the injection of the biogenic composite system to remove plugging and flood the oil, until the water content reaches 98% or more, to obtain a core after secondary water flooding, and performing T2 mapping test and micron core CT scanning on the core after secondary water flooding; S6 uses relaxation time as the horizontal axis and nuclear magnetic resonance signal intensity as the vertical axis to draw a dot-line graph of the T2 spectrum test results to obtain the integral area and peak signal intensity of the T2 spectrum; S7 calculates characteristic parameters based on the results of the micron core CT scan, defines the occurrence state of the residual oil through the characteristic parameters, and obtains an image result.

2. The test evaluation method according to claim 1, wherein: The formation water contains 2.8-3.5 mg / L of oil, 0.2-0.5 mg / L of iron ions, and 20-25 num / mL of sulfate-reducing bacteria.

3. The test evaluation method according to claim 1, wherein: In step S2, the criteria for determining whether the core is blocked are: the water content at the core inlet reaches above 98% and the injection pressure increases significantly.

4. The test and evaluation method according to claim 1, wherein: The biosource composite system is a compound of bioacid, rhamnolipid surfactant and lipopeptide surfactant, with a slug ratio of 1:1:2 to 2:1:1 and a concentration of 500-2000 mg / L.

5. The test evaluation method according to claim 1, characterized in that: The T2 spectrum test is performed using a nuclear magnetic resonance instrument, and the micron core CT scan is performed using a micro-nano dual-ray tube core CT scanning system.

6. The test evaluation method according to claim 5, characterized in that: The setting parameters of the nuclear magnetic resonance instrument are: using CPMG sequence, echo time TE is 0.1-0.5ms, waiting time TW is 4000-12000ms, and the number of echoes is 100-5000.

7. The test evaluation method according to claim 1, characterized in that: The characteristic parameters include area coefficient, overlap degree, and Euler number.

8. The test evaluation method according to claim 1, wherein: The occurrence states include cluster, sieve, drop, column, and sheet.

9. The test and evaluation method according to claim 1, characterized in that: The resolution of the micron core CT scan is 4 μm, and the sample diameter is 10 mm.

10. The test evaluation method according to claim 1, characterized in that: The offshore oilfield core is one of a low permeability core, a medium permeability core, and a high permeability core; wherein the permeability of the low permeability core is less than 10 mD, the permeability of the medium permeability core is 10-100 mD, and the permeability of the high permeability core is greater than 100 mD.

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