A method for measuring porosity and connectivity of rock fragments based on magnetic nanoparticles

Abstract

This invention provides a method for measuring the porosity and connectivity of rock cuttings based on magnetic nanoparticles, comprising: Step 1) saturating the rock cuttings with a polymer-coated magnetic nanoparticle solution to fill the interconnected pores of the rock cuttings with the magnetic nanoparticle solution; Step 2) placing the saturated rock cuttings in a draining agent and centrifuging to remove the magnetic nanoparticle solution from the surface of the rock cuttings, thus obtaining a sample to be tested; Step 3) obtaining the draining agent parameters and rock cutting property parameters of the sample to be tested using nuclear magnetic resonance (NMR), and calculating the porosity and connectivity of the rock cuttings based on the draining agent parameters and rock cutting property parameters. Compared with existing rock cutting NMR measurements that can only obtain porosity, the method provided by this invention can simultaneously obtain accurate porosity and connectivity, thereby enabling accurate calculation of the permeability of the rock cuttings. This overcomes the limitation of traditional NMR relying solely on empirical T2 cutoff values ​​to determine pore connectivity.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas exploration, and in particular relates to a method for measuring the porosity and connectivity of rock fragments based on magnetic nanoparticles. Background Art

[0002] Pore ​​space is where oil and gas resources are stored, so the understanding of pore space is one of the most concerned issues in oil and gas exploration and development. The characterization of pore space is mainly described by two parameters. The first is porosity, which is the ratio of the volume of pore space to the total volume of the rock sample, reflecting the size of the pore space, so to a certain extent, porosity can represent the storage capacity of oil and gas; the second is permeability, which refers to the ability of fluid to pass under a certain pressure difference, which is usually positively correlated with the connectivity of the pores, so to a certain extent, permeability can reflect the migration capacity of oil and gas, which is closely related to production and exploitation.

[0003] At present, the porosity and connectivity are mainly obtained by logging and core testing using downhole geophysical methods. Core refers to the columnar rock blocks taken up by a special core barrel during the drilling process. Generally, it can retain the stress state of the underground to a certain extent, so the formation physical information contained therein has high reliability. However, core has a high sampling cost and a long sampling time, resulting in an increase in its sampling cost with the increase of sampling depth. Moreover, it is difficult to obtain continuous samples by coring, and generally only the target layer is taken.

[0004] Cuttings refer to the rock blocks broken by the drill bit during the drilling process. They return to the surface with the circulation of the drilling fluid and can be cleaned and collected in the surface vibrating screen for cuttings logging analysis. Their diameter is usually between submicron and several millimeters. The in-situ depth of the cuttings can be obtained by calculating the delay time by the flow rate of the drilling fluid. The movement of cuttings in wells with large angles and large displacements can also be predicted in a variety of ways. Compared with drilling cores, cuttings can be obtained at the drilling site almost in real time with drilling, which has a high timeliness; they can also be collected from the beginning of drilling, so that continuous formation information can be obtained; it is important that the sampling cost of cuttings is extremely low compared to cores, and they are additional products produced during the drilling process. It is very cost-effective to obtain relevant rock physical parameters from cuttings measurement. In addition, cuttings are an important supplement when coring is inconvenient or impossible. In the past, cuttings were often treated as one of the drilling wastes or used for other purposes because of the organic and inorganic pollution they produced. Therefore, the industry has long been interested in using rock cuttings to obtain some formation information in near real time at the drilling site.

[0005] However, for a long time, the porosity analysis of rock cuttings at the drilling site has been in a qualitative and semi-quantitative state. This is mainly because the rock cuttings are small in size and irregular in shape, and it is difficult to obtain an accurate rock cutting volume. Therefore, the methods commonly used for laboratory testing and analysis of cores are not suitable for studying rock cuttings, especially some quantitative studies that are sensitive to shape regularity. Low-field nuclear magnetic resonance technology used for rock sample analysis has been developed for decades, but it has not yet been successfully commercially applied at the drilling site. The biggest problem currently recognized is that the error in the sample pre-processing workflow leads to low reliability of the total porosity obtained from the final rock cuttings. The main error comes from the irregular shape of the sample, which may result in liquid in the gaps between particles or a layer of liquid film attached to the surface of the particles. Therefore, the porosity measured by nuclear magnetic resonance is usually larger, and the error increases as the size of the rock cuttings decreases.

[0006] Siddiqui et al. (2005) used polytetrafluoroethylene tape to wrap individual artificial cuttings treated by the wet towel (API) method to prevent evaporation during the measurement process, proving that there was excess attached water outside the cuttings particles. However, the wet paper towel wiping method recommended by API is only applicable to single larger cuttings, generally larger than 4 mm. The wet towel (API) method, porous plate (static) and centrifugation on porous plate were compared with polytetrafluoroethylene. It was found that the porosity of the cuttings treated by the porous plate plus centrifugation method was the closest to that of the core, but it was too time-consuming. Other methods that worked well include shaking the cuttings in a culture dish and manually aspirating the liquid until the cuttings no longer stick together, but these methods are laborious and inefficient overall.

[0007] Yao Yanbin et al. (CN108442927A, 2018) invented a perfluorocarbon solution drainage method to measure the total volume of rock cuttings. This method can eliminate the attached liquid outside the rock cuttings, but this method is only applicable to rock cuttings larger than 3 mm. For rock cuttings with lower particle size, it cannot remove the attached liquid outside the rock cuttings and the fluid in the pore space. Schlumberger's Mitchell et al. (2019) and patents can also add a low-speed centrifugation step to get rid of the external error liquid when using the fluorinated liquid drainage method to measure the total volume: first add the fluorinated liquid in the effective detection area of ​​the nuclear magnetic resonance signal to obtain the maximum fluorinated liquid volume, then add wet rock cuttings and centrifuge. After centrifugation, the blue part representing the error liquid outside the rock cuttings floats beyond the effective detection area of ​​the signal. At this time, the 19F and 1H dual-frequency probes are used to perform nuclear magnetic resonance to measure the changes in 19F and 1H signals to calculate the porosity. This method can obtain results that are consistent with the core for some rock cuttings larger than 1 mm, but it is still questionable whether the liquid film on the surface of the particles is removed by centrifugation. In addition, it also faces problems such as timeliness and applicability.

[0008] In the core connectivity evaluation, predecessors used hot melt method to synthesize iron oxide nanoparticles with negative charge on the surface and diameter of about 60-70nm as contrast agents, formulated them into magnetic fluids, and injected them into the core pores. It can be found that the magnetic fluid group significantly reduced the T2 relaxation time compared with the deionized water group, that is, the T2 relaxation time will change where superparamagnetic iron oxide nanoparticles (SPIONs) exist, and superparamagnetic iron oxide nanoparticles (SPIONs) migrate with the fluid, so it can be considered that some pores with changed T2 relaxation time are connected pores. The pores that have not changed are non-connected because magnetic particles cannot migrate into them. However, this method cannot be applied to the connectivity evaluation of cuttings at present. The main difficulties are: (1) The magnetic nanoparticles used in the past are often difficult to achieve high dispersion and stability. They are extremely unstable when encountering materials such as rock cuttings with large specific surface area and small particle size. They are easy to adhere to the surface of the rock cuttings and can only enter the pores of the rock cuttings in small amounts. (2) The porosity study of rock cuttings often requires the use of drainage methods and centrifugation to remove external error fluids. It is currently unclear whether superparamagnetic iron oxide nanoparticles (SPIONs) affect drainage. Summary of the invention

[0009] In view of the lack of mature technology that can simultaneously measure the porosity and connectivity of rock cuttings, the present invention provides a method for studying the porosity and connectivity of rock cuttings based on superparamagnetic nanomaterials. The rock cuttings samples are processed by using a highly stable and monodisperse magnetic nanoparticle, and then the rock cuttings of different particle sizes are drained under appropriate centrifugal conditions. The porosity and connectivity of the rock cuttings collected by on-site logging are further measured using nuclear magnetic resonance methods.

[0010] Specifically, in order to solve the above technical problems, the present invention provides the following technical solutions:

[0011] On the one hand, the present application provides a method for measuring the porosity and connectivity of rock fragments based on magnetic nanoparticles, comprising:

[0012] Step 1), saturating the rock cuttings with a polymer-coated magnetic nanoparticle solution so that the interconnected pores of the rock cuttings are filled with the magnetic nanoparticle solution;

[0013] Step 2), placing the saturated rock cuttings in a drainage agent, and removing the magnetic nanoparticle solution on the surface of the rock cuttings by centrifugation to obtain a sample to be tested;

[0014] Step 3), using nuclear magnetic resonance to obtain the drainage agent parameters and rock cuttings attribute parameters of the sample to be tested, and calculating the porosity and connectivity of the rock cuttings according to the drainage agent parameters and rock cuttings attribute parameters.

[0015] In one embodiment, the length of the rock cuttings is greater than 1 mm;

[0016] Preferably, the rock cuttings are sandstones with a length of 1-4 mm and / or 4-20 mm.

[0017] Optionally, the rock fragments may be sandstone, carbonate, basalt, or shale.

[0018] In one embodiment, the polymer is a copolymer obtained by copolymerizing an unsaturated monomer containing a sulfonic acid group and an unsaturated monomer containing a carboxyl group, and a salt thereof;

[0019] The unsaturated monomer containing sulfonic acid group is selected from one or more of styrene sulfonate, methyl propylene sulfonate, propylene sulfonate, vinyl sulfonate, butylene sulfonate and 2-acrylamide-2-methylpropane sulfonate;

[0020] The unsaturated monomer containing a carboxyl group is selected from one or more of maleic acid, acrylic acid, methacrylic acid, crotonic acid, 2-ethylacrylic acid, 2-pentenoic acid, 4-pentene, 2-octenoic acid, 3-vinylbenzoic acid, 4-vinylbenzoic acid, 10-undecenoic acid, erucic acid, brassinoic acid, palmitoleic acid, oleic acid, nervonic acid, linolenic acid, ricinoleic acid, 4-oxo-4-phenyl-2-butenoic acid, 2-bromoacrylic acid, 2-bromomethyl-acrylic acid, sorbic acid, itaconic acid, citraconic acid, fumaric acid, methylfumaric acid, mesaconic acid, 2-methylsuccinic acid, and mucofuric acid.

[0021] Preferably, the molecular weight of the polymer is 1 to 3 million, preferably 1.5 to 2 million.

[0022] Preferably, the number of repeating units of the polymer is 50-200, preferably 90-120.

[0023] Preferably, the salt of the polymer is selected from one or more of potassium salt, sodium salt and ammonium salt.

[0024] Preferably, the polymer is a sodium salt of poly(4-styrenesulfonic acid-maleic acid copolymer), wherein the ratio of the sulfonate to the carboxyl group in the polymer is 1:2, and the molecular weight is 1.5-2 million.

[0025] In one embodiment, the chemical structure of the magnetic nanoparticles is Fe (3-x) M x O4(0≤x≤3) or Fe (2-x) M x O3 (0≤x≤2), wherein M is selected from one of Mn, Cu, Zn, Ni, Gd or Co.

[0026] Preferably, the magnetic nanoparticles are Fe3O4.

[0027] Preferably, the particle size of the magnetic nanoparticles is 5-150 nm, preferably 10-20 nm.

[0028] In one embodiment, the polymer-coated magnetic nanoparticles are prepared by the following method:

[0029] Step a), allowing the polymer to self-assemble to form a cage structure;

[0030] Step b), adding metal salt and oxidant to grow into nanoparticle crystals in the cavity of the cage structure formed by the polymer;

[0031] Step c), after centrifugation, the synthesized magnetic nanoparticles are concentrated using a protein enrichment tube.

[0032] Optionally, a purification step is also performed in step b).

[0033] In one embodiment, the liquid-repellent agent is a fluorinated hydrophobic agent with a density of >1 g / cm 3 .

[0034] Preferably, the fluorine-containing hydrophobic agent is selected from one or more of fluorine oil, perfluorinated trialkylamine, and perfluoropolyether.

[0035] Preferably, the drainage agent is FC-40 fluorinated liquid with a density of 1.85 g / cm 3 .

[0036] In one embodiment, the drainage agent parameter is selected from at least one of the position, volume and content of the drainage agent; and / or,

[0037] The rock fragment attribute parameters include the volume of fluid in the rock fragment pores and the total volume of the rock fragments.

[0038] In one embodiment, the method of saturation treatment in step 1) includes a vacuum pressure saturation method, specifically: placing the rock cuttings in a vacuum device and evacuating the vacuum to -0.1MPa, then adding the polymer-coated magnetic nanoparticle solution to soak under vacuum, and applying an external pressure of 210mL / 50MPa for 12 hours.

[0039] In one embodiment, the centrifugation step in step 2) comprises: placing the saturated cuttings in a drainage agent and centrifuging at 1000-2000 r / min for 8-15 min.

[0040] Preferably, the centrifugation step specifically comprises: adding the rock chips saturated with the magnetic nanoparticle solution into a test tube containing 8 ml of a drainage agent, wherein the height of the drainage agent rises by about 0.5 cm after the rock chips are added. Then the test tube is placed in a centrifuge, and the rock chips with a particle size of 1-4 mm are centrifuged at a speed of 1900 rpm for 10 minutes; and the rock chips with a particle size of 4-20 mm are centrifuged at a speed of 1100 rpm for 10 minutes.

[0041] In one embodiment, the step 3) specifically includes: using nuclear magnetic resonance to obtain the fluid volume Vp in the pores and the total volume Vb of the cuttings, and the cuttings porosity φ = Vp / Vb×100%; using nuclear magnetic resonance to measure its T2 spectrum, and evaluating the pore connectivity based on the T2 spectrum drift caused by the magnetic particles.

[0042] Optionally, the nuclear magnetic resonance includes processing using a nuclear magnetic resonance coil, wherein the nuclear magnetic resonance coil includes a fluorine probe and a hydrogen probe, wherein the fluorine probe can detect a certain volume of drainage agent signal, and wherein the hydrogen probe detects the content of the magnetic particle solution in the pores.

[0043] Optionally, the porosity is obtained by obtaining fluorine or hydrogen signals in the nuclear magnetic resonance instrument to invert the porosity of the rock cuttings. Specifically, a drainage agent that exceeds the detection range of the nuclear magnetic resonance instrument is added to the centrifuge tube. At this time, the fluorine coil that specifically detects the 19F signal is replaced to detect the maximum volume of the fluorinated liquid. Then the wet rock cuttings are added thereto, and a set of centrifugal rates are set according to the calculated critical centrifugal rate for centrifugation. After centrifugation, the magnetic nanoparticle liquid attached to the surface of the rock cuttings and the magnetic nanoparticle liquid in the gaps between the particles will float above, exceeding the signal detection area. At this time, the fluid volume obtained by detecting the 1H signal comes from the pores, and the volume inverted by the hydrogen signal represents the volume of the fluid in the pores Vp. At this time, the difference between the volume inverted by the fluorine signal and the maximum volume is the total volume of the rock cuttings Vb. Calculate the rock cuttings nuclear magnetic resonance porosity φ = Vp / Vb×100%.

[0044] Among them, the connectivity rate is achieved by setting up control samples of saturated magnetic nanoparticle solution and saturated saline respectively, measuring their T2 spectra by nuclear magnetic resonance, and evaluating the pore connectivity based on the T2 spectrum drift caused by the magnetic particles.

[0045] The beneficial effects of this application include at least:

[0046] 1. The rock cuttings porosity measurement method provided in the present application optimizes the pre-treatment steps for the rock cuttings to be measured, wherein the use of specific polymers to coat magnetic nanoparticles can significantly improve the dispersibility and stability of the magnetic nanoparticle solution, thereby enabling the magnetic nanoparticles to completely enter the pores of the rock cuttings, thereby improving the accuracy of parameter acquisition and result calculation; at the same time, experiments have shown that superparamagnetic iron oxide nanoparticles do not affect drainage and are suitable for measuring the porosity of rock cuttings;

[0047] 2. The method provided by the present application is simple to operate, has good repeatability, and high calculation accuracy. Compared with the existing rock cuttings NMR measurement that can only obtain porosity, the method provided by the present invention can simultaneously obtain accurate porosity and connectivity, and thus can accurately calculate the permeability of the rock cuttings. This overcomes the limitation of traditional NMR that only relies on the empirical T2 cutoff value to determine pore connectivity. BRIEF DESCRIPTION OF THE DRAWINGS

[0048] The drawings described herein are used to provide a further understanding of the present application and constitute a part of the present application. The illustrative embodiments of the present application and their descriptions are used to explain the present application and do not constitute an improper limitation on the present application. In the drawings:

[0049] Figure 1 A schematic diagram of an implementation of a rock cuttings porosity and connectivity testing procedure based on magnetic nanoparticles;

[0050] Figure 2 Schematic diagram of the use of monodisperse polymer-coated magnetic nanoparticles to verify and assess the porosity and connectivity of rock cuttings;

[0051] Figure 3 Schematic diagram of the geographical location of Dongtang 1 well for sample collection and photos of cores and cuttings used to test porosity and connectivity;

[0052] Figure 4 Schematic diagram of the relationship between porosity and centrifugation rate for cuttings of different particle sizes (1-4 mm and >4 mm) saturated with brine and magnetic nanoparticle solution (magnetic fluid);

[0053] Figure 5 Schematic diagram of different critical centrifugal velocities for 1-4 mm sandstone cuttings using magnetic fluid saturation and brine saturation;

[0054] Figure 6 Schematic diagram of different critical centrifugal velocities for sandstone cuttings larger than 4 mm using magnetic fluid saturation and brine saturation;

[0055] Figure 7 The T2 spectra of magnetic fluid saturated and saline saturated were measured using nuclear magnetic resonance for 1-4 mm and >4 mm. DETAILED DESCRIPTION

[0056] In order to more clearly explain the overall concept of the present application, the following is described in detail in conjunction with the accompanying drawings of the specification by way of embodiment. In the following description, a large number of specific details are provided to provide a more thorough understanding of the present invention. However, it is obvious to those skilled in the art that the present invention can be implemented without one or more of these details. In other examples, in order to avoid confusion with the present invention, some technical features well known in the art are not described.

[0057] Unless otherwise specified, the materials, reagents, instruments and methods used in the following examples are conventional materials, reagents, instruments and methods in the art and can be obtained through commercial channels.

[0058] In the following embodiments, the upper limit of the length of the rock cuttings with a length greater than 4 mm is less than or equal to 20 mm.

[0059] Example 1: Evaluation of the Porosity of Berea Sandstone Core Saturated with Magnetic Nanoparticle Solution (Magnetic Fluid)

[0060] The long Berea sandstone core purchased from Beijing Huasheng Haitian Technology Development Co., Ltd. was cut into 10 small cores as reference samples. The specific method is as follows: the 30 cm long Berea sandstone core was divided equally and cut into ten core plug samples with a length of about 3 cm and a diameter of 2.5 cm. The top and bottom surfaces of the cylinders of the small cores were polished and flattened for accurate geometric volume calculation.

[0061] The small cores were dried at 90°C for about 12 hours to remove any moisture that may exist in the pores. They were numbered Bailey samples 1 to 10. The porosity of the 10 dried core columns of about 3 cm × 2.5 cm was tested by the helium method, and the permeability was measured by dry air. The results are shown in Table 1.

[0062] Table 1 Porosity and permeability of Berea sandstone gas

[0063] serial number Porosity (pu) Permeability (mD) Bailey 1 30.70 850.973 Bailey 2 29.34 918.368 Bailey 3 30.81 872.936 Bailey 4 30.77 1036.041 Bailey 5 30.21 854.857 Bailey 6 30.22 741.408 Bailey 7 31.12 846.814 Bailey 8 29.84 700.910 Bailey 9 30.58 732.958 Bailey 10 31.30 982.107

[0064] It can be seen from the gas test results in Table 1 that the cores in this group have good homogeneity in terms of porosity and permeability parameters. Therefore, preferably, samples of Bailey 1, Bailey 3, and Bailey 6 are saturated with brine, and samples of Bailey 5, Bailey 7, and Bailey 9 are saturated with 50 ppm magnetic fluid for nuclear magnetic resonance porosity testing.

[0065] The preparation method of the saturated 50ppm magnetic fluid solution is as follows:

[0066] (i) Allowing the polymer to self-assemble into a cage-like structure. In order to obtain a polymer capable of self-assembly, 1 g of polystyrene sulfonate sodium-maleic acid copolymer (PSS-co-MA, molecular weight of approximately 20,000) was dissolved in 1 L of 0.1 M NaCl solution until the final concentration was 1 mg / mL, the pH value was adjusted to 8.5 with 0.5 M NaOH, and the temperature was controlled at 55° C. by an electric heating mantle for 10 min. In this way, the polymer began to self-assemble into a cage-like structure (each cage contained 96 monomers and had a molecular weight of approximately 1,920,000) under the conditions of salt ion concentration, pH value and temperature.

[0067] (ii) Add metal salts and oxidants to grow nanoparticle crystals in the cavity of the cage structure formed by the polymer. All solutions are deoxygenated and placed in an anaerobic chamber. Use anaerobic deionized water to prepare ammonium ferrous sulfate (100mM) and hydrogen peroxide (33.33mM) solutions respectively. According to the molar number of polymer cages and the molar concentration of ammonium ferrous sulfate, it is calculated that ammonium ferrous sulfate (100mM) and hydrogen peroxide (33.34mM) solutions are added at a rate of 80 iron atoms per minute per cage. In theory, about 60,000 iron atoms are added to each cage to form polymer-coated iron oxide (magnetite, Fe3O4) nanoparticles.

[0068] (iii) Purification to obtain monodisperse polymer-coated magnetic nanoparticles. To ensure that each iron oxide nanoparticle is completely encapsulated by the polymer cage, the magnetic nanoparticles that are easy to assemble or difficult to encapsulate are removed under a centrifugal force of 10000 g, and the synthesized magnetic nanoparticles are concentrated using a 100 kD protein enrichment tube (amicon Ultra-12100 kda) to remove free polymers and store them at 30 mg / mL.

[0069] (iv) The iron concentration was determined by the philogenin method, and the polymer-coated magnetic nanoparticles were diluted with water to a 50 ppm iron concentration for later use.

[0070] The specific test method is as follows:

[0071] First, the two groups of cores were vacuum-pressurized and saturated. This method is a common way to saturate rock samples in nuclear magnetic resonance testing in recent years. The saturation device used is the ZYB-Ⅱ vacuum-pressurized saturation device produced by Nantong Huaxing Instrument Co., Ltd. It mainly uses a vacuum device to vacuum the core first, and then add a certain specification of liquid to soak it under vacuum to allow the core to fully absorb. In order to speed up the absorption rate, a certain external pressure is applied to the core and liquid during the soaking process. The external pressure can be determined according to the looseness and density of the core. Its pressure resistance is 40Mpa, the vacuum pumping rate is 2L / min, and the manual pressure pump parameter is 210mL / 50MPa. The two groups of cores after saturation were immediately wrapped with plastic wrap to prevent the evaporation of the fluid inside the pores, waiting for further nuclear magnetic resonance testing.

[0072] The low-field NMR instrument selected is MrroMR20-025V NMR analyzer from Suzhou Newmai Analytical Instrument Co., Ltd. The main frequency of the equipment is 23MHz, the permanent magnet magnetic field strength is 0.5±0.08T, the magnet temperature is nonlinear precision constant temperature control, and the range can be adjusted within the range of 25℃-30℃, the probe coil diameter is 25mm, the maximum number of CPMG echoes is 18,000, and the shortest echo time is less than 60 microseconds.

[0073] To test the core NMR porosity of samples that have been saturated with brine and magnetic fluid, calibration must be performed first to establish the calibration line. Measure a set of known volumes of saturated liquid to obtain its signal, obtain the relationship between the volume of saturated liquid and the NMR signal, and calculate the corresponding relationship between the unit volume of saturated liquid sample and the NMR signal. Here, saturated brine and 50ppm magnetic fluid must be calibrated separately. The calibration results are as follows:

[0074] (i) The trend line formula for saturated brine calibration is: y = 39302x + 1599.9, R 2 =0.9998.

[0075] (ii) The trend line formula for 50ppm magnetic fluid calibration is: y = 36503x + 1749.9, R 2 =0.998.

[0076] (iii) The calculated hydrogen signal amount per unit volume of saturated salt water is 40901.9; the hydrogen signal amount per unit volume of 50 ppm magnetic fluid is 38252.9.

[0077] After calibration, core NMR test is performed:

[0078] The surface of the saturated core was lightly wiped with a paper towel to remove the obvious attached fluid, and then placed in the nuclear magnetic resonance instrument probe for measurement to obtain the T2 relaxation time spectrum of the fluid in the pores of the rock sample, and the signal was obtained by integrating the spectrum T2 curve. Since the core has a regular shape, the total volume of the core can be obtained by using a vernier caliper through the geometric method; for saturated rock samples, the fluid volume corresponding to the total signal obtained by the nuclear magnetic resonance hydrogen signal test is the pore volume in the core, and the porosity of the sample can be obtained by comparing the pore volume with the total volume. The results are shown in Table 2. It can be seen from Table 2 that the core saturated with magnetic fluid can obtain the same nuclear magnetic resonance porosity as the core saturated with brine.

[0079] Table 2 NMR porosity of Berea sandstone

[0080]

[0081] Example 2: Evaluation of the ability of artificial cores saturated with magnetic nanoparticle solutions (magnetic fluids) to obtain accurate porosity

[0082] Since the artificial sandstone cores are from the same batch and produced by the same process, they have good homogeneity. Therefore, according to the steps of Example 1, No. 1-3 saturated with 50ppm and No. 4-6 saturated with brine are selected. The nuclear magnetic resonance porosity test results are shown in Table 3. From the results in Table 3, it can be seen that the artificial cores saturated with magnetic fluid can obtain the same nuclear magnetic resonance porosity as the artificial cores saturated with brine.

[0083] Table 3 Nuclear magnetic resonance porosity of artificial sandstone core

[0084]

[0085] Example 3: Evaluation of the ability of magnetic nanoparticle solution (magnetic fluid) to obtain accurate porosity of natural sandstone core saturated with natural sandstone core

[0086] The samples were collected from the third section of the Luzhai Formation of the Lower Carboniferous in Dongtang 1 Well. At a depth of 850-950 meters, there is a thick gray quartz sandstone, which is interspersed with a small amount of gray-black thin mudstone. A section with good homogeneity was selected, and 30 core plugs with a diameter of 2.5 cm were drilled between 912.1 meters and 915.0 meters. The two sides of the cylinder were polished and dried at 90℃ for about 12 hours to remove the water that may exist in the pores. They are numbered Dongtang 1 to 30 respectively.

[0087] The helium method and air permeability method were also used to test 30 natural sandstone cores from Dongtang 1 Well, and the gas porosity and permeability parameters between the cores were obtained as the basis for judging the homogeneity of the pore space. The results are shown in Table 4.

[0088] Table 4 Porosity and permeability of sandstone gas in Dongtang 1 well

[0089] serial number Porosity (pu) Permeability (mD) Dongtang 1 2.20 0.016 Dongtang 2 1.95 0.017 Dongtang 3 2.95 0.049 Dongtang 4 2.66 0.029 Dongtang 5 3.02 0.021 Dongtang 6 2.99 0.026 Dongtang 7 3.01 0.024 Dongtang 8 2.89 0.026 Dongtang 9 2.97 0.029 Dongtang 10 2.91 0.023 Dongtang 11 3.18 0.024 Dongtang 12 2.78 0.019 Dongtang 13 2.32 0.019 Dongtang 14 2.25 0.014 Dongtang 15 2.94 0.022 Dongtang 16 2.68 0.017 Dongtang 17 2.40 0.016 Dongtang 18 2.91 0.024 Dongtang 19 2.50 0.018 Dongtang 20 3.46 0.038 Dongtang 21 2.52 0.018 Dongtang 22 4.67 0.114 Dongtang 23 3.21 0.035 Dongtang 24 3.15 0.031 Dongtang 25 3.16 0.030 Dongtang 26 2.84 0.025 Dongtang 27 2.08 0.022 Dongtang 28 1.70 0.018 Dongtang 29 3.04 0.027 Dongtang 30 2.85 0.028

[0090] It can be seen from the gas test results in Table 4 that the sandstone section of about 915 meters from the third section of the Luzhai Formation in Dongtang 1 well has good overall homogeneity and permeability in terms of pore space, but some samples still have large deviations in porosity and permeability parameters from the rest of the samples. Preferably, the cores of Dongtang 5, Dongtang 6, and Dongtang 7 are saturated with 50ppm magnetic fluid, and the cores of Dongtang 9, Dongtang 11, and Dongtang 15 are saturated with brine, and the remaining samples are kept for later study.

[0091] The ratio of pore volume to total core volume is the core NMR porosity. As shown in Table 5, the average NMR porosity of the core saturated with brine is about 2.55 pu, and the average NMR porosity of the core saturated with 50 ppm magnetic fluid is about 2.50 pu, which is not much different and within the error range.

[0092] Table 5 NMR porosity of sandstone in Dongtang 1 well measured by saturated magnetic fluid and saturated brine

[0093] serial number Hydrogen signal Fluid volume (ml) <![CDATA[Core volume (cm 3 )]]> Porosity (pu) Dongtang 5 20036.108 0.523780106 20.493 2.555897651 Dongtang 6 20074.804 0.524791689 20.566 2.551744087 Dongtang 7 18576.387 0.485620358 20.332 2.388453463 Dongtang 9 22487.724 0.549796562 20.303 2.707957258 Dongtang 11 21464.908 0.524789998 20.550 2.553722616 Dongtang 15 20043.654 0.490042125 20.415 2.400402279

[0094] Example 4: Evaluation of the ability of magnetic nanoparticle solutions (magnetic fluids) to saturate natural sandstone cuttings to obtain accurate porosity

[0095] The six cores saturated with 50ppm magnetic fluid and saturated with brine were crushed separately. The rock cuttings of Dongtang samples 5, 6 and 7 saturated with 50ppm magnetic fluid were evenly mixed, and the rock cuttings of Dongtang samples 9, 11 and 15 saturated with saturated brine were also evenly mixed. Then, the rock cuttings were sieved into three particle sizes of <1mm, 1-4mm and >4mm using 6-mesh (4mm) and 18-mesh (1mm) sieves, and tested separately. FC-40 (3M) fluoride liquid that exceeds the detection range of the nuclear magnetic resonance instrument was added to the centrifuge tube. At this time, the fluorine coil specially used to detect the 19F signal was replaced to detect the maximum volume of fluoride liquid. Then, the wet rock cuttings were added, and a set of centrifugal rates were set according to the calculated critical centrifugal rate for centrifugation. After centrifugation, the liquid attached to the surface of the cuttings and the liquid in the intergranular spaces will float above and exceed the signal detection area. At this time, the fluid volume obtained by detecting the 1H signal comes from the pores, and the volume inverted by the hydrogen signal represents the volume of the fluid in the pores. At this time, the difference between the volume inverted by the fluorine signal and the maximum volume is the total volume of the cuttings, and the nuclear magnetic resonance porosity of the cuttings is calculated.

[0096] The critical centrifugal rate calculated by the Young-Laplace equation: when the sample height is 0.5 cm and the fluid in the pore is saturated brine, the calculated critical centrifugal rate is 1101.99 rpm; the critical centrifugal rate calculated for rock cuttings saturated with 50 ppm magnetic fluid is 1281.25 rpm. A gradient increase in centrifugal rate was set to verify the effect of centrifugal rate on the results of rock cuttings nuclear magnetic resonance porosity. With reference to the calculated centrifugal rate, several groups of centrifugal rates were added before and after the calculation of the centrifugal rate for comparison. Three particle size samples with different saturated fluids were set at 100 rpm, 300 rpm, 500 rpm, 700 rpm, 900 rpm, 1100 rpm, 1300 rpm, 1500 rpm, 1700 rpm, and 1900 rpm, for a total of 10 groups of centrifugal experiments, and the centrifugal time was 10 minutes. Cuttings with three particle sizes of <1mm, 1-4mm, and >4mm were centrifuged according to the above centrifugation parameters. After centrifugation, the samples were placed in a nuclear magnetic resonance instrument with a hydrogen coil to measure the 1H signal, and then placed in a nuclear magnetic resonance instrument of the same model equipped with a fluorine coil to measure the 19F signal. The porosity of the cuttings was calculated based on the formula obtained from the magnetic fluid calibration and fluorine calibration results, the signal corresponding to unit volume of magnetic fluid, and the maximum fluorine volume inverted from the maximum fluorine signal.

[0097] Among them, the porosity results of two groups of cuttings less than 1 mm are shown in Table 6 and Table 7 respectively. The porosity results of two groups of cuttings from 1 to 4 mm are shown in Table 8 and Table 9 respectively. The porosity results of two groups of cuttings greater than 4 mm are shown in Table 10 and Table 11 respectively.

[0098] Table 6 Porosity of cuttings less than 1 mm after centrifugation in magnetic fluid group

[0099] Sample No. Hydrogen signal Fluorine signal Porosity (pu) CLT-less than 1mm-100r 3998.838 21379.124 9.523919159 CLT-less than 1mm-300r 6681.638 19637.561 18.96899727 CLT-less than 1mm-500r 5643.329 20361.497 15.56911534 CLT-less than 1mm-700r 6841.437 21549.873 21.77759033 CLT-less than 1mm-900r 7914.086 19938.017 22.81591463 CLT-less than 1mm-1100r 3413.427 23156.547 7.85456918 CLT-less than 1mm-1300r 5142.021 19126.112 12.70483295 CLT-less than 1mm-1500r 5188.945 20355.562 13.0044462 CLT-less than 1mm-1700r 4179.538 20197.178 9.112709537 CLT-less than 1mm-1900r 2955.391 23628.349 5.488851327

[0100] Table 7 Porosity of saturated brine group with less than 1 mm cuttings after centrifugation

[0101] Sample No. Hydrogen signal Fluorine signal Porosity (pu) Salt water - less than 1mm - 100r 8024.856 19416.059 21.5180837 Salt water - less than 1mm - 300r 5748.063 17792.193 13.50583852 Salt water - less than 1mm - 500r 5131.972 24135.021 16.53581205 Salt water - less than 1mm - 700r 3025.698 24549.875 6.397267908 Salt water - less than 1mm - 900r 6562.532 23160.744 21.76889513 Salt water - less than 1mm - 1100r 2752.065 28549.743 7.030095691 Salt water - less than 1mm - 1300r 3802.234 26802.57 11.61226923 Salt water - less than 1mm - 1500r 2554.536 29486.579 6.36106233 Salt water - less than 1mm - 1700r 3194.702 27640.785 8.995204154 Salt water - less than 1mm - 1900r 2691.857 26436.219 5.598104978

[0102] Table 8 Porosity of 1 to 4 mm cuttings in magnetic fluid group after centrifugation

[0103] Sample No. Hydrogen signal Fluorine signal Porosity (pu) CLT-1 to 4mm-100r 7942.795 17209.704 21.1186493 CLT-1 to 4mm-300r 7526.81 24318.386 29.4924386 CLT-1 to 4mm-500r 6195.549 19560.424 16.14590377 CLT-1 to 4mm-700r 7473.855 16045.741 17.69483513 CLT-1 to 4mm-900r 4666.073 19889.04 10.76709227 CLT-1 to 4mm-1100r 4810.408 14164.442 8.763106305 CLT-1 to 4mm-1300r 3160.9 18712.799 4.917201057 CLT-1 to 4mm-1500r 2361 26778.254 3.462676626 CLT-1 to 4mm-1700r 2372.487 21036.906 2.440375634 CLT-1 to 4mm-1900r 2361.625 20017.136 2.273337194

[0104] Table 9 Porosity of 1 to 4 mm cuttings after centrifugation in saturated brine group

[0105] Sample No. Hydrogen signal Fluorine signal Porosity (pu) Brine - 1 to 4 mm - 100r 3681.573 21995.181 7.989535728 Brine - 1 to 4 mm - 300r 7021.254 18963.502 18.70301082 Brine - 1 to 4 mm - 500r 5143.823 24358.194 16.85092853 Brine - 1 to 4 mm - 700r 3955.285 22342.491 9.221319968 Brine - 1 to 4 mm - 900r 4026.373 18005.174 7.597205014 Brine - 1 to 4 mm - 1100r 2693.758 18548.756 3.513002915 Brine - 1 to 4 mm - 1300r 3388.289 23812.34 7.650781972 Brine - 1 to 4 mm - 1500r 2590.982 22594.545 3.937378003 Brine - 1 to 4 mm - 1700r 2261.627 18709.358 2.14147195 Brine - 1 to 4 mm - 1900r 2174.469 21239.219 2.114733698

[0106] Table 10 Porosity of cuttings larger than 4 mm after centrifugation in magnetic fluid group

[0107] Sample No. Hydrogen signal Fluorine signal Porosity (pu) CLT-greater than 4mm-100r 3423.445 18379.625 5.740849146 CLT-greater than 4mm-300r 4436.726 21943.296 11.07034531 CLT-greater than 4mm-500r 4275.899 23652.941 11.51907477 CLT-greater than 4mm-700r 2999.574 20582.473 4.781728858 CLT-greater than 4mm-900r 3906.334 19021.762 7.627452098 CLT-greater than 4mm-1100r 2725.254 21831.957 3.993591628 CLT-greater than 4mm-1300r 2309.807 26924.317 3.208978237 CLT-greater than 4mm-1500r 2938.178 17701.084 3.950274219 CLT-greater than 4mm-1700r 1953.017 28468.679 1.324604589 CLT-greater than 4mm-1900r 1755.111 23837.611 0.025738076

[0108] Table 11 Porosity of saturated brine group with a diameter of more than 4 mm after centrifugation

[0109]

[0110]

[0111] and, Figure 4 The porosity of different particle size cuttings (1-4 mm and >4 mm) saturated with brine and magnetic nanoparticle solution (ferrofluid) is shown as a function of centrifugation rate. Figure 4 It can be seen that the porosity of cuttings larger than 1 mm decreases with the increase of centrifugal rate.

[0112] Figure 5 It is shown that for 1-4 mm sandstone cuttings, the critical centrifugal speeds for magnetic fluid saturation and brine saturation are different, as shown by Figure 5 It can be seen that the critical centrifugal speed using magnetic fluid is 400 rpm.

[0113] Figure 6 It is shown that the critical centrifugal speeds of sandstone cuttings larger than 4 mm are different when saturated with magnetic fluid and brine. Figure 6 It can be seen that the critical centrifugal speed using magnetic fluid is 300 rpm.

[0114] Example 5: Evaluation of the ability of magnetic nanoparticle solutions (magnetic fluids) to saturate natural sandstone cuttings to obtain accurate pore connectivity

[0115] For the connectivity evaluation of the 1-4 mm Dongtang 1 Well sandstone cuttings, the T2 spectrum corresponding to 1900rpm is used as the standard. Comparing the T2 curves of the magnetic fluid group and the saturated brine group, it can be seen that the T2 peak representing the large pore size has shifted to the left and overlapped. This part of the pores can be considered as connected pores, accounting for about 28%, and the corresponding T2 cutoff value can be set to 160ms. Based on this T2 cutoff value, it can be obtained that the proportion of connected and non-connected pores in this rock sample is 28% / 72%. Figure 7 As shown in the curve on the left.

[0116] The connectivity evaluation of Dongtang 1 Well sandstone cuttings larger than 4 mm needs to be carried out using the T2 spectrum corresponding to 1100rpm as the standard. Compared with the magnetic fluid group, which has completely completed relaxation and has only two peaks, the T2 peak representing the large pores of the brine group is shifted to the left and superimposed. The corresponding pores are connected pores, accounting for about 31.7%, and the corresponding T2 cutoff value can be set to 188ms. Based on this T2 cutoff value, the proportion of connected and non-connected pores in the rock sample is 31.7% / 68.3%, as shown in Figure 7 As shown in the curve in the middle right figure. Figure 7 The results show that the results calculated by the two methods are relatively close. Compared with the 1 to 4 mm, the proportion of connected pores calculated at 1900 rpm is slightly higher, which may be due to the liquid in the interstitial spaces of the particles with larger pore spaces.

[0117] The above is only an embodiment of the present application and is not intended to limit the present application. For those skilled in the art, the present application may have various changes and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present application should be included in the scope of the claims of the present application.

Claims

1. A method for measuring the porosity and connectivity of rock fragments based on magnetic nanoparticles, characterized in that: include: Step 1), saturating the rock cuttings with a polymer-coated magnetic nanoparticle solution so that the interconnected pores of the rock cuttings are filled with the magnetic nanoparticle solution; the saturation treatment is a vacuum pressure saturation method; Step 2), placing the saturated rock cuttings in a drainage agent, and removing the magnetic nanoparticle solution on the surface of the rock cuttings by centrifugation to obtain a sample to be tested; The centrifugal step comprises: placing the saturated rock cuttings in a drainage agent and centrifuging at 1000-2000 r / min for 8-15 minutes; Step 3), using nuclear magnetic resonance to obtain the drainage agent parameters and rock cuttings attribute parameters of the sample to be tested, and calculating the porosity and connectivity of the rock cuttings according to the drainage agent parameters and the rock cuttings attribute parameters; the drainage agent parameters are selected from at least one of the position, volume and content of the drainage agent; the rock cuttings attribute parameters include the fluid volume in the rock cuttings pores and the total volume of the rock cuttings, specifically including: using nuclear magnetic resonance to obtain the fluid volume Vp in the rock cuttings pores and the total volume Vb of the rock cuttings, and the rock cuttings porosity φ = Vp / Vb×100%; using nuclear magnetic resonance to measure the T2 spectrum, and evaluating the pore connectivity according to the T2 spectrum drift caused by magnetic particles; The rock cuttings are sandstones with a length of 1-4 mm and / or 4-20 mm; The polymer is a copolymer obtained by copolymerizing an unsaturated monomer containing a sulfonic acid group and an unsaturated monomer containing a carboxyl group, and a salt thereof; The unsaturated monomer containing sulfonic acid group is selected from one or more of styrene sulfonate, methyl propylene sulfonate, propylene sulfonate, vinyl sulfonate, butylene sulfonate and 2-acrylamide-2-methylpropane sulfonate; The unsaturated monomer containing a carboxyl group is selected from one or more of maleic acid, acrylic acid, methacrylic acid, crotonic acid, 2-ethylacrylic acid, 2-pentenoic acid, 4-pentene, 2-octenoic acid, 3-vinylbenzoic acid, 4-vinylbenzoic acid, 10-undecenoic acid, erucic acid, brassinoic acid, palmitoleic acid, oleic acid, nervonic acid, linolenic acid, ricinoleic acid, 4-oxo-4-phenyl-2-butenoic acid, 2-bromoacrylic acid, 2-bromomethyl-acrylic acid, sorbic acid, itaconic acid, citraconic acid, fumaric acid, methylfumaric acid, mesaconic acid, 2-methylsuccinic acid, and mucofuric acid; The chemical structure of the magnetic nanoparticles is Fe (3-x) M x O4(0≤x≤3) or Fe (2-x) M x O3 (0≤x≤2), wherein M is selected from one of Mn, Cu, Zn, Ni, Gd or Co.

2. The measuring method according to claim 1, characterized in that: The molecular weight of the polymer is 1 to 3 million.

3. The measuring method according to claim 2, characterized in that: The molecular weight of the polymer is 1.5 to 2 million.

4. The measuring method according to claim 1, characterized in that: The number of repeating units of the polymer is 50-200.

5. The measuring method according to claim 4, characterized in that: The number of repeating units of the polymer is 90-120.

6. The measuring method according to claim 1, characterized in that: The salt of the polymer is selected from one or more of potassium salt, sodium salt and ammonium salt.

7. The measuring method according to claim 1, characterized in that: The magnetic nanoparticles are Fe3O4.

8. The measuring method according to claim 1, characterized in that: The particle size of the magnetic nanoparticles is 5-150 nm.

9. The measuring method according to claim 8, characterized in that: The particle size of the magnetic nanoparticles is 10-20 nm.

10. The measuring method according to claim 1, characterized in that: The polymer-coated magnetic nanoparticles are prepared by the following method: Step a), allowing the polymer to self-assemble to form a cage structure; Step b), adding metal salt and oxidant to grow into nanoparticle crystals in the cavity of the cage structure formed by the polymer; Step c), after centrifugation, the synthesized magnetic nanoparticles are concentrated using a protein enrichment tube.

11. The measuring method according to claim 1, characterized in that: The liquid discharging agent is a fluorine-containing hydrophobic agent with a density of >1g / cm 3 .

12. The measuring method according to claim 11, characterized in that: The fluorine-containing hydrophobic agent is selected from one or more of fluorine oil, perfluorinated trialkylamine, and perfluoropolyether.

13. The measuring method according to claim 11, characterized in that: The fluorine-containing hydrophobic reagent is FC-40 fluorinated liquid.

14. The measuring method according to claim 1, characterized in that: The vacuum pressure saturation treatment method is specifically as follows: the rock cuttings are placed in a vacuum device and evacuated to -0.1 MPa, and then the polymer-coated magnetic nanoparticle solution is added and immersed in the vacuum state, and an external pressure of 210 mL / 50 MPa is applied for 12 hours.

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