Core fluid type and distribution characteristic determination method and system

Abstract

The embodiment of the invention provides a core fluid type and distribution characteristic determination method and system, and belongs to the technical field of oil-gas field development. The method comprises the following steps: setting different centrifugal forces through centrifugal equipment to carry out a nuclear magnetic resonance experiment, collecting T2 spectrum distribution data of a rock core under each centrifugal force, and drawing an accumulation curve; determining a T2 cut-off value according to the curves, and identifying the type and the occurrence space of the fluid in the rock core by combining high-pressure mercury injection experimental data, so as to analyze the fluid distribution characteristics of the rock core. According to the scheme, mobility evaluation can better respond to reservoir mineral composition and micrometer-nanometer pore throat development characteristics, meanwhile, the limitation of dividing fluid types through a single cut-off value is effectively avoided, and the dependence of experts and scholars on empirical values is reduced.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, specifically to a method and system for determining the type and distribution characteristics of core fluids. Background Technology

[0002] Nuclear magnetic resonance (NMR) is a rapid, simple, and non-destructive method for measuring pore structure characteristics. As a typical reservoir evaluation technique, it has been widely used in the field of oil exploration and development. Low-field NMR experiments have been applied to the exploration of conventional oil and gas reservoirs since the 1960s to analyze the rock physical characteristics of target reservoirs. Related experimental tests include four types: NMR experiments under saturated formation water conditions, centrifugal NMR experiments, displacement NMR experiments, and NMR imaging. Compared with other analytical methods, it can not only classify reservoirs by integrating multiple information, such as pore structure, porosity, permeability, mobile fluid saturation, and effective porosity, but also optimize NMR logging parameters and apply them in the oilfield. It is generally believed that the mobile fluids studied in NMR experiments correspond to pore water and mobile fluids within gas reservoirs. Precise division of the T2 cutoff value can clarify the occurrence state of pore water and mobile fluids within the reservoir.

[0003] Currently, the T2 cutoff value still uses empirical values ​​such as 33ms for sandstone / mudstone and 92ms for carbonates. However, in reality, the T2 cutoff value varies significantly depending on lithology and pore structure, which can affect the determination of bound water saturation, mobile fluid saturation, permeability prediction, and reservoir evaluation to varying degrees. Currently, there are three methods for determining the T2 cutoff value in the laboratory: centrifugation NMR experiments, regional empirical methods, and parameter fitting methods. Among these, the regional empirical method relies heavily on expert experience, and the subjectivity of human interpretation can influence the calibration results. The parameter fitting method requires the assistance of other experimental results and is limited by the availability and cost of simultaneous sample experiments. The centrifugation NMR experiment method is currently the most widely used method in the industry for determining the T2 cutoff value.

[0004] However, centrifugation-based NMR experiments are significantly limited by instrumentation and experimental conditions. If a single cutoff value is used, the saturation of the bound fluid varies under different centrifugal forces, leading to the simplistic assumption that the bound fluid in the core is completely immobile. Conversely, if a dual cutoff value is used, the reservoir space cannot be further divided based on the fluid state within the pores, resulting in a simplistic assumption of uniform mobility and a single free state. Given the insufficient accuracy of existing core fluid type and distribution characteristics determination schemes, a new scheme is needed. Summary of the Invention

[0005] The purpose of this invention is to provide a method and system for determining the type and distribution characteristics of core fluids, so as to at least solve the problem of insufficient accuracy in existing methods for determining the type and distribution characteristics of core fluids.

[0006] To achieve the above objectives, the first aspect of the present invention provides a method for determining the fluid type and distribution characteristics of a core sample. The method includes: defining multiple experimental centrifugal forces based on the performance information of a centrifuge device, and collecting experimental data from centrifugation-based nuclear magnetic resonance experiments performed on the core sample under each experimental centrifugal force; plotting T2 spectrum distribution curves corresponding to the experimental data under each experimental centrifugal force, and plotting corresponding cumulative curves based on each T2 spectrum distribution curve; determining multiple T2 cutoff values ​​based on the distribution relationship between each T2 spectrum distribution curve and each cumulative curve; collecting high-pressure mercury intrusion porosimetry (HIP) data of the corresponding core sample, and determining the fluid type and the occurrence space of each fluid type based on the HIP data and each T2 cutoff value; and determining the fluid distribution characteristics of the corresponding core sample based on the fluid type and the occurrence space of each fluid type.

[0007] Optionally, the step of defining multiple experimental centrifugal forces based on the operating performance information of the centrifuge equipment includes: determining the maximum centrifugal force of the corresponding equipment based on the operating performance information of the centrifuge equipment, as the maximum centrifugal force for the experiment; determining the centrifugal force that can be generated by the T2 spectrum distribution curve under saturated water conditions and satisfy a preset difference as the minimum centrifugal force for the experiment; selecting multiple unequal centrifugal forces between the minimum centrifugal force and the maximum centrifugal force as multiple intermediate centrifugal forces; and using the minimum centrifugal force, the maximum centrifugal force, and the multiple intermediate centrifugal forces as the result of defining the experimental centrifugal forces.

[0008] Optionally, experimental data from centrifugal nuclear magnetic resonance experiments performed on cores under each experimental centrifugal force can be collected, including: based on each defined experimental centrifugal force, centrifugal equipment parameters can be adjusted sequentially, and after each parameter adjustment, a centrifugal nuclear magnetic resonance experiment of the corresponding core can be performed, and the corresponding experimental data can be collected.

[0009] Optionally, determining multiple T2 cutoff values ​​based on the distribution relationship between each T2 spectrum distribution curve and each cumulative curve includes: taking the T2 value corresponding to the divergence point between the T2 spectrum distribution curve under the maximum centrifugal force condition and the T2 spectrum distribution curve under the preset saturated water condition as the first T2 cutoff value; taking the first non-zero point along the x-axis direction of the T2 spectrum distribution curve under the minimum centrifugal force condition as the Nth T2 cutoff value; N is the number of T2 spectrum distribution curves; and determining the T2 cutoff value corresponding to each medium centrifugal force based on the cross relationship between the T2 spectrum distribution curve and the cumulative curve corresponding to each medium centrifugal force.

[0010] Optionally, N is 4. The determination of the T2 cutoff value corresponding to each medium centrifugal force based on the cross relationship between the T2 spectrum distribution curve and the cumulative curve corresponding to each medium centrifugal force includes: taking the intersection of each cumulative curve with the y-axis as the cumulative porosity value under the corresponding experimental centrifugal force; when the difference between the cumulative porosity value of the third experimental centrifugal force and the cumulative porosity value of the maximum experimental centrifugal force is greater than the difference between the cumulative porosity value of the second experimental centrifugal force and the cumulative porosity value of the third experimental centrifugal force, the cumulative curve of the third experimental centrifugal force is taken as the confirmation curve corresponding to the second experimental centrifugal force; otherwise, the cumulative curve of the second experimental centrifugal force is taken as the confirmation curve corresponding to the second experimental centrifugal force; wherein, the third experimental centrifugal force is greater than the second experimental centrifugal force; taking the intersection of the extension of the confirmation curve corresponding to the third experimental centrifugal force and the T2 spectrum distribution curve under the preset saturated water condition as the second T2 cutoff value; taking the intersection of the extension of the cumulative curve corresponding to the minimum centrifugal force and the T2 spectrum distribution curve under the preset saturated water condition as the third T2 cutoff value.

[0011] Optionally, the determination of the fluid type and the storage space of each fluid type for the corresponding core based on the high-pressure mercury intrusion porosimetry experimental data and each T2 cutoff value includes: based on the high-pressure mercury intrusion porosimetry experimental data and the experimental data of centrifugal nuclear magnetic resonance experiments performed on the core under each experimental centrifugal force, performing T2 spectrum distribution and pore radius correspondence based on a preset correspondence relationship; wherein, the T2 spectrum distribution is obtained based on historically retained T2 values; based on the fact that the same sample has a unique corresponding pore radius and T2 value under the same wetting phase saturation condition, a conversion model is obtained based on the correspondence relationship between the T2 spectrum distribution and the pore radius; based on the conversion model, the pore radius determined by the high-pressure mercury intrusion porosimetry experimental data is converted into the corresponding T2 value; and based on the T2 value corresponding to each pore radius, the determination of the fluid type and the storage space of each fluid type for the corresponding core is performed.

[0012] Optionally, the fluid type includes: clay-bound fluid, capillary-bound fluid, tertiary free fluid, secondary free fluid, and primary free fluid.

[0013] Optionally, the determination of the fluid type and the storage space of each fluid type based on the T2 value corresponding to each pore radius includes: if the T2 value corresponding to the pore radius is less than the first T2 cutoff value, the corresponding fluid type is clay-bound fluid, and the corresponding storage space is clay-bound pores; if the T2 value corresponding to the pore radius is between the first and second T2 cutoff values, the corresponding fluid type is capillary-bound fluid, and the corresponding storage space is capillary-bound pores; if the T2 value corresponding to the pore radius is between the second and third T2 cutoff values, the corresponding fluid type is tertiary free fluid, and the corresponding storage space is tertiary free fluid pores; if the T2 value corresponding to the pore radius is between the third and fourth T2 cutoff values, the corresponding fluid type is secondary free fluid, and the corresponding storage space is secondary free fluid pores; if the T2 value corresponding to the pore radius is greater than the fourth T2 cutoff value, the corresponding fluid type is primary free fluid, and the corresponding storage space is primary free fluid pores.

[0014] Optionally, determining the fluid distribution characteristics of the corresponding core based on the fluid type and the occurrence space of each fluid type includes: determining the movable fluid saturation and movable fluid porosity of the corresponding core under each experimental centrifugal force; and characterizing the fluid distribution characteristics of the corresponding core based on the movable fluid saturation, the movable fluid porosity, the corresponding fluid type, and the occurrence space of the corresponding fluid type.

[0015] A second aspect of the present invention provides a system for determining the fluid type and distribution characteristics of a core sample. The system includes: a data acquisition unit, configured to define multiple experimental centrifugal forces based on the performance information of a centrifuge, and to acquire experimental data from centrifugation-based nuclear magnetic resonance experiments performed on the core sample under each experimental centrifugal force; a processing unit, configured to plot T2 spectrum distribution curves corresponding to the experimental data under each experimental centrifugal force, and to plot corresponding cumulative curves based on each T2 spectrum distribution curve; a determination unit, configured to determine multiple T2 cutoff values ​​based on the distribution relationship between each T2 spectrum distribution curve and each cumulative curve; a judgment unit, configured to acquire high-pressure mercury intrusion porosimetry experimental data of the corresponding core sample, and to determine the fluid type and the storage space of each fluid type based on the high-pressure mercury intrusion porosimetry experimental data and each T2 cutoff value; and an output unit, configured to determine the fluid distribution characteristics of the corresponding core sample based on the fluid type and the storage space of each fluid type.

[0016] On the other hand, the present invention provides a computer-readable storage medium storing instructions that, when executed on a computer, cause the computer to perform the above-described method for determining the type and distribution characteristics of core fluid.

[0017] Based on the above technical solutions, this invention proposes a method for classifying fluid types using multiple T2 cutoff values, based on the cumulative T2 spectrum curves under different centrifugal forces and the T2 spectrum distribution characteristics under saturated formation water conditions. This method further subdivides the fluid types, occurrence states, and distribution characteristics within the core. The classification of bound fluids fully considers mineral composition, while the classification of movable fluids fully considers pore size distribution characteristics. This method will enable mobility assessment to better respond to reservoir mineral composition and micron-nano pore throat development characteristics, while also effectively avoiding the limitations of classifying fluid types using a single cutoff value and reducing the reliance of experts and scholars on empirical values.

[0018] Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0019] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings:

[0020] Figure 1 This is a flowchart of the steps of a method for determining the type and distribution characteristics of core fluid provided in one embodiment of the present invention;

[0021] Figure 2 This is a schematic diagram of a multi-cutoff value partitioning scheme based on centrifugal nuclear magnetic resonance provided by one embodiment of the present invention;

[0022] Figure 3 This is a schematic diagram of the equation for determining the conversion between the T2 distribution spectrum and the pore radius r, provided by one embodiment of the present invention;

[0023] Figure 4 This is a schematic diagram illustrating the division of multiple cutoff values ​​for samples with different physical properties according to one embodiment of the present invention;

[0024] Figure 5 This is a schematic diagram of the pore size distribution characteristics of a sample within a study area provided by one embodiment of the present invention;

[0025] Figure 6 This is a schematic diagram illustrating the classification of sample fluid types and their storage space ratio within the study area according to one embodiment of the present invention;

[0026] Figure 7 This is a system structure diagram of a core fluid type and distribution characteristic determination system provided in one embodiment of the present invention. Detailed Implementation

[0027] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0028] In nuclear magnetic resonance (NMR) logging, the methods used by field interpreters for selecting many important parameters are still relatively outdated. For example, the T2 cutoff value still relies on empirical values ​​such as 33ms for sandstone / mudstone and 92ms for carbonates. However, the T2 cutoff value can vary significantly depending on lithology and pore structure, which can affect the determination of bound water saturation, mobile fluid saturation, permeability prediction, and reservoir evaluation to varying degrees. Currently, there are several methods for determining the T2 cutoff value in the laboratory:

[0029] 1) Centrifugation NMR experiment method, which obtains the cutoff value by comparing the cumulative curves of T2 spectrum in saturated formation water and after centrifugation.

[0030] 2) Regional empirical method: Based on previous experience and a large amount of experimental data, the average cutoff value of the T2 spectrum in the study area is obtained. This method is too empirical and difficult to be widely promoted and applied.

[0031] 3) Parameter fitting method. This method uses the effective porosity, permeability, porosity-permeability composite index, and T2 geometric mean obtained from NMR experiments to fit the parameters and determine the T2 cutoff value. However, this method is only applicable to high-porosity rock samples; for low-porosity and complex pore structures, more reasonable fitting parameters are needed.

[0032] Because the regional empirical method for calibrating the T2 cutoff value relies heavily on expert experience, the subjectivity of human interpretation can influence the calibration results. The parameter fitting method requires the assistance of other experimental results and is limited by the availability and cost of simultaneous sample experiments. Centrifugation-based nuclear magnetic resonance (NMR) experiments are considered an effective method for calibrating the T2 cutoff value. Generally, fluids in pores with a T2 cutoff value smaller than the cutoff value are considered bound fluids, while fluids in pores with a T2 cutoff value larger than the cutoff value are considered mobile fluids. With the deepening research into the pore structure of tight reservoirs, researchers have continuously optimized the conversion parameters. For the multi-peak T2 spectrum distribution characteristics, due to the wide range of pore size distributions, a single curve is insufficient to meet the conversion conditions. Numerous experimental results also show that the magnitude of centrifugal force, to a certain extent, determines the level of the bound water saturation calibration value. However, due to limitations in experimental instruments, the maximum measurable centrifugal force is finite, and bound fluids and free fluids cannot be simply considered completely immobile or completely mobile.

[0033] Since the regional empirical method for calibrating the T2 cutoff value relies heavily on expert experience, the subjectivity of human interpretation can have a certain impact on the calibration results. The parameter fitting method for calibrating the T2 cutoff value requires the assistance of other experimental results and is limited by the availability and cost of simultaneous sample experiments. The centrifugation-based nuclear magnetic resonance method for determining the T2 cutoff value is currently the most widely used method in the industry.

[0034] Centrifugation-based nuclear magnetic resonance experiments are subject to significant limitations in terms of instruments and experimental conditions. If a single cutoff value is used for classification, the saturation of the bound fluid calibrated under different centrifugal force conditions will be different. In this case, the bound fluid in the core will simply be considered to be completely immobile. If a double cutoff value is used for classification, the reservoir space cannot be further divided based on the state of the fluid contained in the pores. It will simply be considered to have the same mobility and present a single free state.

[0035] The purpose of this invention is to address the problems existing in the prior art. Based on the cumulative T2 spectrum curves under different centrifugal forces and the T2 spectrum distribution characteristics under saturated formation water conditions, a method for classifying fluid types using multiple T2 cutoff values ​​is proposed, further subdividing the fluid types, occurrence states, and distribution characteristics within the core. The classification of bound fluids fully considers mineral composition, while the classification of movable fluids fully considers pore size distribution characteristics. This method will enable mobility assessment to better respond to reservoir mineral composition and micron-nano pore throat development characteristics, while also effectively avoiding the limitations of classifying fluid types using a single cutoff value, and reducing the reliance of experts and scholars on empirical values.

[0036] Figure 1 This is a flowchart of a method for determining the type and distribution characteristics of core fluids according to one embodiment of the present invention. Figure 1 As shown, this invention provides a method for determining the type and distribution characteristics of core fluids, the method comprising:

[0037] Step S10: Based on the working performance information of the centrifuge equipment, define multiple experimental centrifugal forces, and collect experimental data of centrifugal nuclear magnetic resonance experiments performed on the core under each experimental centrifugal force.

[0038] Specifically, the maximum centrifugal force of the corresponding equipment is determined based on the working performance information of the centrifuge equipment, and is taken as the maximum centrifugal force for the experiment; the centrifugal force that can be generated by the T2 spectrum distribution curve under saturated water conditions and meet the preset difference is taken as the minimum centrifugal force for the experiment; multiple unequal centrifugal forces are selected between the minimum centrifugal force and the maximum centrifugal force, and are taken as multiple medium centrifugal forces; the minimum centrifugal force, the maximum centrifugal force and the multiple medium centrifugal forces are taken as the result of defining the experimental centrifugal force.

[0039] In one possible implementation, the minimum centrifugal force is determined: a centrifugal force that produces a significant difference from the T2 spectral distribution curve under saturated water conditions is selected, denoted as F. c-min Select the maximum centrifugal force that can be set on the instrument, denoted as F. c-max Determine the moderate centrifugal force as F. c-mid1 F c-mid2 (F c-min <F c-mid1 <F c-mid2 <F c-maxCentrifugal nuclear magnetic resonance experiments were conducted under four determined centrifugal forces.

[0040] Specifically, based on the defined experimental centrifugal force, the centrifuge equipment parameters are adjusted sequentially, and after each adjustment, a centrifugation nuclear magnetic resonance experiment is performed on the corresponding core, and the corresponding experimental data are collected.

[0041] Step S20: Plot the T2 spectrum distribution curves corresponding to the experimental data under centrifugal force for each experiment, and plot the corresponding cumulative curves based on each T2 spectrum distribution curve.

[0042] Specifically, such as Figure 2 T2 spectral distribution curves were plotted under different centrifugal forces. The curve plotted under the Fc-min condition was denoted as T. 2min F c-mid1 The curve plotted under the given conditions is denoted as T. 2mid1 F c-mid2 The curve plotted under the given conditions is denoted as T. 2mid2 F c-max The curve plotted under the given conditions is denoted as T. 2-max Draw T respectively 2-min T 2-mid1 T 2-mid2 T 2-max The cumulative curves of the four curves are denoted as C. min C mid1 C mid2 C max .

[0043] Specifically, T2 relaxation time data of the sample is obtained through centrifugation NMR experiments. This data is typically presented as relaxation curves. Data processing may include denoising, smoothing, and data fitting to prepare the data needed for plotting the T2 spectral distribution curve. The T2 spectral distribution curve is then plotted using data processing software or a programming language (such as the Matplotlib library in Python). In this plotting process, the horizontal axis usually represents the T2 relaxation time, and the vertical axis represents the corresponding intensity or signal strength. The plotted T2 spectral distribution curve is analyzed to identify different peaks and spectral line shapes, and the relationship between these characteristics and the sample properties is interpreted.

[0044] Furthermore, the cumulative percentage or cumulative intensity can be obtained by integrating or summing the T2 spectral distribution curve data. The cumulative curve can then be plotted using data processing software or programming languages ​​(such as the Matplotlib library in Python). The horizontal axis typically represents the T2 relaxation time, and the vertical axis represents the cumulative percentage or cumulative intensity.

[0045] Step S30: Determine multiple T2 cutoff values ​​based on the distribution relationship between each T2 spectrum distribution curve and each cumulative curve.

[0046] Specifically, the T2 value corresponding to the divergence point between the T2 spectrum distribution curve under the maximum centrifugal force condition and the T2 spectrum distribution curve under the preset saturated water condition is taken as the first T2 cutoff value; the first non-zero point along the x-axis of the T2 spectrum distribution curve under the minimum centrifugal force condition is taken as the N2 cutoff value; N is the number of T2 spectrum distribution curves; the T2 cutoff value corresponding to each medium centrifugal force is determined based on the cross relationship between the T2 spectrum distribution curve and the cumulative curve corresponding to each medium centrifugal force.

[0047] Furthermore, N is 4. The determination of the T2 cutoff value corresponding to each medium centrifugal force based on the intersection relationship between the T2 spectrum distribution curve and the cumulative curve corresponding to each medium centrifugal force includes: taking the intersection point of each cumulative curve with the y-axis as the cumulative porosity value under the corresponding experimental centrifugal force; when the difference between the cumulative porosity value of the third experimental centrifugal force and the cumulative porosity value of the maximum experimental centrifugal force is greater than the difference between the cumulative porosity value of the second experimental centrifugal force and the cumulative porosity value of the third experimental centrifugal force, the cumulative curve of the third experimental centrifugal force is taken as the confirmation curve corresponding to the second experimental centrifugal force; otherwise, the cumulative curve of the second experimental centrifugal force is taken as the confirmation curve corresponding to the second experimental centrifugal force; wherein, the third experimental centrifugal force is greater than the second experimental centrifugal force; the intersection point of the extension line of the confirmation curve corresponding to the third experimental centrifugal force and the T2 spectrum distribution curve under the preset saturated water condition is taken as the second T2 cutoff value; the intersection point of the extension line of the cumulative curve corresponding to the minimum centrifugal force and the T2 spectrum distribution curve under the preset saturated water condition is taken as the third T2 cutoff value.

[0048] In embodiments where a purple-red color is possible, the cumulative curve C w C min C mid1 C mid2 C max The intersection with the y-axis represents the cumulative porosity under different conditions, denoted as P. w P min P mid1 P mid2 P max .

[0049] The T2 spectral distribution curve under the maximum centrifugal force condition is T 2-max T2 spectral distribution curve under saturated water conditions 2-w The T2 value corresponding to the divergence point is determined as the first T2 cutoff value T. 2cutoff1 .

[0050] The second cutoff value T will be determined. 2cutoff2 The cumulative curve is denoted as C. -cutoff2 When (P) mid2 -P max )>(P mid1 -Pmid2 When C) -cutoff2 =C mid2 When (P) mid2 -P max ) < (P mid1 -P mid2 ) at C -cutoff2 =C mid1 ; will C -cutoff2 Extension line and T 2-w The T2 value corresponding to the intersection point is determined as the second T2 cutoff value T. 2cutoff2 .

[0051] C min Extension line and T 2-w The T2 value corresponding to the intersection point is determined as the third T2 cutoff value T. 2cutoff3 ;

[0052] The T2 spectral distribution curve under the minimum centrifugal force condition is T 2-min The first non-zero point from right to left is determined as the fourth T2 cutoff value T. 2cutoff4 .

[0053] Step S40: Collect high-pressure mercury intrusion test data of the corresponding core, and determine the fluid type and the occurrence space of each fluid type based on the high-pressure mercury intrusion test data and each T2 cutoff value.

[0054] Specifically, based on the high-pressure mercury intrusion porosimetry experimental data and the experimental data from centrifugal nuclear magnetic resonance experiments performed on the cores under various experimental centrifugal forces, a T2 spectrum distribution and pore radius correspondence are performed based on a preset correspondence relationship. The T2 spectrum distribution is obtained based on historically retained T2 values. Since the same sample has a unique corresponding pore radius and T2 value under the same wetting phase saturation condition, a conversion model is obtained based on the correspondence relationship between the T2 spectrum distribution and the pore radius. Based on the conversion model, the pore radius determined by the high-pressure mercury intrusion porosimetry experimental data is converted into the corresponding T2 value. Based on the T2 value corresponding to each pore radius, the fluid type of the corresponding core and the occurrence space of each fluid type are determined.

[0055] Specifically, based on nuclear magnetic resonance experiments and high-pressure mercury intrusion porosimetry experiments, the correspondence between the T2 spectral distribution and the pore radius r is matched according to a pre-defined correspondence. The pre-defined correspondence is as follows:

[0056]

[0057] Where r is the pore throat radius (μm); Pc is the capillary pressure (MPa); T2 is the transverse relaxation time (ms); σ is the surface tension of mercury and gas (mN / m, taken as 480 mN / m); θ is the contact angle between mercury and air (taken as 140°); ρ2 is the surface relaxation rate (μm / ms); and F is the pore shape factor. The NMR T2 spectrum essentially reflects the pore size distribution. The mobility of a fluid varies depending on the size of the pore space it occupies. By constructing a capillary pressure curve using the T2 spectrum and fitting it with the capillary pressure curve measured in actual mercury intrusion porosimetry experiments, a pore size distribution curve based on NMR experiments can be obtained. Therefore, the type of mobile fluid needs further evaluation based on the quantitative classification of the storage space.

[0058] Furthermore, such as Figure 3 Based on the fact that for the same sample under the same wetting phase saturation conditions, Sw(i) has a unique corresponding radius value r(i) and T2(i), a logarithmic fit is taken to determine the transformation equation, and the relationship is as follows:

[0059]

[0060] Furthermore, the confined fluid space is divided into: clay-bound pores and capillary-bound pores; the pore space occupied by the movable fluid is divided into: tertiary free fluid pores, secondary free fluid pores and primary free fluid pores according to the pore size distribution of the T2 spectrum response from small to large, corresponding to pore spaces of different levels and sizes.

[0061] Specifically, the determination of the fluid type and the storage space of each fluid type based on the T2 value corresponding to each pore radius includes: if the T2 value corresponding to the pore radius is less than the first T2 cutoff value, the corresponding fluid type is clay-bound fluid, and the corresponding storage space is clay-bound pores; if the T2 value corresponding to the pore radius is between the first and second T2 cutoff values, the corresponding fluid type is capillary-bound fluid, and the corresponding storage space is capillary-bound pores; if the T2 value corresponding to the pore radius is between the second and third T2 cutoff values, the corresponding fluid type is tertiary free fluid, and the corresponding storage space is tertiary free fluid pores; if the T2 value corresponding to the pore radius is between the third and fourth T2 cutoff values, the corresponding fluid type is secondary free fluid, and the corresponding storage space is secondary free fluid pores; if the T2 value corresponding to the pore radius is greater than the fourth T2 cutoff value, the corresponding fluid type is primary free fluid, and the corresponding storage space is primary free fluid pores.

[0062] In one possible implementation, when the throat radius r corresponds to a T2 value that satisfies T2 < T 2cutoff1When the pores are identified as clay-bound pores, the fluids contained within them are called clay-bound fluids. In this case, the fluid within the pores is completely bound and immobile, manifesting as a water film on the surface of hydrophilic clay minerals, or as micropores. When the pore throat radius r corresponds to a T2 value that satisfies T... 2cutoff1 <T2<T 2cutoff2 When a pore is identified as a capillary-bound pore, the fluid contained within it is called a capillary-bound fluid. At this time, the fluid within the pore is primarily bound by capillary pressure. When the centrifugal force (external force) is sufficiently large, it can break free from the capillary force and become a movable fluid, exhibiting alternating mobility. When the pore throat radius r corresponds to a T2 value that satisfies T... 2cutoff2 <T2<T 2cutoff3 At this point, the pores are identified as third-order free fluid pores, and the fluids contained within these pores are third-order free fluids. In this case, the fluid within the pores is flowable under relatively large centrifugal forces, exhibiting moderate mobility. When the pore throat radius r corresponds to a T2 value that satisfies T... 2cutoff3 <T2<T 2cutoff4 At this point, the pores are identified as third-order free fluid pores, and the fluids contained within these pores are third-order free fluids. In this case, the fluid within the pores is flowable under relatively small centrifugal forces, exhibiting strong mobility. When the pore throat radius r corresponds to a T2 value that satisfies T2 > T... 2cutoff4 At this point, the pores are identified as first-order free fluid pores, and the fluids contained within these pores are first-order free fluids. In this case, the fluid within the pores is completely mobile.

[0063] Step S50: Determine the fluid distribution characteristics of the corresponding core based on the fluid type of the core and the occurrence space of each fluid type.

[0064] Specifically, the movable fluid saturation and movable fluid porosity of the corresponding core under each experimental centrifugal force are determined respectively; based on the movable fluid saturation, the movable fluid porosity, the corresponding fluid type, and the occurrence space of the corresponding fluid type, the fluid distribution characteristics of the corresponding core are characterized.

[0065] Specifically, four cutoff values ​​T were statistically analyzed for samples with different lithologies and physical properties within the region. 2cutoff1 T 2cutoff2 T2cutoff3, T 2cutoff4 Size. Find F. c-min F c-mid1 F c-mid2 F c-max The corresponding movable fluid porosity is denoted as S. mf1 S mf2 S mf3 S mf4 Find F c-min F c-mid1 F c-mid2 F c-max The corresponding saturation of the movable fluid is denoted as φ.mf1 φ mf2 φ mf3 φ mf4 Nuclear magnetic resonance porosity is calculated based on the porosity and saturation of the mobile fluid. The calculation rule is as follows:

[0066] Φ mf =S mf ×Φ×100%

[0067] Where, Φ mf Porosity of movable fluid, %; S mf Φ represents the saturation of the mobile fluid, in %; Φ represents the nuclear magnetic porosity, in %.

[0068] Furthermore, based on the correspondence between pore throat radius r and T2, the pore size distribution range of different types of fluid occurrence space is calculated. If only a single sample is tested, the distribution characteristics of different types of fluid in that sample can be directly determined. To ensure the effectiveness of lateral comparisons between different samples in the same region (well group), it is necessary to comprehensively consider the cutoff value division results of various samples in the study area, and to perform correlation analysis between the pore structure characteristic parameters, mineral composition characteristic parameters, and other parameters that reflect reservoir geological characteristics of multiple samples in the lateral comparison area and the fluid occurrence space. Continuous optimization and adjustment are then carried out, verification is performed, and finally a unified calibration interval is determined.

[0069] In this embodiment of the invention, based on the cumulative T2 spectrum curves under different centrifugal forces and the T2 spectrum distribution characteristics under saturated formation water conditions, a method for classifying fluid types using multiple T2 cutoff values ​​is proposed, thereby determining the fluid type and distribution characteristics within the core. This method can reduce errors caused by mismatched synchronous sample experiments, ensuring that the core T2 cutoff value calibration is based to the maximum extent on the reservoir space characteristics of the sample itself. It also effectively avoids the limitations of classifying fluid types using a single cutoff value, reducing the reliance of experts and scholars on empirical values.

[0070] Example:

[0071] Step 1: Centrifugation nuclear magnetic resonance experiments were conducted on three tight sandstone reservoir samples with different physical properties in the northern Ordos Basin. The basic parameters of the samples are shown in Table 1.

[0072] Table 1. Physical properties and porosity characteristics of the test samples.

[0073]

[0074] The tests were conducted under five conditions: saturated formation water, 42 psi (0.290 MPa), 208 psi (1.434 MPa), 417 psi (2.875 MPa), and 900 psi (6.205 MPa).

[0075] Step 2: Select the divergence point between the T2 spectrum distribution curve under the maximum centrifugal force of 900 psi and the T2 spectrum distribution curve under saturated water conditions as the first cutoff value T. 2cutoff1 Consistent with the traditional method for determining the T2 cutoff value of centrifugation-based NMR, the intersection of the extended lines of the T2 cumulative spectrum curves at the inflection points under centrifugal forces of 208 psi and 42 psi with the T2 cumulative spectrum curve under saturated water conditions was selected as the second cutoff value T. 2cutoff2 and the third cutoff value T 2cutoff3 We can see the second cutoff value T. 2cutoff2 The first non-zero point from left to right on the T2 spectrum distribution curve under a centrifugal force of 417 psi is basically consistent with this point. Finally, the first non-zero point from right to left on the T2 spectrum distribution curve under a minimum centrifugal force of 42 psi is selected as the fourth cutoff value T. 2cutoff4 (Table 2, Appendix) Figure 4 ).

[0076] Table 2 Cutoff Value Division Results

[0077] Cutoff value SU-1 SU-21 SU-17 Cutoff1 6.83 8.49 7.62 <![CDATA[Cutoff2]]> 28.11 31.34 28.11 Cutoff3 74.82 60.19 38.95 Cutoff4 819.19 830.16 426.5

[0078] Step 3: To determine the fluid distribution characteristics within the region (well group), this step involves a horizontal comparison of eight samples within the region. Based on the distribution characteristics of the nuclear magnetic resonance T2 spectrum under saturated water conditions and the correspondence with high-pressure mercury intrusion, the pore size distribution characteristics are determined using the conversion equation (see appendix). Figure 2 , attached Figure 5 This lays the foundation for the next step of identifying the fluid distribution characteristics within the region by measuring multiple curves for samples of different lithologies and lithofacies. It also determines the classification of fluid types and their spatial proportions within the study area (see appendix). Figure 6 ).

[0079] Step 4: To facilitate lateral comparison between different samples, and considering the cutoff values ​​of different samples, the bound fluid space is divided into: clay-bound pores (T2 < 5ms) and capillary-bound pores (5ms < T2 < 25ms); the pore space occupied by the movable fluid is divided into three levels of free fluid pores (25ms < T2 < 100ms), two levels of free fluid pores (100ms < T2 < 500ms), and one level of free fluid pores (T2 > 500ms) according to the pore size distribution of the T2 spectrum response, corresponding to different levels and sizes of pore space.

[0080] Through simultaneous constant-rate mercury intrusion porosimetry (NMR) testing on the same standard core plunger sample, the pore structure characteristic parameters showed good response to different fluid storage space types. Eleven pore-throat parameters showed significant correlation with mobile fluid saturation, ranked from highest to lowest correlation as follows: final mercury intrusion saturation (positive correlation, R² = 0.944 at 900 psi), total pore mercury intrusion saturation (positive correlation, R² = 0.937 at 900 psi), relative sorting coefficient (negative correlation, R² = 0.87 at 900 psi), median saturation pressure (negative correlation, R² = 0.846 at 208 psi), median saturation radius (positive correlation, R² = 0.766 at 42 psi), and maximum connecting throat radius (…). Positive correlations were found in the mean capillary radius (R² = 0.777 at 42 psi), mean pore volume (R² = 0.766 at 42 psi), mean throat radius (R² = 0.762 at 417 psi), mean throat radius (R² = 0.753 at 42 psi), displacement pressure (R² = 0.735 at 42 psi), and skewness (R² = 0.678 at 900 psi). Among these, the mean capillary radius, mean throat radius, and skewness showed relatively significant correlations only under specific centrifugal forces.

[0081] Under the maximum centrifugal force of 900 psi, all three types of free fluids are in a mobile state. At this point, only the pore volume component of the tertiary free fluid shows a good correlation with the mobile fluid saturation (R² = 0.724). This result indicates that under higher displacement pressures, the mobile fluid saturation is mainly controlled by the pore throat with a diameter ranging from 0.5 to 2 μm; that is, the magnitude of the mobile fluid saturation increases with the size of the pore throat. Under different centrifugal forces, the mobile fluid saturation shows the best negative correlation with the pore volume contribution rate of clay mineral-bound fluids, but no significant correlation with capillary-bound fluid pores. Secondly, it shows a significant positive correlation with different levels of free fluid pore size. Under the minimum centrifugal force of 42 psi, only the secondary and primary free fluids are in a flowing state; the tertiary free fluid remains bound by capillary forces. At this point, the pore volume component of the primary free fluid pores shows the best correlation with the mobile fluid saturation, followed by the secondary free fluid pore volume component.

[0082] The pore characteristics occupied by the bound fluid are closely related to the mineral composition. Specifically, the pore volume component of the bound fluid in clay minerals shows a significant positive correlation (R² = 0.909), while the quartz content shows a significant negative correlation (R² = 0.898). This further confirms that when the pore throat radius is smaller than the first cutoff value T2cutoff1, the fluid within the pores is formed by a water film on the surface of the hydrophilic clay minerals and is completely bound and immobile. However, the bound fluid between the first and second cutoff values ​​T2cutoff1 shows no significant correlation with the content of various minerals, revealing that this type of bound fluid is mainly controlled by capillary forces. Furthermore, with increasing centrifugal force, the bound fluid tends to exhibit a tendency to be primarily bound by the micropores of clay minerals.

[0083] The saturation of movable fluid is significantly negatively correlated with the total amount of clay minerals and significantly positively correlated with the quartz content. This trend strengthens with increasing centrifugal force, indicating that as centrifugal force increases, movable fluid tends to be contained in the intergranular pores formed by the edges of quartz minerals, the throats of the slits between particles, and the micropores of clay minerals. The maximum and minimum pores significantly control the occurrence of movable fluid, while the medium-sized pores have little effect on controlling movable fluid.

[0084] Figure 7 This is a system structure diagram of a core fluid type and distribution characteristic determination system provided in one embodiment of the present invention. Figure 7 As shown, this invention provides a system for determining the fluid type and distribution characteristics of a core sample. The system includes: a data acquisition unit, used to define multiple experimental centrifugal forces based on the performance information of a centrifuge, and to acquire experimental data from centrifugation-based nuclear magnetic resonance experiments performed on the core sample under each experimental centrifugal force; a processing unit, used to plot the T2 spectrum distribution curves corresponding to the experimental data under each experimental centrifugal force, and to plot corresponding cumulative curves based on each T2 spectrum distribution curve; a determination unit, used to determine multiple T2 cutoff values ​​based on the distribution relationship between each T2 spectrum distribution curve and each cumulative curve; a judgment unit, used to acquire high-pressure mercury intrusion porosimetry experimental data of the corresponding core sample, and to determine the fluid type and the storage space of each fluid type based on the high-pressure mercury intrusion porosimetry experimental data and each T2 cutoff value; and an output unit, used to determine the fluid distribution characteristics of the corresponding core sample based on the fluid type and the storage space of each fluid type.

[0085] The present invention also provides a computer-readable storage medium storing instructions that, when executed on a computer, cause the computer to perform the above-described method for determining the type and distribution characteristics of core fluid.

[0086] Those skilled in the art will understand that all or part of the steps in the methods of the above embodiments can be implemented by a program instructing related hardware. This program is stored in a storage medium and includes several instructions to cause a microcontroller, chip, or processor to execute all or part of the steps of the methods described in the various embodiments of the present invention. The aforementioned storage medium includes various media capable of storing program code, such as a USB flash drive, portable hard drive, read-only memory (ROM), random access memory (RAM), magnetic disk, or optical disk.

[0087] The optional embodiments of the present invention have been described in detail above with reference to the accompanying drawings. However, the embodiments of the present invention are not limited to the specific details described above. Within the scope of the technical concept of the embodiments of the present invention, various simple modifications can be made to the technical solutions of the embodiments of the present invention, and these simple modifications all fall within the protection scope of the embodiments of the present invention. It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any suitable manner without contradiction. To avoid unnecessary repetition, the embodiments of the present invention will not further describe the various possible combinations.

[0088] Furthermore, various different embodiments of the present invention can be combined in any way, as long as they do not violate the spirit of the embodiments of the present invention, they should also be regarded as the content disclosed by the embodiments of the present invention.

Claims

1. A method for determining the type and distribution characteristics of core fluids, characterized in that, The method includes: Multiple experimental centrifugal forces were defined based on the working performance information of the centrifuge equipment, and experimental data of centrifugal nuclear magnetic resonance experiments were collected on the core under each experimental centrifugal force. Plot the T2 spectrum distribution curves corresponding to the experimental data under centrifugal force for each experiment, and plot the corresponding cumulative curves based on each T2 spectrum distribution curve; Multiple T2 cutoff values ​​are determined based on the distribution relationship between each T2 spectral distribution curve and each cumulative curve; High-pressure mercury intrusion test data of the corresponding core were collected, and the fluid type and the occurrence space of each fluid type of the corresponding core were determined based on the high-pressure mercury intrusion test data and each T2 cutoff value. The fluid distribution characteristics of the corresponding core are determined based on the fluid type and the occurrence space of each fluid type.

2. The method according to claim 1, characterized in that, The determination of multiple experimental centrifugal forces based on the performance information of the centrifuge equipment includes: The maximum centrifugal force of the corresponding equipment is determined based on the working performance information of the centrifuge equipment, and is used as the maximum centrifugal force for the experiment. The minimum centrifugal force that can generate the T2 spectrum distribution curve under saturated water conditions to meet the preset difference is taken as the experimental centrifugal force. Multiple unequal centrifugal forces are selected between the minimum centrifugal force and the maximum centrifugal force to serve as multiple intermediate centrifugal forces; The minimum centrifugal force, the maximum centrifugal force, and several intermediate centrifugal forces are used as the results of defining the experimental centrifugal force.

3. The method according to claim 1, characterized in that, Experimental data from centrifugation-based nuclear magnetic resonance experiments performed on cores under various experimental centrifugal forces were collected, including: Based on the defined experimental centrifugal force, the centrifuge equipment parameters were adjusted sequentially, and after each adjustment, a centrifugation nuclear magnetic resonance experiment was performed on the corresponding core, and the corresponding experimental data were collected.

4. The method according to claim 1, characterized in that, The determination of multiple T2 cutoff values ​​based on the distribution relationship between each T2 spectral distribution curve and each cumulative curve includes: The T2 value corresponding to the divergence point between the T2 spectrum distribution curve under the maximum centrifugal force condition and the T2 spectrum distribution curve under the preset saturated water condition is taken as the first T2 cutoff value. The first non-zero point along the x-axis of the T2 spectral distribution curve under the minimum centrifugal force condition is taken as the N2 cutoff value; N is the number of T2 spectral distribution curves; The T2 cutoff value for each medium centrifugal force is determined based on the cross relationship between the T2 spectrum distribution curve and the cumulative curve corresponding to each medium centrifugal force.

5. The method according to claim 4, characterized in that, When N is 4, determining the T2 cutoff value for each moderate centrifugal force based on the cross-relationship between the T2 spectral distribution curve and the cumulative curve corresponding to each moderate centrifugal force includes: The intersection of each cumulative curve with the y-axis is taken as the cumulative porosity value under the corresponding experimental centrifugal force; When the difference between the cumulative porosity value of the third experimental centrifugal force and the cumulative porosity value of the maximum experimental centrifugal force is greater than the difference between the cumulative porosity values ​​of the second and third experimental centrifugal forces, the cumulative curve of the third experimental centrifugal force is used as the confirmation curve corresponding to the second experimental centrifugal force; conversely, when the difference is less than the difference, the cumulative curve of the second experimental centrifugal force is used as the confirmation curve corresponding to the second experimental centrifugal force. The centrifugal force in the third experiment was greater than that in the second experiment. The intersection of the extension of the confirmation curve corresponding to the centrifugal force in the third experiment and the T2 spectrum distribution curve under the preset saturated water condition is taken as the second T2 cutoff value. The intersection of the extension of the cumulative curve corresponding to the minimum centrifugal force and the T2 spectrum distribution curve under the preset saturated water condition is taken as the third T2 cutoff value.

6. The method according to claim 5, characterized in that, The determination of fluid type and the occurrence space of each fluid type based on the high-pressure mercury injection experimental data and each T2 cutoff value includes: Based on the high-pressure mercury intrusion test data and the experimental data of centrifugal nuclear magnetic resonance experiments performed on the cores under centrifugal force in each experiment, the T2 spectrum distribution and pore radius correspondence are performed based on a preset correspondence; wherein, the T2 spectrum distribution is obtained based on historically retained T2 values; Based on the fact that the same sample has a unique corresponding pore radius and T2 value under the same wetting phase saturation condition, a conversion model is obtained based on the correspondence between the T2 spectrum distribution and the pore radius. Based on the aforementioned conversion model, the pore radius determined from the high-pressure mercury intrusion test data is converted into the corresponding T2 value; Based on the T2 value corresponding to each pore radius, the fluid type of the corresponding core and the occurrence space of each fluid type are determined.

7. The method according to claim 6, characterized in that, The fluid types include: Clay-bound fluids, capillary-bound fluids, tertiary free fluids, secondary free fluids, and primary free fluids.

8. The method according to claim 7, characterized in that, The determination of the fluid type and the storage space of each fluid type based on the T2 value corresponding to each pore radius includes: If the T2 value corresponding to the pore radius is less than the first T2 cutoff value, the corresponding fluid type is clay-bound fluid and the corresponding storage space is clay-bound pore. If the T2 value corresponding to the pore radius is between the first T2 cutoff value and the second T2 cutoff value, the corresponding fluid type is capillary-bound fluid, and the corresponding storage space is capillary-bound pore. If the T2 value corresponding to the pore radius is between the second T2 cutoff value and the third T2 cutoff value, the corresponding fluid type is a third-level free fluid and the corresponding storage space is a third-level free fluid pore. If the T2 value corresponding to the pore radius is between the third T2 cutoff value and the fourth T2 cutoff value, the corresponding fluid type is a second-order free fluid, and the corresponding storage space is a second-order free fluid pore. If the T2 value corresponding to the pore radius is greater than the fourth T2 cutoff value, the corresponding fluid type is a first-order free fluid, and the corresponding storage space is a first-order free fluid pore.

9. The method according to claim 1, characterized in that, The determination of fluid distribution characteristics of the corresponding core based on the fluid type and the occurrence space of each fluid type includes: Determine the saturation and porosity of the mobile fluid in the corresponding core under each experimental centrifugal force; The fluid distribution characteristics of the corresponding core are characterized based on the movable fluid saturation, the movable fluid porosity, the corresponding fluid type, and the occurrence space of the corresponding fluid type.

10. A system for determining the type and distribution characteristics of core fluids, characterized in that, The system includes: The acquisition unit is used to define multiple experimental centrifugal forces based on the working performance information of the centrifuge equipment, and to acquire experimental data of centrifugal nuclear magnetic resonance experiments performed on the core under each experimental centrifugal force. The processing unit is used to plot the T2 spectrum distribution curves corresponding to the experimental data under each experimental centrifugal force, and to plot the corresponding cumulative curves based on each T2 spectrum distribution curve. The determination unit is used to determine multiple T2 cutoff values ​​based on the distribution relationship between each T2 spectrum distribution curve and each cumulative curve; The determination unit is used to collect high-pressure mercury intrusion test data of the corresponding core and determine the fluid type and the storage space of each fluid type based on the high-pressure mercury intrusion test data and each T2 cutoff value. The output unit is used to determine the fluid distribution characteristics of the corresponding core based on the fluid type of the core and the occurrence space of each fluid type.

11. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores instructions that, when executed on a computer, cause the computer to perform the method for determining the core fluid type and distribution characteristics as described in any one of claims 1-9.

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