A method, system, logging tool, and medium for formation porosity measurement

Abstract

The application discloses a formation porosity measurement method, system, logging instrument and medium, and relates to the field of oil and natural gas development. First, the hot neutron counts detected by a first hot neutron detector and a second hot neutron detector in a D-D neutron porosity logging instrument are acquired respectively. Then, gamma time spectrum information detected by a gamma detector in the D-D neutron porosity logging instrument is acquired, and a wellbore Sigma value is determined according to the gamma time spectrum information. Finally, the formation porosity is determined by combining the first hot neutron count, the second hot neutron count and the wellbore Sigma value. The scheme does not need to measure the wellbore size and the fluid type, and improves the accuracy of formation porosity calculation.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of oil and gas development, in particular to a formation porosity measurement method, system, logging instrument and medium. BACKGROUND

[0002] Porosity is one of the basic parameters of formation evaluation, which is of great significance to formation lithology, gas layer judgment, reserve estimation, etc. The principle of neutron porosity logging is to utilize the difference in the slowing-down ability of neutrons by different element nuclei. The hydrogen element nuclei in the formation pore fluid slow down neutrons the most, so the greater the formation porosity, the more obvious the difference in the measured thermal neutron count. The conventional compensated neutron porosity instrument uses an Am-Be (americium-beryllium neutron source) neutron source and two He3 thermal neutron detectors to measure the porosity by establishing the response relationship between the near and far thermal neutron count ratio and the formation porosity. Since the Am-Be neutron source has a long half-life, there are great risks in source preservation, transportation and operation, and it is harmful to the environment and human body. Therefore, it is an inevitable trend to replace the Am-Be neutron source with a controllable neutron source (D-T (deuterium-tritium) source or D-D (deuterium-deuterium) source) for neutron porosity measurement.

[0003] The existing compensated neutron porosity instrument based on the controllable neutron source still uses a double-detector structure, and the porosity calculation method continues the original near and far thermal neutron ratio method. For the influence of the borehole size and fluid type, the borehole size and fluid parameters in the well are input to obtain a more accurate formation porosity value through a chart correction. The calculation method is complicated and the accuracy needs to be improved. SUMMARY

[0004] The purpose of the present application is to provide a formation porosity measurement method, system, logging instrument and medium. The D-D neutron porosity logging instrument is used to measure the formation porosity, without the need to measure the borehole size and fluid type of the calibration well, thereby simplifying the measurement process of the formation porosity and improving the accuracy of the measurement process.

[0005] To solve the above technical problems, the present application provides a formation porosity measurement method applied to a D-D neutron porosity logging instrument placed in a to-be-measured calibration well. The D-D neutron porosity logging instrument has a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source arranged in order from top to bottom. The method comprises:

[0006] Respectively acquiring the thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector to obtain a first thermal neutron count and a second thermal neutron count;

[0007] acquire gamma time spectrum information detected by the gamma detector, and determine a borehole Sigma value of the well to be measured according to the gamma time spectrum information;

[0008] determine formation porosity based on the first thermal neutron count, the second thermal neutron count, and the borehole Sigma value.

[0009] Optionally, the determination of the borehole Sigma value of the well to be measured according to the gamma time spectrum information comprises:

[0010] determine thermal neutron lifetime of the formation and corresponding gamma count according to the gamma time spectrum information;

[0011] determine thermal neutron lifetime of the borehole of the well to be measured by using a double exponential inversion formula, the thermal neutron lifetime of the formation, and the gamma count;

[0012] determine the borehole Sigma value of the well to be measured based on the thermal neutron lifetime of the borehole and a thermal neutron macroscopic capture cross-section formula of the borehole.

[0013] Optionally, the determination of the formation porosity based on the first thermal neutron count, the second thermal neutron count, and the borehole Sigma value comprises:

[0014] determine the formation porosity based on a self-compensated porosity calculation formula, a ratio of the second thermal neutron count and the first thermal neutron count, and the borehole Sigma value.

[0015] Optionally, before the acquisition of the first thermal neutron count and the second thermal neutron count detected by the first thermal neutron detector and the second thermal neutron detector respectively, the method further comprises:

[0016] determine structure parameters of the D-D neutron porosity logging instrument and measured data of a standard calibration well, the measured data comprising borehole size of the standard calibration well, fluid type in the standard calibration well, and formation porosity of the standard calibration well;

[0017] establish a three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, the borehole of the standard calibration well, and the formation corresponding to the standard calibration well based on the structure parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well;

[0018] simulate detection results of the first thermal neutron detector, the second thermal neutron detector, and the gamma detector of the D-D neutron porosity logging instrument when the D-D neutron porosity logging instrument detects other calibration wells by using the three-dimensional numerical calculation model, to obtain corresponding simulation results, wherein the other calibration wells have different borehole sizes and fluid types from the standard calibration well.

[0019] determine the self-compensated porosity calculation formula based on the simulation result.

[0020] Optionally, the three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, the borehole of the standard calibration well and the formation corresponding to the standard calibration well is established based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well, and the three-dimensional numerical calculation model comprises the following steps:

[0021] The three-dimensional numerical calculation model is constructed by using a Monte Carlo simulation method and based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well.

[0022] Optionally, after the three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, the borehole of the standard calibration well and the formation corresponding to the standard calibration well is established based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well, the method further comprises the following steps:

[0023] determining whether the absolute error between the simulated measured data of the standard calibration well simulated by the three-dimensional numerical calculation model and the measured data of the standard calibration well is less than a standard absolute error value;

[0024] If the absolute error is not less than the standard absolute error value, the three-dimensional numerical calculation model is adjusted and optimized so that the absolute error of the three-dimensional numerical calculation model after adjustment is less than the standard absolute error value.

[0025] Optionally, the self-compensated porosity calculation formula is determined based on the simulation result, and the method comprises the following steps:

[0026] The simulation result comprises formation porosity response data under different borehole sizes and fluid types, and the self-compensated porosity calculation formula is obtained by fitting and analyzing the simulation result by using a least square method.

[0027] To solve the above technical problem, the present application further provides a formation porosity measurement system applied to a D-D neutron porosity logging instrument placed in a to-be-measured calibration well, wherein the D-D neutron porosity logging instrument comprises, from top to bottom, a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source; the system comprises:

[0028] a first acquisition unit configured to acquire thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector respectively to obtain first thermal neutron counts and second thermal neutron counts;

[0029] A second acquisition unit is configured to acquire gamma time spectrum information detected by the gamma detector, and determine a borehole Sigma value of the calibration well according to the gamma time spectrum information.

[0030] A determination unit is configured to determine formation porosity based on the first thermal neutron count, the second thermal neutron count and the borehole Sigma value.

[0031] To solve the above technical problems, the present application further provides a D-D neutron porosity logging instrument, comprising:

[0032] A gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source are sequentially arranged from top to bottom.

[0033] A processor is connected with the gamma detector, the first thermal neutron detector, the second thermal neutron detector and the neutron source, and is configured to implement the steps of the formation porosity measurement method when executing the computer program.

[0034] To solve the above technical problems, the present application further provides a computer readable storage medium, wherein the computer readable storage medium stores a computer program, and the computer program is configured to implement the steps of the formation porosity measurement method when executed by a processor.

[0035] The present application aims to provide a formation porosity measurement method, system, logging instrument and medium, which firstly acquires thermal neutron counts detected by a first thermal neutron detector and a second thermal neutron detector of a D-D neutron porosity logging instrument, then acquires gamma time spectrum information detected by a gamma detector of the D-D neutron porosity logging instrument, and determines a borehole Sigma value according to the gamma time spectrum information, and finally determines formation porosity by combining the first thermal neutron count, the second thermal neutron count and the borehole Sigma value, which does not need to measure the borehole size and the fluid type, and improves the accuracy of formation porosity calculation. BRIEF DESCRIPTION OF DRAWINGS

[0036] In order to more clearly illustrate the technical solutions in the embodiments of the present application or the prior art, the following will briefly introduce the drawings needed to be used in the embodiments or prior art description. Obviously, the drawings in the following description are only embodiments of the present application, and for those skilled in the art, other drawings can be obtained without creative labor based on the provided drawings.

[0037] Figure 1 A process flow chart of a formation porosity measurement method provided by the present application;

[0038] Figure 2An XZ view of a D-D source three-probe neutron porosity instrument stratum numerical model provided by the present application;

[0039] Figure 3 An XY view of a D-D source three-probe neutron porosity instrument stratum numerical model provided by the present application;

[0040] Figure 4 A schematic diagram of a gamma time spectrum measured by an ultra-long gamma probe provided by the present application;

[0041] Figure 5 A schematic diagram of a stratum porosity result calculated by a near-far count ratio under different hole diameters provided by the present application;

[0042] Figure 6 A schematic diagram of a stratum porosity result calculated by a self-compensation method under different hole diameters provided by the present application;

[0043] Figure 7 A structural schematic diagram of a stratum porosity measurement system provided by the present application. DETAILED DESCRIPTION

[0044] The core of the present application is to provide a stratum porosity measurement method, system, logging instrument and medium, which does not need to measure the borehole size and fluid type of the calibration well, thereby simplifying the stratum porosity measurement process and improving the accuracy of the measurement process.

[0045] To make the objectives, technical solutions and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present application will be described clearly and completely below with reference to the drawings in the embodiments of the present application. Obviously, the described embodiments are some embodiments of the present application, rather than all the embodiments of the present application. Based on the embodiments in the present application, all other embodiments obtained by those skilled in the art without creative labor fall within the protection scope of the present application.

[0046] Please refer to Figure 1 , Figure 1 A process flowchart of a stratum porosity measurement method provided by the present application. It is applied to a D-D neutron porosity logging instrument placed in a to-be-measured calibration well, and the D-D neutron porosity logging instrument has a gamma probe, a first thermal neutron probe, a second thermal neutron probe and a neutron source arranged in sequence from top to bottom; the method comprises the following steps:

[0047] S11: respectively acquiring the thermal neutron counts detected by the first thermal neutron probe and the second thermal neutron probe to obtain a first thermal neutron count and a second thermal neutron count;

[0048] S12: Obtain the gamma time spectrum information detected by the gamma detector, and determine the borehole Sigma value of the to-be-measured calibration well according to the gamma time spectrum information;

[0049] S13: Determine the formation porosity based on the first thermal neutron count, the second thermal neutron count, and the borehole Sigma value.

[0050] In the present application, in order to measure the formation porosity corresponding to the to-be-measured calibration well, the first thermal neutron count detected by the first thermal neutron detector in the D-D neutron porosity logging instrument arranged in the to-be-measured calibration well and the second thermal neutron count detected by the second thermal neutron detector in the D-D neutron porosity logging instrument are obtained first, in addition, the gamma time spectrum information is detected by the gamma detector in the D-D neutron porosity logging instrument, and the borehole Sigma value of the to-be-measured calibration well is determined according to the gamma time spectrum information, and finally the formation porosity can be accurately determined according to the first thermal neutron count, the second thermal neutron count, and the borehole Sigma value, without measuring the borehole size and the fluid type of the calibration well, thereby simplifying the measurement process of the formation porosity and improving the accuracy of the measurement process.

[0051] The present embodiment provides a formation porosity measurement method, which first obtains the thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector in the D-D neutron porosity logging instrument, then obtains the gamma time spectrum information detected by the gamma detector in the D-D neutron porosity logging instrument, and determines the borehole Sigma value according to the gamma time spectrum information, and finally determines the formation porosity by combining the first thermal neutron count, the second thermal neutron count, and the borehole Sigma value, which does not need to measure the borehole size and the fluid type and improves the accuracy of the formation porosity calculation.

[0052] On the basis of the above-mentioned embodiments:

[0053] As an optional embodiment, the determination of the borehole Sigma value of the to-be-measured calibration well according to the gamma time spectrum information comprises:

[0054] determining the thermal neutron lifetime of the formation and the corresponding gamma count according to the gamma time spectrum information;

[0055] determining the thermal neutron lifetime of the borehole of the to-be-measured calibration well by using a double exponential inversion formula, the thermal neutron lifetime of the formation, and the gamma count;

[0056] determining the borehole Sigma value of the to-be-measured calibration well based on the thermal neutron lifetime of the borehole and a thermal neutron macroscopic capture cross-section formula of the borehole.

[0057] In the present application, firstly, the thermal neutron lifetime of the formation and the corresponding gamma count are determined according to the gamma time spectrum information, then the determined thermal neutron lifetime of the formation and the gamma count are calculated by using the double exponential inversion formula to obtain the thermal neutron lifetime of the borehole of the to-be-measured calibration well, and finally the borehole Sigma value of the to-be-measured calibration well is determined based on the thermal neutron lifetime of the borehole and the thermal neutron macroscopic capture cross section formula of the borehole, so that the borehole Sigma value of the to-be-measured calibration well is accurately determined.

[0058] It should be noted that the gamma time spectrum is processed by using the double exponential inversion method, and the double exponential inversion formula is as follows:

[0059]

[0060] In formula (1), N t is the gamma count at different times, A BH and A F are constant coefficients, t is time, the unit is mu s, tau BH and tau F are the thermal neutron lifetimes of the borehole and the formation respectively, the unit is mu s, and B is a local constant. The thermal neutron macroscopic capture cross section (Sigma) of the borehole can be expressed as:

[0061]

[0062] In formula (2), Sigma BH is the macroscopic capture cross section of the borehole, the unit is c.u., and v is the thermal neutron velocity at 25 DEG C, generally taken as 0.22 cm / mu s.

[0063] As an optional embodiment, the formation porosity is determined based on the first thermal neutron count, the second thermal neutron count and the borehole Sigma value, and the method comprises the following steps:

[0064] The formation porosity is determined based on the self-compensating porosity calculation formula, the ratio of the second thermal neutron count and the first thermal neutron count and the borehole Sigma value.

[0065] In the present application, the method for determining the formation porosity corresponding to the to-be-measured calibration well is specifically as follows: the formation porosity corresponding to the to-be-measured calibration well is determined based on the self-compensating porosity calculation formula, the ratio of the second thermal neutron count and the first thermal neutron count and the borehole Sigma value.

[0066] It should be noted that the relationship between the formation porosity and the ratio of the near thermal neutron count and the far thermal neutron count (wherein the near thermal neutron count is the second thermal neutron count, and the far thermal neutron count is the first thermal neutron count) and the borehole Sigma can be expressed as: The formation porosity value is phi, the unit is p.u., N S and N LThe near and far thermal neutron counts are respectively a second thermal neutron count and a first thermal neutron count.

[0067] As an optional embodiment, before the thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector are respectively acquired, the method further comprises the following steps of:

[0068] The structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well are determined, and the measured data comprises the borehole size of the standard calibration well, the fluid type in the standard calibration well and the formation porosity of the standard calibration well.

[0069] A three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, the borehole of the standard calibration well and the formation corresponding to the standard calibration well is established based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well.

[0070] The detection results of the first thermal neutron detector, the second thermal neutron detector and the gamma detector of the D-D neutron porosity logging instrument when detecting other calibration wells are simulated by using the three-dimensional numerical calculation model to obtain corresponding simulation results, wherein the other calibration wells have different borehole sizes and fluid types from the standard calibration well.

[0071] The self-compensating porosity calculation formula is determined based on the simulation results.

[0072] In the present application, before the thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector are respectively acquired, the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well are determined, and then a three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, the borehole of the standard calibration well and the formation corresponding to the standard calibration well is established based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well, so as to simulate the detection results of the first thermal neutron detector, the second thermal neutron detector and the gamma detector of the D-D neutron porosity logging instrument when detecting other calibration wells by using the three-dimensional numerical calculation model to obtain corresponding simulation results, and finally the self-compensating porosity calculation formula is determined based on the simulation results, so as to obtain the self-compensating porosity calculation formula by simulating the detection results of the three detectors under different conditions, that is, to accurately obtain the corresponding relationship among the formation porosity, the thermal neutron count ratio and the borehole Sigma value.

[0073] It should be noted that the determination process of the measured data of the standard calibration well comprises calibrating the three-detector D-D neutron porosity logging instrument in the standard borehole size and the calibration well filled with the known fluid type and different porosities to obtain the relationship between the near and far detector thermal neutron count ratio and the porosity, wherein the relationship between the near and far thermal neutron count ratio and the formation porosity after the standard well diameter neutron porosity calibration well is calibrated can be expressed as: wherein φ is the formation porosity value, in p.u., N S and N L are the near and far thermal neutron counts, k and b are constant coefficients, the values of which are affected by the wellbore environment and the formation environment, and can be obtained by fitting the calibration well data.

[0074] It should be further noted that the XZ view and the XY view of the three-dimensional numerical calculation model are as shown in Figures 1 and 2, respectively. Figure 2 and Figure 3 The instrument formation includes 1, a D-D neutron tube control system, 2, a D-D neutron tube target area, 3, a shielding body, 4, a near He3 thermal neutron detector (a second thermal neutron detector), 5, a shielding body, 6, a far He3 thermal neutron detector (a first thermal neutron detector), 7, a shielding body, 8, a gamma detector, 9, an instrument shell, 10, a formation, and 11, a wellbore.

[0075] As an optional embodiment, a three-dimensional numerical calculation model of a D-D neutron porosity logging instrument, a wellbore of a standard calibration well, and a formation corresponding to the standard calibration well is established based on structural parameters of the D-D neutron porosity logging instrument and measured data of the standard calibration well, and includes:

[0076] The three-dimensional numerical calculation model is constructed by using a Monte Carlo simulation method and based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well.

[0077] In the present application, the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well are simulated by using a Monte Carlo simulation method, so as to construct the three-dimensional numerical calculation model.

[0078] It should be noted that the three-dimensional numerical calculation model can be established by using a Monte Carlo simulation method based on the structural parameters of the three-detector D-D neutron porosity logging instrument and the parameters of the standard calibration well, and the geometric structure of the instrument and the detector is defined by using a cell card in the Monte Carlo simulation software, the material composition of the instrument and the formation and the emission mode of the D-D source are defined by using a material card and a source data card in the Monte Carlo simulation software, and the establishment of the three-dimensional numerical calculation model can also be realized. In this process, the Monte Carlo simulation software can use MCNP (Monte Carlo N Particle Transport code), SuperMC (Super Monte Carlo Simulation Program for Nuclear and Radiation Process), Geant4 (GEometry ANd Tracking), etc.

[0079] As an optional embodiment, after establishing the three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, the borehole of the standard calibration well and the formation corresponding to the standard calibration well based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well, the method further comprises:

[0080] judging whether the absolute error between the simulated measured data of the standard calibration well simulated by the three-dimensional numerical calculation model and the measured data of the standard calibration well is less than a standard absolute error value;

[0081] If the absolute error is not less than the standard absolute error value, the three-dimensional numerical calculation model is adjusted and optimized so that the absolute error of the adjusted three-dimensional numerical calculation model is less than the standard absolute error value.

[0082] In the present application, after establishing the three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, the borehole of the standard calibration well and the formation corresponding to the standard calibration well based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well, it is necessary to judge whether the absolute error between the simulated measured data of the standard calibration well simulated by the three-dimensional numerical calculation model and the measured data of the standard calibration well is less than a standard absolute error value. If the absolute error is not less than the standard absolute error value, the three-dimensional numerical calculation model is adjusted and optimized so that the absolute error of the adjusted three-dimensional numerical calculation model is less than the standard absolute error value, the optimization of the three-dimensional numerical calculation model is realized, the three-dimensional numerical calculation model generates more accurate simulation data, and the accuracy of the scheme is improved.

[0083] It should be noted that in the numerical simulation process, the formation porosity is set to 0.1 p.u., 5.0 p.u., 13.2 p.u., 20.2 p.u., 23.5 p.u., 30.0 p.u., 37.2 p.u., 52.9 p.u. and 100 p.u., the formation lithology is limestone, and the instrument is measured close to the well wall during simulation. In order to increase the matching degree of the numerical calculation model and the actual instrument, the measured data of the standard calibration well and the MCNP numerical simulation calibration data are compared, and the absolute error and the relative error of simulation and measurement are defined as:

[0084] σ A =|p M -p S |; (3)

[0085]

[0086] In formula (3) and formula (4), σ A and σ R are the absolute error and the relative error, respectively, p Mp is a measured value S For the numerical simulation value, in order to ensure the accuracy of the numerical calculation, the relative error of the detector count is required to be less than the standard relative error value, and the absolute error of the near-far count ratio is required to be less than the standard absolute error value when the three-dimensional numerical calculation model is fed back. In practical application, the standard relative error value is generally 5%, and the standard absolute error value is generally 1%.

[0087] It should be noted that, by using the optimized three-dimensional numerical calculation model, the near-far detector thermal neutron count and the ultra-far gamma detector time spectrum are simulated and calculated by changing the borehole size and the type of fluid in the well. The borehole size ranges from 15 cm to 40 cm with an interval of 2 cm, and the fluid type in the well includes fresh water, oil, gas, salinity water and oil-water mixture. The response of the gamma time spectrum is shown in Figure 4 The horizontal coordinate in the figure is time, unit: μs, and the vertical coordinate is gamma count, unit: cps. It can be seen from the figure that 0-300 μs is the borehole decay zone, and 450-1800 μs is the formation decay zone. The gamma count decay obeys the exponential decay law.

[0088] As an optional embodiment, the self-compensating porosity calculation formula is determined based on the simulation results, which comprises:

[0089] The self-compensating porosity calculation formula is obtained by fitting and analyzing the simulation results by using the least square method. The simulation results include the formation porosity response data under different borehole sizes and fluid types.

[0090] In the present application, the self-compensating porosity calculation formula is obtained by fitting and analyzing the simulation results by using the least square method, that is, the self-compensating porosity calculation formula is obtained by fitting and analyzing the formation porosity response data under different borehole sizes and fluid types by using the least square method, so that the self-compensating porosity calculation formula is obtained.

[0091] It should be noted that, Figure 5 The result of determining the porosity by using the near-far count ratio under different borehole diameters is shown in the figure. It can be seen from the figure that the change of the borehole diameter has a great influence on the calculation of the formation porosity. The absolute error of the porosity increases by 1 p.u. when the borehole diameter increases by 1.5 cm in the conventional near-far count ratio calculation method. Figure 6 The self-compensating method proposed in the present application is used to calculate the formation porosity under different borehole diameters. Compared with Figure 5 and Figure 6 , the self-compensating method greatly reduces the error of the formation porosity calculation caused by the change of the borehole diameter, and improves the calculation accuracy of the formation porosity.

[0092] Please refer to Figure 7 , Figure 7A structural schematic diagram of a formation porosity measurement system is provided. The system is applied to a D-D neutron porosity logging instrument placed in a calibration well to be measured. The D-D neutron porosity logging instrument is sequentially provided with a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source from top to bottom. The system comprises:

[0093] A first acquisition unit 21 is configured to acquire thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector respectively, so as to obtain first thermal neutron counts and second thermal neutron counts.

[0094] A second acquisition unit 22 is configured to acquire gamma time spectrum information detected by the gamma detector, and determine a borehole Sigma value of the calibration well according to the gamma time spectrum information.

[0095] A determination unit 23 is configured to determine formation porosity based on the first thermal neutron counts, the second thermal neutron counts and the borehole Sigma value.

[0096] The formation porosity measurement system provided in the embodiment corresponds to the method described above, and has the same beneficial effects as the method described above. Therefore, the embodiments of the formation porosity measurement system are described in the description of the embodiments of the method, and will not be described here.

[0097] The application further provides a corresponding embodiment of a D-D neutron porosity logging instrument, comprising:

[0098] The gamma detector, the first thermal neutron detector, the second thermal neutron detector and the neutron source are sequentially arranged from top to bottom.

[0099] A processor is connected with the gamma detector, the first thermal neutron detector, the second thermal neutron detector and the neutron source, and is configured to implement the steps of the formation porosity measurement method when executing a computer program.

[0100] The processor can include one or more processing cores, such as a 4-core processor, an 8-core processor, etc. The processor can be implemented in at least one of a hardware form of a digital signal processor (DSP), a field-programmable gate array (FPGA), a programmable logic array (PLA). The processor can also include a main processor and a coprocessor. The main processor is a processor for processing data in an awake state, also known as a central processing unit (CPU). The coprocessor is a low-power processor for processing data in a standby state. In some embodiments, the processor can be integrated with a graphics processor (GPU) for rendering and drawing content required to be displayed by the display screen. In some embodiments, the processor can also include an artificial intelligence (AI) processor for processing machine learning-related computing operations.

[0101] The D-D neutron porosity logging instrument provided in the embodiment corresponds to the above method, and therefore has the same beneficial effects as the above method. Therefore, the embodiments of the D-D neutron porosity logging instrument are described in the description of the embodiments of the method, and will not be described here.

[0102] The present application also provides an embodiment corresponding to a computer-readable storage medium, and the computer-readable storage medium stores a computer program. When the computer program is executed by a processor, the steps of the above formation porosity measurement method are implemented.

[0103] It can be understood that if the method in the above embodiment is implemented in the form of a software function unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the technical solutions of the present application or the whole or part of the technical solutions that essentially contribute to the prior art can be embodied in the form of a software product. The computer software product is stored in a storage medium, and executes all or part of the steps of the method of each embodiment of the present application. The foregoing storage medium includes a U disk, a mobile hard disk, a read-only memory (ROM), a random access memory (RAM), a magnetic disk or an optical disk, and various program code storage media.

[0104] The computer readable storage medium provided by the embodiment corresponds to the method, and has the same beneficial effects as the method. Therefore, the embodiments of the computer readable storage medium are described in the description of the embodiments of the method, and are not described here.

[0105] It should be noted that the relative terms, such as first and second, and the like, are used herein only to distinguish one entity or action from another, and do not necessarily require or imply any actual such relationship or order between or among these entities or actions. Moreover, the terms "comprising", "including", or any other variant thereof are intended to cover a non-exclusive inclusion, so that a process, method, article, or apparatus that includes a list of elements not only includes those elements, but also includes other elements not expressly listed or inherent to such process, method, article, or apparatus. Without more limitations, an element defined by the statement "comprising a" does not exclude the existence of additional identical elements in the process, method, article, or apparatus that includes the element.

[0106] The above description of the disclosed embodiments enables a person skilled in the art to implement or use the present application. Various modifications to the embodiments will be apparent to those skilled in the art, and the general principles defined herein can be implemented in other embodiments without departing from the spirit or scope of the present application. Therefore, the present application will not be limited to the embodiments shown herein, but will conform to the widest scope consistent with the principles and novel features disclosed herein.

Claims

1. A method of formation porosity measurement, characterized by, The application is applied to a D-D neutron porosity logging instrument placed in a to-be-measured calibration well, wherein a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source are sequentially arranged from top to bottom in the D-D neutron porosity logging instrument; the method comprises the following steps: respectively acquiring thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector to obtain first thermal neutron counts and second thermal neutron counts; acquiring gamma time spectrum information detected by the gamma detector, and determining a borehole Sigma value of the to-be-measured calibration well according to the gamma time spectrum information; determining formation porosity based on the first thermal neutron counts, the second thermal neutron counts and the borehole Sigma value; the step of determining the borehole Sigma value of the to-be-measured calibration well according to the gamma time spectrum information comprises the following steps: determining thermal neutron lifetime of a formation and corresponding gamma counts according to the gamma time spectrum information; determining thermal neutron lifetime of a borehole by using a double exponential inversion formula, the thermal neutron lifetime of the formation and the gamma counts; determining the borehole Sigma value of the to-be-measured calibration well based on the thermal neutron lifetime of the borehole and a thermal neutron macroscopic capture cross-section formula of the borehole; the step of determining formation porosity based on the first thermal neutron counts, the second thermal neutron counts and the borehole Sigma value comprises the following step: determining formation porosity based on a self-compensating porosity calculation formula, a ratio of the second thermal neutron counts and the first thermal neutron counts and the borehole Sigma value; before the step of respectively acquiring thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector, the method further comprises the following steps: determining structural parameters of the D-D neutron porosity logging instrument and measured data of a standard calibration well, wherein the measured data comprises borehole size of the standard calibration well, fluid type in the standard calibration well and formation porosity of the standard calibration well; establishing a three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, a borehole of the standard calibration well and a corresponding formation of the standard calibration well based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well; simulating detection results of the first thermal neutron detector, the second thermal neutron detector and the gamma detector of the D-D neutron porosity logging instrument when detecting other calibration wells by using the three-dimensional numerical calculation model to obtain corresponding simulation results, wherein the other calibration wells have different borehole sizes and fluid types from the standard calibration well; determining the self-compensating porosity calculation formula based on the simulation results.

2. The method of formation porosity measurement of claim 1, wherein, the step of establishing a three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, a borehole of the standard calibration well and a corresponding formation of the standard calibration well based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well comprises the following step: constructing the three-dimensional numerical calculation model by using a Monte Carlo simulation method and based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well.

3. The method of formation porosity measurement of claim 1, wherein, The three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, the borehole of the standard calibration well, and the formation corresponding to the standard calibration well is established based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well, and the method further comprises the following steps of: determining whether the absolute error between the simulated measured data of the standard calibration well simulated by the three-dimensional numerical calculation model and the measured data of the standard calibration well is less than a standard absolute error value; if the absolute error is not less than the standard absolute error value, the three-dimensional numerical calculation model is adjusted and optimized so that the absolute error of the adjusted three-dimensional numerical calculation model is less than the standard absolute error value.

4. The method of formation porosity measurement of any one of claims 1 to 3, wherein, The self-compensated porosity calculation formula is determined based on the simulation result, and the method comprises the following steps of: fitting and analyzing the simulation result by using the least square method to obtain the self-compensated porosity calculation formula; wherein the simulation result comprises formation porosity response data under different borehole sizes and fluid types.

5. A formation porosity measurement system characterized by, The system is applied to a D-D neutron porosity logging instrument placed in a to-be-measured calibration well, and the D-D neutron porosity logging instrument comprises, from top to bottom, a gamma detector, a first thermal neutron detector, a second thermal neutron detector, and a neutron source; the system comprises: a first acquisition unit configured to acquire thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector respectively to obtain first thermal neutron counts and second thermal neutron counts; a second acquisition unit configured to acquire gamma time spectrum information detected by the gamma detector and determine a borehole Sigma value of the calibration well according to the gamma time spectrum information; a determination unit configured to determine formation porosity based on the first thermal neutron counts, the second thermal neutron counts, and the borehole Sigma value; The second acquisition unit is specifically configured to: determine thermal neutron lifetime of the formation and corresponding gamma counts according to the gamma time spectrum information; determine thermal neutron lifetime of the borehole of the to-be-measured calibration well by using a double exponential inversion formula, the thermal neutron lifetime of the formation, and the gamma counts; determine the borehole Sigma value of the to-be-measured calibration well based on the thermal neutron lifetime of the borehole and a thermal neutron macroscopic capture cross-section formula of the borehole; The determination unit is specifically configured to: determine formation porosity based on a self-compensated porosity calculation formula, a ratio of the second thermal neutron counts and the first thermal neutron counts, and the borehole Sigma value; The formation porosity measurement system is further configured to: determine structural parameters of the D-D neutron porosity logging instrument and measured data of a standard calibration well, wherein the measured data comprises borehole size of the standard calibration well, fluid type in the standard calibration well, and formation porosity of the standard calibration well; establish a three-dimensional numerical calculation model of the D-D neutron porosity logging instrument, the borehole of the standard calibration well, and the formation corresponding to the standard calibration well based on the structural parameters of the D-D neutron porosity logging instrument and the measured data of the standard calibration well; The three-dimensional numerical calculation model is used to simulate the detection results of the first thermal neutron detector, the second thermal neutron detector and the gamma detector of the D-D neutron porosity logging tool when detecting other calibration wells, to obtain corresponding simulation results; wherein the other calibration wells have different borehole sizes and fluid types from the standard calibration well. The self-compensation porosity calculation formula is determined based on the simulation results.

6. A D-D neutron porosity tool characterized by, The method comprises the following steps: a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source are sequentially arranged from top to bottom; a processor connected with the gamma detector, the first thermal neutron detector, the second thermal neutron detector and the neutron source, used to execute the computer program to realize the steps of the formation porosity measurement method according to any one of claims 1 to 4.

7. A computer readable storage medium characterized in that, The computer readable storage medium stores a computer program, and the computer program is executed by the processor to realize the steps of the formation porosity measurement method according to any one of claims 1 to 4.

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