Formation porosity measuring method and system, logging instrument and medium

Abstract

The invention discloses a formation porosity measuring method, a formation porosity measuring system, a logging instrument and a medium, and relates to the field of petroleum and natural gas development. Firstly, thermal neutron counts detected by a first thermal neutron detector and a second thermal neutron detector in a D-D neutron porosity logging instrument are obtained respectively; the method comprises the steps of firstly obtaining a first thermal neutron count and a second thermal neutron count, then obtaining gamma time spectrum information detected by a gamma detector in a D-D neutron porosity logging instrument, determining a borehole Sigma value according to the gamma time spectrum information, and finally determining the formation porosity by combining the first thermal neutron count, the second thermal neutron count and the borehole Sigma value. And the accuracy of formation porosity calculation is improved.

Description

Technical Field

[0001] The invention relates to the field of oil and natural gas development, and in particular to a formation porosity measurement method, system, well logging instrument and medium. Background Art

[0002] Porosity is one of the basic parameters for formation evaluation, and is of great significance for formation lithology, gas layer judgment, and reserve assessment. The principle of neutron porosity logging is to use the difference in the deceleration ability of atomic nuclei of different elements to neutrons. The atomic nuclei of hydrogen in the formation pore fluid have the strongest deceleration to neutrons. Therefore, the greater the formation porosity, the more obvious the difference in the measured thermal neutron counts. Conventional compensated neutron porosity instruments use Am-Be (americium-beryllium neutron source) neutron sources and two He3 thermal neutron detectors to achieve porosity measurement by establishing a response relationship between the near and far thermal neutron count ratio and formation porosity. Due to the long half-life of the Am-Be neutron source, there are great risks in source storage, transportation, and construction, and it is harmful to the environment and human body. It is an inevitable trend for future development to use a controlled neutron source (DT (deuterium-tritium) source or DD (deuterium-deuterium) source) to replace the Am-Be neutron source for neutron porosity measurement.

[0003] The existing controlled neutron source-based compensated neutron porosity instrument still uses a dual-detector structure, and the porosity calculation method continues the original near-far thermal neutron ratio method. For the influence of wellbore size and fluid type, it is necessary to input the wellbore size and wellbore fluid parameters, and obtain a more accurate formation porosity value through plate correction. The calculation method is cumbersome and the accuracy needs to be improved. Summary of the invention

[0004] The purpose of the present invention is to provide a formation porosity measurement method, system, logging instrument and medium. The present invention uses a DD neutron porosity logging instrument to measure the formation porosity without measuring the wellbore size and fluid type of the calibrated well, thereby simplifying the formation porosity measurement process and improving the accuracy of the measurement process.

[0005] In order to solve the above technical problems, the present invention provides a formation porosity measurement method, which is applied to a DD neutron porosity logging instrument placed in a calibration well to be measured, wherein the DD neutron porosity logging instrument is provided with a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source in order from top to bottom; the method comprises:

[0006] Respectively acquiring 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 the gamma time spectrum information detected by the gamma detector, and determine the borehole Sigma value of the calibration well to be measured according to the gamma time spectrum information;

[0008] A formation porosity is determined based on the first thermal neutron count, the second thermal neutron count, and the wellbore Sigma value.

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

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

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

[0012] The wellbore Sigma value of the calibration well to be measured is determined based on the thermal neutron lifetime of the wellbore and the thermal neutron macroscopic capture cross section formula of the wellbore.

[0013] Optionally, determining the formation porosity based on the first thermal neutron count, the second thermal neutron count and the wellbore Sigma value includes:

[0014] The formation porosity is determined based on a self-compensating porosity calculation formula, a ratio of the second thermal neutron count to the first thermal neutron count, and the wellbore Sigma value.

[0015] Optionally, before respectively acquiring the thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector, the method further includes:

[0016] Determining the structural parameters of the DD neutron porosity logging instrument and the measured data of the standard calibration well, wherein the measured data includes the wellbore size of the standard calibration well, the fluid type in the standard calibration well, and the formation porosity of the standard calibration well;

[0017] A three-dimensional numerical calculation model of the DD neutron porosity logging instrument, the wellbore of the standard calibration well, and the formation corresponding to the standard calibration well is established based on the structural parameters of the DD neutron porosity logging instrument and the measured data of the standard calibration well;

[0018] 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 when the DD neutron porosity logging instrument detects other calibration wells, so as to obtain corresponding simulation results; wherein the other calibration wells have different wellbore sizes and fluid types from the standard calibration well;

[0019] The self-compensating porosity calculation formula is determined based on the simulation results.

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

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

[0022] Optionally, after establishing the three-dimensional numerical calculation model of the DD neutron porosity logging instrument, the wellbore of the standard calibration well, and the formation corresponding to the standard calibration well based on the structural parameters of the DD neutron porosity logging instrument and the measured data of the standard calibration well, the method further includes:

[0023] Determine 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 the 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 optimized and adjusted so that the absolute error of the adjusted three-dimensional numerical calculation model is less than the standard absolute error value.

[0025] Optionally, determining the self-compensating porosity calculation formula based on the simulation result includes:

[0026] The simulation results are fitted and analyzed using the least square method to obtain the self-compensating porosity calculation formula; wherein the simulation results include formation porosity response data under different wellbore sizes and fluid types.

[0027] In order to solve the above technical problems, the present invention also provides a formation porosity measurement system, which is applied to a DD neutron porosity logging instrument placed in a calibration well to be measured, wherein the DD neutron porosity logging instrument is provided with a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source in order from top to bottom; the system comprises:

[0028] A first acquisition unit, used to respectively acquire 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;

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

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

[0031] In order to solve the above technical problems, the present invention also provides a DD neutron porosity logging tool, comprising:

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

[0033] A processor, wherein the processor is respectively connected to the gamma detector, the first thermal neutron detector, the second thermal neutron detector and the neutron source, and is used to implement the steps of the above-mentioned formation porosity measurement method when executing the computer program.

[0034] In order to solve the above technical problem, the present invention also provides a computer-readable storage medium, on which a computer program is stored. When the computer program is executed by a processor, the steps of the above-mentioned formation porosity measurement method are implemented.

[0035] The purpose of the present invention is to provide a formation porosity measurement method, system, logging instrument and medium. First, the thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector in the DD neutron porosity logging instrument are respectively obtained, and then the gamma time spectrum information detected by the gamma detector in the DD neutron porosity logging instrument is obtained, and the wellbore Sigma value is determined according to the gamma time spectrum information. Finally, the formation porosity is determined by combining the first thermal neutron count, the second thermal neutron count and the wellbore Sigma value. This scheme does not require the measurement of wellbore size and fluid type, and improves the accuracy of formation porosity calculation. BRIEF DESCRIPTION OF THE DRAWINGS

[0036] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on the provided drawings without paying creative work.

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

[0038] Figure 2An XZ view of a formation numerical model of a DD source three-detector neutron porosity instrument provided by the present invention;

[0039] Figure 3 An XY view of a formation numerical model of a DD source three-detector neutron porosity instrument provided by the present invention;

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

[0041] Figure 5 A schematic diagram of formation porosity results calculated by near-far counting ratios under different well diameters provided by the present invention;

[0042] Figure 6 A schematic diagram of formation porosity results calculated by a self-compensation method under different well diameters provided by the present invention;

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

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

[0045] In order to make the purpose, technical solution and advantages of the embodiments of the present invention clearer, the technical solution in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0046] Please refer to Figure 1 , Figure 1 A process flow chart of a formation porosity measurement method provided by the present invention. The method is applied to a DD neutron porosity logging instrument placed in a calibration well to be measured, wherein a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source are sequentially arranged in the DD neutron porosity logging instrument from top to bottom; the method comprises:

[0047] S11: respectively acquiring 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;

[0048] S12: Obtaining gamma time spectrum information detected by the gamma detector, and determining the borehole Sigma value of the calibration well to be measured 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 wellbore Sigma value.

[0050] In the present invention, in order to measure the formation porosity corresponding to the calibration well to be measured, it is necessary to use a DD neutron porosity logging instrument arranged in the calibration well to be measured, first obtain the first thermal neutron count detected by the first thermal neutron detector in the DD neutron porosity logging instrument and the second thermal neutron count detected by the second thermal neutron detector in the DD neutron porosity logging instrument, in addition, it is also necessary to use the gamma detector in the DD neutron porosity logging instrument to detect the gamma time spectrum information, and determine the wellbore Sigma value of the calibration well to be measured according to the gamma time spectrum information, finally, the formation porosity can be accurately determined according to the first thermal neutron count, the second thermal neutron count and the wellbore Sigma value, without measuring the wellbore size and fluid type of the calibration well, thereby simplifying the formation porosity measurement process and improving the accuracy of the measurement process.

[0051] The present embodiment provides a formation porosity measurement method, firstly, thermal neutron counts detected by a first thermal neutron detector and a second thermal neutron detector in a DD neutron porosity logging instrument are respectively obtained, then the gamma time spectrum information detected by a gamma detector in the DD neutron porosity logging instrument is obtained, and the wellbore Sigma value is determined according to the gamma time spectrum information, and finally the formation porosity is determined by combining the first thermal neutron count, the second thermal neutron count and the wellbore Sigma value. This scheme does not require the measurement of wellbore size and fluid type, and improves the accuracy of formation porosity calculation.

[0052] Based on the above embodiments:

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

[0054] Determine the thermal neutron lifetime and corresponding gamma count of the formation based on the gamma time spectrum information;

[0055] The thermal neutron lifetime of the borehole of the calibration well to be tested is determined by using the double exponential inversion formula, the thermal neutron lifetime of the formation and the gamma count;

[0056] The wellbore Sigma value of the calibration well to be measured is determined based on the wellbore thermal neutron lifetime and the wellbore thermal neutron macroscopic capture cross section formula.

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

[0058] It should be noted that the double exponential inversion method is used to process the gamma time spectrum. The double exponential inversion formula is:

[0059]

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

[0061]

[0062] In formula (2), ∑ BH is the macroscopic capture cross section of the wellbore, in units of cu, v is the thermal neutron velocity at 25°C, and is generally taken as 0.22cm / μs.

[0063] As an optional embodiment, determining the formation porosity based on the first thermal neutron count, the second thermal neutron count and the borehole Sigma value includes:

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

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

[0066] It should be noted that the relationship between formation porosity, near-to-far thermal neutron count ratio (where near neutron count is the second thermal neutron count and far neutron count is the first thermal neutron count) and wellbore Sigma can be expressed as: φ is the formation porosity value, the unit is pu, N S and N LThey are near and far thermal neutron counts, namely the second thermal neutron count and the first thermal neutron count.

[0067] As an optional embodiment, before respectively acquiring the thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector, the method further includes:

[0068] Determine the structural parameters of the DD neutron porosity logging tool and the measured data of the standard calibration well, the measured data including the wellbore size of the standard calibration well, the fluid type in the standard calibration well and the formation porosity of the standard calibration well;

[0069] Based on the structural parameters of the DD neutron porosity logging tool and the measured data of the standard calibration well, a three-dimensional numerical calculation model of the DD neutron porosity logging tool, the wellbore of the standard calibration well and the formation corresponding to the standard calibration well is established;

[0070] 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 DD neutron porosity logging tool when detecting other calibration wells, so as to obtain corresponding simulation results; wherein the other calibration wells have different wellbore sizes and fluid types from the standard calibration wells;

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

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

[0073] It should be noted that the process of determining the measured data of the standard calibration well includes placing the three-detector DD neutron porosity logging instrument in a calibration well of different porosities with a standard borehole size and filled with known fluid types to calibrate, and obtain the relationship between the near and far detector thermal neutron count ratio and porosity. After calibration of the standard borehole neutron porosity calibration well, the relationship between the near and far thermal neutron count ratio and formation porosity can be expressed as: Where φ is the formation porosity value, in units of pu, N S and N L are the near and far thermal neutron counts, respectively. k and b are constant coefficients, whose values ​​are affected by the borehole environment and formation environment and can be obtained by fitting the calibrated well data.

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

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

[0076] A three-dimensional numerical calculation model was constructed using the Monte Carlo simulation method based on the structural parameters of the DD neutron porosity logging tool and the measured data of standard scale wells.

[0077] In the present invention, the Monte Carlo simulation method is used to simulate the structural parameters of the DD neutron porosity logging instrument and the measured data of the standard calibration well, so as to construct a three-dimensional numerical calculation model, and accurately construct a three-dimensional numerical calculation model.

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

[0079] As an optional embodiment, after establishing a three-dimensional numerical calculation model of the DD neutron porosity logging tool, the wellbore of the standard calibration well, and the formation corresponding to the standard calibration well based on the structural parameters of the DD neutron porosity logging tool and the measured data of the standard calibration well, it also includes:

[0080] Determine 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 the 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 optimized and adjusted 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 invention, after establishing a three-dimensional numerical calculation model of the DD neutron porosity logging instrument, the wellbore of the standard calibration well and the formation corresponding to the standard calibration well based on the structural parameters of the DD neutron porosity logging instrument and the measured data of the standard calibration well, it is also necessary to determine 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 the standard absolute error value. If the absolute error is not less than the standard absolute error value, the three-dimensional numerical calculation model is optimized and adjusted so that the absolute error of the adjusted three-dimensional numerical calculation model is less than the standard absolute error value, thereby optimizing the three-dimensional numerical calculation model, facilitating the three-dimensional numerical calculation model to generate more accurate simulation data, and improving the accuracy of the solution.

[0083] It should be noted that in the numerical simulation process, the formation porosity was set to 0.1pu, 5.0pu, 13.2pu, 20.2pu, 23.5pu, 30.0pu, 37.2pu, 52.9pu and 100p.u., the formation lithology was limestone, and the instrument was close to the well wall for measurement during the simulation. In order to increase the matching degree between the numerical calculation model and the actual instrument, the measured data of the standard scale well was compared with the MCNP numerical simulation scale data, and the absolute error and relative error between the simulation and the actual measurement were 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 relative error, respectively, Mis the measured value, p S It is a numerical simulation value. In order to ensure the accuracy of numerical calculation when feeding back the three-dimensional numerical calculation model, it is required that the relative error of detector counting is smaller than the standard relative error value, and the absolute error of near-far counting ratio is smaller than the standard absolute error value. In practical applications, the standard relative error value is generally 5%, and the standard absolute error value is generally 1%.

[0087] It should also be noted that the optimized three-dimensional numerical calculation model is used to change the borehole size and the fluid type in the well to simulate the thermal neutron counts of the near and far detectors and the time spectrum of the ultra-far gamma detector. The borehole size range is 15cm-40cm, with an interval of 2cm. The fluid types in the well include fresh water, oil, gas, salinized water and oil-water mixture. The response of the gamma time spectrum is as follows: Figure 4 As shown, the horizontal axis in the figure is time, unit μs, and the vertical axis is gamma count, unit cps. It can be seen from the figure that 0-300μs is the borehole attenuation zone, 450-1800μs is the formation attenuation zone, and the gamma count attenuation obeys the exponential attenuation law.

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

[0089] The least squares method is used to fit the simulation results to obtain the self-compensating porosity calculation formula; the simulation results include formation porosity response data under different wellbore sizes and fluid types.

[0090] In the present invention, the least squares method is used to fit the simulation results to obtain the self-compensating porosity calculation formula, that is, the least squares method is used to fit the formation porosity response data under different wellbore sizes and fluid types to obtain the self-compensating porosity calculation formula, and the self-compensating porosity calculation formula is accurately obtained.

[0091] It should be noted that Figure 5 The figure shows the results of determining porosity using the near-far count ratio under different borehole diameter conditions. It can be clearly seen from the figure that changes in well diameter have a great influence on the calculation of formation porosity. For the conventional method of calculating porosity using the near-far count ratio, the absolute error of porosity increases by 1 p.u. for every 1.5 cm increase in borehole diameter. Figure 6 In order to use the self-compensation method proposed in this paper, the formation porosity under different wellbore diameter conditions is calculated. Figure 5 and Figure 6 Based on the self-compensation method, the formation porosity calculation error caused by the change of wellbore diameter is greatly reduced, and the calculation accuracy of formation porosity is improved.

[0092] Please refer to Figure 7 , Figure 7The structural schematic diagram of a formation porosity measurement system provided by the present invention is applied to a DD neutron porosity logging instrument placed in a calibration well to be measured, in which a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source are arranged in order from top to bottom; the system includes:

[0093] A first acquisition unit 21 is used to respectively acquire 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;

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

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

[0096] The formation porosity measurement system provided in this embodiment corresponds to the above method, and therefore has the same beneficial effects as the above method. Therefore, for the embodiments of the formation porosity measurement system, please refer to the description of the embodiments of the method part, which will not be repeated here.

[0097] The present invention also provides an embodiment corresponding to a DD neutron porosity logging tool, including:

[0098] A gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source are arranged in sequence from top to bottom;

[0099] A processor is connected to the gamma detector, the first thermal neutron detector, the second thermal neutron detector and the neutron source respectively, and is used to implement the steps of the above-mentioned formation porosity measurement method when executing the computer program.

[0100] Among them, the processor may 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 hardware form of a digital signal processor (DSP), a field-programmable gate array (FPGA), and a programmable logic array (PLA). The processor may also include a main processor and a coprocessor. The main processor is a processor for processing data in the awake state, also known as a central processing unit (CPU); the coprocessor is a low-power processor for processing data in the standby state. In some embodiments, the processor may be integrated with a graphics processing unit (GPU), which is responsible for rendering and drawing the content to be displayed on the display screen. In some embodiments, the processor may also include an artificial intelligence (AI) processor, which is used to process computing operations related to machine learning.

[0101] The DD neutron porosity logging tool provided in this embodiment corresponds to the above method, and thus has the same beneficial effects as the above method. Therefore, for the embodiments of the DD neutron porosity logging tool, please refer to the description of the embodiments of the method part, which will not be repeated here.

[0102] The present invention also provides an embodiment corresponding to a computer-readable storage medium, on which a computer program is stored, and when the computer program is executed by a processor, the steps of the above-mentioned formation porosity measurement method are implemented.

[0103] It is understandable that if the method in the above embodiment is implemented in the form of a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on such an understanding, the technical solution of the present invention is essentially or the part that contributes to the prior art or all or part of the technical solution can be embodied in the form of a software product, and the computer software product is stored in a storage medium to execute all or part of the steps of the methods of each embodiment of the present invention. The aforementioned storage medium includes: U disk, mobile hard disk, read-only memory (ROM), random access memory (RAM), disk or optical disk and other media that can store program code.

[0104] The computer-readable storage medium provided in this embodiment corresponds to the above method, and therefore has the same beneficial effects as the above method. Therefore, for the embodiments of the computer-readable storage medium part, please refer to the description of the embodiments of the method part, which will not be repeated here.

[0105] It should be noted that, in this specification, relational terms such as first and second, etc. are only used to distinguish one entity or operation from another entity or operation, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Moreover, the terms "include", "comprise" or any other variants thereof are intended to cover non-exclusive inclusion, so that a process, method, article or device including a series of elements includes not only those elements, but also other elements not explicitly listed, or also includes elements inherent to such process, method, article or device. In the absence of further restrictions, an element defined by the sentence "comprises a ..." does not exclude the presence of other identical elements in the process, method, article or device including the element.

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

Claims

1. A formation porosity measurement method, characterized in that: The method is applied to a DD neutron porosity logging instrument placed in a calibration well to be measured, wherein the DD neutron porosity logging instrument is provided with a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source in order from top to bottom; the method comprises: Respectively acquiring 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; Acquire the gamma time spectrum information detected by the gamma detector, and determine the borehole Sigma value of the calibration well to be measured according to the gamma time spectrum information; A formation porosity is determined based on the first thermal neutron count, the second thermal neutron count, and the wellbore Sigma value.

2. The formation porosity measurement method according to claim 1, characterized in that: Determining the borehole Sigma value of the calibration well to be measured according to the gamma time spectrum information includes: Determining the thermal neutron lifetime and the corresponding gamma count of the formation according to the gamma time spectrum information; Determine the thermal neutron lifetime of the borehole of the calibration well to be measured by using a double exponential inversion formula, the thermal neutron lifetime of the formation and the gamma count; The wellbore Sigma value of the calibration well to be measured is determined based on the thermal neutron lifetime of the wellbore and the thermal neutron macroscopic capture cross section formula of the wellbore.

3. The formation porosity measurement method according to claim 1, characterized in that: The determining of formation porosity based on the first thermal neutron count, the second thermal neutron count and the wellbore Sigma value comprises: The formation porosity is determined based on a self-compensating porosity calculation formula, a ratio of the second thermal neutron count to the first thermal neutron count, and the wellbore Sigma value.

4. The formation porosity measurement method according to claim 3, characterized in that: Before respectively acquiring the thermal neutron counts detected by the first thermal neutron detector and the second thermal neutron detector, the method further includes: Determining the structural parameters of the DD neutron porosity logging instrument and the measured data of the standard calibration well, wherein the measured data includes the wellbore size of the standard calibration well, the fluid type in the standard calibration well, and the formation porosity of the standard calibration well; A three-dimensional numerical calculation model of the DD neutron porosity logging instrument, the wellbore of the standard calibration well, and the formation corresponding to the standard calibration well is established based on the structural parameters of the DD 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 when the DD neutron porosity logging instrument detects other calibration wells, so as to obtain corresponding simulation results; wherein the other calibration wells have different wellbore sizes and fluid types from the standard calibration well; The self-compensating porosity calculation formula is determined based on the simulation results.

5. The formation porosity measurement method according to claim 4, characterized in that: The method of establishing a three-dimensional numerical calculation model of the DD neutron porosity logging instrument, the wellbore of the standard calibration well, and the formation corresponding to the standard calibration well based on the structural parameters of the DD neutron porosity logging instrument and the measured data of the standard calibration well comprises: The three-dimensional numerical calculation model is constructed by using a Monte Carlo simulation method and based on the structural parameters of the DD neutron porosity logging instrument and the measured data of the standard scale well.

6. The formation porosity measurement method according to claim 4, characterized in that: After establishing the three-dimensional numerical calculation model of the DD neutron porosity logging instrument, the wellbore of the standard calibration well and the formation corresponding to the standard calibration well based on the structural parameters of the DD neutron porosity logging instrument and the measured data of the standard calibration well, the method further includes: Determine 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 the standard absolute error value; If the absolute error is not less than the standard absolute error value, the three-dimensional numerical calculation model is optimized and adjusted so that the absolute error of the adjusted three-dimensional numerical calculation model is less than the standard absolute error value.

7. The formation porosity measurement method according to any one of claims 4 to 6, characterized in that: The step of determining the self-compensating porosity calculation formula based on the simulation results comprises: The simulation results are fitted and analyzed using the least square method to obtain the self-compensating porosity calculation formula; wherein the simulation results include formation porosity response data under different wellbore sizes and fluid types.

8. A formation porosity measurement system, characterized in that: The system is applied to a DD neutron porosity logging instrument placed in a calibration well to be measured, wherein the DD neutron porosity logging instrument is provided with a gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source in order from top to bottom; the system comprises: A first acquisition unit, used to respectively acquire 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; A second acquisition unit is used to acquire the gamma time spectrum information detected by the gamma detector, and determine the borehole Sigma value of the calibration well according to the gamma time spectrum information; A determination unit is used to determine the formation porosity based on the first thermal neutron count, the second thermal neutron count and the wellbore Sigma value.

9. A DD neutron porosity logging tool, characterized in that: include: A gamma detector, a first thermal neutron detector, a second thermal neutron detector and a neutron source are arranged in sequence from top to bottom; A processor, wherein the processor is respectively connected to the gamma detector, the first thermal neutron detector, the second thermal neutron detector and the neutron source, and is used to implement the steps of the formation porosity measurement method as described in any one of claims 1 to 7 when executing the computer program.

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

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