Method for measuring formation porosity using a pulsed neutron source and a dual-function detector

Abstract

A logging tool is used to measure formation porosity. The tool has a pulsed neutron generator and multiple dual-function detectors that can detect neutrons and gamma rays. The ratios of thermal neutrons, epithermal neutrons, and captured gamma rays from multiple detectors are used to obtain multiple neutron porosities and multiple gamma-ray porosities at different exploration depths. The neutron porosity and gamma-ray porosity can be further corrected by excluding peak regions attributed to hydrogen and / or chlorine to reduce shale effects and / or chlorine effects. The neutron porosity and gamma-ray porosity can be combined to provide a better porosity assessment at different exploration depths in the formation over the entire porosity measurement range (0-100 p.u.).

Description

Technical Field

[0001] The present disclosure provides methods and apparatuses for formation logging through a borehole, in particular methods and apparatuses for providing formation porosity for different depths of investigation (DOI) in a formation over the entire porosity measurement range (0 - 100 p.u.) by selecting and / or combining neutron porosity and gamma ray porosity obtained simultaneously using multiple dual - function detectors. Background Art

[0002] Today, formation porosity can be measured using a compensated neutron tool, which has a neutron source and two neutron detectors spaced at different distances from the neutron source. The neutron source can be an isotope neutron source (e.g., Am - Be source). The neutron detectors can detect thermal neutrons or epithermal neutrons. Fast neutrons emitted from the neutron source are slowed down to thermal neutrons in the formation. Some thermal neutrons are captured by elements in the formation (i.e., thermal neutron capture), and gamma rays (i.e., capture gamma rays) are produced when the excited elements decay to their ground state. Other neutrons are scattered back to the detectors and detected.

[0003] The downhole formation contains water (H2O), gas (CH4) and / or oil (C n H 2n+2 )), all of which are rich in hydrogen. In contrast, common rocks such as limestone (CaCO3), sandstone (SiO2), dolomite (CaMg(CO3)2) do not contain a large amount of hydrogen. Since hydrogen can effectively capture thermal neutrons, the higher the formation porosity, the fewer thermal neutrons can escape thermal capture and reach the detectors. Since the percentage of thermal neutrons at the far detector is higher than that at the near detector in the total neutrons, the neutron count rate at the far detector is more affected than that at the near detector. Therefore, the ratio of the count rate at the near detector to the count rate at the far detector (near - far ratio) is positively correlated with the formation porosity. That is, the higher the near - far ratio, the higher the formation porosity, and vice versa. In addition, the correlation between this ratio and the formation porosity is unique for a specific tool and a specific formation mineralogy (e.g., sandstone, limestone or dolomite). A specific count rate ratio can be associated with the formation porosity.

[0004] As is well known, porosity measurements are affected by near-wellbore environmental factors such as borehole size, tool spacing, borehole salinity, temperature, pressure, etc. Therefore, various algorithms have been developed to correct these environmental factors. However, when the salinity in the wellbore, mud filtrate, or formation fluid (NaCl, KCl in the fluid) is high, more thermal neutrons are absorbed by chlorine (Cl) in the high-salinity fluid. So, the neutron count rate of the detector decreases. In addition, since the percentage of thermal neutrons at the far detector in the total neutrons is higher than that at the near detector, the neutron absorption at the far detector is more significant than that at the near detector. So, the count rate of the far detector decreases more than that of the near detector, causing the near-far detector count ratio to increase. Consequently, the formation apparent porosity increases. The pseudo-increase in formation apparent porosity due to high salinity is generally referred to as the chlorine effect.

[0005] The presence of shale in the formation can also distort the apparent neutron porosity to the extent that the reading can be as high as 100 p.u. Shale contains a large amount of clay-bound water and other minerals that affect the moderation and absorption of neutrons. Therefore, the neutron count rate in shale sand or shale decreases significantly. Since the count rate of the far detector is more affected than that of the near detector, the far-near ratio increases. Therefore, the reading of the apparent neutron porosity in shale sand or shale is usually higher than the actual porosity, which is called the shale effect. In field applications, the chlorine effect and the shale effect can be so high that even after correction, the measurement of formation porosity is unreliable.

[0006] The number of captured gamma rays is proportional to the number of thermal neutrons. Therefore, formation porosity can also be measured by using the ratio of the captured gamma-ray count rates. In addition, the formation porosity obtained based on captured gamma rays is also affected by the shale effect and the chlorine effect. Gamma-ray porosity logging usually uses a pulsed neutron generator and two gamma-ray detectors. In this case, the gamma rays from the thermal neutron capture reaction can be distinguished from the gamma rays from fast neutron inelastic scattering.

[0007] Therefore, there is a need to develop methods and tools for porosity logging that reduce or avoid the chlorine effect and / or the shale effect and generally improve accuracy. SUMMARY OF THE INVENTION

[0008] The present disclosure provides methods and apparatuses for improved formation porosity measurement that can cover the entire porosity measurement range (0 - 100 p.u.). The apparatus has a pulsed neutron generator and multiple dual-function detectors that can detect both neutrons and gamma rays. By using multiple dual-function detectors, multiple neutron porosity readings and gamma-ray porosity readings with different detection depths for the formation can be obtained simultaneously. Then, the neutron porosity and the gamma-ray porosity are corrected and / or combined to obtain one or more formation porosities with improved accuracy.

[0009] One embodiment of the present disclosure provides a method for evaluating the porosity of a downhole formation. The method includes using a pulsed neutron generator and a plurality of dual-function detectors in a wellbore to measure the formation porosity. By selecting and / or combining the neutron porosity and gamma-ray porosity obtained simultaneously using the plurality of dual-function detectors, a deterministic solution can be used to estimate the values of the formation porosity at different detection depths within the entire measurement range.

[0010] Another embodiment of the present disclosure provides an apparatus configured to evaluate the porosity of a downhole formation. The apparatus includes a pulsed neutron generator and a plurality of dual-function detectors capable of detecting neutrons and gamma rays.

[0011] The present disclosure further provides a method for evaluating the porosity of a downhole formation. The method includes the following steps: emitting neutron pulses from a pulsed neutron tool deployed in a wellbore to irradiate the formation around the wellbore; using a plurality of detectors provided in the pulsed neutron tool to detect neutrons and gamma rays; and estimating a plurality of neutron porosities and a plurality of gamma-ray porosities based on data from the plurality of detectors. The detectors in the pulsed neutron tool are dual-function detectors and can be used to detect neutrons and gamma rays in the formation.

[0012] In some embodiments, the neutrons detected by the plurality of detectors are selected from thermal neutrons, epithermal neutrons, or a mixture thereof, and the gamma rays detected by the plurality of detectors are inelastic gamma rays, capture gamma rays, or a mixture thereof. The signals from neutrons and the signals from gamma rays detected by the detectors are distinguished by applying pulse shape discrimination techniques.

[0013] In some other embodiments, the estimating step in the method includes: obtaining a neutron count rate and a capture gamma-ray count rate from each of the plurality of detectors; calculating a neutron count rate ratio and a capture gamma-ray count rate ratio between every two of the plurality of detectors to obtain a plurality of neutron count rate ratios and a plurality of capture gamma-ray count rate ratios; and using the plurality of neutron count rate ratios to estimate a plurality of neutron porosities, and / or using the plurality of gamma-ray count rate ratios to estimate a plurality of gamma-ray porosities.

[0014] In other embodiments, each of the plurality of neutron porosities is obtained using an algorithm, for example, a polynomial function as shown in Equation 4 of the present disclosure, which has a corresponding neutron count rate ratio among the plurality of neutron count rate ratios as an input. Each of the plurality of gamma-ray porosities is obtained using an algorithm, for example, a polynomial function as shown in Equation 11 of the present disclosure, which has a corresponding gamma-ray count rate ratio among the plurality of gamma-ray count rate ratios as an input.

[0015] In some other embodiments, each of the plurality of neutron porosities is obtained using a corrected neutron count rate ratio, wherein the corrected neutron count rate ratio is obtained by applying a correction factor to the neutron count rate ratio, and the correction factor is a function of the plurality of neutron count rate ratios, such as according to Equations 5-7 in the present disclosure.

[0016] In still other embodiments, each of the plurality of gamma ray porosities is obtained using a corrected gamma ray count rate ratio, wherein the corrected gamma ray count rate ratio is obtained by applying a correction factor to the gamma ray count rate ratio, and the correction factor is a function of the plurality of gamma ray count rate ratios, such as according to Equations 12-14 in the present disclosure.

[0017] In a specific embodiment, the method is performed using a pulsed neutron tool that includes three detectors, namely a first, a second, and a third detector. The method includes the following steps: obtaining a neutron count rate and a capture gamma ray count rate from each of the first detector, the second detector, and the third detector; calculating a first neutron count rate ratio and a first capture gamma ray count rate ratio between the first detector and the second detector, a second neutron count rate ratio and a second capture gamma ray count rate ratio between the second detector and the third detector, and a third neutron count rate ratio and a third capture gamma ray count rate ratio between the first detector and the third detector; calculating three neutron porosities using the first neutron count rate ratio, the second neutron count rate ratio, and the third neutron count rate ratio, respectively; and / or calculating three capture gamma ray porosities using the first gamma ray count rate ratio, the second capture gamma ray count rate ratio, and the third capture gamma ray count rate ratio, respectively.

[0018] The method may optionally include a correction step. One embodiment of the correction step is to correct the plurality of neutron porosities and the plurality of gamma ray porosities by subtracting the capture gamma ray count rate attributed to hydrogen, chlorine, or both, such as according to Formulas 15-20.

[0019] In a further embodiment, the neutron porosity and the gamma ray porosity are evaluated and combined to provide a formation porosity. In one such method, a neutron porosity value selected from the plurality of neutron porosities is compared with a corresponding gamma ray porosity value selected from the plurality of gamma ray porosities. When the difference between the two values is less than or equal to a predetermined value, the value of the neutron porosity is taken as the formation porosity; when the difference between the two values is greater than the predetermined value, the value of the gamma ray porosity is taken as the formation porosity. The predetermined value can be any value in the range of 2% to 10%.

[0020] In another method, the value of the neutron porosity selected from the plurality of neutron porosities and the corresponding gamma-ray porosity value selected from the plurality of gamma-ray porosities are compared with a predetermined value. When the neutron porosity value is less than or equal to the predetermined value, the formation porosity value is equal to the neutron porosity value, and when the gamma-ray porosity value is greater than the predetermined value, the formation porosity value is equal to the gamma-ray porosity value. The predetermined value can be any value from 30 p.u. to 50 p.u., for example, 30 p.u., 35 p.u., 40 p.u., 45 p.u., or 50 p.u.

[0021] In yet another method, the formation porosity is calculated according to a weighted function of one of the plurality of gamma-ray porosities and one of the plurality of neutron porosities, for example, according to Equation 21. BRIEF DESCRIPTION OF THE DRAWINGS

[0022] The teachings of the present invention can be easily understood by considering the following detailed description in conjunction with the accompanying drawings.

[0023] Figure 1A It is shown that the gamma-ray signal recorded by the detector decays faster than the neutron signal.

[0024] Figure 1B A crossplot of pulse shape discrimination (PSD) versus energy is shown to distinguish between neutrons and gamma rays.

[0025] Figure 2A 、 Figure 2B 、 Figure 2C and Figure 2D Four exemplary configurations of a pulsed neutron logging tool are shown, which has a neutron source S1 and three detectors D1, D2, and D3 arranged along the longitudinal direction of the tool housing.

[0026] Figure 3A 、 Figure 3B and Figure 3C A cross-sectional view of an exemplary pulsed neutron logging tool with S1, D1, D2, and D3 is shown.

[0027] Figure 4A and Figure 4B Cross-sectional views of exemplary pulsed neutron logging tools with four detectors D1, D2, D31, D32 and six detectors D1, D21, D22, D31, D32, D33 are shown respectively.

[0028] Figure 5 A block diagram of an exemplary drilling system suitable for implementing the present disclosure is shown.

[0029] Figure 6 Sketches showing neutron pulses, neutron count rates, and inelastic and capture spectra of neutron-induced gamma rays are shown.

[0030] Figure 7 Shows a workflow for estimating formation porosity according to an embodiment of the present disclosure.

[0031] Figure 8 Shows Figure 7 Details of S706 to S708 in the shown workflow.

[0032] Figure 9 Shows how to separate gamma-ray counts from hydrogen and chlorine in the energy spectrum of captured gamma rays from a detector to correct the total captured gamma-ray count rate. Detailed Description of the Invention

[0033] The following detailed embodiments provided can help the reader obtain a comprehensive understanding of the methods, apparatuses, and / or systems described herein. References to the specific embodiments of the present disclosure are shown by way of example in the drawings. Like or similar reference numerals may be used in the drawings and may indicate like or similar elements.

[0034] The features described herein may be embodied in different forms and should not be construed as limiting the embodiments described herein. On the contrary, the embodiments described herein and depicted in the drawings have been provided so that this disclosure will be thorough and complete, and will convey the full scope of the disclosure to those of ordinary skill in the art, such that they can readily recognize from the following description that alternative embodiments exist without departing from the general principles of the disclosure.

[0035] Therefore, the scope of the present invention is not defined by the detailed embodiments, but by the claims and their equivalents, and all variations within the scope of the claims and their equivalents are construed as being included in this disclosure.

[0036] In oil and gas exploration, density, porosity, mineralogy, and gas / oil saturation are important formation parameters for evaluating the total oil / gas reserves of an oilfield. Various wireline and LWD (logging while drilling) logging tools have been developed to obtain downhole formation parameters.

[0037] Formation density is obtained by measuring backscattered gamma rays from a gamma radiation source (e.g., a Cs-137 source), which are received by two detectors (e.g., two sodium iodide scintillation detectors) arranged at different distances from the gamma ray source. These two detectors are typically referred to as the near detector and the far detector according to their relative distances from the gamma ray source.

[0038] Neutron porosity logging tools obtain formation porosity by measuring the ratio of the neutron count rates of a near detector and a far detector after fast neutrons from an isotopic neutron source (e.g., an Am-Be source) are slowed down and scattered back to the detectors by the tool's surrounding environment (e.g., wellbore fluid and formation). This ratio is then converted to porosity according to a specific tool in the formation mineralogy (e.g., sandstone, limestone, or dolomite). Using the count rate ratio from two detectors reduces the impact of changes in the near-wellbore environment (wellbore fluid, borehole size, etc.) on porosity measurements.

[0039] Pulsed neutron logging tools use a pulsed neutron source (e.g., a D-T neutron generator) and one, two, or three detectors that detect neutrons or neutron-induced gamma rays. The energy spectrum of the neutron-induced gamma rays from each element is unique. Thus, by measuring the energy spectrum of the gamma rays from inelastic scattering and / or neutron capture reactions, elements can be identified and the relative percentages of gamma rays from each element in the formation, i.e., the element abundances, can be obtained. The inelastic scattering energy spectrum is the basis for carbon-oxygen (C / O) ratio logging, but the capture gamma ray energy spectrum can also provide information about other elements, such as magnesium (Mg), silicon (Si), calcium (Ca), iron (Fe), sulfur (S), and aluminum (Al). The capture gamma ray energy spectrum can also provide information about many elements, such as magnesium (Mg), silicon (Si), calcium (Ca), iron (Fe), sulfur (S), titanium (Ti), potassium (K), gadolinium (Ga), hydrogen (H), and chlorine (Cl).

[0040] Since elemental abundance logging only provides the relative concentrations of elements, they are usually expressed as ratios, such as C / O, Cl / H, Si / (Si + Ca), H / (Si + Ca), and Fe / (Si + Ca). These ratios are indicators of oil, salinity, mineralogy, porosity, and clay, respectively. Elemental abundance logging, as well as the reaction cross-sections of the neutron inelastic scattering and neutron capture reactions of these elements, can also be used to obtain the elemental content in the formation.

[0041] In addition, by measuring the thermal neutron time decay curve or the capture gamma ray time decay curve after one or more neutron pulses, the macroscopic thermal neutron absorption cross-section (sigma) of the formation can be obtained, which can be used to estimate the gas / oil saturation.

[0042] In most of these applications, neutrons and gamma rays are detected by their respective detectors / sensors. For example, a He-3 gas detector is used to detect thermal neutrons. The He-3 isotope has a high thermal neutron absorption cross-section. After fast neutrons emitted from a neutron source are slowed down and scattered back to the detector by the formation, the neutrons are absorbed and other detectable ions, such as protons (p) and tritium (T), are produced, thereby ionizing the gas. Ions and electrons multiply and drift in an electric field to form an electrical signal. Various scintillation detectors, such as NaI, CsI, BGO, GSO, LaBr3, YAP scintillators, and photomultiplier tubes (PMT), can be used to detect gamma rays. These scintillators convert the deposited energy of gamma rays into scintillation light. The PMT converts the scintillation light into electrons and amplifies them to form a current signal.

[0043] Existing nuclear logging tools typically use single-function detectors to detect neutrons or gamma rays. For example, to obtain both formation density and neutron porosity simultaneously, the traditional method is to combine a density tool and a neutron porosity tool in a tool string. The density tool may have a gamma ray source and two gamma ray detectors. The neutron porosity tool may have a neutron source and two neutron detectors. Therefore, the measurement of formation density and neutron porosity requires the use of two different radiation sources and four radiation detectors. To obtain other parameters, such as gas saturation, a third detector may be required. In addition, a neutron monitoring detector may be needed to monitor the source intensity of the neutron generator, as the source intensity can decrease or fluctuate over time. Therefore, nuclear logging tools need to carry multiple different types of radiation sources and detectors to measure multiple formation parameters. Such logging tools are limited in use due to high cost, low reliability, and large volume.

[0044] Recently, scintillator materials sensitive to both neutrons and gamma rays, such as Cs2LiYCl6 (CLYC) and Cs2LiLaBr6 (CLLB), have been developed. By coupling a crystal of this material with a scintillation photosensitive element, such as a photomultiplier tube (PMT), a dual-function scintillator, i.e., a dual-function detector, capable of detecting neutrons and gamma rays can be produced. As Figure 1A and Figure 1B shown, based on the fact that the electronic signal attributed to gamma rays from the detector decays faster than that of neutrons, the neutrons and gamma rays received by the dual-function detector can be distinguished from each other using pulse shape discrimination (PSD) technology.

[0045] Figure 9Shows a typical energy spectrum of the captured gamma rays from the detector. When the salinity is high, there are peaks at approximately 1.95 MeV, 5.09 MeV, 5.61 MeV, and 6.11 MeV for the gamma rays attributed to the thermal neutrons captured by chlorine, and there is a peak at approximately 2.23 MeV for the gamma rays attributed to the thermal neutrons captured by hydrogen. These peaks can be eliminated when calculating the total detector count rate of the captured gamma rays.

[0046] In the present disclosure, unless otherwise specified, the detector refers to a dual - function detector that can detect neutrons and gamma rays. Such a detector employs a scintillation crystal (e.g., Cs2LiLaBr6 (CLLB)) and a photosensitive device (e.g., PMT). When the detector is deployed downhole, it can be actively cooled or non - actively cooled. For example, a detector using a CLLB crystal and a high - temperature PMT can be used at high temperatures without an additional cooling device. Additionally, the ratio or count - rate ratio refers to the ratio between two count rates detected by two different detectors, which can be the ratio of two neutron count rates or the ratio of two gamma - ray count rates.

[0047] Figures 2A - 2D Is a schematic diagram (not to scale) of four exemplary configurations of a cylindrical pulsed - neutron logging tool, which has a pulsed - neutron source S1 and three dual - function detectors D1, D2, D3, and these three detectors are arranged along the housing of the logging tool suitable for logging - while - drilling (LWD) operations. A mud channel (MC) is arranged along the axis of the logging tool, and each detector is eccentrically arranged along the longitudinal direction of the logging tool. Figure 2A Also shown are: a high - voltage power supply (HV); electronic instruments, such as a controller, for sending instructions, receiving, and processing data from the pulsed - neutron source and each detector; and a telemetry device for transmitting data between the logging tool and the surface. The high - voltage power supply provides high - voltage electricity to detectors D1, D2, D3 and the pulsed - neutron source S1. For simplicity, the required high - voltage power supply, electronic instruments, and telemetry device are not shown in Figures 2B - 2D the figure.

[0048] As shown in the figure, D1 is a near detector with the shortest distance from the pulsed - neutron source in the longitudinal direction, D3 is a far detector with the longest longitudinal distance from the pulsed - neutron source, and D2 is a middle detector with a longitudinal distance in the middle.

[0049] As Figure 2AAs shown, all three detectors are located on one side of the pulsed neutron source along the logging tool. This side can be the near side or the far side of the pulsed neutron source. The near side is the side closer to the surface when the pulsed neutron logging tool is deployed downhole, while the far side is the side away from the surface. The high-voltage power supply provides high voltage to detectors D1, D2, D3 and pulsed neutron source S1. Signals from each detector are processed by the electronic instrument and the measurements / data are acquired and transmitted via the telemetry device. As Figure 2B , 2C and as shown in 2D, at least one detector is provided on both the far side and the near side of the pulsed neutron source.

[0050] In wireline logging, the tool can be installed in a sonde that does not contain a mud channel. The detectors can be installed along or offset from the axis of the tool body. Power and control signals can also be provided to the logging tool from the surface, and data from the logging tool can be transmitted to the surface via the cable.

[0051] In Figures 2A - 2D each logging tool depicted, the pulsed neutron source S1 is a pulsed neutron generator. The pulsed neutron generator can be a deuterium-tritium (D-T) pulsed neutron generator, which can operate in a pulsed mode with various pulse output manners (e.g., frequency, pulse duration). For example, the frequency of the neutron pulse can be about 10 kHz (period of 100 μs), and the duration of the neutron pulse can be about 20 μs. In another embodiment, the frequency of the neutron pulse can be about 1 kHz (period of 1000 μs), and the neutron duration can be 50 μs. According to the method and measurement, the D-T neutron generator can also operate in a continuous mode. In this case, the start-up frequency of the neutron generator is high enough such that neutrons are continuously emitted. Neutrons from the D-T neutron generator have an initial energy of about 14.1 MeV.

[0052] The pulsed neutron source can also be a deuterium-deuterium (D-D) pulsed neutron generator, which can operate in a pulsed mode with different pulse output manners (e.g., frequency, pulse duration). For example, the frequency of the neutron pulse can be about 20 kHz (period of 50 μs), and the duration of the neutron pulse can be about 20 μs. Alternatively, the frequency of the neutron pulse can be about 1 kHz (period of 1000 μs), and the duration of the neutron pulse can be 40 μs. According to the method and measurement, the D-D neutron generator can also operate in a continuous mode. Neutrons from the D-D neutron generator have an initial energy of about 2.5 MeV.

[0053] In Figures 2A - 2DThe neutron source S1 and detectors D1, D2, and D3 therein only indicate their relative positions along the longitudinal direction of the logging tool housing, and do not indicate their positions in the radial direction in the cross-section of the tool housing.

[0054] In some embodiments, S1, D1, D2, and D3 may be arranged in the same radial direction or different radial directions, i.e., having the same or different measurement azimuth angles when deployed in the formation. Figure 2A , 2B , 2C and 2D respectively show exemplary cross-sectional views in the A - A, B - B, C - C, and D - D directions. Figure 3A In, S1, D1, D2, and D3 are arranged at the same azimuth angle. However, in Figure 3B , S1, D1, and D3 have the same azimuth angle, while D2 is at a different azimuth angle. In Figure 3C , S1 and D1 have the same azimuth angle, while each of D2 and D3 has a different azimuth angle.

[0055] Other embodiments of the logging tool may have more than three detectors. For example, Figure 4A depicts Figure 2A a variant of the logging tool in, which has four detectors, namely D1, D2, D31, and D32. D31 and D32 are at approximately the same distance from S1, but are arranged at two different azimuth angles. Similarly, Figure 4B depicts another variant of the tool in Figure 2A , which has six detectors, namely D1, D21, D22, D31, D32, and D33. In this embodiment, D21 and D22 are arranged opposite each other in the cross-section of the logging tool, i.e., the azimuth angles of D21 and D22 are 0° and 180° respectively. D31, D32, and D33 are arranged at intervals of 120° in the cross-section of the logging tool, i.e., the difference in azimuth angles between any two of D31, D32, and D33 is 120°. Having different azimuth angles allows the detectors to preferentially receive neutrons and gamma rays with specific incident angles from the formation. This embodiment also improves the detection efficiency of neutrons and gamma rays by increasing the total count rate of all detectors.

[0056] In addition, in Figure 4A , D31 and D32 are at substantially the same distance from S1. In Figure 4BAmong them, the distances from the middle detectors D21 and D22 to S1 are substantially the same, and the distances from the far detectors D31, D32, and D33 to S1 are substantially the same. "Substantially the same distance" means that the distances from S1 to the centers of the scintillators of the detectors (e.g., D31 and D32) are approximately the same. For example, the difference is less than one-half or one-fourth of an inch. With this arrangement, the overall middle detectors and the overall far detectors have a higher counting rate than when only one middle detector or only one far detector is used. Therefore, the pulsed neutron source S1 can be a source with a lower intensity, which can be free from the strict regulations of a higher-intensity neutron source. In addition, the counting rates of individual detectors can be recorded and processed separately. The differences in distance and azimuth angle of various detectors can be used to obtain formation information in a specific azimuth angle direction.

[0057] In some embodiments, the logging tool has a plurality of shields (not shown) that can absorb neutrons and gamma rays. The shields can be placed between the neutron source in the logging tool and each detector so that the detectors receive neutrons and gamma rays from the formation, rather than neutrons and gamma rays passing through the body of the logging tool. Alternatively, the detectors can also be partially shielded by setting shielding materials that absorb neutrons and gamma rays from certain directions.

[0058] The shields are made of or contain one or more materials that can effectively attenuate thermal neutrons and gamma rays. The shielding material can include materials selected from heavy elements with a high thermal neutron absorption cross-section, including metals such as gadolinium (Gd), samarium (Sm), metal oxides (such as Gd2O3, Sm2O3, B2O3), alloys containing Gd or Sm combined with other heavy metals (such as Fe, Pb, or W), or boron-containing materials (such as tungsten boride (WB, WB2, etc.)).

[0059] The shields can be independent metal pieces inserted into the logging tool or an integral part of the detector housing. For example, the part of the detector housing facing the logging tool can be made of shielding material, and the part facing the formation can be made of a material transparent to neutrons and gamma rays to form a window through which neutrons and gamma rays can pass. Therefore, neutrons and gamma rays from certain incident angles can be absorbed by the shielding material, while those passing through the window are received by the detector. Thus, by adjusting the size and direction of the window in the detector housing, the detector can be more sensitive to certain incident angles. During the operation, the data collected by various detectors may yield formation properties in a specific direction, which can be used to guide the drilling direction.

[0060] The logging tool can be part of a wireline logging tool or included in downhole equipment as an LWD logging tool in a drilling operation. Figure 5FIG. 0 is a schematic view of an oil drilling system 10 applied in directional drilling of a wellbore 16. The oil drilling system 10 can be used for drilling on land as well as underwater. A rotary drilling rig including a derrick 12, a drill floor 14, a drawworks 18, a traveling block 20, a hook 22, a swivel 24, a kelly bushing 26, and a rotary table 28 is used to drill a wellbore 16 in a formation. The drill string 100 includes a plurality of drill pipes connected in series and fixed to the bottom of the kelly bushing 26 at the surface. The rotary table 28 is used to rotate the entire drill string 100, while the drawworks 18 is used to lower the drill string 100 into the wellbore 16 and apply a controllable axial compressive load. The bottomhole assembly 150 is disposed at the distal end of the drill string 100.

[0061] The drilling fluid (also known as mud) is typically stored in a mud pit or mud tank 46 and is pumped using a mud pump 38. The mud pump 38 forces the drilling fluid to flow through a surge suppressor 40, then through a kelly hose 42, and through the swivel 24, thereby entering the top of the drill string 100. The drilling fluid flows through the drill string 100 at a rate of about 150 gallons per minute to about 600 gallons per minute and flows into the bottomhole assembly 150. Then, the drilling fluid returns to the surface through the annular space between the outer surface of the drill string 100 and the wellbore 16. When the drilling fluid reaches the surface, it is pumped back to the mud tank 46 through a mud return line 44.

[0062] The pressure required to maintain the drilling fluid circulation is measured by a pressure-sensitive sensor 48 on the kelly hose 42. The pressure-sensitive sensor detects a pressure change caused by a pressure pulse generated by a pulse generator. The amplitude of the pressure wave from the pulse generator can reach 500 psi or higher. The measured pressure is transmitted as an electrical signal through a sensor cable 50 to a surface computer 52, and the surface computer 52 decodes and displays the transmitted information. Alternatively, the measured pressure is transmitted as an electrical signal through the sensor cable 50 to a decoder, which decodes the electrical signal and transmits the decoded signal to the surface computer 52, and the surface computer 52 displays the data on a display screen.

[0063] As described above, the lower portion ("distal portion") of the drill string 100 includes a bottom hole assembly (BHA) 150, which includes a non-magnetic drill collar in which an MWD system (MWD equipment or MWD tool) 160 is installed, a logging while drilling (LWD) tool sub 165 containing LWD instruments, a downhole motor 170, a near-bit measurement sub 175, and a drill bit 180 having drill nozzles (not shown). The drilling fluid flows through the drill string 100 and exits through the drill nozzles of the drill bit 180. During the drilling operation, the drilling system 10 can operate in a rotary mode, in which the drill string 100 is rotated from the surface by an electric motor (i.e., a top drive) in the rotary table 28 or the traveling block 20. The drilling system 10 can also operate in a sliding mode, in which the drill string 100 is not rotated from the surface, but the drill bit 180 is rotated by the downhole motor 170. The drilling fluid is pumped from the surface through the drill string 100 to the drill bit 180 and is injected into the annular space between the drill string 100 and the wall of the wellbore 16. The drilling fluid carries the cuttings from the wellbore 16 to the surface.

[0064] In one or more embodiments, the MWD system 160 can include a pulse generator sub, a pulse generator drive sub, a battery sub, a central storage unit, a main board, a power supply sub, a directional module sub, and other sensor boards. In some embodiments, some of these devices can be located in other areas of the BHA 150. One or more of the pulse generator sub and the pulse generator drive sub can communicate with a pulse generator 300, which can be located below the MWD system 160. The MWD system 160 can transmit data to the pulse generator 300 such that the pulse generator 300 generates pressure pulses.

[0065] The non-magnetic drill collar houses the MWD system 160, which includes a set of instruments for measuring inclination, azimuth, well trajectory (borehole trajectory), etc. A pulsed neutron logging tool and associated electronics can be located in the LWD tool sub 165. The pulsed neutron logging tool and other logging instruments can be electrically coupled or wirelessly coupled together and powered by a battery pack or a mud-driven generator. All the information collected is transmitted to the surface in the form of pressure pulses generated by the pulse generator 300 through the mud column in the drill string.

[0066] The near-bit measurement sub 175 can be disposed between the downhole motor 170 and the drill bit 180. The pulsed neutron logging tool can alternatively be installed in the near-bit measurement sub 175 to provide more accurate real-time formation parameters to guide directional drilling. Data can be transmitted through a cable embedded in the downhole motor 170 to the MWD system 160 in the bottom hole assembly 150.

[0067] In one embodiment of the present disclosure, a logging tool having a D-T neutron generator and three dual-function detectors is used to obtain various formation parameters.Figure 6 A schematic diagram showing a neutron pulse, neutron count rate, and inelastic and capture energy spectra of neutron-induced gamma rays. The frequency of the neutron pulse is 10 kHz (period 100 μs), and the neutron working time is 20 μs, as shown in subfigure (b) of Figure 6 as shown.

[0068] As Figure 6 shown in subfigure (a) of

[0069] The neutron count rate measured by the bifunctional detector, as shown in subfigure (a) of Figure 6 is used to obtain formation porosity and other formation parameters. The neutrons of the bifunctional detector can be further separated according to whether the neutron pulse is on or off, using the pulsed neutron synchronization signal as the coincidence or anti-coincidence signal for the neutrons of the three detectors, so that during the neutron pulse (when the neutron pulse is on), the neutrons are mainly recorded as fast neutrons. Between neutron pulses (when the neutron pulse is off), the neutrons are recorded as thermal neutrons. The fast neutrons and thermal neutrons recorded by the three detectors can be used to obtain the fast neutron spatial distribution and thermal neutron spatial distribution. The neutrons from each detector can also be recorded together. In this case, all neutrons (from thermal neutrons to fast neutrons) are used to obtain the neutron spatial distribution. Figure 6 The gamma rays recorded by the bifunctional detector can be further separated according to whether the neutron pulse is on or off, using the pulsed neutron synchronization signal as the coincidence or anti-coincidence signal for the gamma rays from the three detectors, so that during the neutron pulse (when the neutron pulse is on), the gamma rays are mainly recorded as the inelastic energy spectrum, as shown in subfigure (c) of

[0070] as shown. Between neutron pulses (when the neutron pulse is off), the gamma rays are recorded as the capture energy spectrum, as shown in subfigure (d) of

[0071] A suitable time window is selected so that most of the gamma rays measured in the capture time window come from thermal neutron capture reactions, and most of the gamma rays measured in the inelastic time window come from fast neutron inelastic scattering.

[0072] In an exemplary embodiment, a logging tool having a neutron source and three dual-function detectors (i.e., a near detector, a mid detector, and a far detector) is used to measure formation porosity Φ. Figure 2A , 2B , 2C or 2D are examples of such logging tools. Additionally, the neutron source can be a pulsed neutron source or an isotopic neutron source.

[0073] The logging tool is lowered into the wellbore to perform pulsed neutron logging, either in a probe for wireline logging or as part of LWD commands in the drill string. Each of the far, mid, and near detectors detects neutrons and neutron-induced gamma rays. Pulse shape discrimination (PSD) techniques are used to separate the detector signals from neutrons and gamma rays.

[0074] Then, neutron signals from the three detectors are used to obtain thermal neutron and epithermal neutron count rates (the total count rate CRN n of the near detector, the total count rate CRN m of the mid detector, the total count rate CRN f of the far detector), fast neutron count rates (the count rate CRFN n of the near detector, the count rate CRFN m of the mid detector, the count rate CRFN f of the far detector), and thermal neutron count rates (the count rate CRTN n of the near detector, the count rate CRTN m of the mid detector, the count rate CRTN f of the far detector). During a short neutron pulse, there are fast neutrons, epithermal neutrons, and thermal neutrons. Between neutron pulses, most neutrons are epithermal neutrons and thermal neutrons. However, the dual-function detectors are more sensitive to thermal neutrons and epithermal neutrons, so most of the neutrons detected by the detectors are thermal neutrons and epithermal neutrons. Therefore, the formation porosity can be obtained using the count rates of thermal neutrons, epithermal neutrons, or both thermal and epithermal neutrons of the dual-function detectors.

[0075] Thermal neutrons are neutrons with kinetic energy from approximately 0.025 eV (at room temperature) to 0.4 eV. Epithermal neutrons are neutrons with kinetic energy from 0.4 eV to 10 eV. Fast neutrons are neutrons with kinetic energy higher than 1 MeV.

[0076] To measure epithermal neutrons, a thin layer of thermal neutron absorber (such as cadmium (Cd) or gadolinium (Gd)) is used to wrap the detector so that thermal neutrons scattered back from the formation are absorbed before entering the detector.

[0077] The ratios of the three neutron count rates can be obtained according to Equations 1 - 3:

[0078]

[0079]

[0080]

[0081] Rn m / f is the medium-far ratio, Rn n / f is the near-far ratio, Rn n / m is the near-medium ratio. Since the three detectors are set at different distances from the neutron source, they have different detection depths (DOI). Therefore, the near-borehole environment (such as borehole fluid, cement, etc.) has different effects on these three ratios. Rn m / f is more sensitive to the formation, while Rn n / m is more sensitive to near-borehole materials (such as borehole fluid).

[0082] By applying the three ratios Rn n / m , Rn n / f and Rn m / f to the ratio-porosity transformation shown in Equation 4 (which is a polynomial function of the ratio) respectively, three neutron porosities Φ n / m , Φ n / f and Φ m / f with different DOI can be obtained respectively. The coefficients a, b, c, d, e of the polynomial are different according to the different formations to be explored (such as sandstone, limestone or dolomite). These coefficients can be obtained by using data fitting of the porosity from core samples.

[0083]

[0084] where Rn is one of the three ratios Rn n / m , Rn n / f and Rn m / f of the total neutron count rate.

[0085] The neutron porosity Φ n can also be obtained in the following way: First, use Rn n / m and Rn n / f to correct Rn m / f , and then make the corrected far-near ratio Rnc m / f to obtain the formation porosity. Equations 5 to 7 show this algorithm.

[0086] Rnc m / f = Rn m / f + ΔR (5)

[0087]

[0088] Φ n = f1(Rnc m / f) (7)

[0089] Equation (6) indicates that all three total neutron count rate ratios are used to calculate the correction value ΔR. ΔR is added to the mid-far ratio Rn m / f to obtain Rnc m / f . Finally, Rnc m / f is used to calculate the neutron porosity Φ n , as shown in Equation (7). Alternatively, corrections can be made for Rn n / m or Rn n / f and used to calculate Φ n . It should be noted that the three Φ n obtained based on Equations 1 to 4 or 5 to 7 have different DOIs.

[0090] In addition, different from using the three ratios of neutron count rates, the formation porosity Φ can be calculated according to the algorithms shown in Equations 8 to 11 or Equations 12 to 14, which is done by using the ratios between the capture gamma-ray count rates (Rg n / m , Rg n / f and Rg m / f ) of three detectors to obtain the gamma-ray porosity Φ g .

[0091]

[0092]

[0093]

[0094]

[0095] where Rg can be Rg m / f , Rg n / f or Rg n / m . The coefficients A, B, C, D, E of the polynomial vary according to the different formations being explored (such as sandstone, limestone or dolomite) and can be obtained by fitting the data of core samples. It should be noted that three neutron porosities are calculated according to Equation 4 using three different ratios of neutron count rates, while three gamma-ray porosities are calculated according to Equation 11 using three different ratios of gamma-ray count rates. When using the ratios of the same pair of detectors, such as both using R m / f for calculation, Φ n and Φ g can be considered corresponding to each other.

[0096] Rgc m / f = Rg m / f +ΔR (12)

[0097] ΔR = f4(Rg m / f , Rg n / f , Rg n / m ) (13)

[0098] Φ g = f3(Rgc m / f ) (14)

[0099] Equation (13) represents calculating the correction value ΔR using all three captured gamma-ray count rate ratios. ΔR is added to the mid-far ratio Rg m / f to obtain Rgc m / f . Finally, Rgc m / f is used to calculate the gamma-ray porosity Φ g , as shown in Equation (14). Alternatively, the correction can be made for Rg n / m or Rg n / f and used to calculate Φ g . It should be noted that for each of the three neutron porosities calculated based on Equations 5 to 7, one corresponding gamma-ray porosity can be found among the three gamma-ray porosities calculated based on Equations 12 to 14.

[0100] Among the three detectors, the DOI of the near detector is the shallowest, the DOI of the mid detector is moderate, and the DOI of the far detector is the deepest. Therefore, the neutron porosity obtained using Rn n / m is the shallowest, while the neutron porosities obtained using Rn n / f and Rn m / f have a moderate DOI and the deepest DOI respectively. Similarly, the DOIs of the gamma-ray porosities obtained using Rg n / m , Rg n / f and Rg m / f are the shallowest, moderate, and deepest respectively. These different porosities have different DOIs into the formation and can be used to evaluate the near-wellbore environment, such as mud invasion in the formation.

[0101] The DOI of a pulsed neutron tool depends to a large extent on the distance from the neutron source to the detector and the formation porosity. When the formation porosity is about 20 p.u., the DOIs of the near detector, mid detector, and far detector for thermal neutron measurements can be about 8 inches, 10 inches, and 12 inches respectively. The DOIs of the near detector, mid detector, and far detector from captured gamma-ray measurements can be about 10 inches, 12 inches, and 15 inches respectively.

[0102] In porosity measurement, Φ n and Φ g can complement each other. For example, Φ nis more accurate at lower formation porosities (e.g., below 40 p.u., 35 p.u., or 30 p.u.), while Φ g is more precise at higher formation porosities (e.g., greater than 40 p.u., 45 p.u., or 50 p.u.). Additionally, in high salinity environments or in shale / sandstone, Φ n tends to overestimate porosity more than Φ g . Thus, the combination of Φ n and Φ g can achieve improved porosity readings over a wider range of formation porosities (e.g., 0 - 100 p.u.) under various wellbore and formation conditions.

[0103] Figure 7 shows a workflow for obtaining improved formation porosity using a logging tool with a pulsed neutron generator and three detectors. Figure 8 Details of steps S706 to S708 in this workflow are provided. As Figure 7 shown, in S701, fast neutron pulses emitted from the pulsed neutron generator enter the wellbore and formation. In S702, the fast neutrons are slowed down to thermal neutrons by inelastic scattering (producing inelastic gamma rays) or elastic scattering with the near - wellbore materials and formation. Some thermal neutrons are captured by elements in the wellbore and formation, thereby producing capture gamma rays. In S703, some neutrons and gamma rays are scattered back to the three detectors and detected. In S704, the signals of each detector are separated based on neutron - induced signals or gamma - ray - induced signals. In S705, the count rates of thermal neutrons, epithermal neutrons, or both thermal and epithermal neutrons for each detector, as well as the count rate of capture gamma rays, are obtained.

[0104] Figure 8 shows details of S706, S707, and S708 according to one embodiment. In S706, three ratios (Rn,i, i = 1, 2, 3) between the count rates of thermal neutrons, epithermal neutrons, or both thermal and epithermal neutrons are calculated.

[0105] In S707, both neutron porosity and gamma - ray porosity are calculated based on the count rate ratios. When the formation has a high shale content (containing clay - bound water H2O and other minerals) or high salinity (containing NaCl and KCl), both the neutron porosity and gamma - ray porosity are further corrected to obtain a corrected neutron porosity (Φ n，t ) and a corrected gamma - ray porosity (Φ g，t ).

[0106] Figure 9 shows an example performance spectrum of the capture gamma - ray signal. The capture gamma - ray count rate (CR) under the 2.23 MeV hydrogen peak above the dashed lineH ) is attributed to the clay-bound water in the shale formation, while the capture gamma-ray count rates (CR Cl ) under the 1.95 MeV, 5.09 MeV, 5.61 MeV, and 6.11 MeV chlorine peaks above the dashed line are attributed to the high salinity, both of which increase the gamma-ray count rate. CR H and CR Cl are both calculated and used as inputs to the algorithm to further correct for the chlorine and shale effects on neutron porosity and gamma-ray porosity, as shown in Equations 15 to 20.

[0107] ΔΦ n，H = f5(CR H , Φ n ) (15)

[0108] ΔΦ n，Cl = f6(CR Cl , Φ n ) (16)

[0109] Φ n，t = Φ n + ΔΦ n，H + ΔΦ n，CL (17)

[0110] ΔΦ g，H = f7(CR H , Φ g ) (18)

[0111] ΔΦ g，Cl = f8(CR Cl , Φ g ) (19)

[0112] Φ g，t = Φ g + ΔΦ g，H + ΔΦ g，CL (20)

[0113] Equation 15 provides a function that uses the initial values of CR H and neutron porosity Φ n as inputs to calculate the correction value corresponding to the shale effect. Similarly, Equation 16 provides a function that uses the initial values of CR Cl and neutron porosity Φ n as inputs to calculate the correction value corresponding to the chlorine effect. The corrected neutron porosity Φ n，t can be obtained according to Equation 17.

[0114] Equations 18 and 19 calculate the correction values of gamma-ray porosity attributed to the shale effect and chlorine effect, respectively. Then, the corrected gamma-ray porosity Φg，t 。

[0115] Although S707 provides a calibration step, the calibration step is optional. If the shale effect or the chlorine effect is strong, one or both of them can be calibrated according to the above method. If both the shale effect and the chlorine effect are weak and have little impact on the accuracy of formation porosity, the calibration step can be bypassed.

[0116] In S708, Φ n，t and Φ g，t are evaluated and combined to obtain the formation porosity. In one embodiment, Φ n，t and Φ g，t are compared with each other to select a value that can better represent the formation porosity. For example, if the difference between the values of Φ n，t and Φ g，t is less than a predetermined percentage, the formation porosity is assigned the value of Φ n，t ; if the difference is greater than the predetermined percentage, the formation porosity is assigned the value of Φ g，t . The predetermined percentage can be between 2% - 10%, such as 2%, 3%, 5%, 7% or 10%. In another embodiment, if the calibrated porosity Φ n，t and Φ g，t are equal to or lower than a predetermined value, the formation porosity is assigned the value of the calibrated porosity Φ n，t . If the calibrated porosity Φ n，t and Φ g，t are equal to or higher than the predetermined value, the formation porosity is assigned the value of Φ g，t . The predetermined value can be in the range of 30 p.u. to 50 p.u., such as 30 p.u., 35 p.u., 40 p.u., 45 p.u. or 50 p.u.

[0117] In another embodiment, the formation porosity is a weighted function of the calibrated neutron porosity and the calibrated gamma-ray porosity, as shown in Equation 21.

[0118] Φ t = w1Φ n，t +(1 - w1)Φ g，t (21)

[0119] Wherein, w1 and (1 - w1) are the relevant weights of the calibrated neutron porosity and the calibrated gamma-ray porosity. The value of w1 can be obtained by matching the calculated porosity value with the porosity value of core analysis. In addition, all coefficients in the equations of the present disclosure can be obtained by data fitting using empirical data (such as data obtained from formation core analysis).

[0120] It should be noted that the methods and apparatuses of the present disclosure are not limited to the examples shown. The apparatus may have a pulsed neutron generator and more than three dual-function detectors that can detect both neutrons and gamma rays. The method can provide improved formation porosity over the entire range from 0 to 100 p.u. at different DOIs within the formation by correcting and / or combining neutron porosity and gamma ray porosity. The porosity evaluation can be relatively unaffected by chlorine effects and shale effects. Additionally, the method can be used to obtain formation porosity by using thermal neutrons, epithermal neutrons, or both thermal neutrons and epithermal neutrons and / or the ratio of capture gamma rays. Additionally, the method can be used in wireline logging and logging-while-drilling environments.

[0121] While the present disclosure has been described in the foregoing specification with respect to certain preferred embodiments and numerous details have been set forth for purposes of illustration, it will be apparent to those skilled in the art that the present disclosure may be varied and that certain other details described herein may vary significantly without departing from the basic principles of the present disclosure. Additionally, it should be understood that the structural features or methods shown or described in any one of the embodiments herein may also be used in other embodiments.

Claims

1. A method for evaluating the porosity of an underground formation, comprising: A neutron pulse is emitted by a pulsed neutron tool deployed in a wellbore to irradiate a formation surrounding the wellbore; Multiple detectors arranged in the pulsed neutron tool are used to detect neutrons and gamma rays, where each detector can be used to detect neutrons and gamma rays from the formation; Estimate a plurality of neutron porosities and a plurality of gamma ray porosities based on data from the plurality of detectors; and Evaluate the formation porosity, including: Comparing the value of the neutron porosity selected from the plurality of neutron porosities with the corresponding value of the gamma ray porosity selected from the plurality of gamma ray porosities, where when the difference between the two values is less than or equal to a first predetermined value, the value of the neutron porosity is designated as the formation porosity, and when the difference between the two values is greater than the first predetermined value, the value of the gamma ray porosity is designated as the formation porosity; or Comparing the value of the neutron porosity selected from the plurality of neutron porosities and the corresponding value of the gamma ray porosity selected from the plurality of gamma ray porosities with a second predetermined value, where when the value of the neutron porosity is less than or equal to the second predetermined value, the value of the formation porosity is equal to the value of the neutron porosity, and when the value of the gamma ray porosity is greater than the second predetermined value, the value of the formation porosity is equal to the value of the gamma ray porosity.

2. The method according to claim 1, wherein The neutrons detected by the plurality of detectors are selected from thermal neutrons, epithermal neutrons, or a mixture thereof.

3. The method according to claim 1, wherein The gamma rays detected by the plurality of detectors are inelastic gamma rays, capture gamma rays, or a mixture thereof.

4. The method according to claim 1, wherein Two or more detectors are disposed in the pulsed neutron tool.

5. The method according to claim 4, wherein For each detector, the signals from neutrons and the signals from gamma rays are separated by applying pulse shape discrimination techniques.

6. The method according to claim 1, wherein The estimating step includes: Obtaining a neutron count rate and a capture gamma ray count rate from each of the plurality of detectors; Calculating the ratio of the neutron count rates and the ratio of the capture gamma ray count rates between every two of the plurality of detectors to obtain a plurality of neutron count rate ratios and a plurality of capture gamma ray count rate ratios; Estimating a plurality of neutron porosities using the plurality of neutron count rate ratios, and / or estimating a plurality of gamma ray porosities using the plurality of capture gamma ray count rate ratios.

7. The method according to claim 6, wherein Each of the plurality of neutron porosities is obtained using an algorithm that takes a corresponding one of the plurality of neutron count rate ratios as input.

8. The method according to claim 6, wherein Each of the plurality of gamma ray porosities is obtained using an algorithm that takes a corresponding one of the plurality of gamma ray count rate ratios as input.

9. The method according to claim 6, wherein Each of the plurality of neutron porosities is obtained using a corrected neutron count rate ratio, where the corrected neutron count rate ratio is obtained by applying a correction factor that is a function of the plurality of neutron count rate ratios to the neutron count rate ratio.

10. The method according to claim 6, wherein Each of the plurality of gamma ray porosities is obtained using a corrected gamma ray count rate ratio, where the corrected gamma ray count rate ratio is obtained by applying a correction factor that is a function of the plurality of gamma ray count rate ratios to the gamma ray count rate ratio.

11. The method according to claim 6, wherein The estimating step includes: Calculate the first neutron count rate ratio and the first capture gamma ray count rate ratio between the first detector and the second detector, the second neutron count rate ratio and the second capture gamma ray count rate ratio between the second detector and the third detector, and the third neutron count rate ratio and the third capture gamma ray count rate ratio between the first detector and the third detector; Estimate three neutron porosities using the first neutron count rate ratio, the second neutron count rate ratio, and the third neutron count rate ratio, respectively; and / or Estimate the capture gamma ray porosity using the first gamma ray count rate ratio, the second capture gamma ray count rate ratio, and the third capture gamma ray count rate ratio, respectively.

12. The method according to claim 1, wherein A first detector, a second detector, and a third detector are provided in the pulsed neutron tool, and the method includes: Obtain the neutron count rate and the capture gamma ray count rate from each of the first detector, the second detector, and the third detector; Calculate the first neutron count rate ratio and the first capture gamma ray count rate ratio between the first detector and the second detector, the second neutron count rate ratio and the second capture gamma ray count rate ratio between the second detector and the third detector, and the third neutron count rate ratio and the third capture gamma ray count rate ratio between the first detector and the third detector; Estimate three neutron porosities using the first neutron count rate ratio, the second neutron count rate ratio, and the third neutron count rate ratio, respectively; and / or Estimate the capture gamma ray porosity using the first gamma ray count rate ratio, the second capture gamma ray count rate ratio, and the third capture gamma ray count rate ratio, respectively.

13. The method according to claim 1, whereinFurther include correcting the plurality of neutron porosities and the plurality of gamma ray porosities by subtracting the capture gamma ray count rate attributed to hydrogen, chlorine, or both.

14. The method according to claim 1, characterized in that, The first predetermined value is in the range of 2% to 10%.

15. The method according to claim 1, characterized in that, The second predetermined value is between 30 p.u. and 50 p.u.

16. The method according to claim 1, characterized in that, Further include obtaining the formation porosity according to a weighting function of one of the plurality of gamma ray porosities and one of the plurality of neutron porosities.

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