System and method for real-time acquisition of true formation porosity

Abstract

A method for measuring porosity of a subterranean formation includes the steps of: positioning a nuclear logging tool having one or more neutron sources and two or more dual function detectors in a subterranean formation; causing the one or more neutron sources to emit neutrons in a plurality of neutron pulses toward the subterranean formation and to generate neutrons and gamma rays in the subterranean formation; obtaining one or more neutron count rates for each of the two or more detectors; determining a formation type of the subterranean formation based on the gamma rays received by the one or more detectors; calculating one or more neutron count rate ratios between the neutron count rates of two detectors selected from the two or more detectors; and obtaining one or more formation porosities based on the formation type and the one or more neutron count rate ratios.

Description

Technical Field

[0001] This disclosure provides methods and systems for nuclear logging and formation evaluation, particularly methods and systems for obtaining real formation porosity in real time using pulsed neutron logging tools with multiple dual-function detectors. Background Technology

[0002] In oil and gas exploration, porosity, mineralogical properties, density, and gas / oil saturation are important formation parameters for evaluating the total oil and gas reserves in an oil and gas field. Various wireline and LWD (logging while drilling) logging tools have been developed to measure downhole formation parameters.

[0003] Neutron porosity logging tools study formation porosity by measuring the ratio of the neutron count rate of the near-detector to that of the far-detector after fast neutrons from an isotopic neutron source (e.g., an Am-Be source) are slowed down and scattered back to the detector by the surrounding environment (e.g., wellbore fluids and formation). This ratio is then converted to porosity based on the specific formation mineralogy (e.g., sandstone, limestone, or dolomite). Using the ratio of the count rates from the two detectors reduces the influence of variations in the near-wellbore environment (wellbore fluids, wellbore size, etc.) on porosity measurements.

[0004] To accurately estimate porosity, one needs to know the stratigraphic type or mineralogical properties (e.g., limestone, sandstone, or dolomite) so that a ratio-porosity conversion specific to the relevant stratigraphic type can be used. Figure 1 This is an example diagram illustrating the conversion between near-far ratios of neutron count rates and porosity for three formation types. Currently, two different logging tools—compensated neutron porosity tools and pulsed neutron mineralogical tools—are used to obtain formation porosity and mineralogical properties, respectively. Otherwise, using the standard ratio-porosity conversion for limestone to estimate formation porosity may overestimate or underestimate it. For example, for 25 p.u. sandstone, the apparent porosity is approximately 20 p.u. using the standard limestone ratio-porosity conversion; for 17 p.u. dolomite, the apparent porosity is also approximately 20 p.u. This bias is as follows: Figure 2 As shown.

[0005] Because the precise mineralogical properties of a formation cannot be obtained simultaneously with neutron counts using neutron logging tools, current neutron porosity measurements typically provide three sets of porosity values ​​based on the mineralogical properties of three different formation types: limestone, sandstone, or dolomite. Therefore, it is necessary to simultaneously measure formation mineralogical properties and neutron count rates to accurately estimate the local porosity of the formation during drilling. Summary of the Invention

[0006] This disclosure provides a novel logging tool that combines a neutron source and a dual-function detector, as well as a method for estimating local formation porosity in real time by simultaneously determining formation type and neutron count rate.

[0007] This invention provides a simplified introduction to a series of concepts, which are further described in the detailed description below. It is not intended to identify key or essential features of the subject matter of the claims, nor is it intended to serve as an aid to defining the scope of the claims.

[0008] According to a currently disclosed embodiment, a method for measuring the porosity of a subsurface formation includes the steps of: deploying a nuclear logging tool into a subsurface formation, wherein the nuclear logging tool includes one or more neutron sources and two or more detectors arranged in a housing, each of the one or more neutron sources being configured to generate pulsed neutrons, and each of the two or more detectors being available for detecting neutrons and gamma rays; causing the one or more neutron sources to emit neutrons into the subsurface formation in the form of multiple neutron pulses, thereby generating neutrons and gamma rays in the subsurface formation; obtaining one or more neutron count rates for each of the two or more detectors; determining the formation type of the subsurface formation based on the gamma rays received by the one or more detectors; calculating a ratio of one or more neutron count rates between the neutron count rates of two selected detectors from the two or more detectors; and obtaining one or more formation porosities based on the formation type and the ratio of one or more neutron count rates.

[0009] According to some embodiments, the steps of determining the stratigraphic type of an underground stratum include: obtaining a first gamma-ray energy spectrum from fast neutron inelastic scattering; stripping the first gamma-ray energy spectrum to identify a first plurality of elements in the underground stratum; and determining the stratigraphic type based on the plurality of identified elements.

[0010] According to other embodiments, the step of determining the stratigraphic type of the subsurface strata further includes the steps of obtaining a second gamma-ray energy spectrum from a thermal neutron capture reaction; and stripping the second gamma-ray energy spectrum to identify a second plurality of elements in the subsurface strata.

[0011] In some embodiments, the identified multiple elements include a first multiple element and a second multiple element.

[0012] According to another embodiment, the method further includes calculating the content of a plurality of identified elements and associating the calculated content with the stratigraphic type of a determined underground stratum.

[0013] According to another embodiment, one or more neutron count rates are selected from the total neutron count rate of total neutrons, the fast neutron count rate of fast neutrons, the ultrathermal neutron count rate of ultrathermal neutrons, and the thermal neutron count rate of thermal neutrons.

[0014] According to other embodiments, the method further includes using pulse shape discrimination techniques to separate the gamma-ray signals from the neutron signals of each of two or more detectors.

[0015] In some of the remaining embodiments, and in some further embodiments, the formation type is obtained by associating one of one or more neutron count rate ratios with a ratio-porosity conversion of the identified formation type.

[0016] In other additional embodiments, the nuclear logging tool includes three or more detectors, such that the method includes calculating a ratio of the three or more neutron count rates based on the neutron count rates received on the three or more detectors.

[0017] In one of the other embodiments, a corrected neutron count ratio is obtained using three or more count ratios obtained from three or more detectors, and the formation porosity is obtained by associating the corrected neutron count ratio with a ratio-porosity conversion for the identified formation type.

[0018] In another embodiment, the values ​​of three or more formation porosity are obtained by associating the ratios of three or more neutron count rates with a ratio-porosity conversion of the identified formation type.

[0019] This disclosure also provides a cable logging tool that includes a currently disclosed nuclear logging tool and a cable connecting to a piece of equipment (such as a cable truck) on the surface. Attached Figure Description

[0020] The teachings of the present invention can be readily understood by considering the following detailed description in conjunction with the accompanying drawings.

[0021] Figure 1 Example diagrams showing the conversion between the near-far ratio of neutron count rate and porosity for three different formation types are presented.

[0022] Figure 2 The discrepancy between the true porosity and the apparent limestone porosity using the standard limestone ratio-porosity conversion is shown for three formation types.

[0023] Figure 3A , Figure 3B , Figure 3C and Figure 3D Four exemplary configurations of a nuclear 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.

[0024] Figure 4A , Figure 4B and Figure 4C A cross-sectional view of an exemplary nuclear logging tool with S1, D1, D2, and D3 is shown.

[0025] Figure 5A and Figure 5B Cross-sectional views of exemplary nuclear logging tools with four detectors (D1, D2, D31, D32) and six detectors (D1, D21, D22, D31, D32, and D33) are shown respectively.

[0026] Figure 6A This is another exemplary embodiment of a nuclear logging tool having two neutron sources (S1, S2) and four detectors (D11, D12, D21, D22); Figure 6B A cross-sectional view of this embodiment is provided.

[0027] Figure 7 This is a block diagram of an exemplary drilling system that implements embodiments of the present disclosure.

[0028] Figure 8 The timing of the neutron pulse, the neutron count rate, and the energy spectra of gamma rays caused by inelastic neutron scattering and by thermal neutron capture reactions are shown.

[0029] Figure 9 This is a flowchart illustrating an exemplary method for obtaining various formation parameters.

[0030] Figure 10A An exemplary gamma-ray energy spectrum from fast neutron inelastic scattering is shown; Figure 10B An exemplary gamma-ray energy spectrum from a thermal neutron capture reaction is shown.

[0031] Figure 11A , 11B 11C and 11D show the gamma-ray energy spectra of neutron inelastic scattering of carbon, oxygen, and magnesium. Figure 11E and 11F The gamma-ray energy spectra of thermal neutron capture for magnesium and calcium are shown respectively.

[0032] Figure 12 A flowchart illustrating a process for estimating real formation porosity in real time according to an embodiment of the present disclosure is shown.

[0033] Throughout the accompanying drawings and detailed description, unless otherwise stated, the same reference numerals will be understood to refer to the same elements, features, and structures. For clarity, illustration, and convenience, the relative sizes and descriptions of these elements may be exaggerated. Detailed Implementation

[0034] The following specific embodiments are provided to help the reader gain a comprehensive understanding of the methods, apparatus, and / or systems described herein. Examples of specific embodiments of this disclosure are shown in the accompanying drawings. Similar or related reference numerals may be used in the drawings and may indicate similar or related elements.

[0035] The features described herein may be embodied in different forms and should not be construed as limiting the embodiments described herein. Rather, the embodiments described herein and depicted in the accompanying drawings are provided to make this disclosure thorough and complete, and to convey the full scope of this disclosure to those skilled in the art, so that they may readily recognize from the following description that alternative embodiments exist without departing from the general principles of this disclosure.

[0036] Therefore, the scope of the invention is not defined by specific embodiments, but by the claims and their equivalents, and all variations within the scope of the claims and their equivalents are to be construed as included in this disclosure.

[0037] In this disclosure, unless otherwise stated, the detector refers to a dual-function detector capable of detecting both neutrons and gamma rays. Such detectors employ scintillation crystals (e.g., Cs₂LiYCl₆ (CLYC) or Cs₂LiLaBr₆ (CLLB)) and associated electronics (e.g., PMTs). When deployed downhole, the detector can be actively or passively cooled. For example, a detector using CLLB and a high-temperature PMT can be used at high temperatures without additional cooling.

[0038] Figures 3A-3D This is a schematic diagram (not to scale) of four exemplary configurations of a cylindrical nuclear logging tool, which features a neutron source (S1) and three dual-function detectors (D1, D2, D3) arranged along the casing of the logging tool for logging-while-drilling (LWD) operations. The mud channel (MC) is positioned along the axis of the logging tool, while the detectors are eccentrically positioned along the longitudinal direction of the logging tool. Figure 3A Also shown are: a high-voltage power supply (HV); electronic instruments (e.g., a controller) for sending commands, receiving and processing data from the neutron source and the detectors; and a telemetry device for transmitting data between the logging tool and the surface. The high-voltage power supply powers the detectors (D1, D2, D3) and the pulsed neutron source (S1). For simplicity, the required power supply, electronic instruments, and telemetry device are not shown. Figure 3B-3D As shown in the image.

[0039] As shown in the figure, D1 is the near detector with the shortest distance to the neutron source in the longitudinal direction, D3 is the far detector with the longest longitudinal distance to the neutron source, and D2 is the middle detector with the longitudinal distance in the middle.

[0040] like Figure 3A As shown, all three detectors are located on one side of the neutron source along the logging tool. This side can be either the proximal side or the distal side of the neutron source. The proximal side is the side closer to the surface when the nuclear logging tool 200 is deployed downhole, while the distal side is the side farther from the surface. High-voltage power supplies power the detectors (D1, D2, D3) and the pulsed neutron source (S1). Signals from each detector are processed by electronic instruments and acquired and transmitted via telemetry. Figure 3B , 3C As shown in 3D, the neutron source has at least one detector disposed on both the distal and proximal sides.

[0041] In wireline logging, this tool can be mounted in a probe that does not include a mud channel. The probe can be mounted along or off-axis of the tool body. Power and control signals can also be supplied to the logging tool from the surface, while data from the logging tool can be transmitted to the surface via cable.

[0042] exist Figures 3A-3D The neutron source S1 in each logging tool depicted is a pulsed neutron generator. The pulsed neutron source can be a deuterium-tritium (DT) pulsed neutron generator, which can operate in pulse mode with various pulse patterns (e.g., frequency, pulse duration). For example, the frequency of the neutron pulse can be approximately 10 kHz (period of 100 μs), and the duration of the neutron pulse can be approximately 20 μs. In another embodiment, the frequency of the neutron pulse can be approximately 1 kHz (period of 1000 μs), and the neutron duration can be 50 μs. Neutrons from the DT neutron generator have an initial energy of approximately 14.1 MeV.

[0043] exist Figures 3A-3D The neutron source S1 and detectors D1, D2 and D3 in the tool 200 are only shown in their relative positions along the longitudinal direction of the tool housing, but not in their radial positions in the cross-section of the tool housing.

[0044] In some embodiments, S1, D1, D2 and D3 can be set in the same radial direction or different radial directions, that is, when deployed in the formation, they have the same or different measurement azimuth angles. Figure 4A , 4B And 4C shows in Figures 3A-3D Exemplary cross-sectional views are shown in the AA, BB, CC, and DD directions.

[0045] Figure 4A S1, D1, D2, and D3 are set at the same azimuth angle. However, in Figure 4BIn the diagram, S1, D1, and D3 have the same azimuth angle, while D2 is at a different azimuth angle. Figure 4C In the diagram, S1 and D1 have the same azimuth angle, while each of D2 and D3 has a different azimuth angle.

[0046] Other embodiments of the logging tool may have two or more detectors, such as four detectors. Furthermore, different detectors can be mounted at two or more different azimuth angles. Having different azimuth angles allows the detectors to preferentially receive neutrons and gamma rays from specific incident angles of the formation. It also improves the detection efficiency of neutrons and gamma rays by increasing the overall count rate of all detectors.

[0047] Furthermore, multiple detectors can be installed at approximately the same distance from the neutron source. For example, such as Figure 5A As shown in D31 and D32, a set of two detectors is mounted at one position on a cylindrical short section. They are axially located at the same third distance from the neutron source, but radially at two different angles, for example, two different azimuth angles. Or as... Figure 5B As shown, a first set of detectors, D21 and D22, is installed at a second distance from the neutron source, and a second set of three detectors, D31, D32, and D33, is installed at a third distance from the neutron source. The third distance is farther from the neutron source than the second distance. Thus, the first set of two detectors acts as an intermediate detector, while the second set of three detectors acts as a distant detector. By using two detectors instead of one, the neutron source can be a weaker source, which may not be subject to the same stringent limitations as a stronger neutron source. Furthermore, the count rate of each individual detector can be recorded and processed separately. The differences in distance and azimuth between the various detectors can be used to obtain stratigraphic information at specific azimuths.

[0048] In some embodiments, the logging tool 200 has multiple shields (not shown) capable of absorbing neutrons and gamma rays. The shields can be placed between the neutron source and each detector within the logging tool, so that the detectors receive neutrons and gamma rays from the formation, rather than neutrons and gamma rays passing through the logging tool body. Alternatively, the detectors can also be partially shielded by shielding materials capable of absorbing neutrons and gamma rays from certain directions.

[0049] The shielding material is made of or contains one or more materials that can effectively attenuate thermal neutrons and gamma rays. The shielding material may contain materials selected from heavy elements with high thermal neutron absorption cross sections, including metals such as gadolinium (Gd) and 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.)).

[0050] The shielding element can be a separate metal component inserted into the logging tool or an integral part of the detector housing. For example, the portion of the detector housing facing inward toward the logging tool can be made of shielding material, while the portion facing the formation can be made of a material transparent to neutrons and gamma rays, forming windows 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 windows are received by the detector. Thus, by adjusting the size and orientation of the windows in the detector housing, the detector can be made more sensitive to certain incident angles. During operation, data collected by various detectors may reveal formation properties in specific directions, which can be used to guide drilling direction.

[0051] Nuclear logging tools can have more than one neutron source. Figure 6A and 6B Another embodiment of a logging tool with two neutron sources (S1, S2) is shown, with one neutron source at the near end and the other at the far end, while four detectors (D11, D12, D21, and D22) are arranged between S1 and S2. Alternatively, depending on engineering considerations, S1 and S2 can be arranged in series near one end of the logging tool, while D11, D12, D21, and D22 are arranged in series near the other end of the logging tool.

[0052] The detectors D11 and D12 (as well as D21 and D22) are positioned at approximately the same distance as S1 or S2. As previously mentioned, having more than one detector at a given distance increases the count rate at that distance, thus allowing the use of a lower-power neutron source. The count rate of a single distant detector may be too low to provide reliable measurement data. By using two or more distant detectors, the count rate can be significantly increased, allowing for reliable measurements to be obtained by processing data from multiple distant detectors as a whole.

[0053] exist Figure 6A and 6BIn variations of other embodiments, two detectors (D1 and D2) may be used between S1 and S2 instead of four detectors (D11, D12, D21, and D22). S1, S2, D1, and D2 may have the same or different azimuth angles. When the ion source and detectors have the same azimuth angle, the measurement covers the same sector in the formation at any given time. When the ion source and detectors may have different azimuth angles, the data generated in D1 and D2 reflect different sectors of the formation, thus revealing differences between different stratigraphic sectors at any given time by comparing the measurements of D1 and D2.

[0054] In some embodiments, S1 and S2 can be turned on or off simultaneously. Doing so increases the count rates of D1 and D2, thereby reducing the uncertainty of the statistical measurement.

[0055] The logging tool 200 may be part of a wireline logging tool or may be included in downhole equipment as a LWD logging tool in drilling operations. Figure 7 This is a schematic diagram of an oil drilling system 10 used in directional drilling of wellbore 16. The oil drilling system 10 can be used for drilling both onshore and underwater. A rotary drilling rig, including a derrick 12, drill platform 14, winch 18, traveling block 20, hook 22, rotary joint 24, kelly joint 26, and rotary table 28, is used to drill wellbore 16 into the formation. The drill string 100 includes multiple drill pipes connected in series and fixed to the bottom of the kelly joint 26 at the surface. The rotary table 28 is used to rotate the entire drill string 100, while the winch 18 is used to lower the drill string 100 into the wellbore 16 and apply a controlled axial compressive load. A downhole tool assembly 150 is located at the distal end of the drill string 100.

[0056] Drilling fluid (also known as mud) is typically stored in a mud pit or mud tank 46 and transported using a mud pump 38, which forces the drilling fluid through a surge suppressor 40, then through a crisscross hose 42, and through a rotary joint 24, thus entering the top of the drill string 100. The drilling fluid flows through the drill string 100 at a rate of approximately 150 gallons per minute to approximately 600 gallons per minute and into the downhole assembly 150. The drilling fluid then 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 transported back to the mud tank 46 via a mud return line 44.

[0057] The pressure required to maintain drilling fluid circulation is measured by a pressure sensor 48 on the angular drill pipe hose 42. The pressure sensor detects pressure changes caused by pressure pulses generated by a pulse generator. The amplitude of the pressure waves from the pulse generator can reach 500 psi or higher. The measured pressure is transmitted as an electrical signal to a ground computer 52 via a sensor cable 50, which decodes and displays the transmitted information. Alternatively, the measured pressure is transmitted as an electrical signal via the sensor cable 50 to a decoder, which decodes the electrical signal and transmits the decoded signal to the ground computer 52, which displays the data on a screen.

[0058] As described above, the lower portion (“far end portion”) of the drill string 100 includes a downhole assembly (BHA) 150, which includes a non-magnetic drill collar in which a MWD system (MWD equipment or MWD tool) 160 is installed, a logging-while-drilling (LWD) instrument sub 165 containing an LWD instrument, a downhole motor 170, a near-bit measurement sub 175, and a drill bit 180 with a borehole nozzle (not shown). Drilling fluid flows through the drill string 100 and exits through the borehole nozzle of the drill bit 180. During drilling operations, 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 traveling block 20. The drilling system 10 can also operate in a sliding mode, in which the drill string 100 does not rotate from the surface, but the drill bit 180 is rotated by the downhole motor 170. Drilling fluid is pumped from the surface to the drill bit 180 via the drill string 100 and injected into the annular space between the drill string 100 and the wall of the wellbore 16. The drilling fluid carries rock cuttings from the wellbore 16 to the surface.

[0059] In one or more embodiments, the MWD system 160 may include a pulse generator subsection, a pulse generator drive subsection, a battery subsection, a central storage unit, a motherboard, a power supply subsection, a orientation module subsection, and other sensor boards. In some embodiments, some of these devices may be located in other areas of the BHA 150. One or more of the pulse generator subsection and the pulse generator drive subsection may communicate with a pulse generator 300, which may be located below the MWD system 160. The MWD system 160 may transmit data to the pulse generator 300, causing the pulse generator 300 to generate pressure pulses.

[0060] The non-magnetic drill collar houses the MWD system 160, which includes components for measuring dip, azimuth, and well trajectory (wellbore trajectory). The nuclear logging tool 200 and associated electronics can be housed in the LWD instrument section 165. The nuclear logging tool 200 and other logging instruments can be electrically or wirelessly coupled together, powered by a battery pack or a drilling fluid-driven generator. All collected information is transmitted to the surface via a mud column in the drill string in the form of pressure pulses generated by the pulse generator 300.

[0061] A near-bit measurement sub 175 can be positioned between the downhole motor 170 and the drill bit 180. A nuclear logging tool 200 can be alternatively mounted in the near-bit measurement sub 175 to provide more accurate real-time formation parameters to guide directional drilling. Data can be transmitted via a cable embedded in the downhole motor 170 to the MWD system 160 in the downhole drill string assembly 150.

[0062] In one embodiment of this disclosure, a logging tool with a DT neutron generator and three dual-function detectors is used to obtain a variety of formation parameters. Figure 8 A schematic diagram is shown, illustrating the neutron pulse, neutron count rate, and the inelastic and trapping energy spectra of neutron-induced gamma rays. The neutron pulse frequency is 10 kHz (period 100 μs), and the neutron pulse width is 20 μs. Figure 8 The subgraph (b) is shown in the figure.

[0063] The neutron count rate measured by each of the three detectors is as follows: Figure 8 Subfigure (a) shows the data used to obtain formation porosity. Neutrons from the three detectors can be further separated based on whether the neutron pulse is on or off, serving as coincidence or anti-coincidence signals for the neutrons from the three detectors, so that during the neutron pulse (when the neutron pulse is on), neutrons are primarily recorded as fast neutrons. Between neutron pulses (when the neutron pulse is off), neutrons are recorded as thermal neutrons. The fast and thermal neutrons recorded by the three detectors can be used to obtain the spatial distribution of fast and thermal neutrons. Neutrons from each detector can also be recorded together. In this case, all neutrons (from thermal to fast neutrons) are used to obtain the spatial distribution of neutrons.

[0064] The gamma rays received by the three detectors can be further separated based on whether the neutron pulse is on or off, thus serving as coincidence or anti-coincidence signals for the gamma rays from the three detectors. This allows the gamma rays to be primarily recorded as an inelastic energy spectrum during the neutron pulse (when the neutron pulse is on), such as... Figure 8 Subgraph (c) is shown in the figure. Between neutron pulses (neutron pulses are off), gamma rays are recorded as a trapping energy spectrum, as shown in the figure. Figure 8Subplot (d) is shown in the figure. An appropriate time window is selected so that the gamma rays measured in the capture time window all come from the thermal neutron capture reaction, and most of the gamma rays measured in the inelastic time window come from fast neutron inelastic scattering.

[0065] The detector background can be measured some time after the neutron generator is turned off and can be subtracted from the total signal of neutrons or gamma rays. The neutron background measured during a neutron pulse can be further subtracted using a small fraction of the neutrons measured between neutron pulses to obtain a “pure” fast neutron spectrum. Similarly, the trapped gamma rays measured during a neutron pulse can be further subtracted using a small fraction of the trapped energy spectrum measured between neutron pulses to obtain a “pure” inelastic energy spectrum.

[0066] Figure 9 This is an exemplary workflow demonstrating the steps of processing data from a logging tool 200, which has a DT neutron generator and three detectors: a near-field detector, a mid-field detector, and a far-field detector. First, pulse shape discrimination (PSD) technology is used to distinguish between neutron and neutron-induced gamma-ray signals from the three detectors. Then, the total count rate (CRN) is obtained using the neutron signals from the three detectors. n CRN m CRN f Fast neutron count rate (CRFN) n CRFN m CRFN f ), thermal neutron count rate (CRTN) n CRTN m CRTN f ), and based on them and using three ratios (Rn) m / f 、Rn n / f 、Rn n / m ), fast neutron distribution (e.g., Rfn) m / f 、Rfn n / f 、Rfn n / m ) and thermal neutron distribution (e.g., Rtn m / f 、Rtn n / f 、Rtn n / m To obtain neutron porosity.

[0067] Fast neutron spatial distribution and thermal neutron spatial distribution can be used to calculate formation elemental content using inelastic and trapped energy spectra. They can also be used to obtain more accurate hydrocarbon saturation. Examples for obtaining formation porosity, density, elemental content, and gas and oil saturation are provided below.

[0068] like Figure 9As shown, the neutron (CRN) count rate (CRN) is measured from near-detector, intermediate-detector, and far-detector during and between neutron pulses. n CRN m CRN f Formation porosity (Φ) is obtained by using the ratio of count rates.

[0069] The mid-distance ratio (Rn) is obtained using formulas 1, 2, and 3 respectively. m / f ), near-far ratio (Rn) n / f ) and the near-middle ratio (Rn) n / m Because the three detectors are positioned at different distances from the neutron source, they have different detection depths. Therefore, the near-wellbore environment (such as wellbore fluids, cement, etc.) has different effects on these three ratios. f / m More sensitive to strata, Rn m / n More sensitive to near-wellbore changes, Rn f / n It is sensitive to both formation and near-wellbore changes.

[0070]

[0071]

[0072]

[0073] Formation porosity Φ n It can be obtained as follows: First use Rn n / m and / or Rn n / f Correction Rn m / f Then use the corrected mid-to-long distance ratio Rnc m / f The formation porosity of a specific stratum (e.g., sandstone, limestone, or dolomite) is obtained. Formulas (4)-(6) illustrate the algorithm, where ΔR is the correction value.

[0074] Rnc m / f =Rn m / f +ΔR (4)

[0075] ΔR=f1(Rn m / f ,Rn n / f ,Rn n / m (5)

[0076] Φ n =f2(Rnc) m / f (6)

[0077] Based on an algorithm similar to that described in Equations 1-6, the formation porosity Φ can also be obtained by using the ratio of the three count rates of the captured gamma rays obtained from the three detectors. n .

[0078] Formation porosity Φ n It can also be obtained by combining the two porosities obtained separately from neutrons and captured gamma rays. Alternatively, it can be obtained directly from the three ratios of neutrons and the three ratios of captured gamma rays using other methods.

[0079] Mineralogical property measurements can be obtained by using the same tools to measure the energy spectrum of gamma rays from neutron inelastic scattering and neutron capture reactions.

[0080] The gamma rays detected by each detector can be recorded in two separate energy spectra (inelastic and captured spectra) or in a single energy spectrum (total or combined spectrum). In either case, elements can be identified, from which the relative yields of characteristic gamma rays and elemental abundances can be obtained. Based on the elemental profile of the formation, the mineralogical characteristics, i.e., the formation type, can be determined. Then, as the logging tools advance, the formation type is used to calibrate or adjust the neutron count ratio to obtain the true porosity of the formation.

[0081] Figure 12 Another workflow is provided, detailing the steps for obtaining real-time formation porosity using a logging tool with a neutron generator and three dual-function detectors.

[0082] In step 1201, the neutron generator in the logging tool emits fast neutrons into the wellbore and formation. In step 1202, the fast neutrons are slowed down by the formation to produce thermal neutrons. Inelastic gamma rays are emitted by the scattering of fast neutrons. Captured gamma rays are emitted by the thermal neutron capture reaction. In step 1203, the neutrons and gamma rays are scattered back and detected by three detectors in the logging tool. In step 1204, the neutron and gamma ray signals from each of the three detectors are separated using, for example, a PSD technique.

[0083] In step 1205, gamma rays from fast neutron inelastic scattering (also known as "inelastic gamma rays") are separated from gamma rays from thermal neutron capture reactions (also known as "captured gamma rays"). Most inelastic gamma rays are generated during neutron pulses, while captured gamma rays are generated between neutron pulses. The signal from the neutron generator is synchronized with the high-voltage signal of the neutron generator target. This signal is then used as the coincidence or anticoincidence signal for the gamma rays after they have been separated from the neutrons using PSD technology. Therefore, gamma rays captured during a neutron pulse (coincidence event) are identified as inelastic gamma rays, while gamma rays between two neutron pulses (anticoincidence events) are identified as captured gamma rays. Inelastic and captured gamma rays are recorded in two different energy spectra for each detector. Figure 10A An exemplary inelastic gamma-ray energy spectrum from fast neutron inelastic scattering is shown, while Figure 10B An exemplary captured gamma-ray energy spectrum from a thermal neutron capture reaction is shown.

[0084] Each inelastic gamma-ray spectrum and captured gamma-ray spectrum is a superposition of signals from multiple elements in the formation. The inelastic gamma-ray spectrum is composed of the gamma-ray spectra of Mg, Fe, S, C, Al, Si, Ca, and O, combined with the background noise of the measuring instrument (i.e., the instrument background). The captured gamma-ray spectrum includes the thermal neutron captured gamma-ray spectra of Mg, S, Ti, Al, K, Ca, Si, Gd, Fe, Cl, and H, combined with the instrument background. To determine the formation type, the combined spectra need to be stripped to estimate the abundance of some or all of these elements in the formation.

[0085] Step 1206 involves stripping the inelastic gamma-ray energy spectrum and the captured gamma-ray energy spectrum to estimate the abundance of these elements. Stripping is complete when the sum of the individual element gamma-ray energy spectra of all elements equals or approximates the combined energy spectrum. In one stripping method, the overall least-squares relative error between the sum of all individual element energy spectra and the combined energy spectrum is used as the standard for data fitting. For example, the least-squares relative error at each data energy point is less than 2% of an acceptable fit. The individual element energy spectrum of gamma rays inelastically scattered by neutrons on C is shown below. Figure 11A As shown, the single-element energy spectrum of gamma rays inelastically scattered by neutrons on O is as follows: Figure 11B As shown, Mg, Si, and Ca can produce gamma rays from fast neutron inelastic scattering and thermal neutron capture reactions, respectively, thus allowing the identification of elements using the energy spectra of gamma rays from inelastic scattering or capture reactions. Figure 11C and Figure 11E The inelastic energy spectrum and thermal capture energy spectrum of Mg are shown respectively. Figure 11D The gamma-ray energy spectrum of fast neutron inelastic scattering of Si is shown. Figure 11F The gamma-ray energy spectrum of thermal neutron capture of Ca is shown.

[0086] Once the energy spectrum of each element has been stripped, step 1207 calculates the elemental weight percentage for each element, for example, using the cross-section of the fast neutron inelastic scattering and / or thermal neutron capture reaction for each element. The sum of the weight percentages of all elements is set to approximately 100%.

[0087] In step 1208, the mineralogical type, such as SiO2, CaCO3, and CaMg(CO3)2, can be determined based on the weight percentages of C, O, Mg, Si, and Ca from the detector. For example, if the weight percentages of O and Si are higher than preset values, the stratum is sandstone (SiO2). If the weight percentages of C, O, and Ca are higher than preset values, while the weight percentage of Mg is lower than preset values, the stratum is limestone (CaCO3). If the weight percentages of C, O, Ca, and Mg are all higher than preset values, the stratum is dolomite (CaMg(CO3)2).

[0088] Steps 1209 and 1210 are performed to obtain the ratio of neutron count rates from the detectors. Specifically, in step 1209, the total neutron count, as well as the count rates of fast and thermal neutrons, are obtained for each detector. Subsequently, in step 1210, the ratio of the thermal neutron count rates between any one or all two of the three detectors is obtained. Specifically, a first ratio can be obtained from a pair of detectors (e.g., middle to far); a second ratio can be between the near and far detectors; and a third ratio can be between the near and middle detectors. It should be noted that the first ratio represents a deeper exploration depth than the second or third ratio. The difference between the first and second or third ratios may indicate that the near-wellbore effect is more significant, and therefore the first ratio may be more reliable. Thus, the first ratio can be selected for the next step.

[0089] Alternatively, a corrected neutron count ratio can be obtained using three or more ratios according to an algorithm. For example, as shown in Formulas 1-6 of this disclosure and their description, multiple ratios can be used to obtain a corrected count ratio, thereby reducing disturbance to the environment near the wellbore.

[0090] In step 1211, based on the formation type determined in step 1208 and the count ratio determined in step 1210, one or more neutron count ratios can be associated with the formation type, and the real-time true formation porosity can be obtained using a ratio-porosity conversion specific to that formation type. For example, using... Figure 1 The chart shown can be used to first select a suitable curve based on the determined formation type, and then find the porosity on that specific curve. Alternatively, a coefficient can be assigned to each formation type based on empirical data. The porosity obtained using the counting ratio is multiplied by this coefficient to obtain the true formation porosity. In this invention, true formation porosity refers to the porosity adjusted according to a specific formation type to make it more accurate.

[0091] Other embodiments are also possible. For example, each neutron count ratio obtained from step 1210 can be applied to obtain its corresponding formation porosity value in step 1211. In this embodiment, step 1211 may generate three or more porosity values, which may not be equal to each other. One of the three or more porosity values ​​can be selected as the formation porosity. The differences between these three or more porosity values ​​can also reveal additional information about the near-wellbore.

[0092] Furthermore, this disclosure uses the thermal neutrons of the detector and the thermal neutron count ratio as examples. However, the count rate and its ratio can also be obtained based on the ultrathermal neutrons detected by a detector sensitive to ultrathermal neutrons. The method disclosed herein remains applicable to using the ratio of ultrathermal neutron count rates.

[0093] Although this disclosure has been described in conjunction with certain preferred embodiments thereof in the foregoing specification, and many details have been set forth for illustrative purposes, it will be apparent to those skilled in the art that this disclosure is readily adaptable and that certain other details described herein may vary considerably without departing from the fundamental principles of this disclosure. Furthermore, it should be understood that the structural features or methods shown or described in any embodiment herein may also be used in other embodiments.

Claims

1. A method for measuring the porosity of underground strata, comprising: Deploying nuclear logging tools into underground formations, wherein the nuclear logging tools include one or more neutron sources and two or more detectors arranged in a housing, each of the one or more neutron sources being configured to generate neutrons in a pulsed manner, and each of the two or more detectors being used to detect neutrons and gamma rays; The one or more neutron sources emit neutrons into the underground strata in the form of multiple neutron pulses, thereby generating neutrons and gamma rays in the underground strata; Obtain one or more neutron count rates for each of the two or more detectors; The stratigraphic type of the underground strata is determined based on the gamma rays received by the one or more detectors, the stratigraphic type being selected from sandstone, limestone, and dolomite; Calculate the ratio of one or more neutron count rates between the neutron count rates of two detectors selected from the two or more detectors; and One or more formation porosities are obtained based on the ratio of the formation type to the one or more neutron count rates. The steps for determining the stratigraphic type of underground strata include: The first gamma-ray energy spectrum was obtained from fast neutron inelastic scattering. Stripping the first gamma-ray energy spectrum to identify a first plurality of elements in the subsurface strata; The second gamma-ray spectrum was obtained from the thermal neutron capture reaction; and Stripping the second gamma-ray energy spectrum to identify a second plurality of elements in the subsurface strata; The formation type is determined based on the first plurality of elements and the second plurality of elements.

2. The method according to claim 1, characterized in that, The plurality of identified elements includes the first plurality of elements and the second plurality of elements.

3. The method according to claim 2, characterized in that, The method further includes: calculating the content of the plurality of identified elements and associating the calculated content with the stratigraphic type of the determined underground strata.

4. The method according to claim 1, characterized in that, Choose one or more neutron count rates from the total neutron count rate of total neutrons, the fast neutron count rate of fast neutrons, the ultrathermal neutron count rate of ultrathermal neutrons, and the thermal neutron count rate of thermal neutrons.

5. The method according to claim 1, characterized in that, The method further includes using pulse shape discrimination technology to separate the gamma-ray signal measured by each of two or more detectors from the neutron signal.

6. The method according to claim 1, characterized in that, The first gamma-ray spectrum is obtained within the duration of each of the plurality of neutron pulses, and the second gamma-ray spectrum is obtained between each consecutive neutron pulse in the plurality of neutron pulses.

7. The method according to claim 1, characterized in that, The formation type is obtained by associating one of the one or more neutron count rate ratios with a ratio-porosity conversion of the identified formation type.

8. The method according to claim 1, characterized in that, The nuclear logging tool includes three or more detectors.

9. The method according to claim 8, characterized in that, The method further includes: calculating a ratio of three or more neutron count rates based on the neutron count rates received on three or more detectors.

10. The method according to claim 9, characterized in that, The method further includes: using three or more count ratios to obtain a corrected neutron count ratio, and obtaining formation porosity by associating the corrected neutron count ratio with a ratio-porosity conversion of the identified formation type.

11. The method according to claim 9, characterized in that, The method further includes: associating the ratio of the three or more neutron count rates with a ratio-porosity conversion of the identified formation type to obtain values ​​for the porosity of the three or more formations.

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