Patent ID: 12216240

Throughout the drawings and the detailed description, unless otherwise described, the same drawing reference numerals will be understood to refer to the same elements, features, and structures. The relative size and depiction of these elements may be exaggerated for clarity, illustration, and convenience.

DETAILED DESCRIPTION

The following detailed description is provided to assist the reader in gaining a comprehensive understanding of the methods, apparatuses, and/or systems described herein. References are made in detail to embodiments of the present disclosure, examples of which are illustrated in the accompanying drawings. Similar or like reference numbers may be used in the drawings and may indicate similar or like elements.

The features described herein may be embodied in different forms and are not to be construed as being limited to the embodiments described herein. Rather, 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 one of ordinary skill in the art, who may readily recognize from the following description that alternative embodiments exist without departing from the general principles of the disclosure.

Therefore, the scope of the disclosure is defined not by the detailed description, but by the claims and their equivalents, and all variations within the scope of the claims and their equivalents are to be construed as being included in the disclosure.

In this disclosure, unless otherwise noted, a detector refers to a dual-function detector that can detect both neutrons and gamma rays. Such a detector employs scintillation crystals such as Cs2LiYCl6(CLYC) or Cs2LiLaBr6(CLLB) and associated electronics, e.g., PMT. The detectors may be actively cooled or not actively cooled when deployed downhole. For example, a detector using CLLB and high-temperature PMT can be used at a high temperature without additional cooling.

FIG.1A,FIG.1B,FIG.1C, andFIG.1Dillustrate how formation gas saturation correlates to formation type, porosity, Rtnn/fand/or Rgn/fratios from the near and far detectors for a specific wellbore environment.FIGS.1A and1Bare exemplary charts showing the correlations between Rtnn/fand Rgn/fof the count rate of capture gamma rays from the near detector to the count rate of capture gamma rays from the far detector, respectively in the limestone formation with varied porosities.FIGS.1C and1Dare exemplary charts showing the correlations between Rtnn/fand Rgn/f, respectively, in the sandstone formation with varied porosities. At the same porosity and gas saturation, Rtnn/fand/or Rgn/fratios are different for limestone and sandstone. Therefore, by measuring Rtnn/fand/or Rgn/fratios using the near and far detectors and applying a correction algorithm for the wellbore fluid, one may reduce the effect of wellbore environments (e.g., wellbore fluid) on the measured formation gas saturation.

To obtain the gas saturation, a series of simulations can also be run using a calibrated model to obtain Rtnn/fand/or Rgn/ffrom the near and far detectors at various formation porosities for a specific formation type in a specific wellbore condition. The calibrated model is a model that has been calibrated (i.e., adjusted) according to experimental data. A calibrated model is to a large extent free of systematic errors but still has statistical errors. Then algorithms can be developed to correlate Rtnn/fand/or Rgn/fand the formation porosity to the gas saturation for typical formation types and a specific wellbore environment (e.g., wellbore size, borehole fluid etc.).

In addition, algorithms can be developed to correlate the ratios of both thermal neutrons and capture gamma rays (Rtnn/f, Rtnn/f, Rtnm/fand Rgn/f, Rtnn/m, Rtnm/f) from more than two detectors at different locations and utilize them to automatically correct near-wellbore environmental effects so that the gas saturation measurement is independent to those effects. The algorithms can be implemented into the tool's firmware or software. In the field application, as soon as formation type is determined, formation porosity, and ratios are obtained, gas saturation can be obtained using the algorithm.

FIGS.2A to2Dare schematic illustrations (not to scale) of four exemplary configurations of a cylindrical nuclear logging tool200having a neutron source (S1) and three dual-function detectors (D1, D2, D3) disposed along the housing of the logging tool suitable for logging-while-drilling (LWD) operations. A mud channel (MC) is disposed along the axis of the logging tool while the detectors are eccentrically disposed along the longitudinal direction of the tool.FIG.2Aalso shows a high voltage power supply (HV), an electronic instrument, e.g., a controller, for sending instructions, receiving, and processing data from the neutron source and the detectors, as well as a telemetry for transmitting data between the logging tool and surface. The high voltage power supply provides power to detectors (D1, D2, D3) and to the pulsed neutron source (S1). The power supply, the electronic instrument, and telemetry are required but not shown inFIGS.2B-2Dfor simplicity.

As shown in the figures, D1is the near detector that has the shortest distance in longitudinal direction to the neutron source, D3is the far detector having the longest longitudinal distance to the neutron source, and D2is the middle detector that has a longitudinal distance that is in the middle.

InFIG.2A, all three detectors reside on one side of the neutron source along the logging tool200. The one side can be either the proximal side or the distal side of the neutron source. The proximal side is the side of the nuclear logging tool200that is closer to the surface when it is deployed downhole while the distal side is farther away from the surface. The high voltage power supply provides power to detectors (D1, D2, D3) and to the pulsed neutron source (S1). The signals from detectors are processed by the electronic instruments and measurements/data are collected and transmitted by telemetry. InFIGS.2B,2C, and2D, both the distal side and the proximal side of the neutron source has at least one detector disposed thereto.

In wireline logging, the tool can be installed in a sonde, which does not contain a mud channel. Detectors can be installed either along or off the axis of the tool body. Power and control signals can also be provided to the logging tool from the surface while data from the logging tool can be transmitted to the surface via the wireline cable.

The neutron source S1in each logging tool depicted inFIGS.2A to2Dis a pulsed neutron generator. However, an isotope neutron source can be used as well. The pulsed neutron source may be a Deuterium-Tritium (D-T) pulsed neutron generator, which can be operated in a variety of pulse schematics (e.g., frequency, duty time) in a pulse mode. For example, the frequency of neutron pulses may be about 10 kHz (the period is 100 μs) and the neutron duty time may be about 20 μs. Depending on the methods and measurements, the D-T neutron generator may also be operated in a continuous mode. In that case, the neutron generator is activated frequent enough so that neutrons are emitted continuously. Neutrons from a D-T neutron generator has an initial energy of about 14.1 MeV.

An isotope neutron source, such as Am-Be, Pu-Be, Cf-252, may also be used in the place of the pulsed neutron source, depending on the target formation parameters and measurement methods. Neutrons from these isotope neutron sources have different energy spectra. For an example, the energy of neutrons emitted from an Am-Be source is from 0 MeV to about 10 MeV with an average energy of about 4.2 MeV. However, due to lower neutron energy, gamma ray signals generated by fast inelastic scattering from carbon and oxygen using an isotope neutron source are much lower than those triggered by a D-T neutron generator.

The neutron source S1and detectors D1, D2, and D3as depicted inFIGS.1A-1Donly show their relative positions along the longitudinal direction of the housing of the tool200but not their positions in the radial direction in a cross-section of the tool housing.

In certain embodiments, S1, D1, D2, and D3can be disposed at the same radial or different radial directions, i.e., having the same or different toolface angles when deployed in the formation.FIGS.3A,3B, and3Cshow exemplary cross-sectional views in the directions of A-A, B-B, C-C, and D-D as shown inFIGS.2A to2D. S1, D1, D2, and D3inFIG.3Aare disposed at same toolface angle. InFIG.3B, however, S1, D1, and D3have the same toolface angle while D2is at a different toolface angle. InFIG.3C, S1and D1have the same toolface angle while each of D2and D3has a different toolface angle.

Other embodiments of the logging tool may have more than three detectors. For example,FIG.4Adepicts a variation of the logging tool inFIG.2Athat has four detectors—D1, D2, D31, and D32. D31and D32have approximately the same distance from S1but are disposed at two different toolface angles. Likewise,FIG.4Bdepicts another variation of tool inFIG.2A, which has six detectors—D1, D21, D22, D31, D32, and D33. In this embodiment, D21and D22are disposed opposite to each other on the cross-sectional area of the logging tool, i.e., the toolface angle of D21and D22is 0° and 180°, respectively. D31, D32, and D33are disposed 120° apart on the cross-sectional area of the logging tool, i.e., a difference in the toolface angles of any two among D31, D32, and D33is 120°. Having different toolface angles allows detectors to preferentially receive neutrons and gamma-rays at certain incident angles from the formation. It also increases the detection efficiency of neutrons and gamma rays by increasing the total count rate of all the detectors.

Further, inFIG.4A, D31and D32have substantially the same distance from S1. InFIG.4B, middle detectors D21and D22have substantially the same distance from S1while far detectors D31, D32, and D33have substantially the same distance from S1. “Substantially the same distance” means the distances from S1to the center of scintillators of the detectors (e.g., D31and D32) is about the same. For example, the difference is less than ½ or ¼″. By this arrangement, the middle detectors as a whole and far detectors as a whole have higher count rates than when only one middle detector or only one far detector is used. Accordingly, the neutron generator S1can be of a less powerful source, which may not be subject to stringent regulations as more powerful neutron sources are subject to. In addition, the count rate of individual detectors can separately be recorded and processed. The differences of various detectors in distance and in toolface angles can be used to obtain formation information in specific azimuthal directions.

In some embodiments, the logging tool200have multiple shields that can absorb neutrons and gamma-rays (not shown). The shields can be placed in the logging tool between the neutron source and the detectors so that the detectors receive neutrons and gamma-rays coming from the formation rather than traveling through the logging tool itself. Alternatively, the detectors can also be partially shielded by the shield material that absorb neutrons and gamma rays from certain directions.

The shield is made of or contains one or more materials that can effectively attenuate both thermal neutrons and gamma rays. The shield material can contain materials chosen from heavy elements having high thermal neutron absorption cross sections, including metals such as gadolinium (Gd), samarium (Sm), metal oxides such as Gd2O3, Sm2O3, B2O3, alloys containing Gd or Sm with other heavy metals Fe, Pb, or W, or materials containing boron, such as tungsten borides (WB, WB2, etc.).

The shield may be a stand-alone metal piece inserted in the logging tool, or an integral part of the detector casing. For example, the portion of the detector casing facing inward to the logging tool can be made of the shield material while the portion facing the formation is made of a material that is transparent to neutrons and gamma rays, forming a window that neutrons and gamma rays can travel through. As such, neutrons and gamma-rays from certain incident angles may be absorbed by the shield material while those travel through the window are received by the detector. Therefore, the detector can be more sensitive to certain incident angles by adjusting the size and orientation of the window in the detector casing. During operation, data collected by various detectors may produce direction-specific formation properties, which can be used to guide directional drilling.

The nuclear logging tool may have more than one neutron sources.FIG.5Ashows a further embodiment of the logging tool having two neutron sources (S1and S2), one at the proximal end and the other at the distal end while two detectors (D1and D2) are arranged between S1and S2. Alternatively, S1and S2can be arranged in tandem and disposed near one end of the logging tool while D1and D2arranged in tandem near the other end, as the engineering considerations require. In both embodiments, the distance between S1and D1is d1, the distance between S1and D2is d2, the distance between S2and D2is d3, while the distance between S2to D1is d4. When S1and S2are both pulsed neutron generators, they can be alternately turned ON or OFF, thereby inducing neutrons and gamma-rays from the formation alternately, which are received by D1and D2. Since there are four different source-to-detector distances (d1to d4), the data generated in D1and D2may be better compensated than tools with only two or three source-to-detector distances for near wellbore effects, such as borehole size, tool standoff, mud weight and/or salinity, casing size, cement thickness, etc. As a result, the obtained formation parameters could be more accurate.

FIG.5BandFIG.5Cillustrate two exemplary embodiments of the logging tool, where the two sources and two detectors can be arranged at same toolface angle or at different toolface angles. When, as inFIG.5B, the sources and detectors have the same toolface angle, the measurement covers the same sector in the formation at any given time. When, as inFIG.5A, the sources and detectors may have different toolface angles, the data generated in D1and D2reflect different sectors of the formation, which can reveal differences amongst various formation sectors at any given time by comparing the measurements from D1and D2.

FIGS.6A and6Billustrate a logging tool that has four detectors (D11, D12, D21, D22) and two neutron sources (S1and S2). Note that the pair of detectors D11and D12(as well as D21and D22) are disposed at substantially the same distance from S1or S2. As indicated before, having more than one detector at a certain distance increase the count rate at that distance so that a less powerful neutron source may be viable. The count rate of one far detector may be too low to provide reliable measurement data. By using two or more far detectors, the count rate can be significantly increased so that reliable measurement results can be obtained by processing data from the multiple far detectors as a whole.

In some embodiments, S1and S2can be turned ON or OFF simultaneously. Doing so increases the count rate of D1and D2, thereby reducing the statistical measurement uncertainty.

In still another embodiment, S1and S2can be same or different types of neutron generators. For example, Both S1and S2can D-T neutron generators or D-D neutron generators, or S1is a D-T neutron generator while S2is a D-D neutron generator.

In yet another embodiment, S1and S2are both isotope neutron sources. Compared with pulsed neutron sources, isotope neutron sources do not need power supply so that the logging tool can be more compact. Moreover, the isotope neutron source has a longer lifetime and is more reliable. For example, the half-life of an isotope Am-Be neutron source has a half-life of 432 years, much longer than the average tube lifetime of a neutron generator of 500 hours to 4000 hours.

In yet another embodiment, S1and S2can be two different types of neutron sources. For example, S1can be a D-T neutron generator or a D-D neutron generator while S2can be an Am-Be neutron source. In the field, the D-T neutron generator or the D-D neutron generator can be turned off, leaving the Am-Be neutron source working by itself to perform the neutron porosity log. Alternatively, the Am-Be neutron source can be taken out from the logging tool so that the D-T neutron generator or the D-D generator alone emits neutron pulses into the surrounding formation. In this case, one may obtain the neutron porosity log as well as other measurements (density, oil and gas saturation, etc.) using the D-T neutron generator or the D-D neutron generator.

The porosity logs obtained using the Am-Be source and the D-T source differ slightly. By comparing these porosity logs of the same well obtained using two different neutron sources, one may obtain the correlation between these two logs. As historical porosity logs were mainly obtained using isotope neutron sources, such correlations may help updating the historical porosity logs so that they become comparable with new logs obtained using pulsed neutron sources. Likewise, the new pulsed neutron porosity logs can be converted to match historical porosity logs to continuously use the reservoir models already built using historical logs in production predictions.

The logging tool200can be a part of a wireline logging tool or be included in a downhole assembly as a LWD logging tool in a drilling operation.FIG.7is a diagram of an oil drilling system10used in the directional drilling of borehole16. The oil drilling system10may be used for drilling on land as well as beneath the water. The borehole16is drilled into the earth formation using a rotary drilling rig that includes a derrick12, drill floor14, draw works18, traveling block20, hook22, swivel joint24, kelly joint26and rotary table28. A drill string100includes a plurality of drill pipes that are serially connected and secured to the bottom of the kelly joint26at the surface. The rotary table28is used to rotate the entire drill string100while the draw works18is used to lower the drill string100into the bore hole16and apply controlled axial compressive loads. The bottom whole assembly150is disposed at the distal end of the drill string100.

The drilling fluid (also referred to as mud) is usually stored in mud pits or mud tanks46, and is transferred using a mud pump38, which forces the drilling fluid to flow through a surge suppressor40, then through a kelly hose42, and through the swivel joint24and into the top of the drill string100. The drilling fluid flows through the drill string100at about 150 gallons per minute to about 600 gallons per minute and flows into the bottom whole assembly150. The drilling fluid then returns to the surface by traveling through the annular space between the outer surface of the drill string100and the bore hole16. When the drilling fluid reaches the surface, it is diverted through a mud return line44back to the mud tanks46.

The pressure required to keep the drilling fluid in circulation is measured by a pressure sensitive transducer48on the kelly hose42. The pressure sensitive transducer detects changes in pressure caused by the pressure pulses generated by a pulser. The magnitude of the pressure wave from the pulser may be up to 500 psi or more. The measured pressure is transmitted as electrical signals through transducer cable50to a surface computer52, which decodes and displays the transmitted information. Alternatively, the measured pressure is transmitted as electrical signals through transducer cable50to a decoder that decodes the electrical signals and transmits the decoded signals to a surface computer52, which displays the data on a display screen.

As indicated above, the lower part (“distal part”) of the drill string100includes the bottom hole assembly (BHA)150, which includes a non-magnetic drill collar with a MWD system (MWD assembly or MWD tool)160installed therein, logging—while drilling (LWD) instruments sub165containing LWD instruments, a downhole motor170, a near-bit measurement sub175, and the drill bit180having drilling nozzles (not shown). The drilling fluid flows through the drill string100and is output through the drilling nozzles of the drill bit180. During the drilling operation, the drilling system10may operate in the rotary mode, in which the drill string100is rotated from the surface either by the rotary table28or a motor in the traveling block20(i.e., a top drive). The drilling system10may also operate in a sliding mode, in which the drill string100is not rotated from the surface but is driven by the downhole motor170rotating the drill bit180. The drilling fluid is pumped from the surface through the drill string100to the drill bit180, being injected into an annulus between the drill string100and the wall of the bore hole16. The drilling fluid carries the cuttings up from the bore hole16to the surface.

In one or more embodiments, the MWD system160may include a pulser sub, a pulser driver sub, a battery sub, a central storage unit, a master board, a power supply sub, a directional module sub, and other sensor boards. In some embodiments, some of these devices may be located in other areas of the BHA150. One or more of the pulser sub and pulser driver sub may communicate with the pulser300, which may be located below the MWD system160. The MWD system160can transmit data to the pulser300so that the pulser300generates pressure pulses.

The non-magnetic drill collar houses the MWD system160, which includes a package of instruments for measuring inclination, azimuth, well trajectory (bore hole trajectory), etc. The nuclear logging tool200and associated electronic components may be located in LWD instrument sub165. The nuclear logging tool200and other well logging instruments may be electrically or wirelessly coupled together, powered by a battery pack or a power generator driven by the drilling fluid. All information gathered may be transmitted to the surface via in the form of pressure pulses generated by the pulser300through the mud column in the drill string.

The near-bit measurement sub175may be disposed between the downhole motor170and drill bit180. The nuclear logging tool200may alternatively been installed in the near-bit measure sub175to provide more accurate real-time formation parameters to guide directional drilling. The data may be transmitted through the cable embedded in the downhole motor170to the MWD system160in the bottom whole assembly150.

In one embodiment of the current disclosure, a variety of formation parameters obtained using a logging tool having a D-T neutron generator and three dual-function detectors.FIG.8shows schematics of neutron pulses, neutron count rates, as well as inelastic spectrum and capture spectrum of neutron-induced gamma rays. The frequency of neutron pulses is 10 kHz (the period is 100 μs) and the neutron duty time is 20 μs, as shown inFIG.8, panel (b).

The neutron count rates measured from each of the three detectors, shown inFIG.8, panel (a), are utilized to obtain formation porosity. Neutrons from three detectors may be further separated according to whether the neutron pulse is ON or OFF, which serves as a coincident or anti-coincident signal to neutrons from the three detectors so that during the neutron pulses (when neutron pulse is ON), neutrons are recorded mainly as fast neutrons. Between the neutron pulses (when neutron pulse is OFF), neutrons are recorded as thermal neutrons. Fast neutrons and thermal neutrons recorded at three detectors can be used to obtain fast neutron space distribution and thermal neutron space distribution. The neutrons from each detector may also be recorded together. In that case, all neutrons (from thermal neutrons to fast neutrons) are used to obtain the neutron space distribution.

Gamma rays from three detectors may be further separated according to whether the neutron pulse is ON or OFF, which serves as a coincident or anti-coincident signal to gamma rays from the three detectors so that during the neutron pulses (neutron pulse is ON), gamma rays are mainly recorded as inelastic spectrum induced by inelastically scattered fast neutrons, shown inFIG.8, panel (c). Between the neutron pulses (neutron pulse is OFF), gamma rays are recorded as capture spectrum induced by thermal neutrons, shown inFIG.8, panel (d). Proper time windows are selected so that gamma rays measured in the capture time window are from thermal neutron capture reactions and most gamma rays measured in the inelastic time window are from fast neutron inelastic scattering.

Background noises in various detectors may be measured while the neutron generator is OFF for a period of time and can be subtracted from the total signals of either neutrons or gamma rays. Neutron background measured during the neutron pulses may be further subtracted to get “pure” fast neutrons by using a small percentage of the measured neutrons between the neutron pulses. Similarly, the capture gamma rays measured during the neutron pulses may be further subtracted to get “pure” inelastic spectrum by using a small percentage of the measured capture spectrum between neutron pulses.

Gamma rays detected by each detector can also be recorded in one energy spectrum (e.g., a total energy spectrum), whether they are initiated from neutron inelastic scattering or neutron capture reactions. Accordingly, several formation measurements are feasible, such as the formation porosity, elemental concentrations, and formation oil/gas saturation, but one may not be able to get formation density, as the spectrum of inelastic gamma rays are needed to obtain the formation density for a D-T pulsed neutron generator-based measurement system.

FIG.9is an exemplary workflow showing the steps in the processing of data from the logging tool200having one D-T neutron generator and three detectors (the near detector, the middle detector, and the far detector) to obtain real-time gas saturation in the formation. In Step1001, the D-T neutron generator emits neutron pulses into the formation surrounding the measurement tool. In Step1002, fast neutrons are slowed down to become thermal neutrons. Inelastic gamma rays and capture gamma rays are produced.

In Step1003, neutrons and neutron-induced gamma rays are detected by the three detectors. In Step1004, signals from neutrons and neutron-induced gamma rays are distinguished from each other, e.g., using the pulse shape discrimination (PSD) technique.

In Step1010, the neutron signals from the three detectors are then utilized to obtain the total count rates (CRNn, CRNm, CRNf), fast neutron count rates (CRFNn, CRFNm, CRFNf) thermal neutron count rates (CRTNn, CRTNm, CRTNf), which are further utilized to obtain the element concentrations in Step1008and the neutron porosity in Step1013by using the ratios of total neutrons (Rnm/f, Rnn/f, Rnn/m), or the ratios of thermal neutrons (Rtnm/f, Rtnn/f, Rtnn/m) obtained in Step1011and formation type obtained in Step1009.

On the other hand, in Step1005, the total energy spectrum from inelastic gamma rays and the total energy spectrum from capture gamma rays are obtained after the separation in Step1004. In Step1006, the total energy spectrum from Step1005can be stripped using standard energy spectrum for single elements, e.g., Mg, Fe, S, C, Al, Si, Ca, O, Ti, K, Gd, CI, and H, etc. in Step1006. Then all element concentrations are obtained in Step1008and the formation type is determined mainly by the concentrations of elements like C, O, Mg, Si, Ca in Step1009. Accordingly, Rgn/fcan be obtained in Step1007.

In addition, in Step1013, the fast neutron count rates and the thermal neutron count rates at the three detectors from Step1011and the inelastic spectrum and the capture spectrum obtained in Step1006are used in calculating formation element concentrations. Once formation element concentrations are known, the formation type can be determined, i.e., in Step1009. Equipped with formation type from Step1009and count rate ratios of thermal neutrons from Step1011, one may obtain formation porosity in Step1013. The ratio (Rtnn/f) of the count rate of thermal neutrons from the near detector to the count rate of thermal neutrons from the far detector can be obtained in Step1012.

Finally, In Step1014, the formation gas saturation can be determined using information on formation type, the ratio of thermal neutrons Rtnn/f, the ratio of capture gamma rays Rgn/f, and formation porosity ϕ, as shown in more details inFIG.10and description below. Note that most of the neutrons detected by the detectors are thermal neutrons while some epithermal neutrons are also detected.

FIG.10presents another embodiment of this disclosure using mathematical symbols and equations, carried out using an exemplary logging tool200(e.g.,FIGS.2A to2D). The count rates of neutrons (CRN) measured during and between neutron pulses from the near detector, the middle detector, and the far detector (CRNn, CRNm, CRNf) are utilized to obtain the formation porosity (ϕ) by using the ratios of the count rates.

The middle-to-far ratio (Rnm/f), the near-to-far ratio (Rnn/f) and the near-to-middle ratio (Rnn/m) can be obtained by using Equations 1, 2, and 3, respectively. Since the three detectors are placed at different distances from the neutron source, they have different depth of investigations. As a result, near-wellbore environments, such as borehole fluid, cement, etc., have different impacts on the three ratios. The Rnm/fis more sensitive to the formation while Rnn/mis more sensitive to the near-wellbore changes.

R⁢nm/f=C⁢R⁢NmC⁢R⁢Nf,(1)Rnn/f=C⁢R⁢NnC⁢R⁢Nf,(2)Rnn/m=C⁢R⁢NnC⁢R⁢Nm.(3)

The formation porosity ϕncan be obtained by first using Rnn/mand/or Rnn/fto correct Rnm/f, and then use the corrected far-to-middle ratio Rncm/f to obtain the formation porosity for a specific formation, e.g., sandstone, limestone, or dolomite. Equations (4)-(6) illustrate this algorithm, ΔR being the correction value.
Rncm/f=Rnm/f+ΔR,(4)
ΔR=f1(Rnm/f,Rnn/f,Rnn/m),  (5)
Φn=f2(Rncm/f).  (6)

Alternatively, the formation porosity ϕnmay also be obtained using the three ratios of capture gamma rays count rates obtained by the three detectors, according to an algorithm similar to that described in Equations 1-6.

The formation porosity ϕnmay also be obtained by combining the two porosities obtained based on neutrons and capture gamma rays. In still other methods, the formation porosity ϕncan be obtained directly from the three ratios of neutrons and three ratios of capture gamma rays using other methodologies.

Formation type can be obtained by measuring the energy spectrum of gamma rays from both neutron inelastic scattering and neutron capture reactions, using the same tool. Neutron pulses from the D-T neutron generator are timed as descried in relation toFIG.8. Neutron-induced gamma ray signals from the three detectors, after being separated from neutron signals, are further separated into gamma ray signals from thermal neutron capture reactions and gamma ray signals from fast neutron inelastic scattering. The inelastic spectrum is the basis for detecting Mg, Fe, S, C, Al, Si, Ca, and O elements. The capture spectrum provides information on other elements, such as Mg, S, Ti, Al, K, Ca, Si, Gd, Fe, Cl, H elements.

In some embodiments, gamma rays detected by each detector may be recorded either in two separate spectra (inelastic spectrum and capture spectrum) or in one spectrum (a total spectrum). In either case, the elements can be identified, relative yields of characteristic gamma rays from those elements can be obtained, so as the element concentrations.

Since the three detectors in the logging tool200detect both neutrons and gamma rays simultaneously at three different locations, one may obtain a more precise neutron space distributions (both fast neutron space distribution and thermal neutron space distribution) using the neutron count rates from three detectors. The measured neutron space distributions can then be utilized to get a more accurate calculation of the concentrations of elements.

In this embodiment, both capture gamma rays and thermal neutrons obtained, e.g., in Step1005and in Step1010inFIG.9, are used to calculate the ratios between two among the near, middle, and far detectors, e.g., Rgn/f, Rgn/m, or Rgm/f. Likewise, the thermal neutron count rate ratio between two among the near, middle, and far detectors, e.g., Rtnn/f, Rtnn/m, and Rtnm/fcan be obtained. The following discussion uses the ratios obtained between the near and far detectors Rgn/fand Rtnn/fin the example for illustrative purposes.

An exemplary algorithm calculates the gas saturations for a known wellbore environment (borehole size, wellbore fluid, casing, etc.) is shown by using Equations 7-9.
Sgn=f1(Rtnn/f,Φ,formation type),  (7)
Sgg=f2(Rgn/f,Φ,formation type),  (8)
Sg=f4(Sgn,Sgg).  (9)

In this illustration, the formation type can be sandstone, limestone, or dolomite, which can be determined real time during drilling logging while drilling operation. Formation porosity Φ can also be obtained as illustrated inFIGS.9and10, according to an algorithm, such as illustrated in Equation 6. Wellbore fluid is the fluid filled inside the wellbore, which can be water, oil, gas, drilling mud, or their mixture, which is known during drilling operations.

Sgnis the estimated formation gas saturation based on thermal neutron data, Sggis the estimated formation saturation based on capture gamma ray data, while Sg is the estimate gas saturation by combining Sgnand Sggaccording to a mathematical relation that can be empirical based historical data or a theoretical relation. Accordingly, for a specific well filled with a specific fluid, one can estimate the gas saturation using two or more dual-function detectors at different positions for various formation types in real time.

While the above embodiment uses the ratios of thermal neutron count rates and capture gamma ray count rates between the near and far detectors, one may use ratios between the near and middle detectors or the middle and the far detectors. More ratios can be obtained if there are more than three dual-function detectors. Accordingly, multiple estimated gas saturation values can be obtained. They can be synthesized according to an algorithm to obtain another gas saturation value.

While in the foregoing specification this disclosure has been described in relation to certain preferred embodiments thereof, and many details have been set forth for purpose of illustration, it will be apparent to those skilled in the art that the disclosure is susceptible to alteration and that certain other details described herein can vary considerably without departing from the basic principles of the disclosure. In addition, it should be appreciated that structural features or methodologies shown or described in any one embodiment herein can be used in other embodiments as well.