90 results about "Neutron porosity" patented technology

System and method for characterizing formation properties based on NMR measurements. NMR clay measurements of this invention distinguish between interstitial pore water and the water adsorbed by the clay minerals. The measurements can be used to determine the quantity of adsorbed water in different clays and correct previously available data obtained using conventional density and neutron porosity logs. A new petrophysical parameter wetness clay is defined as an intrinsic parameter for clays, and its value is computed for members of the smectite group of clays, such as montmorillonite. The wet clay values for the density, neutron logs based on the adsorbed water in clays are used to enhance the quality and accuracy of the overall log interpretation.

A method of measuring characteristics of a geologic formation, using the time, energy and spatial spectra of gamma rays induced by an accelerator, which allows (i) the measurement of the photoelectric absorption (Pe) factor of the formation using a gamma-ray spectrum detected from gamma rays induced in the formation, (ii) the calculation of a neutron porosity of the formation using the gamma-ray spectrum, and (iii) the determination of a bulk density of the formation using the spectroscopic measurements. The Pe factor may be inferred by directly mapping the spectroscopic measurements. The porosity may be calculated by relating the gamma-ray spectrum to a hydrogen content of the formation. The density may be determined by computing a gamma diffusion length of the formation based on the gamma-ray spectrum. In addition to these measurements, the resistivity of the formation and its spontaneous potential may also be measured using an electromagnetic induction system.

Method for evaluating cement integrity in a cased well environment using a logging tool that has a neutron source and one or more neutron or gamma ray detectors. Neutron porosity logs are obtained from the well before (42) and after (41) casing. This log data along with well dimensions and material composition parameters are the input quantities to a multi-parameter database (43) that is constructed by computer modeling or laboratory experiments to relate volume fraction for fluid filled channels in the cement sheath to the input quantities. The channel volume fraction (45) corresponding to the input quantities is identified or interpolated (44) from the multi-parameter database.

The invention discloses a method for judging the reservoir fluid type of a difference between density porosity and neutron porosity and relates to the technical fields of oil and gas logging and geology and core test analysis. The method comprises the following steps: 1) accurately calculating the shale content, the rock composition, the density porosity and the neutron porosity of a reservoir bycore data calibrating logging and logging data environmental correction; 2) removing the influence of factors of lithology, well diameter and mud invasion on density and neutron data; and 3) establishing standards for judging the reservoir fluid type by utilizing the response difference of the density and the neutron data to gas and formation water and by comparing the values of the density porosity and the neutron porosity. When the invention judges the reservoir fluid type by utilizing the density and the neutron data, non-fluid influencing factors, such as lithology, borehole conditions, mud invasion and the like are removed, therefore, influence features of different fluids to the density and the neutron data can be truly reflected, and the coincidence rate for judging the reservoir fluid type can be enhanced to above 90 percent from the existing 70 percent.

The invention discloses a method for judging the fluid type of a reservoir through an acoustic porosity-neutron porosity differential, which relates to the technical field of oil and gas logging, geology and core test analysis. The method comprises the following steps: 1) accurately calculating shale content, rock compositions, acoustic porosity and neutron porosity of the reservoir through core data calibration logging and logging data environment correction; 2) excluding the influence of factors such as lithology, borehole diameter and mud invasion on an acoustic transit time and neutron data; and 3) establishing a standard for judging the fluid type of the reservoir by comparing the magnitude of the acoustic porosity and the neutron porosity and using the response difference of the acoustic transit time and the neutron data to the gas and formation water. In the method, non-fluid influence factors such as the lithology, borehole conditions, mud invasion and the like are excluded when the fluid type of the reservoir is judged, so the characteristics of the influence of different fluids on the acoustic transit time and the neutron data can be grasped truly, and the coincidence rate of judging the fluid type of the reservoir is improved from 70 percent currently to over 90 percent.

Harmonics and subharmonics of acoustic measurements made during rotation of a sensor on a downhole are processed to estimate the location of the imager, and size and shape of the borehole. A piecewise elliptical fitting procedure may be used. These estimates may be used to correct measurements made by a standoff-sensitive formation evaluation sensor such as a neutron porosity tool.

A system for measuring the size of a borehole penetrating an earth formation is disclosed. The system uses a neutron source and a least one neutron detector. The neutron detector responds primarily to the composite hydrogen content of material within the borehole and formation upon irradiation by the neutron source. A partition response function is used to delineate the portion of the detector response resulting from borehole and from the formation. Since the detector response from the borehole can be isolated using the partition function and the hydrogen content of the borehole fluid is generally known, the size of the borehole can be determined from borehole response portion of the composite detector response if combined with a neutron porosity measurement of the formation. The neutron porosity measurement can be obtained independently, or by combining the neutron detector response with the response of a second neutron detector at a different axial spacing from the neutron source. The system is applicable in both logging-while-drilling and wireline logging operations.

The invention discloses a method for identifying a fluid type of a reservoir with a complicated pore structure by using conventional logging information and relates to the technical field of judgment of the fluid type according to logging information for oil-gas field exploration and development. The method comprises the steps of 1, distinguishing a gas layer from a non-gas layer according to a ratio of the neutron porosity to the acoustic porosity or the density porosity, wherein the non-gas layer comprises a dry layer, a gas-water layer and a water layer; 2, distinguishing an effective reservoir from an ineffective reservoir in the non-gas layer by a pore-full intersection method; and 3, based on the effective reservoir in the second step, comprehensively identifying the fluid type of the reservoir by a pore-power intersection method and gas logging. According to the method disclosed by the invention, the technical problem in evaluation of fluid type identification for a high-porosity dry layer, a middle-porosity dry layer, a high-resistance water layer and a high-resistance gas-water layer well which have high bound water characteristics under the condition that only conventional logging information is provided is effectively solved, and the difficulty in judgment of the reservoir type represented by the Majiagou formation is effectively solved.

A nuclear logging-while-drilling measuring systems, and the correction of the formation property measurements for adverse effects of instrument standoff from the borehole wall, is disclosed. Detector responses for one or more downhole detectors are sampled and recorded over a time segment. The response samples are then sorted by magnitude, and a running integral of the sorted samples as a function of time is performed over the time segment. Linear segments are then fitted to the running integral, wherein each straight line segment is a function of one or more formation properties, and also a function of the standoff distance of the detector from the borehole wall. Segments are then combined to obtain a measure of one or more formation properties of interest such as formation density, where the adverse effects of borehole standoff are minimized. Standoff magnitude is also obtained and can be used to correct other logs, such as a neutron porosity log, for adverse effects of tool standoff and borehole size. No independent caliper of the borehole is required to perform the standoff correction.

Harmonics and subharmonics of acoustic measurements made during rotation of a sensor on a downhole are processed to estimate the location of the imager, and size and shape of the borehole. A piecewise elliptical fitting procedure may be used. These estimates may be used to correct measurements made by a standoff-sensitive formation evaluation sensor such as a neutron porosity tool.

The invention provides a well logging prediction method of shale gas horizontal well single well production capacity. The method comprises the steps of firstly conducting well logging of interval transit time, density and neutron porosity in a drilled horizontal well, and recording the penetrating depth of a horizontal well section and the corresponding vertical depth; then using formation density well logging and compensated neutron well logging information to calculate formation brittle mineral content; utilizing the three well logging curves of the interval transit time, the density and the neutron porosity which reflect formation porosity in the well to calculate the formation porosity; utilizing a method of inverting reservoir permeability through stoneley wave attenuation to solve formation permeability; utilizing an organic carbon content experiment measurement value a stone sample taken in a formation and density well logging to establish a relation to obtain a calculation formula of organic carbon content; utilizing the formation organic carbon content to calculate to obtain formation gas saturation; finally according to the formation brittle mineral content, the formation porosity, the formation permeability and the formation gas saturation to calculate to obtain the daily production capacity of single well shale gas.

In some embodiments, apparatus and systems, as well as methods, may operate to irradiate a portion of a geological formation (94) with neutrons in a neutron burst generated by a switchable electronic source (84), to measure (with one or more detectors (86) a flux of gamma rays to provide a measured flux, at least a portion of the gamma rays being generated by the neutrons, and to determine one one or more of a neutron porosity, a density, and / or a photoelectric factor of the geological formation based on the measured flux. Other apparatus, systems, and methods are disclosed

A logging-while-drilling density sensor includes a gamma ray source and at least two NaI detectors spaced apart from the source for determining measurements indicative of the formation density. A magnetometer on the drill collar measures the relative azimuth of the NaI detectors. Measurements made by the detectors are partitioned into bins defined by azimuth. A compensated bulk density is determined for selected ones of said azimuthal sectors that meet a threshold test related to a minimum difference of measurements or a minimum correction. The method of the invention may also be used with neutron porosity logging devices.

Caliper measurements made during rotation of a bottomhole assembly are processed to estimate the location of the BHA, and size and shape of the borehole. A piecewise elliptical fitting procedure may be used. These estimates may be used to correct measurements made by a standoff-sensitive formation evaluation sensor such as a neutron porosity tool. It is emphasized that this abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

A method for determining at least one formation property calculated from neutron measurements acquired with a downhole tool includes emitting neutrons from a source in the tool into the formation, detecting neutrons with at least one detector in the downhole tool, calculating a first slowing-down length (L1) based on the detected neutrons, and deriving a second slowing-down length (L2) based on the first slowing-down length (L1). Further steps include deriving a correlation function for relating slowing-down lengths from a first tool to slowing-down lengths associated with a different source, wherein the correlation function depends on formation properties such as bulk density; and applying the correlation function to the slowing-down length of the first tool to derive the slowing-down length of the second tool. A method for determining a thermal neutron formation porosity based on a slowing-down length from epithermal neutron measurements from an electronic neutron source includes converting the slowing-down length into a computed neutron slowing-down length from thermal neutron measurements from a chemical neutron source, wherein the converting uses a correlation function that depends on formation bulk density; deriving a thermal neutron countrate ratio based on the computed neutron slowing-down length, wherein the deriving uses a function that depends on the formation bulk density and formation sigma; and computing the thermal neutron formation porosity from the thermal neutron countrate ratio.

A logging-while-drilling density sensor includes a gamma ray source and at least two NaI detectors spaced apart from the source for determining measurements indicative of the formation density. A magnetometer on the drill collar measures the relative azimuth of the NaI detectors. Measurements made by the detectors are partitioned into bins defined by azimuth. A compensated bulk density is determined for selected ones of said azimuthal sectors that meet a threshold test related to a minimum difference of measurements or a minimum correction. The method of the invention may also be used with neutron porosity logging devices.

Apparatus and methods for determining borehole diameter and standoff for neutron porosity logging systems. The apparatus comprises an isotopic neutron source, a single epithermal neutron detector and two thermal neutron detectors, where all detectors are at different axial spacings from the neutron source. Thermal neutron porosity is determined from the combined response of the thermal neutron detectors. Epithermal neutron porosity is determined from the response of the single epithermal neutron detector. Embodied as a wireline system, a difference between thermal neutron porosity and epithermal neutron porosity is used to compute a tool standoff, which in turn is used to correct the thermal neutron porosity for effects of standoff. Borehole size measurements are made independently and preferably with a mechanical caliper of a density tool subsection. Embodied as a LWD system, the difference between thermal neutron porosity and epithermal neutron porosity is used to correct the thermal neutron porosity measurement for both borehole diameter and radial position (standoff) of the tool within the borehole.

Caliper measurements made during rotation of a bottomhole assembly are processed to estimate the location of the BHA, and size and shape of the borehole. A piecewise elliptical fitting procedure may be used. These estimates may be used to correct measurements made by a standoff-sensitive formation evaluation sensor such as a neutron porosity tool.

A method for determining at least one formation property calculated from neutron measurements acquired with a downhole tool includes emitting neutrons from a source in the tool into the formation, detecting neutrons with at least one detector in the downhole tool, calculating a first slowing-down length (L1) based on the detected neutrons, and deriving a second slowing-down length (L2) based on the first slowing-down length (L1). Further steps include deriving a correlation function for relating slowing-down lengths from a first tool to slowing-down lengths associated with a different source, wherein the correlation function depends on formation properties such as bulk density; and applying the correlation function to the slowing-down length of the first tool to derive the slowing-down length of the second tool. A method for determining a thermal neutron formation porosity based on a slowing-down length from epithermal neutron measurements from an electronic neutron source includes converting the slowing-down length into a computed neutron slowing-down length from thermal neutron measurements from a chemical neutron source, wherein the converting uses a correlation function that depends on formation bulk density; deriving a thermal neutron countrate ratio based on the computed neutron slowing-down length, wherein the deriving uses a function that depends on the formation bulk density and formation sigma; and computing the thermal neutron formation porosity from the thermal neutron countrate ratio.

Caliper measurements made during rotation of an imager on a logging string are processed to estimate the location of the imager, and size and shape of the borehole. A piecewise elliptical fitting procedure may be used. These estimates may be used to correct measurements made by a standoff-sensitive formation evaluation sensor such as a neutron porosity tool. It is emphasized that this abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. 37 CFR 1.72(b).

The invention discloses a method for obtaining the undercompaction overpressure in a stratum. The method comprises the steps that 1, firstly, according to the difference change characteristics of theaverage interval transit time, the average stratum density and the average neutron porosity of a mudstone section along with the average buried depth, the normal compaction section and the undercompaction section are determined; 2, then the index relation of the acoustic wave velocity and the vertical effective stress is fitted by utilizing a scatter diagram of the acoustic wave velocity and the vertical effective stress of the normal compaction section; 3, due to the fact that change of the vertical effective stress and the acoustic wave velocity of the undercompaction section needs to fall on a change trend curve of the acoustic wave velocity and the vertical effective stress of the normal compaction section, the acoustic wave velocity of the undercompaction section is substituted into the index relation obtained in the step 2, and the vertical effective stress of the undercompaction section is obtained; and 4, finally, the overpressure value in the undercompaction section is obtained by combining the relation of the vertical effective stress of the undercompaction section and the overpressure. The magnitude of the undercompaction overpressure can be accurately obtained only through logging data, the characteristics of rapidity, simpleness, convenience and accuracy are achieved, and the evaluation efficiency on the undercompaction overpressure is improved.

An apparatus for estimating a property of an earth formation penetrated by a borehole, the apparatus includes: a carrier configured to be conveyed through the borehole; a neutron source disposed at the carrier and configured to irradiate the earth formation with neutrons; a neutron detector disposed at the carrier and configured to detect neutrons reflected by the earth formation to the detector; a neutron reflector disposed partially around the detector, an area of the detector not covered by the reflector being configured to admit the reflected neutrons; and a neutron absorber disposed at least around the reflector.

The invention provides an oil-water property identification method for a compact sandstone oil reservoir. The oil-water property identification method comprises the steps that S1, the interval transittime and neutron logging data are collected and converted into corresponding acoustic porosity and neutron porosity curves; S2, the converted acoustic porosity and neutron porosity curves are corrected, thus the acoustic porosity and neutron porosity curves are superimposed on the mudstone formation, and a fluid indicating curve is built; and S3, according to the difference value of the acousticporosity and the neutron porosity in the fluid indicating curve, the oil-water property judging standard of the compact sandstone oil reservoir is determined, and the oil-water property is identified.By adopting the method provided by the invention, the reservoir fluid property can be quickly and accurately identified, and the accuracy of the logging technology in compact sandstone reservoir fluid identification is greatly improved.

The invention provides a method for calculating the shale content of a conglomerate oil reservoir based on log curve reconstruction. The method comprises the following steps of (1), measuring the shale content of a rock core sample; (2), optimal selection of sensitivity curves of shale: determining the shale content of the conglomerate oil reservoir and a compensated neutron porosity log curve as well as a compensated density log curve as sensitivity curves for calculating the shale content; (3), normalization processing of the curves: on the basis of the sensitivity curves for calculating the shale content, which are determined in the step (2), carrying out the normalization processing on the compensated neutron porosity log curve and the compensated density log curve respectively; (4), constructing a shale content calculating parameter (NZCS (New Zealand Computing Solution)); (5), establishing and optimizing a calculation model. By using the method for calculating the shale content of the conglomerate oil reservoir based on the log curve reconstruction, which is provided by the invention, the influences of lithology and heterogeneity on a calculation result of the method in the process of calculating the shale content of the conglomerate oil reservoir are eliminated; the calculation precision of the shale content of a reservoir stratum is improved.

A computer system and computer implemented method for automatically identifying a hydrocarbon (such as kerogen, gas, oil) rich zone in a well bore includes obtaining well log data comprising neutron data, density data, radioactivity data, and resistivity data representative of physical characteristics of a formation surrounding the well bore and computing an apparent neutron porosity and an apparent density porosity based on the neutron data and density data. A normalized neutron-density separation is computed based on the computed apparent neutron porosity and the computed apparent density porosity and a baseline of the formation is determined for each data type. Using the computed normalized neutron-density separation, the radioactivity data, the resistivity data, and the determined baselines, the presence or absence of a hydrocarbon rich zone is determined. A quality index may further be derived from the data.

A neutron porosity measurement device adapted to receive a neutron source configured to emit neutrons having a first energy includes a segmented semiconductor detector located at a predetermined distance from the neutron source. The segmented semiconductor detector includes a plurality of semiconductor neutron detection cells configured to detect neutrons having a second energy smaller than the first energy. The cells are arranged in subsets located between a first distance and a second distance from the neutron source, each subset including semiconductor neutron detection cells surrounding an axis and being disposed in opposite sectors defined relative to the axis at substantially same distance from the neutron source. One or more of the neutron detection cells are configured to acquire data related to detected neutrons independently from one or more other of the neutron detected cells. A method of manufacturing the neutron porosity measurement device is also provided.

The invention provides a stratum density measuring while drilling instrument based on a deuterium-tritium accelerator neutron source. The stratum density measuring while drilling instrument is used for measuring the density of a stratum around a well hole in the well drilling process, and meanwhile can measure the neutron porosity. According to the stratum density measuring while drilling instrument, a U-shaped groove is formed in one side of a drill collar, a fast neutron monitoring detector and a neutron generator are arranged inside a neutron generator module compression resistance cylinder, a neutron shielding body, a first thermal neutron detector, a neutron shielding body, a second thermal neutron detector, a gamma ray shielding body, a gamma detector and a control processing circuit are sequentially installed inside a detector installation skeleton from top to bottom, and the neutron generator module compression resistance cylinder and the detector installation skeleton are connected and fixed into the U-shaped groove through a coupling connector. The stratum density measuring while drilling instrument adopts the deuterium-tritium accelerator neutron source for measuring the stratum density, a chemical gamma radioactive source is prevented from being used, damage to people and environment is eliminated, and the measuring precision is effectively improved by monitoring the neutron yield in real time.

Method and system are disclosed for determining hydrocarbon CDVs in a multiphase environment. The method and system involve calculating a total hydrocarbons volume from an apparent oil volume and an apparent gas volume. The apparent oil volume is determined using C / O data from a nuclear logging tool operating in inelastic neutron scattering mode. The apparent gas volume is determined using neutron porosity data from a nuclear logging tool operating in pulsed neutron capture (''PNC'') mode. It is also possible to determine the total hydrocarbons volume using log data from formation thermal neutron capture cross section measurements, or a cased hole formation resistivity tool. The total hydrocarbons volume is then used to back-calculate the total hydrocarbons CDV at various formation depths using the logged C / O data. The resulting independently calculated total hydrocarbon CDV may be used for proper matching of log data and simulation results for history matching purposes.

A logging-while-drilling density sensor includes a gamma ray source and at least two NaI detectors spaced apart from the source for determining measurements indicative of the formation density. An acoustic caliper is used for making standoff measurements of the NaI detectors. Measurements made by the detectors are partitioned into standoff bins. An adaptive spine and rib method uses the standoff measurements to obtain density estimates. The method of the invention may also be used with neutron porosity logging devices.

Caliper measurements made during rotation of an imager on a logging string are processed to estimate the location of the imager, and size and shape of the borehole. A piecewise elliptical fitting procedure may be used. These estimates may be used to correct measurements made by a standoff-sensitive formation evaluation sensor such as a neutron porosity tool. It is emphasized that this abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.