RU2351963C1 - Method of assessment of reservoir bed porosity in horizontal wells by implemeting three-probe neutron survey - Google Patents

Abstract

FIELD: mining.

SUBSTANCE: according to invention there is performed: irradiation of rock with flow of fast neutrons from source of fast neutrons located in well apparatus; separate recording of slow electrons retarded in rock and well with three detectors arranged along axis of well apparatus; forming signals at each quantum of depth proportional to density of absorption of slow electrons in each detector; forming synthetic three-component signal at each quantum of depth with implementation of forming facility, where components of signal are densities of neutron absorption in each of detectors; calibrating obtained synthetic three-component signal for determination of dependence of obtained synthetic signal from porosity and interfering factors; calibrating obtained synthetic three-component signal by means of its measuring in well relative to reservoir bed and to dense reservoir-not bed using obtained results for assessment of porosity in this well; evaluation of collector bed porosity on earlier obtained values of synthetic signal at each quantum of depth in inclined well.

EFFECT: upgraded reliability and noise-immunity of method.

5 cl, 5 dwg

Description

The invention relates to the field of geophysics, namely to oilfield geophysics, and can be used in the study of wells, mainly horizontal, by the method of neutron logging to determine the characteristics, in particular porosity, surrounding the formation well.

In accordance with the instructions for logging (2004), the term “horizontal well” describes wells with an azimuthal angle of inclination of 57 to 110 ° into which the logging tool cannot be lowered by its own weight.

In the framework of this technical solution, the sign of depth quantum was used. This term means the product of the value of a predetermined time quantum by the current speed of the drill pipe.

Known (RU, patent 2253885) is a method for determining the oil productivity of porous reservoirs in a three-dimensional interwell space on the territory of oil fields, including conducting ground-based seismic exploration, drilling with coring, electrical, radioactive, acoustic, seismic logging, coring, well testing and judgment obtained data on the presence of porous reservoirs, their hydraulic conductivity, oil productivity, the level of water-oil contact and the location of oil fields. When implementing the method in the inter-well space, 3D longitudinal seismic surveys are carried out using the longitudinal depth method, according to the data of drilling and geophysical studies of wells, reference model seismic and borehole spectral-temporal images of oil productive deposits and their spectral-temporal attributes are determined, and according to the data of ground three-dimensional seismic exploration in the well region, reference experimental spectral-temporal images and their volumetric spectral seismic attributes on again using the spectral-temporal analysis of 3D seismic data in the target recording interval and quantifying its results, which is the ratio of the energy of high-frequency spectra and large times to the energy of low-frequency spectra and small times. Then, the conductivity and oil production coefficients are cross-correlated according to the data of drilling and geophysical studies of wells with reference model seismic, borehole spectral-temporal attributes and 3D spectral seismic attributes according to 3D seismic data with the choice of the optimal volumetric spectral seismic attribute with the highest cross-correlation coefficient and cross-correlation coefficient the dependence of the optimal volumetric spectral seismic atrib uta or a complex attribute with the values of hydraulic conductivity and oil productivity coefficient of porous reservoirs according to drilling and geophysical studies of wells. Based on the foregoing, for all traces of the seismic temporary cube, spectral-temporal analysis and its quantitative spectral-temporal parameterization are carried out according to the optimal volumetric spectral seismic attribute or complex attribute with the construction of the attribute cube and its subsequent conversion into regression dependences into cubes of hydroconductivity and oil productivity, i.e. determination of the oil productivity of porous reservoirs at any point in the three-dimensional interwell space in the oil fields.

The disadvantage of this method should recognize its complexity.

It is also known (SU, copyright certificate 406179) for pulsed neutron logging, consisting of a ground part containing a power supply, a control pulse generator, time analyzers, thermal neutron lifetime calculators and a recorder, and a depth tool containing a pulsed neutron source with power supplies and control, a scintillation detector of neutrons and gamma-quanta with a pulse separator, which includes a circuit for comparing the full and differentiated current pulses and the anti-coincidence circuit and also an output device, while for measuring a parameter characterizing formation saturation in cased wells, the surface part of the device is additionally equipped with a meter for the ratio of count rates connected to temporary channels of analyzers with the same delay and width values.

The known device operates as follows. When power and control pulses are applied, a pulsed neutron generator emits fast neutrons, which, interacting with environmental nuclei, are slowed down and captured. The resulting neutrons and gamma rays are recorded using a scintillation counter that is sensitive to both neutrons (suprathermal and thermal) and gamma rays. A circuit comparing the total and differential current pulses, comparing the total charge in a pulse with the charge obtained after differentiating the initial signal, produces a signal only when a neutron enters the crystal. This signal is formatted into a rectangular pulse using a pulse shaper block and is fed to the inputs of the output device and the anti-coincidence circuit. The driver amplifier amplifies all pulses and generates rectangular pulses. These pulses are fed to another input of the anti-coincidence circuit, at the output of which a pulse signal arises, which is the result of gamma rays entering the counter crystal. At the output of the output device, pulses of different polarity arise: pulses from neutrons of one polarity, pulses from gamma rays of another polarity. These pulses are sent to the surface of the earth via a wireline cable, where they are separated and fed to the inputs of temporary analyzers. Pulses of time zero to the marker inputs of the analyzers come from the control pulse generator. The pulses received from the well are analyzed in a known manner.

A disadvantage of the known technical solutions should recognize its inapplicability for work in horizontal wells.

Known methods and devices for conducting multi-probe neutron logging of wells (including horizontal) (Khamatdinov R.T. Geological and geophysical technologies, LLC Neftegazgeofizika KAROTAZHNIK No. 2-4 (143-145), Tver, 2006, p. 27; Urmanov E.G., Shkadin M.V., Shirkin V.A., Bannov D.K. Equipment for radioactive logging methods for the study of superdeep wells, ibid., P. 259). Using these methods, the rock is irradiated with a source of fast neutrons and the flux of slow neutrons is recorded by three detectors (Cascade equipment , APRK-3 ) or several detectors of epithermal and thermal neutrons (Tverts equipment ).

The disadvantages of these methods is the lack of a description of the technology for the direct determination of rock porosity from the results of these measurements. This does not allow to determine the reliability and noise immunity of these methods.

The technical problem solved using the proposed technical solution consists in the further development of a method for determining reservoir porosity in horizontal wells using three-probe neutron logging.

The technical result obtained by the implementation of the developed technical solution consists in increasing the reliability and noise immunity of the method.

To achieve the specified technical result, it is proposed to use the developed method for determining reservoir porosity in horizontal wells using three-probe neutron logging. The developed method is characterized by the presence of rock irradiation with a fast neutron flux from a fast neutron source located in the downhole tool, separate registration of slow neutrons slowed down in the rock and the well, three detectors located along the axis of the downhole tool with the ability to collect maximum information, generate signal depths on each quantum, proportional to the absorption density of slow neutrons in each of the detectors, the formation on each quantum of depth using pho a floating device of a synthetic three-component signal, the components of which are the neutron absorption densities in each of the detectors, calibrating the obtained synthetic three-component signal to determine the dependence of the received synthetic signal on porosity and interfering factors, calibrating the obtained synthetic three-component signal by measuring it in the well against the reservoir and against a dense reservoir layer using for assessing the porosity in this well received nnyh results and determining the porosity of the collector of the previously obtained synthesis signal values at each depth slice in an inclined wellbore. To further increase the reliability of determining the porosity of the rock in some embodiments of the method, they are formed using the ratios of the absorption density of slow neutrons by the first detector to the absorption density of slow neutrons by the second detector, the absorption density of slow neutrons by the second detector and the absorption density of slow neutrons by the third detector and the absorption density of slow neutrons by the third detector to the absorption density of slow neutrons by the first detector of the second synthetic a three-component signal, the second synthetic three-component signal is processed similarly to the processing of the first synthetic three-component signal and the processed second synthetic three-component signal is used to determine the porosity of the reservoir. Also, in some embodiments of the developed method, to further increase the reliability of determining the porosity of the rock, a third synthetic three-component signal is generated using the ratios of the slow neutron absorption density by the first detector to the slow neutron absorption density by the second detector and the slow neutron absorption density by the second detector to the slow neutron absorption density by the third detector, process the third synthetic three-component signal is similar processing the first synthetic ternary signal and processed using third synthetic ternary signal for determining the porosity of the collector. Preferably, the obtained synthetic three-component signal is calibrated by measurements in standard neutron-neutron log calibrators, on standard reservoir models, or by Monte Carlo calculations. The calibration of a synthetic three-component signal is usually carried out according to the values measured against the reservoir and against the dense reservoir, using the ratio of the difference between the values of the synthetic three-component signal measured at an arbitrary point in the well and measured against the reservoir to the difference between the values of the synthetic three-component signal measured against non-reservoir and measured against the reservoir.

The method can be implemented with any three-probe neutron logging tool, for example, with an ANKZ device developed and commercially sold by PetroAlliance, shown in Fig. 1. The instrument contains a neutron source (not shown), such as Am-Be, three neutron detectors (shown), the configuration of which is optimized for measurements in horizontal wells. The device contains the necessary electronics of a known type and autonomous memory for recording all signals. An essential element of the device is the task of the value of the quantum of time before starting work (for example, 1 sec, 10 sec, etc.).

The signal processing and porosity assessment technology includes the following elements: 1) reading information from the memory after removing the device to the surface, 2) converting time-depth by known means using drill pipe motion sensors. Since the speed of movement of drill pipes can be different, different quanta (intervals) of depth will correspond to the same time quantum. 3) The readings (counting speed) of the detectors also lead by known means to a single recording point of the device (which coincides with the position of the 2nd detector). 4) Synthetic three-component signal (STS) is formed as follows. For each depth quantum, a triad (three) of readings of detectors N1, N2, N3 is formed, which corresponds to a point in three-dimensional (3D) Cartesian space. For example, the reading of the 1st detector N1 forms the X-coordinate, the reading of the second detector N2 - the Y coordinate, and the reading of the third detector N3 forms the Z-coordinate. Moreover, all indications previously lead to a single recording point of the device, which coincides with the center of the 2nd detector. The performed calculations and measurements show that the interpretation of such a signal has a higher noise immunity. Additional noise immunity is achieved by the formation of STS probe STS relations (N1 / N2, N2 / N3, N3 / N1). Here, the ratios of indications reduced to a single point in the record also form the X-, Y- , Z-coordinates of the Cartesian space. Such a signal does not depend on the power of the source and, as shown by calculations and measurements, weakly depends on the salinity of the solution and formation fluid. The general form of 3D palette is shown in Fig.2. It is calibrated by measurements on porosity models or Monte Carlo calculations, which are known to be analogous to experiments. In this case, the points are assigned the values of porosity and borehole diameter. Figure 3 shows an example of logging using the STS signal in well 107477 (horizontal) of the Samotlor field. The squares indicate productive sandstones with porosity of 22-24%.

Figure 4 presents the palette for the interpretation of the two-component signal STS (N1 / N2, N2 / N3) in accordance with one embodiment of the proposed method. This palette was obtained by measurements on the Ramenskoye standard models of porosity and agreed with Monte Carlo calculations. The coordination was performed for a well with a diameter of 196 mm, and for the practical treatment of the STS, the calculated dependence for a diameter of 120 mm was used. This is also an additional advantage of the proposed method, since there are no models for such a diameter.

Figure 5 presents the interpretation of 2D real borehole measurements in wells. 10747 (horizontal) Samotlor field. To do this, the palette in figure 4 is combined with logging (pointwise) data. Porosity in the range of 20-25% corresponds to collectors, and a higher water content corresponds to clays (non-collectors) containing a large amount of bound water.

When implementing the developed method, the reliability and noise immunity of the reservoir porosity method in horizontal wells are increased.

Claims (5)

1. A method for determining reservoir porosity in horizontal wells using three-probe neutron logging, characterized by the presence of rock irradiation with a fast neutron flux from a fast neutron source located in the downhole tool, separate registration of slow neutrons slowed down in the rock and the well, by three detectors located along the axis of the downhole tool , the formation on each quantum of the depth of signals proportional to the absorption density of slow neutrons in each of the detectors, formation on each depth quantum using a three-component synthetic signal forming device, the components of which are the neutron absorption densities in each of the detectors, calibrating the obtained three-component synthetic signal to determine the dependence of the received synthetic signal on porosity and interfering factors, calibrating the obtained three-component synthetic signal by measurements in the well it against the reservoir and against the dense reservoir, with and use of for evaluating the porosity in this well and the results obtained by determination of the porosity of the collector synthetic previously obtained signal values at each depth slice in an inclined wellbore. 2. The method according to claim 1, characterized in that to further increase the reliability of determining the porosity of the rock is formed using the ratio of the absorption density of slow neutrons by the first detector to the absorption density of slow neutrons by the second detector, the absorption density of slow neutrons by the second detector and the absorption density of slow neutrons by the third detector and the absorption density of slow neutrons by the third detector to the absorption density of slow neutrons by the first detector, the second synthetic ternary signal minutes, treated with a second synthetic ternary signal similarly processed first synthetic ternary signal and processed using a second synthetic signal to determine the three-collector porosity. 3. The method according to claim 1, characterized in that to further increase the reliability of determining the porosity of the rock is formed using the ratio of the absorption density of slow neutrons by the first detector to the absorption density of slow neutrons by the second detector and the absorption density of slow neutrons by the second detector to the absorption density of slow neutrons by the third detector , the third synthetic three-component signal, process the third synthetic three-component signal similarly to the processing of the first synt Cesky ternary signal and processed using third synthetic ternary signal for determining the porosity of the collector. 4. The method according to claim 1, characterized in that the calibration of the obtained synthetic three-component signal is carried out by measuring in standard neutron-neutron log calibrators, on standard reservoir models or using Monte Carlo calculations. 5. The method according to claim 1, characterized in that the calibration of the synthetic three-component signal is carried out according to the values measured against the reservoir and against a dense reservoir, using the ratio of the difference in the values of the synthetic three-component signal measured at an arbitrary point in the well and measured against the formation -collector to the difference in the values of the synthetic three-component signal measured against the non-reservoir and measured against the reservoir.

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