A method, system, device and storage medium for determining formation density

Abstract

The present invention discloses a method, system, device and storage medium for determining formation density. The geometric factor of the density logging-while-drilling instrument is obtained by means of Monte Carlo simulation; the long and short source distance count rates of different sectors are measured by rotating the instrument; then the gap between the density logging-while-drilling instrument and the formation to be detected is obtained; the long and short source distance count rates of different sectors are converted into long and short source distance densities through a calibration equation, and relationship models between the long and short source distance densities and the density of the formation to be detected, the borehole gap and the density of the interborehole medium are respectively established based on the instrument geometric factor; the relationship models are inverted by using the obtained long and short source distance densities of different sectors and the borehole gap by means of the least squares method to determine the density of the formation to be detected, and the influence of the borehole environment on the density logging-while-drilling can be eliminated without analyzing the composition of the interborehole medium, so that it can be used to accurately determine the density of the formation in density logging-while-drilling and lay a foundation for formation evaluation.

Description

Technical Field

[0001] The present invention belongs to the technical field of well logging in oil and gas exploration, and relates to a method, system, device and storage medium for determining formation density. Background Art

[0002] Horizontal wells have a larger contact area with the reservoir and are one of the main means for the development of unconventional oil and gas fields at present. The application scale of horizontal wells is increasing continuously, and the accompanying logging-while-drilling technology is also gradually developing. However, during the drilling process of horizontal wells, due to the influence of factors such as gravity, the wellbore is prone to be irregular, there is an easy gap between the logging tool and the wellbore wall, and cuttings are likely to accumulate at the lower part of the wellbore. The detection depth of density logging-while-drilling is relatively shallow and is greatly affected by the wellbore environment. Formation density is a very important geological parameter in petroleum geology and reservoir evaluation. Based on formation density, lithology identification, porosity calculation and other geological evaluations can be carried out. Therefore, eliminating the influence of the wellbore on density logging-while-drilling is crucial for obtaining formation density, and accurately measuring the density of the formation is of extremely important significance for oil and gas development and exploration.

[0003] Formation density is an important parameter for calculating formation porosity, and density logging is the dominant logging method in the porosity lithology logging series combination. Density logging measures formation density by using gamma photon counting of near and far detectors. Gamma photons will undergo Compton scattering, pair production and photoelectric effect with the formation. Since the Compton scattering cross section is only related to formation density and is not affected by atomic number like the pair production cross section and photoelectric cross section, by setting the energy of the gamma source and the energy of the gamma photons received by the detector, the influence of pair production and photoelectric effect is eliminated, and the formation density is measured by using the good correlation between the Compton scattering cross section and formation density, so as to calculate formation porosity.

[0004] However, the detection range of density logging is relatively shallow and is easily affected by the wellbore environment. Generally, a caliper arm is used to press the density logging tool tightly against the wellbore wall to eliminate the influence of the wellbore environment. However, logging-while-drilling is carried out in real time during the continuous drilling of the drill bit. Due to the influence of factors such as gravity during the drilling process, the wellbore is prone to be irregular, it is difficult for the density logging tool to be tightly attached to the wellbore wall, there is an easy gap, and cuttings are likely to accumulate at the lower part of the wellbore, resulting in the presence of not only mud but also cuttings between the density logging tool and the wellbore wall. Since the density of the medium between the wells cannot be directly determined, correction methods such as wellbore gap correction charts cannot be used to eliminate the influence of the wellbore environment on density logging-while-drilling. Due to the influence of the wellbore environment, the formation density measured by the current technical means is not very accurate, which in turn affects formation evaluation and restricts oil and gas development and exploration to a certain extent. Summary of the Invention

[0005] In order to overcome the above-mentioned disadvantages of the prior art, the object of the present invention is to provide a method, system, device and storage medium for determining formation density, aiming to solve the defective technical problem that the borehole environment affects the density logging while drilling, resulting in inaccurate formation density obtained by the density logging while drilling.

[0006] To achieve the above object, the present invention adopts the following technical solutions:

[0007] A method for determining formation density proposed by the present invention includes:

[0008] Obtain the spatial geometric factor of the density logging while drilling instrument;

[0009] Use a 137Cs gamma source to emit gamma photons to the formation to be detected, and obtain the long and short source distance count rates of different sectors;

[0010] Obtain the borehole clearance between the density logging while drilling instrument and the formation to be detected;

[0011] Convert the long and short source distance count rates of different sectors into long and short source distance densities, and respectively establish relationship models between the long and short source distance densities and the density of the formation to be detected, the borehole clearance and the density of the interborehole medium based on the spatial geometric factor;

[0012] Use the long and short source distance densities and the borehole clearance to invert the relationship model to determine the density of the formation to be detected.

[0013] Preferably, the Monte Carlo method is used to obtain the spatial geometric factor of the density logging while drilling instrument, and the specific steps are as follows:

[0014] Using the Monte Carlo method, establish a calculation model according to the parameters of the density logging while drilling instrument. By dividing the area detected by the logging instrument into several small grid elements, the gamma photon flux in the area detected by the logging instrument is obtained; obtain the spatial importance distribution by setting a weight window for the calculation model, and use the spatial gamma photon flux and the spatial importance distribution to obtain the spatial geometric factor, as shown in Formula 1:

[0015]

[0016] Among them, ω is the spatial geometric factor; σ is the spatial importance; is the spatial gamma photon flux.

[0017] Preferably, the steps of measuring the long and short source distance count rates of different sectors are as follows:

[0018] Use a 137Cs gamma source to emit 0.662 MeV gamma photons to the formation to be detected;

[0019] Using two gamma detectors with different source distances, measure the gamma photon count rates of different sectors with energies in the range of 0.15 MeV - 0.6 MeV by rotating the density while drilling logging tool.

[0020] Obtain the borehole clearance between the density while drilling logging tool and the formation to be detected by using ultrasonic caliper logging.

[0021] Preferably, the steps of converting the long and short source distance count rates of different sectors into long and short source distance densities are as follows:

[0022] Convert the long and short source distance count rates of different sectors into long and short source distance densities through a calibration equation. The calculation methods of the long source distance density and the short source distance density are shown in formulas (2) and (3):

[0023] ρ l =-0.5233·ln(N l ) + 5.9841 (2)

[0024] ρ s =-2.0819·ln(N s ) + 21.2416 (3)

[0025] Where ρ l is the long source distance density, ρ s is the short source distance density, N l represents the long source distance count rate; N s represents the short source distance count rate;

[0026] The steps of establishing the relationship model between the long and short source distance densities and the density of the formation to be detected, the borehole clearance, and the density of the inter-borehole medium are as follows:

[0027] By dividing the area detected by the logging tool into two parts: the borehole clearance and the formation, establish the relationship model between the long and short source distance densities and the density of the formation to be detected, the borehole clearance, and the density of the inter-borehole medium based on the spatial geometric factor of the density while drilling logging tool, as shown in formulas (4) and (5):

[0028] ρ l =ρ CalI ·ω CalI +ρ formation ·(1 - ω CalI ) (4)

[0029] ρ s =ρ CalI ·ω CalI +ρ formation ·(1 - ω CalI ) (5)

[0030] Where ρ formation is the density of the formation to be detected, ω CalIis the geometric factor of the borehole clearance; ρ CalI is expressed as the borehole clearance density; the borehole clearance is obtained by an ultrasonic caliper logging tool, and the geometric factor ω of the borehole clearance CalI is obtained through the borehole clearance and the spatial geometric factor ω; the density ρ of the formation to be detected formation The initial value is the compensated density value ρ calculated using the long-spacing density ρ l and the short-spacing density ρ s b .

[0031] Preferably, the steps of the compensated density algorithm are specifically as follows:

[0032] Using the data of 5mm, 10mm, 15mm and 20mm light and heavy mud cakes collected from the standard well, the calculated values of the long and short-spacing apparent densities at each mud cake point are obtained by means of the long and short-spacing apparent density calculation formulas;

[0033] Taking the true density of the standard well minus the long-spacing apparent density Δρ = (ρ f -ρ l ) as the ordinate, and taking the long-spacing apparent density minus the short-spacing apparent density (ρ l -ρ s ) as the abscissa, fitting the mud cake compensation value, and thus calculating the compensated density ρ b =ρ l +Δρ.

[0034] Preferably, the steps for obtaining the density of the inter-well medium are as follows:

[0035] If ρ l >ρ s , then the initial value of the inter-well medium density is taken as the mud density;

[0036] If ρ l <ρ s , then the initial value of the inter-well medium density is taken as the cuttings bed density.

[0037] Preferably, the density of the formation to be detected is determined by adjusting the formation density, borehole clearance and inter-well medium density through error iteration, and performing inversion on the relationship model by the least squares method. The specific steps are as follows:

[0038] S1. The established target equation is as shown in formula (6):

[0039]

[0040] Among them, error is the error, ρ li估 is the estimated value of the long-spacing density of the i-th group using the relationship model between the long-spacing density and the density of the formation to be detected, borehole clearance and inter-well medium density, ρ li实 is the measured value of the long-spacing density of the i-th group, ρ si估 ​is the density value of the i-th group of short-spacing density estimated by using the relationship model between the short-spacing density and the density of the formation to be detected, the borehole clearance, and the density of the medium between wells, ρ si实 is the measured short-spacing density value of the i-th group;

[0041] S2. According to the target equation value, adjust the formation density and the borehole clearance density to minimize the target equation value:

[0042] S2-1. Substitute the formation density and the density of the medium between wells into the target equation formula (6) to calculate the target equation value;

[0043] S2-2. Calculate the Jacobian matrix according to formulas (2) and (3). The calculation method of the Jacobian matrix is shown in formula (7):

[0044]

[0045] where J i is the Jacobian value of the i-th group of data. By combining n groups of Jacobian values, an n×2 Jacobian matrix can be obtained;

[0046] S2-3. Calculate the Hessian matrix according to the Jacobian matrix. The calculation method of the Hessian matrix is shown in formula (8):

[0047] H = J′*J (8)

[0048] where J′ is the transpose of the Jacobian matrix J, and H is the Hessian matrix;

[0049] S2-4. Add a damping coefficient to the Hessian matrix, as shown in formula (9) specifically:

[0050] H la = H+(la*A) (9)

[0051] where la is the damping coefficient, A is an n×2 identity matrix, and H la is the Hessian matrix with the damping coefficient;

[0052] S2-5. Calculate the adjustment step size according to the Hessian matrix with the damping coefficient, the Jacobian matrix, and the target equation value, as shown in formula (10) specifically:

[0053] dp = R*(J′*d) (10)

[0054] where dp is the step size, R is the inverse matrix of the Hessian matrix with the damping coefficient; after adding the step size to the original formation density and the density of the medium between wells, the new formation density and the density of the medium between wells can be obtained;

[0055] S2-6. Compare the new formation density and the density of the medium between wells with the constraint range:

[0056] If the new formation density and the density of the medium between wells exceed the constraint range, adjust the damping coefficient la and substitute it into formula (9) for recalculation;

[0057] If the new formation density and the density of the medium between wells are within the constraint range, substitute the new formation density and the density of the medium between wells into the objective equation (6), and compare the value of the new objective equation with the value of the original objective equation:

[0058] If the value of the new objective equation is less than the value of the original objective equation, then the new formation density and the density of the medium between wells are used as the optimal values to replace the original formation density and the density of the medium between wells, substitute them into S2-1 for recalculation, and at the same time reduce the damping coefficient la;

[0059] If the value of the new objective equation is greater than the value of the original objective equation, then the original formation density and the density of the medium between wells are used as the optimal values, and at the same time expand the damping coefficient la and substitute it into S2-1 for recalculation;

[0060] When the value of the new objective equation is less than the preset value of the objective equation or the number of iterations of the formation density and the density of the wellbore gap reaches the preset value, the formation density of the optimal value at this time is the inversely deduced formation density;

[0061] Among them, the constraint range is the range of the actual formation density and the density of the medium between wells.

[0062] Preferably, tungsten-nickel-iron shielding bodies are arranged around the gamma source bin and around the detector to shield the gamma photons that directly enter the detector without passing through the formation to be detected.

[0063] The present invention also proposes a system for a method of determining formation density, including:

[0064] A spatial geometric factor acquisition module, which is used to acquire the spatial geometric factor of the density logging-while-drilling instrument;

[0065] A long and short source distance count rate acquisition module, which is used to emit gamma photons to the formation to be detected by using a 137Cs gamma source and acquire the long and short source distance count rates of different sectors;

[0066] A wellbore gap acquisition module, which is used to acquire the wellbore gap between the density logging-while-drilling instrument and the formation to be detected;

[0067] A relationship model establishment module, which is used to convert the long and short source distance count rates of different sectors into long and short source distance densities, and respectively establish relationship models between the long and short source distance densities and the density of the formation to be detected, the wellbore gap, and the density of the medium between wells based on the spatial geometric factor;

[0068] An undetermined formation density determination module, which is used to invert by using the relationship model between the long and short source-spacing densities and the borehole clearance to determine the undetermined formation density.

[0069] A terminal device includes a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, the steps of the method for determining the formation density are implemented.

[0070] A computer-readable storage medium stores a computer program. When the computer program is executed by a processor, the steps of the method for determining the formation density are implemented.

[0071] Compared with the prior art, the present invention has the following beneficial effects:

[0072] A method for determining the formation density proposed by the present invention is based on geometric factors to establish relationship models between the long and short source-spacing densities and the density of the undetermined formation, the borehole clearance, and the density of the inter-borehole medium respectively, and uses the inversion method to determine the undetermined formation density. The method for determining the formation density proposed by the present invention can eliminate the influence of the borehole environment on the density logging while drilling without analyzing the composition of the inter-borehole medium, thereby providing theoretical support and technical support for obtaining a more accurate formation density in the density logging while drilling.

[0073] Furthermore, a 137Cs gamma source is used to make the energy of gamma photons not exceed 0.662 MeV to eliminate the influence of the pair production effect on the measurement result. By detecting the gamma photon count rate with energies between 0.15 MeV and 0.6 MeV, the influence of the photoelectric effect is eliminated. The borehole clearance is measured by an ultrasonic caliper logging tool, providing important parameters for eliminating the influence of the borehole clearance on the measurement.

[0074] Furthermore, the instrument and equipment used in this method are all conventional instrument and equipment in the art, which are convenient for operation, implementation, and testing.

[0075] Furthermore, tungsten-nickel-iron shielding bodies are arranged around the gamma source bin and around the detector, which can shield gamma photons that directly enter the detector without passing through the undetermined formation.

[0076] A system for the method for determining the formation density proposed by the present invention divides the system into a logging curve acquisition module, a cement density acquisition module, a minimum acoustic amplitude acquisition module, and a corrected BI curve acquisition module. The modular idea makes each module independent of each other, facilitating unified management of each module. Description of the Drawings

[0077] Figure 1 It is a schematic diagram of the device for determining the formation density provided by the embodiment of the present invention;

[0078] Figure 2 Schematic flow diagram of the method for determining formation density provided by the embodiment of the present invention;

[0079] Figure 3 System diagram of the formation density determination provided by the embodiment of the present invention;

[0080] Figure 4 Monte Carlo calculation model of the density logging tool provided by the embodiment of the present invention;

[0081] Figure 5 Spatial geometric factor of the short source distance detector of the density logging tool provided by the embodiment of the present invention;

[0082] Figure 6 Spatial geometric factor of the long source distance detector of the density logging tool provided by the embodiment of the present invention;

[0083] Figure 7 Comparison of the method for measuring formation density provided by the embodiment of the present invention with the traditional compensated density in the vertical well section formation;

[0084] Figure 8 Comparison of the method for measuring formation density provided by the embodiment of the present invention with the traditional compensated density in the horizontal well section formation.

[0085] Wherein: 100 - formation to be detected; 101 - wellbore; 102 - drill collar; 103 - mud channel; 104 - shield; 105 - source bin; 106 - window for short source distance detector; 107 - window for long source distance detector; 108 - gamma source emission window; 109 - short source distance detector; 110 - long source distance detector; 111 - ultrasonic caliper logging tool. Detailed implementation manners

[0086] In order to enable those skilled in the art to better understand the solution of the present invention, the technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are only a part of the embodiments of the present invention, rather than all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those of ordinary skill in the art without creative efforts shall fall within the protection scope of the present invention.

[0087] It should be noted that the terms "first", "second", etc. in the description, claims and above-mentioned drawings of the present invention are used to distinguish similar objects, and do not necessarily describe a specific order or sequence. It should be understood that the data used in this way can be interchanged under appropriate circumstances, so that the embodiments of the present invention described herein can be implemented in an order other than those illustrated or described herein. In addition, the terms "comprising" and "having" and any variations thereof are intended to cover non-exclusive inclusion. For example, a process, method, system, product or device comprising a series of steps or units does not necessarily have to be limited to those steps or units clearly listed, but may include other steps or units not clearly listed or inherent to these processes, methods, products or devices.

[0088] For the device used to determine the formation density in this embodiment, the structural schematic diagram can be referred to Figure 1 , and the detector position is illustrated with reference to the schematic diagram of the density logging-while-drilling instrument. The present invention provides a method for determining the formation density, as Figure 2 shown, including the following steps:

[0089] S1. Based on the instrument model parameters and calibration, obtain the spatial geometric factor of the density logging-while-drilling instrument;

[0090] S2. Use a 137Cs gamma source to emit gamma photons of 0.662 MeV to the formation to be detected, and use two detectors with different source distances to measure the long and short source distance count rates of different sectors by rotating the instrument;

[0091] S3. Use the ultrasonic caliper logging method to obtain the wellbore gap between the density logging-while-drilling instrument and the formation to be detected;

[0092] S4. Convert the long and short source distance count rates of different sectors into long and short source distance densities through the calibration equation, and respectively establish relationship models between the long and short source distance densities and the density, wellbore gap and inter-well medium density of the formation to be detected;

[0093] S5. Use the obtained long and short source distance densities and wellbore gaps of different sectors, and use the least squares method to invert the relationship model to determine the density of the formation to be detected.

[0094] A system for the method of determining the formation density proposed by the present invention, as Figure 3 shown, includes:

[0095] A spatial geometric factor acquisition module, which is used to acquire the spatial geometric factor of the density logging-while-drilling instrument;

[0096] Long and short source distance count rate acquisition module, which is used to emit gamma photons to the formation to be detected by using a 137Cs gamma source, and acquire the long and short source distance count rates of different sectors;

[0097] Wellbore clearance acquisition module, which is used to acquire the wellbore clearance between the density logging-while-drilling instrument and the formation to be detected;

[0098] Relationship model establishment module, which is used to convert the long and short source distance count rates of different sectors into long and short source distance densities, and respectively establish the relationship models between the long and short source distance densities and the density of the formation to be detected, the wellbore clearance and the density of the inter-well medium based on the spatial geometric factor;

[0099] Formation density to be detected determination module, which is used to inversely calculate the relationship model by using the long and short source distance densities and the wellbore clearance to determine the density of the formation to be detected.

[0100] The present invention provides a method for determining formation density, and the specific steps are as follows:

[0101] In step S1, the spatial geometric factor of the density logging-while-drilling instrument is less affected by the spatial density and is a parameter only related to the structural parameters of the instrument itself. Therefore, the theoretical spatial geometric factor can be obtained by using the Monte Carlo method, and the specific steps are as follows:

[0102] Using the Monte Carlo simulation method, a calculation model is established based on the parameters of the density logging-while-drilling instrument, as Figure 4 shown. By dividing the area detected by the logging instrument into several small grid elements, the gamma photon flux in the area detected by the logging instrument can be obtained, and the spatial importance distribution can be obtained by setting a weight window for the calculation model. The importance of any grid element in the area detected by the logging instrument, that is, the probability that the photon passing through this grid element is detected by the detector. If the weight of this grid element is non-zero, the importance of this grid element is the reciprocal of the weight. The spatial geometric factor can be obtained by using the spatial gamma photon flux and the spatial importance distribution, as shown in formula (1).

[0103]

[0104] Among them, ω is the spatial geometric factor; σ is the spatial importance; is the spatial gamma photon flux. When the grid element is small enough, the grid element can be regarded as a point in space, so as to obtain the spatial geometric factor of this density logging-while-drilling instrument. The spatial geometric factor is as Figure 5 and Figure 6 shown.

[0105] In step S2, a 137Cs gamma source is used to emit gamma photons with an energy of 0.662 MeV to the formation to be detected. Two gamma detectors with different source distances are used to measure the gamma photon count rates with energies in the range of 0.15 MeV - 0.6 MeV in different sectors by rotating the instrument. Specifically:

[0106] Density logging is a logging method that utilizes the Compton reaction of gamma photons with matter. A 137Cs gamma source is used to ensure that the energy of gamma photons does not exceed 0.662 MeV, eliminating the influence of the electron pair effect on the measurement results. By detecting the gamma photon count rates with energies in the range of 0.15 MeV - 0.6 MeV, the influence of the photoelectric effect is eliminated. An ultrasonic caliper logging tool is used to measure the borehole clearance, providing important parameters for eliminating the influence of the borehole clearance on the measurement. A sector is to equally divide the space into 8 or 16 parts by 360°, and each part is a sector. In step S3, the borehole clearance between the density logging-while-drilling tool and the formation to be detected is obtained by using ultrasonic caliper logging. Specifically:

[0107] The borehole clearance is one of the important factors affecting the density logging response. The influence of the borehole clearance includes the density of the medium between wells and the size of the borehole clearance. An ultrasonic caliper logging tool is used to measure the size of the borehole clearance, providing important parameters for eliminating the influence of the borehole clearance on the measurement.

[0108] In step S4, the long and short source distance count rates in different sectors are converted into long and short source distance densities through a calibration equation, and relationship models between the long and short source distance densities and the density of the formation to be detected, the borehole clearance, and the density of the medium between wells are respectively established. Specifically:

[0109] Using the data of three standard wells to respectively fit the linear calculation formulas of the apparent density of the long source distance and the short source distance ρ l and ρ s , the long and short source distance density formulas for this instrument are shown in formulas (2) and (3) respectively. The long and short source distance count rates in different sectors are converted into long and short source distance densities through a calibration equation. The calculation methods of the long source distance density and the short source distance density are shown in formulas (2) and (3):

[0110] ρ l =-0.5233·ln(N l )+5.9841 (2)

[0111] ρ s =-2.0819·ln(N s )+21.2416 (3)

[0112] Among them, ρ l is the long source distance density, ρ s is the short source distance density, N l represents the long source distance count rate; Ns Expressed as the short source distance count rate.

[0113] The borehole clearance is the main influencing factor for density logging in horizontal wells. The spatial geometric factor describes the contribution of each part of the space to the logging response. By dividing the space into two parts: the borehole clearance and the formation, based on the instrument geometric factor, the relationship models between the long and short source distance densities and the density of the formation to be detected, the borehole clearance, and the density of the medium between wells are established as shown in Formulas (4) and (5):

[0114] ρ l = ρ CalI · ω CalI + ρ formation · (1 - ω CalI ) (4)

[0115] ρ s = ρ CalI · ω CalI + ρ formation · (1 - ω CalI ) (5)

[0116] Where ρ l is the long source distance density, ρ s is the short source distance density, ρ formation is the formation density, ω CalI is the geometric factor of the borehole clearance. ρ CalI is expressed as the borehole clearance density; the borehole clearance is obtained by an ultrasonic caliper logging tool, and the geometric factor ω CalI of the borehole clearance is obtained from the borehole clearance and the spatial geometric factor ω; the initial value of the formation density ρ formation is the compensated density value ρ l calculated using the long source distance density ρ s and the short source distance density ρ b .

[0117] For different sectors, for an isotropic formation, the formation density measured in different sectors is the same; for an anisotropic formation, since the instrument uploads data every 80 ms and it takes 800 ms for the instrument to rotate one circle, and 3 - 4 sector counts are uploaded each time and the detection depth of density logging is relatively shallow, it can still be considered that the formation density measured in different sectors is the same and the size of the borehole clearance is consistent.

[0118] In step S5, using the long and short source distance densities and the borehole clearance of different sectors obtained, the relationship model is inverted by the least squares method to determine the density of the formation to be detected. Specifically, it includes the following steps S51 to S52:

[0119] S51. Set the initial values of the relationship model formulas (4) and (5);

[0120] Specifically, the long and short source distance density values are obtained from the gamma photon count rates of the long and short source distance detectors with energies in the range of 0.15 MeV - 0.6 MeV according to formulas (2) and (3); the wellbore clearance size is substituted into the spatial geometric factor ω to obtain the geometric factor ω of the wellbore clearance. CalI Since the detection range of the short source distance density is shallower and can better reflect the density of the medium between wells, if the long source distance density is greater than the short source distance density, the initial value of the density of the medium between wells is taken as the mud density; if the long source distance density is less than the short source distance density, the initial value of the density of the medium between wells is taken as the cuttings bed density; the initial value of the formation density is the compensated density value calculated using the long and short source distance densities.

[0121] The specific steps of the compensated density algorithm for this instrument are as follows:

[0122] Using the data of 5 mm, 10 mm, 15 mm, and 20 mm light and heavy mud cakes collected from a standard well, the calculated values of the long and short source distance apparent densities at each mud cake point are obtained by means of the long and short source distance apparent density calculation formulas.

[0123] Taking the true density of the standard well minus the long source distance apparent density (ρ f -ρ l ) as the ordinate and the long source distance apparent density minus the short source distance apparent density (ρ l -ρ s ) as the abscissa, fit the calculation formula Δρ of the mud cake compensation value.

[0124] Thus, calculate the compensated density ρ b =ρ l +Δρ.

[0125] Using the relationship model between the long and short source distance densities and the density of the formation to be detected, wellbore clearance, and density of the medium between wells, estimate the long and short source distance densities; compare the estimated long and short source distance densities with the measured long and short source distance densities, and adjust the formation density and density of the wellbore clearance medium by means of error iteration to invert the formation density.

[0126] Establish an objective equation, and the specific relationship is shown in formula (6):

[0127]

[0128] Among them, error is the error, ρ li估 is the estimated value of the long source distance density of the i-th group using the relationship model between the long source distance density and the density of the formation to be detected, wellbore clearance, and density of the medium between wells, ρ li实 is the measured value of the long source distance density of the i-th group, ρ si估 is the estimated value of the short source distance density of the i-th group using the relationship model between the short source distance density and the density of the formation to be detected, wellbore clearance, and density of the medium between wells, ρ si实 is the measured value of the short source distance density of the i-th group.

[0129] S52. Adjust the formation density and wellbore clearance density according to the target equation value to minimize the target equation value. The specific steps are as follows:

[0130] S52-1. Substitute the formation density and the density of the medium between wells into the target equation (6) to calculate the target equation value;

[0131] S52-2. Calculate the Jacobian matrix according to formulas (2) and (3), specifically as shown in formula (7):

[0132]

[0133] where J i is the Jacobian value of the i-th group of data. By combining n groups of Jacobian values, an n×2 Jacobian matrix can be obtained.

[0134] S5-3. Calculate the Hessian matrix according to the Jacobian matrix, specifically as shown in formula (8):

[0135] H = J′ * J (8)

[0136] where J′ is the transpose of the Jacobian matrix J, and H is the Hessian matrix.

[0137] S5-4. Add a damping coefficient to the Hessian matrix, specifically as shown in formula (9):

[0138] H la = H + (la * A) (9)

[0139] where la is the damping coefficient, A is an n×2 identity matrix, and H la is the Hessian matrix with the damping coefficient.

[0140] S5-5. Calculate the adjustment step size according to the Hessian matrix with the damping coefficient, the Jacobian matrix, and the target equation value, specifically as shown in formula (10):

[0141] dp = R * (J′ * d) (10)

[0142] where dp is the step size, and R is the inverse matrix of the Hessian matrix with the damping coefficient. After adding the step size to the original formation density and the density of the medium between wells, new formation density and density of the medium between wells can be obtained.

[0143] S5-6. Compare the new formation density and the density of the medium between wells with the constraint range:

[0144] If the new formation density and the density of the medium between wells exceed the boundary conditions of the constraint range, adjust the damping coefficient la and substitute it into formula (9) to recalculate.

[0145] If the new formation density and the density of the medium between wells are within the constraint range, substitute the new formation density and the density of the medium between wells into the objective equation (6), and compare the value of the new objective equation with the value of the original objective equation:

[0146] If the value of the new objective equation is less than the value of the original objective equation, the new formation density and the density of the medium between wells are used as the optimal values to replace the original formation density and the density of the medium between wells, and are substituted into S2-1 for recalculation. At the same time, the damping coefficient la is reduced;

[0147] If the value of the new objective equation is greater than the value of the original objective equation, the original formation density and the density of the medium between wells are used as the optimal values. At the same time, the damping coefficient la is increased and substituted into S2-1 for recalculation.

[0148] When the value of the new objective equation is less than the preset value of the objective equation or the number of iterations of the formation density and the density of the wellbore annulus reaches the preset value, the formation density of the optimal value at this time is the inversely deduced formation density; wherein, the constraint range is the range of the actual formation density and the density of the medium between wells. The above method eliminates the influence of the wellbore environment and obtains a more accurate formation density value.

[0149] The medium between wells may specifically be mud, cuttings or a mixture of mud and cuttings. The formation to be detected may specifically be a complex formation containing carbonate rock, sandstone, dolomite or mudstone, etc. The compensated density value of the formation to be detected can be calculated by using the long and short source-spacing densities. The long and short source-spacing density values of the formation to be detected are obtained by counting with long and short source-spacing detectors. The wellbore annulus can be determined by ultrasonic caliper logging, which is a conventional technical means in the art and will not be specifically described. According to the size of the wellbore annulus, the contribution ω of the annulus to the measurement result is determined based on the geometric factor CalI 。

[0150] The wellbore is the wellbore channel between the underground and the surface formed when the drill bit drills from the surface to the total depth of the well, and is generally columnar. In the specific implementation process of the present invention, the gamma source and the two detectors are both axially arranged in the wellbore, and the two detectors have different distances from the gamma source. For example, the near detector can be arranged between the pulsed neutron source and the far detector.

[0151] The above detectors and gamma sources can both use conventional instruments in the art. For example, the gamma source can specifically be the commonly used cesium-137 ( 137 Cs) gamma source; the two detectors used can both be sodium iodide (NaI) detectors.

[0152] Further, the above method may further include: a step of shielding gamma photons that do not enter the formation to be detected. In the specific implementation process of the present invention, tungsten-nickel-iron shielding bodies are arranged around the gamma source bin and around the detector to shield gamma photons that directly enter the detector without passing through the formation to be detected. By means of windowing, a more accurate gamma photon counting rate, etc. can be obtained.

[0153] Figures 7 to 8 All are the comparison results between the formation density measured by the method provided in this embodiment and the traditional compensated density, where Figures 7 to 8 the formations to be detected are the vertical well section formation and the horizontal well section formation respectively. There are generally no gaps in the density logging of the vertical well section, and the traditional compensated density can accurately measure the formation density. There are easily gaps in the logging of the horizontal well section. Generally, the logging curve is analyzed by comparing with the curves of adjacent wells. According to Figures 7 to 8 it can be seen that when using the method provided in this embodiment, the application effect in the diameter section is the same as that of the traditional density logging calculation method. In the horizontal well section, compared with the traditional density logging calculation method, the method provided in this embodiment is closer to the density values of adjacent wells. Therefore, the method of the present invention can obtain very accurate formation density values, thereby laying a foundation for formation evaluation.

[0154] The present invention provides a method for determining formation density. Based on the instrument geometric factors, relationship models between the long and short source distance densities and the density of the formation to be detected, the borehole gap, and the density of the interwell medium are respectively established; using the long and short source distance densities and the borehole gap of different sectors obtained, the relationship models are inverted by the least squares method to determine the density of the formation to be detected. Eliminate the influence of the borehole environment, so that the formation density can be accurately determined.

[0155] The terminal device provided by an embodiment of the present invention includes: a processor, a memory, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, the steps in the above-mentioned various method embodiments are implemented. Or, when the processor executes the computer program, the functions of each module / unit in the above-mentioned various device embodiments are implemented.

[0156] The computer program can be divided into one or more modules / units, and the one or more modules / units are stored in the memory and executed by the processor to complete the present invention.

[0157] The terminal device may be a computing device such as a desktop computer, a notebook, a palm computer, and a cloud server. The terminal device may include, but is not limited to, a processor and a memory.

[0158] The processor may be a Central Processing Unit (CPU), or may also be other general-purpose processors, Digital Signal Processors (DSPs), Application Specific Integrated Circuits (ASICs), Field-Programmable Gate Arrays (FPGAs), or other programmable logic devices, discrete gate or transistor logic devices, discrete hardware components, etc.

[0159] The memory can be used to store the computer program and / or modules. By running or executing the computer program and / or modules stored in the memory, and by invoking the data stored in the memory, the processor implements various functions of the terminal device.

[0160] If the modules / units integrated in the terminal device are implemented in the form of software functional units and sold or used as independent products, they can be stored in a computer-readable storage medium. Based on this understanding, to implement all or part of the processes in the above method embodiments of the present invention, it can also be completed by instructing relevant hardware through a computer program. The computer program can be stored in a computer-readable storage medium. When the computer program is executed by the processor, it can implement the steps of the above method embodiments. Among them, the computer program includes computer program code, and the computer program code can be in the form of source code, object code, executable file, or some intermediate form, etc. The computer-readable medium can include: any entity or device that can carry the computer program code, recording medium, USB flash drive, mobile hard disk, magnetic disk, optical disk, computer memory, Read-Only Memory (ROM), Random Access Memory (RAM), electrical carrier signal, telecommunication signal, and software distribution medium, etc. It should be noted that the content included in the computer-readable medium can be appropriately increased or decreased according to the requirements of legislation and patent practice in the jurisdiction. For example, in some jurisdictions, according to legislation and patent practice, the computer-readable medium does not include electrical carrier signals and telecommunication signals.

[0161] The above content is only to illustrate the technical idea of the present invention, and cannot be used to limit the protection scope of the present invention. Any modification made on the basis of the technical solution according to the technical idea proposed by the present invention falls within the protection scope of the claims of the present invention.

Claims

1. A method for determining formation density, characterized in that: include: Obtain the spatial geometric factors of the density logging while drilling tool; A 137Cs gamma source is used to emit gamma photons to the formation to be tested, and the long and short source distance count rates in different sectors are obtained. Obtain the borehole clearance between the density logging while drilling instrument and the formation to be tested; The long and short source distance count rates in different sectors are converted into long and short source distance density, and the relationship models between the long and short source distance density and the density of the formation to be detected, the wellbore clearance and the interwell medium density are established based on the spatial geometric factors. The density of the formation to be tested is determined by inverting the relationship model using the density of the long and short source distances and the wellbore clearance; The Monte Carlo method is used to obtain the spatial geometric factors of the density logging while drilling tool. The specific steps are as follows: Using the Monte Carlo method, a calculation model is established based on the parameters of the while-drilling density logging instrument. The area detected by the logging instrument is divided into several small grid cells to obtain the regional gamma photon flux detected by the logging instrument. A weight window is set for the calculation model to obtain the spatial importance distribution. The spatial gamma photon flux and spatial importance distribution are used to obtain the spatial geometric factor, as shown in Formula 1: （1） Among them, is the spatial geometric factor; is the spatial importance; is the spatial gamma photon flux; The steps to convert the count rate of different sectors with long and short source distances into long and short source distance densities are as follows: The long and short source distance count rates of different sectors are converted into long and short source distance densities through the calibration equation. The calculation methods of long source distance density and short source distance density are shown in formula (2) and formula (3): （2） （3） in, is the long-distance density, is the short-distance density, Expressed as the long-source-distance count rate; Expressed as the short-source-distance count rate; The steps for establishing a relationship model between the long and short source spacing density and the density of the formation to be detected, the wellbore spacing, and the density of the interwell medium are as follows: By dividing the area detected by the logging instrument into two parts: the borehole gap and the formation, a relationship model between the long and short source distance density and the density of the formation to be detected, the borehole gap and the interwell medium density is established based on the spatial geometric factor of the while drilling density logging instrument, as shown in Formula (4) and Formula (5): （4） （5） Among them, is the density of the formation to be detected, is the geometric factor of the borehole clearance; represents the density of the borehole clearance; the borehole clearance is obtained by an ultrasonic caliper logging tool, and the geometric factor of the borehole clearance is obtained through the borehole clearance and the spatial geometric factor ; the initial value of the density of the formation to be detected is the compensated density value calculated using the long-spacing density and the short-spacing density . .

2. The method for determining formation density according to claim 1, wherein The steps to measure the long and short source distance count rates in different sectors are as follows: A 137Cs gamma source is used to emit 0.662 MeV gamma photons to the formation to be tested; Using two gamma detectors at different source distances, the gamma photon count rate in different sectors with energies between 0.15 MeV and 0.6 MeV was measured by rotating the density logging while drilling tool; Ultrasonic caliper logging is used to obtain the borehole clearance between the density logging tool while drilling and the formation to be tested.

3. The method for determining formation density according to claim 1, characterized in that, The specific steps of the compensation density algorithm are: Using the data of 5mm, 10mm, 15mm and 20mm light and heavy mud cakes obtained from standard wells, the long and short source distance apparent density calculation values of each mud cake point are obtained with the help of the long and short source distance apparent density calculation formula; Subtract the apparent density at long source distance from the true density of the standard well = ( ) as the ordinate, and subtract the apparent density at short source distance from the apparent density at long source distance ( ) as the abscissa to fit the mud cake compensation value, and calculate the compensated density from this .

4. The method for determining formation density according to claim 1, characterized in that, The steps for obtaining the interwell medium density are as follows: If , the initial value of the density of the medium between wells is taken as the mud density; If , the initial value of the density of the inter-well medium is taken as the density of the cuttings layer.

5. The method for determining formation density according to claim 1, characterized in that, The formation density, wellbore clearance, and interwell medium density are adjusted by error iteration, and the relationship model is inverted using the least squares method to determine the density of the formation to be tested. The specific steps are as follows: S1. The target equation established is shown in formula (6): （6） where error is the error, is the density value of the i-th long source distance estimated using the relationship model between the long source distance density and the density of the formation to be detected, the borehole clearance, and the density of the medium between wells, is the measured long source distance density value of the i-th group, is the density value of the i-th short source distance estimated using the relationship model between the short source distance density and the density of the formation to be detected, the borehole clearance, and the density of the medium between wells, is the measured short source distance density value of the i-th group; S2. According to the target equation value, adjust the formation density and wellbore clearance density to minimize the target equation value: S2-1. Substitute the formation density and the interwell medium density into the target equation formula (6) to calculate the target equation value; S2-2. Calculate the Jacobian matrix according to formula (2) and formula (3). The calculation method of the Jacobian matrix is shown in formula (7): （7） Among them, is the Jacobian value of the i-th group of data. By combining n groups of Jacobian values, an n×2 Jacobian matrix can be obtained; S2-3. Calculate the Hessian matrix according to the Jacobian matrix. The calculation method of the Hessian matrix is shown in formula (8): （8） Among them, is the transpose of the Jacobian matrix , is the Hessian matrix; S2-4. Add a damping coefficient to the Hessian matrix, as specifically shown in formula (9): （9） wherein, is the damping coefficient, A is an n×2 identity matrix, is the Hessian matrix with the damping coefficient; S2-5. Calculate the adjustment step size according to the Hessian matrix with the damping coefficient, the Jacobian matrix, and the target equation value, as specifically shown in formula (10): （10） Among them, is the step size, is the inverse matrix of the Hessian matrix with a damping coefficient; after adding the step size to the in-situ formation density and the inter-well medium density, the new formation density and the inter-well medium density can be obtained; S2-6. Compare the new formation density and the density of the medium between wells with the constraint range: If the new formation density and the density of the medium between wells exceed the constraint range, adjust the damping coefficient , and substitute it into formula (9) for recalculation; If the new formation density and the density of the medium between wells are within the constraint range, substitute the new formation density and the density of the medium between wells into the target equation (6), and compare the new target equation value with the original target equation value: If the new target equation value is less than the original target equation value, the new formation density and interwell medium density are used as the optimal values, replacing the original formation density and interwell medium density, and substituted into S2-1 for recalculation, while reducing the damping coefficient. ; If the new target equation value is greater than the original target equation value, the original formation density and interwell medium density are taken as the optimal values, and the damping coefficient is expanded at the same time. , substitute into S2-1 and recalculate; When the new target equation value is less than the preset value of the target equation or the iteration times of the formation density and the density of the wellbore clearance reach the preset value, the formation density of the optimal value at this time is the inversely calculated formation density; Among them, the constraint range is the range of the actual formation density and the density of the medium between wells.

6. A system for using the method for determining formation density according to any one of claims 1 to 5, characterized in that, It includes: A spatial geometric factor acquisition module, which is used to acquire the spatial geometric factors of the density logging-while-drilling instrument; A long and short source distance count rate acquisition module, which is used to emit gamma photons to the formation to be detected by using a 137Cs gamma source, and acquire the long and short source distance count rates of different sectors; A wellbore clearance acquisition module, which is used to acquire the wellbore clearance between the density logging-while-drilling instrument and the formation to be detected; A relationship model establishment module, which is used to convert the long and short source distance count rates of different sectors into long and short source distance densities, and respectively establish relationship models between the long and short source distance densities and the density of the formation to be detected, the wellbore clearance, and the density of the medium between wells based on the spatial geometric factors; A formation density to be detected determination module, which is used to inversely calculate the relationship model by using the long and short source distance densities and the wellbore clearance to determine the density of the formation to be detected.

7. A terminal device, characterized in that, It includes a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, the steps of the method for determining the formation density according to any one of claims 1 to 5 are implemented.

8. A computer-readable storage medium storing a computer program, characterized in that: When the computer program is executed by the processor, the steps of the method for determining the formation density according to any one of claims 1 to 5 are implemented.

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