A method and system for identifying fluid properties of oil-based mud drilling reservoirs

Abstract

The present invention provides a method and system for identifying fluid properties of oil-based mud drilling reservoirs. The method includes: obtaining the nuclear magnetic resonance logging T2 spectrum, the nuclear magnetic resonance T2 geometric mean value and the nuclear magnetic resonance porosity of the target reservoir; obtaining the first and second cutoff values ​​of the nuclear magnetic resonance T2 relaxation time; dividing the nuclear magnetic resonance logging T2 spectrum of the target reservoir into three intervals based on the first and second cutoff values ​​of the nuclear magnetic resonance T2 relaxation time, and respectively determining the cumulative amplitudes in the three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir; determining the fluid property identification factor of the target reservoir based on the cumulative amplitudes in the three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir and the nuclear magnetic resonance T2 geometric mean value of the target reservoir; determining the fluid properties of the target reservoir based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir. The method can accurately identify the fluid properties of the oil-based mud drilling reservoir.

Description

Technical Field

[0001] The present invention relates to the field of reservoir evaluation, and in particular to a method and system for identifying fluid properties of oil-based mud drilling reservoirs. Background Art

[0002] Fluid property identification is the key to reservoir evaluation and reserve calculation. For wells drilled with water-based mud, the oil layer, water layer and dry layer have obvious differences in resistivity, porosity and nuclear magnetic resonance logging response. Therefore, many methods for identifying reservoir fluid properties using conventional or nuclear magnetic resonance logging have been developed, including porosity-resistivity crossplot method, density-neutron porosity overlap method, water-porosity-total porosity overlap method, and differential spectrum method and shift spectrum method based on nuclear magnetic resonance logging. These methods can effectively identify the fluid properties of water-based mud drilling into the reservoir. However, in some areas, oil-based mud is required during drilling for the purpose of reservoir protection. Mud filtrate, under the action of drilling pressure, often invades the pore space of the formation, and the organic solvent used in the preparation of oil-based mud will also invade the pore space of the formation. Affected by the invasion of oil-based mud, the resistivity and nuclear magnetic resonance response differences between the water layer and the oil layer decrease, resulting in the ineffectiveness of the conventional method of identifying fluid properties using logging data and low accuracy in identifying fluid properties.

[0003] In order to improve the accuracy of fluid property identification in oil-based mud drilling reservoirs, it is necessary to study new methods for identifying fluid properties using nuclear magnetic resonance logging for oil-based mud drilling reservoirs. At present, no effective fluid property identification methods and technologies have been reported for oil-based mud drilling reservoirs. Summary of the invention

[0004] The object of the present invention is to provide a method and system capable of effectively identifying the fluid properties of oil-based mud drilling reservoirs.

[0005] In order to achieve the above object, the present invention provides a method for identifying fluid properties of oil-based mud drilling reservoirs, wherein the method comprises:

[0006] Obtain the NMR logging T2 spectrum, NMR T2 geometric mean and NMR porosity of the target reservoir;

[0007] Obtaining a first cutoff value and a second cutoff value of the nuclear magnetic resonance T2 relaxation time;

[0008] The target reservoir's nuclear magnetic resonance logging T2 spectrum is divided into three intervals based on the first and second cutoff values ​​of the nuclear magnetic resonance T2 relaxation time, and the cumulative amplitudes in the three intervals of the target reservoir's nuclear magnetic resonance logging T2 spectrum are determined respectively;

[0009] Based on the cumulative amplitude in three intervals of the target reservoir's NMR logging T2 spectrum and the NMR T2 geometric mean of the target reservoir, the fluid property identification factor of the target reservoir is determined;

[0010] The fluid properties of the target reservoir are determined based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir.

[0011] In the above identification method, preferably, the step of obtaining the target reservoir's nuclear magnetic resonance logging T2 spectrum, nuclear magnetic resonance T2 geometric mean value and nuclear magnetic resonance porosity comprises:

[0012] Acquire NMR logging data of target reservoir;

[0013] Based on the NMR logging data of the target reservoir, determine the NMR logging T2 spectrum, NMR T2 geometric mean value and NMR porosity of the target reservoir;

[0014] More preferably, the NMR T2 geometric mean of the target reservoir is determined by the following formula:

[0015]

[0016] Where, T 2gm is the geometric mean of NMR T2, ms; amp(i) is the amplitude corresponding to the i-th T2 relaxation time on the NMR logging T2 spectrum, v / v; n is the number of relaxation time points on the NMR logging T2 spectrum; T2(i) is the i-th T2 relaxation time on the NMR logging T2 spectrum, ms.

[0017] In the above identification method, preferably, the obtaining of the first cutoff value and the second cutoff value of the nuclear magnetic resonance T2 relaxation time comprises:

[0018] Obtain the NMR T2 spectrum of the oil-based mud used in the target reservoir;

[0019] Based on the nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir, the T2 relaxation time corresponding to the main peak position of the nuclear magnetic resonance T2 spectrum of the oil-based mud and the T2 relaxation time corresponding to the convergence point (i.e., the maximum T2 relaxation time of the magnetic resonance T2 spectrum of the oil-based mud) are determined as the first cutoff value and the second cutoff value of the nuclear magnetic resonance T2 relaxation time, respectively.

[0020] In a specific implementation, the first cutoff value and the second cutoff value are 145.0 ms and 587.0 ms, respectively.

[0021] In the above identification method, preferably, the cumulative amplitudes in three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir are determined by the following formulas:

[0022]

[0023]

[0024]

[0025] Where, samp1 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2min is the minimum T2 relaxation time of the NMR T2 spectrum, ms; T 2max is the maximum T2 relaxation time of the nuclear magnetic resonance T2 spectrum, ms; S1cuoff is the smaller cutoff value between the first and second cutoff values, ms; S2cutoff is the larger cutoff value between the first and second cutoff values, ms; S(T2) is a function reflecting the nuclear magnetic resonance porosity component related to the transverse relaxation time (i.e., the nuclear magnetic signal amplitude of the nuclear magnetic resonance T2 spectrum corresponding to each T2 relaxation time).

[0026] In the above identification method, preferably, the determination of the fluid property identification factor of the target reservoir based on the cumulative amplitude in three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir and the nuclear magnetic resonance T2 geometric mean of the target reservoir includes:

[0027] Based on the cumulative amplitudes in three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir, the percentages of the cumulative amplitudes of the nuclear magnetic resonance logging T2 spectrum in the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum are determined respectively;

[0028] Based on the percentage of the cumulative amplitude of the NMR logging T2 spectrum in the three intervals to the total amplitude of the NMR logging T2 spectrum and the NMR T2 geometric mean of the target reservoir, the fluid property identification factor of the target reservoir is determined;

[0029] More preferably, the percentage of the cumulative amplitude of the NMR logging T2 spectrum in the three intervals to the total amplitude of the NMR logging T2 spectrum is determined by the following formula:

[0030]

[0031]

[0032]

[0033] Wherein, rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals;

[0034] More preferably, the fluid property identification factor of the target reservoir is determined by the following formula:

[0035]

[0036] Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; T 2gm is the geometric mean value of NMR T2, ms.

[0037] In the above identification method, preferably, the fluid property identification factor of the target reservoir is determined by the following formula:

[0038]

[0039] Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2gm is the geometric mean value of NMR T2, ms.

[0040] In the above identification method, preferably, the determining the fluid properties of the target reservoir includes determining whether the target reservoir is an oil layer, a water layer, and / or a dry layer;

[0041] More preferably, the determining the fluid property of the target reservoir based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir comprises:

[0042] Obtaining fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for target reservoir fluid properties, including fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for oil layers, fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for water layers, and / or fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for dry layers;

[0043] Based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir, using the discrimination criteria, determining whether the target reservoir is an oil layer, a water layer, and / or a dry layer;

[0044] Further preferably, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard for the oil layer in the target reservoir, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard for the water layer in the reservoir, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard for the dry layer in the reservoir suitable for identifying the fluid property of the target reservoir are determined by calibrating the oil-based mud drilling reservoir test data in the area where the target reservoir is located.

[0045] In the above identification method, preferably, determining the fluid property of the target reservoir based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir comprises:

[0046] When the fluid property identification factor of the target reservoir is ≤0.008 and the nuclear magnetic resonance porosity of the target reservoir is ≤8.0, the target reservoir is determined to be a dry layer;

[0047] and / or;

[0048] When 0.008<the fluid property identification factor of the target reservoir≤0.07 and the nuclear magnetic resonance porosity of the target reservoir≤10.5, or when the fluid property identification factor of the target reservoir≤0.08 and 8.0<the nuclear magnetic resonance porosity of the target reservoir≤10.5, the target reservoir is determined to be a water layer;

[0049] and / or;

[0050] When the fluid property identification factor of the target reservoir is greater than 0.07 or the nuclear magnetic resonance porosity of the target reservoir is greater than 10.5, the target reservoir is determined to be an oil layer.

[0051] The present invention also provides a system for identifying fluid properties of oil-based mud drilling reservoirs, wherein the system comprises:

[0052] Target reservoir NMR data acquisition module: used to obtain the NMR logging T2 spectrum, NMR T2 geometric mean and NMR porosity of the target reservoir;

[0053] A demarcation value acquisition module: used to acquire the first demarcation value and the second demarcation value of the nuclear magnetic resonance T2 relaxation time;

[0054] Cumulative amplitude acquisition module: used for dividing the target reservoir's nuclear magnetic resonance logging T2 spectrum into three intervals based on the first and second cutoff values ​​of the nuclear magnetic resonance T2 relaxation time, and respectively determining the cumulative amplitudes of the target reservoir's nuclear magnetic resonance logging T2 spectrum in the three intervals;

[0055] Target reservoir fluid identification factor acquisition module: used to determine the target reservoir fluid property identification factor based on the cumulative amplitude in three intervals of the target reservoir's nuclear magnetic resonance logging T2 spectrum and the target reservoir's nuclear magnetic resonance T2 geometric mean value;

[0056] Fluid property determination module: used to determine the fluid properties of the target reservoir based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir.

[0057] In the above identification system, preferably, the target reservoir nuclear magnetic data acquisition module includes:

[0058] Well logging data acquisition submodule: used to obtain nuclear magnetic resonance logging data of the target reservoir;

[0059] NMR data determination submodule: used to determine the NMR logging T2 spectrum, NMR T2 geometric mean and NMR porosity of the target reservoir based on the NMR logging data of the target reservoir;

[0060] More preferably, the second acquisition submodule determines the NMR T2 geometric mean of the target reservoir by the following formula:

[0061]

[0062] Where, T 2gm is the geometric mean of NMR T2, ms; amp(i) is the amplitude corresponding to the i-th T2 relaxation time on the NMR logging T2 spectrum, v / v; n is the number of relaxation time points on the NMR logging T2 spectrum; T2(i) is the i-th T2 relaxation time on the NMR logging T2 spectrum, ms.

[0063] In the above recognition system, preferably, the demarcation value acquisition module includes:

[0064] Oil-based mud T2 spectrum acquisition submodule: used to obtain the nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir;

[0065] The demarcation value determination submodule is used to determine, based on the nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir, the T2 relaxation time corresponding to the main peak position and the T2 relaxation time corresponding to the convergence point of the nuclear magnetic resonance T2 spectrum of the oil-based mud (i.e., the maximum T2 relaxation time of the nuclear magnetic resonance T2 spectrum of the oil-based mud), as the first demarcation value and the second demarcation value of the nuclear magnetic resonance T2 relaxation time, respectively.

[0066] In a specific implementation, the first cutoff value and the second cutoff value are 145.0 ms and 587.0 ms, respectively.

[0067] In the above identification system, preferably, the cumulative amplitude acquisition module determines the cumulative amplitude in three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir by the following formula:

[0068]

[0069]

[0070]

[0071] Where, samp1 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2min is the minimum T2 relaxation time of the NMR T2 spectrum, ms; T 2max is the maximum T2 relaxation time of the nuclear magnetic resonance T2 spectrum, ms; S1cuoff is the smaller cutoff value between the first and second cutoff values, ms; S2cutoff is the larger cutoff value between the first and second cutoff values, ms; S(T2) is a function reflecting the nuclear magnetic resonance porosity component related to the transverse relaxation time (i.e., the nuclear magnetic signal amplitude of the nuclear magnetic resonance T2 spectrum corresponding to each T2 relaxation time).

[0072] In the above identification system, preferably, the target reservoir fluid identification factor acquisition module includes:

[0073] Cumulative amplitude ratio determination submodule: used to determine the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum in the three intervals based on the cumulative amplitude in the three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir;

[0074] The fluid identification factor determination submodule is used to determine the fluid property identification factor of the target reservoir based on the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum and the nuclear magnetic resonance T2 geometric mean of the target reservoir;

[0075] More preferably, the cumulative amplitude proportion determination submodule determines the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum by the following formula:

[0076]

[0077]

[0078]

[0079] Wherein, rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals;

[0080] More preferably, the fluid identification factor determination submodule determines the fluid property identification factor of the target reservoir by the following formula:

[0081]

[0082] Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; T 2gm is the geometric mean value of NMR T2, ms.

[0083] In the above identification system, preferably, the target reservoir fluid identification factor acquisition module determines the target reservoir fluid property identification factor by the following formula:

[0084]

[0085] Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2gm is the geometric mean value of NMR T2, ms.

[0086] In the above identification system, preferably, the determining the fluid property of the target reservoir includes determining whether the target reservoir is an oil layer, a water layer, and / or a dry layer;

[0087] Furthermore, the fluid property determination module includes:

[0088] The discrimination standard acquisition submodule is used to obtain the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the target reservoir fluid property identification, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a dry layer;

[0089] Fluid property identification submodule: used to determine whether the target reservoir is an oil layer, a water layer, and / or a dry layer based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir and using the discrimination criteria;

[0090] Further preferably, the discrimination criterion acquisition submodule determines the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard for the target reservoir as an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard for the water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard for the dry layer, which are applicable to the identification of the fluid properties of the target reservoir, by calibrating the oil-based mud drilling reservoir test data in the area where the target reservoir is located.

[0091] In the above identification system, preferably, the determination of whether the target reservoir is an oil layer, a water layer, and / or a dry layer based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir using the discrimination criteria includes:

[0092] When the fluid property identification factor of the target reservoir is ≤0.008 and the nuclear magnetic resonance porosity of the target reservoir is ≤8.0, the target reservoir is determined to be a dry layer;

[0093] and / or;

[0094] When 0.008<the fluid property identification factor of the target reservoir≤0.07 and the nuclear magnetic resonance porosity of the target reservoir≤10.5, or when the fluid property identification factor of the target reservoir≤0.08 and 8.0<the nuclear magnetic resonance porosity of the target reservoir≤10.5, the target reservoir is determined to be a water layer;

[0095] and / or;

[0096] When the fluid property identification factor of the target reservoir is greater than 0.07 or the nuclear magnetic resonance porosity of the target reservoir is greater than 10.5, the target reservoir is determined to be an oil layer.

[0097] The technical solution provided by the present invention can use nuclear magnetic resonance logging data to accurately identify the fluid properties of oil-based mud drilling into the reservoir, and provide high-precision reservoir fluid information for reservoir evaluation and reserve calculation. BRIEF DESCRIPTION OF THE DRAWINGS

[0098] Figure 1 This is the NMR T2 spectrum of the oil-based mud used in the core experiment.

[0099] Figure 2 This is the NMR T2 spectrum of an oil sample with a viscosity of 1.01 mPa.s used in the core experiment.

[0100] Figure 3 These are the NMR T2 spectra of the core fully saturated with water in the core experiment, the NMR T2 spectrum of the core after water displacement by oil-based mud, and the NMR T2 spectrum of the oil-based mud.

[0101] Figure 4 These are the NMR T2 spectra of the core fully saturated with water in the core experiment, the NMR T2 spectrum of the core saturated with oil, the NMR T2 spectrum of the core in the oil-based mud displacement state, the NMR T2 spectrum of the oil-based mud and the NMR T2 spectrum of the oil sample.

[0102] Figure 5 A flow chart of a method for identifying fluid properties of an oil-based mud drilling reservoir provided in one embodiment of the present invention.

[0103] Figure 6 A framework diagram of a system for identifying reservoir fluid properties during oil-based mud drilling provided by an embodiment of the present invention.

[0104] Figure 7 This is a cross-plot of the NMR porosity and fluid property identification factor of each test reservoir in Example 1 of the present invention.

[0105] Figure 8 This is a key data diagram for determining the reservoir fluid properties of an actual oil-based mud drilled reservoir using the method of the present invention in Example 1 of the present invention. DETAILED DESCRIPTION

[0106] In order to make the purpose, technical solution and advantages of the embodiment of the present invention clearer, the technical solution in the embodiment of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiment of the present invention. Obviously, the described embodiment is a part of the embodiment of the present invention, not all of the embodiments. Based on the embodiment of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative work belong to the protection scope of the present invention.

[0107] In order to establish a method for identifying the fluid properties of oil-based mud drilling reservoirs using nuclear magnetic resonance logging, improve the accuracy of identifying the fluid properties of oil-based mud drilling reservoirs, and meet the actual reservoir evaluation and reserve calculation needs, the inventors studied the differences in nuclear magnetic resonance responses caused by oil-based mud invading oil layers and water layers. On the basis of comprehensively considering the impact of oil-based mud invasion on the morphology of nuclear magnetic resonance T2 spectra of water layers and oil layers, sensitivity parameters reflecting the differences in nuclear magnetic resonance relaxation of reservoir fluid properties were extracted from the T2 spectrum and combined, thereby establishing the technical solution for identifying the fluid properties of oil-based mud drilling reservoirs based on nuclear magnetic resonance logging data in the present invention.

[0108] The following is a detailed explanation of the differences in NMR response caused by oil-based mud invading oil layers and water layers based on the analysis of the differences in NMR T2 spectra of cores taken from Block A when they are fully saturated with water, oil-based mud driving water, saturated with oil, oil-based mud driving oil, and laboratory-configured oil-based mud and oil samples.

[0109] Figure 1 and Figure 2 They are the nuclear magnetic resonance T2 spectra (i.e., volume relaxation T2 spectra) of the oil-based mud and oil sample prepared in the laboratory according to the properties of the oil-based mud and formation crude oil used in the drilling of Block A during the core nuclear magnetic resonance experiment. Figure 1 , Figure 2 It can be seen that the NMR T2 spectrum of the oil-based mud is mainly distributed between 51.7-587.0ms, and the T2 relaxation time corresponding to the main peak position is 145.0ms. In other words, the NMR T2 spectrum of the oil-based mud converges at 587.0ms. The T2 relaxation time of the NMR T2 spectrum of the light oil with a viscosity of 1.01mPa.s is mainly distributed between 361.2-1979.2ms, and the T2 relaxation time corresponding to the main peak position is 812.0ms, which is significantly greater than the T2 relaxation time corresponding to the convergence point of the NMR T2 spectrum of the oil-based mud.

[0110] Figure 3 The NMR T2 spectrum of the core taken from Block A after being completely saturated with water, the NMR T2 spectrum measured after being completely saturated with water and driven to the bound water state by oil-based mud, and the NMR T2 spectrum of the oil-based mud. From the morphological comparison of the three, it can be seen that after the invasion of oil-based mud, the morphology of the NMR T2 spectrum of water-bearing rock has changed significantly, showing a clear bimodal distribution. The morphology of the NMR T2 spectrum of the small pore (short relaxation time) part remains basically unchanged, but the position of the movable peak is close to the position of the NMR T2 spectrum of the oil-based mud. This shows that the NMR T2 spectrum after the invasion of oil-based mud not only reflects the surface relaxation properties of water, but also reflects two NMR relaxation properties: the surface relaxation properties of bound water in small pore space and the volume relaxation properties of oil-based mud in large pore space.

[0111] Figure 4 The NMR T2 spectrum of the same core sample after it is completely saturated with water, the NMR T2 spectrum measured after the core is completely saturated with water and 1.01 mPa.s of light oil is used to displace the core until it is saturated with oil, the NMR T2 spectrum measured after the core is completely saturated with water and 1.01 mPa.s of light oil is used to displace the core until it is saturated with oil, and then the configured oil-based mud is used to displace the oil-saturated core, the NMR T2 spectrum of the oil-based mud, and the NMR T2 spectrum of the oil sample. It can be seen that after the core is saturated with oil, the NMR T2 spectrum presents a bimodal distribution, the morphology of the NMR T2 spectrum of the small pore (short relaxation time) part is basically unchanged, but the main peak position of the NMR T2 spectrum of the large pore part is obviously shifted to the right, which is consistent with the main peak position of the NMR T2 spectrum of the light oil of 1.01 mPa.s. It shows that after the pores are filled with oil, the nuclear magnetic resonance T2 spectrum of the large pores (long relaxation time) mainly reflects the volume relaxation properties of light oil. After being affected by the displacement of oil-based mud, the nuclear magnetic resonance T2 spectrum of oil-bearing rocks shows a three-peak distribution. The shape of the first peak on the left is consistent with the shape of the nuclear magnetic resonance T2 spectrum of small pore bound water when fully saturated with water. The main peak position of the second peak is close to the position of the nuclear magnetic resonance T2 spectrum of oil-based mud, and the main peak position of the third peak is consistent with the position of the nuclear magnetic resonance T2 spectrum of light oil of 1.01mPa.s. It shows that after the oil-bearing rock is affected by the invasion of oil-based mud, it reflects three relaxation properties: the surface relaxation properties of small pore bound water, the volume relaxation properties of oil-based mud, and the volume relaxation properties of light oil.

[0112] contrast Figure 3 and Figure 4The NMR T2 spectra of the same core in the states of fully saturated water, saturated oil, oil-based mud driving water, and oil-based mud driving oil are shown. It can be seen that for rocks fully saturated with water, once affected by the invasion of oil-based mud, the NMR T2 spectrum converges to 587.0ms, and there is no T2 spectrum in the part with relaxation time greater than 587.0ms, and the part with relaxation time between 145.0-587.0ms reflects the volume relaxation of oil-based mud. However, when the pore space of the rock is saturated with light oil and affected by the invasion of oil-based mud, there is an obvious third peak reflecting the volume relaxation properties of light oil in the part with NMR T2 relaxation time greater than 587.0ms, while the volume relaxation properties of oil-based mud are still reflected in the part with 145.0-587.0ms.

[0113] based on Figure 3 and Figure 4 The difference in the morphology of the nuclear magnetic resonance T2 spectra of the cores fully saturated with water and saturated with oil after being invaded by oil-based mud can be used to extract sensitive parameters reflecting the difference in reservoir fluid properties from the nuclear magnetic resonance T2 spectra, so as to establish a technical solution for identifying the fluid properties of oil-based mud drilling reservoirs. Based on this, the present invention proposes a new method and system for identifying the fluid properties of oil-based mud drilling reservoirs.

[0114] See also Figure 5 A specific embodiment of the present invention provides a method for identifying fluid properties of oil-based mud drilling reservoirs, wherein the method comprises:

[0115] Step S1: obtaining the NMR logging T2 spectrum, NMR T2 geometric mean and NMR porosity of the target reservoir;

[0116] Step S2: obtaining a first cutoff value and a second cutoff value of the nuclear magnetic resonance T2 relaxation time;

[0117] Step S3: dividing the nuclear magnetic resonance logging T2 spectrum of the target reservoir into three intervals based on the first and second cutoff values ​​of the nuclear magnetic resonance T2 relaxation time, and determining the cumulative amplitudes in the three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir respectively;

[0118] Step S4: determining the fluid property identification factor of the target reservoir based on the cumulative amplitude in three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir and the nuclear magnetic resonance T2 geometric mean of the target reservoir;

[0119] Step S5: determining the fluid property of the target reservoir based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir.

[0120] In this technical solution, the target reservoir is an oil-based mud drilling reservoir.

[0121] In this technical solution, the three intervals of the T2 spectrum of the nuclear magnetic resonance logging of the target reservoir are an interval in which the T2 relaxation time is less than or equal to the smaller of the first and second boundary values, an interval in which the T2 relaxation time is between the first and second boundary values, and an interval in which the T2 relaxation time is greater than or equal to the larger of the first and second boundary values.

[0122] Further, in step S1, obtaining the NMR logging T2 spectrum, NMR T2 geometric mean value and NMR porosity of the target reservoir includes:

[0123] Step S11: Acquire nuclear magnetic resonance logging data of the target reservoir;

[0124] Among them, the nuclear magnetic resonance logging data of the target reservoir can be measured by using a nuclear magnetic resonance logging instrument;

[0125] Step S12: determining the NMR logging T2 spectrum, NMR T2 geometric mean and NMR porosity of the target reservoir based on the NMR logging data of the target reservoir;

[0126] Furthermore, the NMR T2 geometric mean of the target reservoir is determined by the following formula:

[0127]

[0128] Where, T 2gm is the geometric mean of NMR T2, ms; amp(i) is the amplitude corresponding to the i-th T2 relaxation time on the NMR logging T2 spectrum, v / v; n is the number of relaxation time points on the NMR logging T2 spectrum; T2(i) is the i-th T2 relaxation time on the NMR logging T2 spectrum, ms.

[0129] Further, in step S2, obtaining the first and second cutoff values ​​of the nuclear magnetic resonance T2 relaxation time includes:

[0130] Step S21: obtaining a nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir;

[0131] Step S22: Based on the nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir, determine the T2 relaxation time corresponding to the main peak position of the nuclear magnetic resonance T2 spectrum of the oil-based mud and the T2 relaxation time corresponding to the convergence point (i.e., the maximum T2 relaxation time of the nuclear magnetic resonance T2 spectrum of the oil-based mud), which are used as the first demarcation value and the second demarcation value of the nuclear magnetic resonance T2 relaxation time, respectively.

[0132] In a specific implementation, the first demarcation value and the second demarcation value are 145.0 ms and 587.0 ms, respectively.

[0133] Further, in step S3, the cumulative amplitudes in the three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir are determined by the following formulas:

[0134]

[0135]

[0136]

[0137] Where, samp1 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2min is the minimum T2 relaxation time of the NMR T2 spectrum, ms; T 2max is the maximum T2 relaxation time of the nuclear magnetic resonance T2 spectrum, ms; S1cuoff is the smaller cutoff value between the first and second cutoff values, ms; S2cutoff is the larger cutoff value between the first and second cutoff values, ms; S(T2) is a function reflecting the nuclear magnetic resonance porosity component related to the transverse relaxation time (i.e., the nuclear magnetic signal amplitude of the nuclear magnetic resonance T2 spectrum corresponding to each T2 relaxation time).

[0138] Further, in step S4, based on the cumulative amplitudes in three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir and the nuclear magnetic resonance T2 geometric mean of the target reservoir, the fluid property identification factor of the target reservoir is determined to include:

[0139] Step S41: based on the cumulative amplitudes in three intervals of the NMR logging T2 spectrum of the target reservoir, respectively determining the percentages of the cumulative amplitudes of the NMR logging T2 spectrum in the three intervals to the total amplitude of the NMR logging T2 spectrum;

[0140] Step S42: determining the fluid property identification factor of the target reservoir based on the percentage of the cumulative amplitude of the NMR logging T2 spectrum in the three intervals to the total amplitude of the NMR logging T2 spectrum and the NMR T2 geometric mean of the target reservoir;

[0141] Furthermore, the percentage of the cumulative amplitude of the NMR logging T2 spectrum in the three intervals to the total amplitude of the NMR logging T2 spectrum is determined by the following formula:

[0142]

[0143]

[0144]

[0145] Wherein, rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals;

[0146] Furthermore, in step S42, the fluid property identification factor of the target reservoir is determined by the following formula:

[0147]

[0148] Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; T 2gm is the geometric mean value of NMR T2, ms.

[0149] Furthermore, the fluid property identification factor of the target reservoir is determined by the following formula:

[0150]

[0151] Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2gm is the geometric mean value of NMR T2, ms.

[0152] Further, in step S5, the determining of the fluid properties of the target reservoir includes determining whether the target reservoir is an oil layer, a water layer, and / or a dry layer;

[0153] Furthermore, in step S5, determining the fluid properties of the target reservoir based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir includes:

[0154] Step S51: Obtaining fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for target reservoir fluid properties, including fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for oil layers, fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for water layers, and / or fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for dry layers;

[0155] Step S52: Based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir, using the discrimination criteria, determining whether the target reservoir is an oil layer, a water layer, and / or a dry layer;

[0156] Further, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a dry layer applicable to the identification of the fluid property of the target reservoir are determined by calibrating the oil-based mud drilling reservoir test data in the area where the target reservoir is located; specifically, in step S51, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a dry layer applicable to the identification of the fluid property of the target reservoir are obtained, including:

[0157] Obtain oil-based mud drilling reservoir test data in the target reservoir area;

[0158] Based on the oil test data, determine the fluid properties of each test reservoir, that is, determine whether each test reservoir is an oil layer, a water layer or a dry layer;

[0159] Determine the fluid property identification factor and the nuclear magnetic resonance porosity of each test reservoir in accordance with the methods provided in steps S1 to S4;

[0160] Based on the fluid properties, fluid property identification factors and nuclear magnetic resonance porosity of each test oil reservoir, a cross plot of nuclear magnetic resonance porosity and fluid property identification factor of each test oil reservoir is determined;

[0161] Based on the cross plot of nuclear magnetic resonance porosity and fluid property identification factor of each test oil reservoir, determine the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is a dry layer as the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is a dry layer applicable to fluid property identification of the target reservoir;

[0162] In a specific embodiment, the fluid property identification factor and nuclear magnetic resonance porosity discrimination criteria for the dry layer of the target reservoir fluid property identification are: fluid property identification factor ≤ 0.008 and nuclear magnetic resonance porosity ≤ 8.0;

[0163] In a specific embodiment, the fluid property identification factor and nuclear magnetic resonance porosity discrimination criteria for the target reservoir fluid property identification reservoir being a water layer are: 0.008<fluid property identification factor≤0.07 and nuclear magnetic resonance porosity≤10.5, or, fluid property identification factor≤0.08 and 8.0<nuclear magnetic resonance porosity≤10.5;

[0164] In a specific embodiment, the fluid property identification factor and nuclear magnetic resonance porosity discrimination criteria for the target reservoir fluid property identification being an oil layer are: fluid property identification factor>0.07 or nuclear magnetic resonance porosity>10.5.

[0165] In a specific embodiment, in step S5, determining the fluid property of the target reservoir based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir includes:

[0166] When the fluid property identification factor of the target reservoir is ≤0.008 and the nuclear magnetic resonance porosity of the target reservoir is ≤8.0, the target reservoir is determined to be a dry layer;

[0167] and / or;

[0168] When 0.008<the fluid property identification factor of the target reservoir≤0.07 and the nuclear magnetic resonance porosity of the target reservoir≤10.5, or when the fluid property identification factor of the target reservoir≤0.08 and 8.0<the nuclear magnetic resonance porosity of the target reservoir≤10.5, the target reservoir is determined to be a water layer;

[0169] and / or;

[0170] When the fluid property identification factor of the target reservoir is greater than 0.07 or the nuclear magnetic resonance porosity of the target reservoir is greater than 10.5, the target reservoir is determined to be an oil layer.

[0171] The embodiment of the present invention further provides a system for identifying the properties of fluid in an oil-based mud drilling reservoir, and the system is used to implement the above-mentioned embodiment of the method for identifying the properties of fluid in an oil-based mud drilling reservoir.

[0172] Figure 6 is a structural block diagram of a system for identifying fluid properties of oil-based mud drilling reservoirs according to an embodiment of the present invention. Figure 6 As shown, the system includes:

[0173] Target reservoir nuclear magnetic resonance data acquisition module 21: used to obtain the nuclear magnetic resonance logging T2 spectrum, nuclear magnetic resonance T2 geometric mean and nuclear magnetic resonance porosity of the target reservoir;

[0174] The demarcation value acquisition module 22 is used to acquire the first demarcation value and the second demarcation value of the nuclear magnetic resonance T2 relaxation time;

[0175] Cumulative amplitude acquisition module 23: used to divide the target reservoir's nuclear magnetic resonance logging T2 spectrum into three intervals based on the first and second cutoff values ​​of the nuclear magnetic resonance T2 relaxation time, and respectively determine the cumulative amplitudes in the three intervals of the target reservoir's nuclear magnetic resonance logging T2 spectrum;

[0176] The target reservoir fluid identification factor acquisition module 24 is used to determine the target reservoir fluid property identification factor based on the cumulative amplitude in three intervals of the target reservoir nuclear magnetic resonance logging T2 spectrum and the target reservoir nuclear magnetic resonance T2 geometric mean value;

[0177] The fluid property determination module 25 is used to determine the fluid property of the target reservoir based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir.

[0178] In this technical solution, the target reservoir is an oil-based mud drilling reservoir.

[0179] In this technical solution, the three intervals of the T2 spectrum of the nuclear magnetic resonance logging of the target reservoir are an interval in which the T2 relaxation time is less than or equal to the smaller of the first and second boundary values, an interval in which the T2 relaxation time is between the first and second boundary values, and an interval in which the T2 relaxation time is greater than or equal to the larger of the first and second boundary values.

[0180] Further, the target reservoir nuclear magnetic resonance data acquisition module 21 includes:

[0181] Well logging data acquisition submodule 211: used to acquire nuclear magnetic resonance well logging data of the target reservoir;

[0182] The NMR data determination submodule 212 is used to determine the NMR logging T2 spectrum, NMR T2 geometric mean value and NMR porosity of the target reservoir based on the NMR logging data of the target reservoir;

[0183] Furthermore, the second acquisition submodule 212 determines the NMR T2 geometric mean value of the target reservoir by the following formula:

[0184]

[0185] Where, T 2gm is the geometric mean of NMR T2, ms; amp(i) is the amplitude corresponding to the i-th T2 relaxation time on the NMR logging T2 spectrum, v / v; n is the number of relaxation time points on the NMR logging T2 spectrum; T2(i) is the i-th T2 relaxation time on the NMR logging T2 spectrum, ms.

[0186] Further, the demarcation value acquisition module 22 includes:

[0187] Oil-based mud T2 spectrum acquisition submodule 221: used to acquire the nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir;

[0188] The demarcation value determination submodule 222 is used to determine, based on the nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir, the T2 relaxation time corresponding to the main peak position of the nuclear magnetic resonance T2 spectrum of the oil-based mud and the T2 relaxation time corresponding to the convergence point (i.e., the maximum T2 relaxation time of the nuclear magnetic resonance T2 spectrum of the oil-based mud), as the first demarcation value and the second demarcation value of the nuclear magnetic resonance T2 relaxation time, respectively.

[0189] In a specific implementation, the first demarcation value and the second demarcation value are 145.0 ms and 587.0 ms, respectively.

[0190] Further, the cumulative amplitude acquisition module 23 determines the cumulative amplitude in three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir by the following formula:

[0191]

[0192]

[0193]

[0194] Where, samp1 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2min is the minimum T2 relaxation time of the NMR T2 spectrum, ms; T 2maxis the maximum T2 relaxation time of the nuclear magnetic resonance T2 spectrum, ms; S1cuoff is the smaller cutoff value between the first and second cutoff values, ms; S2cutoff is the larger cutoff value between the first and second cutoff values, ms; S(T2) is a function reflecting the nuclear magnetic resonance porosity component related to the transverse relaxation time (i.e., the nuclear magnetic signal amplitude of the nuclear magnetic resonance T2 spectrum corresponding to each T2 relaxation time).

[0195] Further, the target reservoir fluid identification factor acquisition module 24 includes:

[0196] The cumulative amplitude ratio determination submodule 241 is used to determine the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum in the three intervals based on the cumulative amplitude in the three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir;

[0197] The fluid identification factor determination submodule 242 is used to determine the fluid property identification factor of the target reservoir based on the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum and the nuclear magnetic resonance T2 geometric mean of the target reservoir;

[0198] Furthermore, the cumulative amplitude ratio determination submodule 241 determines the percentage of the cumulative amplitude of the NMR logging T2 spectrum in the three intervals to the total amplitude of the NMR logging T2 spectrum by the following formula:

[0199]

[0200]

[0201]

[0202] Wherein, rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals;

[0203] Furthermore, the fluid identification factor determination submodule 242 determines the fluid property identification factor of the target reservoir by the following formula:

[0204]

[0205] Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; T 2gm is the geometric mean value of NMR T2, ms.

[0206] Furthermore, the target reservoir fluid identification factor acquisition module 24 can also determine the target reservoir fluid property identification factor by the following formula:

[0207]

[0208] Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2gm is the geometric mean value of NMR T2, ms.

[0209] Further, the determining of the fluid properties of the target reservoir includes determining whether the target reservoir is an oil layer, a water layer, and / or a dry layer;

[0210] Furthermore, the fluid property determination module 25 includes:

[0211] The discrimination standard acquisition submodule 251 is used to obtain the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the target reservoir fluid property identification, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a dry layer;

[0212] Fluid property identification submodule 252: used to determine whether the target reservoir is an oil layer, a water layer, and / or a dry layer based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir and using the discrimination criteria;

[0213] Furthermore, the discrimination standard acquisition submodule 251 determines the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the target reservoir as an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the dry layer, which are applicable to the target reservoir fluid property identification, by calibrating the oil-based mud drilling reservoir test data in the target reservoir area;

[0214] Specifically, obtaining the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the target reservoir fluid property identification, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a dry layer includes:

[0215] Obtain oil-based mud drilling reservoir test data in the target reservoir area;

[0216] Based on the oil test data, determine the fluid properties of each test reservoir, that is, determine whether each test reservoir is an oil layer, a water layer or a dry layer;

[0217] Determine the fluid property identification factor and the nuclear magnetic resonance porosity of each test reservoir in accordance with the methods provided in steps S1 to S4;

[0218] Based on the fluid properties, fluid property identification factors and nuclear magnetic resonance porosity of each test oil reservoir, a cross plot of nuclear magnetic resonance porosity and fluid property identification factor of each test oil reservoir is determined;

[0219] Based on the cross plot of nuclear magnetic resonance porosity and fluid property identification factor of each test oil reservoir, determine the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is a dry layer as the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard when the reservoir is a dry layer applicable to fluid property identification of the target reservoir;

[0220] In a specific embodiment, the fluid property identification factor and nuclear magnetic resonance porosity discrimination criteria for the dry layer of the target reservoir fluid property identification are: fluid property identification factor ≤ 0.008 and nuclear magnetic resonance porosity ≤ 8.0;

[0221] In a specific embodiment, the fluid property identification factor and nuclear magnetic resonance porosity discrimination criteria for the target reservoir fluid property identification reservoir being a water layer are: 0.008<fluid property identification factor≤0.07 and nuclear magnetic resonance porosity≤10.5, or, fluid property identification factor≤0.08 and 8.0<nuclear magnetic resonance porosity≤10.5;

[0222] In a specific embodiment, the fluid property identification factor and nuclear magnetic resonance porosity discrimination criteria for the target reservoir fluid property identification being an oil layer are: fluid property identification factor>0.07 or nuclear magnetic resonance porosity>10.5.

[0223] In a specific embodiment, based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir, using the discrimination criteria, determining whether the target reservoir is an oil layer, a water layer, and / or a dry layer includes:

[0224] When the fluid property identification factor of the target reservoir is ≤0.008 and the nuclear magnetic resonance porosity of the target reservoir is ≤8.0, the target reservoir is determined to be a dry layer;

[0225] and / or;

[0226] When 0.008<the fluid property identification factor of the target reservoir≤0.07 and the nuclear magnetic resonance porosity of the target reservoir≤10.5, or when the fluid property identification factor of the target reservoir≤0.08 and 8.0<the nuclear magnetic resonance porosity of the target reservoir≤10.5, the target reservoir is determined to be a water layer;

[0227] and / or;

[0228] When the fluid property identification factor of the target reservoir is greater than 0.07 or the nuclear magnetic resonance porosity of the target reservoir is greater than 10.5, the target reservoir is determined to be an oil layer.

[0229] Example 1

[0230] A method for identifying fluid properties of oil-based mud drilling reservoirs is used to identify fluid properties of low-permeability sandstone reservoirs drilled with oil-based mud in well B of block A.

[0231] The method is carried out according to the following steps:

[0232] 1) Obtain the NMR logging data of the target reservoir (the low permeability sandstone reservoir drilled by oil-based mud in Well B); Based on the NMR logging data of the target reservoir, determine the NMR logging T2 spectrum and NMR T2 geometric mean T of the target reservoir 2gm and NMR porosity Among them, the NMR T2 geometric mean value T 2gm Determined by the following formula:

[0233]

[0234] Where amp(i) is the amplitude corresponding to the i-th T2 relaxation time on the NMR logging T2 spectrum, v / v; n is the number of relaxation time points on the NMR logging T2 spectrum; T2(i) is the i-th T2 relaxation time on the NMR logging T2 spectrum, ms.

[0235] 2) obtaining a nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir; based on the nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir, determining a T2 relaxation time corresponding to a main peak position and a T2 relaxation time corresponding to a convergence point of the nuclear magnetic resonance T2 spectrum of the oil-based mud, as a first cutoff value S1cuoff and a second cutoff value S2cutoff of the nuclear magnetic resonance T2 relaxation time, respectively;

[0236] The nuclear magnetic resonance T2 spectrum of oil-based mud is mainly distributed between 51.7-587.0ms. The T2 relaxation time corresponding to the main peak position is 145.0ms. The nuclear magnetic resonance T2 spectrum of oil-based mud converges to 587.0ms. Therefore, the first boundary value S1cuoff of the nuclear magnetic resonance T2 relaxation time is 145.0ms, and the second boundary value S2cutoff of the nuclear magnetic resonance T2 relaxation time is 587.0ms.

[0237] 3) Based on the first cutoff value S1cuoff and the second cutoff value S2cutoff of the nuclear magnetic resonance T2 relaxation time, the nuclear magnetic resonance logging T2 spectrum of the target reservoir is divided into three intervals, and the cumulative amplitudes samp1, samp2, and samp3 in the three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir are determined respectively by the following formulas:

[0238]

[0239]

[0240]

[0241] Where, samp1 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the NMR logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2min is the minimum T2 relaxation time of the NMR T2 spectrum, ms; T 2maxis the maximum T2 relaxation time of the NMR T2 spectrum, ms; S(T2) is a function that reflects the NMR porosity component related to the transverse relaxation time (i.e. the NMR signal amplitude corresponding to each T2 relaxation time of the NMR T2 spectrum).

[0242] 4) Based on the cumulative amplitudes samp1, samp2, and samp3 in the three intervals of the NMR logging T2 spectrum of the target reservoir, the percentages rs1, rs2, and rs3 of the cumulative amplitudes of the NMR logging T2 spectrum in the three intervals to the total amplitude of the NMR logging T2 spectrum are determined respectively by the following formulas:

[0243]

[0244]

[0245]

[0246] Wherein, rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals, which accounts for the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals, which accounts for the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals, which accounts for the total amplitude of the nuclear magnetic resonance logging T2 spectrum.

[0247] Based on the percentage of the cumulative amplitude of the NMR logging T2 spectrum in the three intervals rs1, rs2, rs3 to the total amplitude of the NMR logging T2 spectrum and the NMR T2 geometric mean T of the target reservoir 2gm , the fluid property identification factor ifluid of the target reservoir is determined by the following formula:

[0248]

[0249] Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; T 2gm is the geometric mean value of NMR T2, ms.

[0250] 5) Calibrate using the oil test data of the oil-based mud drilling reservoir that has completed the oil test in the same block as the target reservoir of this embodiment to determine the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard for the oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard for the water layer, and the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard for the dry layer that are applicable to the target reservoir fluid property identification; specifically:

[0251] Obtain oil test data of 13 layers of reservoirs drilled with oil-based mud in 4 wells of Block A; based on the oil test data, determine the fluid properties of these test reservoirs (i.e., the 13 layers of reservoirs drilled with oil-based mud in the 4 wells) to determine whether each test reservoir is an oil layer, a water layer, or a dry layer; determine the fluid property identification factor and the nuclear magnetic resonance porosity of each test reservoir respectively according to the methods provided in steps 1) to 4); based on the fluid properties, fluid property identification factor, and nuclear magnetic resonance porosity of each test reservoir, determine the cross plot of the nuclear magnetic resonance porosity and the fluid property identification factor of each test reservoir (e.g., Figure 7 as shown); based on the cross plot of the nuclear magnetic resonance porosity and fluid property identification factor of each test oil reservoir, determine the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a water layer, and the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a dry layer as the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being an oil layer, the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a water layer, and the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a dry layer for fluid property identification of the target reservoir;

[0252] The fluid property identification factor and nuclear magnetic resonance porosity discrimination criteria for the target reservoir fluid property identification when the reservoir is a dry layer are determined as follows: fluid property identification factor ≤ 0.008 and nuclear magnetic resonance porosity ≤ 8.0; the fluid property identification factor and nuclear magnetic resonance porosity discrimination criteria for the target reservoir fluid property identification when the reservoir is a water layer are determined as follows: 0.008 < fluid property identification factor ≤ 0.07 and nuclear magnetic resonance porosity ≤ 10.5, or, fluid property identification factor ≤ 0.08 and 8.0 < nuclear magnetic resonance porosity ≤ 10.5; the fluid property identification factor and nuclear magnetic resonance porosity discrimination criteria for the target reservoir fluid property identification when the reservoir is an oil layer are determined as follows: fluid property identification factor > 0.07 or nuclear magnetic resonance porosity > 10.5.

[0253] 6) Based on the fluid property identification factor ifluid of the target reservoir and the NMR porosity of the target reservoir The discrimination criteria are used to determine whether the target reservoir is an oil layer, a water layer, or a dry layer; specifically:

[0254] When ifluid ≤ 0.008 and then, it is determined that the target reservoir is a dry layer;

[0255] When 0.008 < ifluid ≤ 0.07 and Or, when ifluid ≤ 0.08 and then, it is determined that the target reservoir is a water layer;

[0256] When ifluid > 0.07 or then, it is determined that the target reservoir is an oil layer.

[0257] The key data are as Figure 8 shown. Figure 8 In the nuclear magnetic resonance logging T2 spectrum, the T2 relaxation time indicated by the black dashed line is equal to 145.0 ms, and the T2 relaxation time indicated by the black solid line is equal to 587.0 ms. In the well section of 5831.5 - 5839.5 m, the three-peak distribution of the nuclear magnetic resonance logging T2 spectrum is obvious, and there is an obvious T2 spectrum in the part where the relaxation time is greater than 587.0 ms, and the relaxation response in the part of 145.0 - 587.0 ms is also relatively obvious. The nuclear magnetic resonance porosity of the reservoir in the range of 5831.5 - 5839.5 m is greater than 10.5%, and the fluid property identification factor ifluid is greater than 0.07. It is judged that the reservoir in the range of 5831.5 - 5839.5 m is an oil layer. In the well section of 5839.5 - 5930.0 m, the main peak position of the movable peak in the nuclear magnetic resonance logging T2 spectrum is mainly distributed between 145.0 - 587.0 ms, and there is almost no nuclear magnetic resonance T2 spectrum in the part where the relaxation time is greater than 587.0 ms. Although the nuclear magnetic resonance porosity is also relatively high, the calculated value of the fluid property identification factor ifluid is small. Specifically, the reservoir in the range of 5839.5 - 5930.0 m satisfies 0.008 < ifluid ≤ 0.07 and Or, ifluid ≤ 0.08 and It is judged that the reservoir in the range of 5839.5 - 5930.0 m is a water layer.

[0258] According to the oil testing results of this well, the daily oil production in the well section of 5832.0 - 5838.0 m is 188.36 t, and the daily gas production is 9.765×10 4 m 3 , and the daily water production in the well section of 5885.0 - 5966.0 m is 561.88 m 3 . It indicates that the reservoir in the well section of 5832.0 - 5838.0 m is a pure oil and gas layer, and the reservoir in the well section of 5885.0 - 5966.0 m is a pure water layer. The oil testing results are consistent with the results identified by the method proposed in the present invention, which proves the accuracy of the method shown in the present invention.

[0259] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principle of the present invention should be included in the protection scope of the present invention.

Claims

1. A method for identifying fluid properties of oil-based mud drilling reservoirs, wherein: The method includes: Obtain the NMR logging T2 spectrum, NMR T2 geometric mean and NMR porosity of the target reservoir; Obtaining a first cutoff value and a second cutoff value of the nuclear magnetic resonance T2 relaxation time; The target reservoir's nuclear magnetic resonance logging T2 spectrum is divided into three intervals based on the first and second cutoff values ​​of the nuclear magnetic resonance T2 relaxation time, and the cumulative amplitudes in the three intervals of the target reservoir's nuclear magnetic resonance logging T2 spectrum are determined respectively; Based on the cumulative amplitude in three intervals of the target reservoir's nuclear magnetic resonance logging T2 spectrum and the target reservoir's nuclear magnetic resonance T2 geometric mean, the target reservoir's fluid property identification factor is determined; the target reservoir's fluid property identification factor is determined by one of the following two formulas: Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2gm is the NMR T2 geometric mean, ms; rs1 is the percentage of the cumulative amplitude of the NMR logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the NMR logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the NMR logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the NMR logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the NMR logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the NMR logging T2 spectrum; the fluid properties of the target reservoir are determined based on the fluid property identification factor of the target reservoir and the NMR porosity of the target reservoir, including: Obtaining fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for target reservoir fluid properties when the reservoir is an oil layer, and / or fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for the reservoir is a water layer, and / or fluid property identification factors and nuclear magnetic resonance porosity discrimination criteria for the reservoir is a dry layer; Based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir, using the discrimination criteria, determining whether the target reservoir is an oil layer, and / or a water layer, and / or a dry layer; Among them, the fluid property identification factors and nuclear magnetic resonance porosity discrimination standards for oil layers and / or the fluid property identification factors and nuclear magnetic resonance porosity discrimination standards for water layers and / or the fluid property identification factors and nuclear magnetic resonance porosity discrimination standards for dry layers applicable to target reservoir fluid property identification are determined by calibrating the oil-based mud drilling reservoir test data in the area where the target reservoir is located.

2. The identification method according to claim 1, wherein: The obtaining of the first demarcation value and the second demarcation value of the nuclear magnetic resonance T2 relaxation time comprises: Obtain the NMR T2 spectrum of the oil-based mud used in the target reservoir; Based on the nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir, the T2 relaxation time corresponding to the main peak position and the T2 relaxation time corresponding to the convergence point of the nuclear magnetic resonance T2 spectrum of the oil-based mud are determined as the first cutoff value and the second cutoff value of the nuclear magnetic resonance T2 relaxation time, respectively.

3. The identification method according to claim 2, wherein: The first demarcation value and the second demarcation value are 145.0 ms and 587.0 ms respectively.

4. The identification method according to claim 1, wherein: The determination of the fluid property identification factor of the target reservoir based on the cumulative amplitude in three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir and the nuclear magnetic resonance T2 geometric mean value of the target reservoir includes: Based on the cumulative amplitudes in three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir, the percentages of the cumulative amplitudes of the nuclear magnetic resonance logging T2 spectrum in the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum are determined respectively; The fluid property identification factor of the target reservoir is determined based on the percentage of the cumulative amplitude of the NMR logging T2 spectrum in the three intervals to the total amplitude of the NMR logging T2 spectrum and the NMR T2 geometric mean of the target reservoir.

5. The identification method according to claim 4, wherein: The percentage of the cumulative amplitude of the NMR logging T2 spectrum in the three intervals to the total amplitude of the NMR logging T2 spectrum is determined by the following formula: Wherein, rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals.

6. The identification method according to claim 1, wherein: The fluid properties of the target reservoir are determined based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir, including: When the fluid property identification factor of the target reservoir is ≤0.008 and the nuclear magnetic resonance porosity of the target reservoir is ≤8.0, the target reservoir is determined to be a dry layer; and / or; When 0.008<the fluid property identification factor of the target reservoir≤0.07 and the nuclear magnetic resonance porosity of the target reservoir≤10.5, or when the fluid property identification factor of the target reservoir≤0.08 and 8.0<the nuclear magnetic resonance porosity of the target reservoir≤10.5, the target reservoir is determined to be a water layer; and / or; When the fluid property identification factor of the target reservoir is greater than 0.07 or the nuclear magnetic resonance porosity of the target reservoir is greater than 10.5, the target reservoir is determined to be an oil layer.

7. A system for identifying the fluid properties of oil-based mud drilling reservoirs, wherein: The system includes: Target reservoir NMR data acquisition module: used to obtain the NMR logging T2 spectrum, NMR T2 geometric mean and NMR porosity of the target reservoir; A demarcation value acquisition module: used to acquire the first demarcation value and the second demarcation value of the nuclear magnetic resonance T2 relaxation time; Cumulative amplitude acquisition module: used for dividing the target reservoir's nuclear magnetic resonance logging T2 spectrum into three intervals based on the first and second cutoff values ​​of the nuclear magnetic resonance T2 relaxation time, and respectively determining the cumulative amplitudes of the target reservoir's nuclear magnetic resonance logging T2 spectrum in the three intervals; Target reservoir fluid identification factor acquisition module: used to determine the target reservoir fluid property identification factor based on the cumulative amplitude in three intervals of the target reservoir's nuclear magnetic resonance logging T2 spectrum and the target reservoir's nuclear magnetic resonance T2 geometric mean; the target reservoir fluid property identification factor is determined by one of the following two formulas: Wherein, ifluid is the fluid property identification factor of the oil-based mud drilling reservoir; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals; T 2gm is the geometric mean value of nuclear magnetic resonance T2, ms; rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; Fluid property determination module: used to determine the fluid property of the target reservoir based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir; Among them, the fluid property determination module includes: The discrimination standard acquisition submodule is used to obtain the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being an oil layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a dry layer, which are applicable to the identification of the fluid property of the target reservoir; Fluid property identification submodule: used to determine whether the target reservoir is an oil layer, and / or a water layer, and / or a dry layer based on the fluid property identification factor of the target reservoir and the nuclear magnetic resonance porosity of the target reservoir and using the discrimination criteria; Among them, the discrimination standard acquisition submodule determines the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being an oil layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a water layer, and / or the fluid property identification factor and nuclear magnetic resonance porosity discrimination standard of the reservoir being a dry layer, which are applicable to the identification of the fluid properties of the target reservoir, by calibrating the oil-based mud drilling reservoir test data in the area where the target reservoir is located.

8. The identification system according to claim 7, wherein: The cutoff value acquisition module includes: Oil-based mud T2 spectrum acquisition submodule: used to obtain the nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir; The demarcation value determination submodule is used to determine the T2 relaxation time corresponding to the main peak position and the T2 relaxation time corresponding to the convergence point of the nuclear magnetic resonance T2 spectrum of the oil-based mud used in the target reservoir based on the nuclear magnetic resonance T2 spectrum of the oil-based mud, as the first demarcation value and the second demarcation value of the nuclear magnetic resonance T2 relaxation time, respectively.

9. The identification system according to claim 7, wherein: The target reservoir fluid identification factor acquisition module includes: Cumulative amplitude ratio determination submodule: used to determine the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum in the three intervals based on the cumulative amplitude in the three intervals of the nuclear magnetic resonance logging T2 spectrum of the target reservoir; Fluid identification factor determination submodule: used to determine the fluid property identification factor of the target reservoir based on the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum and the nuclear magnetic resonance T2 geometric mean of the target reservoir.

10. The identification system according to claim 9, wherein: The cumulative amplitude ratio determination submodule determines the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum through the following formula: Wherein, rs1 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs2 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; rs3 is the percentage of the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals to the total amplitude of the nuclear magnetic resonance logging T2 spectrum; samp1 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the smallest T2 relaxation time among the three intervals; samp2 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the median T2 relaxation time among the three intervals; samp3 is the cumulative amplitude of the nuclear magnetic resonance logging T2 spectrum in the interval with the largest T2 relaxation time among the three intervals.

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