Methods, apparatus, media, and equipment for determining total porosity of shale gas reservoirs

Abstract

The present invention discloses a method, device, medium and equipment for determining the total porosity of a shale gas reservoir. The method comprises: obtaining the equivalent total porosity of a shale sample and a target shale respectively; obtaining the experimental total porosity of the shale sample; fitting the equivalent total porosity of the shale sample and the experimental total porosity to obtain a fitting relationship between the equivalent total porosity and the experimental total porosity; obtaining the experimental total porosity of the target shale based on the fitting relationship between the equivalent total porosity and the experimental total porosity and the equivalent total porosity of the target shale. The method for determining the total porosity of a shale gas reservoir of the present invention uses two relatively common curves, namely, a natural gamma curve and an acoustic wave curve, to simply, quickly and accurately calculate the experimental total porosity, and is particularly suitable for shale gas horizontal wells with relatively large logging difficulties and relatively few logging data (no neutron logging and density logging).

Description

Technical Field

[0001] The present invention belongs to the field of unconventional oil and gas exploration and development, and specifically relates to a method, a device, a medium and equipment for determining the total porosity of a shale gas reservoir. Background Art

[0002] The determination of porosity in shale reservoirs is a key parameter for natural gas resource and economic evaluation. The pores in shale can be simply divided into inorganic pores and organic pores. Inorganic pores include microcracks, clay pores and debris pores, while organic pores are mainly nano-scale pores formed during the thermal evolution stage of organic hydrocarbon generation.

[0003] At present, the logging methods for determining porosity mainly include nuclear magnetic resonance logging, core calibration, density-based rock physics volume model method and neutron density intersection method. Among them, Ding Yujiao et al. (2014) pointed out that nuclear magnetic resonance logging has incomparable advantages in shale gas porosity evaluation, but this method is costly and not suitable for large-scale measurement. The core calibration method is based on a large number of analytical tests. Due to the complexity of rock components, the established model is often too complex and lacks corresponding physical meaning. At the same time, different experimental standards have a great influence on the shale porosity measurement results, and the difference can reach 1 to 3 times (Li Jun et al., 2017), which makes it difficult to evaluate the porosity by core calibration due to the lack of a unified experimental standard. Ultey (2005), Mavor (2009) and Sondergeld (2010) simplified shale into three parts: inorganic skeleton, organic matter and pores, and calculated the total porosity based on the rock physics volume response equation of density logging; however, this method is greatly affected by the borehole quality, and the mixed density of the inorganic skeleton also changes with the change of lithofacies. Considering the shortcomings of a single density logging curve, Li Jun et al. (2017) used density logging, neutron logging and sonic logging to equate shale to dry clay, non-clay particle skeleton, organic matter and pores, and then determined the total porosity. This method can more accurately obtain the total porosity of shale, but in the process of shale horizontal well logging, due to safety and funding considerations, there are generally no density and neutron logging curves, only gamma logging and sonic logging.

[0004] In the shale logging process, the gamma logging response value is mainly affected by the background value of the mud content and the organic matter content. When the proportion of organic pores is consistent, after deducting the influence of the background value of the mud content, it can be approximately considered that the gamma logging value is linearly related to the size of the organic porosity. At the same time, the acoustic porosity mainly reflects the primary porosity.

[0005] Therefore, a method for determining the total porosity of shale gas reservoirs using gamma and sonic curves can be proposed. Summary of the invention

[0006] The purpose of the present invention is to provide a method for determining the total porosity of shale gas reservoirs by using gamma and sonic curves.

[0007] The present invention provides a method for determining the total porosity of a shale gas reservoir, comprising: obtaining the equivalent total porosity of a shale sample and a target shale, respectively; obtaining the experimental total porosity of the shale sample; fitting the equivalent total porosity of the shale sample with the experimental total porosity to obtain a fitting relationship between the equivalent total porosity and the experimental total porosity; and obtaining the experimental total porosity of the target shale based on the fitting relationship between the equivalent total porosity and the experimental total porosity and the equivalent total porosity of the target shale.

[0008] Optionally, the equivalent total porosity of shale is obtained by the following steps: performing organic matter content correction on the acoustic time difference logging curve of shale to obtain an equivalent acoustic time difference; normalizing the equivalent acoustic time difference to obtain a normalized value of the equivalent acoustic time difference; normalizing the natural gamma curve of shale to obtain a normalized value of the natural gamma curve; and obtaining the equivalent total porosity based on the normalized value of the equivalent acoustic time difference and the normalized value of the natural gamma curve.

[0009] Optionally, the equivalent acoustic wave time difference is:

[0010] Δt'=Δt-V k (Δt k -Δt ma )

[0011] Among them, Δt' is the equivalent acoustic time difference, Δt is the logging acoustic time difference value of shale, V k is the volume percentage of the organic framework, Δt k and Δt ma are the acoustic time difference values ​​of organic skeleton and inorganic skeleton respectively.

[0012] Optionally, the normalized value of the equivalent acoustic wave time difference is:

[0013]

[0014] Where: φ ac is the normalized value of the equivalent acoustic wave time difference, which reflects the relative size of the inorganic porosity; Δt' is the equivalent acoustic wave time difference; Δt' max and Δt' min They are the upper and lower limits of the equivalent acoustic time difference respectively.

[0015] Optionally, the value of the natural gamma curve after normalization is:

[0016]

[0017] Where: φ gr is the value after normalization of the natural gamma curve, which reflects the relative size of organic porosity; GR is the natural gamma logging value of shale, GR max and GR min They are the upper and lower limits of natural gamma logging values ​​respectively.

[0018] Optionally, the equivalent total porosity is calculated using the following formula:

[0019] φ ag =φ ac +φ gr

[0020] Among them, φ ag is the equivalent total porosity.

[0021] Optionally, the fitting relationship between the equivalent total porosity and the experimental total porosity is:

[0022] φ t =Aφ ag +B

[0023] Among them, φ t is the total porosity of the experiment, φ ag is the equivalent total porosity, A and B are constants.

[0024] The present invention also provides an electronic device, comprising: a memory storing executable instructions; and a processor, wherein the processor runs the executable instructions in the memory to implement the above-mentioned method for determining the total porosity of a shale gas reservoir.

[0025] The present invention also provides a computer-readable storage medium, which stores a computer program. When the computer program is executed by a processor, the method for determining the total porosity of a shale gas reservoir is implemented.

[0026] The present invention also provides a device for determining the total porosity of a shale gas reservoir, comprising: an equivalent total porosity acquisition module for respectively obtaining the equivalent total porosity of a shale sample and a target shale; an experimental total porosity acquisition module for a shale sample for obtaining the experimental total porosity of the shale sample; a fitting relationship determination module for fitting the equivalent total porosity of the shale sample with the experimental total porosity to obtain a fitting relationship between the equivalent total porosity and the experimental total porosity; and an experimental total porosity acquisition module for a target shale for obtaining the experimental total porosity of the target shale based on the fitting relationship between the equivalent total porosity and the experimental total porosity and the equivalent total porosity of the target shale.

[0027] Optionally, the equivalent acoustic wave time difference is:

[0028] Δt'=Δt-Vk (Δt k -Δt ma )

[0029] Among them, Δt' is the equivalent acoustic time difference, Δt is the logging acoustic time difference value of shale, V k is the volume percentage of the organic framework, Δt k and Δt ma are the acoustic time difference values ​​of organic skeleton and inorganic skeleton respectively.

[0030] Optionally, the normalized value of the equivalent acoustic wave time difference is:

[0031]

[0032] Where: φ ac is the normalized value of the equivalent acoustic wave time difference, which reflects the relative size of the inorganic porosity; Δt' is the equivalent acoustic wave time difference; Δt' max and Δt' min They are the upper and lower limits of the equivalent acoustic time difference respectively.

[0033] Optionally, the value of the natural gamma curve after normalization is:

[0034]

[0035] Where: φ gr is the value after normalization of the natural gamma curve, which reflects the relative size of organic porosity; GR is the natural gamma logging value of shale, GR max and GR min They are the upper and lower limits of natural gamma logging values ​​respectively.

[0036] Optionally, the equivalent total porosity is calculated using the following formula:

[0037] φ ag =φ ac +φ gr

[0038] Among them, φ ag is the equivalent total porosity.

[0039] Optionally, the fitting relationship between the equivalent total porosity and the experimental total porosity is:

[0040] φ t =Aφ ag +B

[0041] Among them, φ t is the total porosity of the experiment, φ ag is the equivalent total porosity, A and B are constants.

[0042] The beneficial effect of the present invention is that the method for determining the total porosity of shale gas reservoirs of the present invention utilizes two relatively common curves, namely the natural gamma curve and the acoustic wave curve, to simply, quickly and accurately calculate the experimental total porosity, and is particularly suitable for shale gas horizontal wells where logging is relatively difficult and logging data is relatively scarce (no neutron logging and density logging).

[0043] The present invention has other features and advantages, which will be apparent from or will be described in detail in the accompanying drawings and the following specific embodiments incorporated herein, which together serve to explain the specific principles of the present invention. BRIEF DESCRIPTION OF THE DRAWINGS

[0044] The above and other objects, features and advantages of the present invention will become more apparent through a more detailed description of exemplary embodiments of the present invention in conjunction with the accompanying drawings, wherein like reference numerals generally represent like components throughout the exemplary embodiments of the present invention.

[0045] Figure 1 A flow chart of a method for determining the total porosity of a shale gas reservoir according to an embodiment of the present invention is shown.

[0046] Figure 2 The relationship between the experimental total porosity and the equivalent total porosity of shale gas reservoirs in the Sichuan Basin is shown.

[0047] Figure 3 The figure shows the comparison between the experimental total porosity calculated by vertical well A1 in Sichuan Basin and the total porosity analyzed by core.

[0048] Figure 4 A comparison chart showing the experimental total porosity calculated for horizontal well B1 in the Sichuan Basin and the total porosity calculated using neutron density intersection is shown.

[0049] Figure 5 A block diagram of a device for determining the total porosity of a shale gas reservoir according to an embodiment of the present invention is shown.

[0050] Description of Reference Numerals

[0051] 102. Equivalent total porosity acquisition module; 104. Experimental total porosity acquisition module for shale samples; 106. Fitting relationship determination module; 108. Experimental total porosity acquisition module for target shale. DETAILED DESCRIPTION

[0052] The preferred embodiments of the present invention will be described in more detail below. Although the preferred embodiments of the present invention are described below, it should be understood that the present invention can be implemented in various forms and should not be limited to the embodiments set forth herein.

[0053] The present invention provides a method for determining the total porosity of a shale gas reservoir, comprising: respectively obtaining the equivalent total porosities of a shale sample and a target shale; obtaining the experimental total porosity of the shale sample; fitting the equivalent total porosity of the shale sample with the experimental total porosity to obtain a fitting relationship between the equivalent total porosity and the experimental total porosity; and obtaining the experimental total porosity of the target shale based on the fitting relationship between the equivalent total porosity and the experimental total porosity and the equivalent total porosity of the target shale.

[0054] Specifically, first, the sonic logging is corrected for organic matter and normalized to eliminate the combined effects of organic matter and inorganic skeletons, and obtain a quantity reflecting the relative size of inorganic pores; secondly, the gamma logging is normalized to eliminate the influence of inorganic skeletons, and obtain a quantity reflecting the relative size of organic pores; then, the two normalized porosities are added together to obtain the equivalent total porosity, and a quantitative relationship between the equivalent total porosity and the experimental total porosity of core analysis is established, and finally, based on the quantitative relationship and the equivalent total porosity of the target shale, the quantitative calculation of the experimental total porosity of the target shale is achieved.

[0055] According to an exemplary embodiment, the method for determining the total porosity of shale gas reservoirs utilizes two relatively common curves, namely the natural gamma curve and the acoustic wave curve, to simply, quickly and accurately calculate the experimental total porosity. It is particularly suitable for shale gas horizontal wells where logging is relatively difficult and logging data is relatively scarce (no neutron logging and density logging).

[0056] As an optional scheme, the equivalent total porosity of shale is obtained by the following steps: the sonic time difference logging curve of shale is corrected for organic matter content to obtain an equivalent sonic time difference; the equivalent sonic time difference is normalized to obtain a normalized value of the equivalent sonic time difference; the natural gamma curve of shale is normalized to obtain a normalized value of the natural gamma curve; the equivalent total porosity is obtained based on the normalized value of the equivalent sonic time difference and the normalized value of the natural gamma curve.

[0057] As an alternative, the equivalent acoustic time difference is:

[0058] Δt'=Δt-V k (Δt k -Δt ma )

[0059] Among them, Δt' is the equivalent acoustic time difference, Δt is the logging acoustic time difference value of shale, V k is the volume percentage of the organic framework, Δt k and Δt ma are the acoustic time difference values ​​of organic skeleton and inorganic skeleton respectively.

[0060] As an option, the normalized value of the equivalent acoustic time difference is:

[0061]

[0062] Where: φ ac is the normalized value of the equivalent acoustic wave time difference, which reflects the relative size of the inorganic porosity; Δt' is the equivalent acoustic wave time difference; Δt' max and Δt' min They are the upper and lower limits of the equivalent acoustic time difference respectively.

[0063] Specifically, the acoustic wave curve is corrected for organic matter to obtain the equivalent acoustic wave time difference Δt' with the same porosity, the same fluid and inorganic skeleton as the shale, and then the equivalent acoustic wave time difference Δt' is normalized to eliminate the influence of lithology:

[0064] Δt'=Δt-V k (Δt k -Δt ma ) (1)

[0065]

[0066] Where: φ ac V is the normalized value of the equivalent acoustic wave time difference, dimensionless, reflecting the relative size of the inorganic porosity; k Organic framework volume percentage, v / v; Δt k and Δt ma are the acoustic time difference values ​​of organic skeleton and inorganic skeleton, us / ft; Δt is the logging acoustic time difference value of shale, us / ft; Δt' max and Δt' min They are the upper and lower limits of the equivalent acoustic time difference, us / ft.

[0067] As an alternative, the normalized value of the natural gamma curve is:

[0068]

[0069] Where: φ gr is the value after normalization of the natural gamma curve, which reflects the relative size of organic porosity; GR is the natural gamma logging value of shale, GR max and GR min They are the upper and lower limits of natural gamma logging values ​​respectively.

[0070] Specifically, the natural gamma ray curve is normalized to eliminate the influence of lithology on the natural gamma ray, and the value reflecting the relative size of organic porosity is obtained:

[0071]

[0072] Where: φ gr It is the normalized value of the natural gamma curve, dimensionless, and reflects the relative size of the organic porosity.

[0073] As an alternative, the equivalent total porosity can be calculated using the following formula:

[0074] φ ag =φ ac +φ gr

[0075] Among them, φ ag is the equivalent total porosity.

[0076] Specifically, the normalized results of the equivalent acoustic wave curve and the gamma curve are added together to obtain a curve φ reflecting the relative size of the equivalent total porosity. ag :

[0077] φ ag =φ ac +φ gr (4).

[0078] As an alternative, the fitting relationship between the equivalent total porosity and the experimental total porosity is:

[0079] φ t =Aφ ag +B

[0080] Among them, φ t is the total porosity of the experiment, φ ag is the equivalent total porosity, A and B are constants.

[0081] Specifically, compared with φ ag Curve and core analysis experiment total porosity, φ ag There is a linear positive correlation with the porosity of the core analysis experiment. ag The larger it is, the larger the corresponding total porosity of the shale experiment is.

[0082] φ t =Aφ ag +B (5)

[0083] After experimental calibration, we can obtain: A=7.08, B=4.38.

[0084] The present invention also provides an electronic device, which includes: a memory storing executable instructions; and a processor, which runs the executable instructions in the memory to implement the above-mentioned method for determining the total porosity of a shale gas reservoir.

[0085] The present invention also provides a computer-readable storage medium, which stores a computer program. When the computer program is executed by a processor, the method for determining the total porosity of a shale gas reservoir is implemented.

[0086] The present invention also provides a device for determining the total porosity of a shale gas reservoir, comprising: an equivalent total porosity acquisition module for respectively obtaining the equivalent total porosities of a shale sample and a target shale; an experimental total porosity acquisition module for a shale sample for obtaining the experimental total porosity of the shale sample; a fitting relationship determination module for fitting the equivalent total porosity of the shale sample with the experimental total porosity to obtain a fitting relationship between the equivalent total porosity and the experimental total porosity; and an experimental total porosity acquisition module for a target shale for obtaining the experimental total porosity of the target shale based on the fitting relationship between the equivalent total porosity and the experimental total porosity and the equivalent total porosity of the target shale.

[0087] Specifically, first, the sonic logging is corrected for organic matter and normalized to eliminate the combined effects of organic matter and inorganic skeletons, and obtain a quantity reflecting the relative size of inorganic pores; secondly, the gamma logging is normalized to eliminate the influence of inorganic skeletons, and obtain a quantity reflecting the relative size of organic pores; then, the two normalized porosities are added together to obtain the equivalent total porosity, and a quantitative relationship between the equivalent total porosity and the experimental total porosity of core analysis is established, and finally, based on the quantitative relationship and the equivalent total porosity of the target shale, the quantitative calculation of the experimental total porosity of the target shale is achieved.

[0088] According to an exemplary embodiment, the device for determining the total porosity of shale gas reservoirs uses two of the more common curves, the natural gamma curve and the acoustic wave curve, to simply, quickly and accurately calculate the experimental total porosity. It is particularly suitable for shale gas horizontal wells where logging is relatively difficult and logging data is relatively scarce (no neutron logging and density logging).

[0089] As an optional scheme, the equivalent total porosity of shale is obtained by the following steps: the sonic time difference logging curve of shale is corrected for organic matter content to obtain an equivalent sonic time difference; the equivalent sonic time difference is normalized to obtain a normalized value of the equivalent sonic time difference; the natural gamma curve of shale is normalized to obtain a normalized value of the natural gamma curve; the equivalent total porosity is obtained based on the normalized value of the equivalent sonic time difference and the normalized value of the natural gamma curve.

[0090] As an alternative, the equivalent acoustic time difference is:

[0091] Δt'=Δt-V k (Δt k -Δt ma )

[0092] Among them, Δt' is the equivalent acoustic time difference, Δt is the logging acoustic time difference value of shale, V k is the volume percentage of the organic framework, Δt k and Δt ma are the acoustic time difference values ​​of organic skeleton and inorganic skeleton respectively.

[0093] As an option, the normalized value of the equivalent acoustic time difference is:

[0094]

[0095] Where: φ ac is the normalized value of the equivalent acoustic wave time difference, which reflects the relative size of the inorganic porosity; Δt' is the equivalent acoustic wave time difference; Δt' max and Δt' min They are the upper and lower limits of the equivalent acoustic time difference respectively.

[0096] Specifically, the acoustic wave curve is corrected for organic matter to obtain the equivalent acoustic wave time difference Δt' with the same porosity, the same fluid and inorganic skeleton as the shale, and then the equivalent acoustic wave time difference Δt' is normalized to eliminate the influence of lithology:

[0097] Δt'=Δt-V k (Δt k -Δt ma ) (1)

[0098]

[0099] Where: φ ac V is the normalized value of the equivalent acoustic wave time difference, dimensionless, reflecting the relative size of the inorganic porosity; k Organic framework volume percentage, v / v; Δt k and Δt ma are the acoustic time difference values ​​of organic skeleton and inorganic skeleton, us / ft; Δt is the logging acoustic time difference value of shale, us / ft; Δt' max and Δt' min They are the upper and lower limits of the equivalent acoustic time difference, us / ft.

[0100] As an alternative, the normalized value of the natural gamma curve is:

[0101]

[0102] Where: φ gr is the value after normalization of the natural gamma curve, which reflects the relative size of organic porosity; GR is the natural gamma logging value of shale, GR max and GR minThey are the upper and lower limits of natural gamma logging values ​​respectively.

[0103] Specifically, the natural gamma ray curve is normalized to eliminate the influence of lithology on the natural gamma ray, and the value reflecting the relative size of organic porosity is obtained:

[0104]

[0105] Where: φ gr It is the normalized value of the natural gamma curve, dimensionless, and reflects the relative size of the organic porosity.

[0106] As an alternative, the equivalent total porosity can be calculated using the following formula:

[0107] φ ag =φ ac +φ gr

[0108] Among them, φ ag is the equivalent total porosity.

[0109] Specifically, the normalized results of the equivalent acoustic wave curve and the gamma curve are added together to obtain a curve φ reflecting the relative size of the equivalent total porosity. ag :

[0110] φ ag =φ ac +φ gr (4).

[0111] As an alternative, the fitting relationship between the equivalent total porosity and the experimental total porosity is:

[0112] φ t =Aφ ag +B

[0113] Among them, φ t is the total porosity of the experiment, φ ag is the equivalent total porosity, A and B are constants.

[0114] Specifically, compared with φ ag Curve and core analysis experiment total porosity, φ ag There is a linear positive correlation with the porosity of the core analysis experiment. ag The larger it is, the larger the corresponding total porosity of the shale experiment is.

[0115] φ t =Aφ ag +B (5)

[0116] After experimental calibration, we can obtain: A=7.08, B=4.38.

[0117] Embodiment 1

[0118] Figure 1 A flow chart of a method for determining the total porosity of a shale gas reservoir according to an embodiment of the present invention is shown. Figure 2 The relationship between the experimental total porosity and the equivalent total porosity of shale gas reservoirs in the Sichuan Basin is shown. Figure 3 The figure shows the comparison between the experimental total porosity calculated by vertical well A1 in Sichuan Basin and the total porosity analyzed by core. Figure 4 A comparison chart showing the experimental total porosity calculated for horizontal well B1 in the Sichuan Basin and the total porosity calculated using neutron density intersection is shown.

[0119] Combination Figure 1 , Figure 2 , Figure 3 and Figure 4 As shown, the method for determining the total porosity of a shale gas reservoir comprises:

[0120] Step 1: Obtain the equivalent total porosity of the shale sample and the target shale respectively;

[0121] The equivalent total porosity of shale is obtained by the following steps: the sonic time difference logging curve of shale is corrected for organic matter content to obtain an equivalent sonic time difference; the equivalent sonic time difference is normalized to obtain a normalized value of the equivalent sonic time difference; the natural gamma curve of shale is normalized to obtain a normalized value of the natural gamma curve; the equivalent total porosity is obtained based on the normalized value of the equivalent sonic time difference and the normalized value of the natural gamma curve.

[0122] Among them, the equivalent sound wave time difference is:

[0123] Δt'=Δt-V k (Δt k -Δt ma )

[0124] Among them, Δt' is the equivalent acoustic time difference, Δt is the logging acoustic time difference value of shale, V k is the volume percentage of the organic framework, Δt k and Δt ma are the acoustic time difference values ​​of organic skeleton and inorganic skeleton respectively.

[0125] Among them, the normalized value of the equivalent acoustic time difference is:

[0126]

[0127] Where: φ ac is the normalized value of the equivalent acoustic wave time difference, which reflects the relative size of the inorganic porosity; Δt' is the equivalent acoustic wave time difference; Δt' max and Δt'min They are the upper and lower limits of the equivalent acoustic time difference respectively.

[0128] Among them, the value of the natural gamma curve after normalization is:

[0129]

[0130] Where: φ gr is the value after normalization of the natural gamma curve, which reflects the relative size of organic porosity; GR is the natural gamma logging value of shale, GR max and GR min They are the upper and lower limits of natural gamma logging values ​​respectively.

[0131] Among them, the equivalent total porosity is calculated using the following formula:

[0132] φ ag =φ ac +φ gr

[0133] Among them, φ ag is the equivalent total porosity.

[0134] Step 2: Obtain the experimental total porosity of the shale sample;

[0135] Step 3: Fit the equivalent total porosity of the shale sample and the experimental total porosity to obtain the fitting relationship between the equivalent total porosity and the experimental total porosity;

[0136] Among them, the fitting relationship between the equivalent total porosity and the experimental total porosity is:

[0137] φ t =Aφ ag +B

[0138] Among them, φ t is the total porosity of the experiment, φ ag is the equivalent total porosity, A and B are constants.

[0139] Step 4: Based on the fitting relationship between the equivalent total porosity and the experimental total porosity and the equivalent total porosity of the target shale, the experimental total porosity of the target shale is obtained.

[0140] Taking the vertical well A1 in the Sichuan Basin as an example, the total porosity of vertical well A1 is explained. Figure 3 As shown, the first solid line in the figure is the logging acoustic time difference curve, and the dotted line is the natural gamma curve; the second dotted line in the figure is the natural potential curve, and the solid line is the wellbore curve; the third track is the TOC mass percentage content curve; and the fourth track is the depth track.

[0141] The sonic time difference logging curve AC is corrected for organic matter content to obtain an equivalent sonic time difference curve that is not affected by changes in organic matter content, as shown by the solid line in the fifth track in the figure; the equivalent sonic time difference curve is normalized to obtain a curve reflecting the relative size of inorganic porosity, as shown by the solid line in the sixth track in the figure; the natural gamma curve is normalized to obtain a curve reflecting the relative size of organic porosity, as shown by the dotted line in the sixth track in the figure. Then the two normalized curves are added together to obtain a curve reflecting the relative size of total porosity, and the fitting relationship between the equivalent total porosity and the experimental total porosity is obtained. Finally, the experimental total porosity curve of the target shale is obtained, as shown by the solid line in the seventh track in the figure, and the total porosity of shale measured by the gas logging method is represented by a rod-shaped line in the seventh track. Compared with core analysis, it is shown that the calculation method of shale total porosity proposed by the present invention has good evaluation accuracy.

[0142] Taking the horizontal well B1 in the Sichuan Basin as an example, the interpretation of the experimental total porosity was carried out. Figure 4 As shown in the figure, the first dotted line is the acoustic time difference curve, the solid line is the natural gamma curve; the second dotted line is the wellbore curve; the third dotted line is the neutron curve, the solid line is the density curve; the fourth is the TOC content curve; the fifth is the depth curve. The interpretation of the porosity of this well can refer to the interpretation process of the vertical well A1. The eighth solid line in the figure is the total porosity of shale experiment calculated by the new method, and the dotted line is the total porosity of shale calculated by the neutron density intersection method. The two have good consistency.

[0143] From the comparison of the logging evaluation results of the pilot well and the horizontal well, it can be seen that the total porosity evaluation method proposed by the present invention not only has high accuracy but also has strong applicability.

[0144] Embodiment 2

[0145] Figure 5 A block diagram of a device for determining the total porosity of a shale gas reservoir according to an embodiment of the present invention is shown.

[0146] like Figure 5 As shown, the device for determining the total porosity of a shale gas reservoir comprises:

[0147] An equivalent total porosity acquisition module 102 is used to obtain the equivalent total porosity of the shale sample and the target shale respectively;

[0148] The experimental total porosity acquisition module 104 of the shale sample is used to obtain the experimental total porosity of the shale sample;

[0149] A fitting relationship determination module 106 is used to fit the equivalent total porosity of the shale sample and the experimental total porosity to obtain a fitting relationship between the equivalent total porosity and the experimental total porosity;

[0150] The experimental total porosity acquisition module 108 of the target shale obtains the experimental total porosity of the target shale based on the fitting relationship between the equivalent total porosity and the experimental total porosity and the equivalent total porosity of the target shale.

[0151] The equivalent total porosity of shale is obtained by the following steps: the sonic time difference logging curve of shale is corrected for organic matter content to obtain an equivalent sonic time difference; the equivalent sonic time difference is normalized to obtain a normalized value of the equivalent sonic time difference; the natural gamma curve of shale is normalized to obtain a normalized value of the natural gamma curve; the equivalent total porosity is obtained based on the normalized value of the equivalent sonic time difference and the normalized value of the natural gamma curve.

[0152] Among them, the equivalent sound wave time difference is:

[0153] Δt'=Δt-V k (Δt k -Δt ma )

[0154] Among them, Δt' is the equivalent acoustic time difference, Δ t is the logging acoustic time difference of shale, V k is the volume percentage of the organic framework, Δt k and Δt ma are the acoustic time difference values ​​of organic skeleton and inorganic skeleton respectively.

[0155] Among them, the normalized value of the equivalent acoustic time difference is:

[0156]

[0157] Where: φ ac is the normalized value of the equivalent acoustic wave time difference, which reflects the relative size of the inorganic porosity; Δt' is the equivalent acoustic wave time difference; Δt' max and Δt' min They are the upper and lower limits of the equivalent acoustic time difference respectively.

[0158] Among them, the value of the natural gamma curve after normalization is:

[0159]

[0160] Where: φ gr is the value after normalization of the natural gamma curve, which reflects the relative size of organic porosity; GR is the natural gamma logging value of shale, GR max and GR min They are the upper and lower limits of natural gamma logging values ​​respectively.

[0161] Among them, the equivalent total porosity is calculated using the following formula:

[0162] φ ag =φ ac +φ gr

[0163] Among them, φ ag is the equivalent total porosity.

[0164] Among them, the fitting relationship between the equivalent total porosity and the experimental total porosity is:

[0165] φ t =Aφ ag +B

[0166] Among them, φ t is the total porosity of the experiment, φ ag is the equivalent total porosity, A and B are constants.

[0167] Embodiment 3

[0168] The present disclosure provides an electronic device, which includes: a memory storing executable instructions; a processor, which runs the executable instructions in the memory to implement the above-mentioned method for determining the total porosity of a shale gas reservoir.

[0169] An electronic device according to an embodiment of the present disclosure includes a memory and a processor.

[0170] The memory is used to store non-temporary computer-readable instructions. Specifically, the memory may include one or more computer program products, which may include various forms of computer-readable storage media, such as volatile memory and / or non-volatile memory. The volatile memory may, for example, include random access memory (RAM) and / or cache memory (cache), etc. The non-volatile memory may, for example, include read-only memory (ROM), hard disk, flash memory, etc.

[0171] The processor may be a central processing unit (CPU) or other forms of processing units having data processing capabilities and / or instruction execution capabilities, and may control other components in the electronic device to perform desired functions. In one embodiment of the present disclosure, the processor is used to run the computer-readable instructions stored in the memory.

[0172] Those skilled in the art should be able to understand that in order to solve the technical problem of how to obtain a good user experience, the present embodiment may also include well-known structures such as a communication bus and an interface, and these well-known structures should also be included in the protection scope of the present disclosure.

[0173] For detailed description of this embodiment, reference may be made to the corresponding descriptions in the aforementioned embodiments, which will not be repeated here.

[0174] Embodiment 4

[0175] The present disclosure provides a computer-readable storage medium storing a computer program, which implements the above-mentioned method for determining the total porosity of a shale gas reservoir when executed by a processor.

[0176] According to the computer-readable storage medium of the embodiment of the present disclosure, non-transitory computer-readable instructions are stored thereon. When the non-transitory computer-readable instructions are executed by a processor, all or part of the steps of the above-mentioned methods of each embodiment of the present disclosure are executed.

[0177] The above-mentioned computer-readable storage media include, but are not limited to: optical storage media (e.g., CD-ROM and DVD), magneto-optical storage media (e.g., MO), magnetic storage media (e.g., magnetic tape or mobile hard disk), media with built-in rewritable non-volatile memory (e.g., memory card) and media with built-in ROM (e.g., ROM box).

[0178] The embodiments of the present invention have been described above, and the above description is exemplary, not exhaustive, and is not limited to the disclosed embodiments. Many modifications and changes will be apparent to those skilled in the art without departing from the scope and spirit of the described embodiments.

Claims

1. A method for determining the total porosity of a shale gas reservoir, characterized in that: include: The equivalent total porosity of the shale sample and the target shale is obtained respectively; Obtain the experimental total porosity of the shale sample; Fitting the equivalent total porosity of the shale sample and the experimental total porosity to obtain a fitting relationship between the equivalent total porosity and the experimental total porosity; Based on the fitting relationship between the equivalent total porosity and the experimental total porosity and the equivalent total porosity of the target shale, the experimental total porosity of the target shale is obtained; The equivalent total porosity of shale is obtained by the following steps: The sonic transit time logging curve of shale is corrected for organic matter content to obtain equivalent sonic transit time; Normalizing the equivalent acoustic wave time difference to obtain a normalized value of the equivalent acoustic wave time difference; Normalizing the natural gamma curve of the shale to obtain a normalized value of the natural gamma curve; Obtaining an equivalent total porosity based on the normalized value of the equivalent acoustic wave time difference and the normalized value of the natural gamma curve; Wherein, the equivalent acoustic wave time difference is: Δt′=Δt-V k (Δt k -Δt ma ) Among them, Δt′ is the equivalent acoustic time difference, Δt is the logging acoustic time difference value of shale, V k is the volume percentage of the organic framework, Δt k and Δt ma are the acoustic time difference values ​​of organic skeleton and inorganic skeleton respectively.

2. The method for determining the total porosity of a shale gas reservoir according to claim 1, characterized in that: The normalized value of the equivalent acoustic wave time difference is: Where: φ ac is the normalized value of the equivalent acoustic wave time difference, which reflects the relative size of the inorganic porosity; Δt′ is the equivalent acoustic wave time difference; Δt′ max and Δt′ min They are the upper and lower limits of the equivalent acoustic time difference respectively.

3. The method for determining the total porosity of a shale gas reservoir according to claim 2, characterized in that: The value of the natural gamma curve after normalization is: Where: φ gr is the value after normalization of the natural gamma curve, which reflects the relative size of organic porosity; GR is the natural gamma logging value of shale, GR max and GR min They are the upper and lower limits of natural gamma logging values ​​respectively.

4. The method for determining the total porosity of a shale gas reservoir according to claim 3, characterized in that: The equivalent total porosity is calculated using the following formula: f ag =φ ac +φ gr Among them, φ ag is the equivalent total porosity.

5. The method for determining the total porosity of a shale gas reservoir according to claim 1, characterized in that: The fitting relationship between the equivalent total porosity and the experimental total porosity is: φ t =Aφ ag +B Among them, φ t is the total porosity of the experiment, φ ag is the equivalent total porosity, A and B are constants.

6. An electronic device, characterized in that: The electronic device comprises: A memory storing executable instructions; A processor, wherein the processor runs the executable instructions in the memory to implement the method for determining the total porosity of a shale gas reservoir as described in any one of claims 1-5.

7. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores a computer program, which, when executed by a processor, implements the method for determining the total porosity of a shale gas reservoir according to any one of claims 1-5.

8. A device for determining the total porosity of a shale gas reservoir, characterized in that: include: An equivalent total porosity acquisition module is used to obtain the equivalent total porosity of the shale sample and the target shale respectively; A shale sample experimental total porosity acquisition module, which obtains the experimental total porosity of the shale sample; A fitting relationship determination module is used to fit the equivalent total porosity of the shale sample and the experimental total porosity to obtain a fitting relationship between the equivalent total porosity and the experimental total porosity; An experimental total porosity acquisition module for a target shale, which acquires the experimental total porosity of the target shale based on the fitting relationship between the equivalent total porosity and the experimental total porosity and the equivalent total porosity of the target shale; The equivalent total porosity of shale is obtained by the following steps: The sonic transit time logging curve of shale is corrected for organic matter content to obtain equivalent sonic transit time; Normalizing the equivalent acoustic wave time difference to obtain a normalized value of the equivalent acoustic wave time difference; Normalizing the natural gamma curve of the shale to obtain a normalized value of the natural gamma curve; Obtaining an equivalent total porosity based on the normalized value of the equivalent acoustic wave time difference and the normalized value of the natural gamma curve; Wherein, the equivalent acoustic wave time difference is: Δt′=Δt-V k (Δt k -Δt ma ) Among them, Δt′ is the equivalent acoustic time difference, Δt is the logging acoustic time difference value of shale, V k is the volume percentage of the organic framework, Δt k and Δt ma are the acoustic time difference values ​​of organic skeleton and inorganic skeleton respectively.

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