Method and device for identifying coexistence of natural gas hydrate and free gas, and electronic equipment

Abstract

The application discloses a method and device for identifying coexistence of natural gas hydrate and free gas and electronic equipment. The method comprises the following steps: obtaining the measured value of formation resistivity and the measured value of nuclear magnetic porosity of the reservoir to be interpreted of the target well; calculating the water saturation of the reservoir to be interpreted according to the measured value of formation resistivity and the pre-calculated formation water resistivity, formation porosity, lithology coefficient and preset saturation index; based on the nuclear magnetic resonance logging porosity calculation model, taking the reservoir to be interpreted as a pure gas layer as a hypothetical condition, substituting the water saturation, and forward calculating the nuclear magnetic porosity calculation value of the reservoir to be interpreted under the condition of the pure gas layer; and according to the nuclear magnetic porosity calculation value and the measured value of nuclear magnetic porosity, constructing an identification chart of the reservoir to be interpreted to identify whether the reservoir to be interpreted contains natural gas hydrate. The application can accurately identify the coexistence of hydrate and free gas under the condition of lacking expensive core data and lacking shear wave data based on the measured data on site.

Description

Technical Field

[0001] This invention relates to the field of natural gas hydrate exploration technology in drilling wells, and particularly to a method, apparatus, and electronic device for identifying the coexistence of natural gas hydrates and free gas. Background Technology

[0002] The presence of coexisting natural gas hydrate (hereinafter referred to as "hydrate") and free gas layers has a crucial impact on hydrate resource assessment, reservoir stability analysis, and exploitation scheme design. Misclassifying these layers as pure hydrate layers would severely overestimate the saturation and resource quantity of solid hydrates; conversely, it would underestimate the total gas resources in these layers. Therefore, accurately identifying the coexistence of hydrates and free gas is a key technical challenge in the field of hydrate exploration and development.

[0003] Currently, common methods for identifying whether natural gas hydrates and free gas coexist are as follows:

[0004] (1) Drilling and coring: If the infrared scan of the sediment sample shows low temperature anomalies or a significant decrease in pore water salinity, it indicates the presence of hydrates. Combined with density neutron logging response, it can be identified whether hydrates and free gas coexist. However, offshore drilling and coring is very expensive, both time-consuming and costly, especially in deep-sea environments where drilling costs are even higher.

[0005] (2) Patent No. [CN201811316048.8] sets a fixed range of scales for neutron, density, and acoustic transit time curves, allowing these three curves to intersect. The intersecting areas of different three-porosity curves are marked accordingly, and the existence state of hydrates and free gas is determined based on the corresponding marks. The disadvantage is that for a study area, it is difficult to ensure that the same type of instrument, the same standard calibrator, and the same operating method are used for measurement and calibration. Therefore, there will inevitably be errors between the logging data of each well, mainly due to calibration factors. Furthermore, using a fixed curve scale range to intersect curves to identify the coexistence layer of hydrates and free gas will inevitably lead to misjudgment of the hydrate reservoir type. Moreover, there is an overlap in the intersecting areas, and different personnel may have different identification results. It is highly subjective, has large errors, and lacks universality.

[0006] (3) In coexisting layers, the presence of hydrates increases shear wave velocity, while free gas has little inhibitory effect. Therefore, shear wave velocity will mainly reflect the skeletal support effect of hydrates, making it a potentially effective indicator for identifying coexisting layers. The disadvantage is that not all drilled wells have measured shear wave data, and some logging equipment cannot measure shear wave velocity. Summary of the Invention

[0007] This invention provides a method, apparatus, and electronic device for identifying the coexistence of natural gas hydrates and free gas, which can accurately identify the hydrate and free gas coexisting zones without the need for expensive core data and in the absence of shear wave data.

[0008] According to one aspect of the present invention, a method for identifying the coexistence of natural gas hydrates and free gas is provided, comprising:

[0009] Obtain measured values ​​of formation resistivity and nuclear magnetic resonance porosity of the reservoir to be interpreted in the target well;

[0010] The water saturation of the reservoir to be interpreted is calculated based on the measured value of the formation resistivity and the pre-calculated formation water resistivity, formation porosity, lithology coefficient and preset saturation index.

[0011] Based on the nuclear magnetic resonance logging porosity calculation model, taking the reservoir to be explained as a pure gas layer as an assumption, and substituting the water saturation, the nuclear magnetic porosity calculation value of the reservoir to be explained under the pure gas layer state is calculated by forward modeling.

[0012] Based on the calculated NMR porosity and the measured NMR porosity, an identification chart of the reservoir to be explained is constructed to identify whether the reservoir contains natural gas hydrates.

[0013] Optionally, the water saturation of the reservoir to be interpreted is calculated based on the measured value of the formation resistivity and pre-calculated formation water resistivity, formation porosity, lithology coefficient, and preset saturation index, including:

[0014] The water saturation of the reservoir to be interpreted is calculated using the following formula:

[0015] In the formula, Water saturation To preset the saturation index, The pre-calculated formation water resistivity; Lithology coefficient, The cementation index; This is the measured value of the formation resistivity. This refers to the porosity of the formation.

[0016] Optionally, the formation water resistivity can be determined as follows:

[0017] Given the salinity and geothermal gradient of the formation water, the formula can be used to... The calculation yields the result; where, , All are formation temperatures. For the formation temperature at The resistivity of formation water at that time;

[0018] Given the unknown salinity, seabed temperature, and geothermal gradient of the formation water, the resistivity of the formation water is taken as 0.25Ω.

[0019] Alternatively, formation porosity can be determined as follows:

[0020] In the formula, Formation porosity, Density porosity, The neutron porosity is measured on-site during drilling; among which, , For the density of the stratigraphic framework, For the density of the formation fluid, These are density logging values ​​measured at the drilling site.

[0021] Optionally, the lithology coefficient and the cementation index are obtained in the following manner:

[0022] Select the pure water zone of the target well;

[0023] Plot a cross-plot of the relationship between formation factors and density / porosity in the pure water layer, and fit a power-law equation. ;in, For stratigraphic factors, Lithology coefficients to be determined based on requirements , The bonding index is determined based on demand. .

[0024] Optionally, the nuclear magnetic resonance logging porosity calculation model is as follows:

[0025] In the formula, This is the calculated porosity value based on nuclear magnetic resonance (NMR). Water saturation To explain the free gas saturation in the reservoir, The polarization factor of the gas. , These are the hydrogen content indices of formation water and free gas, respectively. This refers to the porosity of the formation.

[0026] Optionally, the hydrogen index of formation water is set to 1, the hydrogen index of free gas is set to 0.356, and the polarization factor of the gas is set to 0.865.

[0027] Optionally, based on the calculated NMR porosity value and the measured NMR porosity value, an identification map of the reservoir to be explained is constructed to identify whether the reservoir contains natural gas hydrates, including:

[0028] A cross-plot comparing the calculated NMR porosity with the measured NMR porosity is plotted, with the calculated NMR porosity on the ordinate and the measured NMR porosity on the abscissa.

[0029] The distribution of all calculated and measured NMR porosity values ​​of the reservoir to be explained in the cross-plot is statistically analyzed. The 45° diagonal of the cross-plot coordinate system is used as the dividing line, and the percentage of data points falling below the dividing line is calculated.

[0030] When the percentage meets the preset percentage, the reservoir to be explained is determined to be a layer where natural gas hydrates and free gas coexist.

[0031] According to another aspect of the present invention, a device for identifying the coexistence of natural gas hydrates and free gas is provided, comprising:

[0032] The acquisition module is used to acquire the measured values ​​of formation resistivity and nuclear magnetic resonance porosity of the reservoir to be interpreted in the target well.

[0033] A water saturation calculation module is used to calculate the water saturation of the reservoir to be interpreted based on the measured value of the formation resistivity and the pre-calculated formation water resistivity, formation porosity, lithology coefficient and preset saturation index.

[0034] The nuclear magnetic resonance porosity calculation module is used to perform forward modeling calculation of the nuclear magnetic resonance porosity of the reservoir under pure gas layer state based on the nuclear magnetic resonance logging porosity calculation model, taking the reservoir to be explained as a pure gas layer as an assumption, substituting the water saturation, and calculating the nuclear magnetic resonance porosity of the reservoir to be explained under pure gas layer state.

[0035] A construction module is used to construct an identification map of the reservoir to be interpreted based on the calculated NMR porosity value and the measured NMR porosity value, so as to identify whether the reservoir to be interpreted contains natural gas hydrates.

[0036] According to another aspect of the present invention, an electronic device is provided, the electronic device comprising:

[0037] At least one processor; and

[0038] A memory communicatively connected to the at least one processor; wherein,

[0039] The memory stores a computer program that can be executed by the at least one processor, which enables the at least one processor to perform the method for identifying the coexistence of natural gas hydrates and free gas as described in any embodiment of the present invention.

[0040] This invention accurately identifies hydrate and free gas coexisting zones based on field measurement data, without requiring expensive core data or lacking shear wave data. It provides important technical support for hydrate resource evaluation and the determination of hydrate trial production "sweet spots." It avoids instrument calibration errors and subjective human judgment errors caused by fixed-scale cross-plots in existing technologies, improving the accuracy and universality of the identification results. It eliminates the need for costly deep-sea drilling and coring in existing technologies, as well as the need for shear wave logging data that cannot be measured in some wells, significantly reducing identification costs and application barriers.

[0041] It should be understood that the description in this section is not intended to identify key or essential features of the embodiments of the present invention, nor is it intended to limit the scope of the invention. Other features of the invention will become readily apparent from the following description. Attached Figure Description

[0042] To more clearly illustrate the technical solutions in the embodiments of the present invention, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0043] Figure 1 A flowchart illustrating a method for identifying the coexistence of natural gas hydrates and free gas, provided in an embodiment of the present invention;

[0044] Figure 2 Provided for embodiments of the present invention Solution resistivity chart;

[0045] Figure 3 A partial log chart of well logging curves for well QDN-B;

[0046] Figure 4 Here is the formation water resistivity curve for well QDN-B;

[0047] Figure 5 A cross-sectional diagram of formation factors and density / porosity in the pure water section of the QDN-B well provided in an embodiment of the present invention;

[0048] Figure 6 A comparison of calculated and measured NMR porosity when the reservoir (138-141 mbsf) to be interpreted in well QDN-B is forward modeled as a pure gas layer;

[0049] Figure 7 To verify the judgment results using shear wave data;

[0050] Figure 8 A schematic diagram of the structure of a device for identifying the coexistence of natural gas hydrates and free gas provided in an embodiment of the present invention;

[0051] Figure 9 This is a schematic diagram of an electronic device for identifying the coexistence of natural gas hydrates and free gas, as provided in an embodiment of the present invention. Detailed Implementation

[0052] To enable those skilled in the art to better understand the present invention, the technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of the present invention.

[0053] It should be noted that the terms "first," "second," etc., in the specification, claims, and accompanying drawings of this invention are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of the invention described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover a non-exclusive inclusion; for example, a process, method, system, product, or apparatus that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or apparatus.

[0054] Figure 1 This is a flowchart illustrating a method for identifying the coexistence of natural gas hydrates and free gas, provided in an embodiment of the present invention. This embodiment is applicable to the accurate identification of the coexistence of natural gas hydrates and free gas. The method can be executed by a device for identifying the coexistence of natural gas hydrates and free gas. This device can be implemented in hardware and / or software and can be configured in any electronic device with communication capabilities. See also... Figure 1 The method includes:

[0055] S110. Obtain the measured values ​​of formation resistivity and nuclear magnetic resonance porosity of the reservoir to be interpreted in the target well.

[0056] Specifically, the formation resistivity of the target well's reservoir to be interpreted is directly measured downhole using resistivity logging instruments, and the nuclear magnetic resonance porosity of the target well's reservoir to be interpreted is directly measured downhole using nuclear magnetic resonance logging instruments.

[0057] Formation water is a conductive medium in the formation, while solid hydrates and gaseous free gas are non-conductive. The higher the hydrate / free gas content in the reservoir, the higher the measured formation resistivity. This parameter is the core parameter for calculating formation water saturation. The response signal of nuclear magnetic resonance logging comes only from the hydrogen nuclei of the fluids (formation water and free gas) in the formation pores. The hydrogen nuclei in solid hydrates cannot be identified by nuclear magnetic resonance logging. Therefore, this measured value only reflects the pore space occupied by the flowable fluid in the reservoir and does not include the pore volume occupied by solid hydrates. This parameter is the core reference for identifying the presence of hydrates in this invention. The theoretical nuclear magnetic porosity of a "pure gas layer without hydrates" will be calculated in forward modeling and compared with this measured value to finally complete the identification of the coexisting layer.

[0058] By using raw downhole measurement data, the instrument calibration error and human subjective judgment error caused by fixed-scale cross-plots in existing technologies are avoided, which improves the accuracy and universality of the identification results. It eliminates the need for the extremely costly deep-sea drilling coring in existing technologies, as well as the need for shear wave logging data that cannot be measured in some wells, thus significantly reducing the identification cost and application threshold.

[0059] S120. Calculate the water saturation of the reservoir to be interpreted based on the measured value of formation resistivity and the pre-calculated formation water resistivity, formation porosity, lithology coefficient, and preset saturation index.

[0060] Specifically, the water saturation of the reservoir to be interpreted is calculated using the following formula:

[0061] In the formula, Water saturation To preset the saturation index, The pre-calculated formation water resistivity; Lithology coefficient, The cementation index; This is the measured value of the formation resistivity. This represents the formation porosity. The saturation index is typically taken as 1.9386.

[0062] The method for determining the resistivity of formation water is as follows:

[0063] Given the salinity and geothermal gradient of the formation water, the formula can be used to... The calculation yields the result; where, , All are formation temperatures. For the formation temperature at The resistivity of formation water at that time. Among them, ; For geothermal gradient, For the formation temperature at The corresponding stratigraphic depth point at that time, through By using a solution resistivity chart and combining it with known formation water salinity, the formation temperature can be determined. The corresponding formation water resistivity Formation temperature ; For the formation temperature at The corresponding stratum depth at that time. The solution resistivity chart can be found in [reference needed]. Figure 2 , Figure 2 Provided for embodiments of the present invention The solution resistivity chart shows the formation temperature on the bottom horizontal axis, the solution resistivity on the left vertical axis, and salinity on the right. Blue diagonal lines represent isoconcentration lines. All blue diagonal lines from the upper left to the lower right are isoconcentration lines for fixed salinity, each labeled with a corresponding salinity (ppm) value. Salinity is constant along the same line; higher temperatures result in lower resistivity, and at the same temperature, higher salinity results in lower resistivity. The usage is as follows: First, locate the actual formation temperature of the reservoir to be interpreted on the bottom horizontal axis and draw a straight line vertically upwards from that position. On the right scale, find the corresponding NaCl salinity (ppm) of the formation water and locate the corresponding blue isoconcentration line. Find the intersection of the vertical temperature line and the isoconcentration line. Draw a line horizontally to the left from the intersection to the left vertical axis; the value read is the formation water resistivity at that temperature and salinity. .

[0064] Given the unknown salinity, seabed temperature, and geothermal gradient of the formation water, the resistivity of the formation water is taken as 0.25Ω.

[0065] The method for determining formation porosity is as follows:

[0066] In the formula, Formation porosity, Density porosity, The neutron porosity is measured on-site during drilling; among which, , For the density of the stratigraphic framework, For the density of the formation fluid, These are density logging values ​​measured at the drilling site.

[0067] The lithology coefficient and cementation index are obtained in the following ways:

[0068] Select the pure water zone of the target well;

[0069] Plot a cross-plot of the relationship between formation factors and density / porosity in the pure water layer, and fit a power-law equation. ;in, For the land ; This is the resistivity when the formation is 100% saturated with formation water. This value needs to be obtained through actual measurement and is limited to the measured value of formation resistivity in pure water layers.

[0070] S130. Based on the nuclear magnetic resonance logging porosity calculation model, the reservoir to be explained is assumed to be a pure gas layer. Water saturation is substituted into the model, and the nuclear magnetic resonance porosity of the reservoir to be explained under the pure gas layer condition is calculated by forward modeling.

[0071] Specifically, nuclear magnetic resonance (NMR) logging is based on the resonance response of hydrogen nuclei in formation fluids within a magnetic field, with the signal primarily originating from hydrogen in the pore fluid. Although hydrate molecules contain hydrogen, because hydrates are solids, NMR logging cannot reflect solid hydrates in the pores; it can only reflect formation water and a portion of the free gas. Therefore, regardless of whether the reservoir to be interpreted contains hydrates, based on the traditional volumetric model, the NMR porosity calculation model for the reservoir to be interpreted is as follows:

[0072] In the formula, This is the calculated porosity value based on nuclear magnetic resonance (NMR). Water saturation To explain the free gas saturation in the reservoir, The polarization factor of the gas. , These are the hydrogen content indices of formation water and free gas, respectively. This refers to the porosity of the formation.

[0073] Assuming the reservoir to be explained is a pure gas layer, meaning the formation pores contain no hydrates and only formation water and free gas, then the free gas saturation...

[0074] Among them, the hydrogen content index of formation water, the hydrogen content index of free gas, and the polarization factor of gas can all be preset. Generally, the hydrogen content index of formation water is set to 1, the hydrogen content index of free gas is set to 0.356, and the polarization factor of gas is set to 0.865.

[0075] S140. Based on the calculated and measured NMR porosity values, construct an identification chart of the reservoir to be explained to identify whether the reservoir contains natural gas hydrates.

[0076] Specifically, a cross-plot comparing calculated and measured NMR porosity values ​​is plotted, with the calculated NMR porosity value on the ordinate and the measured NMR porosity value on the abscissa. The distribution of all calculated and measured NMR porosity values ​​of the reservoir to be explained within the cross-plot is statistically analyzed. Using the 45° diagonal of the cross-plot coordinate system as the boundary, the percentage of data points falling below this boundary is calculated. If the percentage meets a preset threshold, the reservoir to be explained is determined to be a region where natural gas hydrates and free gas coexist. Otherwise, it does not contain hydrates.

[0077] The scales of the horizontal and vertical axes must be consistent. Preset percentages can be set according to testing requirements; this invention uses 80% as an example. Data points refer to the calculated and measured NMR porosity values. Total quantity refers to the total number of all calculated and measured NMR porosity values.

[0078] The technical solution provided by this invention involves obtaining measured values ​​of formation resistivity and nuclear magnetic resonance (NMR) porosity of the reservoir to be interpreted in the target well. Based on the measured formation resistivity and pre-calculated formation water resistivity, formation porosity, lithology coefficient, and a preset saturation index, the water saturation of the reservoir to be interpreted is calculated. Using a nuclear magnetic resonance logging porosity calculation model, assuming the reservoir to be interpreted is a pure gas layer, the water saturation is substituted to perform a forward modeling calculation of the NMR porosity of the reservoir under pure gas layer conditions. Based on the calculated and measured NMR porosity values, an identification chart of the reservoir to be interpreted is constructed to identify whether the reservoir contains natural gas hydrates. This invention accurately identifies hydrate and free gas coexisting zones based on field measurement data, without requiring expensive core data or lacking shear wave data. It provides important technical support for hydrate resource evaluation and the determination of hydrate trial production "sweet spots." It avoids instrument calibration errors and subjective human judgment errors caused by fixed-scale cross-plots in existing technologies, improving the accuracy and universality of the identification results. It eliminates the need for costly deep-sea drilling and coring in existing technologies, as well as the need for shear wave logging data that cannot be measured in some wells, significantly reducing identification costs and application barriers.

[0079] The following is a specific embodiment to illustrate the method for identifying the coexistence of natural gas hydrates and free gas provided in this application.

[0080] Take a well drilled in the southeastern sea area of ​​Qiongdong as an example (QDN-B). Figure 3This is a partial log chart of the QDN-B well. Based on the logging response characteristics, it is easy to identify the pure water layer and pure hydrate layer (135-138 mbsf) in the QDN-B well. However, in the depth range of 138-141 mbsf, resistivity increases, density decreases, neutron porosity decreases, and these two phenomena exhibit an "anti-crossing" phenomenon. Combined with the high resistivity, this indicates the presence of natural gas, but it is impossible to determine whether this layer contains hydrates. The following section will determine whether natural gas hydrates and free gas coexist:

[0081] Step 1: Calculate the water saturation at different depths of the reservoir (138-141 mbsf) to be interpreted in well QDN-B:

[0082] Based on the measured formation resistivity of well QDN-B ( Figure 3 The third step in the process involves calculating the water saturation of the reservoir to be interpreted using the following formula:

[0083] ;

[0084] The method for determining formation porosity is as follows:

[0085] In the formula, For formation porosity, see Figure 3 The last black line in the middle, Density porosity, Neutron porosity measured on-site during drilling ( Figure 3 The fourth red line in the text); among them, , The density of the stratigraphic framework is generally taken as... ; The density of the formation fluid is generally taken as... ; Density logging values ​​measured at the drilling site ( Figure 1 The fourth black line in the text), the unit is .

[0086] Formation water resistivity Determination of: QDN-B well formation water salinity 33 ppt, seafloor temperature 3°C, geothermal gradient

[0087] ,according to Solution resistivity chart ( Figure 2 By combining this information with the known formation water salinity, the formation temperature can be determined. The corresponding formation water resistivity Then, according to the formula... The formation water resistivity at different depths in well QDN-B can be calculated. ,See Figure 4 , Figure 4This is a graph showing the formation water resistivity of well QDN-B.

[0088] Lithology coefficient Cementation index Determination: Plot the intersection of formation factors and density / porosity in the pure water section of well QDN-B, and fit a power-law equation. The lithology coefficient can be obtained from the formula. Cementing index See details. Figure 5 , Figure 5 This is a cross-sectional diagram of formation factors and density / porosity in the pure water section of the QDN-B well, provided as an embodiment of the present invention.

[0089] Using the lithology coefficients that have already been obtained Cementation Index Formation water resistivity The water saturation at different depths of the unexplained reservoir (138-141 mbsf) in well QDN-B was calculated using a formula. The calculation results are shown in the third column of Table 1. Table 1 is a comparison table of different fluid saturation and nuclear magnetic porosity of the reservoir (138-141 mbsf) to be interpreted in well QDN-B.

[0090] Table 1

[0091]

[0092] Step 2: Forward modeling calculation of the nuclear magnetic porosity of the reservoir (138-141 mbsf) to be interpreted in well QDN-B as a pure gas layer:

[0093] The reservoir to be explained (138-141 mbsf) is a pure gas layer (i.e., the formation pores contain no hydrates, only formation water and free gas), and the free gas saturation is... ; ( The free gas saturation has been obtained through step one (see the third column of Table 1). See the fourth column of Table 1, using the formula The nuclear magnetic porosity of the reservoir to be explained (138-141 mbsf) can be calculated by forward modeling when it is a pure gas layer, as shown in the fifth column of Table 1.

[0094] Step 3: Create an identification chart to determine whether the reservoir to be interpreted contains hydrates:

[0095] For the reservoir to be explained (138-141 mbsf), calculated NMR porosity was plotted on the ordinate, and measured NMR porosity on the abscissa (last column in Table 1). The scales of both axes were kept consistent (scale range 0.10~0.50). A cross-plot comparing the two different porosities was obtained, and the 45° diagonal of the coordinate system was drawn. See details... Figure 6 , Figure 6 This is a comparison chart of calculated and measured NMR porosity when the reservoir (138-141 mbsf) to be interpreted in well QDN-B is forward-modeled as a pure gas layer. Based on... Figure 6 It is known that there are 20 data points in the reservoir to be interpreted (138-141 mbsf), of which 16 data points are located below the 45° diagonal, i.e., 80% of the data points. Therefore, it can be determined that the gas layer of the reservoir to be interpreted (138-141 mbsf) in well QDN-B contains hydrates.

[0096] Figure 7 To verify the judgment results using shear wave data. See [link / reference]. Figure 7 To verify the accuracy of the above judgment, field-measured shear wave velocity data were used. Shear wave velocity is unaffected by free gas; the measured shear wave velocity in this section (average 864 m / s) is significantly higher than the shear wave logging value of the underlying mudstone water layer (414 m / s). Figure 7 The final step (which proved that the high shear wave velocity in this section was due to the presence of hydrates) confirmed that the reservoir section to be explained contained hydrates, thus verifying the accuracy of the above judgment.

[0097] The technical solution provided by this invention accurately identifies hydrate and free gas coexisting zones based on field measurement data, without requiring expensive core data or lacking shear wave data. This provides important technical support for hydrate resource evaluation and the determination of hydrate trial production "sweet spots," avoiding instrument calibration errors and subjective human judgment errors caused by fixed-scale cross-plots in existing technologies. It improves the accuracy and universality of the identification results, eliminates the need for costly deep-sea drilling and coring in existing technologies, and eliminates the need for shear wave logging data that cannot be measured in some wells, significantly reducing identification costs and application thresholds.

[0098] Figure 8 This is a schematic diagram of a device for identifying the coexistence of natural gas hydrates and free gas, provided in an embodiment of the present invention. (See attached diagram.) Figure 8 The device includes an acquisition module 810, a water saturation calculation module 820, a nuclear magnetic resonance porosity calculation module 830, and a construction module 840.

[0099] The acquisition module 810 is used to acquire the measured values ​​of formation resistivity and nuclear magnetic resonance porosity of the reservoir to be interpreted in the target well.

[0100] The water saturation calculation module 820 is used to calculate the water saturation of the reservoir to be interpreted based on the measured value of formation resistivity and the pre-calculated formation water resistivity, formation porosity, lithology coefficient and preset saturation index.

[0101] The nuclear magnetic resonance porosity calculation module 830 is used to calculate the nuclear magnetic resonance porosity of the reservoir under pure gas layer conditions based on the nuclear magnetic resonance logging porosity calculation model. It assumes that the reservoir to be explained is a pure gas layer and substitutes the water saturation to perform forward modeling.

[0102] The construction module 840 is used to construct an identification map of the reservoir to be interpreted based on the calculated and measured NMR porosity values, so as to identify whether the reservoir contains natural gas hydrates.

[0103] The identification device for the coexistence of natural gas hydrate and free gas provided in the embodiments of the present invention can execute the identification method for the coexistence of natural gas hydrate and free gas provided in any embodiment of the present invention, and has the corresponding functional modules and beneficial effects of the method.

[0104] Figure 9 This is a schematic diagram of an electronic device used in an embodiment of the present invention to identify the coexistence of natural gas hydrates and free gas. The electronic device is intended to represent various forms of digital computers, such as laptops, desktop computers, workstations, personal digital assistants, servers, blade servers, mainframes, and other suitable computers. The electronic device can also represent various forms of mobile devices, such as personal digital processors, cellular phones, smartphones, wearable devices (e.g., helmets, glasses, watches), and other similar computing devices. The components shown herein, their connections and relationships, and their functions are merely illustrative and are not intended to limit the implementation of the invention described and / or claimed herein.

[0105] like Figure 9 As shown, the electronic device 10 includes at least one processor 11 and a memory, such as a read-only memory (ROM) 12 and a random access memory (RAM) 13, communicatively connected to the at least one processor 11. The memory stores computer programs executable by the at least one processor. The processor 11 can perform various appropriate actions and processes based on the computer program stored in the ROM 12 or loaded into the RAM 13 from storage unit 18. The RAM 13 can also store various programs and data required for the operation of the electronic device 10. The processor 11, the ROM 12, and the RAM 13 are interconnected via a bus 14. An input / output (I / O) interface 15 is also connected to the bus 14.

[0106] Multiple components in electronic device 10 are connected to input / output I / O interface 15, including: input unit 16, such as keyboard, mouse, etc.; output unit 17, such as various types of monitors, speakers, etc.; storage unit 18, such as disk, optical disk, etc.; and communication unit 19, such as network card, modem, wireless transceiver, etc. Communication unit 19 allows electronic device 10 to exchange information / data with other devices through computer networks such as the Internet and / or various telecommunications networks.

[0107] Processor 11 can be a variety of general-purpose and / or special-purpose processing components with processing and computing capabilities. Some examples of processor 11 include, but are not limited to, central processing unit (CPU), graphics processing unit (GPU), various special-purpose artificial intelligence (AI) computing chips, various processors running machine learning model algorithms, digital signal processors (DSPs), and any suitable processor, controller, microcontroller, etc. Processor 11 performs the various methods and processes described above, such as a method for identifying the coexistence of natural gas hydrates and free gas.

[0108] In some embodiments, the method for identifying the coexistence of natural gas hydrates and free gas can be implemented as a computer program tangibly contained in a computer-readable storage medium, such as storage unit 18. In some embodiments, part or all of the computer program can be loaded and / or installed on electronic device 10 via read-only memory ROM 12 and / or communication unit 19. When the computer program is loaded into random access memory RAM 13 and executed by processor 11, one or more steps of the method for identifying the coexistence of natural gas hydrates and free gas described above can be performed. Alternatively, in other embodiments, processor 11 can be configured in any other suitable manner to perform the method for identifying the coexistence of natural gas hydrates and free gas.

[0109] Various embodiments of the systems and techniques described above herein can be implemented in digital electronic circuit systems, integrated circuit systems, field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), application-specific standard products (ASSPs), systems-on-a-chip (SoCs), payload-programmable logic devices (CPLDs), computer hardware, firmware, software, and / or combinations thereof. These various embodiments may include implementations in one or more computer programs that can be executed and / or interpreted on a programmable system including at least one programmable processor, which may be a dedicated or general-purpose programmable processor, capable of receiving data and instructions from a storage system, at least one input device, and at least one output device, and transferring data and instructions to the storage system, the at least one input device, and the at least one output device.

[0110] Computer programs used to implement the methods of the present invention may be written in any combination of one or more programming languages. These computer programs may be provided to a processor of a general-purpose computer, a special-purpose computer, or other programmable data processing device, such that when executed by the processor, the computer programs cause the functions / operations specified in the flowcharts and / or block diagrams to be performed. The computer programs may be executed entirely on a machine, partially on a machine, or as a standalone software package, partially on a machine and partially on a remote machine, or entirely on a remote machine or server.

[0111] In the context of this invention, a computer-readable storage medium can be a tangible medium that may contain or store a computer program for use by or in conjunction with an instruction execution system, apparatus, or device. A computer-readable storage medium may include, but is not limited to, electronic, magnetic, optical, electromagnetic, infrared semiconductor systems, apparatus, or devices, or any suitable combination of the foregoing. Alternatively, a computer-readable storage medium may be a machine-readable signal medium. More specific examples of machine-readable storage media include electrical connections based on one or more wires, portable computer disks, hard disks, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), optical fibers, portable compact disk read-only memory (CD-ROM), optical storage devices, magnetic storage devices, or any suitable combination of the foregoing.

[0112] To provide interaction with a user, the systems and techniques described herein can be implemented on an electronic device having: a display device for displaying information to a user; and a keyboard and pointing device through which the user provides input to the electronic device. Other types of devices can also be used to provide interaction with a user; for example, feedback provided to the user can be any form of sensory feedback; and input from the user can be received in any form.

[0113] The systems and technologies described herein can be implemented in computing systems that include backend components, middleware components, or frontend components (e.g., a user computer with a graphical user interface or web browser through which a user can interact with implementations of the systems and technologies described herein), or any combination of such backend, middleware, or frontend components. The components of the system can be interconnected via digital data communication of any form or medium. Examples of communication networks include local area networks (LANs), wide area networks (WANs), blockchain networks, and the Internet.

[0114] A computing system can include clients and servers. Clients and servers are generally located far apart and typically interact through communication networks. The client-server relationship is created by computer programs running on the respective computers and having a client-server relationship with each other. The server can be a cloud server, also known as a cloud computing server or cloud host, which is a hosting product within the cloud computing service system to address the shortcomings of traditional physical hosts and VPS services, such as high management difficulty and weak business scalability.

[0115] It should be understood that the various forms of processes shown above can be used, with steps reordered, added, or deleted. For example, the steps described in this invention can be executed in parallel, sequentially, or in different orders, as long as the desired result of the technical solution of this invention can be achieved, and this is not limited herein.

[0116] The specific embodiments described above do not constitute a limitation on the scope of protection of this invention. Those skilled in the art should understand that various modifications, combinations, sub-combinations, and substitutions can be made according to design requirements and other factors. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of this invention should be included within the scope of protection of this invention.

Claims

1. A method for identifying the coexistence of natural gas hydrates and free gas, characterized in that, include: Obtain measured values ​​of formation resistivity and nuclear magnetic resonance porosity of the reservoir to be interpreted in the target well; The water saturation of the reservoir to be interpreted is calculated based on the measured value of the formation resistivity and the pre-calculated formation water resistivity, formation porosity, lithology coefficient and preset saturation index. Based on the nuclear magnetic resonance logging porosity calculation model, taking the reservoir to be explained as a pure gas layer as an assumption, and substituting the water saturation, the nuclear magnetic porosity calculation value of the reservoir to be explained under the pure gas layer state is calculated by forward modeling. Based on the calculated NMR porosity and the measured NMR porosity, an identification chart of the reservoir to be explained is constructed to identify whether the reservoir contains natural gas hydrates.

2. The method according to claim 1, characterized in that, Based on the measured formation resistivity and pre-calculated formation water resistivity, formation porosity, lithology coefficient, and preset saturation index, the water saturation of the reservoir to be interpreted is calculated as follows: The water saturation of the reservoir to be interpreted is calculated using the following formula: In the formula, Water saturation To preset the saturation index, The pre-calculated formation water resistivity; Lithology coefficient, The cementation index; This is the measured value of the formation resistivity. This refers to the porosity of the formation.

3. The method according to claim 2, characterized in that, The method for determining the resistivity of the formation water is as follows: Given the salinity and geothermal gradient of the formation water, the formula can be used to... The calculation yields the result; where, , All are formation temperatures. For the formation temperature at The resistivity of formation water at that time; Given the unknown salinity, seabed temperature, and geothermal gradient of the formation water, the resistivity of the formation water is taken as 0.25Ω.

4. The method according to claim 2, characterized in that, The method for determining formation porosity is as follows: In the formula, Formation porosity, Density porosity, The neutron porosity is measured on-site during drilling; among which, , For the density of the stratigraphic framework, For the density of the formation fluid, These are density logging values ​​measured at the drilling site.

5. The method according to claim 2, characterized in that, The lithology coefficient and the cementation index are obtained in the following manner: Select the pure water zone of the target well; Plot a cross-plot of the relationship between formation factors and density / porosity in the pure water layer, and fit a power-law equation. ;in, For stratigraphic factors, Lithology coefficients to be determined based on requirements , The bonding index is determined based on demand. .

6. The method according to claim 1, characterized in that, The nuclear magnetic resonance logging porosity calculation model is as follows: In the formula, This is the calculated porosity value based on nuclear magnetic resonance (NMR). Water saturation To explain the free gas saturation in the reservoir, The polarization factor of the gas. , These are the hydrogen content indices of formation water and free gas, respectively. This refers to the porosity of the formation.

7. The method according to claim 5, characterized in that, The hydrogen index of formation water is set to 1, the hydrogen index of free gas is set to 0.356, and the polarization factor of the gas is set to 0.

865.

8. The method according to claim 1, characterized in that, Based on the calculated NMR porosity value and the measured NMR porosity value, an identification chart of the reservoir to be explained is constructed to identify whether the reservoir contains natural gas hydrates, including: A cross-plot comparing the calculated NMR porosity with the measured NMR porosity is plotted, with the calculated NMR porosity on the ordinate and the measured NMR porosity on the abscissa. The distribution of all calculated and measured NMR porosity values ​​of the reservoir to be explained in the cross-plot is statistically analyzed. The 45° diagonal of the cross-plot coordinate system is used as the dividing line, and the percentage of data points falling below the dividing line is calculated. When the percentage meets the preset percentage, the reservoir to be explained is determined to be a layer where natural gas hydrates and free gas coexist.

9. A device for identifying the coexistence of natural gas hydrates and free gas, characterized in that, include: The acquisition module is used to acquire the measured values ​​of formation resistivity and nuclear magnetic resonance porosity of the reservoir to be interpreted in the target well. A water saturation calculation module is used to calculate the water saturation of the reservoir to be interpreted based on the measured value of the formation resistivity and the pre-calculated formation water resistivity, formation porosity, lithology coefficient and preset saturation index. The nuclear magnetic resonance porosity calculation module is used to perform forward modeling calculation of the nuclear magnetic resonance porosity of the reservoir under pure gas layer state based on the nuclear magnetic resonance logging porosity calculation model, taking the reservoir to be explained as a pure gas layer as an assumption, substituting the water saturation, and calculating the nuclear magnetic resonance porosity of the reservoir to be explained under pure gas layer state. A construction module is used to construct an identification map of the reservoir to be interpreted based on the calculated NMR porosity value and the measured NMR porosity value, so as to identify whether the reservoir to be interpreted contains natural gas hydrates.

10. An electronic device, characterized in that, The electronic device includes: At least one processor; and A memory communicatively connected to the at least one processor; wherein, The memory stores a computer program that can be executed by the at least one processor, the computer program being executed by the at least one processor to enable the at least one processor to perform the identification method for the coexistence of natural gas hydrate and free gas as described in any one of claims 1-8.

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