A method and device for quantitatively evaluating the saturation of a hydrate mixed layer

Abstract

The present invention discloses a method and device for quantitatively evaluating the saturation of a hydrate mixed layer. The method comprises: obtaining the formation parameters of the mixed layer to obtain the gas layer density ρ of the mixed layer. g ; According to the mixed layer gas layer density ρ g To obtain the hydrogen index HI of the gas in the mixed layer g ; Analyze the natural gamma GR and total porosity of the pure water layer to obtain the total porosity φ of the mixed layer; Establish a rock physics model of the mixed layer to obtain the saturation of hydrates, free gas and formation water in the mixed layer. The present invention accurately determines the rock mineral components based on element capture spectrum logging and conventional logging. On this basis, an interpretation model of nuclear magnetic resonance logging and density logging is jointly established, and hydrates and formation water are separated when establishing the density model. There are fewer unknown parameters involved, and the three-phase saturation of hydrates, free gas and water in the mixed layer is accurately and continuously evaluated, providing accurate reservoir parameters for hydrate resource evaluation.

Description

Technical Field

[0001] The present invention relates to the technical field of measurement and evaluation, and particularly relates to a method and device for quantitatively evaluating the saturation of a hydrate mixed layer. Background Art

[0002] Natural gas hydrate is a high-efficiency clean energy source with abundant resources. Research shows that multiple regions of the mixed layer coexisting with hydrate, free gas and water in the gas hydrate stability zone have been confirmed. The coexistence of the three phases has been confirmed in two hydrate production tests in the Shenhu Sea Area of the South China Sea. However, the key problem is how to accurately evaluate the saturation of hydrate, gaseous hydrocarbon and water to provide a basis for the development of hydrate deposits.

[0003] Currently, the methods for quantitatively evaluating the three-phase saturation of the mixed layer include core analysis method, acoustic logging method, and combination of nuclear magnetic resonance and density.

[0004] For the core analysis method, by collecting the total amount of released gas from the pressure-retained core and combining with the desalination of pore water, the three-phase saturation can be calculated. However, the disadvantages of this method are as follows: First, the cost of obtaining cores in the deep sea is high, and the obtained data is discrete, so continuous results of the mixed layer cannot be obtained. Second, it is difficult to maintain the pressure of the core, and it is difficult to determine the salinity of formation water and the gas concentration in the in-situ state.

[0005] For the acoustic logging method, the disadvantages are as follows: First, due to the presence of gas in the mixed layer, the extracted longitudinal and transverse wave velocities are inaccurate, affecting the calculation results. Second, the rock physics model used in this method mainly depends on the microscopic occurrence state of hydrate in the mixed layer, which needs to be obtained by other means such as core CT scanning, and the uncertainty is relatively high. Third, there are multiple unknowns in the formula, and default values are often used, while different regions and different sediments have different values, resulting in large errors in the calculation results.

[0006] For the conventional combination of nuclear magnetic resonance and density, the main problems existing in this method are as follows: First, when establishing the density model, it is considered that the density value of the rock skeleton is a fixed value, but in fact, the rock skeleton density is affected by different mineral components. Second, it is considered that the density of hydrate and formation water is close, which simplifies the model and leads to large errors in the calculation results.

[0007] Patent document CN112946783A discloses a method, apparatus and equipment for determining hydrate saturation. The method includes: obtaining logging data and rock component mineral parameters of a target reservoir; calculating the dry rock frame parameters of the target reservoir according to the rock component mineral parameters; calculating the estimated P-wave velocity corresponding to at least two groups of candidate model parameters by using the dry rock frame parameters; selecting the applied model parameters from the candidate model parameters based on the comparison result between the estimated P-wave velocity and the measured P-wave velocity; calculating the estimated P-wave inverse quality factor corresponding to at least two candidate hydrate saturations by combining the applied model parameters, the P-wave inverse quality factor and the dry rock frame parameters; and determining the target hydrate saturation from the candidate hydrate saturations according to the comparison result between the estimated P-wave inverse quality factor and the measured P-wave inverse quality factor. However, this method can only calculate the hydrate saturation in the reservoir and cannot obtain the saturation of free gas in the reservoir. Summary of the Invention

[0008] To solve at least one of the technical problems existing in the above background art, the present invention provides a method and apparatus for quantitatively evaluating the saturation of a hydrate mixed layer.

[0009] To achieve the above object, the technical solution of the present invention is:

[0010] In a first aspect, the present invention provides a method for quantitatively evaluating the saturation of a hydrate mixed layer, including:

[0011] Obtaining formation parameters of the mixed layer section to obtain the density ρ of the gas layer in the mixed layer g ;

[0012] According to the density ρ of the gas layer in the mixed layer g to obtain the hydrogen index HI of the gas in the mixed layer section g ;

[0013] Analyzing the natural gamma ray GR and the total porosity of the pure water layer section to obtain the total porosity φ of the formation in the mixed layer section;

[0014] Establishing a rock physics model for the mixed layer section to obtain the saturations of hydrate, free gas and formation water in the mixed layer section.

[0015] In a second aspect, the present invention provides an apparatus for quantitatively evaluating the saturation of a hydrate mixed layer, including:

[0016] An input module for inputting formation parameters of the mixed layer section to obtain the density ρ of the gas layer in the mixed layer g ;

[0017] A search module for searching and obtaining the hydrogen index HI of the gas in the mixed layer section according to the density ρ of the gas layer in the mixed layer g ; g ;

[0018] An analysis module for analyzing the natural gamma ray GR and total porosity of the pure water layer section to obtain the total porosity φ of the formation in the mixed layer section;

[0019] A model module for establishing a petrophysical model of the mixed layer section to obtain the saturations of hydrate, free gas, and formation water in the mixed layer section.

[0020] Furthermore, the formation parameters of the mixed layer section include the formation pressure P and formation temperature T of the mixed layer section;

[0021]

[0022] where M g is the apparent molecular weight of CH4 and Z is the compressibility factor.

[0023] Furthermore, the total porosity φ of the formation in the mixed layer section is:

[0024] φ = -0.00276 * GR + 0.6259.

[0025] Furthermore, the petrophysical model of the mixed layer section is established in the following manner:

[0026] The sediment consists of two parts: the rock skeleton and the pores; the pores contain three-phase fluids of hydrate, free gas, and water;

[0027] For the sediment skeleton part, first, according to the quantitative X-ray analysis of the core, determine the main mineral types of the skeleton in the mixed layer section; since the core data is discrete, combine the elemental capture spectroscopy logging to obtain the continuous mineral components of the formation and perform core calibration, assuming that the content of each mineral obtained is V i ;

[0028] For the fluid part in the pores, assume that the pore volumes occupied by hydrate, free gas, and water in the mixed layer section are φ gh , φ g , φ w , and the saturations are S gh , S g , S w ; due to the presence of gas in the mixed layer section, the nuclear magnetic porosity measures the pore volume occupied by all formation water and part of the free gas; therefore, the petrophysical model of the formation includes:

[0029] is the polarization factor of the gas under formation conditions; φ nmr is the nuclear magnetic porosity; 1 - φ represents the volume occupied by the rock skeleton, φS gh represents the volume occupied by hydrate, φS g represents the volume occupied by gas, φS wrepresents the volume occupied by water, and the sum of these four is equal to 1; φ nmr represents the volume that can measure the volume of water and the volume occupied by part of the gas, 1 - φ nmr represents the volume not detected by nuclear magnetic resonance logging; W is the waiting time of the gas layer pulse sequence; T1 is the transverse relaxation time of the gas under formation conditions; HI w is the hydrogen index of water.

[0030] Furthermore, according to the petrophysical model, the following formula is listed:

[0031]

[0032] In the above formula, ρ, ρ i , ρ gh , ρ g , ρ w are the densities of formation measurement, the i-th mineral, hydrate, free gas, and formation water respectively, which are known numbers; φ nmr is the nuclear magnetic porosity measured by nuclear magnetic resonance in the mixed layer;

[0033] Therefore, by combining the above formulas, the pore volumes of free gas and formation water in the mixed layer section, φ g , φ w ; can be obtained respectively. Then, the pore volume φ gh occupied by hydrate = φ - φ g - φ w

[0034] According to the definition of saturation, the saturations of hydrate, free gas, and formation water in the mixed layer section are respectively:

[0035]

[0036]

[0037]

[0038] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0039] Based on the elemental capture spectroscopy logging and conventional logging, the present invention accurately determines the rock mineral components. On this basis, an interpretation model of nuclear magnetic resonance logging and density logging is jointly established, and the hydrate and formation water are separated when establishing the density model. There are fewer unknown parameters involved, and the saturations of hydrate, free gas, and water in the mixed layer section are accurately and continuously evaluated, providing accurate reservoir parameters for the evaluation of hydrate resources. BRIEF DESCRIPTION OF THE DRAWINGS

[0040] Figure 1 is a flowchart of the method for quantitatively evaluating the saturation of the hydrate mixed layer provided by the embodiment of the present invention;

[0041] Figure 2 is the relationship chart of density and hydrogen index;

[0042] Figure 3 is the petrophysical model diagram

[0043] Figure 4 is the relationship chart of transverse relaxation time and temperature-pressure of gas layer;

[0044] Figure 5 is the overall principle flow chart of the quantitative evaluation method for hydrate mixed layer saturation provided by the embodiment of the present invention;

[0045] Figure 6 is the comparison chart of hydrate mixed layer saturation calculated before and after NMR-density optimization of Well SH-W09-2019;

[0046] Figure 7 is the composition schematic diagram of the device for quantitatively evaluating the hydrate mixed layer saturation provided by the embodiment of the present invention. Detailed implementation manners

[0047] The technical solutions of the present invention will be further described below with reference to the accompanying drawings and embodiments.

[0048] Embodiment 1:

[0049] Refer to Figure 1 As shown, the quantitative evaluation method for hydrate mixed layer saturation provided in this embodiment mainly includes the following steps:

[0050] 101. Obtain the formation parameters of the mixed layer section to calculate the density ρ of the gas layer in the mixed layer g ;

[0051] Specifically, the density of natural gas is defined as the mass of gas per unit volume. The density of underground natural gas needs to consider the volume under the temperature and pressure conditions of the gas layer and can be derived from the state equation:

[0052]

[0053] Among them, P is the formation pressure of the mixed layer section, M g is the apparent molecular weight of CH4, Z is the compressibility factor (obtained by referring to the nomogram), and T is the formation temperature of the mixed layer section.

[0054] 102. Obtain the hydrogen index HI of the gas in the mixed layer section according to the density ρ of the gas layer in the mixed layer g ; g ;

[0055] Specifically, the hydrogen index means that the hydrogen content of fresh water is defined as one unit, and 1 cm 3The hydrogen index in any rock or mineral is defined as the ratio of its hydrogen index to that of fresh water of the same volume. From Step 101, the gas density in the mixed layer section can be obtained, and according to Figure 2 the corresponding hydrogen index can be found out.

[0056] 103. Analyze the natural gamma ray GR and total porosity of the pure water layer section to obtain the total porosity φ of the formation in the mixed layer section;

[0057] Specifically, the total porosity refers to the ratio of the pore volume in the rock to the rock volume. At present, the formation porosity can be calculated using acoustic travel time, density, and neutron in conventional logging curves. When there is gas in the formation, the measured density logging is on the low side, resulting in an overestimated calculated porosity. The acoustic travel time will show periodic jumps due to the presence of the gas layer, leading to deviations in the calculation results; while the neutron logging shows a lower porosity due to the "excavation effect" of the gas layer. By analyzing the natural gamma ray (GR) and total porosity of the pure water layer section (where there is neither hydrate nor gas in the pores), it is found that the formation porosity gradually decreases as the natural gamma ray increases, and there is a good linear correlation between the two, with the correlation coefficient r reaching 0.85. The regression formula is as follows:

[0058] φ = -0.00276 * GR + 0.6259

[0059] Therefore, the total porosity of the formation in the mixed layer section can be calculated using the above formula, effectively avoiding the influence of the gas layer.

[0060] 104. Establish a petrophysical model for the mixed layer section to obtain the saturations of hydrate, free gas, and formation water in the mixed layer section.

[0061] Specifically, the sediment consists of two parts: the rock skeleton and the pores. The pores contain three-phase fluids: hydrate, free gas, and water;

[0062] For the sediment skeleton part, first, determine the main mineral types of the skeleton in the mixed layer section according to the quantitative analysis of core X-ray. Since the core data is discrete, it is necessary to combine the elemental capture spectroscopy logging to obtain the continuous mineral components of the formation and perform core calibration. Assume that the content of each mineral obtained is V i ;

[0063] For the fluid part in the pores, assume that the pore volumes occupied by hydrate, free gas, and water in the mixed layer section are φ gh , φ g , φ w , and the saturations are S gh , S g , S w . Due to the presence of gas in the mixed layer section, the nuclear magnetic porosity measures the pore volume occupied by all formation water and part of the free gas. Therefore, the petrophysical model of the formation is as Figure 3as shown

[0064] In Figure 3 , is the polarization factor of gas under formation conditions; φ nmr is the nuclear magnetic porosity; 1 - φ on the far left represents the volume occupied by the rock skeleton, φS gh represents the volume occupied by hydrate, φS g represents the volume occupied by gas, φS w represents the volume occupied by water, and the sum of these four is equal to 1. φ nmr represents the volume of water that can be measured and the volume of part of the gas occupied, that is, to the right of the dashed line, while to the left of the dashed line (1 - φ nmr ) represents the volume not detected by nuclear magnetic resonance logging. W is the waiting time of the gas layer pulse sequence, generally taking a value of 8 s, T1 is the transverse relaxation time of gas under formation conditions, and can be queried through Figure 4 HI w is the hydrogen index of water, generally taking a value of 1.

[0065] According to the above petrophysical model, the following formula can be listed:

[0066]

[0067] The above formula is the interpretation model of nuclear magnetic resonance logging and density logging. In the formula, ρ, ρ i , ρ gh , ρ g , ρ w are the densities of formation measurement, the i-th mineral, hydrate, free gas, and formation water respectively, which are known numbers. The formation porosity φ, V i have been obtained according to steps 103 and 104 respectively. φ nmr is the nuclear magnetic porosity of the mixed layer measurement; P g , HI g have been obtained according to steps 104 and 102 respectively. Therefore, by combining the above formulas, the pore volumes of free gas and formation water in the mixed layer section, φ g , φ w can be obtained respectively. Then, the pore volume φ gh occupied by hydrate = φ - φ g - φ w

[0068] According to the definition of saturation, the saturations of hydrate, free gas, and formation water in the mixed layer section are respectively:

[0069]

[0070]

[0071]

[0072] like Figure 5 As shown, this is the overall principle flow chart of the method. The present invention deeply mines unconventional logging information, accurately determines the formation porosity, avoids the influence of gas layers, optimizes the nuclear magnetic resonance-density model, and accurately evaluates the three-phase saturation of hydrate, free gas and water in the marine natural gas hydrate mixed layer, providing accurate reservoir parameters for hydrate production capacity simulation and resource evaluation.

[0073] It can be seen that the present invention is based on element capture spectrum logging (that is, since the core data is discrete, the continuous mineral composition of the formation is obtained by combining element capture spectrum logging and corrected by the core, assuming that the content of each mineral is V i ) and conventional logging to accurately determine the rock mineral composition. On this basis, the interpretation model of nuclear magnetic resonance logging and density logging was jointly established, and the hydrate and formation water were separated in the density model. There were fewer unknown parameters involved, and the three-phase saturation of hydrate, free gas and water in the mixed layer was accurately and continuously evaluated, providing accurate reservoir parameters for hydrate resource evaluation.

[0074] The following is a verification example to further verify this method:

[0075] Take a well drilled in Shenhu Sea Area in 2019 as an example (SH-W09-2019), Figure 6 The first channel is the depth channel, the second channel is the gamma and wellbore curves, the third channel is different resistivity, the fourth and fifth channels are the saturations of hydrate, gas and water in the mixed layer calculated by the conventional NMR-density model and the optimized NMR-density model (i.e., the rock physics model of the mixed layer established in step 104 of the method), respectively, and the sixth channel is the measured formation temperature.

[0076] By comparing the two methods, it can be seen that the bottom depth of the mixed layer determined before and after the optimization of the NMR-density model is about 279 mbsf and 260 mbsf respectively. According to the measured formation temperature, the abnormal temperature point of the geothermal gradient line that is significantly lower than the formation ends at 260 mbsf, and the abnormal temperature is caused by the presence of hydrates. Therefore, according to the above analysis, the optimized NMR-density model (i.e., the rock physics model of the mixed layer established in step 104 of this method) is more consistent with the measured temperature data.

[0077] Embodiment 2:

[0078] See also Figure 7 As shown, this embodiment provides a hydrate mixed layer saturation quantitative evaluation device which mainly includes:

[0079] Input module, used to input the formation parameters of the mixed layer to obtain the gas density ρ of the mixed layerg ;

[0080] A searching module, configured to search for and obtain the hydrogen index HI of the gas in the mixed layer section according to the density ρ of the gas layer in the mixed layer g ; g ;

[0081] An analysis module, configured to analyze the natural gamma ray GR and the total porosity in the pure water layer section to obtain the total porosity φ of the formation in the mixed layer section;

[0082] A model module, configured to establish a petrophysical model for the mixed layer section to obtain the saturations of hydrates, free gas, and formation water in the mixed layer section.

[0083] Since the specific working principles of the input module, the searching module, the analysis module, and the model module respectively correspond to steps 101-104 in Embodiment 1 one by one, they will not be elaborated herein in this embodiment.

[0084] The above embodiments are only used to illustrate the technical concept and features of the present invention, and the purpose is to enable those of ordinary skill in the art to understand the content of the present invention and implement it accordingly. It should not be used to limit the protection scope of the present invention. Any equivalent changes or modifications made according to the essence of the content of the present invention should be covered within the protection scope of the present invention.

Claims

1. A method for quantitatively evaluating the saturation of a hydrate mixed layer, characterized in that Including: Obtain formation parameters of the mixed layer section to calculate the density ρ of the gas layer in the mixed layer g ; Based on the density ρ of the mixed layer gas layer g to obtain the hydrogen index HI of the gas in the mixed layer section g ; Analyzing the natural gamma ray GR and total porosity of the pure water layer section to obtain the total porosity φ of the formation in the mixed layer section; Establishing a petrophysical model for the mixed layer section to obtain the saturations of hydrate, free gas, and formation water in the mixed layer section; The petrophysical model for the mixed layer section is established in the following manner: Sediments consist of two parts: a rock skeleton and pores; the pores contain three-phase fluids of hydrate, free gas, and water; For the sediment skeleton part, first, based on the quantitative X-ray analysis of the core, determine the main mineral types of the skeleton in the mixed layer section; since the core data is discrete, combine the elemental capture spectroscopy logging to obtain the continuous mineral components of the formation and perform core calibration. Assume that the content of each mineral obtained is V i ; For the fluid part in the pores, it is assumed that the pore volumes occupied by hydrates, free gas, and water in the mixed layer section are φ gh , φ g , and φ w , respectively, and the saturations are S gh , S g , and S w ; due to the presence of gas in the mixed layer section, the nuclear magnetic porosity measures the pore volume occupied by all formation water and part of the free gas; therefore, the rock physics model of the formation includes: is the polarization factor of gas under formation conditions; φ nmr is the nuclear magnetic porosity; 1 - φ represents the volume occupied by the rock skeleton, φS gh represents the volume occupied by hydrate, φS g represents the volume occupied by gas, φS w represents the volume occupied by water, and the sum of these four is equal to 1; φ nmr represents the volume of water that can be measured and the volume of part of the gas occupied, 1 - φ nmr represents the volume not detected by nuclear magnetic resonance logging; W is the waiting time of the gas layer pulse sequence; T1 is the transverse relaxation time of gas under formation conditions; HI w is the hydrogen index of water; Based on the petrophysical model, the following formula is listed: In the above formula, ρ, ρ i , ρ gh , ρ g , ρ w are the densities of formation measurement, the i-th mineral, hydrate, free gas, and formation water respectively, which are known numbers; φ nmr is the nuclear magnetic porosity measured by nuclear magnetic resonance in the mixed layer; Combining the above formulas, the pore volumes of free gas and formation water in the mixed layer section, φ g , φ w can be obtained respectively; then, the pore volume occupied by hydrate, φ gh = φ - φ g - φ w According to the definition of saturation, the saturations of hydrate, free gas, and formation water in the mixed layer section are respectively:

2. The method for quantitatively evaluating the saturation of the hydrate mixed layer according to claim 1, wherein The formation parameters of the mixed layer section include the formation pressure P and formation temperature T of the mixed layer section; Among them, M g is the apparent molecular weight of CH4, and Z is the compressibility factor.

3. The method for quantitatively evaluating the saturation of the hydrate mixed layer according to claim 1, wherein The total porosity φ of the formation in the mixed layer section is: φ = -0.00276 * GR + 0.6259.

4. A device for quantitatively evaluating the saturation of a hydrate mixed layer, characterized in that, Including: An input module for inputting formation parameters of the mixed layer section to obtain the density ρ of the gas layer in the mixed layer g ; Search module, configured to search for and obtain the hydrogen index HI of the gas in the mixed layer section according to the density ρ of the gas layer in the mixed layer g ; g ; An analysis module for analyzing the natural gamma ray GR and total porosity of the pure water layer section to obtain the total porosity φ of the formation in the mixed layer section; A model module for establishing a petrophysical model for the mixed layer section to obtain the saturations of hydrate, free gas, and formation water in the mixed layer section; The petrophysical model for the mixed layer section is established in the following manner: Sediments consist of two parts: a rock skeleton and pores; the pores contain three-phase fluids of hydrate, free gas, and water; For the sediment skeleton part, first, based on the quantitative X-ray analysis of the core, determine the main mineral types of the skeleton in the mixed layer section; since the core data is discrete, combine the elemental capture spectroscopy logging to obtain the continuous mineral components of the formation and perform core calibration, assuming that the content of each mineral obtained is V i ; For the fluid part in the pores, it is assumed that the pore volumes occupied by hydrates, free gas, and water in the mixed layer section are φ gh , φ g , and φ w , and the saturations are S gh , S g , and S w ; due to the presence of gas in the mixed layer section, the nuclear magnetic porosity measures the pore volume occupied by all formation water and part of the free gas; therefore, the petrophysical model of the formation includes: is the polarization factor of gas under formation conditions; φ nmr is the nuclear magnetic porosity; 1 - φ represents the volume occupied by the rock skeleton, φS gh represents the volume occupied by hydrates, φS g represents the volume occupied by gas, φS w represents the volume occupied by water, and the sum of these four is equal to 1; φ nmr represents the volume of water that can be measured and the volume of part of the gas occupied, 1 - φ nmr represents the volume not detected by nuclear magnetic resonance logging; W is the waiting time of the gas layer pulse sequence; T1 is the transverse relaxation time of gas under formation conditions; HI w is the hydrogen index of water; Based on the petrophysical model, the following formula is listed: In the above formula, ρ, ρ i , ρ gh , ρ g , ρ w are the densities of formation measurement, the i-th mineral, hydrate, free gas, and formation water respectively, which are known numbers; φ nmr is the nuclear magnetic porosity of the nuclear magnetic measurement in the mixed layer; Combining the above formulas, the pore volumes of free gas and formation water in the mixed layer section, φ g , φ w can be obtained respectively; then, the pore volume occupied by hydrate, φ gh = φ - φ g - φ w According to the definition of saturation, the saturations of hydrate, free gas, and formation water in the mixed layer section are respectively:

5. The hydrate mixed layer saturation quantitative evaluation device according to claim 4, wherein The formation parameters of the mixed layer section include the formation pressure P and formation temperature T of the mixed layer section; Among them, M g is the apparent molecular weight of CH4, and Z is the compressibility factor.

6. The hydrate mixed layer saturation quantitative evaluation device according to claim 4, wherein The total porosity φ of the formation in the mixed layer section is: φ = -0.00276 * GR + 0.6259.

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