T2 cut-off value determination method and system

Abstract

The invention relates to a T2 cut-off value determination method, and belongs to the technical field of oil-gas field development, and the method comprises the steps: determining a model coefficient based on a free fluid permeability model; obtaining movable porosity and bound water porosity based on the core porosity, the nuclear magnetic porosity, the second permeability and the model coefficient; and obtaining a T2 cutoff value based on the logging T2 spectrum, the movable porosity and the bound water porosity. According to the method and the system for determining the T2 cut-off value, the T2 cut-off value is determined through core physical property measurement porosity, permeability and irreducible fluid saturation data when there is no core nuclear magnetic resonance experiment data. Conventional rock core information is easy to obtain and low in cost, the number of coring data points is large, more T2 cut-off value and data matched with the logging T2 spectrum can be accumulated, and a morphological method or a regional experience T2 cut-off value can be established.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas field development, and particularly relates to a method for determining a T2 cutoff value. Background Art

[0002] In recent years, with the continuous breakthroughs in unconventional oil and gas exploration and development, accelerating unconventional oil and gas exploration and development has become the key technology for oil and gas field development. However, unconventional reservoirs have the characteristics of diverse fluid occurrence states, complex pore structures, and high clay mineral content, which makes conventional logging methods less effective in evaluating reservoir parameters such as porosity, permeability, and saturation in unconventional reservoirs.

[0003] Nuclear magnetic resonance technology, with its high efficiency, non-destructiveness and sensitivity only to hydrogen-containing fluids, has been used in my country for more than 20 years. It has made positive contributions to the logging evaluation of complex oil and gas reservoirs in my country and the development of petroleum logging technology itself. It has been widely used in various types of reservoirs. It measures the nuclear signals of hydrogen atoms in the formation to obtain nuclear magnetic resonance logging data containing rich formation information.

[0004] Nuclear magnetic resonance has been successfully applied in reservoir evaluation, such as porosity calculation, pore structure evaluation, fluid identification, permeability calculation, saturation calculation, etc. In the process of using nuclear magnetic resonance technology to evaluate reservoir properties, a key parameter cannot be avoided: T2 (transverse relaxation time) cutoff value. How to determine the T2 cutoff value is a complex problem in nuclear magnetic resonance logging and is also an important indicator for evaluating reservoir quality.

[0005] At present, there are three main methods for determining the T2 cutoff value in NMR logging data processing:

[0006] (1) Regional empirical value: 33ms for sandstone and 92ms for carbonate rock. The disadvantage of this method is that it cannot solve the problem of large differences in T2 cutoff values ​​in different blocks, different layers, and different lithologies.

[0007] (2) Experimental determination: The T2 integral curves of saturated water rock samples before and after centrifugation are compared and analyzed. The disadvantages of this method are high cost, long cycle, limited data volume, and usually the average value of the regional T2 cutoff value is established; secondly, the magnetic field design, measurement parameters, noise level, etc. of the experimental instrument and the logging instrument are different. Therefore, the T2 cutoff value obtained by the experimental method is difficult to be directly promoted to different types of logging instruments.

[0008] (3) Morphological method: Based on a large amount of core experimental data, a method for determining the T2 cutoff value is established according to the T2 spectrum morphology and the T2 spectrum peak position. This method also requires a large amount of experimental data. The differences in the environment between the experimental instrument and the logging instrument lead to a large difference between the experimental spectrum and the logging spectrum, which is difficult to unify and coordinate. Summary of the invention

[0009] In view of the above problems, the present invention provides a method and system for determining the T2 cutoff value, which is implemented based on the T2 spectrum of nuclear magnetic resonance logging and the permeability model, adopts a small amount of conventional physical property core experimental data or with the help of existing regional empirical formulas for porosity and permeability bound fluid, and uses the Coates_Timur (free fluid) permeability model to reversely determine the T2 cutoff value.

[0010] A first object of the present invention is to provide a method for determining a T2 cutoff value, the method comprising:

[0011] Based on the free fluid permeability model, determine the model coefficients;

[0012] Based on core porosity, nuclear magnetic porosity, second permeability and model coefficient, movable porosity and irreducible water porosity are obtained;

[0013] The T2 cutoff value is obtained based on the well logging T2 spectrum, movable porosity and irreducible water porosity.

[0014] In the embodiment of the present invention, the free fluid permeability model is established according to the porosity, the first permeability, and the irreducible fluid saturation.

[0015] In the embodiment of the present invention, the porosity, the first permeability, and the irreducible fluid saturation are obtained from core physical property measurements or conventional logging interpretation calculations.

[0016] In an embodiment of the present invention, the second permeability is the full-well permeability or the core analysis permeability.

[0017] In the embodiment of the present invention, the movable porosity and irreducible water porosity are obtained based on the core porosity, nuclear magnetic porosity, second permeability and model coefficient, including:

[0018] Based on the core porosity and nuclear magnetic porosity, the corrected nuclear magnetic porosity is obtained;

[0019] Based on the model coefficient, the second permeability and the corrected NMR porosity, the movable porosity and the irreducible water porosity are obtained.

[0020] In the embodiment of the present invention, when the second permeability is the full-well section permeability, the full-well section permeability is obtained according to the core analysis permeability, the corrected nuclear magnetic porosity and the T2 logarithmic average value.

[0021] In the embodiment of the present invention, the movable porosity and irreducible water porosity are obtained based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity, including:

[0022] Based on the model coefficient, the second permeability and the corrected NMR porosity, the movable bound water porosity ratio is obtained;

[0023] Based on the movable bound water porosity ratio and the second permeability, the movable porosity and the bound water porosity are obtained.

[0024] The second object of the present invention is to provide a T2 cutoff value determination system, the determination system comprising a model coefficient module, an acquisition module and a back-calculation module;

[0025] The model coefficient module is used to determine the model coefficient based on the free fluid permeability model;

[0026] The acquisition module is used to obtain movable porosity and irreducible water porosity based on core porosity, nuclear magnetic porosity, second permeability and model coefficient;

[0027] The reverse inference module is used to obtain a T2 cutoff value based on the well logging T2 spectrum, movable porosity and irreducible water porosity.

[0028] In the embodiment of the present invention, the acquisition module includes a correction level submodule and a calculation level submodule;

[0029] The first-level correction submodule is used to obtain the corrected nuclear magnetic porosity based on the core porosity and the nuclear magnetic porosity;

[0030] The first-level calculation submodule is used to obtain the movable porosity and the irreducible water porosity based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity.

[0031] In the embodiment of the present invention, the computing level 1 submodule includes a first level 2 submodule and a second level 2 submodule;

[0032] The first secondary submodule is used to obtain the movable bound water porosity ratio based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity;

[0033] The second secondary submodule is used to obtain the movable porosity and the irreducible water porosity based on the movable irreducible water porosity ratio and the second permeability.

[0034] Beneficial effects of the present invention:

[0035] The T2 cutoff value determination method and system provided by the present invention have the following effects:

[0036] (1) When there is no core NMR experimental data, the T2 cutoff value is determined by measuring the porosity, permeability, and bound fluid saturation data of core physical properties. Conventional core data is easy to obtain, inexpensive, and has many coring data points. More data matching the T2 cutoff value with the well logging T2 spectrum can be accumulated to establish the morphological method or regional empirical T2 cutoff value;

[0037] (2) When there is no porosity, permeability, and bound fluid saturation data measured by core physical properties, conventional methods (such as neutron density intersection to calculate porosity, core analysis permeability and neutron density, GR and other conventional curve correlation formulas or charts; core analysis permeability and porosity, shale content and correlation formulas or charts interpreted by conventional logging processing; bound water saturation and shale content correlation formulas or charts) and porosity, permeability, and bound fluid saturation data determined by empirical regional models can be effectively used as an alternative to core analysis data, which is more convenient and faster.

[0038] Therefore, the present invention has low application cost, fast effectiveness, convenient implementation, easy promotion, and broad application prospects.

[0039] Other features and advantages of the present invention will be described in the following description, and partly become apparent from the description, or understood by practicing the present invention. The purpose and other advantages of the present invention can be realized and obtained by the structures pointed out in the description, claims and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0040] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required for use in the embodiments or the description of the prior art. Obviously, the drawings described below are some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0041] Figure 1 A flow chart of a method for determining a T2 cutoff value according to an embodiment of the present invention is shown;

[0042] Figure 2 A zero-intercept analysis diagram of permeability and conversion term of core analysis according to an embodiment of the present invention is shown;

[0043] Figure 3 A diagram showing the full-well nuclear magnetic porosity correction result according to an embodiment of the present invention is shown;

[0044] Figure 4 A result diagram of the full well section permeability obtained by nuclear magnetic porosity correction according to an embodiment of the present invention is shown;

[0045] Figure 5 A result diagram of the T2 cutoff value and irreducible fluid saturation of the entire well section according to an embodiment of the present invention is shown;

[0046] Figure 6 A comparative analysis diagram of irreducible fluid saturation and irreducible fluid saturation of core analysis according to an embodiment of the present invention is shown;

[0047] Figure 7A framework diagram of a T2 cutoff value determination system according to an embodiment of the present invention is shown;

[0048] In the figure:

[0049] 1. Model coefficient module; 2. Acquisition module; 3. Inverse module. DETAILED DESCRIPTION

[0050] In order to make the purpose, technical solution and advantages of the embodiments of the present invention clearer, the technical solution in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0051] like Figure 1 As shown, a method for determining a T2 cutoff value in an embodiment of the present invention includes:

[0052] Step S1, determining a model coefficient based on a free fluid permeability model;

[0053] Step S2, based on the core porosity, nuclear magnetic porosity, the second permeability and the model coefficient, obtain the movable porosity and the irreducible water porosity;

[0054] Step S3: Obtain a T2 cutoff value based on the well logging T2 spectrum, movable porosity and irreducible water porosity.

[0055] In step S1, the free fluid permeability model is established according to the porosity, the first permeability, and the bound fluid saturation. The first permeability is the core analysis permeability. Specifically, the porosity, the first permeability, and the bound fluid saturation can be determined from core physical property measurement or conventional logging interpretation. In the embodiment of the present invention, the porosity, the first permeability, and the bound fluid saturation are derived from core experimental analysis data. Conventional physical property measurements of 37 cores were performed in Well A. The measurement data parameters are shown in Table 1.

[0056] Table 1

[0057]

[0058]

[0059] In Table 1, NO. indicates a serial number, DEPTH indicates the core retrieval depth, PORC indicates the porosity of core analysis, PERMC indicates the permeability of core analysis, and SWBC indicates the bound water saturation of core analysis.

[0060] Based on the porosity, first permeability, and bound fluid saturation data, a Coates-Timur (free fluid) permeability model is established. The model formula is shown in formula (1):

[0061]

[0062] In formula (1), PMB = Φ * Swb, PMF = Φ - PMB, K is the first permeability (core analysis permeability in this embodiment), Φ is porosity, Swb is irreducible fluid saturation, PMB is irreducible fluid porosity, PMF is movable fluid porosity, a, b, c are model parameters of the Coates-Timur permeability model;

[0063] For the convenience of data processing, the model formula of formula (1) is transformed into formula (2):

[0064]

[0065] In formula (2), Φ is expressed in %.

[0066] Based on formula (2) and the data in Table 1, the model parameters a, b, and c are determined. Specifically, the determination method is as follows:

[0067] Simple method: first set the specific values ​​of a and b, remove the coefficient c on the right side of the calculation formula (2), and then use zero-intercept least squares fitting with the analyzed permeability to determine c;

[0068] Complex method: Take the logarithm of both sides of the permeability model, and a, b, and c become the coefficients of the binary linear equation. Substitute the values ​​of each variable and use the linear equation solution method to determine a, b, and c.

[0069] In this embodiment, the above-mentioned concise method is used to calculate the relevant items of the data in Table 1 to obtain Table 2;

[0070] Table 2

[0071]

[0072]

[0073] In Table 2, NO. is a serial number, DEPTH indicates the core return depth, Φ is PORC (core analysis porosity), Swb is SWBC (core analysis bound water saturation), core analysis movable bound water porosity ratio RFB = PMF / PMB, PERMC is core analysis permeability, KC is a temporary conversion term calculated by formula (3), that is, the comprehensive term on the right side of the above formula (2) without the coefficient c;

[0074] After removing the coefficient c in formula (2), the values ​​of a and b are: a = 4, b = 2, respectively. Substituting them into formula (2), we get formula (3):

[0075]

[0076] Use PERMC and KC to perform zero-intercept correlation analysis and draw the curve as follows Figure 2 As shown, from Figure 2 The relationship between PERMC and KC obtained from the curve in is: PERMC = 3.41*KC, with a correlation coefficient of 0.885, which is a good correlation, and then c = 3.41 is determined;

[0077] The permeability model coefficients obtained are: a = 4, b = 2, c = 3.41;

[0078] In step S2, the movable porosity and irreducible water porosity are obtained based on the core porosity, nuclear magnetic porosity, second permeability and model coefficient, including:

[0079] Step A1, based on the core porosity and the nuclear magnetic porosity, obtain the corrected nuclear magnetic porosity;

[0080] Step A2: based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity, obtain the movable porosity and the irreducible water porosity.

[0081] Specifically, in step A1, the nuclear magnetic porosity is corrected based on the core porosity and the nuclear magnetic porosity, including:

[0082] After the core depth is returned, the core analysis porosity and nuclear magnetic porosity are subjected to linear least square fitting processing to obtain the corrected nuclear magnetic porosity, as follows:

[0083] According to the analysis, the porosity correction equation is: Φmc = 1.21*Φm, where: Φm, initial porosity after NMR treatment; Φmc, corrected NMR porosity (corrected NMR porosity);

[0084] Similarly, the porosity Pi of each component of T2 distribution is corrected, and the correction equation is: Pic = 1.21*Pi, where: Pi, each component of T2 distribution; Pic, each component after T2 distribution correction;

[0085] The above correction processing results are as follows Figure 3 As shown, Figure 3 Among them, the first track is the depth track; the second track is the natural gamma ray GR; the third track is the initial NMR processing porosity PMT and the core analysis porosity PORC; the fourth track is the corrected NMR processing porosity PMT and the core analysis porosity PORC; the fifth track is the T2 distribution DISTAT (NMR total T2 spectrum or total T2 distribution).

[0086] Specifically, in step A2, the movable porosity and irreducible water porosity are obtained based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity, including:

[0087] Step B1, obtaining the movable bound water porosity ratio based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity;

[0088] Step B2: based on the movable bound water porosity ratio and the second permeability, obtain the movable porosity and the bound water porosity.

[0089] In step B1, the movable bound water porosity ratio is obtained based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity, that is, the movable bound water porosity ratio Rfb=PMF / PMB is substituted into formula (2) to obtain formula (4):

[0090]

[0091] In formula (4), K is the second permeability, which is the full-well permeability. The full-well permeability is obtained based on the core analysis permeability, the corrected nuclear magnetic porosity and the T2 logarithmic average. The specific results are as follows: Figure 4 As shown, Figure 4 In the figure, the first track is the depth track; the second track is the natural gamma ray GR; the third track is the corrected nuclear magnetic processing porosity PMT and the core analysis porosity PORC; the fourth track is the curve relationship between the core analysis permeability PERMC and the permeability Kd; the fifth track is the T2 distribution DISTAT and the logarithmic mean curve T2LM;

[0092] The values ​​of a, b, and c obtained in step A1 above, and Figure 4 Substituting the relationship curve between the permeability PERMC and the permeability Kd of the core analysis of the whole well section into formula (4), the curve of the movable bound water porosity ratio Rfb of the whole well section can be obtained;

[0093] In step B2, the movable porosity and the irreducible water porosity are obtained based on the movable irreducible water porosity ratio and the second permeability, that is,

[0094] Substituting the relationship curve of the movable bound water porosity ratio Rfb of the whole well section in step B1 into equations (5) and (6), the curve of the movable porosity of the whole well section and the curve of the bound water porosity of the whole well section can be obtained:

[0095]

[0096]

[0097] In formulas (5)-(6), PMF is the movable fluid porosity, PMB is the bound fluid porosity, Rfb is the movable bound water porosity ratio, and Φmc is the corrected nuclear magnetic porosity;

[0098] In the embodiment of the present invention, in step S3, obtaining the T2 cutoff value based on the well logging T2 spectrum, movable porosity and irreducible water porosity includes:

[0099] Calculate the integral curve starting from the front end of the T2 spectrum. On the integral curve, find the point on the Y axis where the bound fluid porosity PMB is equal. The X value of this point is the T2 cutoff value T2C1.

[0100] Calculate the integral curve starting from the back end of the T2 spectrum. On the integral curve, find the point on the Y axis where the movable fluid porosity PMF is equal. The X value of this point is the T2 cutoff value T2C2.

[0101] The average value of T2C1 and T2C2 is the T2 cutoff value T2C to be determined, and then the T2 cutoff value T2C curve of the whole well section is obtained. For details, see Figure 5 ; Figure 5 The first track is the depth track; the second track is the natural gamma GR; the third track is the corrected nuclear magnetic porosity PMT and the core analysis porosity PORC; the fourth track is the core analysis permeability PERMC and the calculated permeability Kd; the fifth track is the T2 distribution DISTAT and the calculated full-well T2 cutoff value T2C; the sixth track is the calculated full-well bound fluid saturation SWB and the core analysis bound fluid saturation SWBC;

[0102] based on Figure 3-Figure 5 The corrected NMR processed porosity PMT curve, permeability Kd curve, logarithmic average curve T2LM, movable porosity curve of the whole well section, water-bound porosity curve of the whole well section, bound fluid saturation SWB curve of the whole well section, T2 cutoff value T2C curve of the whole well section, and the relevant processed curve values ​​extracted according to the coring depth, the obtained data results are shown in the table.

[0103] Table 3

[0104]

[0105]

[0106] Wherein: T2C is the processed T2 cutoff value, SWB is the bound fluid saturation obtained after correction, Kd is the permeability calculated based on the corrected NMR porosity, KTIM is the permeability calculated by the Coates_Timur (free fluid) model, PMT is the corrected NMR porosity, PMF is the movable fluid porosity, PMB is the bound fluid porosity, NO. is the serial number, and DEPTN is the coring depth.

[0107] According to Table 1 and Table 3, the irreducible fluid saturation SWBC and irreducible fluid saturation SWB of the core analysis are compared to obtain Figure 6 The comparison results shown are from Figure 6 It can be seen that the correlation between SWBC and SWB reaches 0.972, the absolute average deviation is 6.33, and the relative error is 13.2%, which shows that the cutoff value determined by the embodiment of the present invention has high accuracy and good practical value.

[0108] In certain embodiments of the present invention, the second permeability is taken as the core analysis permeability, that is, the KC value in Table 1, which is substituted into formula (4). The remaining steps are the same as those in the above embodiment, and finally only the T2 cutoff value T2C at the core position can be obtained.

[0109] In an embodiment of the present invention, a T2 cutoff value determination system is provided, comprising a model coefficient module 1, an acquisition module 2 and a back-calculation module 3;

[0110] The model coefficient module 1 is used to determine the model coefficient based on the free fluid permeability model;

[0111] The acquisition module 2 is used to obtain the movable porosity and the irreducible water porosity based on the core porosity, the nuclear magnetic porosity, the second permeability and the model coefficient;

[0112] The reverse inference module 3 is used to obtain a T2 cutoff value based on the well logging T2 spectrum, movable porosity and irreducible water porosity.

[0113] In an embodiment of the present invention, the acquisition module includes a correction level submodule and a calculation level submodule;

[0114] The first-level correction submodule is used to obtain the corrected nuclear magnetic porosity based on the core porosity and the nuclear magnetic porosity;

[0115] The first-level calculation submodule is used to obtain the movable porosity and the irreducible water porosity based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity.

[0116] In the embodiment of the present invention, the computing level 1 submodule includes a first level 2 submodule and a second level 2 submodule;

[0117] The first secondary submodule is used to obtain the movable bound water porosity ratio based on the model coefficient and the corrected nuclear magnetic porosity;

[0118] The second secondary submodule is used to obtain the movable porosity and the irreducible water porosity based on the movable irreducible water porosity ratio and the second permeability.

[0119] Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art should understand that they can still modify the technical solutions described in the aforementioned embodiments, or make equivalent substitutions for some of the technical features therein; and these modifications or substitutions do not make the essence of the corresponding technical solutions deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for determining a T2 cutoff value, characterized in that: include: Based on the free fluid permeability model, determine the model coefficients; Based on core porosity, nuclear magnetic porosity, second permeability and model coefficient, movable porosity and irreducible water porosity are obtained; The T2 cutoff value is obtained based on the well logging T2 spectrum, movable porosity and irreducible water porosity.

2. A method for determining a T2 cutoff value according to claim 1, characterized in that: The free fluid permeability model is established according to porosity, first permeability, and irreducible fluid saturation.

3. A method for determining a T2 cutoff value according to claim 2, characterized in that: The porosity, first permeability and irreducible fluid saturation are obtained from core physical property measurement or conventional logging interpretation calculation.

4. A method for determining a T2 cutoff value according to claim 1, characterized in that: The second permeability is the full-well permeability or the core analysis permeability.

5. A method for determining a T2 cutoff value according to claim 4, characterized in that: The movable porosity and irreducible water porosity are obtained based on the core porosity, nuclear magnetic porosity, second permeability and model coefficient, including: Based on the core porosity and nuclear magnetic porosity, the corrected nuclear magnetic porosity is obtained; Based on the model coefficient, the second permeability and the corrected NMR porosity, the movable porosity and the irreducible water porosity are obtained.

6. A method for determining a T2 cutoff value according to claim 5, characterized in that: When the second permeability is the full-well section permeability, the full-well section permeability is obtained according to the core analysis permeability, the corrected nuclear magnetic porosity and the T2 logarithmic average value.

7. A method for determining a T2 cutoff value according to any one of claims 5 to 6, characterized in that: The movable porosity and irreducible water porosity are obtained based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity, including: Based on the model coefficient, the second permeability and the corrected NMR porosity, the movable bound water porosity ratio is obtained; Based on the movable bound water porosity ratio and the second permeability, the movable porosity and the bound water porosity are obtained.

8. A T2 cutoff value determination system, characterized in that: It includes model coefficient module, acquisition module and back-calculation module; The model coefficient module is used to determine the model coefficient based on the free fluid permeability model; The acquisition module is used to obtain movable porosity and irreducible water porosity based on core porosity, nuclear magnetic porosity, second permeability and model coefficient; The reverse inference module is used to obtain a T2 cutoff value based on the well logging T2 spectrum, movable porosity and irreducible water porosity.

9. A T2 cutoff value determination system according to claim 8, characterized in that: The acquisition module includes a correction level submodule and a calculation level submodule; The first-level correction submodule is used to obtain the corrected nuclear magnetic porosity based on the core porosity and the nuclear magnetic porosity; The first-level calculation submodule is used to obtain the movable porosity and the irreducible water porosity based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity.

10. A T2 cutoff value determination system according to claim 9, characterized in that: The computing level 1 submodule includes a first level 2 submodule and a second level 2 submodule; The first secondary submodule is used to obtain the movable bound water porosity ratio based on the model coefficient, the second permeability and the corrected nuclear magnetic porosity; The second secondary submodule is used to obtain the movable porosity and the irreducible water porosity based on the movable irreducible water porosity ratio and the second permeability.

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