A method for constructing a digital core based on a rock chip sample

Abstract

A method for constructing a digital core based on a rock sample, the method comprising the steps of: obtaining logging data of an oil and gas well; determining a reservoir section according to the logging data; obtaining logging data of a drill cuttings in the reservoir section; determining a real sample of the drill cuttings according to the logging data and the logging data; and establishing a digital core of the drill cuttings according to the real sample of the drill cuttings. The method for constructing a digital core based on a rock sample provided by the application establishes selection criteria for representative real samples of drill cuttings, and the selection of the real samples of drill cuttings can solve the problem of limited samples when constructing a digital core, thereby realizing the construction of digital cores of all depth sections, and obtaining a brittleness index of the oil and gas well by calculating a core brittleness index, which is beneficial to the development of the oil and gas well.

Description

Technical Field

[0001] This invention belongs to the field of digital core technology, specifically relating to a method for constructing digital cores based on rock cuttings samples. Background Technology

[0002] Digital core technology plays a crucial role in oil and gas exploration and development, significantly contributing to the evaluation of reservoir properties, seepage characteristics, oil-bearing capacity, and fracturing resilience. However, the most fundamental and critical initial step in core construction and rock physics numerical simulation is the selection of core samples. The accuracy of this selection not only affects the accuracy of the digital core construction but also the accuracy of the simulation results and analytical data.

[0003] Currently, the main method for constructing digital cores is high-precision imaging technology (including X-ray CT scanning and FIB-SEM). Core samples are mainly obtained from well drilling. However, the problem with these samples is that most oil and gas fields are now in the middle and late stages of exploration and development, and the possibility of large-scale well drilling is extremely small. At the same time, for the complex reservoirs such as mudstone, shale, tight sandstone, and carbonate rocks currently being explored, the heterogeneity is strong, and secondary pores such as fractures and caves are well developed, making it difficult to obtain cores. Therefore, it is imperative to establish digital cores after high-precision imaging of rock cuttings.

[0004] However, for cuttings samples, there is a discrepancy between the on-site sample well depth and the logging depth. During PDC drilling, the cuttings particles experience severe wear, damaging formation properties. Furthermore, in loose formations, the cuttings primarily consist of mineral particles. To ensure the establishment of an accurate digital core reflecting the formation lithology and physical properties, precise selection of true cuttings samples is crucial. Therefore, establishing a representative cuttings sample selection process is of paramount importance.

[0005] To date, there has been a great deal of research on how to build digital cores, but there are no research reports on how to select representative rock cuttings samples through representative characterization, or on the idea of ​​using drilling rock cuttings samples to construct digital cores. Summary of the Invention

[0006] In view of the above problems, the present invention provides a method for constructing digital cores based on rock cuttings samples to overcome or at least partially solve the above problems.

[0007] To address the aforementioned technical problems, this invention provides a method for constructing digital cores based on rock cuttings samples, the method comprising the following steps:

[0008] Obtain logging data from oil and gas wells;

[0009] The reservoir section is determined based on the well logging data;

[0010] Obtain logging data of cuttings from the transfer well in the reservoir section;

[0011] The true rock cuttings sample was determined based on the well logging data and the well logging data.

[0012] A digital core of rock fragments was constructed based on the actual rock fragment samples.

[0013] Preferably, the step of acquiring logging data from oil and gas wells includes the following steps:

[0014] Calculate the clay content of the oil and gas well;

[0015] Calculate the porosity of the oil and gas well.

[0016] Preferably, the expression for the mud content is:

[0017] Vsh = 100 * (2 G*IGR -1) / (2 G -1),

[0018] Wherein, Vsh represents the mud content, G represents the Hilchie index, and IGR represents the natural gamma relative value.

[0019] Preferably, the step of obtaining logging data of cuttings from the transfer well in the reservoir section includes the following steps:

[0020] Calculate the porosity of the well cuttings;

[0021] Calculate the permeability of the well cuttings;

[0022] Calculate the movable fluid saturation of the well cuttings;

[0023] Calculate the saturation of the bound fluid in the well cuttings.

[0024] Preferably, the expression for the porosity is:

[0025]

[0026] Where, Φ z The porosity is represented by A(t), and the spectral distribution of NMR T2 is represented by A(t).

[0027] Preferably, the expression for the permeability is:

[0028]

[0029] Among them, K coates Φ represents the permeability. MRI The value represents nuclear magnetic porosity, FFI represents mobile fluid saturation, and BVI represents bound fluid saturation.

[0030] Preferably, the expression for the saturation of the movable fluid is:

[0031]

[0032] Wherein, FFI represents the saturation of the movable fluid, T2 represents the nuclear magnetic resonance (NMR) value, and T2 cutoff This represents the cutoff value for NMR T2. max Let T(t) represent the maximum value of NMR T2, and A(t) represent the spectral distribution of NMR T2.

[0033] Preferably, the expression for the bound fluid saturation is:

[0034]

[0035] Wherein, BVI represents the saturation of the bound fluid, and T2 cutoff This represents the cutoff value for NMR T2. max Let T(t) represent the maximum value of NMR T2, and A(t) represent the spectral distribution of NMR T2.

[0036] Preferably, the method further includes the step of:

[0037] The brittleness index of oil and gas wells is calculated based on the digital core samples of the rock cuttings.

[0038] Preferably, the step of calculating the brittleness index of the oil and gas well based on the rock cuttings digital core includes the following steps:

[0039] Establish a core mechanics calculation model;

[0040] The core mechanical parameters are solved based on the core mechanical calculation model.

[0041] Calculate the core brittleness index based on the core mechanical parameters;

[0042] Calculate the silica index, ash index, and brittleness index of the oil and gas well;

[0043] The mineral element brittleness index is calculated based on the silica index, the ash index, and the brittleness index.

[0044] The brittleness index of the oil and gas well is calculated based on the core brittleness index and the mineral element brittleness index.

[0045] One or more technical solutions in the embodiments of the present invention have at least the following technical effects or advantages: The method for constructing digital cores based on rock cuttings samples provided in this application establishes a selection standard for representative true rock cuttings samples. The selection of true rock cuttings samples can solve the problem of limited samples when constructing digital cores, thereby realizing the construction of digital cores for all depth ranges. Furthermore, the brittleness index of oil and gas wells can be obtained by calculating the core brittleness index, which is beneficial to the development of oil and gas wells. Attached Figure Description

[0046] 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 some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0047] Figure 1 This is a schematic flowchart of a method for constructing digital cores based on rock cuttings samples provided in an embodiment of the present invention;

[0048] Figure 2 This is a schematic diagram of drilling cuttings in a method for constructing a digital core based on cuttings samples provided in an embodiment of the present invention;

[0049] Figure 3 This is a schematic diagram of rock cuttings after being classified according to grain size in a method for constructing digital cores based on rock cuttings samples provided in an embodiment of the present invention.

[0050] Figure 4 This is a schematic diagram of CT scan samples of rock cuttings of different grain sizes in a method for constructing digital cores based on rock cuttings samples provided in an embodiment of the present invention;

[0051] Figure 5 This is a schematic diagram of three-dimensional images obtained by CT scanning of rock cuttings at different depths in a method for constructing digital cores based on rock cuttings samples provided in an embodiment of the present invention;

[0052] Figure 6 This is a schematic diagram of rock debris particle identification in a method for constructing a digital core based on rock debris samples provided in an embodiment of the present invention;

[0053] Figure 7 This is a schematic diagram of the brittleness index of oil and gas wells calculated using a method for constructing digital cores based on rock cuttings samples, provided in an embodiment of the present invention. Detailed Implementation

[0054] The present invention will be described in detail below with reference to specific embodiments and examples, thereby making the advantages and various effects of the present invention more clearly apparent. Those skilled in the art should understand that these specific embodiments and examples are for illustrative purposes only and are not intended to limit the present invention.

[0055] Throughout this specification, unless otherwise specified, the terminology used herein should be understood as having the meaning commonly used in the art. Therefore, unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains. In the event of any conflict, this specification shall prevail.

[0056] Unless otherwise specified, all raw materials, reagents, instruments and equipment used in this invention can be purchased from the market or prepared by existing methods.

[0057] like Figure 1 In this embodiment, the present invention provides a method for constructing digital cores based on rock cuttings samples, the method comprising the following steps:

[0058] S1: Obtain logging data from oil and gas wells;

[0059] In this embodiment of the application, the step of obtaining logging data from oil and gas wells includes:

[0060] Calculate the clay content of the oil and gas well;

[0061] Calculate the porosity of the oil and gas well.

[0062] In this embodiment of the application, when obtaining logging data of oil and gas wells, it is specifically necessary to obtain the clay content and porosity of the oil and gas wells. The clay content of oil and gas wells can be calculated using corresponding expressions, while the porosity of oil and gas wells can be obtained through sonic logging, density logging, and neutron logging curves.

[0063] In this embodiment, the content of clay and minerals can be calculated using well logging curves. Fluorescence analysis determines the mineral content, thereby calculating the content of various minerals and clay. Based on rock mineral element and content data obtained from X-ray fluorescence logging measurements, and according to the geochemical theory of sedimentary rocks and their element enrichment patterns, silicon is generally enriched in sandstone; aluminum, potassium, and iron are enriched in mudstone; magnesium and calcium are enriched in dolomite; calcium accumulates in limestone; sulfur and calcium are enriched in gypsum; phosphorus and sulfur are enriched in coal seams; sodium and chloride are enriched in salt rocks; aluminum, iron, and titanium are enriched in weathering crusts; and sulfur and iron are enriched in pyrite. The sand content in sandstone is defined as Si / (Al+Fe+Si+Ca), and the characteristic parameter for clay content in mudstone is (Al+Fe) / (Al+Fe+Si+Ca). When the clay strata contain no other radioactive minerals besides clay, the natural radioactivity of the strata is mainly determined by the radioactive elements adsorbed by the clay; therefore, natural gamma logging is commonly used to determine the clay content of rocks. Based on statistical analysis of extensive actual data, when the clay content (Vsh) of the rock strata is low (Vsh < 20%), the natural gamma intensity is almost linearly related to the clay content; when the Vsh value is high, the GR (gravity gradient) and Vsh have an exponential relationship. Therefore, empirical formulas for determining the clay content in this region using the natural gamma method are usually derived through statistical analysis of actual data. The empirical relationship between clay content (Vsh) and the relative value of natural gamma (IGR) can be used to obtain Vsh.

[0064] In this embodiment of the application, the expression for the mud content is:

[0065] Vsh = 100 * (2 G*IGR -1) / (2 G -1),

[0066] Wherein, Vsh represents the mud content, G represents the Hilchie index, and IGR represents the natural gamma relative value.

[0067] In the embodiments of this application, the Hilchie index G varies with the geological age of the strata and is determined empirically. For Tertiary strata, G is 3.7, and for older strata, G is 2.0.

[0068] In this embodiment of the application, the expression for the natural gamma relative value IGR is:

[0069] IGR=(GR-GR min ) / (GR max -GR min ),

[0070] Wherein, IGR represents the relative value of natural gamma, GR represents the natural gamma logging value of the target interval, GRmax represents the natural gamma logging value of the adjacent mudstone layer, and GRmin represents the natural gamma logging value of pure sandstone.

[0071] In this embodiment of the application, the porosity of the oil and gas well measured by acoustic waves is called acoustic porosity, and its expression is:

[0072]

[0073] Where, Φ s Δt represents acoustic porosity, Δt represents acoustic transit time, Δtma represents acoustic transit time in the skeleton, and Δtf represents acoustic transit time in the fluid.

[0074] In this embodiment of the application, the porosity of the oil and gas well obtained by density measurement is called density porosity, and its expression is:

[0075]

[0076] Where, Φ D ρb represents density porosity, ρma represents skeletal density, and ρf represents fluid density.

[0077] In this embodiment of the application, the porosity of the oil and gas well obtained by neutron measurement is neutron porosity, and its expression is:

[0078]

[0079] Wherein, ΦN represents neutron porosity, ΦNma represents framework neutron porosity, and ΦNf represents fluid neutron porosity.

[0080] S2: Determine the reservoir section based on the logging data;

[0081] In this embodiment of the application, logging data of oil and gas wells can be obtained through step S1. Then, the logging data can be used to quickly identify the reservoir sections in the oil and gas wells and the fluid properties of the oil and gas wells, and determine the key depth range for which digital cores need to be constructed.

[0082] S3: Obtain logging data of cuttings from the transfer well in the reservoir section;

[0083] In this embodiment of the application, the step of obtaining logging data of cuttings from the reservoir section includes the following steps:

[0084] Calculate the porosity of the well cuttings;

[0085] Calculate the permeability of the well cuttings;

[0086] Calculate the movable fluid saturation of the well cuttings;

[0087] Calculate the saturation of the bound fluid in the well cuttings.

[0088] In this embodiment of the application, when obtaining logging data of cuttings from the well in the reservoir section, it is specifically necessary to calculate the porosity, permeability, movable fluid saturation, and bound fluid saturation of the cuttings.

[0089] In this embodiment of the application, the expression for porosity is:

[0090]

[0091] Where, Φ z The porosity is represented by A(t), and the spectral distribution of NMR T2 is represented by A(t).

[0092] In this embodiment of the application, the expression for the penetration rate is:

[0093]

[0094] Among them, K coates Φ represents the permeability. MRI The value represents nuclear magnetic porosity, FFI represents mobile fluid saturation, and BVI represents bound fluid saturation.

[0095] In this embodiment of the application, the expression for the saturation of the movable fluid is:

[0096]

[0097] Wherein, FFI represents the saturation of the movable fluid, T2 represents the nuclear magnetic resonance (NMR) value, and T2 cutoffThis represents the cutoff value for NMR T2. max Let T(t) represent the maximum value of NMR T2, and A(t) represent the spectral distribution of NMR T2.

[0098] In this embodiment of the application, the expression for the confined fluid saturation is:

[0099]

[0100] Wherein, BVI represents the saturation of the bound fluid, and T2 cutoff This represents the cutoff value for NMR T2. max Let T(t) represent the maximum value of NMR T2, and A(t) represent the spectral distribution of NMR T2.

[0101] S4: Determine the true rock cuttings sample based on the well logging data and the well logging data;

[0102] In this embodiment, the rock cuttings particle size needs to be sufficiently large (greater than 1 mm) for core drilling. Simultaneously, the mineral composition and NMR porosity measured in the logging data of the rock cuttings sample must match the mineral content and porosity calculated from the logging data. Such rock cuttings samples are considered true rock cuttings samples. That is, the logging data obtained in step S1 and the drilling cuttings logging data obtained in step S3 are compared. From among the numerous drilling cuttings samples, rock cuttings samples with a particle size greater than 1 mm and whose mineral composition and NMR porosity match the mineral content and porosity calculated from the logging data are selected as true rock cuttings samples for subsequent analysis.

[0103] S5: Establish a digital core of rock fragments based on the real rock fragment samples.

[0104] In this embodiment of the application, the following is selected: Figure 2 True rock cutting samples from the target layer were shown, and then pretreated (e.g., by using a vibrating sieve to classify the rock cutting samples according to their particle size, and obtaining...). Figure 3 (as shown in the true rock fragment sample), and then prepare as follows Figure 4 The image shows rock cuttings samples used for CT scanning, and high-precision CT scans of actual rock cuttings samples (e.g.) Figure 5 As shown in the figure, image intelligent recognition technology is used for image processing to identify different mineral components. After three-dimensional grayscale reconstruction, particle labeling, and grayscale image segmentation, a model is established. Figure 6 The three-dimensional rock cuttings digital core is shown.

[0105] In this embodiment of the invention, a method for constructing digital cores based on rock cuttings samples further includes the following steps:

[0106] The brittleness index of oil and gas wells is calculated based on the digital core samples of the rock cuttings.

[0107] In the embodiments of this application, after obtaining the digital core of rock cuttings, the brittleness index of oil and gas wells can also be calculated, thereby providing a reference for oil and gas well development.

[0108] In this embodiment of the application, the step of calculating the brittleness index of the oil and gas well based on the rock cuttings digital core includes the following steps:

[0109] Establish a core mechanics calculation model;

[0110] The core mechanical parameters are solved based on the core mechanical calculation model.

[0111] Calculate the core brittleness index based on the core mechanical parameters;

[0112] Calculate the silica index, ash index, and brittleness index of the oil and gas well;

[0113] The mineral element brittleness index is calculated based on the silica index, the ash index, and the brittleness index.

[0114] The brittleness index of the oil and gas well is calculated based on the core brittleness index and the mineral element brittleness index.

[0115] In this embodiment of the application, after establishing a digital core of rock cuttings, a core mechanics calculation model can be established based on the elastic parameters of each mineral phase in the multi-component core. The core mechanics parameters are solved by parallel computation and the conjugate gradient method, and the core brittleness index is calculated based on the rock mechanics parameters.

[0116] In this embodiment, the core mechanical parameters mainly include Young's modulus and Poisson's ratio of the core rock, while the core brittleness index BI is calculated based on the representative Young's modulus E and Poisson's ratio v of the rock, and its formula is:

[0117] BI = (E + v) / 2

[0118] In this embodiment, rock mineral elements and their contents can be measured using X-ray fluorescence logging data. Since the contents of Si, Ca, and Mg can reflect the contents of quartz and carbonate minerals to some extent, the silica index (SI), ash index (CI), and brittleness index (BI) can be introduced based on these three elements to characterize the contents of quartz, carbonate, and brittle minerals in the formation. The calculation formulas are as follows:

[0119]

[0120]

[0121]

[0122] In the formula, SI is the silicon index, ω(Si) is the measured value of Si element content, CI is the ash index, ω(Ca+Mg) is the measured value of Ca and Mg element content, BI is the brittleness index, and ω(Ca+Mg+Si) is the measured value of Ca, Mg and Si element content.

[0123] In this embodiment of the application, by combining the core brittleness index calculated through digital core numerical simulation with the mineral element brittleness index calculated through cuttings fluorescence logging analysis, not only is the representativeness of the selected cuttings verified, but they also jointly provide the depth of study, such as... Figure 7 The brittleness index of oil and gas wells is shown.

[0124] This application provides a method for constructing digital cores based on rock cuttings samples. It establishes a selection criterion for representative true rock cuttings samples. By selecting true rock cuttings samples, the problem of limited samples when constructing digital cores can be solved, thereby enabling the construction of digital cores for all depth ranges. Furthermore, by calculating the core brittleness index, the brittleness index of oil and gas wells can be obtained, which is beneficial to the development of oil and gas wells.

[0125] It should be noted that, in this document, relational terms such as "first" and "second" are used merely to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes said element. The above descriptions are merely specific embodiments of this application, enabling those skilled in the art to understand or implement this application. Various modifications to these embodiments will be readily apparent to those skilled in the art, and the general principles defined herein may be implemented in other embodiments without departing from the spirit or scope of this application. Therefore, this application is not to be limited to the embodiments shown herein, but is to be accorded the widest scope consistent with the principles and novel features claimed herein.

[0126] In summary, the above description is merely a preferred embodiment of the technical solution of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for constructing digital cores based on rock cuttings samples, characterized in that, The method includes the following steps: Obtain logging data from oil and gas wells; The reservoir section is determined based on the well logging data; Obtain logging data of cuttings from the transfer well in the reservoir section; The true rock cuttings sample was determined based on the well logging data and the well logging data. A digital core of rock fragments was constructed based on the actual rock fragment samples.

2. The method for constructing digital cores based on rock cuttings samples according to claim 1, characterized in that, The steps for obtaining logging data from oil and gas wells include: Calculate the clay content of the oil and gas well; Calculate the porosity of the oil and gas well.

3. The method for constructing digital cores based on rock cuttings samples according to claim 2, characterized in that, The expression for the mud content is: Vsh=100*(2 G*IGR -1) / (2 G -1) Wherein, Vsh represents the mud content, G represents the Hilchie index, and IGR represents the natural gamma relative value.

4. The method for constructing digital cores based on rock cuttings samples according to claim 1, characterized in that, The steps for obtaining logging data of cuttings from the transfer well in the reservoir section include: Calculate the porosity of the well cuttings; Calculate the permeability of the well cuttings; Calculate the movable fluid saturation of the well cuttings; Calculate the saturation of the bound fluid in the well cuttings.

5. The method for constructing digital cores based on rock cuttings samples according to claim 4, characterized in that, The expression for porosity is: Where, Φ z The porosity is represented by A(t), and the spectral distribution of NMR T2 is represented by A(t).

6. The method for constructing digital cores based on rock cuttings samples according to claim 4, characterized in that, The expression for the permeability is: Among them, K coates Φ represents the permeability. MRI The value represents nuclear magnetic porosity, FFI represents mobile fluid saturation, and BVI represents bound fluid saturation.

7. The method for constructing digital cores based on rock cuttings samples according to claim 4, characterized in that, The expression for the saturation of the movable fluid is: Wherein, FFI represents the saturation of the movable fluid, T2 represents the nuclear magnetic resonance (NMR) value, and T2 cutoff This represents the cutoff value for NMR T2. max Let T(t) represent the maximum value of NMR T2, and A(t) represent the spectral distribution of NMR T2.

8. The method for constructing digital cores based on rock cuttings samples according to claim 4, characterized in that, The expression for the saturation of the bound fluid is: Wherein, BVI represents the saturation of the bound fluid, and T2 cutoff This represents the cutoff value for NMR T2. max Let T(t) represent the maximum value of NMR T2, and A(t) represent the spectral distribution of NMR T2.

9. The method for constructing digital cores based on rock cuttings samples according to claim 1, characterized in that, It also includes the following steps: The brittleness index of oil and gas wells is calculated based on the digital core samples of the rock cuttings.

10. The method for constructing digital cores based on rock cuttings samples according to claim 9, characterized in that, The calculation of the brittleness index of oil and gas wells based on the digital core of the rock cuttings includes the following steps: Establish a core mechanics calculation model; The core mechanical parameters are solved based on the core mechanical calculation model. Calculate the core brittleness index based on the core mechanical parameters; Calculate the silica index, ash index, and brittleness index of the oil and gas well; The mineral element brittleness index is calculated based on the silica index, the ash index, and the brittleness index: The brittleness index of the oil and gas well is calculated based on the core brittleness index and the mineral element brittleness index.

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