Methods, devices, equipment, media and products for determining drilling fluid density

Abstract

An embodiment of the present invention provides a method, device, equipment, medium, and product for determining drilling fluid density. The method includes: obtaining the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured; inputting the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate into a preset safe drilling fluid pressure calculation model to determine the safe drilling fluid pressure; and determining the safe drilling fluid density based on the safe drilling fluid pressure and a preset safe drilling fluid density algorithm. The method for determining drilling fluid density of the embodiment of the present invention can determine a safe drilling fluid pressure that matches the salt rock at the target drilling depth through the preset safe drilling fluid pressure calculation model. Based on the safe drilling fluid pressure, a safe drilling fluid density with a smaller error than the actual mud density can be determined, thereby improving the accuracy of the safe drilling fluid density.

Description

Technical Field

[0001] The embodiments of the present invention relate to the technical field of oil and gas exploration and development, and in particular to a method, device, equipment, medium and product for determining the density of drilling fluid. Background Art

[0002] Salt rock is often encountered in oil drilling projects. As a special type of rock, salt rock includes rock salt, gypsum salt rock, etc. Its significant creep characteristics can cause complex situations such as drill sticking, wellbore collapse, and wellbore abandonment during drilling projects, greatly reducing drilling efficiency.

[0003] At present, according to the creep characteristics of salt rock, the safe drilling fluid density for drilling in salt rock formations is usually designed based on viscoelastic theory or numerical simulation methods, so as to improve the drilling efficiency by determining the safe drilling fluid density.

[0004] However, the error between the safe drilling fluid density determined by the current method and the actual mud density is large, resulting in low accuracy of the determined safe drilling fluid density. Summary of the Invention

[0005] The present invention provides a method, device, equipment, medium and product for determining the density of drilling fluid, so as to solve the problem of low accuracy in the current determination of the density of safe drilling fluid.

[0006] A first aspect of an embodiment of the present invention provides a method for determining drilling fluid density, comprising:

[0007] Obtaining the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured;

[0008] Inputting the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, and the target creep rate into a preset safe drilling fluid pressure calculation model to determine the safe drilling fluid pressure;

[0009] The safety drilling fluid density is determined according to the safety drilling fluid pressure and a preset safety drilling fluid density algorithm.

[0010] Furthermore, in the above method, obtaining the maximum horizontal principal stress and the minimum horizontal principal stress of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured includes:

[0011] Obtaining ground stress parameters corresponding to a target drilling depth in the salt rock formation area to be measured;

[0012] The maximum horizontal principal stress and the minimum horizontal principal stress are determined according to the geostress parameters.

[0013] Furthermore, in the above method, the in-situ stress parameters include: vertical stress related parameters, maximum horizontal principal stress related parameters, and minimum horizontal principal stress related parameters;

[0014] Determining the maximum horizontal principal stress and the minimum horizontal principal stress according to the geostress parameter includes:

[0015] Inputting the vertical stress related parameters into a preset vertical stress algorithm to output the vertical stress through the preset vertical stress algorithm;

[0016] Inputting the vertical stress and the maximum horizontal principal stress related parameters into a preset maximum horizontal principal stress algorithm to output the maximum horizontal principal stress through the maximum horizontal principal stress algorithm;

[0017] The vertical stress and the minimum horizontal principal stress related parameters are input into a preset minimum horizontal principal stress algorithm to determine the minimum horizontal principal stress through the minimum horizontal principal stress algorithm.

[0018] Furthermore, the vertical stress related parameters in the above method include at least: formation rock density and formation rock thickness;

[0019] The maximum horizontal principal stress related parameters include at least: formation rock thickness, reservoir elastic modulus, reservoir Poisson's ratio, formation pore pressure, tectonic strain coefficient along the maximum horizontal principal stress direction, and tectonic strain coefficient along the minimum horizontal principal stress direction;

[0020] The minimum horizontal principal stress related parameters include at least: formation rock thickness, reservoir elastic modulus, reservoir Poisson's ratio, formation pore pressure, tectonic strain coefficient along the direction of maximum horizontal principal stress, and tectonic strain coefficient along the direction of minimum horizontal principal stress;

[0021] The step of obtaining a target temperature of rock salt corresponding to a target drilling depth in the salt rock formation area to be measured includes:

[0022] Obtain the geothermal gradient and target drilling depth corresponding to the salt rock formation area to be tested;

[0023] The product of the geothermal gradient and the target drilling depth is determined as the target temperature.

[0024] Furthermore, the method as described above, before determining the safe drilling fluid pressure according to the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, the target creep rate, and a preset safe drilling fluid pressure algorithm, further comprises:

[0025] Obtaining at least three different test creep rates and test environment parameters corresponding to salt rock samples corresponding to a target drilling depth in a salt rock formation area to be tested;

[0026] Inputting each of the test creep rates and test environment parameters into a preset salt rock creep algorithm to determine a creep activation energy, a first creep constant, and a second creep constant;

[0027] A safe drilling fluid pressure calculation model is constructed according to the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, the creep activation energy, the first creep constant and the second creep constant.

[0028] Furthermore, in the method described above, the test environment parameters include test temperature, test axial pressure and test confining pressure;

[0029] The preset salt rock creep algorithm is:

[0030]

[0031] in, is the creep rate, Q is the creep activation energy, R is the ideal gas constant, t is the test temperature, σ1 is the test axial pressure, σ3 is the test confining pressure, A is the first creep constant, and n is the second creep constant;

[0032] The safety drilling fluid pressure calculation model is:

[0033]

[0034] Among them, P w To ensure safe drilling fluid pressure, is the creep rate, Q is the creep activation energy, R is the ideal gas constant, T is the target temperature, σ H is the maximum horizontal principal stress, σ h is the minimum horizontal principal stress, A is the first creep constant, and n is the second creep constant.

[0035] A second aspect of an embodiment of the present invention provides a device for determining drilling fluid density, comprising:

[0036] An acquisition module is used to obtain the maximum horizontal principal stress, minimum horizontal principal stress, target temperature and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured;

[0037] a pressure determination module, configured to input the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, and the target creep rate into a preset safety drilling fluid pressure calculation model to determine the safety drilling fluid pressure;

[0038] The density determination module is used to determine the safety drilling fluid density according to the safety drilling fluid pressure and a preset safety drilling fluid density algorithm.

[0039] Furthermore, in the above-mentioned device, when obtaining the maximum horizontal principal stress and the minimum horizontal principal stress of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured, the acquisition module is specifically used to:

[0040] Obtaining in-situ stress parameters corresponding to a target drilling depth in a salt rock formation area to be measured; and determining the maximum horizontal principal stress and the minimum horizontal principal stress according to the in-situ stress parameters.

[0041] Furthermore, in the device as described above, the in-situ stress parameters include: vertical stress related parameters, maximum horizontal principal stress related parameters, and minimum horizontal principal stress related parameters;

[0042] When determining the maximum horizontal principal stress and the minimum horizontal principal stress according to the in-situ stress parameter, the acquisition module is specifically configured to:

[0043] The vertical stress-related parameters are input into a preset vertical stress algorithm to output the vertical stress through the preset vertical stress algorithm; the vertical stress and the maximum horizontal principal stress-related parameters are input into a preset maximum horizontal principal stress algorithm to output the maximum horizontal principal stress through the maximum horizontal principal stress algorithm; the vertical stress and the minimum horizontal principal stress-related parameters are input into a preset minimum horizontal principal stress algorithm to determine the minimum horizontal principal stress through the minimum horizontal principal stress algorithm.

[0044] Furthermore, in the above-mentioned device, the vertical stress-related parameters include at least: formation rock density and formation rock thickness;

[0045] The maximum horizontal principal stress related parameters include at least: formation rock thickness, reservoir elastic modulus, reservoir Poisson's ratio, formation pore pressure, tectonic strain coefficient along the maximum horizontal principal stress direction, and tectonic strain coefficient along the minimum horizontal principal stress direction;

[0046] The minimum horizontal principal stress related parameters include at least: formation rock thickness, reservoir elastic modulus, reservoir Poisson's ratio, formation pore pressure, tectonic strain coefficient along the direction of maximum horizontal principal stress, and tectonic strain coefficient along the direction of minimum horizontal principal stress;

[0047] When acquiring the target temperature of rock salt corresponding to the target drilling depth in the salt rock formation area to be measured, the acquisition module is specifically used to:

[0048] Obtaining a geothermal gradient and a target drilling depth corresponding to a salt rock formation area to be measured; and determining the target temperature as the product of the geothermal gradient and the target drilling depth.

[0049] Furthermore, the device as described above further comprises:

[0050] A construction module is used to obtain at least three different test creep rates and test environment parameters corresponding to salt rock samples corresponding to a target drilling depth in a salt rock formation area to be tested; input each of the test creep rates and test environment parameters into a preset salt rock creep algorithm to determine creep activation energy, a first creep constant, and a second creep constant; and construct a safe drilling fluid pressure calculation model based on the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, the creep activation energy, the first creep constant, and the second creep constant.

[0051] Furthermore, in the above-mentioned device, the test environment parameters include test temperature, test axial pressure and test confining pressure; the preset salt rock creep algorithm is:

[0052]

[0053] in, is the creep rate, Q is the creep activation energy, R is the ideal gas constant, t is the test temperature, σ1 is the test axial pressure, σ3 is the test confining pressure, A is the first creep constant, and n is the second creep constant;

[0054] The safety drilling fluid pressure calculation model is:

[0055]

[0056] Among them, P w To ensure safe drilling fluid pressure, is the creep rate, Q is the creep activation energy, R is the ideal gas constant, T is the target temperature, σ H is the maximum horizontal principal stress, σ h is the minimum horizontal principal stress, A is the first creep constant, and n is the second creep constant.

[0057] A third aspect of an embodiment of the present invention provides an electronic device, including: a memory, a processor;

[0058] Memory; a memory for storing instructions executable by the processor;

[0059] Wherein, the processor is configured to execute the method for determining the drilling fluid density described in any one of the first aspects.

[0060] A fourth aspect of an embodiment of the present invention provides a computer-readable storage medium, wherein the computer-readable storage medium stores computer-executable instructions, and when the computer-executable instructions are executed by a processor, they are used to implement the method for determining the drilling fluid density described in any one of the first aspects.

[0061] A fifth aspect of an embodiment of the present invention provides a computer program product, comprising a computer program, which, when executed by a processor, implements the method for determining the drilling fluid density described in any one of the first aspects.

[0062] Embodiments of the present invention provide a method, apparatus, device, medium, and product for determining drilling fluid density. The method comprises: obtaining the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to a target drilling depth in a salt rock formation region to be measured; inputting the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate into a preset safe drilling fluid pressure calculation model to determine a safe drilling fluid pressure; and determining the safe drilling fluid density based on the safe drilling fluid pressure and a preset safe drilling fluid density algorithm. The method for determining drilling fluid density in the embodiment of the present invention first obtains the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation region to be measured. Because the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate are highly correlated with the creep properties of the salt rock, inputting the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate into the preset safe drilling fluid pressure calculation model can determine a safe drilling fluid pressure that better matches the salt rock corresponding to the target drilling depth. Finally, the safety drilling fluid density with a smaller error than the actual mud density can be determined according to the safety drilling fluid pressure, thereby improving the accuracy of the safety drilling fluid density. BRIEF DESCRIPTION OF THE DRAWINGS

[0063] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments consistent with the invention and, together with the description, serve to explain the principles of the invention.

[0064] Figure 1 A diagram showing a scenario in which the method for determining the drilling fluid density according to an embodiment of the present invention can be implemented;

[0065] Figure 2 A schematic flow chart of a method for determining drilling fluid density provided in a first embodiment of the present invention;

[0066] Figure 3 A schematic flow chart of a method for determining drilling fluid density provided in a second embodiment of the present invention;

[0067] Figure 4 A schematic flow chart of a method for determining drilling fluid density provided in a third embodiment of the present invention;

[0068] Figure 5 A comparison chart of the safe drilling fluid density and the actual mud density according to the method for determining the drilling fluid density provided by the third embodiment of the present invention;

[0069] Figure 6 A schematic structural diagram of a device for determining drilling fluid density according to a fourth embodiment of the present invention;

[0070] Figure 7 A schematic structural diagram of a device for determining drilling fluid density according to a fifth embodiment of the present invention;

[0071] Figure 8 This is a structural diagram of an electronic device provided by a sixth embodiment of the present invention.

[0072] The above drawings illustrate specific embodiments of the present invention, which will be described in more detail below. These drawings and the accompanying description are not intended to limit the scope of the present invention in any way, but rather to illustrate the concept of the present invention to those skilled in the art by reference to specific embodiments. DETAILED DESCRIPTION

[0073] Exemplary embodiments will be described in detail herein, examples of which are illustrated in the accompanying drawings. In the following description, when referring to the drawings, like numbers in different figures represent like or similar elements unless otherwise indicated. The embodiments described in the following exemplary embodiments are not intended to represent all possible embodiments consistent with the present invention. Rather, they are merely examples of apparatus and methods consistent with certain aspects of the present invention, as detailed in the appended claims.

[0074] The technical solution of the present invention is described in detail below with specific embodiments. The following specific embodiments can be combined with each other, and the same or similar concepts or processes may not be repeated in some embodiments. The embodiments of the present invention will be described below with reference to the accompanying drawings.

[0075] To clearly understand the technical solution of this application, we first provide a detailed introduction to the existing technical solutions. Salt rock is often encountered in oil drilling projects. Its significant creep characteristics can cause complex situations such as stuck drill, wellbore collapse, and wellbore abandonment, significantly impacting oil drilling operations. Therefore, the smooth drilling of salt rock formations is of great significance in drilling projects.

[0076] In the existing technology, in view of the creep characteristics of salt rock, the safe drilling fluid density for drilling in salt rock formations is usually designed based on viscoelastic theory or numerical simulation methods. Drilling fluid is a general term for various circulating fluids that meet the needs of drilling work with their multiple functions during the drilling process. The safe drilling fluid density refers to the drilling fluid density that can prevent formation fluid from invading the wellbore and does not overflow. The safe drilling fluid density determined in the existing technology has a low degree of match with the actual situation of the target drilling depth in the rock salt area to be tested, and is a universal determination method. Therefore, the error between the currently determined safe drilling fluid density and the actual mud density is large, resulting in inaccurate determined safe drilling fluid density.

[0077] Therefore, in order to address the problem that the safe drilling fluid density determined in the prior art has a large error between the actual mud density and the safe drilling fluid density, resulting in an inaccurate safe drilling fluid density, the inventors discovered that in order to solve the problem of the large error between the safe drilling fluid density determined in the prior art and the actual mud density, resulting in an inaccurate safe drilling fluid density, a safe drilling fluid pressure calculation model and a safe drilling fluid density algorithm can be pre-established. By combining the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the target drilling depth with the algorithm and model, a safe drilling fluid density that better matches the target drilling depth in the rock salt area to be measured is determined. Specifically, the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation to be measured are first obtained. Since the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate are highly correlated with the creep properties of the salt rock, the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate are input into the preset safe drilling fluid pressure calculation model to determine the safe drilling fluid pressure that matches the salt rock corresponding to the target drilling depth. Finally, the safe drilling fluid density with a smaller error than the actual mud density can be determined based on the safe drilling fluid pressure, thereby improving the accuracy of the safe drilling fluid density. Furthermore, drilling in salt formations using the determined safe drilling fluid density with a smaller error than the actual mud density can improve drilling efficiency.

[0078] Based on the above creative findings, the inventor proposed the technical solution of this application.

[0079] The following describes the application scenarios of the method for determining the density of drilling fluid provided by the embodiment of the present invention. Figure 1As shown, 1 is a first electronic device and 2 is a second electronic device. The network architecture of the application scenario corresponding to the method for determining drilling fluid density provided in an embodiment of the present invention includes: a first electronic device 1 and a second electronic device 2. The second electronic device 2 stores relevant parameter data of the salt rock corresponding to each drilling depth in the salt rock formation area to be measured, such as the maximum horizontal principal stress, minimum horizontal principal stress, temperature, and creep rate. When it is necessary to determine the safe drilling fluid density corresponding to the target drilling depth in the salt rock formation area to be measured, the first electronic device 1 obtains the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured from the second electronic device 2. The first electronic device 1 then inputs the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate into a preset safe drilling fluid pressure calculation model to determine the corresponding safe drilling fluid pressure. Simultaneously, the first electronic device 1 determines a safe drilling fluid density with a smaller error than the actual mud density based on the safe drilling fluid pressure. The determined safe drilling fluid density can be output to other electronic devices, such as drilling-related control equipment, so that the corresponding control equipment can control the safe drilling fluid density during the drilling process, thereby improving drilling efficiency. Furthermore, the first electronic device 1 can also be used as a drilling control device to control the safe drilling fluid density during the drilling process.

[0080] The embodiments of the present invention are described below with reference to the accompanying drawings.

[0081] Figure 2 A flow chart of a method for determining the density of drilling fluid provided in the first embodiment of the present invention is shown as follows: Figure 2 As shown, in this embodiment, the execution subject of the embodiment of the present invention is a device for determining the density of drilling fluid, which can be integrated into an electronic device. The method for determining the density of drilling fluid provided in this embodiment includes the following steps:

[0082] Step S101 : obtaining the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured.

[0083] In this embodiment, in oil drilling projects, the drilling depths in the same salt rock formation area are usually different. Therefore, when determining the safe drilling fluid density, it is necessary to consider the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the drilling depth.

[0084] Maximum and minimum horizontal principal stresses are considered geostress. Geostress is stress existing in the Earth's crust. When an object deforms due to external factors (such as force, humidity, or temperature changes), stress is an internal force that interacts between its components to resist the external factors and attempt to restore the object to its pre-deformation position. Salt formations refer to rock salt formations and gypsum salt formations. Creep rate refers to the time derivative of elongation during creep deformation of a material at high temperatures.

[0085] In this embodiment, the creep rate can be obtained in either of the following two ways: The first way is to directly measure the creep rate of the salt rock formation area to be measured. The other way is to apply the corresponding temperature and ground stress of the salt rock formation area to be measured to a salt rock sample, and measure the creep rate of the salt rock sample as the creep rate of the salt rock formation in the area to be drilled. Therefore, the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured can be obtained from a database storing the corresponding parameter data, or from other data acquisition equipment, which is not limited in this embodiment.

[0086] Step S102: input the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, and the target creep rate into a preset safe drilling fluid pressure calculation model to determine the safe drilling fluid pressure.

[0087] In this embodiment, the safe drilling fluid pressure calculation model is pre-built and combines the maximum horizontal principal stress, minimum horizontal principal stress, target temperature and target creep rate associated with the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured.

[0088] Step S103: Determine the safety drilling fluid density according to the safety drilling fluid pressure and a preset safety drilling fluid density algorithm.

[0089] In this embodiment, drilling fluid is a general term for various circulating fluids used during the drilling process to fulfill drilling requirements through their various functions. The safe drilling fluid pressure refers to the pressure that prevents formation fluid from invading the wellbore and causing overflow. Similarly, the safe drilling fluid density refers to the drilling fluid density that prevents formation fluid from invading the wellbore and causing overflow.

[0090] An embodiment of the present invention provides a method for determining drilling fluid density. The method includes obtaining the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to a target drilling depth in a salt rock formation region to be measured. The maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate are input into a preset safe drilling fluid pressure calculation model to determine a safe drilling fluid pressure. The safe drilling fluid density is determined based on the safe drilling fluid pressure and a preset safe drilling fluid density algorithm. The method for determining drilling fluid density in an embodiment of the present invention first obtains the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation region to be measured. Because the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate are highly correlated with the creep properties of the salt rock, inputting the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate into the preset safe drilling fluid pressure calculation model can determine a safe drilling fluid pressure that matches the salt rock corresponding to the target drilling depth. Finally, the safe drilling fluid density with a smaller error than the actual mud density can be determined based on the safe drilling fluid pressure, thereby improving the accuracy of the safe drilling fluid density. Furthermore, drilling in salt formations using the determined safe drilling fluid density with a smaller error than the actual mud density can improve drilling efficiency.

[0091] Figure 3 A flow chart of a method for determining the density of drilling fluid provided in the second embodiment of the present invention is shown as follows: Figure 3 As shown, the method for determining the drilling fluid density provided in this embodiment is based on the method for determining the drilling fluid density provided in the previous embodiment of the present invention, and further refines each step. The method for determining the drilling fluid density provided in this embodiment includes the following steps.

[0092] Step S201: Obtaining the ground stress parameters and target creep rate corresponding to the target drilling depth in the salt rock formation area to be measured.

[0093] In this embodiment, the ground stress parameters mainly include vertical stress related parameters, maximum horizontal principal stress related parameters and minimum horizontal principal stress related parameters, such as formation rock density, formation rock thickness, reservoir Poisson's ratio and formation pore pressure.

[0094] Step S202: determining the maximum horizontal principal stress and the minimum horizontal principal stress according to the in-situ stress parameters.

[0095] In this embodiment, since the maximum horizontal principal stress and the minimum horizontal principal stress belong to the in-situ stress, the maximum horizontal principal stress and the minimum horizontal principal stress can be determined by the in-situ stress parameters.

[0096] The geostress parameters may be obtained from a database storing geostress parameters, or may be directly measured in the salt rock formation in the drilling area using a well logging instrument, which is not limited in this embodiment.

[0097] Optionally, in this embodiment, the geostress parameters include: vertical stress related parameters, maximum horizontal principal stress related parameters, and minimum horizontal principal stress related parameters.

[0098] Determining the maximum horizontal principal stress and the minimum horizontal principal stress based on the ground stress parameters includes:

[0099] The vertical stress related parameters are input into a preset vertical stress algorithm to output the vertical stress through the preset vertical stress algorithm.

[0100] At the same time, the vertical stress and maximum horizontal principal stress related parameters are input into the preset maximum horizontal principal stress algorithm to output the maximum horizontal principal stress through the maximum horizontal principal stress algorithm.

[0101] The vertical stress and minimum horizontal principal stress related parameters are input into a preset minimum horizontal principal stress algorithm to determine the minimum horizontal principal stress through the minimum horizontal principal stress algorithm.

[0102] In this embodiment, the in-situ stress includes vertical stress, maximum horizontal principal stress, and minimum horizontal principal stress. Therefore, the in-situ stress parameters may include vertical stress-related parameters, maximum horizontal principal stress-related parameters, and minimum horizontal principal stress-related parameters.

[0103] Optionally, in this embodiment, the vertical stress-related parameters include at least: formation rock density and formation rock thickness.

[0104] The parameters related to the maximum horizontal principal stress include at least: formation rock thickness, elastic modulus of the reservoir, Poisson's ratio of the reservoir, formation pore pressure, tectonic strain coefficient along the direction of the maximum horizontal principal stress, and tectonic strain coefficient along the direction of the minimum horizontal principal stress.

[0105] The minimum horizontal principal stress related parameters include at least: formation rock thickness, reservoir elastic modulus, reservoir Poisson's ratio, formation pore pressure, tectonic strain coefficient along the maximum horizontal principal stress direction, and tectonic strain coefficient along the minimum horizontal principal stress direction.

[0106] In this embodiment, the preset vertical stress algorithm, the preset maximum horizontal principal stress algorithm, and the preset minimum horizontal principal stress algorithm are:

[0107]

[0108] Among them, σ v is the vertical stress, ρ i is the density of the formation rock, g is the acceleration of gravity, h isi is the thickness of the formation rock. H is the maximum horizontal principal stress, E is the elastic modulus of the reservoir, μ is the Poisson's ratio of the reservoir, P p is the formation pore pressure, α is the Biot coefficient, ε H is the structural strain coefficient along the direction of the maximum horizontal principal stress, ε h is the structural strain coefficient along the direction of the minimum horizontal principal stress, σ h is the minimum horizontal principal stress.

[0109] Formation rock density ρ i It means that from the surface to the reservoir, there are multiple rock layers, each with different density. The gravity acceleration g is 9.8m / s 2 , formation rock thickness h i Indicates that from the surface to the reservoir, there are multiple rock layers, each with different thicknesses. The structural strain coefficient ε along the direction of the maximum horizontal principal stress H and the structural strain coefficient ε along the direction of minimum horizontal principal stress h The value of is usually obtained based on rock mechanics experiments and experience with salt rock formations in the area to be drilled, and can be set according to actual needs, which is not limited in this embodiment.

[0110] Step S203: obtaining the geothermal gradient and target drilling depth corresponding to the salt rock formation area to be measured.

[0111] In this embodiment, the geothermal gradient refers to the rate of increase in the temperature of the earth's strata that are not affected by the atmospheric temperature as the depth increases. The temperatures of strata at different depths are different.

[0112] Step S204: The product of the geothermal gradient and the target drilling depth is determined as the target temperature.

[0113] In this embodiment, the target temperature is related to the geothermal gradient and the target drilling depth, and the following temperature algorithm can be used:

[0114] T=kH

[0115] Where T is the target temperature, k is the geothermal gradient, and H is the target drilling depth.

[0116] Step S205 : inputting the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, and the target creep rate into a preset safe drilling fluid pressure calculation model to determine the safe drilling fluid pressure.

[0117] In this embodiment, the implementation of step 205 is similar to the implementation of step 102 in the previous embodiment of the present invention, and will not be described in detail here.

[0118] Step S206: Determine the safety drilling fluid density according to the safety drilling fluid pressure and a preset safety drilling fluid density algorithm.

[0119] In this embodiment, the implementation of step 206 is similar to the implementation of step 103 in the previous embodiment of the present invention, and will not be described in detail here.

[0120] An embodiment of the present invention provides a method for determining drilling fluid density. This method obtains in-situ stress parameters and combines them with a preset vertical stress algorithm, a preset maximum horizontal principal stress algorithm, and a preset minimum horizontal principal stress algorithm to determine the maximum and minimum horizontal principal stresses. By combining the in-situ stress parameters with multiple algorithms, the maximum and minimum horizontal principal stresses are determined with greater accuracy, providing a foundation for subsequent determination of a more accurate and safe drilling fluid density.

[0121] Figure 4 Schematic diagram of the flow chart of the method for determining the density of drilling fluid provided by the third embodiment of the present invention. Figure 4 As shown, the method for determining drilling fluid density provided in this embodiment is based on the method for determining drilling fluid density provided in the previous embodiment of the present invention, but adds the step of constructing a safe drilling fluid pressure calculation model. The method for determining drilling fluid density provided in this embodiment includes the following steps.

[0122] Step S301 : obtaining at least three different test creep rates and test environment parameters corresponding to salt rock samples corresponding to a target drilling depth in a salt rock formation area to be tested.

[0123] In this embodiment, since the safe drilling fluid pressure calculation model requires three parameters whose values ​​must be determined, at least three different creep rate tests are required. Furthermore, these three creep rate tests must be conducted under different temperatures and geostress conditions. Each creep rate test must be conducted under different temperature and geostress conditions.

[0124] The test environment parameters include test temperature, test axial pressure and test confining pressure, which are the parameters of the test environment corresponding to the test of salt rock samples.

[0125] Step S302: Input each test creep rate and test environment parameter into a preset salt rock creep algorithm to determine creep activation energy, a first creep constant, and a second creep constant.

[0126] In this embodiment, the creep activation energy, the first creep constant, and the second creep constant are three parameters that must be determined in the safe drilling fluid pressure calculation model. Creep activation energy refers to the thermal activation energy that controls the steady-state creep rate. The creep rate increases with increasing temperature. Creep activation energy is the energy required to implement the creep meta-process, and its value reflects the difficulty of the meta-process. The first and second creep constants are constants used in creep experiments.

[0127] The test environment parameters include test temperature, test axial pressure and test confining pressure. The preset salt rock creep algorithm is:

[0128]

[0129] in, is the creep rate, Q is the creep activation energy, R is the ideal gas constant, t is the test temperature, σ1 is the test axial pressure, σ3 is the test confining pressure, A is the first creep constant, and n is the second creep constant.

[0130] Substituting multiple measured creep rates into the aforementioned salt rock creep algorithm yields multiple equations. Each of these equations contains three unknown parameters: the creep activation energy Q, the first creep constant A, and the second creep constant n. Solving these equations simultaneously allows the calculation of the creep activation energy Q, the first creep constant A, and the second creep constant n. The more creep rates measured, the more accurate the first creep constant A and the second creep constant n determined using the salt rock creep algorithm.

[0131] Step S303: constructing a safe drilling fluid pressure calculation model according to the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, the creep activation energy, the first creep constant, and the second creep constant.

[0132] In this embodiment, the safety drilling fluid pressure calculation model is composed of the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, the creep activation energy, the first creep constant, and the second creep constant. Since each parameter is highly correlated with the salt rock corresponding to the salt rock formation area to be measured, the safety drilling fluid pressure determined by the safety drilling fluid pressure calculation model is more accurate.

[0133] Among them, the calculation model of safe drilling fluid pressure is:

[0134]

[0135] Among them, P w To ensure safe drilling fluid pressure, is the creep rate, Q is the creep activation energy, R is the ideal gas constant, T is the target temperature, σ H is the maximum horizontal principal stress, σ his the minimum horizontal principal stress, A is the first creep constant, and n is the second creep constant.

[0136] In order to better illustrate the solution of this embodiment, the following will take the safe drilling fluid density of salt rock formation in a certain drilling area as an example. When drilling in the 6008-6055m section, salt rock formation is encountered. Figure 5 As shown in the figure, the straight line is the actual mud density, and the broken line with triangles is the determined safe drilling fluid density, which is the calculated equivalent density in the figure. The actual mud density, that is, the safe drilling fluid density used in practice, is 2.32g / cm 3 , the safe drilling fluid density determined by the embodiment of the present invention is Figure 5 At a well depth of 6037 meters, the safety drilling fluid density determined using the embodiment of the present invention is the safety drilling fluid density farthest to the left of the actual mud density. At this time, the error between the determined safety drilling fluid density and the actual mud density reaches a negative maximum value, which is only 0.06 g / cm away from the actual mud density. 3 At a well depth of 6046 m, the safety drilling fluid density determined using the embodiment of the present invention is the safety drilling fluid density that is farthest to the right of the actual mud density. The error between the determined safety drilling fluid density and the actual mud density reaches a positive maximum value, which differs from the actual mud density by only 0.06 g / cm 3 . Therefore, the safety drilling fluid density calculated by the embodiment of the present invention is slightly different from the actual mud density, and except for the well depths of 6037m and 6046m, the safety drilling fluid density calculated using the embodiment of the present invention is closer to the actual mud density and has a smaller difference from the actual mud density. It can be seen that the error between the safety drilling fluid density calculated according to the safety drilling fluid pressure of the embodiment of the present invention and the actual mud density is smaller, and the determined safety drilling fluid density is more accurate. In subsequent drilling projects, drilling salt rock formations according to a more accurate safety drilling fluid density can more effectively prevent wellbore shrinkage, reduce drilling time, and thus improve drilling efficiency.

[0137] Figure 6 A schematic diagram of the structure of a device for determining the density of drilling fluid provided in a fourth embodiment of the present invention is shown in FIG. Figure 6 As shown, in this embodiment, the drilling fluid density determination device 400 includes:

[0138] The acquisition module 401 is used to obtain the maximum horizontal principal stress, minimum horizontal principal stress, target temperature and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured.

[0139] The pressure determination module 402 is used to input the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, and the target creep rate into a preset safety drilling fluid pressure calculation model to determine the safety drilling fluid pressure.

[0140] The density determination module 403 is configured to determine the safety drilling fluid density according to the safety drilling fluid pressure and a preset safety drilling fluid density algorithm.

[0141] The drilling fluid density determination device provided in this embodiment can be executed Figure 2 The technical solution of the method embodiment shown in the figure has the same implementation principle and technical effect as Figure 2 The method embodiments shown are similar and will not be described in detail here.

[0142] at the same time, Figure 7 A schematic diagram of the structure of a device for determining the density of drilling fluid provided in a fifth embodiment of the present invention is shown in FIG. Figure 7 As shown, the device for determining the drilling fluid density provided by the present invention is a device for determining the drilling fluid density provided by the previous embodiment, and the device for determining the drilling fluid density 500 is further refined.

[0143] Optionally, in this embodiment, when obtaining the maximum horizontal principal stress and the minimum horizontal principal stress of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured, the acquisition module 401 is specifically configured to:

[0144] Obtain the in-situ stress parameters corresponding to the target drilling depth in the salt rock formation area to be measured. Determine the maximum horizontal principal stress and the minimum horizontal principal stress based on the in-situ stress parameters.

[0145] Optionally, in this embodiment, the geostress parameters include: vertical stress related parameters, maximum horizontal principal stress related parameters, and minimum horizontal principal stress related parameters.

[0146] When determining the maximum horizontal principal stress and the minimum horizontal principal stress according to the in-situ stress parameters, the acquisition module 401 is specifically configured to:

[0147] Input parameters related to vertical stress into a preset vertical stress algorithm to output the vertical stress using the preset vertical stress algorithm. Input parameters related to vertical stress and maximum horizontal principal stress into a preset maximum horizontal principal stress algorithm to output the maximum horizontal principal stress using the maximum horizontal principal stress algorithm. Input parameters related to vertical stress and minimum horizontal principal stress into a preset minimum horizontal principal stress algorithm to determine the minimum horizontal principal stress using the minimum horizontal principal stress algorithm.

[0148] Optionally, in this embodiment, the vertical stress-related parameters include at least: formation rock density and formation rock thickness.

[0149] The parameters related to the maximum horizontal principal stress include at least: formation rock thickness, elastic modulus of the reservoir, Poisson's ratio of the reservoir, formation pore pressure, tectonic strain coefficient along the direction of the maximum horizontal principal stress, and tectonic strain coefficient along the direction of the minimum horizontal principal stress.

[0150] The minimum horizontal principal stress related parameters include at least: formation rock thickness, reservoir elastic modulus, reservoir Poisson's ratio, formation pore pressure, tectonic strain coefficient along the maximum horizontal principal stress direction, and tectonic strain coefficient along the minimum horizontal principal stress direction.

[0151] Meanwhile, when acquiring the target temperature of the rock salt corresponding to the target drilling depth in the salt rock formation area to be measured, the acquisition module 401 is specifically used to:

[0152] Obtain the geothermal gradient and target drilling depth corresponding to the salt rock formation area to be measured. The product of the geothermal gradient and the target drilling depth is determined as the target temperature.

[0153] Optionally, in this embodiment, the drilling fluid density determination device 500 further includes:

[0154] Construction module 501 is configured to obtain at least three different test creep rates and test environment parameters corresponding to salt rock samples at a target drilling depth in the salt rock formation to be tested. Each test creep rate and test environment parameter is input into a preset salt rock creep algorithm to determine the creep activation energy, the first creep constant, and the second creep constant. A safe drilling fluid pressure calculation model is constructed based on the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, the creep activation energy, the first creep constant, and the second creep constant.

[0155] Optionally, in this embodiment, the test environment parameters include test temperature, test axial pressure and test confining pressure.

[0156] The default salt rock creep algorithm is:

[0157]

[0158] in, is the creep rate, Q is the creep activation energy, R is the ideal gas constant, t is the test temperature, σ1 is the test axial pressure, σ3 is the test confining pressure, A is the first creep constant, and n is the second creep constant.

[0159] The calculation model of safe drilling fluid pressure is:

[0160]

[0161] Among them, P w To ensure safe drilling fluid pressure, is the creep rate, Q is the creep activation energy, R is the ideal gas constant, T is the target temperature, σH is the maximum horizontal principal stress, σ h is the minimum horizontal principal stress, A is the first creep constant, and n is the second creep constant.

[0162] The drilling fluid density determination device provided in this embodiment can be executed Figure 2-Figure 5 The technical solution of the method embodiment shown in the figure has the same implementation principle and technical effect as Figure 2-Figure 5 The method embodiments shown are similar and will not be described in detail here.

[0163] According to an embodiment of the present invention, the present invention further provides an electronic device, a computer-readable storage medium, and a computer program product.

[0164] like Figure 8 As shown, Figure 8 : is a schematic diagram of the structure of an electronic device provided by the sixth embodiment of the present invention. The electronic device is intended to be various forms of digital computers, such as laptop computers, desktop computers, workstations, personal digital assistants, servers, blade servers, mainframe computers, and other suitable computers. The electronic device may also represent various forms of mobile devices, such as personal digital assistants, cellular phones, smart phones, wearable devices, and other similar computing devices. The components shown herein, their connections and relationships, and their functions are merely examples and are not intended to limit the implementation of the present invention described and / or claimed herein.

[0165] like Figure 8 As shown, the electronic device includes: a processor 601 and a memory 602. The various components are connected to each other using different buses and can be installed on a common motherboard or in other ways as needed. The processor can process instructions executed in the electronic device.

[0166] Memory 602 is the non-transitory computer-readable storage medium provided by the present invention. The memory stores instructions executable by at least one processor, causing the at least one processor to perform the method for determining drilling fluid density provided by the present invention. The non-transitory computer-readable storage medium of the present invention stores computer instructions for causing a computer to perform the method for determining drilling fluid density provided by the present invention.

[0167] The memory 602 is a non-transient computer-readable storage medium that can be used to store non-transient software programs, non-transient computer executable programs and modules, such as the program instructions / modules corresponding to the method for determining the density of drilling fluid in the embodiment of the present invention (for example, the attached Figure 6The processor 601 executes the non-transient software programs, instructions, and modules stored in the memory 602 to execute various functional applications and data processing of the server, thereby implementing the method for determining the drilling fluid density in the above method embodiment.

[0168] At the same time, this embodiment also provides a computer product. When the instructions in the computer product are executed by the processor of the electronic device, the electronic device can execute the method for determining the drilling fluid density of the above-mentioned embodiments one to three.

[0169] Those skilled in the art will readily recognize other embodiments of the present invention after considering the specification and practicing the invention disclosed herein. The present invention is intended to cover any variations, uses, or adaptations of the present invention that follow the general principles of the present invention and include common knowledge or customary techniques in the art not disclosed in the present invention. The specification and examples are to be considered as exemplary only, with the true scope and spirit of the present invention being indicated by the following claims.

[0170] It should be understood that the embodiments of the present invention are not limited to the precise structures described above and shown in the drawings, and various modifications and changes can be made without departing from the scope thereof. The scope of the embodiments of the present invention is limited only by the appended claims.

Claims

1. A method for determining the density of a drilling fluid, characterized in that: include: Obtaining the maximum horizontal principal stress, minimum horizontal principal stress, target temperature, and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured; Inputting the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, and the target creep rate into a preset safe drilling fluid pressure calculation model to determine the safe drilling fluid pressure; The safety drilling fluid density is determined according to the safety drilling fluid pressure and a preset safety drilling fluid density algorithm.

2. The method according to claim 1, characterized in that The step of obtaining the maximum horizontal principal stress and the minimum horizontal principal stress of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured includes: Obtaining ground stress parameters corresponding to a target drilling depth in the salt rock formation area to be measured; The maximum horizontal principal stress and the minimum horizontal principal stress are determined according to the geostress parameters.

3. The method according to claim 2, characterized in that The in-situ stress parameters include: vertical stress related parameters, maximum horizontal principal stress related parameters and minimum horizontal principal stress related parameters; Determining the maximum horizontal principal stress and the minimum horizontal principal stress according to the geostress parameter includes: Inputting the vertical stress related parameters into a preset vertical stress algorithm to output the vertical stress through the preset vertical stress algorithm; Inputting the vertical stress and the maximum horizontal principal stress related parameters into a preset maximum horizontal principal stress algorithm to output the maximum horizontal principal stress through the maximum horizontal principal stress algorithm; The vertical stress and the minimum horizontal principal stress related parameters are input into a preset minimum horizontal principal stress algorithm to determine the minimum horizontal principal stress through the minimum horizontal principal stress algorithm.

4. The method according to claim 3, characterized in that The vertical stress related parameters include at least: formation rock density and formation rock thickness; The maximum horizontal principal stress related parameters include at least: formation rock thickness, reservoir elastic modulus, reservoir Poisson's ratio, formation pore pressure, tectonic strain coefficient along the maximum horizontal principal stress direction, and tectonic strain coefficient along the minimum horizontal principal stress direction; The minimum horizontal principal stress related parameters include at least: formation rock thickness, reservoir elastic modulus, reservoir Poisson's ratio, formation pore pressure, tectonic strain coefficient along the direction of maximum horizontal principal stress, and tectonic strain coefficient along the direction of minimum horizontal principal stress; The step of obtaining a target temperature of rock salt corresponding to a target drilling depth in the salt rock formation area to be measured includes: Obtain the geothermal gradient and target drilling depth corresponding to the salt rock formation area to be tested; The product of the geothermal gradient and the target drilling depth is determined as the target temperature.

5. The method according to any one of claims 1 to 4, characterized in that Before determining the safe drilling fluid pressure according to the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, the target creep rate, and a preset safe drilling fluid pressure algorithm, the method further includes: Obtaining at least three different test creep rates and test environment parameters corresponding to salt rock samples corresponding to a target drilling depth in a salt rock formation area to be tested; Inputting each of the test creep rates and test environment parameters into a preset salt rock creep algorithm to determine a creep activation energy, a first creep constant, and a second creep constant; A safe drilling fluid pressure calculation model is constructed according to the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, the creep activation energy, the first creep constant and the second creep constant.

6. The method according to claim 5, characterized in that The test environment parameters include test temperature, test axial pressure and test confining pressure; The preset salt rock creep algorithm is: in, is the creep rate, Q is the creep activation energy, R is the ideal gas constant, t is the test temperature, σ1 is the test axial pressure, σ3 is the test confining pressure, A is the first creep constant, and n is the second creep constant; The safety drilling fluid pressure calculation model is: Among them, P w To ensure safe drilling fluid pressure, is the creep rate, Q is the creep activation energy, R is the ideal gas constant, T is the target temperature, σ H is the maximum horizontal principal stress, σ h is the minimum horizontal principal stress, A is the first creep constant, and n is the second creep constant.

7. A device for determining the density of drilling fluid, characterized in that: include: An acquisition module is used to obtain the maximum horizontal principal stress, minimum horizontal principal stress, target temperature and target creep rate of the salt rock corresponding to the target drilling depth in the salt rock formation area to be measured; a pressure determination module, configured to input the maximum horizontal principal stress, the minimum horizontal principal stress, the target temperature, and the target creep rate into a preset safety drilling fluid pressure calculation model to determine the safety drilling fluid pressure; The density determination module is used to determine the safety drilling fluid density according to the safety drilling fluid pressure and a preset safety drilling fluid density algorithm.

8. An electronic device, characterized in that: include: Memory, processor; Memory; a memory for storing instructions executable by the processor; The processor is configured to execute the method for determining the drilling fluid density according to any one of claims 1 to 6.

9. A computer-readable storage medium, characterized in that The computer-readable storage medium stores computer-executable instructions, which, when executed by a processor, are used to implement the method for determining the drilling fluid density according to any one of claims 1 to 6.

10. A computer program product comprising a computer program, characterized in that When the computer program is executed by a processor, the method for determining the drilling fluid density according to any one of claims 1 to 6 is implemented.

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