A gas logging experimental device and method based on the flow state of drilling fluid in a wellbore

Abstract

The present application belongs to the field of petroleum and natural gas logging engineering, and particularly relates to a gas logging experiment device and method based on the flow state of drilling fluid in a wellbore, aiming at solving the problem that the influence of the flow state of drilling fluid on gas logging data cannot be analyzed in the prior art. The present application comprises a drilling fluid injection module, a drilling fluid flow state excitation module, a gas sample injection module and a data processing module. The drilling fluid injection module is used for injecting drilling fluid into the annulus of the wellbore. The drilling fluid flow state excitation module is used for exciting the flow state of drilling fluid as laminar flow or turbulent flow. The gas sample injection module is used for simulating the uniform gas inlet process of the gas sample along the well wall. The data processing module is connected with the drilling fluid flow state excitation module, and is used for processing the upflowing drilling fluid through gas logging analysis, degassing and recovery. The present application simulates the state of drilling fluid under different conditions, realizes different flow states of drilling fluid in the wellbore, and can analyze the influence of the flow state of drilling fluid on gas logging data.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas logging engineering, and specifically relates to a gas logging experimental device and method based on the flow state of drilling fluid in the wellbore. Background Technology

[0002] Gas logging is a key technology in oil and gas reservoir development. This technology reveals reservoir oil and gas information by analyzing the hydrocarbon gas content in the backflow drilling fluid. However, the hydrocarbon gas content in the backflow drilling fluid is affected by many factors, such as drilling fluid parameters (density, viscosity, temperature), drilling fluid flow regime, and bottom hole pressure fluctuations, which to some extent interfere with the accuracy of gas logging. Among these factors, the influence of drilling fluid flow regime on gas logging has not been discussed. Drilling fluid flow regimes can be laminar or turbulent, and different flow regimes will affect the migration of hydrocarbon gases in the wellbore, leading to distortion of gas logging data. Therefore, there is an urgent need to develop a gas logging experimental device and method that considers the drilling fluid flow regime in the wellbore to obtain the influence law of drilling fluid flow regime on gas logging data.

[0003] Through literature review, some gas logging experimental devices have been developed to discuss the impact of different factors on gas logging data. For example, patents with application number CN201720060698.5 ("A Downhole Gas Logging Testing Device While Drilling"), application number CN201910717334.3 ("A Fourier Transform Infrared Gas Logging Method and Device"), and application number CN202011123186.1 ("A Gas Logging Data Detection Device for Simulating Wellbore Environment") cannot achieve different drilling fluid flow states in the wellbore, and therefore cannot analyze the impact of drilling fluid flow states on gas logging data.

[0004] Based on this, the present invention provides a gas logging experimental device and method based on the flow state of drilling fluid in the wellbore. Summary of the Invention

[0005] To address the aforementioned problems in the prior art, namely the inability to achieve different drilling fluid flow states within the wellbore, thus hindering the analysis of the impact of drilling fluid flow states on gas logging data, this invention provides a gas logging experimental device and method based on drilling fluid flow states within the wellbore.

[0006] In a first aspect, the present invention proposes a gas logging experimental device based on the flow state of drilling fluid in the wellbore, the device comprising a drilling fluid injection module, a drilling fluid flow state activation module, a gas sample injection module, and a data processing module;

[0007] The drilling fluid injection module is used to inject drilling fluid into the wellbore annulus;

[0008] The drilling fluid flow state activation module includes a first magnet, a second magnet, and a metal partition connected to the drilling fluid injection module; based on the magnetic force of the first magnet and the second magnet, the metal partition is moved to activate a laminar or turbulent drilling fluid flow state.

[0009] The gas injection module is fixed below the drilling fluid flow state activation module. The gas injection module is used to change the rock formation permeability through the gas injection structure and to simulate the uniform gas intake process along the well perimeter, thereby simulating the process of hydrocarbon gas infiltrating into the wellbore annulus.

[0010] The data processing module is connected to the drilling fluid flow state activation module, and the data processing module is used to perform gas detection analysis, degassing and recovery on the upward-returning drilling fluid.

[0011] In some preferred embodiments, the drilling fluid injection module includes a mixing tank, valves, delivery pipes, a first booster pump, drill string, drill bit, and wellbore.

[0012] The preparation tank is used to prepare and store drilling fluid. The preparation tank is sealed and connected to one end of the delivery pipe. The other end of the delivery pipe is disposed in the drill string through a first booster pump. A valve is installed on the delivery pipe between the first booster pump and the preparation tank. The valve is used to control the flow of the drilling fluid. The drill string and the drill bit are coaxially fixed. The drill string and the drill bit are disposed in the well wall, which is formed on the surface of the wellbore.

[0013] In some preferred embodiments, the drilling fluid flow state activation module further includes a receiving tank, a first flow velocity monitor, a fixing tank, a heating plate, a supporting wall, a thin tube, a second flow velocity monitor, and a second booster pump;

[0014] The first magnet is coaxially fixed to the outer circumferential surface of the drill string. A receiving groove is formed on the outer circumferential surface of the first magnet along its axial direction. A metal partition that can move along the receiving groove is arranged in the receiving groove. The metal partition is initially fixed in the fixing groove. The fixing groove is formed on the second magnet. The second magnet is fixed to the supporting wall and the second magnet is fixed to the heating plate. The heating plate is used to change the magnetic force of the second magnet.

[0015] The thin tube penetrates the well wall and the supporting wall, the supporting wall is located outside the well wall, the outlet of the thin tube is sealed and connected to the second flow rate monitor, the inlet of the thin tube is sealed and connected to the inner wall of the wellbore, and a second booster pump is installed on the thin tube. The second booster pump is used to change the fluid inlet speed of the thin tube, thereby stimulating different turbulence states of the drilling fluid.

[0016] The first flow rate monitor is fixed to the outer circumferential surface of the drill string, and the first flow rate monitor is used to monitor the flow rate of the drilling fluid.

[0017] In some preferred embodiments, the gas injection module includes a gas tank, a third booster pump, and a gas delivery pipe;

[0018] The gas tank is used to store hydrocarbon gases. The gas tank is sealed and connected to the inlet of the third booster pump. The outlet of the third booster pump is sealed and connected to one end of the gas transmission pipe. The other end of the gas transmission pipe is connected to the gas sample injection structure.

[0019] The gas injection structure includes a circumferential gas intake layer, a rock layer, a first partition, and a second partition.

[0020] The other end of the gas pipeline is sealed and connected to the circumferential gas intake layer. The circumferential gas intake layer is fixed to the lower end face of the well wall. The inner circumferential surface of the circumferential gas intake layer is provided with a second partition that can rotate along it. Multiple sets of first partitions are fixed to the second partition along its axial direction. A rock layer is provided between each pair of first partitions. The rock layer consists of rock blocks with different permeabilities. Multiple rock blocks are provided along the axial direction of the circumferential gas intake layer.

[0021] In some preferred embodiments, the data processing module includes a degassing tank, a degasser, a chromatograph, a host display, and a recovery tank;

[0022] The degassing tank is sealed and connected to the wellbore annulus. A degasser is installed inside the degassing tank to degas the gas returning upwards in the wellbore annulus. The chromatograph is connected to the degasser and the host display. The chromatograph is used to perform gas analysis on the gas degassed by the degasser, and the host display is used to record the gas analysis data. The recovery tank is used to recover the degassed drilling fluid in the degassing tank.

[0023] In some preferred embodiments, the metal partition, the fixing groove, the second magnet, the heating plate, and the thin tube are evenly arranged in multiple sets along the axial direction of the supporting wall, and the number of receiving grooves is equal to the number and size of the fixing grooves.

[0024] In some preferred embodiments, the magnetism of the first magnet is less than the initial magnetism of the second magnet.

[0025] In another aspect, the present invention proposes a gas logging experiment method based on the flow state of drilling fluid in the wellbore. This method simulates the laminar flow state of the drilling fluid by altering the flow state. Based on a gas logging experiment device based on the flow state of drilling fluid in the wellbore, the method includes the following steps:

[0026] Step S10: Prepare drilling fluid in the preparation tank of the drilling fluid injection module and obtain the original parameters of the drilling fluid; inject the drilling fluid into the wellbore annulus, and set the characteristic length of the wellbore annulus based on the position of the metal partition; set the flow rate of the drilling fluid in the wellbore annulus using the first booster pump in the drilling fluid injection module; calculate the Reynolds number of the drilling fluid flowing in the wellbore annulus based on the original parameters, the characteristic length, and the flow rate, combined with the Reynolds number formula; the original parameters include the density and dynamic viscosity coefficient of the drilling fluid.

[0027] Step S20: Initialize the lower critical Reynolds number and determine whether the Reynolds number is greater than the lower critical Reynolds number; if so, change the flow rate by the first booster pump or change the magnetism of the second magnet by changing the temperature of the heating plate, thereby changing the characteristic length, so that the Reynolds number is less than the lower critical Reynolds number, and the drilling fluid is in a laminar flow state.

[0028] Step S30: Pump a gas sample into the wellbore annulus using the gas sample injection module; degas the returning drilling fluid using the degasser in the gas sample injection module; analyze the extracted gas using a chromatograph in the gas sample injection module after degassing; record the gas analysis data using the main display in the gas sample injection module; and discharge the analyzed drilling fluid into the recovery tank in the gas sample injection module.

[0029] Step S40: Change the feature length to recalculate the Reynolds number, and jump to step S30 to obtain multiple sets of gas measurement data corresponding to the Reynolds number; when the number of repeated experimental groups reaches the required number of experimental groups, end and jump to step S50.

[0030] Step S50: Calculate the laminar state coefficient based on the lower critical Reynolds number and multiple sets of the Reynolds number; arrange the multiple sets of the laminar state coefficient in ascending order and use them as the horizontal axis, and use the gas measurement data corresponding to the laminar state coefficient as the vertical axis to establish a first variation curve.

[0031] A third aspect of the present invention proposes a gas logging experiment method based on the flow state of drilling fluid in a wellbore. This method simulates the turbulence of the drilling fluid by altering its flow state. Based on a gas logging experiment device for the flow state of drilling fluid in a wellbore, the method includes the following steps:

[0032] Step A10: Prepare drilling fluid in the preparation tank of the drilling fluid injection module and obtain the original parameters of the drilling fluid; inject the drilling fluid into the wellbore annulus, and set the characteristic length of the wellbore annulus based on the position of the metal partition; set the flow rate of the drilling fluid in the wellbore annulus using the first booster pump in the drilling fluid injection module; set the injection speed of the capillary tube using the second booster pump in the drilling fluid flow state activation module; and calculate the Reynolds number of the drilling fluid flowing in the wellbore annulus based on the original parameters, the characteristic length, the flow rate, and the injection speed, combined with the Reynolds number formula; the original parameters include the density and dynamic viscosity coefficient of the drilling fluid.

[0033] Step A20: Obtain the upper critical Reynolds number corresponding to the flow rate or the injection rate, and determine whether the Reynolds number is less than the lower critical Reynolds number; if so, change the flow rate by the first booster pump or change the injection rate by the second booster pump to make the Reynolds number greater than the upper critical Reynolds number, so that the drilling fluid is in a turbulent state.

[0034] Step A30: Pump a gas sample into the wellbore annulus using the gas sample injection module; degas the returning drilling fluid using the degasser in the gas sample injection module; analyze the extracted gas using a chromatograph in the gas sample injection module after degassing; record the gas analysis data using the main display in the gas sample injection module; and discharge the analyzed drilling fluid into the recovery tank in the gas sample injection module.

[0035] Step A40: Change the flow rate or the liquid inlet rate according to the Reynolds number to recalculate the Reynolds number, and then jump to step A30 to obtain multiple sets of gas measurement data corresponding to the Reynolds number; when the number of repeated experimental groups reaches the required number of experimental groups, the process ends and jumps to step A50.

[0036] Step A50: Calculate the turbulence state coefficients based on the upper critical Reynolds number and multiple sets of Reynolds numbers corresponding to the upper critical Reynolds number; arrange the multiple sets of turbulence state coefficients in ascending order and use them as the horizontal axis, and use the gas measurement data corresponding to the turbulence state coefficients as the vertical axis to establish a second variation curve.

[0037] In some preferred embodiments, the upper critical Reynolds number is obtained by the following steps:

[0038] Step A21: Drilling fluid containing tracer is injected into the wellbore annulus. The injection speed of the thin tube is set by the second booster pump. The gamma photon signal in the tracer is detected by CT scan, and the flow pattern of the tracer in the wellbore annulus is imaged in real time in the computer.

[0039] Step A22: Increase the flow rate by the first booster pump. When the tracer flows irregularly, mixed, and with a tortuous and chaotic trajectory in the wellbore annulus, calculate the upper critical Reynolds number under the injection rate condition.

[0040] Step A23: Change the liquid inlet speed using the second booster pump, then jump to step A21. When the required experiments with different liquid inlet speeds are completed, stop jumping to obtain multiple sets of upper critical Reynolds numbers under different liquid inlet speed conditions.

[0041] The beneficial effects of this invention are:

[0042] This invention, by setting up a drilling fluid flow state excitation module and a gas sample injection module, can simulate laminar and turbulent flow states under different conditions, thereby enabling the realization of different drilling fluid flow states within the wellbore. By setting up a data processing module, it can analyze the impact of drilling fluid flow state on gas logging data, thereby improving the accuracy of gas logging data correction under the influence of drilling fluid flow state. Attached Figure Description

[0043] Other features, objects, and advantages of this application will become more apparent from the following detailed description of non-limiting embodiments with reference to the accompanying drawings:

[0044] Figure 1 This is a schematic diagram of the structure of a gas logging experimental device based on the flow state of drilling fluid in a wellbore, according to the first embodiment of the present invention.

[0045] Figure 2 This is a cross-sectional view of the wellbore structure in a gas logging experimental device based on the flow state of drilling fluid in the wellbore, according to the first embodiment of the present invention.

[0046] Figure 3 yes Figure 2 Top view;

[0047] Figure 4 This is a cross-sectional view of the gas sample injection structure in a gas logging experimental device based on the flow state of drilling fluid in a wellbore, according to the first embodiment of the present invention.

[0048] Figure 5 yes Figure 4 Top view;

[0049] Figure 6 This is a schematic diagram of the first variation curve of a gas logging experiment method based on the flow state of drilling fluid in the wellbore, according to the second embodiment of the present invention.

[0050] Figure 7 This is a schematic diagram of the second variation curve of a gas logging experiment method based on the flow state of drilling fluid in the wellbore, according to the third embodiment of the present invention. Detailed Implementation

[0051] The present application will now be described in further detail with reference to the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are for illustrative purposes only and are not intended to limit the invention. Furthermore, it should be noted that, for ease of description, only the parts relevant to the invention are shown in the accompanying drawings.

[0052] It should be noted that, unless otherwise specified, the embodiments and features described in this application can be combined with each other. This application will now be described in detail with reference to the accompanying drawings and embodiments.

[0053] The first embodiment of the present invention, see [link to embodiment]. Figures 1-5 A gas logging experimental device based on the flow state of drilling fluid in the wellbore is provided. The device includes a drilling fluid injection module, a drilling fluid flow state activation module, a gas sample injection module, and a data processing module.

[0054] The drilling fluid injection module is used to inject drilling fluid into the wellbore annulus;

[0055] The drilling fluid flow state activation module includes a first magnet 51, a second magnet 83, and a metal partition 81 connected to the drilling fluid injection module; based on the magnetic force of the first magnet 51 and the second magnet 83, the metal partition 81 is moved to activate the laminar or turbulent drilling fluid flow state.

[0056] The gas injection module is fixed below the drilling fluid flow state activation module. The gas injection module is used to change the permeability of the rock formation 142 through the gas injection structure 14 and to simulate the uniform gas intake process of the gas sample along the well perimeter, thereby simulating the process of hydrocarbon gas infiltrating into the wellbore annulus.

[0057] The data processing module is connected to the drilling fluid flow state activation module, and the data processing module is used to perform gas detection analysis, degassing and recovery on the upward-returning drilling fluid.

[0058] For further explanation of the present invention, see Figure 1 The drilling fluid injection module includes a mixing tank 1, a valve 2, a delivery pipe 3, a first booster pump 4, a drill string 5, a drill bit 6, and a well wall 8;

[0059] The preparation tank 1 is used to prepare and store drilling fluid. The preparation tank 1 is sealed and connected to one end of the delivery pipe 3. The other end of the delivery pipe 3 is disposed in the drill string 5 through the first booster pump 4. A valve 2 is installed on the delivery pipe 3 between the first booster pump 4 and the preparation tank 1. The valve 2 is used to control the flow of the drilling fluid. The drill string 5 is coaxially fixed with the drill bit 6. The drill string 5 and the drill bit 6 are disposed in the well wall 8, which is formed on the surface of the wellbore.

[0060] For further explanation of the present invention, see Figures 1-3 The drilling fluid flow state activation module also includes a receiving tank 52, a first flow velocity monitor 7, a fixing tank 82, a heating plate 84, a supporting wall 85, a thin tube 86, a second flow velocity monitor 9, and a second booster pump 10.

[0061] The first magnet 51 is coaxially fixed to the outer circumferential surface of the drill string 5. A receiving groove 52 is formed on the outer circumferential surface of the first magnet 51 along its axial direction. A metal partition 81 that can move along the receiving groove 52 is arranged in the receiving groove 52. The metal partition 81 is initially fixed in the fixing groove 82. The fixing groove 82 is formed on the second magnet 83. The second magnet 83 is fixed to the supporting wall 85. The second magnet 83 is fixed to the heating plate 84. The heating plate 84 is used to change the magnetic force of the second magnet 83.

[0062] The thin tube 86 penetrates the well wall 8 and the supporting wall 85. The supporting wall 85 is located outside the well wall 8. The outlet of the thin tube 86 is sealed and connected to the second flow rate monitor 9. The inlet of the thin tube 86 is sealed and connected to the inner wall of the wellbore. A second booster pump 10 is installed on the thin tube 86. The second booster pump 10 is used to change the fluid inlet speed of the thin tube 86, thereby stimulating different turbulence states of the drilling fluid.

[0063] The first flow rate monitor 7 is fixed to the outer circumferential surface of the drill string 5, and the first flow rate monitor 7 is used to monitor the flow rate of the drilling fluid.

[0064] The annular volume between the drill string 5 and the well wall 8 is defined as the wellbore annulus.

[0065] For further explanation of the present invention, see Figure 1 , Figure 4 , Figure 5 The gas sample injection module includes a gas tank 11, a third booster pump 12, and a gas delivery pipe 13;

[0066] The gas tank 11 is used to store hydrocarbon gases. The gas tank 11 is sealed and connected to the inlet of the third booster pump 12. The outlet of the third booster pump 12 is sealed and connected to one end of the gas delivery pipe 13. The other end of the gas delivery pipe 13 is connected to the gas sample injection structure 14.

[0067] The gas injection structure 14 includes a circumferential gas intake layer 141, a rock layer 142, a first partition 144, and a second partition 145;

[0068] The other end of the gas pipeline 13 is sealed and connected to the circumferential air intake layer 141. The circumferential air intake layer 141 is fixed to the lower end face of the well wall 8. The inner circumferential surface of the circumferential air intake layer 141 is provided with a second partition 145 that can rotate along it. Multiple sets of first partitions 144 are fixed along the axial direction of the second partition 145. A rock layer 142 is provided between each pair of first partitions 144. The rock layer 142 consists of rock blocks 143 with different permeabilities. Multiple rock blocks 143 are provided along the axial direction of the circumferential air intake layer 141.

[0069] For further explanation of the present invention, see Figure 1 The data processing module includes a degassing tank 15, a degasser 16, a chromatograph 17, a main display 18, and a recovery box 19;

[0070] The degassing tank 15 is sealed and connected to the wellbore annulus. A degasser 16 is installed inside the degassing tank 15. The degasser 16 is used to degas the gas returning upward in the wellbore annulus. The chromatograph 17 is connected to the degasser 16 and the host display 18. The chromatograph 17 is used to perform gas analysis on the gas degassed by the degasser 16. The host display 18 is used to record the gas analysis data. The recovery tank 19 is used to recover the drilling fluid after degassing in the degassing tank 15.

[0071] For further explanation of the present invention, see Figure 3 The metal partition 81, the fixing groove 82, the second magnet 83, the heating plate 84 and the thin tube 86 are evenly arranged in multiple sets along the axial direction of the supporting wall 85. The number of receiving grooves 52 is equal to the number and size of the fixing grooves 82.

[0072] For further explanation of the present invention, see Figure 3 The magnetism of the first magnet 51 is less than the initial magnetism of the second magnet 83.

[0073] The second embodiment of the present invention, see [link to embodiment]. Figures 1-5 , Figure 6 This paper provides a gas logging experiment method based on the flow state of drilling fluid in the wellbore. The method simulates the laminar flow by changing the state of the drilling fluid. Based on a gas logging experiment device based on the flow state of drilling fluid in the wellbore, the method includes the following steps:

[0074] Step S10: Prepare drilling fluid in the preparation tank 1 of the drilling fluid injection module and obtain the original parameters of the drilling fluid; inject the drilling fluid into the wellbore annulus, and set the characteristic length of the wellbore annulus through the position of the metal partition 81; use the first booster pump 4 in the drilling fluid injection module to set the flow rate of the drilling fluid in the wellbore annulus; based on the original parameters, the characteristic length, and the flow rate, and combined with the Reynolds number formula, calculate the Reynolds number of the drilling fluid flowing in the wellbore annulus; the original parameters include the density and dynamic viscosity coefficient of the drilling fluid;

[0075] Step S20: Initialize the lower critical Reynolds number and determine whether the Reynolds number is greater than the lower critical Reynolds number; if so, change the flow rate by the first booster pump 4 or change the magnetism of the second magnet 83 by changing the temperature of the heating plate 84, thereby changing the characteristic length, so that the Reynolds number is less than the lower critical Reynolds number, and the drilling fluid is in a laminar flow state.

[0076] Step S30: Pump a gas sample into the wellbore annulus using the gas sample injection module; degas the returning drilling fluid using the degasser 16 in the gas sample injection module; analyze the extracted gas using the chromatograph 17 in the gas sample injection module after degassing; record the gas analysis data using the host display 18 in the gas sample injection module; and discharge the analyzed drilling fluid into the recovery tank 19 in the gas sample injection module.

[0077] Step S40: Change the feature length to recalculate the Reynolds number, and jump to step S30 to obtain multiple sets of gas measurement data corresponding to the Reynolds number; when the number of repeated experimental groups reaches the required number of experimental groups, end and jump to step S50.

[0078] Step S50: Calculate the laminar state coefficient based on the lower critical Reynolds number and multiple sets of the Reynolds number; arrange the multiple sets of the laminar state coefficient in ascending order and use them as the horizontal axis, and use the gas measurement data corresponding to the laminar state coefficient as the vertical axis to establish a first variation curve.

[0079] The Reynolds number is calculated as follows:

[0080]

[0081] Among them, R e ρ is the Reynolds number, dimensionless; ρ is the density of the drilling fluid, in kg / m³. 3 v is the flow velocity of the drilling fluid in the wellbore annulus, in m / s; d is the characteristic length of the wellbore annulus, in m; μ is the dynamic viscosity coefficient of the drilling fluid, in N·s / m. 2 .

[0082] The lower critical Reynolds number is set to a fixed value of 2300.

[0083] The laminar state coefficient L is calculated as follows:

[0084] L=R ec下 / R e The R ec下 L represents the lower critical Reynolds number; different values ​​of L indicate different laminar flow states, with a larger L indicating more stable laminar flow.

[0085] The method of "changing the feature length" is to change the annular volume and annular surface area by changing the number of connections between the metal partition 81 and the receiving slot 52, thereby changing the feature length (feature length = annular volume / annular surface area).

[0086] In this embodiment, the drilling fluid density ρ is obtained as 1200 kg / m³. 3 The dynamic viscosity coefficient μ of the drilling fluid is 0.036 N·s / m. 2 Given a drilling fluid velocity v of 1 m / s in the wellbore annulus, an inner diameter of 63.5 mm, and an outer diameter of 88.9 mm, the characteristic length d of the wellbore annulus is calculated to be 0.0762 m using the inner and outer diameters. The Reynolds number R is then calculated. e The value is 1270; the laminar flow state, i.e., R, is determined. e =1270<R ec下 =2300 indicates laminar flow; 0.6L of a 10% mixed gas sample is injected into the wellbore annulus for gas logging analysis; the laminar flow state coefficient L is calculated to be 1.81 under the above conditions, and the corresponding gas logging data T is obtained. g Different laminar flow states (L = 2.58, 2.20, 1.51, 1.21) were achieved by adjusting the drilling fluid flow rate v and the characteristic length d of the wellbore annulus, and gas logging data T were obtained under the corresponding conditions. g Acquire gas measurement data T g The first variation curve is a graph showing the variation of laminar flow state coefficients L (L = 2.58, 2.20, 1.81, 1.51, 1.21). Figure 6 As shown, the total hydrocarbon detection value decreases as the laminar flow state coefficient increases (the laminar flow is more stable).

[0087] The third embodiment of the present invention, see [link to embodiment]. Figures 1-5 , Figure 7 A gas logging experiment method based on the flow state of drilling fluid in the wellbore is proposed. This method simulates the turbulence of the drilling fluid by altering its flow state. Based on a gas logging experiment device based on the flow state of drilling fluid in the wellbore, the method includes the following steps:

[0088] Step A10: Prepare drilling fluid in the preparation tank 1 of the drilling fluid injection module and obtain the original parameters of the drilling fluid; inject the drilling fluid into the wellbore annulus, and set the characteristic length of the wellbore annulus by the position of the metal partition 81; set the flow rate of the drilling fluid in the wellbore annulus using the first booster pump 4 in the drilling fluid injection module; set the injection speed of the capillary tube 86 using the second booster pump 10 in the drilling fluid flow state activation module; and calculate the Reynolds number of the drilling fluid flowing in the wellbore annulus based on the original parameters, the characteristic length, the flow rate, and the injection speed, combined with the Reynolds number formula; the original parameters include the density and dynamic viscosity coefficient of the drilling fluid.

[0089] Step A20: Obtain the upper critical Reynolds number corresponding to the flow rate or the injection rate, and determine whether the Reynolds number is less than the lower critical Reynolds number; if so, change the flow rate by the first booster pump 4 or change the injection rate by the second booster pump 10 to make the Reynolds number greater than the upper critical Reynolds number, so that the drilling fluid is in a turbulent state.

[0090] Step A30: Pump a gas sample into the wellbore annulus using the gas sample injection module; degas the returning drilling fluid using the degasser 16 in the gas sample injection module; analyze the extracted gas using the chromatograph 17 in the gas sample injection module after degassing; record the gas analysis data using the host display 18 in the gas sample injection module; and discharge the analyzed drilling fluid into the recovery tank 19 in the gas sample injection module.

[0091] Step A40: Change the flow rate or the liquid inlet rate according to the Reynolds number to recalculate the Reynolds number, and then jump to step A30 to obtain multiple sets of gas measurement data corresponding to the Reynolds number; when the number of repeated experimental groups reaches the required number of experimental groups, the process ends and jumps to step A50.

[0092] Step A50: Calculate the turbulence state coefficients based on the upper critical Reynolds number and multiple sets of Reynolds numbers corresponding to the upper critical Reynolds number; arrange the multiple sets of turbulence state coefficients in ascending order and use them as the horizontal axis, and use the gas measurement data corresponding to the turbulence state coefficients as the vertical axis to establish a second variation curve.

[0093] In this embodiment, the flow rate or the inlet velocity is changed according to the required Reynolds number (e.g., 3564, 3117, 2743).

[0094] The Reynolds number is calculated using the method described in the second embodiment.

[0095] The turbulence state coefficient T is calculated as follows:

[0096] T = R e / R ec上 ;

[0097] Among them, R ec上 T is the upper critical Reynolds number; different T values ​​indicate different turbulent states, with a larger T value indicating more turbulent flow.

[0098] The tracer is 133 xenon.

[0099] In this embodiment, the drilling fluid density ρ is obtained as 1200 kg / m³. 3 The dynamic viscosity coefficient μ of the drilling fluid is 0.036 N·s / m. 2 The drilling fluid velocity v in the wellbore annulus is 3 m / s, the inner diameter of the wellbore annulus is 63.5 mm, and the outer diameter of the wellbore annulus is 88.9 mm. The fluid inlet velocity v′ in the capillary tube is set to 1 m / s. Using the inner and outer diameters of the wellbore annulus, the characteristic length d of the wellbore annulus is calculated to be 0.0762 m. The Reynolds number R is then calculated. e The upper critical Reynolds number R is 3810; obtain the upper critical Reynolds number R for different capillary inlet velocities. ec上 Experiments showed that the upper critical Reynolds numbers for the capillary inlet velocities of 1 m / s, 1.5 m / s, and 2 m / s were 3564, 3117, and 2743, respectively; the turbulent state, i.e., R... e =3810>R ec上 =3564 indicates a turbulent state; 0.6L of a 10% mixed gas sample was injected into the wellbore annulus for gas logging analysis; the turbulence state coefficient T under the above conditions was calculated to be 1.07, and the corresponding gas logging data T was obtained. g Different turbulence states (T = 1.22, 1.38, 1.53, 1.67) were achieved by adjusting the drilling fluid flow rate v and the capillary fluid inlet velocity v′, and gas logging data T was obtained under the corresponding conditions. g Acquire gas measurement data T g The curves showing the variation of the turbulence state coefficient T (T = 1.07, 1.22, 1.38, 1.53, 1.67), i.e., the second variation curve, are shown below. Figure 7 As shown, the total hydrocarbon detection value increases with the increase of the turbulence state coefficient (the more turbulent the flow).

[0100] Preferably, the method for obtaining the upper critical Reynolds number includes the following steps:

[0101] Step A21: Drilling fluid containing tracer is injected into the wellbore annulus. The injection speed of the thin tube 86 is set by the second booster pump 10. The gamma photon signal in the tracer is detected by CT scan, and the flow pattern of the tracer in the wellbore annulus is imaged in real time in the computer.

[0102] Step A22: Increase the flow rate by the first booster pump 4. When the tracer flows in an irregular, mixed, and chaotic manner in the wellbore annulus, calculate the upper critical Reynolds number under the injection rate condition.

[0103] Step A23: Change the liquid inlet speed by the second booster pump 10, jump to step A21, and stop jumping when the required experiments at different liquid inlet speeds are completed, to obtain multiple sets of upper critical Reynolds numbers under different liquid inlet speed conditions.

[0104] The terms “first”, “second”, etc., are used to distinguish similar objects, not to describe or indicate a specific order or sequence.

[0105] The term "comprising" or any other similar term is intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus / device that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent in such process, method, article, or apparatus / device.

[0106] The technical solution of the present invention has been described above with reference to the preferred embodiments shown in the accompanying drawings. However, it will be readily understood by those skilled in the art that the scope of protection of the present invention is obviously not limited to these specific embodiments. Without departing from the principles of the present invention, those skilled in the art can make equivalent changes or substitutions to the relevant technical features, and the technical solutions after these changes or substitutions will all fall within the scope of protection of the present invention.

Claims

1. A gas logging experimental device based on the flow pattern of drilling fluid in a wellbore, characterized in that, The device includes a drilling fluid injection module, a drilling fluid flow state activation module, a gas sample injection module, and a data processing module; The drilling fluid injection module is used to inject drilling fluid into the wellbore annulus; The drilling fluid flow state activation module includes a first magnet (51), a second magnet (83), and a metal partition (81) connected to the drilling fluid injection module; based on the magnetic force of the first magnet (51) and the second magnet (83), the metal partition (81) is moved to activate the laminar or turbulent drilling fluid flow state; The gas injection module is fixed below the drilling fluid flow state activation module. The gas injection module is used to change the permeability of the rock formation (142) through the gas injection structure (14) and to simulate the uniform gas intake process of the gas sample along the well perimeter, thereby simulating the process of hydrocarbon gas infiltrating into the wellbore annulus. The data processing module is connected to the drilling fluid flow state activation module, and the data processing module is used to perform gas detection analysis, degassing and recovery on the upward-returning drilling fluid.

2. The gas logging experimental device based on drilling fluid flow patterns in a wellbore according to claim 1, characterized in that, The drilling fluid injection module includes a mixing tank (1), a valve (2), a delivery pipe (3), a first booster pump (4), a drill string (5), a drill bit (6), and a wellbore (8). The preparation tank (1) is used to prepare and store drilling fluid. The preparation tank (1) is sealed and connected to one end of the delivery pipe (3). The other end of the delivery pipe (3) is configured in the drill string (5) through the first booster pump (4). A valve (2) is installed on the delivery pipe (3) between the first booster pump (4) and the preparation tank (1). The valve (2) is used to control the flow of the drilling fluid. The drill string (5) is coaxially fixed with the drill bit (6). The drill string (5) and the drill bit (6) are configured in the well wall (8). The well wall (8) is opened on the surface of the well barrel.

3. The gas logging experimental device based on the drilling fluid flow pattern in the wellbore according to claim 2, characterized in that, The drilling fluid flow state activation module also includes a receiving tank (52), a first flow velocity monitor (7), a fixing tank (82), a heating plate (84), a supporting wall (85), a thin tube (86), a second flow velocity monitor (9), and a second booster pump (10); The first magnet (51) is coaxially fixed to the outer circumferential surface of the drill string (5). A receiving groove (52) is provided on the outer circumferential surface of the first magnet (51) along its axial direction. A metal partition (81) that can move along it is arranged in the receiving groove (52). The metal partition (81) is initially fixed in the fixing groove (82). The fixing groove (82) is opened on the second magnet (83). The second magnet (83) is fixed to the supporting wall (85). The second magnet (83) is fixed to the heating plate (84). The heating plate (84) is used to change the magnetic force of the second magnet (83). The thin tube (86) penetrates the well wall (8) and the supporting wall (85). The supporting wall (85) is located outside the well wall (8). The outlet of the thin tube (86) is sealed and connected to the second flow rate monitor (9). The inlet of the thin tube (86) is sealed and connected to the inner wall of the well. A second booster pump (10) is installed on the thin tube (86). The second booster pump (10) is used to change the inlet speed of the thin tube (86), thereby stimulating different turbulent states of the drilling fluid. The first flow rate monitor (7) is fixed to the outer circumferential surface of the drill string (5), and the first flow rate monitor (7) is used to monitor the flow rate of the drilling fluid.

4. The gas logging experimental device based on drilling fluid flow patterns in a wellbore according to claim 3, characterized in that, The gas injection module includes a gas tank (11), a third booster pump (12), and a gas delivery pipe (13). The gas tank (11) is used to store hydrocarbon gases. The gas tank (11) is sealed and connected to the inlet of the third booster pump (12). The outlet of the third booster pump (12) is sealed and connected to one end of the gas transmission pipe (13). The other end of the gas transmission pipe (13) is connected to the gas sample injection structure (14). The gas injection structure (14) includes a circumferential gas intake layer (141), a rock layer (142), a first partition (144), and a second partition (145). The other end of the gas pipeline (13) is sealed and connected to the circumferential gas intake layer (141). The circumferential gas intake layer (141) is fixed to the lower end face of the well wall (8). The inner circumferential surface of the circumferential gas intake layer (141) is provided with a second partition (145) that can rotate along it. The second partition (145) is fixed with multiple sets of first partitions (144) along its axial direction. A rock layer (142) is provided between each pair of first partitions (144). The rock layer (142) is a rock block (143) with different permeability. Multiple rock blocks (143) are provided along the axial direction of the circumferential gas intake layer (141).

5. The gas logging experimental device based on the drilling fluid flow pattern in the wellbore according to claim 4, characterized in that, The data processing module includes a degassing tank (15), a degasser (16), a chromatograph (17), a host display (18), and a recovery box (19). The degassing tank (15) is sealed and connected to the wellbore annulus. A degasser (16) is installed inside the degassing tank (15). The degasser (16) is used to degas the gas returning upward in the wellbore annulus. The chromatograph (17) is connected to the degasser (16) and the host display (18). The chromatograph (17) is used to perform gas analysis on the gas degassed by the degasser (16). The host display (18) is used to record the gas analysis data. The recovery tank (19) is used to recover the drilling fluid after degassing in the degassing tank (15).

6. The gas logging experimental device based on drilling fluid flow patterns in a wellbore according to claim 5, characterized in that, The metal partition (81), the fixing groove (82), the second magnet (83), the heating plate (84) and the thin tube (86) are evenly arranged in multiple sets along the axial direction of the supporting wall (85). The number of receiving grooves (52) is equal to the number and size of the fixing grooves (82).

7. The gas logging experimental device based on the drilling fluid flow pattern in the wellbore according to claim 6, characterized in that, The magnetism of the first magnet (51) is less than the initial magnetism of the second magnet (83).

8. A gas logging experiment method based on the flow state of drilling fluid in the wellbore, characterized by simulating the laminar flow state of the drilling fluid by changing the laminar flow state, wherein... A gas logging experimental device based on the drilling fluid flow pattern in a wellbore, according to any one of claims 1-7, comprises the following steps: Step S10: Prepare drilling fluid in the preparation tank (1) of the drilling fluid injection module and obtain the original parameters of the drilling fluid; inject the drilling fluid into the wellbore annulus, and set the characteristic length of the wellbore annulus by the position of the metal partition (81); set the flow rate of the drilling fluid in the wellbore annulus using the first booster pump (4) in the drilling fluid injection module; calculate the Reynolds number of the drilling fluid flowing in the wellbore annulus based on the original parameters, the characteristic length and the flow rate, and in combination with the Reynolds number formula; the original parameters include the density and dynamic viscosity coefficient of the drilling fluid. Step S20: Initialize the lower critical Reynolds number and determine whether the Reynolds number is greater than the lower critical Reynolds number; if so, change the flow rate by the first booster pump (4) or change the magnetism of the second magnet (83) by changing the temperature of the heating plate (84), thereby changing the characteristic length, so that the Reynolds number is less than the lower critical Reynolds number, and the drilling fluid is in a laminar flow state. Step S30: Pump the gas sample into the wellbore annulus using the gas sample injection module; degas the drilling fluid returning to the well using the degasser (16) in the gas sample injection module; analyze the extracted gas using the chromatograph (17) in the gas sample injection module after degassing; record the gas measurement data using the host display (18) in the gas sample injection module; and discharge the drilling fluid after gas measurement analysis into the recovery tank (19) in the gas sample injection module. Step S40: Change the feature length to recalculate the Reynolds number, and jump to step S30 to obtain multiple sets of gas measurement data corresponding to the Reynolds number; when the number of repeated experimental groups reaches the required number of experimental groups, end and jump to step S50. Step S50: Calculate the laminar state coefficient based on the lower critical Reynolds number and multiple sets of the Reynolds number; arrange the multiple sets of the laminar state coefficient in ascending order and use them as the horizontal axis, and use the gas measurement data corresponding to the laminar state coefficient as the vertical axis to establish a first variation curve.

9. A gas logging experiment method based on the flow state of drilling fluid in the wellbore, characterized by simulating the turbulence state of the drilling fluid by changing the turbulence state, wherein... A gas logging experimental device based on the drilling fluid flow pattern in a wellbore, according to any one of claims 1-7, comprises the following steps: Step A10: Prepare drilling fluid in the preparation tank (1) of the drilling fluid injection module and obtain the original parameters of the drilling fluid; inject the drilling fluid into the wellbore annulus, and set the characteristic length of the wellbore annulus by the position of the metal partition (81); set the flow rate of the drilling fluid in the wellbore annulus by the first booster pump (4) in the drilling fluid injection module; set the injection speed of the thin tube (86) by the second booster pump (10) in the drilling fluid flow state activation module, and calculate the Reynolds number of the drilling fluid flowing in the wellbore annulus based on the original parameters, the characteristic length, the flow rate and the injection speed, and in combination with the Reynolds number formula; the original parameters include the density and dynamic viscosity coefficient of the drilling fluid; Step A20: Obtain the upper critical Reynolds number corresponding to the flow rate or the injection rate, and determine whether the Reynolds number is less than the upper critical Reynolds number; if so, change the flow rate by the first booster pump (4) or change the injection rate by the second booster pump (10) to make the Reynolds number greater than the upper critical Reynolds number, so that the drilling fluid is in a turbulent state. Step A30: Pump the gas sample into the wellbore annulus using the gas sample injection module; degas the drilling fluid returning to the well using the degasser (16) in the gas sample injection module; analyze the extracted gas using the chromatograph (17) in the gas sample injection module after degassing; record the gas measurement data using the host display (18) in the gas sample injection module; and discharge the drilling fluid after gas measurement analysis into the recovery tank (19) in the gas sample injection module. Step A40: Change the flow rate or the liquid inlet rate according to the Reynolds number to recalculate the Reynolds number, and then jump to step A30 to obtain multiple sets of gas measurement data corresponding to the Reynolds number; when the number of repeated experimental groups reaches the required number of experimental groups, the process ends and jumps to step A50. Step A50: Calculate the turbulence state coefficients based on the upper critical Reynolds number and multiple sets of Reynolds numbers corresponding to the upper critical Reynolds number; arrange the multiple sets of turbulence state coefficients in ascending order and use them as the horizontal axis, and use the gas measurement data corresponding to the turbulence state coefficients as the vertical axis to establish a second variation curve.

10. The gas logging experimental method based on drilling fluid flow patterns in the wellbore according to claim 9, characterized in that, The method for obtaining the upper critical Reynolds number includes the following steps: Step A21: Drilling fluid containing tracer is injected into the wellbore annulus. The injection speed of the thin tube (86) is set by the second booster pump (10). The γ photon signal in the tracer is detected by CT scan, and the flow pattern of the tracer in the wellbore annulus is imaged in real time in the computer. Step A22: Increase the flow rate by the first booster pump (4). When the tracer flows in an irregular, mixed, and chaotic manner in the wellbore annulus, calculate the upper critical Reynolds number under the inlet velocity condition. Step A23: Change the liquid inlet speed by the second booster pump (10) and jump to step A21. When the required different liquid inlet speed experiments are completed, stop jumping and obtain multiple sets of upper critical Reynolds numbers under different liquid inlet speed conditions.

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