Hydrate inhibitor injection method for deep-sea mixed transportation pipeline
By using real-time monitoring and dynamic calculations, the precise injection of inhibitors into deep-sea gas fields is achieved, which solves the risk of hydrate formation when the flow state is complex and variable, and ensures the safe and efficient operation of the gas field.
Patent Information
- Application Number
- CN202511066309.5
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- Filing Date
- 2025-07-31
- Publication Date
- 2025-11-14
AI Technical Summary
In existing technologies, the problem of hydrate formation and blockage in deep-sea gas pipelines is difficult to control effectively, especially when the flow conditions are complex and variable. Insufficient or excessive injection of inhibitors leads to safety risks and waste.
By monitoring the liquid and gas phase contents, natural gas composition, pressure, and temperature in the pipeline in real time, the injection volume of inhibitors is dynamically calculated. Combined with the flow state judgment, the precise dynamic injection of inhibitors is achieved, and different inhibitor injection volumes are used to adapt to different flow patterns.
It improves the inhibitory effect of the inhibitor, reduces the risk of hydrate formation, ensures the stable operation and efficient development of the gas field, and avoids the excessive injection and waste of the inhibitor.
Smart Images
Figure CN120946951A_ABST
Abstract
Description
Technical Field
[0001] This invention relates to the field of gas field development technology, and more specifically, to a method for injecting hydrate inhibitors into deep-sea mixed-transport pipelines. Background Technology
[0002] Deep-sea gas field products include natural gas, carbon dioxide, hydrogen sulfide, water, condensate oil, and a small amount of solid particles, forming a multiphase mixture. During long-distance gas transmission in the low-temperature environment of the seabed within deep-sea gas pipelines, the high-pressure multiphase mixture inside the pipeline easily meets the conditions for hydrate formation, leading to hydrate blockage inside the pipeline and causing serious hidden dangers to deep-sea gas pipelines.
[0003] In horizontal pipelines, water-gas mixed media are prone to mist flow, slug flow, and stratified flow, and different flow patterns have different effects on hydrate formation. Stratified flow has a relatively obvious gas-liquid interface and is commonly seen in the later stages of gas field production when the gas phase velocity is low and the liquid carrying capacity is low. Although the gas-liquid two-phase contact area is relatively small and the mass transfer efficiency is low in long-distance pipelines, the continuity of the liquid phase is better, providing a stable aqueous environment for hydrate formation. The contact time between water molecules and natural gas molecules is longer, and the continuity of the liquid phase is conducive to hydrate nucleation and growth. The stability of stratified flow makes it easier for local temperature and pressure conditions to reach the thermodynamic equilibrium conditions for hydrate formation. The relatively slow flow of the liquid phase means that heat and mass transfer processes mainly rely on molecular diffusion and convective diffusion. This relatively stable heat and mass transfer environment is conducive to hydrate formation and growth. Therefore, among various flow states, stratified flow is more likely to form natural gas hydrates.
[0004] The water-to-gas ratio varies significantly at different stages of natural gas extraction. In the early stages, the gas phase velocity is high and the liquid phase velocity is low. In the middle and later stages of extraction, the gas phase velocity decreases while the liquid phase velocity increases. The impact of different water-to-gas ratios on hydrate formation is manifested in the following ways: the water-to-gas ratio needs to be within a certain range to effectively support hydrate formation; different water-to-gas ratios affect the hydrate equilibrium temperature; and the distribution state between water and gas also influences the formation or inhibition of hydrates. Even with the same water-to-gas ratio, different flow patterns and different relative distribution states of water and gas lead to significantly different assessments of hydrate formation or inhibition.
[0005] Currently, natural gas hydrate suppression primarily considers the inherent properties of natural gas, mainly referencing its composition and the pressure and temperature of the current operating conditions to determine the degree of supercooling for hydrate formation. Injection volume is then assessed based on this supercooling. Since natural gas composition is generally stable over a period, and formation and pipeline pressures and temperatures remain relatively stable, the inhibitor injection rate is fixed at a constant rate with a margin. This current control scheme can meet the needs under normal pipeline conditions, while maintaining a relatively large injection volume to ensure flow safety and prevent blockages. However, this also leads to excessive inhibitor injection, resulting in waste and requiring a large amount of inhibitor. Furthermore, when pipeline flow conditions are complex and variable, hydrate formation is not only related to natural gas properties but also to flow conditions, water content changes, and the phase of water. Simply using the aforementioned fixed-rate injection method is insufficient and raises flow safety concerns, failing to meet actual hydrate suppression needs. Summary of the Invention
[0006] To overcome the shortcomings of existing technologies where quantitative input of inhibitors during natural gas extraction cannot meet production demands, this invention provides a method for injecting hydrate inhibitors into deep-sea mixed-transport pipelines. This method achieves dynamic control of inhibitor injection based on actual operating conditions, thereby meeting production requirements.
[0007] To solve the above-mentioned technical problems, the technical solution adopted by the present invention is: a method for injecting hydrate inhibitors into deep-sea mixed-transport pipelines, comprising the following steps: Step 1: Real-time monitoring of the liquid and gas phase contents, natural gas composition, pressure, and temperature in the pipeline to obtain real-time production data; Step 2: Confirm the subcooling of natural gas hydrate based on production data, calculate and obtain the injection amount of inhibitor based on the subcooling, and at the same time use production data to judge the flow state of pipeline fluid in real time. Determine the real-time compensation amount of inhibitor based on the flow state, and determine the final injection amount of inhibitor based on the obtained inhibitor injection amount and compensation amount. Step 3: Perform real-time dynamic injection of inhibitors based on the obtained final injection volume.
[0008] This method primarily targets and controls the risks associated with stratified flow processes, which carry significant risks. In step one, all data are monitored in real-time, and dynamic real-time production data is output to ensure the calculation of the real-time inhibitor input. In step two, the subcooling of natural gas hydrates is related to pressure and temperature, and a correlation exists between them. This can be determined by consulting existing data. Real-time subcooling data is output based on real-time pressure and temperature data, and the required real-time inhibitor injection amount is calculated from this data. Similarly, real-time production data is used to determine the real-time flow state of the fluid, and the required real-time inhibitor compensation amount is confirmed based on the flow state, thus determining the final inhibitor injection amount. This final injection amount is also dynamic data, allowing for dynamic inhibitor input to meet production needs. Simultaneously, the fluid state determination fully references and utilizes relevant data from the liquid and gas phases in the pipeline, as well as the natural gas composition, to ensure accurate fluid state assessment under different water-to-gas ratios, improving accuracy.
[0009] The above methods enable more refined dynamic injection of inhibitors in deep-sea gas fields. By identifying the flow patterns in multiphase mixed-transport pipelines, different inhibitor injection volumes are adopted when different flow patterns occur, thereby achieving automatic adjustment and optimization of the inhibitor injection volume. This improves the inhibitor suppression effect, reduces the risk of hydrate formation, and ensures the stable operation and efficient development of the gas field.
[0010] Preferably, in step two, the flow state of the fluid in the pipeline is determined based on the following first empirical model:
[0011]
[0012] when At that time, if , or when At that time, if At this point, the flow pattern is stratified flow; Above: X and Y are dimensionless parameters; , These are the liquid phase and gas phase mass flow rates, respectively, measured by a multiphase flow meter, with units of kg / h. The density refers to the gas phase and liquid phase. The gas phase density is calculated from the molar composition of the natural gas components, which are measured by relevant instruments. The unit is kg / m³. 3 A represents the cross-sectional area of the pipe, in meters (m²). 3 ; The viscosity of the fluid in the pipeline is expressed in Pa·s. Specifically, it can be real-time or average data of the fluid viscosity in the pipeline, or data of the viscosity of the formation water. The surface tension of the fluid in the pipeline is expressed in N / m. It can be expressed as real-time or average data of the fluid viscosity in the pipeline, or as data of the viscosity of the formation water.
[0013] Preferably, in step two, the supercooling of the natural gas hydrate is calculated based on the real-time monitored pressure and temperature. The formula for calculating the supercooling is as follows:
[0014] The above formula: This indicates the degree of subcooling of natural gas hydrate at the current pressure, expressed in °C. This represents the saturation temperature of natural gas under the current pressure, obtained by looking up a table; T is the current temperature.
[0015] Preferably, based on subcooling The injection volume of the inhibitor was calculated using the following second empirical model:
[0016]
[0017] Above: Cm represents the minimum concentration of the inhibitor in the liquid-phase aqueous solution, by mass percentage; This indicates the dosage of inhibitors, expressed in kg / day. This indicates the flow rate of liquid water in a mixed-transport pipeline, expressed in kg / day.
[0018] Preferably, in the case of stratified flow, there is a special gas-liquid distribution state. The ethylene glycol distribution equilibrium process between the gas and liquid phases results in ethylene glycol vaporization loss, calculated as QG (kg / day).
[0019]
[0020] This indicates the natural gas flow rate, in units of 10. 4 m 3 / day, The loss coefficient of the inhibitor in the pipeline is represented by an empirical value or by calculation. This indicates the final amount of inhibitor injected.
[0021] Preferably, based on the first empirical model, if the fluid state is stratified flow, then:
[0022]
[0023] If the fluid state is not a flow split, then .
[0024] Preferably, an automatic valve with the function of dynamically adjusting the injection volume based on real-time data and calculating the real-time injection volume based on valve detection parameters is used as the injection valve for the inhibitor. Specifically, a CIMV valve or other automatic valves with the above functions are used.
[0025] Preferably, a multiphase flow meter is used to monitor the liquid and gaseous contents of the pipeline in real time.
[0026] Preferably, a chromatographic analysis instrument is used to monitor the natural gas components in the pipeline in real time.
[0027] Preferably, the inhibitor is methanol or ethylene glycol.
[0028] Compared with the prior art, the beneficial effects of the present invention are: The above methods enable more refined dynamic injection of inhibitors in deep-sea gas fields. By identifying the flow patterns in multiphase mixed-transport pipelines, different inhibitor injection volumes are adopted when different flow patterns occur, thereby achieving automatic adjustment and optimization of the inhibitor injection volume. This improves the inhibitor suppression effect, reduces the risk of hydrate formation, and ensures the stable operation and efficient development of the gas field. Attached Figure Description
[0029] Figure 1 This is a flowchart of a method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline according to the present invention. Detailed Implementation
[0030] The accompanying drawings are for illustrative purposes only and should not be construed as limiting this patent. To better illustrate this embodiment, some components in the drawings may be omitted, enlarged, or reduced, and do not represent the actual dimensions of the product. It is understandable to those skilled in the art that some well-known structures and their descriptions may be omitted in the drawings. The positional relationships described in the drawings are for illustrative purposes only and should not be construed as limiting this patent.
[0031] In the accompanying drawings of the embodiments of the present invention, the same or similar reference numerals correspond to the same or similar components. In the description of the present invention, it should be understood that if terms such as "upper," "lower," "left," "right," "long," and "short" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the drawings, they are only for the convenience of describing the present invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, the terms used to describe positional relationships in the drawings are only for illustrative purposes and should not be construed as limiting the present patent. For those skilled in the art, the specific meaning of the above terms can be understood according to the specific circumstances.
[0032] The technical solution of the present invention will be further described in detail below through specific embodiments and in conjunction with the accompanying drawings: Example 1 like Figure 1 As shown, a method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline includes the following steps: Step 1: Real-time monitoring of the liquid and gas phase contents, natural gas composition, pressure, and temperature in the pipeline to obtain real-time production data; Step 2: Confirm the subcooling of natural gas hydrate based on production data, calculate and obtain the injection amount of inhibitor based on the subcooling, and at the same time use production data to judge the flow state of pipeline fluid in real time. Determine the real-time compensation amount of inhibitor based on the flow state, and determine the final injection amount of inhibitor based on the obtained inhibitor injection amount and compensation amount. Step 3: Perform real-time dynamic injection of inhibitors based on the obtained final injection volume.
[0033] This method primarily targets and controls the risks associated with stratified flow processes, which carry significant risks. In step one, all data are monitored in real-time, and dynamic real-time production data is output to ensure the calculation of the real-time inhibitor input. In step two, the subcooling of natural gas hydrates is related to pressure and temperature, and a correlation exists between them. This can be determined by consulting existing data. Real-time subcooling data is output based on real-time pressure and temperature data, and the required real-time inhibitor injection amount is calculated from this data. Similarly, real-time production data is used to determine the real-time flow state of the fluid, and the required real-time inhibitor compensation amount is confirmed based on the flow state, thus determining the final inhibitor injection amount. This final injection amount is also dynamic data, allowing for dynamic inhibitor input to meet production needs. Simultaneously, the fluid state determination fully references and utilizes relevant data from the liquid and gas phases in the pipeline, as well as the natural gas composition, to ensure accurate fluid state assessment under different water-to-gas ratios, improving accuracy.
[0034] The beneficial effects of this embodiment are as follows: Through the above method, more refined dynamic injection of inhibitors can be achieved in deep-sea gas fields. The flow pattern of multiphase mixed-transport pipelines can be identified. When different flow patterns occur, different inhibitor injection amounts are used to achieve automatic adjustment and optimization of the inhibitor injection amount, thereby improving the inhibitor suppression effect, reducing the risk of hydrate formation, and ensuring the stable operation and efficient development of the gas field.
[0035] Example 2 This embodiment further defines the features of Embodiment 1, and its difference from Embodiment 1 lies in: In step two, the flow state of the fluid in the pipeline is determined based on the following first empirical model:
[0036]
[0037] when At that time, if , or when At that time, if At this point, the flow pattern is stratified flow; Above: X and Y are dimensionless parameters; , These are the liquid phase and gas phase mass flow rates, respectively, measured by a multiphase flow meter, with units of kg / h. The density refers to the gas phase and liquid phase. The gas phase density is calculated from the molar composition of the natural gas components, which are obtained by measurement using relevant instruments. The unit is kg / m³. 3 A represents the cross-sectional area of the pipe, in meters (m²). 3 ; The viscosity of the fluid in the pipeline is expressed in Pa·s. Specifically, it can be real-time or average data of the fluid viscosity in the pipeline, or data of the viscosity of the formation water. The surface tension of the fluid in the pipeline is expressed in N / m. It can be expressed as real-time or average data of the fluid viscosity in the pipeline, or as data of the viscosity of the formation water.
[0038] The subcooling of natural gas hydrate is calculated based on real-time monitored pressure and temperature. The formula for calculating the subcooling is as follows:
[0039] The above formula: This indicates the degree of subcooling of natural gas hydrate at the current pressure, expressed in °C. This represents the saturation temperature of natural gas under the current pressure, obtained by looking up a table; T is the current temperature.
[0040] Preferably, based on subcooling The injection volume of the inhibitor was calculated using the following second empirical model:
[0041]
[0042] Above: Cm represents the minimum concentration of the inhibitor in the liquid-phase aqueous solution, by mass percentage; This indicates the dosage of the inhibitor, expressed in kg / day. This indicates the flow rate of liquid water in a mixed-transport pipeline, expressed in kg / day.
[0043] In stratified flow, there is a special gas-liquid distribution state. The equilibrium process of ethylene glycol distribution between the gas and liquid phases results in ethylene glycol vaporization loss, which is calculated as QG (kg / day).
[0044]
[0045] This indicates the natural gas flow rate, in units of 10. 4 m 3 / day, The loss coefficient of the inhibitor in the pipeline is represented by an empirical value or by calculation. This indicates the final amount of inhibitor injected.
[0046] Based on the first empirical model, if the fluid state is stratified flow, then:
[0047]
[0048] If the fluid state is not a flow split, then .
[0049] The remaining features and working principles of this embodiment are the same as those of Embodiment 1.
[0050] Example 3 Based on Example 1 or Example 2, Example 1 or Example 2 are further defined, with the following differences: An automatic valve capable of dynamically adjusting the injection volume based on real-time data and calculating the real-time injection volume based on valve detection parameters is used as the inhibitor injection valve; specifically, a CIMV valve or other automatic valves with the aforementioned functions are employed. A multiphase flow meter is used to monitor the liquid and gas phase contents in the pipeline in real time. A chromatographic analysis instrument is used to monitor the natural gas composition in the pipeline in real time. Methanol or ethylene glycol is used as the inhibitor.
[0051] The remaining working principles and processes of this embodiment are the same as those of Embodiment 1 or Embodiment 2.
[0052] In the specific implementation of the above embodiments, the technical features can be combined in any non-contradictory way. For the sake of brevity, not all possible combinations of the above technical features are described. However, as long as the combination of these technical features is not contradictory, it should be considered to be within the scope of this specification.
[0053] Obviously, the above embodiments of the present invention are merely examples for clearly illustrating the present invention, and are not intended to limit the implementation of the present invention. Those skilled in the art can make other variations or modifications based on the above description. It is neither necessary nor possible to exhaustively describe all embodiments here. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of the present invention should be included within the scope of protection of the claims of the present invention.
Claims
1. A method for injecting hydrate inhibitors into deep-sea mixed-transport pipelines, characterized in that, Includes the following steps: Step 1: Real-time monitoring of the liquid and gas phase contents, natural gas composition, pressure, and temperature in the pipeline to obtain real-time production data; Step 2: Confirm the subcooling of natural gas hydrate based on production data, calculate and obtain the injection amount of inhibitor based on the subcooling, and at the same time use production data to judge the flow state of pipeline fluid in real time. Determine the real-time compensation amount of inhibitor based on the flow state, and determine the final injection amount of inhibitor based on the obtained inhibitor injection amount and compensation amount. Step 3: Perform real-time dynamic injection of inhibitors based on the final injection volume obtained.
2. The method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline according to claim 1, characterized in that: In step two, the flow state of the fluid in the pipeline is determined based on the following first empirical model: when At that time, if , or when At that time, if At this point, the flow pattern is stratified flow; Above: X and Y are dimensionless parameters; , These are the liquid phase and gas phase mass flow rates, respectively, measured by a multiphase flow meter, with units of kg / h. The density refers to the gas phase and liquid phase. The gas phase density is calculated from the molar composition of the natural gas components, which are obtained by measurement using relevant instruments. The unit is kg / m³. 3 A represents the cross-sectional area of the pipe, in meters (m²). 3 ; The viscosity of the liquid in the pipeline is expressed in Pa·s. The surface tension of the liquid in the pipe is expressed in N / m.
3. The method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline according to claim 2, characterized in that: In step two, the supercooling of natural gas hydrate is calculated based on the real-time monitored pressure and temperature. The formula for calculating the supercooling is as follows: The above formula: This indicates the degree of subcooling of natural gas hydrate at the current pressure, expressed in °C. This represents the saturation temperature of natural gas under the current pressure, obtained by looking up a table; T is the current temperature.
4. The method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline according to claim 3, characterized in that: Based on supercooling The injection volume of the inhibitor was calculated using the following second empirical model: Above: Cm represents the minimum concentration of the inhibitor in the liquid-phase aqueous solution, by mass percentage; This indicates the dosage of the inhibitor, expressed in kg / day. This indicates the flow rate of liquid water in a mixed-transport pipeline, expressed in kg / day.
5. The method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline according to claim 4, characterized in that: In stratified flow, there is a special gas-liquid distribution state. The equilibrium process of ethylene glycol distribution between the gas and liquid phases results in ethylene glycol vaporization loss, which is calculated as QG (kg / day). This indicates the natural gas flow rate, in units of 10. 4 m 3 / day, The loss coefficient of the inhibitor in the pipeline is represented by an empirical value or by calculation. This indicates the final amount of inhibitor injected.
6. The method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline according to claim 5, characterized in that: Based on the first empirical model, if the fluid state is stratified flow, then: If the fluid state is not a flow split, then .
7. The method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline according to claim 1, characterized in that: An automatic valve capable of dynamically adjusting the injection volume based on real-time data and calculating the real-time injection volume based on valve detection parameters is used as the injection valve for the inhibitor.
8. The method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline according to claim 1, characterized in that: A multiphase flow meter is used to monitor the liquid and gaseous contents of the pipeline in real time.
9. The method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline according to claim 1, characterized in that: Chromatographic analysis instruments are used to monitor the composition of natural gas in the pipeline in real time.
10. A method for injecting hydrate inhibitors into a deep-sea mixed-transport pipeline according to any one of claims 1-9, characterized in that: The inhibitor is methanol or ethylene glycol.