Natural gas pipeline cleaning method

Abstract

The invention provides a natural gas pipeline cleaning method which comprises the steps that a pipeline cleaner is used for cleaning a pipeline, and operation parameters of the pipeline cleaner comprise the maximum pressure difference P between the starting point and the end point of the pipeline in the pipeline cleaning process; the total air inflow required by pigging in a standard state is Q1; a natural gas flow rate Q required by ball pushing in a standard state; judging whether the pipeline starting point and the pipeline terminal point can meet the parameters required by the operation of the pipe cleaner or not; if yes, pipe cleaning operation is carried out; and if not, adjusting the pipeline starting point and / or the pipeline end point, or replacing equipment at the pipeline starting point and / or the pipeline end point, so that the pipeline starting point and the pipeline end point can meet the conditions. According to the method provided by the invention, key parameters can be calculated for pipelines of different types and different working conditions, so that the potential risk of pipeline cleaning operation is reduced, a natural gas pipeline cleaning risk evaluation system is perfected, and the feasibility of the natural gas pipeline cleaning operation is indirectly evaluated.

Description

Technical Field

[0001] The present disclosure relates to, but is not limited to, the field of safety assurance of natural gas transmission pipelines, relates to, but is not limited to, the calculation of key parameters before natural gas pipeline cleaning, and in particular relates to, but is not limited to, a natural gas pipeline cleaning method. Background Art

[0002] Pipe cleaning is an important daily task for natural gas pipelines. Conventional pipe cleaning can maintain the initial design transmission capacity of natural gas pipelines, clean up pipeline impurities, and purify the internal corrosion environment. Special pipe cleaning can also meet the needs of pipeline internal inspection in the later stage. Natural gas pipelines have complex working conditions, large numbers, and large volumes. The "Regulations on the Integrity Management of Oil and Gas Field Pipelines and Stations of China National Petroleum Corporation" has clearly stated that intelligent internal inspection of pipelines is the priority inspection and evaluation method in the management strategy for the construction period and operation and maintenance period of natural gas pipelines. It is an important means to reduce the leakage rate and maintenance costs of natural gas pipelines and protect the integrity of the system. The prerequisite for the above work is that the pipeline has the conditions for pipe cleaning, can smoothly implement the first pipe cleaning, and then realize periodic pipe cleaning. However, the natural gas pipeline cleaning operation faces many risks such as the failure of the pig to be sent out, pipeline leakage, wax blockage, pig blocking, stagnation, tracking failure, personal injury, and environmental pollution. Therefore, for natural gas pipelines that need to be cleaned, how to establish a steady-state mathematical model for pipe cleaning and clarify the pipe cleaning process parameters are crucial to ensure the safe and stable operation of natural gas pipelines.

[0003] The prior art lacks the steps and methods for determining key parameters before cleaning, and is unable to evaluate the cleaning conditions and capabilities of natural gas pipelines, which can easily cause the cleaning device to become stuck after throwing the ball and be unable to collect the ball. Therefore, the invention cannot meet the actual needs of the project. Summary of the invention

[0004] The following is a summary of the subject matter of the detailed description of the present disclosure. This summary is not intended to limit the scope of the claims.

[0005] The present invention discloses a method for determining key parameters of natural gas pipeline cleaning based on a steady-state mathematical model, which can calculate key parameters for natural gas pipelines of different types and working conditions, reduce potential risks of pipeline cleaning operations, improve the risk assessment system for natural gas pipeline cleaning, indirectly evaluate the feasibility of natural gas pipeline cleaning operations, and guide management units to formulate guidelines for safety assurance measures for cleaning operations, thereby reducing repair and maintenance costs caused by cleaning failures and improving the passability and work efficiency of cleaning.

[0006] The present disclosure provides a natural gas pipeline cleaning method, the method comprising:

[0007] The natural gas pipeline is cleaned using a pig, and the pig operation parameters include:

[0008] The maximum pressure difference ΔP between the starting point and the end point of the pipeline during the pigging process; the total air intake required for pigging under standard conditions Q1; the required natural gas flow rate Q required for pushing the ball under standard conditions;

[0009] Determine whether the starting point and the end point of the pipeline can meet the maximum pressure difference ΔP between the starting point and the end point of the pipeline during the pigging process required by the pig operation; the total air intake volume Q1 required for pigging under standard conditions; the natural gas flow rate Q required for pushing the ball under standard conditions;

[0010] If it can be met, then the pigging operation is carried out;

[0011] If it cannot be satisfied, adjust the pipeline starting point and / or the pipeline end point, or replace the equipment at the pipeline starting point and / or the pipeline end point, so that the pipeline starting point and the pipeline end point can meet the above conditions.

[0012] In one embodiment provided by the present disclosure, the method comprises:

[0013] Obtain the original parameters, which include: pipeline diameter d, pipeline distance x; along the pipeline pressure drop P, gas-liquid mixture Reynolds number Re m , the volume flow rate of the liquid phase Q l , the volume flow rate of the gas phase Q g , liquid density ρ l , gas phase density ρ g , the flow area occupied by the liquid phase is A l , the flow area occupied by the gas phase is A g , total length of pipeline L, radius of pipeline r, sliding friction coefficient between pipe cleaner and pipe wall λ, actual height of deformation of contact zone between pipe cleaner and inner wall of pipeline h, diameter of pipe cleaner r1; Poisson coefficient of rubber cup of pipe cleaner μ1, elastic modulus of rubber cup of pipe cleaner E1, bow area Δ;

[0014] Substitute the original parameters into equations (1) to (18) to calculate the maximum pressure difference ΔP between the starting point and the end point of the pipeline during the cleaning process:

[0015] The maximum pressure difference ΔP between the starting point and the end point of the pipeline during the cleaning process is calculated according to formula (1):

[0016] ΔP=ΔP1+ΔP2 (1)

[0017] In formula (1), ΔP is the maximum pressure difference between the starting point and the end point of the pipeline during the cleaning process, MPa; ΔP1 is the pressure drop along the natural gas pipeline, MPa; ΔP2 is the pressure drop caused by the friction resistance between the pig and the pipe wall, MPa;

[0018] The pressure drop ΔP1 along the natural gas pipeline described in formula (1) is calculated according to formula (2):

[0019] ΔP1=ΔP3+ΔP4 (2)

[0020] In formula (2), ΔP1 is the pressure drop along the natural gas pipeline, MPa; ΔP3 is the pressure drop along the natural gas horizontal pipeline, MPa; ΔP4 is the pressure drop caused by pipeline fluctuation and pigging liquid, MPa;

[0021] The pressure drop ΔP3 along the natural gas horizontal pipeline described in formula (2) is calculated according to formula (3):

[0022]

[0023] In formula (3), m is the hydraulic friction coefficient, dimensionless; ρ m is the density of gas-liquid mixture, kg / m 3 ;ω m is the flow rate of the gas-liquid mixture, m / s; d is the pipe diameter, mm; x is the distance along the pipe, m; P is the pressure drop along the pipe, MPa;

[0024] The hydraulic friction coefficient λ in formula (3) m Calculate according to formula (4):

[0025]

[0026] In formula (4), m is the hydraulic friction coefficient, dimensionless; C D2 is a coefficient, a function of the volume liquid content R1, dimensionless; Re m is the Reynolds number of the gas-liquid mixture;

[0027] In formula (4), the coefficient C D2 According to formula (5), we can calculate:

[0028]

[0029] In formula (5), C D2 is a coefficient, a function of the volume liquid content R1, dimensionless; S0 is a constant, dimensionless; R1 is the volume liquid content, %;

[0030] The volume liquid content R1 in formula (5) is calculated according to formula (6), and the constant S0 is calculated according to formula (7):

[0031]

[0032] S0=1.281-0.478(-lnR1)+0.444(-lnR1) 2 -0.094(-lnR1) 3 +0.00843(-lnR1)4 (7)

[0033] In formula (6), R1 is the volume liquid content, %; Q l is the volume flow rate of the liquid phase, m 3 / s;Q g is the volume flow rate of the gas phase, m 3 / s;

[0034] In formula (7), S0 is a constant, dimensionless; R1 is the volume liquid content, %;

[0035] In formula (3), the density of the gas-liquid mixture is m According to formula (8), it is calculated as follows:

[0036]

[0037] In formula (8), ρ m is the density of gas-liquid mixture, kg / m 3 ; R1 is the volume liquid content, %; ρ l is the liquid density, kg / m 3 ρ g is the gas phase density, kg / m 3 ; A l is the flow area occupied by the liquid phase, m 2 ; A g is the flow area occupied by the gas phase, m 2 ;

[0038] The gas-liquid mixture flow rate ω in formula (3) m According to formula (9), it is calculated as follows:

[0039]

[0040] In formula (9), ω m is the flow rate of the gas-liquid mixture, m / s; d is the pipe diameter, m; ρ m is the density of gas-liquid mixture, kg / m 3 ; G is the mass flow rate of the mixture, kg / s;

[0041] The pressure drop ΔP4 caused by pipeline fluctuation and pigging liquid in formula (2) is calculated according to formula (10). Formula (10) calculates the liquid accumulation pressure drop caused by pigging, assuming that the liquid accumulation is evenly distributed along the length of the pipe, and the total amount of liquid accumulation along the entire line is V w ; Only the static pressure loss caused by the increase in elevation is considered, and the energy release when the elevation is reduced is not considered. The pipeline is divided into sections according to the actual terrain height difference. Each pipeline with approximately the same slope is divided into a section. The length of each section i is ΔL i , the elevation difference of each segment i is ΔH i , the length of each segment i is Δ

[0042] H wi , calculate the accumulated fluid drop ΔP of each section i respectively wi :

[0043]

[0044] In formula (10), ΔP4 is the pressure drop caused by pipeline fluctuation and liquid accumulation during cleaning, MPa; ∑ΔH i is the cumulative elevation difference of each section, m;

[0045]

[0046] In formula (11), ΔH wi is the length of the fluid accumulation in each segment i, m; V w is the total amount of fluid accumulated along the entire line, m 3 ; d is the pipe diameter, m; ΔL i is the length of each section i of the pipeline, m; L is the total length of the pipeline, m;

[0047] ΔP wi =ρ w g×min(ΔH wi ,ΔH i ) (12)

[0048] In formula (12), ΔP wi is the accumulated hydraulic pressure drop in each section i, Pa; ρ w is the liquid density, kg / m 3 ; g is the acceleration due to gravity, which is 9.8m / s 2 ; ΔH wi is the length of the fluid accumulation in each section i, m; ΔH i is the elevation difference of each segment i, m;

[0049] In formula (1), the friction pressure difference ΔP2 between the pig and the pipe wall is calculated according to formula (13):

[0050] ΔP2=2πrlP'λ (13)

[0051] In formula (13), ΔP2 is the friction pressure difference between the pig and the pipe wall, MPa; r is the pipe radius, m; λ is the sliding friction coefficient between the pig and the pipe wall; l is the contact zone width between the pig and the pipe wall, m;

[0052] P' is the contact stress between the pig and the pipeline, Pa;

[0053] In formula (13), is the contact width l between the pig and the pipe wall, which is calculated according to formula (14):

[0054]

[0055] In formula (13), l is the width of the contact zone between the pig and the pipe wall, m; r is the radius of the pipe, m; h is the actual height of the deformation of the contact zone between the pig and the inner wall of the pipe, m;

[0056] In formula (13), the contact stress P' between the pig and the pipeline is calculated according to formula (15):

[0057]

[0058] In formula (15), P' is the contact stress between the pipe cleaner and the pipeline, Pa; δ is the average height of the deformation of the contact zone between the pipe cleaner and the inner wall of the pipeline, m; r is the radius of the pipeline, m; r1 is the diameter of the pipe cleaner, m; μ1 is the Poisson coefficient of the rubber cup of the pipe cleaner; E1 is the elastic modulus of the rubber cup of the pipe cleaner, Pa;

[0059] In formula (15), the average height δ of the deformation of the contact zone between the pig and the inner wall of the pipeline is calculated according to formula (16):

[0060]

[0061] In formula (16), δ is the average height of the contact zone between the pig and the inner wall of the pipeline, m; Δ is the arch area, m 2 ; l is the contact zone width between the pipe cleaner and the pipe wall, m.

[0062] In one embodiment provided by the present disclosure, the method comprises:

[0063] Obtain original parameters, the original parameters including:

[0064] Pipeline diameter d, total length of pipeline L, temperature T0 under standard conditions, atmospheric pressure P0 under standard conditions, natural gas temperature T at the pipeline starting point, natural gas compression factor Z, pipeline inlet pressure P Q , pipeline outlet pressure P Z ,

[0065] Among them, the total air intake volume Q1 required for pigging under standard conditions is calculated according to formula (17):

[0066]

[0067] In formula (17), Q1 is the required total air intake under standard conditions, m; d is the pipeline diameter, m; L is the total length of the pipeline, m; is the average pressure of the whole pipeline, MPa; T0 is the temperature under standard conditions, 293K; P0 is the atmospheric pressure under standard conditions, 0.1013MPa; T is the natural gas temperature at the starting point of the pipeline, K; Z is the natural gas compression factor;

[0068] The average pressure of the whole pipeline in formula (17) Calculate according to formula (18):

[0069]

[0070] In formula (18) is the average pressure of the whole pigging line, MPa; P Q is the pipeline inlet pressure, MPa; P Z is the pipeline outlet pressure, MPa.

[0071] In one embodiment provided by the present disclosure, the method comprises:

[0072] Obtain original parameters, the original parameters including:

[0073] Pipeline diameter d, average pig running speed The contact stress P' between the pig and the pipeline, the temperature T0 under standard conditions, the atmospheric pressure P0 under standard conditions, the natural gas temperature T at the starting point of the pipeline, and the natural gas compression factor Z;

[0074] The natural gas flow rate Q required for pigging and pushing the ball under standard conditions is calculated according to formula (19):

[0075]

[0076] In formula (19), Q is the natural gas flow rate required for pigging and pushing the ball under standard conditions, m / d; d is the pipeline diameter, m; P' is the contact stress between the pig and the pipeline, Pa; T0 is the temperature under standard conditions, 293K; P0 is the atmospheric pressure under standard conditions, 0.1013MPa; T is the natural gas temperature at the starting point of the pipeline, K; Z is the natural gas compression factor; Average operating speed of the pig, km / h.

[0077] In an embodiment provided by the present disclosure, the method further includes: the pig operation parameter also includes the total time t required for the pig pushing ball;

[0078] Determine whether the starting point and the end point of the pipeline can meet the total time t required for the pig to push the ball;

[0079] If it can be met, then the pigging operation is carried out;

[0080] If it cannot be satisfied, adjust the pipeline starting point and / or the pipeline end point, or replace the equipment at the pipeline starting point and / or the pipeline end point, so that the pipeline starting point and the pipeline end point can meet the above conditions.

[0081] In one embodiment provided by the present disclosure, the method further comprises:

[0082] Obtain original parameters, the original parameters including:

[0083] Total length of pipeline L, average speed of pig operation

[0084] The total time t required for pigging and pushing the ball is calculated according to formula (20):

[0085]

[0086] In formula (20), t is the time required for pipeline cleaning, h; L is the total length of the pipeline, km; is the average speed of the pig, km / h.

[0087] In one embodiment provided by the present disclosure, the method comprises: the average running speed of the pig is 12km / h to 18km / h.

[0088] In another aspect, the present disclosure provides a natural gas pipeline pigging system, using the natural gas pipeline pigging method described above, the system comprising:

[0089] The first acquisition module is used to obtain the original parameters: pipeline diameter d, pipeline distance x; along the pipeline pressure drop P, gas-liquid mixture Reynolds number Re m , the volume flow rate of the liquid phase Q l , the volume flow rate of the gas phase Q g , liquid density ρ l , gas phase density ρ g , the flow area occupied by the liquid phase is A l , the flow area occupied by the gas phase is A g , total length of pipeline L, pipeline radius r, sliding friction coefficient λ between pig and pipe wall, actual height of deformation of contact zone between pig and inner wall of pipe h, diameter of pig r1; Poisson coefficient μ1 of rubber cup of pig, elastic modulus E1 of rubber cup of pig, bow area Δ; pipeline diameter d, average speed of pig operation The contact stress P' between the pig and the pipeline, the temperature T0 under standard conditions, the atmospheric pressure P0 under standard conditions, the natural gas temperature T at the start of the pipeline, the natural gas compression factor Z; the average speed of the pig

[0090] The second acquisition module is used to calculate the maximum pressure difference ΔP between the starting point and the end point of the pipeline during the cleaning process using the formulas (1) to (20); the total air intake volume Q1 required for cleaning under standard conditions; the required natural gas flow rate Q required for pushing the ball under standard conditions; the pig operation parameters also include the total time t required for cleaning the ball;

[0091] The third acquisition module determines whether the pipeline start point and the pipeline end point can meet the maximum pressure difference ΔP between the pipeline start point and the pipeline end point during the pigging process required by the pig operation; the total air intake volume Q1 required for pigging under standard conditions; and the natural gas flow rate Q required for pushing the ball under standard conditions;

[0092] The fourth pigging module is used to determine whether to perform a pigging operation, or to provide feedback on parameters or conditions that may cause a pigging operation to fail to be performed.

[0093] On the other hand, the present disclosure provides an electronic device, which includes a memory and a processor, wherein the memory stores a computer program, and the processor executes the above-mentioned method for reducing the viscosity of oilfield produced fluid when running the computer program.

[0094] In yet another aspect, the present disclosure provides a storage device for storing a computer-readable program, wherein the computer-readable program, when executed, executes the above-mentioned method for reducing viscosity of oilfield produced fluid.

[0095] Other features and advantages of the present disclosure will be described in the following description, and partly become apparent from the description, or be understood by implementing the present disclosure. Other advantages of the present disclosure can be invented and obtained by the schemes described in the description. DETAILED DESCRIPTION

[0096] To make the purpose, technical solution and advantages of the present disclosure more clear, the embodiments of the present disclosure are described in detail below. It should be noted that the embodiments and features in the embodiments of the present disclosure can be combined with each other arbitrarily without conflict.

[0097] This disclosure makes the following assumptions for natural gas pipelines:

[0098] ① The flow rates of gas and liquid phases in natural gas pipelines are generally different, and there is slippage between the gas and liquid phases. Only when the flow rate is extremely high can it be approximately considered that there is no slippage between the two phases. Since the flow rate of general pipelines is not high, it is assumed in this disclosure that the slip ratio between the gas and liquid phases along the pipeline is constant;

[0099] ②The accumulated liquid in the pipeline is evenly distributed along the pipeline;

[0100] ③Since the static pressure loss is much higher than the energy recovery, the pipeline pigging process only considers the static pressure loss caused by the elevation increase, and the energy recovery of the downhill section can be ignored;

[0101] ④ It is assumed that the liquid holdup is only a function of the gas-liquid two-phase velocity, and the effect of the actual velocity of the gas and liquid on the liquid holdup is not considered;

[0102] ⑤ Ignore the weight of the pipe cleaner.

[0103] The above assumptions do not affect the universality of the natural gas pipeline cleaning method provided by the present disclosure.

[0104] The present disclosure exemplarily provides a natural gas pipeline pigging method, the method comprising:

[0105] The natural gas pipeline is cleaned using a pig, and the pig operation parameters include:

[0106] The maximum pressure difference ΔP between the starting point and the end point of the pipeline during the pigging process; the total air intake required for pigging under standard conditions Q1; the required natural gas flow rate Q required for pushing the ball under standard conditions;

[0107] Determine whether the starting point and the end point of the pipeline can meet the maximum pressure difference ΔP between the starting point and the end point of the pipeline during the pigging process required by the pig operation; the total air intake volume Q1 required for pigging under standard conditions; the natural gas flow rate Q required for pushing the ball under standard conditions;

[0108] If it can be met, then the pigging operation is carried out;

[0109] If it cannot be satisfied, adjust the pipeline starting point and / or the pipeline end point, or replace the equipment at the pipeline starting point and / or the pipeline end point, so that the pipeline starting point and the pipeline end point can meet the above conditions.

[0110] Exemplarily, the method comprises:

[0111] Obtain the original parameters, which include: pipeline diameter d, pipeline distance x, pressure drop P, gas-liquid mixture Reynolds number Re m , the volume flow rate of the liquid phase Q l , the volume flow rate of the gas phase Q g , liquid density ρ l , gas phase density ρ g , the flow area occupied by the liquid phase is A l , the flow area occupied by the gas phase is A g , total length of pipeline L, radius of pipeline r, sliding friction coefficient between pipe cleaner and pipe wall λ, actual height of deformation of contact zone between pipe cleaner and inner wall of pipeline h, diameter of pipe cleaner r1; Poisson coefficient of rubber cup of pipe cleaner μ1, elastic modulus of rubber cup of pipe cleaner E1, bow area Δ;

[0112] Substitute the original parameters into equations (1) to (18) to calculate the maximum pressure difference ΔP between the starting point and the end point of the pipeline during the cleaning process:

[0113] The maximum pressure difference ΔP between the starting point and the end point of the pipeline during the cleaning process is calculated according to formula (1):

[0114] ΔP=ΔP1+ΔP2 (1)

[0115] In formula (1), ΔP is the maximum pressure difference between the starting point and the end point of the pipeline during the pigging process, MPa; ΔP1 is the pressure drop along the natural gas pipeline, MPa; ΔP2 is the pressure drop caused by the friction resistance between the pig and the pipe wall, MPa;

[0116] The pressure drop ΔP1 along the natural gas pipeline described in formula (1) is calculated according to formula (2):

[0117] ΔP1=ΔP3+ΔP4 (2)

[0118] In formula (2), ΔP1 is the pressure drop along the natural gas pipeline, MPa; ΔP3 is the pressure drop along the natural gas horizontal pipeline, MPa; ΔP4 is the pressure drop caused by pipeline fluctuation and pigging liquid, MPa;

[0119] The pressure drop ΔP3 along the natural gas horizontal pipeline described in formula (2) is calculated according to formula (3):

[0120]

[0121] In formula (3), m is the hydraulic friction coefficient, dimensionless; ρ m is the density of gas-liquid mixture, kg / m 3 ;ω m is the flow rate of the gas-liquid mixture, m / s; d is the pipe diameter, mm; x is the distance along the pipe, m; P is the pressure drop along the pipe, MPa. is the pressure drop along the pipeline microelement section. After integration, we get ΔP3, which is the pressure drop along the horizontal natural gas pipeline.

[0122] The hydraulic friction coefficient λ in formula (3) m Calculate according to formula (4):

[0123]

[0124] In formula (4), m is the hydraulic friction coefficient, dimensionless; C D2 is a coefficient, a function of the volume liquid content R1, dimensionless; Re m is the Reynolds number of the gas-liquid mixture;

[0125] In formula (4), the coefficient C D2 According to formula (5), we can calculate:

[0126]

[0127] In formula (5), C D2 is a coefficient, a function of the volume liquid content R1, dimensionless; S0 is a constant, dimensionless; R1 is the volume liquid content, %;

[0128] The volume liquid content R1 in formula (5) is calculated according to formula (6), and the constant S0 is calculated according to formula (7):

[0129]

[0130] S0=1.281-0.478(-lnR1)+0.444(-lnR1) 2 -0.094(-lnR1) 3 +0.00843(-lnR1) 4 (7)

[0131] In formula (6), R1 is the volume liquid content, %; Q l is the volume flow rate of the liquid phase, m 3 / s;Q g is the volume flow rate of the gas phase, m 3 / s;

[0132] In formula (7), S0 is a constant, dimensionless; R1 is the volume liquid content, %;

[0133] In formula (3), the density of the gas-liquid mixture is m According to formula (8), it is calculated as follows:

[0134]

[0135] In formula (8), ρ m is the density of gas-liquid mixture, kg / m 3 ; R1 is the volume liquid content, %; ρ l is the liquid density, kg / m 3 ρ g is the gas phase density, kg / m 3 ; A l is the flow area occupied by the liquid phase, m 2 ; A g is the flow area occupied by the gas phase, m 2 ;

[0136] The gas-liquid mixture flow rate ω in formula (3) m According to formula (9), it is calculated as follows:

[0137]

[0138] In formula (9), ω m is the flow rate of the gas-liquid mixture, m / s; d is the pipe diameter, m; ρ m is the density of gas-liquid mixture, kg / m 3 ; G is the mass flow rate of the mixture, kg / s;

[0139] The pressure drop ΔP4 caused by pipeline fluctuation and pigging liquid in formula (2) is calculated according to formula (10). Formula (10) calculates the liquid accumulation pressure drop caused by pigging, assuming that the liquid accumulation is evenly distributed along the length of the pipe, and the total amount of liquid accumulation along the entire line is V w ; Only the static pressure loss caused by the increase in elevation is considered, and the energy release when the elevation is reduced is not considered. The pipeline is divided into sections according to the actual terrain height difference. Each pipeline with approximately the same slope is divided into a section. The length of each section i is ΔL i , the elevation difference of each segment i is ΔH i , the length of the liquid accumulation in each segment i is ΔH wi , calculate the accumulated fluid drop ΔP of each section i respectively wi :

[0140]

[0141] In formula (10), ΔP4 is the pressure drop caused by pipeline fluctuation and liquid accumulation during cleaning, MPa; ∑ΔH i is the cumulative elevation difference of each section, m;

[0142]

[0143] In formula (11), ΔH wi is the length of the fluid accumulation in each segment i, m; V w is the total amount of fluid accumulated along the entire line, m 3 ; d is the pipe diameter, m; ΔL i is the length of each section i of the pipeline, m; L is the total length of the pipeline, m;

[0144] ΔP wi =ρ w g×min(ΔH wi ,ΔH i ) (12)

[0145] In formula (12), ΔP wi is the accumulated hydraulic pressure drop in each section i, Pa; ρ w is the liquid density, kg / m 3 ; g is the acceleration due to gravity, which is 9.8m / s 2 ; ΔH wi is the length of the fluid accumulation in each section i, m; ΔH i is the elevation difference of each segment i, m;

[0146] In formula (1), the friction pressure difference ΔP2 between the pig and the pipe wall is calculated according to formula (13):

[0147] ΔP2=2πrlP'λ (13)

[0148] In formula (13), ΔP2 is the friction pressure difference between the pig and the pipe wall, MPa; r is the pipe radius, m; λ is the sliding friction coefficient between the pig and the pipe wall; l is the contact zone width between the pig and the pipe wall, m;

[0149] P' is the contact stress between the pig and the pipeline, Pa;

[0150] In formula (13), is the contact width l between the pig and the pipe wall, which is calculated according to formula (14):

[0151]

[0152] In formula (13), l is the width of the contact zone between the pig and the pipe wall, m; r is the radius of the pipe, m; h is the actual height of the deformation of the contact zone between the pig and the inner wall of the pipe, m;

[0153] In formula (13), the contact stress P' between the pig and the pipeline is calculated according to formula (15):

[0154]

[0155] In formula (15), P' is the contact stress between the pipe cleaner and the pipeline, Pa; δ is the average height of the deformation of the contact zone between the pipe cleaner and the inner wall of the pipeline, m; r is the radius of the pipeline, m; r1 is the diameter of the pipe cleaner, m; μ1 is the Poisson coefficient of the rubber cup of the pipe cleaner; E1 is the elastic modulus of the rubber cup of the pipe cleaner, Pa;

[0156] In formula (15), the average height δ of the deformation of the contact zone between the pig and the inner wall of the pipeline is calculated according to formula (16):

[0157]

[0158] In formula (16), δ is the average height of the contact zone between the pig and the inner wall of the pipeline, m; Δ is the arch area, m 2 ; l is the contact zone width between the pipe cleaner and the pipe wall, m.

[0159] Exemplarily, the method comprises:

[0160] Obtain original parameters, the original parameters including:

[0161] Pipeline diameter d, total length of pipeline L, temperature T0 under standard conditions, atmospheric pressure P0 under standard conditions, natural gas temperature T at the pipeline starting point, natural gas compression factor Z, pipeline inlet pressure P Q , pipeline outlet pressure P Z ,

[0162] Among them, the total air intake volume Q1 required for pigging under standard conditions is calculated according to formula (17):

[0163]

[0164] In formula (17), Q1 is the required total air intake under standard conditions, m; d is the pipeline diameter, m; L is the total length of the pipeline, m; is the average pressure of the whole pipeline, MPa; T0 is the temperature under standard conditions, 293K; P0 is the atmospheric pressure under standard conditions, 0.1013MPa; T is the natural gas temperature at the starting point of the pipeline, K; Z is the natural gas compression factor;

[0165] The average pressure of the whole pipeline in formula (17) Calculate according to formula (18):

[0166]

[0167] In formula (18) is the average pressure of the whole pigging line, MPa; P Q is the pipeline inlet pressure, MPa; P Z is the pipeline outlet pressure, MPa.

[0168] Exemplarily, the method comprises:

[0169] Obtain original parameters, the original parameters including:

[0170] Pipeline diameter d, average pig running speed The contact stress P' between the pig and the pipeline, the temperature T0 under standard conditions, the atmospheric pressure P0 under standard conditions, the natural gas temperature T at the starting point of the pipeline, and the natural gas compression factor Z;

[0171] The natural gas flow rate Q required for pigging and pushing the ball under standard conditions is calculated according to formula (19):

[0172]

[0173] In formula (19), Q is the natural gas flow rate required for pigging and pushing the ball under standard conditions, m / d; d is the pipeline diameter, m; P' is the contact stress between the pig and the pipeline, Pa; T0 is the temperature under standard conditions, 293K; P0 is the atmospheric pressure under standard conditions, 0.1013MPa; T is the natural gas temperature at the starting point of the pipeline, K; Z is the natural gas compression factor; Average operating speed of the pig, km / h.

[0174] Exemplarily, the pig operation parameters also include the total time t required for the pig pushing ball;

[0175] Determine whether the starting point and the end point of the pipeline can meet the total time t required for the pig to push the ball;

[0176] If it can be met, then the pigging operation is carried out;

[0177] If it cannot be satisfied, adjust the pipeline starting point and / or the pipeline end point, or replace the equipment at the pipeline starting point and / or the pipeline end point, so that the pipeline starting point and the pipeline end point can meet the above conditions.

[0178] Exemplarily, the method further includes:

[0179] Obtain original parameters, the original parameters including:

[0180] Total length of pipeline L, average speed of pig operation

[0181] The total time t required for pigging and pushing the ball is calculated according to formula (20):

[0182]

[0183] In formula (20), t is the time required for pipeline cleaning, h; L is the total length of the pipeline, km; is the average speed of the pig, km / h.

[0184] Exemplarily, the method comprises: the average speed of the pig operation 12km / h to 18km / h.

[0185] In another aspect, an embodiment of the present disclosure provides a natural gas pipeline pigging system, using the natural gas pipeline pigging method described above, the system comprising:

[0186] The first acquisition module is used to obtain the original parameters: pipeline diameter d, pipeline distance x; along the pipeline pressure drop P, gas-liquid mixture Reynolds number Re m , the volume flow rate of the liquid phase Q l , the volume flow rate of the gas phase Q g , liquid density ρ l , gas phase density ρ g , the flow area occupied by the liquid phase is A l , the flow area occupied by the gas phase is A g , total length of pipeline L, pipeline radius r, sliding friction coefficient λ between pig and pipe wall, actual height of deformation of contact zone between pig and inner wall of pipe h, diameter of pig r1; Poisson coefficient μ1 of rubber cup of pig, elastic modulus E1 of rubber cup of pig, bow area Δ; pipeline diameter d, average speed of pig operation The contact stress P' between the pig and the pipeline, the temperature T0 under standard conditions, the atmospheric pressure P0 under standard conditions, the natural gas temperature T at the start of the pipeline, the natural gas compression factor Z; the average speed of the pig

[0187] The second acquisition module is used to calculate the maximum pressure difference ΔP between the starting point and the end point of the pipeline during the cleaning process using the formulas (1) to (20); the total air intake volume Q1 required for cleaning under standard conditions; the required natural gas flow rate Q required for pushing the ball under standard conditions; the pig operation parameters also include the total time t required for cleaning the ball;

[0188] The third acquisition module determines whether the pipeline start point and the pipeline end point can meet the maximum pressure difference ΔP between the pipeline start point and the pipeline end point during the pigging process required by the pig operation; the total air intake volume Q1 required for pigging under standard conditions; and the natural gas flow rate Q required for pushing the ball under standard conditions;

[0189] The fourth pigging module is used to determine whether to perform a pigging operation, or to provide feedback on parameters or conditions that may cause a pigging operation to fail to be performed.

[0190] On the other hand, an embodiment of the present disclosure provides an electronic device, which includes a memory and a processor, wherein the memory stores a computer program, and the processor executes the above-mentioned method for reducing the viscosity of oilfield produced fluid when running the computer program.

[0191] The electronic device includes: at least one processor, at least one communication interface, at least one memory and at least one communication bus; optionally, the communication interface may be an interface of a communication module, such as an interface of a GSM module; the processor may be a processor CPU, or an application specific integrated circuit ASIC (Application Specific Integrated Circuit), or one or more integrated circuits configured to implement the embodiments of the present invention. The memory may include a high-speed RAM memory, and may also include a non-volatile memory (non-volatile memory), such as at least one disk memory. The memory stores a program, and the processor calls the program stored in the memory to execute some or all of the above-mentioned method embodiments.

[0192] The method provided by the present invention can calculate key parameters for pipelines of different types and working conditions, thereby reducing the potential risks of pipeline pigging operations, improving the risk assessment system for natural gas pipeline pigging operations, indirectly evaluating the feasibility of natural gas pipeline pigging operations, and guiding management units to formulate guidelines for safety assurance measures for pigging operations, thereby reducing the repair and maintenance costs caused by pigging failures and improving the passability and work efficiency of pigging operations.

[0193] Pipe cleaning is a routine operation of natural gas pipelines and is also the "inevitable path" for intelligent internal inspection. Every year, many oil and gas field companies in China need to carry out pipe cleaning, internal corrosion inspection and evaluation of a large number of pipelines, which requires a large workload and high capital investment. The method provided by the present disclosure can quickly, conveniently, scientifically and effectively predict pipe cleaning. It can be directly applied to the integrity management of oil and gas field enterprises. At the same time, the method provided by the present disclosure can not only be directly applied to the first pipe cleaning risk assessment of natural gas pipelines, but also effectively improve the management data analysis capabilities, and provide efficient and scientific method model tools for decision support, with broad market application prospects.

Claims

1. A natural gas pipeline cleaning method, characterized in that: The method comprises: The method uses a pipe cleaning device to clean the pipe, and the operating parameters of the pipe cleaning device include: The maximum pressure difference △P between the starting point and the end point of the pipeline during the cleaning process; the total air intake required for cleaning under standard conditions Q1; the required natural gas flow rate Q required for pushing the ball under standard conditions; Determine whether the starting point and the end point of the pipeline can meet the maximum pressure difference △P between the starting point and the end point of the pipeline during the pigging process required by the pig operation; the total air intake volume Q1 required for pigging under standard conditions; the natural gas flow rate Q required for pushing the ball under standard conditions; If it can be met, then the pigging operation is carried out; If it cannot be satisfied, adjust the pipeline starting point and / or the pipeline end point, or replace the equipment at the pipeline starting point and / or the pipeline end point, so that the pipeline starting point and the pipeline end point can meet the above conditions.

2. The method according to claim 1, characterized in that The method comprises: Obtain the original parameters, which include: pipeline diameter d, pipeline distance x, pressure drop P, gas-liquid mixture Reynolds number Re m , the volume flow rate of the liquid phase Q l , the volume flow rate of the gas phase Q g , liquid density ρ l , gas phase density ρ g , the flow area occupied by the liquid phase is A l , the flow area occupied by the gas phase is A g , total length of pipeline L, radius of pipeline r, sliding friction coefficient between pipe cleaner and pipe wall λ, actual height of deformation of contact zone between pipe cleaner and inner wall of pipeline h, diameter of pipe cleaner r1; Poisson coefficient of rubber cup of pipe cleaner μ1, elastic modulus of rubber cup of pipe cleaner E1, bow area Δ; Substitute the original parameters into equations (1) to (18) to calculate the maximum pressure difference △P between the starting point and the end point of the pipeline during the cleaning process: The maximum pressure difference △P between the starting point and the end point of the pipeline during the cleaning process is calculated according to formula (1): ΔP=ΔP1+ΔP2 (1) In formula (1), △P is the maximum pressure difference between the starting point and the end point of the pipeline during the cleaning process, MPa; △P1 is the pressure drop along the natural gas pipeline, MPa; △P2 is the pressure drop caused by the friction resistance between the cleaning device and the pipe wall, MPa; The pressure drop △P1 along the natural gas pipeline described in formula (1) is calculated according to formula (2): ΔP1=ΔP3+ΔP4 (2) In formula (2), △P1 is the pressure drop along the natural gas pipeline, MPa; △P3 is the pressure drop along the natural gas horizontal pipeline, MPa; △P4 is the pressure drop caused by pipeline fluctuation and liquid accumulation during cleaning, MPa; The pressure drop △P3 along the natural gas horizontal pipeline described in formula (2) is calculated according to formula (3): In formula (3), m is the hydraulic friction coefficient, dimensionless; ρ m is the density of gas-liquid mixture, kg / m 3 ;ω m is the flow rate of the gas-liquid mixture, m / s; d is the pipe diameter, mm; x is the distance along the pipe, m; P is the pressure drop along the pipe, MPa; The hydraulic friction coefficient λ in formula (3) m Calculate according to formula (4): In formula (4), m is the hydraulic friction coefficient, dimensionless; C D2 is a coefficient, a function of the volume liquid content R1, dimensionless; Re m is the Reynolds number of the gas-liquid mixture; In formula (4), the coefficient C D2 According to formula (5), we can calculate: In formula (5), C D2 is a coefficient, a function of the volume liquid content R1, dimensionless; S0 is a constant, dimensionless; R1 is the volume liquid content, %; The volume liquid content R1 in formula (5) is calculated according to formula (6), and the constant S0 is calculated according to formula (7): In formula (6), R1 is the volume liquid content, %; Q l is the volume flow rate of the liquid phase, m 3 / s;Q g is the volume flow rate of the gas phase, m 3 / s; S0=1.281-0.478(-lnR1)+0.444(-lnR1) 2 -0.094(-lnR1) 3 +0.00843(-lnR1) 4 (7) In formula (7), S0 is a constant, dimensionless; R1 is the volume liquid content, %; In formula (3), the density of the gas-liquid mixture is m According to formula (8), it is calculated as follows: In formula (8), ρ m is the density of gas-liquid mixture, kg / m 3 ; R1 is the volume liquid content, %; ρ l is the liquid density, kg / m 3 ρ g is the gas phase density, kg / m 3 ; A l is the flow area occupied by the liquid phase, m 2 ; A g is the flow area occupied by the gas phase, m 2 ; The gas-liquid mixture flow rate ω in formula (3) m According to formula (9), it is calculated as follows: In formula (9), ω m is the flow rate of the gas-liquid mixture, m / s; d is the pipe diameter, m; ρ m is the density of gas-liquid mixture, kg / m 3 ; G is the mass flow rate of the mixture The pressure drop △P4 caused by pipeline fluctuation and pigging liquid in formula (2) is calculated according to formula (10). Formula (10) calculates the liquid drop caused by pigging, assuming that the liquid is evenly distributed along the length of the pipe, and the total amount of liquid accumulated along the entire line is V w ; Only the static pressure loss caused by the elevation increase is considered, and the energy release when the elevation decreases is not considered. The pipeline is divided into sections according to the actual terrain elevation difference. Each pipeline with approximately the same slope is divided into a section. The length of each section i is △L i , the elevation difference of each segment i is △H i , the length of the liquid accumulation in each segment i is △H wi , calculate the accumulated fluid pressure drop △P of each section i respectively wi : In formula (10), △P4 is the pressure drop caused by pipeline fluctuation and liquid accumulation during cleaning, MPa; ∑△H i is the cumulative elevation difference of each section, m; In formula (11), △H wi is the length of the fluid accumulation in each segment i, m; V w is the total amount of fluid accumulated along the entire line, m 3 ; d is the pipe diameter, m; △L i is the length of each section i of the pipeline, m; L is the total length of the pipeline, m; ΔP wi =ρ l g×min(ΔH wi ,ΔH i ) (12) In formula (12), △P wi is the accumulated hydraulic pressure drop in each section i, Pa; ρ l is the liquid density, kg / m 3 ; g is the acceleration due to gravity, which is 9.8m / s 2 ; △H wi is the length of the fluid accumulation in each section i, m; △H i is the elevation difference of each segment i, m; In formula (1), the friction pressure difference △P2 between the pig and the pipe wall is calculated according to formula (13): ΔP2=2πrlP'λ (13) In formula (13), △P2 is the friction pressure difference between the pig and the pipe wall, MPa; r is the pipe radius, m; λ is the sliding friction coefficient between the pig and the pipe wall; l is the contact zone width between the pig and the pipe wall, m; P' is the contact stress between the pig and the pipe, Pa; In formula (13), is the contact width l between the pig and the pipe wall, which is calculated according to formula (14): In formula (13), l is the width of the contact zone between the pig and the pipe wall, m; r is the radius of the pipe, m; h is the actual height of the deformation of the contact zone between the pig and the inner wall of the pipe, m; In formula (13), the contact stress P' between the pig and the pipeline is calculated according to formula (15): In formula (15), P' is the contact stress between the pipe cleaner and the pipeline, Pa; δ is the average height of the deformation of the contact zone between the pipe cleaner and the inner wall of the pipeline, m; r is the radius of the pipeline, m; r1 is the diameter of the pipe cleaner, m; μ1 is the Poisson coefficient of the rubber cup of the pipe cleaner; E1 is the elastic modulus of the rubber cup of the pipe cleaner, Pa; In formula (15), the average height δ of the deformation of the contact zone between the pig and the inner wall of the pipeline is calculated according to formula (16): In formula (16), δ is the average height of the contact zone between the pig and the inner wall of the pipeline, m; Δ is the arch area, m 2 ; l is the contact zone width between the pipe cleaner and the pipe wall, m.

3. The method according to claim 1 or 2, characterized in that: The method comprises: Obtain original parameters, the original parameters including: Pipeline diameter d, total length of pipeline L, temperature T0 under standard conditions, atmospheric pressure P0 under standard conditions, natural gas temperature T at the pipeline starting point, natural gas compression factor Z, pipeline inlet pressure P Q , pipeline outlet pressure P Z , Among them, the total air intake volume Q1 required for pigging under standard conditions is calculated according to formula (17): In formula (17), Q1 is the required total air intake under standard conditions, m; d is the pipeline diameter, m; L is the total length of the pipeline, m; is the average pressure of the whole pipeline, MPa; T0 is the temperature under standard conditions, 293K; P0 is the atmospheric pressure under standard conditions, 0.1013MPa; T is the natural gas temperature at the starting point of the pipeline, K; Z is the natural gas compression factor; The average pressure of the whole pipeline in formula (17) Calculate according to formula (18): In formula (18) is the average pressure of the whole pigging line, MPa; P Q is the pipeline inlet pressure, MPa; P Z is the pipeline outlet pressure, MPa.

4. The method according to claim 2, characterized in that: The method comprises: Obtain original parameters, the original parameters including: Pipeline diameter d, average pig running speed The contact stress P' between the pig and the pipeline, the temperature T0 under standard conditions, the atmospheric pressure P0 under standard conditions, the natural gas temperature T at the starting point of the pipeline, and the natural gas compression factor Z; The natural gas flow rate Q required for pigging and pushing the ball under standard conditions is calculated according to formula (19): In formula (19), Q is the natural gas flow rate required for pigging and pushing the ball under standard conditions, m / d; d is the pipeline diameter, m; P' is the contact stress between the pig and the pipeline, Pa; T0 is the temperature under standard conditions, 293K; P0 is the atmospheric pressure under standard conditions, 0.1013MPa; T is the natural gas temperature at the starting point of the pipeline, K; Z is the natural gas compression factor; Average operating speed of the pig, km / h.

5. The method according to claim 1 or 2, characterized in that: The method further comprises: The pig operation parameters also include the total time t required for the pig pushing ball; Determine whether the starting point and the end point of the pipeline can meet the total time t required for the pig to push the ball; If it can be met, then the pigging operation is carried out; If it cannot be satisfied, adjust the pipeline starting point and / or the pipeline end point, or replace the equipment at the pipeline starting point and / or the pipeline end point, so that the pipeline starting point and the pipeline end point can meet the above conditions.

6. The method according to claim 5, characterized in that Obtain original parameters, the original parameters including: Total length of pipeline L, average speed of pig operation The total time t required for pigging and pushing the ball is calculated according to formula (20): In formula (20), t is the time required for pipeline cleaning, h; L is the total length of the pipeline, km; is the average speed of the pig, km / h.

7. The method according to claim 4 or 6, characterized in that: The average speed of the pig operation 12km / h to 18km / h.

8. A natural gas pipeline pigging system, characterized in that: Using the method of any one of claims 1 to 7, the system comprises: The first acquisition module is used to obtain the original parameters: pipeline diameter d, pipeline distance x; along the pipeline pressure drop P, gas-liquid mixture Reynolds number Re m , the volume flow rate of the liquid phase Q l , the volume flow rate of the gas phase Q g , liquid density ρ l , gas phase density ρ g , the flow area occupied by the liquid phase is A l , the flow area occupied by the gas phase is A g , total length of pipeline L, pipeline radius r, sliding friction coefficient λ between pig and pipe wall, actual height of deformation of contact zone between pig and inner wall of pipe h, diameter of pig r1; Poisson coefficient μ1 of rubber cup of pig, elastic modulus E1 of rubber cup of pig, bow area Δ; pipeline diameter d, average speed of pig operation The contact stress P' between the pig and the pipeline, the temperature T0 under standard conditions, the atmospheric pressure P0 under standard conditions, the natural gas temperature T at the start of the pipeline, the natural gas compression factor Z; the average speed of the pig The second acquisition module is used to calculate the maximum pressure difference ΔP between the starting point and the end point of the pipeline during the cleaning process using the formula (1) to the formula (20); the total air intake volume Q1 required for cleaning under standard conditions; the required natural gas flow rate Q required for pushing the ball under standard conditions; the pig operation parameters also include the total time t required for cleaning the ball; The third acquisition module determines whether the pipeline start point and the pipeline end point can meet the maximum pressure difference △P between the pipeline start point and the pipeline end point during the pigging process required by the pig operation; the total air intake volume Q1 required for pigging under standard conditions; the required natural gas flow rate Q required for pigging under standard conditions; and the total time t required for pigging pigging; The fourth pigging module is used to perform a pigging operation, or to provide feedback on parameters or conditions that are involved in a pigging operation that cannot be performed.

9. An electronic device, comprising a memory and a processor, wherein the memory stores a computer program, and the processor executes the method according to any one of claims 1 to 7 when running the computer program.

10. A storage device for storing a computer-readable program, wherein when the computer-readable program is executed, the method according to any one of claims 1 to 7 is executed.

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