GB/T 47444-2026Prediction and prevention requirements for natural gas hydrate formation in subsea oil and gas pipelines (English PDF)

5.1 Experimental determination of hydrate formation temperature

5.1.1 Natural gas and water samples should be taken during the determination of hydrate formation temperature. Natural gas sampling should be performed in accordance with GB/T 13609; Water sampling shall be carried out in accordance with GB/T 4756.

5.1.2 The experimental method for determining the hydrate formation temperature shall be performed in accordance with SY/T 7676.

5.1.3 There should be no fewer than 5 hydrate formation temperature measurement points for each sample, and the distribution of pressure measurement points should cover the operating conditions of subsea oil and gas pipelines. scope.

5.2 Calculation of Hydrate Formation Temperature Model

5.2.1 Fluid composition data When calculating the hydrate formation temperature, the fluid composition should include the following data.

a) Content of components C1, C2, C3, C4, C5, and C6;

b) Content of non-hydrocarbon components such as CO2, N2, and H2S;

c) Water production rate and concentrations of thermodynamic inhibitors such as methanol and ethylene glycol in the water;

d) Content of salt ions such as Na, Ca2+, K+, Cl-, and Br- in the aqueous phase of the pipeline.

5.2.2 Pure Water System For pure water systems, the calculation of hydrate formation temperature in subsea oil and gas pipelines should preferably use the van der Waals-Platform method. teeuw (see A.1 in Appendix A) or Chen-Guo (see A.2) theoretical models.

5.2.3 Systems containing thermodynamic inhibitors or salts For systems containing thermodynamic inhibitors or salts, hydration can be directly calculated using the van der Waals-Platau and Chen-Guo theoretical models. The hydrate formation temperature; alternatively, it can be calculated based on the hydrate formation temperature in a pure water system, combined with the Hammerschmidt method. (Hammerschmidt, see A.3), Nielsen, see A.4, Yousif, see A.5, Muhammadi Empirical models such as (Mohammadi, see A.6) are used to calculate hydrate formation temperatures, but empirical models should be selected and used according to their applicable range. The empirical model is applicable to the following areas.

a) When methanol is used as a hydrate inhibitor in the system, the empirical model for calculating the hydrate formation temperature should preferably be the Hammerschmidt model. Model;

b) When ethylene glycol is used as a hydrate inhibitor in the system, the Nelson model should be used as the empirical model for calculating the hydrate formation temperature;

c) The cations and anions in a salt-containing system usually inhibit hydrate formation. Water mainly contains five ions. Na^+, Ca^2+, K^+, Cl^-, and Br^-. For the calculation of the hydrate formation temperature of ions, the Yussiff model is recommended as an empirical model; other salt ions in water can be calculated based on ionic equivalence and relative... Based on the principle of approximate molecular weight, the mole fractions of Na, Ca2+, K+, Cl-, or Br- are used for approximate calculation.

d) When methanol or ethylene glycol and salt components are present in the system, the hydrate formation temperature should be calculated using the Muhammad model.

5.2.4 Other Systems The hydrate formation temperature of other systems besides those mentioned above should not be calculated by model but should be determined experimentally.

Note. Other systems include, but are not limited to, alcohol systems other than methanol and ethylene glycol, and systems containing mixtures of various thermodynamic inhibitors.

6.2 Chemical control methods

6.2.1 Selection of Chemical Reagents Chemical agents that can be used to control natural gas hydrates in subsea oil and gas pipelines include thermodynamic inhibitors, kinetic inhibitors, and polymerization inhibitors. Chemical agents. When using chemical agents for the control of natural gas hydrates in subsea oil and gas pipelines, the following rules apply, including but not limited to.

a) The freezing point of chemical reagents should be at least 5°C lower than the operating temperature at any point along the subsea oil and gas pipeline;

b) Thermodynamic inhibitors should be given priority in the control of hydrates;

c) When a subsea oil and gas pipeline is scheduled to be shut down, thermodynamic inhibitors should be used for hydrate control;

d) When the storage space for thermodynamic inhibitors on offshore platforms is limited and the gas-oil ratio in the pipelines is greater than 550, kinetic inhibitors may be selected. Implement hydrate control measures;

e) When the storage space for thermodynamic inhibitors on offshore platforms is limited and the liquid phase water content in the fluid in the pipeline is less than 30%, polymerization inhibitors can be selected. Implement hydrate control measures.

6.2.2 Thermodynamic Inhibitors When using thermodynamic inhibitors for hydrate control, the following rules apply, including but not limited to.

a) The principle for determining the amount of thermodynamic inhibitor injected is that after adding the thermodynamic inhibitor, the operating temperature at any point along the pipeline should be higher than that of the pipeline. The hydrate formation temperature is more than 5°C higher;

b) The calculation method for the dosage of hydrate thermodynamic inhibitors is given in Appendix B;

c) If methanol is selected for hydrate control, it should be used in accordance with GB/T 338.

6.2.3 Kinetic Inhibitors When using kinetic inhibitors for hydrate control, the following rules apply, including but not limited to.

a) The effectiveness of kinetic inhibitors in controlling hydrates under different degrees of supercooling and dosages should be evaluated experimentally;

b) The induction period for the formation of kinetic inhibitors should be at least 5 hours longer than the time it takes for the fluid to flow from the pipe inlet to the outlet;

c) The concentration of the active ingredient in the kinetic inhibitor should preferably be 0.5% to 3.0% of its concentration in the aqueous solution (by mass fraction). The quantity should be determined based on the laboratory evaluation results;

6.5 Dehydration Control Methods

6.5.1 If the inlet of the subsea oil and gas pipeline is located on an offshore oil and gas processing platform and the platform is equipped with dehydration facilities, the dehydration method can be used for subsea processing. Control of hydrates in oil and gas pipelines.

6.5.2 When using dehydration methods for hydrate control in subsea oil and gas pipelines, the formation temperature of natural gas hydrates after dehydration should be lower than that of the fluid inside the pipeline. The minimum temperature is more than 5°C lower.