SY/T 5904-2024 Selection principle and design method for electrie submersible pump English, Anglais, Englisch, Inglés, えいご
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ICS
E
Professional standard of the People's Republic of China
SY/T 5904-2024
Replaces SY/T 5904-2004
Selection principle and design method for electric submersible pump
潜油电泵选型原则及设计方法
(English Translation)
Issue date: 2024-12-25 Implementation date: 2025-06-25
Issued by National Development and Reform Commission, P.R.C
Contents
Foreword
1 Scope
2 Normative References
3 Terms and Definitions
4 Safety Management
5 Pipeline Commissioning
6 Operation Control
7 Station Management
8 Pipeline Route
9 Emergency Management
Appendix A (Informative) Evaluation Content for Crude Oil Pipeline Flow Safety
Appendix B (Informative) Operational Process Calculations for Crude Oil Pipelines
Bibliography
Selection Principles and Design Method for Electric Submersible Pumps
1 Scope
This document specifies the selection of electric submersible pumps, well selection and data preparation, calculation of gas volume fraction at the pump intake, pressure determination, inflow performance calculation for oil wells, and selection of electric submersible pump units and their auxiliary equipment.
This document applies to the selection and design of electric submersible pumps for oil wells.
2 Normative References
The following documents contain provisions which, through normative reference in this text, constitute essential provisions of this document. For dated references, only the edition cited applies. For undated references, the latest edition (including any amendments) applies.
GB/T 16750 Electric submersible pump unit
GB/T 17386 Sizing and selection of electric submersible pump installations
3 Terms and Definitions
No terms and definitions are required for this document.
4 Well Selection and Data Preparation
4.1 Well Selection Requirements
The selected target oil well shall meet the following requirements:
a) The formation should have the capacity for continuous and stable fluid supply, and the fluid supply capacity should match the equipment;
b) Well conditions meet the requirements, such as no casing deformation, no leakage, etc.;
c) The maximum projected size of the electric submersible pump unit matches the casing inner diameter;
d) Under predetermined production conditions, the gas volume fraction at the pump intake shall not exceed the maximum gas handling capacity of the electric submersible pump unit.
4.2 Data Preparation
4.2.1 Basic Data of the Oil Well
Basic data of the oil well includes:
a) Wellbore trajectory;
b) Oil well casing specifications and artificial bottom hole depth;
c) Oil well tubing specifications and its connection thread specifications;
d) Midpoint depth of the oil layer and perforated interval;
e) Relative density of crude oil, formation water, and natural gas;
f) Oil layer temperature;
g) Crude oil viscosity;
h) Saturation pressure and original gas-oil ratio.
4.2.2 Current Production Data of the Oil Well
Current production data of the oil well includes:
a) Formation pressure;
b) Productivity index for liquid or oil;
c) Liquid production rate and flowing pressure of the oil well;
d) Water cut;
e) Tubing pressure and casing pressure;
f) Producing gas-oil ratio and total gas production rate;
g) Sand content, wax deposition, scaling, and corrosion conditions.
4.2.3 Comprehensive Information
Other comprehensive information includes:
a) Casing damage conditions and locations;
b) Power supply mode and voltage at the well site;
c) Degree of perfection of the injection-production system.
5 Determination of Gas Volume Fraction at Pump Intake and Pressure
5.1 Dissolved Gas-Oil Ratio at Pump Intake
5.1.1 When the pressure at the pump intake is higher than the saturation pressure, the dissolved gas-oil ratio is calculated according to Formula (1).
5.1.2 When the pressure at the pump intake is lower than the saturation pressure, the dissolved gas-oil ratio needs correction. The corrected dissolved gas-oil ratio is calculated according to Formula (2).
5.2 Natural Gas Volume Factor
The natural gas volume factor is calculated according to Formula (4).
5.3 Oil Formation Volume Factor
The oil formation volume factor is calculated according to Formula (5).
5.4 Gas Volume Fraction at Pump Intake
The gas volume fraction at the pump intake is the percentage of the gas phase volume relative to the total volume of oil, gas, and water three phases at the pump intake, calculated according to Formula (6).
Using Formula (6), the gas volume fraction at the pump intake under different pump intake pressures can be calculated, and a curve of the relationship between pump intake pressure and intake gas volume fraction can be plotted (see Figure 2).
5.5 Pump Intake Pressure
Based on the gas handling capacity of the gas separator and/or gas handler, determine the appropriate gas volume fraction at the pump intake. Then, from Figure 2, find the pump intake pressure when using the electric submersible pump for production.
6 Inflow Performance Calculation for Oil Wells
6.1 Inflow Performance Judgment
Obtain key data points of liquid production rate and bottomhole flowing pressure from production data. Plot the inflow performance relationship curve (referred to as "IPR curve", see Figure 3) to determine the type of oil well inflow performance, which assists in pump selection design.
6.2 Determination of Productivity Index for Liquid
6.2.1 When the bottomhole flowing pressure is not less than the saturation pressure, its value is the negative reciprocal of the curve slope. The productivity index for liquid is calculated according to Formula (7).
6.2.2 When the bottomhole flowing pressure is greater than the pressure on the oil-gas-water three-phase IPR curve corresponding to the limit production rate of oil-gas inflow performance (i.e., the pressure Pwc corresponding to point G in Figure 3), and the bottomhole flowing pressure is less than the saturation pressure, the productivity index for liquid is calculated according to Formulas (8) to (12).
6.2.3 When the bottomhole flowing pressure is less than the pressure on the oil-gas-water three-phase IPR curve corresponding to the limit production rate of the oil-gas two-phase IPR, the productivity index for liquid is calculated according to Formulas (13) to (15).
6.2.4 When the saturation pressure, oil well water cut, formation pressure, and the oil well liquid production rate and its corresponding bottomhole flowing pressure at a test point are known for a given oil well, the productivity index for liquid of that oil well can be calculated using the formulas for the productivity index for liquid from Formulas (7) to (15).
6.3 Calculation of Inflow Performance for Oil, Gas, and Water Three-Phase Flow
6.3.1 When the bottomhole flowing pressure is greater than the saturation pressure, the liquid production rate is calculated according to Formula (16).
6.3.2 When the bottomhole flowing pressure is greater than the pressure on the oil-gas-water three-phase IPR curve corresponding to the limit production rate of the oil-gas two-phase IPR, and the bottomhole flowing pressure is less than the saturation pressure, the liquid production rate is calculated according to Formula (17).
6.3.3 When the bottomhole flowing pressure is less than the pressure on the oil-gas-water three-phase IPR curve corresponding to the limit production rate of the oil-gas two-phase IPR, the liquid production rate is calculated according to Formulas (18) to (20).
By transforming this calculation model, three-phase inflow performance calculation models for vertical, deviated, and horizontal wells can also be established, which calculate the corresponding bottomhole flowing pressure based on different liquid production rates.
6.4 Determination of Fluid Supply Capacity of Oil Wells
