SY/T 10024-1998 Recommended practices for the design, installation, repair and operation of underground safety valve systems
Some standard content:
ICS75.180.10
Record number: 5021-1998
People's Republic of China offshore oil and gas industry standard SY/T10024--1998
Replaces SY/T4807-92
idtAPIRP14B:1994
Recommended practice for design, installation, repair and operation of safety valve system1998-09-20 Released
1999-01-01 Implementation
Released by China National Offshore Oil Corporation
SY/T10024—1998
API Pre-Ji
Specialized Period
1 Description
2 Reference Standards
3 Terminology
4 Design
5 Installation
6 Operation, Inspection, Testing, Repair and Maintenance Appendix A (Appendix to the Standard)
Appendix B (Appendix to the Standard)
Appendix C (Appendix of the Standard)
Appendix D (Appendix of the Standard)
Appendix E (Appendix of the Standard)
Conversion of SI units and imperial system
Specification data format of underground safety valves under control Small example of wireline (rope) man and pull-out and push-out safety valves Fault report
Downhole valve shipment report (example) +
Appendix F (Appendix of the Standard)
Downhole safety valve repair report (example)…
Appendix G (Appendix of the Standard) Post-installation test procedure for ground control well safety valves Appendix II (Appendix of the Standard) Recommendations for ordering underground safety valve equipment… Figure 1 Example of downhole safety valve system
Figure 2 Schematic diagram of downhole safety valve control system controlled by ground: Figure 3 Flow chart of downhole control of speed type valve Figure 4 Flow chart of downhole control of low tubing pressure type valve Figure 5 Design of gas lift and low tubing pressure type left bottom control safety valve 13
SY/T10024—1998
This standard is based on the American Petroleum Institute (API) "Recommended Practice for Design, Installation, Repair and Operation of Downhole Safety Valve Systems 1994 Edition, namely API RP14B (API Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve System, 1990) Fourth Edition, revised SY/T4807-92, and is equivalent to APIRP14B in technical content. In this way, the design, installation, handling and operation procedures of my country's downhole safety valve system are directly in line with international standards through equivalent adoption, so as to meet the needs of my country's offshore oil and gas resource development. The measurement units in this standard are mainly expressed in SI units, that is: SI units are in front, and the corresponding values of British units are marked in brackets at the end: In order not to change the formulas in the original standard, the constants, coefficients and shape characteristics of the curves are still expressed in the original British system. If there is any objection to the standard translation, the original text shall prevail. In the design, construction and use of offshore oil and natural gas development projects involving the government of the original standard or other current laws, regulations and regulations, they shall be implemented in accordance with the corresponding laws, regulations and regulations promulgated by the government of the People's Republic of China or the competent government departments. The data or quantitative calculation methods of environmental conditions such as wind, waves, currents, ice, temperature, earthquakes, etc. in the original standard should be combined with the actual situation in my country, and the actual data and quantitative calculation methods that conform to the environmental conditions in my country should be used: According to the requirements of GB/T1.1--1993, the original preface of the original standard is retained, and the preface of the Chinese version of this standard is added. The provisions of this standard are related to the design, installation, repair and operation procedures of the downhole safety valve system to ensure that future offshore operations are in line with international standards, and it is recommended to be implemented in accordance with the requirements of this standard. This standard will be implemented from January 1, 1999. From the date of entry into force, this standard will replace SY/T4807-92. Appendix A, Appendix B, Appendix C, Appendix D, Appendix E, Appendix F, Appendix G, and Appendix II of this standard are all appendices to the standard. This standard is proposed and sponsored by China National Offshore Oil Corporation. This standard is compiled and edited by the Secretariat of the Offshore Oil Standardization Committee. SY/T10024—1998
API Foreword
Note: This section is not part of ISO10417—1993 edition. ASUOfT
APIRP14B is the basic part of ISO10417-1993 edition. The full text of AP1 and ISO standards is included in this document. There are some differences between the API and ISO versions of this standard, such as: API's "Special Instructions" and "Foreword" sections are not included in ISO10417-1993. The text of the ISO version is unique in that the text of the chapter titles is in bold italics, or the chapters are distinguished and identified by annotations. The API version is unique in that the chapter titles are identified by annotations or shading. This version changes the practice of using bold lines to mark each section in the previous version.
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API specifications and recommended practices for safety, pollution prevention equipment and systems for offshore oil and gas production, with an emphasis on standards applicable to manufacturing, equipment testing and system analysis methods. Unless otherwise required in the text, the appendix is included as a reference only. This standard will take effect on the date printed on the cover, but can be used voluntarily from the date of issuance. Users of this standard should be familiar with the content of this field. This document is intended to supplement rather than replace the judgment of individual projects. SY/T10024—1998||tt ||Special Notes
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1 Overview
Offshore Oil and Gas Industry Standard of the People's Republic of China Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve System 1.1 Purpose
SY/T 10024—1998
Replaces SY/T4807—92
idt API RP 14B: 1994
The purpose of this recommended practice is to describe the components and engineering principles for the design, installation, and operation of subsurface safety valve (SSSV) systems. This standard is intended for use by engineering design and operation personnel. 1.2 Classification of Operations
SSSVs installed in accordance with this recommended practice should be suitable for one or more of the following operations. 1.2.1 Class 1 - Standard Operations
SSSVs of this type are designed for use in oil wells or gas wells where there is no harmful effect of sand erosion or stress corrosion cracking. 1.2.2 Class 2 - Sandy Operations
SSSVs of this type are suitable for oil wells and gas wells where sand production is expected to occur downhole and may cause SSSV equipment failure. SSSVs of Class 2 must also meet the requirements of Class 1 Standard Operations. 1.2.3 Class 3 - Stress Corrosion Cracking Operations This type of SSSV is intended for use in oil wells and gas wells where there is a corrosive medium that may cause stress corrosion cracking. Category 3 equipment must also meet the requirements of Category 1 or Category 2 services and be made of materials that resist stress corrosion cracking. There are two categories in this category, 35 for sulfide stress cracking services and 3C for chloride stress cracking services. 1.2.4 Category 4 - Weight Loss Corrosion Service Category This category of SSSV equipment is intended for use in downhole environments with corrosive media where weight loss corrosion is expected. Category 4 equipment must meet the requirements of Category 1 or Category 2 and be made of materials that resist weight loss corrosion. 1.3 Scope bzxz.net
This recommended practice includes considerations for system design, safe installation and repair, and operating and inspection guidelines to ensure the safe and effective operation of the SSSV system. It also includes procedures for incident reporting. This recommended practice is for SSSV systems for wireline (rope), tubing pullout, and pumping.
2 Dream Test Standards
The following are some recommended practices and standards that are useful for the design, installation, operation, repair, and maintenance of SSV systems. American Petroleum Institute
API SP14A Downhole Safety Valve Equipment Specification [ISO10432] API RP14C, Recommended Practice for Analysis, Design, Installation and Testing of Safety Systems for Offshore Production Platform Topside Facilities, API RP14E Recommended Practice for Design and Installation of Offshore Production Platform Pipeline Systems, API RP14F Recommended Practice for Design and Installation of Offshore Production Platform Electrical Systems. Approved by China National Offshore Oil Corporation on September 20, 1998 and implemented on January 1, 1999
3 Terms
SY/T10024—1998
The following definitions are used to explain some terms that appear in the downhole safety valve system standard: 3.1 Bean
A throttling or orifice device designed to cause a pressure drop in velocity-type SSCSVs 3.2 Concentric Control System—A concentric pipe device that transmits control signals to the SSCSV system. 3.3 Control Line
A separate line used to transmit control signals to the SCSSV. 3.4 Equalizing Featrue (EF) A mechanism for opening the SSSV. A type of closing element that allows oil to flow and bypass pressure across the SSSV to help open the 3.5 Emergency Shut-Down (ESD) - complete shutdown.
3.6 Failure
Safety Device (Fail-SafeDevice) 3.7 Failure -
A system in the control station. Once the system is triggered, the platform will automatically shut down when the control medium is lost. A device that switches to a safe position. Any accident that prevents the SSSV device from performing its designed functions. 3.8 Erosion of Flow Coupling
.
3.9 Fusible Plug
Failure in SSSV system
A thick-walled short section. Its function is to withstand the flow caused by the throttling in the pipe string. A fusible plug or a component of the SSSV ground control system, which melts and activates the safety device in the event of a fire.
3.10: Manufacturer r)
A broker who is engaged in the design, manufacture and supply of SSSV equipment and who complies with API Spec 14A. 3.11 Operating Manual (Operating Manual) and detailed data and instructions for repairs
3.12 Operator (Operator
A manual compiled by the manufacturer. It contains information about the design, installation, and operation of SSSV equipment.
3.13 Preventative Maintenance (Preventative Maintenance) 3.14 Qualified Parts (Qualified Part) The performance is equal to or better than the original parts
3.15 Qualified Pers (Qualilied Pers
Maintenance work performed before the SSSV equipment fails. Parts produced according to the approved quality assurance plan. As a replacement part, its performance
Those who have been qualified through training or their own experience or one of them, and have been tested and assessed by established standards, have the ability to complete the specified tasks. Any operation of replacing parts or disassembling/reassembling SSSV equipment according to the operating manual. Repairs can be performed in the existing 3.16 Repair (Repair)
On-site or off-site, the explanation is as follows
a) On-site repair
b) Off-site repair
Replacement of parts as specified in the operating manual
The operation of disassembly, reassembly and functional testing of SSSV equipment. According to the operating manual, it involves
3.17 Safety Valve Seat Sleeve (SafetyValv
SSSV is installed inside. It is connected to an external power source of SSSV.
Landing Nipple)
A kind of landing working cylinder. It has an inner sealing surface, a groove in the production string that can accommodate the safety valve locking device, and fix the SSSV in place, and has an opening and an operation 3.18 Safety Valve Locking Device (SafetyValveLock) or a part of the valve.
A device that locks the SSSV in position and is attached to the SSSV. 3.19 Shall—This term indicates that this Recommended Practice has a specific applicability to the situation. 3.20 Should—This term indicates that this Recommended Practice: a) has an available operating procedure that is similarly safe; b) may be impractical in certain circumstances; or c) may be unnecessary in certain circumstances. 3.21 Surface-Controlled Subsurface Safety Valve (SCSSV)—SSSV that is controlled from the surface by hydraulic, electrical, mechanical or other means. 3.22 Surface-Controlled Subsurface Safety Valve (SSCSV)—SSSV that is actuated based on the flow characteristics of the well. This valve is usually actuated by the pressure differential across the SSCSV (velocity type) or by the tubing pressure at the SSCSV (high or low tubing pressure type). 3.23 Subsurface Safety Valve (SSSV)—A device installed below the wellbore port that is designed to prevent a blowout. It can be lowered or pulled out by steel wire (rope) and/or pumping (through oil pipe) [wire (rope) recovery type], or it can be installed on the oil pipe string and lowered into the well with the oil pipe string (oil pipe recovery type). 3.24 The lower safety valve assembly (SSSVAssembly) only includes the SSSV itself.
Includes the SSSV and the safety valve locking device. If it refers to tubing-recoverable SSSVs, ssVEquipment) - includes SSSV, safety valve locking device and safety valve seat sleeve 3.25 Downhole safety valve equipment (
3.26 Downhole safety valve system (sssVSystem) Any required control components.
Its downhole components include SSSV, safety valve locking device, seat sleeve, flow short joint and 3.27 Surface control system (SurtaeeControlSystem) 3.28 Surface safety valve (SurfaceSaletyValve) The surface system includes manifolds, sensors and power sources to drive SCSSV. An automatic wellhead valve that closes when the power supply disappears. Under this standard, the safety valve includes a surface safety valve, a safety valve driver and a thermally sensitive switch device. 3.29 Well test rate (WellTestRate) 3.30 Well (Wcll head)—
The stable production at that time according to routine production. The oil well head refers to the combined equipment on the ground used to maintain control of the oil well. Its equipment includes the lowest and middle casing heads, tubing heads, Christmas trees, valves and accessories, casing and tubing hangers and accessories, etc. 4 Design (1)
4.1 Introduction
The typical system diagrams of these two types are shown in Figure 1. The SSSV system can be selected according to the applicable specifications. On the other hand, designers should consider the specifications of the tubing string in the well. SSSV systems are designed based on factors such as size, clearances, flow conditions, corrosion inhibitors, installation depth, and well production performance. Attention should also be paid to the types of operations identified in Chapter 1 of this recommended practice. 4.1.2 This chapter covers factors that should be considered in the design, installation, operation, and repair of surface systems for SCSSVs that are controlled from the surface or other remote control points.
4.2 Surface-Controlled Subsurface Safety Valves (SCSSVs) 4.2.1 For surface-controlled systems, clearances are an important design consideration. Casing and tubing size dictate the type of SCSSV. The concentric control system requires more space than a separate control line. The threaded interface of the tubing-recoverable SCSSV generally has a larger outer diameter than the wire (rope)-recoverable safety valve. When designing and testing the system, the inner and outer tubing strings must take the larger of the two values of liquid control pressure or wellhead pressure. 4.2.2 When using concentric control
, the complete design of such systems should be estimated to ensure the integrity of the components under the test pressure. Special attention should be paid to avoid leakage at the joints. 4.2.3 When selecting the control line, the following factors should be considered: a) The complete liquid and its temperature in the annular space where the control pipeline is located: b) operating pressure;
c) rated working pressure:
d) damage to the control pipeline due to corrosion during operation or installation; e) selection of binding materials;
f) downhole fluid flow conditions;
g) inner and outer diameters of the control pipeline
h) continuous control pipe;
i) design and material of the control pipeline joint; i) material of the control pipeline;
k) control pipe liquid;
1) control pipeline manufacturing process.
4.2.4 The following factors should be considered when selecting the control pipe liquid: Note: 1) The design referred to in this standard should be understood as the design of the system. 3
a) Flammability:
b) Flash point:
c) Solid content;
d) Corrosiveness:
e) Lubricity:
SY/T10024—1998
1) Compatibility with SCSSV metal materials and sealing materials;
g) Compatibility with downstream fluids:
h) Ambient temperature:
) Viscosity;
) Density.
4.2.5 Determination of SCSSV installation depth
The following factors should be considered when determining the installation depth of SCSSV;a) Determine a safe installation depth according to the operating manual;b) Pressure gradient between the annular space and the control/balance pipeline body; Determine the SSSV first closing pressure from the performance test data;d) Calculate the SCSV under the condition of opening the well and flowing automatically Tubing pressure at: e) Operating friction associated with SCssV type and sealing element: f) Safety factor:
g) Minimum depth allowed according to regulation requirements. 4.2.6- This method is to re-pressurize the tubing to the shut-in tubing pressure (i.e., balance pressure) before any SSV is opened. 4.2.7 The SSSV seat sleeve and locking device for wire (rope) recovery should be selected to adapt to the wellbore environmental conditions. 4.2.8 The flow short joint (flawcnipling) can be selected according to the wellbore conditions to reduce the pressure on the SSS Erosion of the SCSSV and/or the tubing string. Consideration should be given to installing a flow nipple on each SSSV.
4.3 Surface control system
4.3.1 The surface control system must include the necessary components to detect abnormal conditions that may lead to uncontrolled and blowout, and must transmit the necessary signals to the SCSSV for closure (see Figure 2). 4.3.2 All components in the system must be analyzed for potential hazards that may cause equipment damage. For example, the control system should not contain automatic reset components, because such components may cause the SCSSV that should have remained closed to reopen. 4.3.3 It is appropriate to integrate the ground control system of the SCSSV into the entire ground safety system to avoid duplication. However, certain components should be added to the integrated system design so that abnormalities caused by daily production will not cause all SCSSVs to close. 4.3.4 Whenever a hydraulic or pneumatic control system is used, the test pressure of the ground control system should be the rated working pressure of its components. 4.3.5 All components that are under the operating pressure of the SSSV must be designed according to the expected maximum operating pressure of the SSSV. 4.3.6 Materials should be selected to resist the effects of environmental factors such as turbidity and ambient temperature. 4.3.7 Sensors
a) Each device must be analyzed to determine the available sensors for providing signals to the SCSSV. Types include thermal sensors, pressure sensors and level sensors.
b) High/low level sensors can be placed in the hydraulic system supply tank to warn of abnormal operating conditions: for example: oil and fluid flow into the control line or there is a leak in the control line. A low pressure controller can also be installed at the pump discharge port. 4.3.8 Power
a) The minimum input power of the system design should exceed the operating power of the entire system. b) For convenience, the design should include a backup power source. It can be a common manual pump in the hydraulic system or an independent prime mover in other systems. For routine maintenance operations of oil wells, measures should be formulated to operate SCSSVs separately. In the steam pressure and hydraulic system, a pressure relief valve should be installed to avoid system overpressure. 4
SY/T10024—1998
d) The capacity of the hydraulic fluid storage tank of the hydraulic indicator system should be large enough to increase the system to the rated working force after the system is fully filled, while maintaining an effective working level.
e) In the hydraulic system, the hydraulic fluid storage tank must have a large enough drain hole to release the pressure of the hydraulic fluid backflow when the SCSSV is closed or to release the pressure of the hydraulic fluid flowing through the control pipeline. Systems using gas flow control require a supply of clean gas: 4.3.9 General
a) Figure 2 shows a simplified control system. It includes a manifold, sensors and power source, ground control system! The manifold includes an emergency shutdown (FSI) valve, a multi-stage separation valve and a connector for connecting to the safety system: b) For multi-stage installations, the manifold should include a device to separate each switch. () Care should be taken when designing the outlet position of the multi-stage control pipeline. This connection is equipped with a valve to close the valve and separate the valve from the control system. However, this valve must remain in the open position during normal operation. And once closed, its position should also be easily identified. Because the beauty will effectively make the SSV inoperative:
d) Emergency Shutdown (ESI) should be installed in an easily accessible location based on current regulations and reliable process judgment: To avoid closing the SSSV when the oil flow is fully produced. There is a delay between the shutdown of the ground safety system and the shutdown time of the SCSSV: When restoring the production facilities to normal operation, the opening sequence should be reversed. This delay mechanism must be carefully designed to ensure that it does not cause additional hazards and add additional faults to the system. Under normal conditions, the full time should be 2 min-5 min4.4 Factors to be considered in the downhole safety valve system controlled by the downhole control4.4.1 For the downhole control SSSVs, the downhole flow and production characteristics become the decisive factors in the selection and design: 4.4.2 When determining the installation depth of the SSSV, the extent of scaling or accumulation is given consideration4.4.3 In the absence of facilities for pressurizing the oil pipe, for! When using a steel wire (green) to open the SSCSV, it is necessary to consider installing a balancing nipple. 4.4.4 SSCSV Screening Procedure
a) Overview
Generally, there are two designs of SSCSV (speed type or low tubing pressure type: The speed type SSCSV is designed based on the pressure difference generated by the high-speed liquid flow through the throttle nozzle in the valve exceeding the design difference predetermined by the installer: The low tubing pressure type SSV is designed based on the principle of closing the valve when the tubing pressure drops to a predetermined reference value below ten: The reference pressure value is determined by the air pressure of an air bottle in the valve: For the design of the SCSV, it is recommended to consult the valve manufacturer: b) Speed type SSCSV
The following is the recommended procedure for screening speed type SSCSV. Figure 3 is a flow chart of the SSCSV screening procedure: Step 1: Take a representative oil well to test the production. The requirements for testing oil and gas wells are shown in Appendix P, B and B: Step 2: Calculate or measure the well bottom flow dynamics under production conditions as indicated in Step 1: When making this calculation, an appropriate vertical flow related value should be used. If installed in SSCSV during testing. To determine the correct bottom flow dynamics, the pressure drop through the orifice (orifice) must be calculated:
Bei Step 3: Calculate the bottom flow dynamics of the well based on the data obtained in Steps 1 and 2. For oil wells, the production index or Vog IPR should be calculated. The back pressure equation for unobstructed flow derived from the U.S. Bureau of Mines can be used for gas slurries. Having data from two different test productions is beneficial for more accurate determination of the slurry bottom flow dynamics: After the bottom flow dynamics of the half-liter are determined, the slurry bottom flow dynamics of the other productions can be calculated: Step 4: Select the throttle nozzle based on the specific manufacturer, model mode, or the required pressure drop to screen the speed type SSSV: The throttle nozzle must have a small enough diameter to produce the pressure required to close the SSCSV. On the other hand, the throttle nozzle should have a large diameter to avoid excessive drop, thereby To reduce the erosion/corrosion of the tubing, the pressure difference range recommended by the manufacturer is followed for all speed-type SSCSVs of various specifications. Note: 1) The production index (PE) can be defined as the number of condensates produced when the volume drops by 1/2.0% above the bottom of the sump. 2) Vog, IV "Natural Gas Weak Flow Rate (R Petroleum Technology Journal 19i[392, 3) Rawling, F.1. and M.A. Slallardt: "Natural Gas and Application Data and Application in Production Practice: Island Special Paper 7: (1935). J68. 5
SY/T10024—1998
. Due to the low reliability of pressure drop calculation, it must be used with caution if the throttle orifice diameter exceeds 0% of the tubing diameter. For gas wells, the calculated flow rate through the choke should not exceed the critical flow rate. For reliable gas well orifice calculations, the pressure drop through the choke should not exceed 15% of the pressure value immediately below the SSCSV under normal conditions. The comparison coefficients of reasonable flow coefficients and pressure drops for SSCSV and chokes can be obtained from the manufacturer. Step 5: Select a rate of shut-in. This rate should not be greater than 150% of the test rate, but should not be less than 110% of the test rate. For wells with a rate of less than 63.6m/d (400bbl/d), the SSCSV can be designed to shut-in at a rate not greater than 31.8m/d (200bbl/d) of the test rate. To avoid the trouble of frequent shut-ins and valve throttling, this rate must be greater than the test rate.
Step 6: The shut-in production parameters are calculated as follows: Bottomhole flowing pressure. Calculate this value using the bottomhole flow dynamic equation obtained in step 3. - Pressure immediately below the SSCSV. Obtained using appropriate vertical flow related values. Pressure drop or choke size, using a reasonable orifice contrast factor and tubing flow pressure. The surface tubing pressure should exceed 345 kPa (50 psig) at the flow rate that causes the shut-in. If the calculated surface tubing pressure is less than 345 kPa (50 psig), select a smaller shut-in rate and recalculate.
Step 7: Calculate the required shut-in force for the SSCSV. The manufacturer will provide applicable data. Shims are usually used to obtain the required spring compression. A spring with a specific stiffness must be selected and properly compressed to cause the valve to remain open at the test rate and close at the calculated shut-in rate. Ensure that all requirements of steps 4, 5, and 6 are met. If not, return to step 4 and select another choke size or pressure drop. c) Low tubing pressure type:
SSCSV driven by reduced tubing pressure surface can be used for self-flowing oil wells and gas and continuous gas lift wells. This pressure type SSCSV is not suitable for intermittent gas lift wells. As with velocity-type SSCSVs, to properly screen for low tubing pressure-type SSCSVs, the well test rate and the rate that caused the shut-in must be known. Some wells may require pressure measurements to more accurately determine the flowing pressure at the SSCSV. Low tubing pressure-type SSCSVs can be screened using the following recommended procedure. Figure 4 shows a flow chart for SSCSV screening. 1) Flowing oil and gas wells
Step 1: Obtain test rates. Appendix A lists the data required for oil and gas wells. Step 2: Calculate or measure the flowing pressure at the depth of the SSCSV and the flowing pressure at the bottom. When calculating, use an appropriate vertical flow correlation equation.
Step 3: Determine the bottomhole flow state equation. The same method listed in Step 3 for velocity-type SSCSVs can be used. Step 4: Determine the flowing temperature at the SSCSV. This temperature requirement is required to properly screen for gas-filled pressure-type SSCSVs. It is usually assumed that the flow temperature increases linearly from the surface to the bottomhole static temperature. Step 5: Select the rate that caused the shut-in. This production should not be greater than 150% of the test production, nor less than 110% of the test production. For oil wells with production less than 63.6m/d (400bbl/d), the SSCSV can be designed to shut in a production no greater than 31% of the test production.Close when the flow rate is above 8m/d (200bbl/d). To avoid frequent closing and valve throttling, the closing rate must be greater than the test rate
Step 6: Calculate the parameters that cause the closing rate: Bottomhole flowing pressure. Apply the dynamic equation for the bottom flow obtained in step 3 to calculate this value. Pressure at the SSCSV. Use an appropriate vertical flow correlation equation. Wellhead flowing pressure. Under the flow rate flow that causes the closing, the surface tubing pressure should exceed 345kPa (50psig). If the calculated wellhead tubing flowing pressure is less than 345kPa (50psig), select a smaller closing rate and recalculate.
Step 7: Set the closing pressure of the low tubing pressure type SSCSV under the condition of causing the closing rate. To avoid frequent closing, the closing pressure should be at least 345kPa (50psig) less than the flowing pressure at the safety valve depth.
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