ICS75-010 E10 File No.: 11576-2003 SY

Petroleum and Natural Gas Professional Standard of The

People’s Republic of China SY/T5922-2003

Replace SY/T 5922-94, SY/T6149-1995, SY/T6233-2002, SY/T6383-1999

Run Criterion of Natural Gas Pipeline

Issued on March 18, 2003 Implemented on August 1, 2003

Issued by the State Economic and Trade Commission

SY/T 5922-2003

Contents

Foreword ........................................................................................................Error! Bookmark not defined.

1. Scope........................................................................................................................................................... 3

2. Normative references .................................................................................................................................. 3

3. Terms and definations ................................................................................................................................. 4

4. General ........................................................................................................................................................ 5

5. Gas quality requirement ............................................................................................................................. 6

6. Project pre-acceptance................................................................................................................................. 7

7. Trial operation and commissioning ............................................................................................................. 8

8. Operation management ............................................................................................................................... 9

Annex A (Informative) Pipeline Drying Method........................................................................................... 20

Annex B (Normative) Pipeline Operation Process Calculation .................................................................... 22

Annex C (Normative) Pipeline Pressure Test Process Calculation ............................................................... 28

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SY/T 5922-2003

Foreword

This standard is the revision of SY/T5922-94 “Code for Operation and Management of Natural Gas Pipeline”, SY/T6149-1995 “Technical Code for Pressure Test of Natural Gas Running Pipeline”, SY/T6233-2002 “Code for Trial Operation and Commissioning of Natural Gas Pipeline” and SY/T6383-1999 “Regulations on Cleaning Operation of Long Distance Natural Gas Pipeline”.

This standard has integrated the four standards of SY/T5922-94, SY/T6149-1995, SY/T6233-2002 and SY/T6383-1999 into one and in addition, it has revised the part of the original standards that can no longer meet the actual needs and made consistency modification for the content of conflict between standards.

Annex A of this standard is informative and Annexes B and C are normative.

This standard was proposed by and under the jurisdiction of the Standardization Technical Committee for Oil and Gas Storage and Transportation.

The drafting organizations of this standard: Pipeline Branch of PetroChina Company Limited, Southwest Oil and Gas Field Branch, Beijing Huayou Natural Gas Co. Ltd.

The main draftsmen of this standard: Zhang Cheng, Lu Xiaofeng, Shu Changcheng, Zhang Zengqiang, Liao Qiang, Zhang Xiangping and Zhang Peng.

The previous versions of the standards replaced by this standard are:

- SY/T5922-94;

- SY/T6149-1995;

- SY/T6233-1996, SY/T6233-2002;

- SY/T6383-1999.

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SY/T 5922-2003

Run Criterion of Natural Gas Pipeline

1. Scope

This standard specifies the technical requirements and regulations for the commissioning, acceptance, trial operation, and operation management and maintenance of the pipeline to transmit purified natural gas.

This standard is applicable to the transmission pipeline of purified natural gas.

2. Normative references The following normative documents contain provision which, through reference in this text, constitutes provisions of this national standard. For dated reference, subsequent amendments (excluding error correction) to, or revisions of, any of these publications do not apply. However all parties to agreements based on this standard are encouraged to investigate the possibility of applying the most recent editions of the standards. For undated references, the latest edition of the normative document referred to applies.

GB/T 11060.1 Natural gas--Determination of hydrogen sulfide content--Lodometric titration method

GB/T 11061 Natural gas--Determination of sulfur--Oxidative microcoulometry method

GB/T11062 Natural gas-Calculation of calorific values, density, relative density and Wobbe index

GB/T13609 Natural gas - Sampling guidelines

GB/T13610 Analysis of natural gas by gas chromatography

GB/T17283 Determination of the water dew point of natural gas--Cooled surface condensation hygrometers

GB50251-1994 Design code for gas transportation pipeline engineering

SY/T 0043 Standard for painting color of pipelines and equipments in oil-gas field

SY/T0061 Technical regulations on organic coatings on external walls of buried steel pipelines

SY0401 Code for construction and acceptance of oil and natural gas pipeline project

SY0402 Standard for construction and acceptance of oil and natural gas station process pipeline project

SY/T0420 Technology standard of petroleum asphalt coating for buried steel pipeline

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SY0470 Code for construction and acceptance of oil and gas pipeline aerial crossing engineering

SYJ4006 Code for construction and acceptance of long distance pipeline cathodic protection project

SYJ4051 Safety code on hot work for gathering process pipeline in oil-gas field

SY/T4079 Specification for construction and acceptance of petroleum and gas pipeline crossing engineering

SY/T5918 Technical regulations on overhaul of asphalt anti-corrosion coating on buried steel pipeline

SY/T6045 Code for equipping of measuring instruments for natural gas transportation enterprises

SY/T6068 Code of service and maintenance for elevated part of oil-gas pipeline and its auxiliary facilities

SY/T6143 Calculation Method of natural gas flow rate with the standard orifice

SY/T6324 Administrative provisions for oil and gas pipeline instrument and automation facilities

SY/T6325 Regulations of Technical management for oil and gas pipeline technical equipment

SY/T6470 Regulations of operation, maintenance and service for common valves of oil and gas pipeline

Protective Rules for Petroleum and Natural Gas Pipeline Order 313 of State Council, issued on July 26, 2001.

3. Terms and definitions

The following terms and definitions are applicable to this standard.

3.1 Water dew point

The temperature at which gas educes the first drop of water under certain pressure.

3.2 Hydrocarbon dew point

The temperature at which gas educes the first drop of liquid hydrocarbon under certain pressure.

3.3 Compression factor

The ratio of the volume of any mass gas to the volume of the gas calculated according to the perfect gas law under same conditions, under the specified pressure and temperature:

Z=Vm (actual)/Vm (ideal) (1)

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Vm (ideal)=RT/p (2)

Z (p, T, y)=pVm (actual) /(RT) (3)

Where:

p –absolute pressure;

T –thermodynamic temperature;

y – represents a set of gas parameters (in principle, y can be total molar composition or a characteristic set of relevant physicochemical properties or the combination of the two);

Vm –molar volume of gas;

R –molar gas constant, unrelated to unit;

Z – compressive factor.

3.4 Gas transmission station

Station yards set up according to the need of transmission process at the start and end points and along the line of the gas transmission pipeline, generally including initial station, final station, intermediate pigging station, compressor station, offtake station and distribution etc.

3.5 Compressor station

The station arranged along the gas pipeline where compressor is used to pressurize natural gas in pipeline.

3.6 Surging

A phenomenon specific to the centrifugal compressor. The centrifugal compressor with any structural size will have a lower limit for flow and upper limit for compression ratio at a certain speed. Lower than the lower limit for flow or higher than the upper limit for compression ratio, the unit will start to surge intensely accompanied with abnormal blare.

3.7 Surplus quantum

The percentage of the value of spherical pig OD higher than pipeline ID to pipeline ID.

3.8 SCADA system

Supervisory control and data acquisition system, regardless of scale or size, consists of three parts: the Master Terminal Unit (MTU), the Remote Terminal Unit (RTU) in station yards and the communication system connecting them. The SCADA system is used to continuously monitor the designated facilities and operate and control these facilities from the control center.

3.9 Underground gas storage

The facility that stores natural gas in gaseous state by taking the advantage of the natural geological structure (e.g. depleted oil-gas field, aquifer and salt bed etc).

4. General

4.1 A 15d~20d maintenance period should be arranged annually for the gas pipeline.

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4.2 A detailed scheme shall be compiled for the production activities such as pipe purging, pressure test, drying, displacement, commissioning, pigging, and internal (external) wall test of trunk pipeline, including:

a) Organizational framework, responsibility and agreement etc of production activities;

b) Historic records and present situation of pipeline;

c) Detailed operation procedure and sequence;

d) Safety and environmental protection measures;

e) Accident prevention plan.

4.3 All pipeline production activities shall be recorded, analyzed, compiled and placed on file.

4.4 All pipeline production activities shall meet the requirements of national and local laws and regulations on safety and environmental protection.

5. Gas quality requirement

5.1 Gas quality index

5.1.1 Quality indices of pipeline gas are shown in Table 1.

Table 1 Quality Indices of Pipeline Gas

Item Quality index

Gross calorific value, MJ/m3 ≥31.4

Total sulfur (based on sulfur), mg/m3

≤200

Hydrogen sulfide, mg/m3 ≤20

Carbon dioxide, % (volume fraction)

≤3.0

Oxygen, % (volume fraction) ≤0.5

Water dew point, °C Water dew point should be 5°C lower than the minimum ambient temperature for transmission under maximum operation pressure

Hydrocarbon dew point, °C Hydrocarbon dew point should not be higher than the minimum ambient temperature for transmission under maximum operation pressure

Note: the standard reference condition of gas volume in this standard is 101.325kPa, 20°C.

5.1.2 Content of solid particles in natural gas shall not affect the transmission and utilization of the natural gas and diameter of solid particles shall be smaller than 5mm.

5.2 Test method and test rule

5.2.1 Gas inlets (including the pipeline inlets of the natural gas stored in the underground

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gas storage) shall be equipped with micromoisture analyzer, hydrogen sulfide and carbon dioxide analyzers.

5.2.2 Gross calorific value, compression factor and gas composition of natural gas shall be analyzed once a quarter of year; gross calorific value shall be calculated according to GB/T11062 and the natural gas composition shall be determined according to GB/T13610.

5.2.3 Total sulfur content of natural gas shall be determined according to GB/T11061.

5.2.4 Hydrogen sulfide of natural gas shall be determined once a month and the determination and arbitration of hydrogen sulfide shall execute GB/T11060.1.

5.2.5 Carbon dioxide of natural gas shall be determined once a month and the determination of carbon dioxide content shall execute GB/T13610.

5.2.6 Oxygen content of natural gas is determined according to GB/T13610.

5.2.7 Water dew point of natural gas is determined once a day and the determination of water dew point executes GB/T17283.

5.2.8 Hydrocarbon dew point of natural gas is determined once a year and the determination of hydrocarbon dew point may execute GB/T17283.

5.2.9 Natural gas is sampled according to GB/T13609 and the sampling point should be at the natural gas takeover point specified in the contract. When the gas source composition or gas property changes, it should be sampled and analyzed promptly.

5.2.10 Gas quality analysis and gas quality monitoring data shall be sorted out, compiled and placed on file.

6. Project pre-acceptance

6.1 Pre-acceptance before the project is put into production.

6.1.1 Pipeline route engineering shall conform to SY0401.

6.1.2 Line crossing engineering shall conform to SY0470.

6.1.3 Line crossing engineering shall conform to SY/T4079.

6.1.4 Oil and natural gas station process pipeline project shall conform to SY0402.

6.1.5 Cathodic protection for trunk gas pipeline and station process pipeline network and facilities shall conform to SYJ4006.

6.2 Drying

6.2.1 Pipeline shall be dried before put into use and after leak test is completed.

6.2.2 Pipe pig should be used to dry and remove free water from pipeline; tightness of pipe pig should be ensured and pig running speed should be controlled at 0.5m/s~1m/s.

6.2.3 After drying, it should be ensured that the water dew point of the gas in the end pipeline is 5°C lower than the minimum ambient temperature under maximum transmission pressure.

6.2.4 See Annex A for pipeline drying method.

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7. Trial operation and commissioning

7.1 Trial operation of gas transmission station

7.1.1 Trial operation conditions: the gas transmission station should be trial operated after pressure test of the station process pipeline is passed.

7.1.2 Individual trial operation:

7.1.2.1 Compressor unit and process equipment etc shall be trial operated according to design and equipment operation manual and reach the design indices within the specified time.

7.1.2.2 Power transformation and transmission system, fire fighting system and communication system shall execute related national and industrial standards and pass trial operation and commissioning.

7.1.2.3 Trial operation of auxiliary systems such as heat supply, compressed air and water systems shall be accepted.

7.1.2.4 Individual commissioning of instruments and monitoring and control system shall be accepted.

7.1.3 Integrated trial operation: all flows shall be trial operated according to design conditions, station process pipeline, equipment, instrument, station control and SCADA system shall be commissioned and accepted and the systems are accepted if they continuously and smoothly for 72h.

7.2 Displacement

7.2.1 Displacement of air in pipeline shall be done after pressure test, leak test, pipe purging and pigging and drying are accepted.

7.2.2 Nitrogen gas or other non-corrosive, nontoxic and harmless gases shall be used as isolation media for the air in the pipeline.

7.2.3 During displacement, different gas interfaces shall be isolated with batching sphere or pipe pig.

7.2.4 When air is displaced, the isolating length of nitrogen gas or inert gases shall reach the end of the displacement pipeline so that air will not be mixed with natural gas.

7.2.5 Gas speed in the pipeline during displacement shall not be greater than 5m/s.

7.2.6 During displacement, mixed gases shall be discharged to the venting system. The vent port shall be far away from traffic line and residential area and a 300m-radius isolated area shall be arranged around the vent port.

7.2.7 No smoke and fire and static spark are allowed in the venting and isolated area.

7.2.8 The end of the displacement pipeline shall be provided with gas content detection equipment. When oxygen content of the gas at the venting port of the displacement pipeline end is not greater than 2%, the displacement is acceptable.

7.2.9 The gas in the pipeline is used to displace the gases in the process pipeline and

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equipment in the gas transmission station.

7.3 Put into production

7.3.1 The pipeline can be put into production after displacement of natural gas is completed.

7.3.2 Open the user valve and adjust gas supply pressure to normal.

7.3.3 After the pipeline is put into production, perform patrol inspection, measure various parameters and fill in the report form.

8. Operation management

8.1 Basic requirement

8.1.1 Pipeline operation process calculation refers to Annex B.

8.1.2 Pipeline operation pressure shall not be greater than the maximum pipeline operation pressure.

8.1.3 The temperature of natural gas in pipeline shall be lower than the maximum allowable temperature of pipeline and station anticorrosion materials and it should be ensured that pipe thermal stress conform to the design requirements.

8.1.4 SCADA system should be used to monitor and control pipeline production and operation.

8.1.5 Peak shaving should be performed through operation optimization according to the pipeline operation pressure, temperature, whole line equipment condition and season features.

a) The underground gas storage is an integral part of the natural gas pipeline and should be set up for peak shaving for the regions where seasonal gas consumption fluctuates greatly;

b) In the natural gas consuming regions where construction conditions underground gas storage are not available, other facilities and methods may be considered for peak shaving.

8.1.6 Various original records and report forms shall be established and have unified formats and accurate data and be cared by full time personnel.

8.2 Dispatch management

8.2.1 Dispatching order:

8.2.1.1 The dispatching order can only be given from higher level to lower level in the same gas transmission dispatching and commanding system.

8.2.1.2 The order for adjusting operating parameters is given by the dispatcher on duty.

8.2.1.3 The dispatching order for changing natural gas transportation and sale, gas transmission production flow and operation mode and in special situations shall be issued after approved by chief dispatcher

8.2.1.4 Emergency dispatching order is decided and issued by the dispatcher on duty in case the pipeline incurs accident or the pipeline operation is threatened by accident. The site personnel shall promptly take emergency measures to prevent the situation from becoming serious and promptly report the higher level. 9

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8.2.1.5 Dispatch order can be given in written form or by telephone.

8.2.1.6 The organization receiving the dispatch order shall promptly feed back its execution.

8.2.1.7 When test or detection is performed during operation management, the pipeline operation parameters or operation mode must be adjusted under the unified direction of the dispatcher.

8.2.1.8 For dispatch communication, in addition to normal communication, emergency communication channel shall be prepared to ensure smooth communication.

8.2.2 Operation analysis:

8.2.2.1 Pipeline transmission capacity and production capacity utilization rate shall be analyzed periodically.

8.2.2.2 The cause of equipment and pipeline operation efficiency reduction shall be analyzed promptly and improvement scheme be proposed.

8.2.2.3 Load distribution between the whole line and compressor unit shall be analyzed and operation be optimized to ensure that the power consumption (total energy consumption cost) from firm gas transmission is minimum and realize the optimal match of compressor unit at stable transmission flow.

8.2.2.4 When gas transmission condition changes, promptly analyze it so that gas pipeline changes from initial condition to new stable condition as soon as possible and the deviation between the actual operation parameters under new conditions and the specific operation parameters is minimum and the gas transmission cost is minimum.

8.2.2.5 The factors of pigging effect and pipeline transmission efficiency reduction shall be promptly analyzed.

8.2.2.6 Pipeline hydraulic, temperature and gas quality parameters shall be analyzed periodically to promptly the abnormalities such as know pipeline leakage and possible clogging and promptly determine leakage or clogging locations.

8.2.2.7 Pipeline operation shall be analyzed thoroughly after technical innovation.

8.2.2.8 Pipeline safety and reliability shall be analyzed and evaluated periodically according to internal pipeline test, external anticorrosion coating investigation, pipeline transmission medium composition, pipeline material characteristics and natural and social conditions along the pipeline.

8.2.3 Gas flow adjustment and distribution:

8.2.3.1 Reasonable gas transmission and supply plan and operation scheme shall be formulated according to gas transmission and supply contract.

8.2.3.2 When gas transmission and supply plan changes, the operation scheme shall be promptly adjusted according to the present situation of pipeline system and user class.

8.2.3.3 When operation scheme changes, coordinate with the upstream gas supplier and downstream users in advance and well do the gas flow adjustment and distribution work.

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8.3 Automated management

8.3.1 The management of various instruments and automation facilities shall conform to the regulations of SY/T6324 to ensure that site instrumentation has complete and good performance and is set up correctly.

8.3.2 Professionals shall be arranged to daily maintain the SCADA system.

8.4 Pipeline maintenance and management

8.4.1 Pipeline protection:

8.4.1.1 The pipeline protection shall execute the “Protective Rules for Petroleum and Natural Gas Pipeline”.

8.4.1.2 Pipeline protection shall be managed by professionals. The line shall be patrolled periodically and more frequently in rainy season and when other disasters happen. Patrol inspection contains:

a) Buried pipeline is not exposed and anticorrosion coating is not damaged;

b) Cross-over pipeline structure is stable, parts and components are not missing or damaged and exposed pipeline is not rusty;

c) Marking post, test pile and mile post are not missing or damaged;

d) Dike dam, revetment, bank protection and bridge head have not collapsed;

e) It is prohibited to grow deeprooted plants or borrow soil, quarry or construct other buildings in a 5m range on the two sides of the pipeline;

f) It is prohibited to cut into mountains, blast or construct large building and structure works.

8.4.1.3 Penetrating pipeline section shall be checked after each flood season and a underwater operation inspection shall be made once two to four years to check the stability, exposure, suspension, displacement or damage due to wash-out or denudation of penetrating pipeline section. The inspection and construction should be done in the dry season.

8.4.1.4 Protection of cross-over pipeline section and other elevated pipeline section shall execute SY/T6068.

8.4.2 Internal pipeline protection:

8.4.2.1 Corrosion inhibitor may be used to protect internal pipeline wall depending on natural gas quality.

8.4.2.2 During transmission, natural gas should be separated, dedusted and removed of dirt again.

8.4.2.3 Pigging operation should promptly be made when the pipeline has accumulated water or dirt inside.

8.4.2.4 Pipeline may be filled with anti-freezing agent in winter to prevent hydrate from clogging the pipeline.

8.4.3 Pipeline corrosion prevention: 11

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8.4.3.1 Pipeline cathodic protection rate is 100% and operation rate greater than 98%.

8.4.3.2 External pipeline corrosion protection shall be made with insulation coating in combination with cathodic protection.

8.4.3.3 Cathodic protection polarization potential should be controlled at -0.85V~-1.25V.

8.4.3.4 Station yard insulation, cathode potential and the protection potential along the line shall be measured once a month and pipeline anticorrosion coating and the natural potential along the line shall be measured once every three years.

8.4.3.5 Damage and repair of petroleum asphalt anticorrosion coating shall execute SY/T0420 and SY/T5918.

8.4.3.6 Other types of external anticorrosion coating damage and repair execute SY/T0061.

8.4.4 Pipeline test:

8.4.4.1 New pipeline shall undergo general test within one year and then pipeline operation safety shall be checked once every one to three years.

8.4.4.2 New pipeline shall be thoroughly tested within three years and then comprehensive test period shall be determined depending on pipeline operation safety and not more than eight years at most.

8.4.4.3 It is necessary to analyze test result, establish pipeline test file and place the raw data and data analysis result on file.

8.4.4.4 Periodically evaluate pipe age, grade, position, stress level, leakage history, coating condition, conveyance medium and environmental factor influence to determine pipeline repair type and service life.

8.5 Station yard management

8.5.1 General requirements:

8.5.1.1 Corrosion protection measures must be taken for station yard pipeline network and steel equipment.

8.5.1.2 Color painting of station ground pipeline network and equipment executes SY/T00043.

8.5.1.3 Station electric equipment management shall conform to SY/T6325.

8.5.1.4 Improvement and hot work of station pipeline network and equipment shall conform to equipment management requirements and SYJ4051.

8.5.1.5 Anti-freezing measures shall be taken for pipeline and station equipment depending on air temperature.

8.5.1.6 Station operation shall avoid static electricity and spark.

8.5.1.7 Stations shall be equipped with combustible gas detector.

8.5.1.8 Station pipeline and valve shall be tight and leakfree.

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8.5.1.9 Station equipment and instruments shall be grounded according to the regulations and ground resistance shall conform to requirements and tested periodically.

8.5.1.10 Fire equipment shall be provided according to the regulations.

8.5.1.11 Safety release device shall be provided for pipeline and equipment depending on operation pressure and calibrated periodically.

8.5.1.12 Parameter setup of pressure regulator, pressure limiting shut-off valve and pressure release valve shall be tested periodically.

8.5.2 Equipment management:

8.5.2.1 Enough equipment parts shall be provided.

8.5.2.2 Operation, maintenance and repair of pipeline valves for general use shall conform to SY/T6470.

8.5.2.3 For operation, maintenance and repair of important equipment like compressor unit, corresponding operation instructions shall be formulated and equipment files shall be established.

8.5.2.4 Equipment shall not operate in over-temperature, overpressure, over-speed or over-load conditions and important equipment shall be provided with safety protection devices.

8.5.2.5 Equipment maintenance shall include cleaning, lubrication, tightening, adjustment and corrosion protection.

8.5.2.6 Centrifugal compressor shall avoid surging.

8.5.2.7 Important equipment such as cutoff valve, ball valve, venting valve, blow down valve and quick switch blind plate of pipeline and station equipment shall be operated periodically and recorded.

8.5.2.8 Equipment repair shall execute the combined method of scheduled preventative repair, maintenance repair and preventative maintenance.

8.5.2.9 Equipment operation, operation accuracy, wearing or corrosion shall be checked and monitored before equipment repair.

8.5.2.10 Equipment repair execute the operation and repair parties handover system and conform to the related quality standards and safety regulations.

8.6 Measuring control

8.6.1 Natural gas measurement must conform to national metrological laws and regulations and inspection and calibration regulations.

8.6.2 Configuration of measurement instruments shall conform to SY/T6045.

8.6.3 Measuring method of orifice meter executes SY/T6143 and use of other types of flow meters shall conform to equipment user requirements; orifice meters shall be tested once a month.

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8.6.4 Measuring instruments and devices shall be checked and calibrated periodically to ensure accurate measured values.

8.7 Pigging

8.7.1 Pigging period of operation pipeline: a reasonable pigging period should be determined according to pipeline gas composition, pipeline transmission efficiency and pressure difference. When pipeline transmission efficiency η0 is smaller than 0.95, pigging should be made.

8.7.2 Previous pigging record: previous pipeline pigging records should be known before pigging, such as pipeline gas flow, pressure difference and transmission efficiency.

8.7.3 Pigging facilities: pipeline conditions should be investigated before the first pipeline cleaning and the facilities not conforming to pigging requirements shall be rectified.

8.7.4 Hydraulic calculation shall be conducted before and during pipeline cleaning to predict and know the position of cleaning pig (refer to Annex B).

8.7.4.1 Cleaning pig running speed should be controlled at 3.5m/s~5m/s.

8.7.4.2 The ball-pushing gas transmission flow necessary for pipeline cleaning shall be estimated according to cleaning pig running speed, average ball-pushing pressure and pipeline diameter.

8.7.4.3 If the pipeline has considerable dirt and accumulated liquid and high height difference, pay attention to gas reserve.

8.7.4.4 Total running time of cleaning pig should be estimated.

8.7.5 Selection of cleaning pig:

8.7.5.1 The cleaning pig should be installed with transmitter for easy trace and positioning.

8.7.5.2 Select cleaning pig according to pipeline conditions and cleaning pig features. Spherical pig, leather cup pig, straight plate pig or their combination can be selected.

8.7.5.3 Selection of cleaning pig surplus quantum:

a) Surplus quantum of spherical pig filled with water is 3%~10%;

b) Surplus quantum of leather cup and straight plate pigs is 1%~4%.

8.7.6 Cleaning pig operation monitoring:

8.7.6.1 Listening point is set up according to complete pipeline investigation data and actual condition.

8.7.6.2 Listening point should be set up in the special locations such as intermediate valve chamber, branch line, penetrating and cross-over and high height difference pipeline section.

8.7.6.3 Listening point shall be equipped with information receiver and pass indicator.

8.7.7 Emptying and blow down in final pigging station:

8.7.7.1 Emptying and blow down shall meet the requirements and safety and environmental

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protection.

8.7.7.2 Air release amount shall be estimated to make preparation.

8.7.7.3 Blow down amount shall be estimated to make preparation for dirt and polluted liquid treatment.

8.7.7.4 For the natural gas pipeline containing high content of sulfide, spray water to ball collecting barrel for wet operation to prevent spontaneous combustion of ferrous sulfide.

8.7.8 Precautions and problem handling in pigging process;

8.7.8.1 Always know pigging pressure difference and change in the pigging process.

8.7.8.2 When the cleaning pig is jammed, send the second cleaning pig or increase the running pressure after the cleaning pig or reduce the pressure before cleaning pig depending on operation. If the above methods can not remove jamming, cut open the pipeline to remove the cleaning pig.

8.8 Pipeline maintenance and first aid repair

8.8.1 Compile emergency prevention plan for leakage and breakage of natural gas pipeline according to physical and chemical composition of the conveyed medium, natural and social situation along the line and type of accidents.

8.8.2 Prepare maintenance and first aid repair equipment and materials and establish maintenance and first aid repair organizations according to emergency prevention plan.

8.8.3 After pipe maintenance and first aid repair works are completed, organize site acceptance according to the regulations and place all repair and acceptance data on file.

8.9 Pressure test of operation pipeline

8.9.1 General requirements:

8.9.1.1 Class division of the regions where the pipeline passes shall execute 4.2.2 of GB50251-1994.

8.9.1.2 The pipeline operating under pressure shall undergo pressure test and then leak test.

Pressure test medium:

a) Pressure test water shall not be corrosive and be from organic or inorganic dirt. Allowable water pH is 6~7.5 and content of harmful salt and particularly chloride shall be lower than 500mg/L.

b) If the minimum ambient temperature is not greater than 0°C, use of the water containing ice inhibitor should be allowed.

c) Water, air or other nonflammable and non-toxic gases can be used as pressure test medium.

8.9.1.4 Leak test shall use gas as test medium.

8.9.1.5 Pressure test instrument:

a) Test instruments must be calibrated and accepted before use.

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b) Accuracy of test pressure meter should not be lower than Grade 1.0, range is 1.5~2 times maximum test pressure, division value not greater than 0.02MPa and indicator dial not smaller than 150mm.

c) Each section of pressure test pipeline shall be installed with not less than 2 pressure meters and the two ends of pipeline are installed with one pressure meter respectively; for the pipeline section with relatively high height difference in the pressure test section, one pressure meter shall be installed at the highest point and the lowest point of the pipeline section respectively.

d) Division value of the test thermometer shall not be greater than 0.5°C and measuring range shall meet the measuring requirements.

e) The test thermometer shall be installed in the location free from sunlight and otherwise sunshading measures shall be taken. Each section of pressure test pipeline shall be installed with not less than 2 thermometers and the two ends of pipeline shall be installed with one thermometer respectively.

8.9.1.6 Measurement of pressure test value shall be subject to the pressure value measured at the highest point of the pipeline and circumferential stress of the pipeline at the lowest point shall not exceed the product of pipeline material yield strength by weld joint factor.

8.9.1.7 If the pipeline leaks during pressure test and leak test, it should be repaired after pressure release and undergo pressure test again after repair is accepted.

8.9.1.8 For the prefabricated parts, above-ground pipeline or completely exposed but not buried pipeline, the test medium in this system will expand due to heat during pressure stabilization period, measures shall be taken to avoid over-pressure.

8.9.1.9 The weld between the pipelines passing sectional pressure test shall undergo and 100% radiographic analysis or other nondestructive inspection, and after the whole line is connected, pressure test may not be conducted.

8.9.1.10 Leak test can be conducted after sectional pressure test is accepted or after the whole line is connected.

8.9.2 Pressure test and leak test of penetrating and cross-over pipeline:

8.9.2.1 Penetrating and cross-over pipeline shall individually undergo pressure test.

8.9.2.2 Pressure test shall have clean water as test medium and test pressure shall not be lower than 1.5 times maximum operation pressure and pressure shall be stabilized for 4h under test pressure.

8.9.2.3 Leak test pressure shall not be lower than maximum operation pressure and pressure shall be stabilized for 24h under test pressure.

8.9.2.4 After the penetrating and cross-over pipeline is connected to the whole line, it is necessary to conduct another leak test.

8.9.3 Line pressure test and leak test:

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SY/T 5922-2003

8.9.3.1 Pressure test shall be conducted section by section according to the pipeline of different region class in combination with landform.

8.9.3.2 The pipeline of the same region class shall also undergo section-by-section pressure test and the section length depends on test medium.

8.9.3.3 The pipeline of Region Class I and II can have air or water as test medium.

8.9.3.4 The pipeline of Region Class III and IV shall have water as test medium.

8.9.3.5 Hydraulic test:

a) For the pipe section with water as test medium, each section shall not be longer than 35km and height difference of test pipe section shall not exceed 30m.

b) For pressure test water filling, batching sphere or heather cup pig with good sealability shall be added to prevent air from existing in the pipeline and it is necessary to tap holes at the high point of the pipeline to exhaust air. Batching sphere or leather cup pig can be taken out after pressure test.

c) Test pressure shall rise evenly and gradually. When it rises to 1/3 test pressure, stop pressure rise for 15min for check; then raise pressure to 2/3 test pressure and stop for 15min for check; finally raise pressure to and hold at test pressure. Check for abnormality of pipeline pressure during pressure rise stop period.

d) Before elevated gas pipeline undergoes hydraulic test, calculate the strength of pipeline and support structure and if necessary temporarily reinforce them to prevent deformation of pipeline and support structure.

e) The pipeline is accepted if pressure drop is not greater than 1% test pressure or greater than 0.1mPa after held for 4h under test pressure, pressure.

f) Clean out accumulated water from pipeline section after pressure test is accepted.

8.9.3.6 Gas pressure test:

a) For the pipe section with gas as test medium, each section shall not be longer than 18km.

b) Test pressure shall rise evenly and gradually and pressure rise shall not exceed 1MPa per hour.

c) When test pressure is lower than 3MPa, pressure rise is made by two times: when pressure is 1/2 test pressure, it should be stabilized for 30min and if no problem is found, it should be raised again to the test pressure.

d) When test pressure is greater than 3MPa, pressure rise is made by three times: when pressure is 1/3 test pressure, it should be stabilized for 30min for check; then it should be raised again to 2/3 test pressure and stopped for 30min for check; finally it should be raised to and held at the test pressure. Check for abnormality of pipeline pressure during pressure rise stop period.

e) The pipeline is accepted if it is not broken or does not leak after the pressure is held for 4h under test pressure.

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SY/T 5922-2003

8.9.3.7 Maximum pressure for pressure test:

a) The pipeline in Class I region shall not be lower than 1.1 times maximum operation pressure;

b) The pipeline in Class II region shall not be lower than 1.25 times maximum operation pressure;

c) The pipeline in Class III region shall not be lower than 1.4 times maximum operation pressure;

d) The pipeline in Class IV region shall not be lower than 1.5 times maximum operation pressure.

8.9.3.8 Leak test:

a) Leak test pressure is the maximum pipeline operation pressure.

b) The pipeline undergoing leak test shall be kept under test pressure for 24h and if pressure drop is not greater than 1% the test pressure, it is acceptable (See Annex C for pressure drop rate calculation).

8.9.4 Pressure test and leak test of gas transmission station:

8.9.4.1 Station process pipeline shall undergo sectional or individual pressure test and leak test according to pressure level and different pressure requirements of equipment, fittings and valves.

8.9.4.2 Pressure test:

a) The process pipeline in stations shall have water as pressure test medium.

b) When water is used for pressure test, pressure rise should be gradual and when the pressure reaches the test pressure, it should be held for 10min to check for leakage. If no leakage, it is acceptable.

c) When gas is used for pressure test, the pressure test should be conducted section by section and foaming agent should be used to check for leakage. Pressure rise should be gradual. The system shall be pressurized first to 1/2 test pressure and be held to check for leakage. If no leakage or abnormality, the pressure should be raised at increment of 1% test pressure and pressure should be held at each stage to check for leakage. When the pressure is raised to the test pressure, it should be held for at least 30min. each holding time is determined according to the time needed for leakage check with foaming agent and shall not be shorter than 10min.

d) The pressure test for station equipment such as valve shall be performed individually and test pressure shall conform to the equipment (or design) requirements.

e) The pressure for pressure test shall not be lower than 1.5 times maximum operation pressure or 0.7MPa.

8.9.4.3 Leak test:

a) Gas should be used as test medium and when pressure reaches the test pressure, it should be held for 30min to check for leakage. If no leakage, it is accepted.

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SY/T 5922-2003

b) When natural gas is used as test medium, the test should be done after the natural gas is completely dried and the air in the pipeline is displaced.

c) Leak test pressure shall be the maximum operation test and not lower than 0.7MPa.

8.9.5 Safety requirement:

8.9.5.1 During pressure test or other tests, the 100m area on the two sides of the pipeline shall be isolated area and non-working staffs shall keep away from the area.

8.9.4.2 If gas is used as pressure test medium, no working staffs are allowed to make inspection along the line from the time when circumferential stress of the pipeline is raised for the first time from 50% specified minimum steel yield strength to maximum test pressure till the time pressure drops to maximum operation pressure. If inspection is necessary, test pressure should be reduced.

8.9.4.3 If natural gas is used as leak test medium, fire and static spark are prohibited in the isolated area.

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SY/T 5922-2003

Annex A Pipeline Drying Method

(Informative)

A.1 Dry air dehydrating method (dry air and cleaning pig make up the dehydrating and pig train)

A.1.1 Dry air is used to drive the pig train to run along the pipeline and when the last cleaning pig of the pig train reaches the terminal of drying pipeline section, the pressure in the pipeline is reduced to a certain value.

A.1.2 Dry air is used to perform low pressure drying and purging until reaching the necessary criteria.

A.2 Nitrogen drying method

A.2.1 Nitrogen drying method is the same as dry air dehydrating method (but has better drying effect due to lower dew point of nitrogen gas).

A.2.2 After nitrogen drying, displacement operation is not necessary and pipeline can be directly put into production.

A.2.3 Drying of large pipeline consumes a large quantity of nitrogen gas and it is necessary to analyze the economic efficiency of nitrogen gas.

A.3 Vacuum drying method

A.3.1 Pressure reduction (extraction) stage: reduce the pressure from pipeline initial pressure to saturated pressure of water vapor under pipeline wall temperature.

A.3.2 Boiling (evaporation) stage: repeat vacuum extraction and isolation process and maintain internal pipeline pressure to the value at the end of pressure reduction stage.

A.3.3 Drying stage: vacuum pump is used to reduce internal pipeline pressure to the saturated pressure of water vapor corresponding to the dew point needed (drying index usually is -20°C). Seal and isolate the pipeline and measure internal pipeline pressure. Repeat vacuum extraction until no pressure rises significantly in the pipeline after detection.

A.3.4 It is allowed to directly introduce natural gas under vacuum condition to put the pipeline into production.

A.3.5 Drying time depends on vacuum extraction time and evaporation time.

Theoretical vacuum extraction time is calculated with equation (A.1):

tExtraction = 排Q

V lnp

p 0 (A.1)

Where:

t Extraction – Theoretical vacuum extraction time, h;

V – Pipeline volume of drying pipeline section, m3;

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SY/T 5922-2003

Q Displacement – Vacuum pump displacement (p0=0.101325MPa, T0=293.15K), m3/h;

p0 – Internal pipeline pressure before vacuum extraction, kPa;

p – International pipeline pressure at the end of vacuum extraction, kPa.

Theoretical evaporation time is calculated with equation (A.2):

t Evaporation = ⎟⎟⎠

⎞⎜⎜⎝

⎛ρW / Q Extraction (A.2)

Where:

T Evaporation – Theoretical evaporation time, h;

W – Water content of drying pipeline section, kg;

ρ - Saturated density of water vapor under pipe wall temperature and evaporating pressure, kg/m3;

A.4 Drying method by dehydrating pig train

A.4.1 Natural gas is used to drive methanol (or ethylene glycol etc) dehydrating and pig train.

A.4.2 The pigging, dehydrating, drying, displacing and commissioning work is realized at one time and thus the time to put the pipeline into production is shortened.

A.4.3 The method of gel in combination with dehydrating and pig train can reduce cleaning pig abrasion, prevent bad sealing property and remove mechanical impurities such as pipe wall rust.

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SY/T 5922-2003

Annex B Pipeline Operation Process Calculation

(Normative)

B.1 Gas delivery capacity calculation

B.1.1 Calculation equation when the relative height difference between pipeline section start point and final point is ∆h≤200

Q=11522Ed2.5351.0

961.0

22

21

⎥⎦

⎤⎢⎣

⎡ −ZTLG

pp (B.1)

Where:

Q – Gas flow (p0=0.101325MPa, T0=293.15K), m3/d;

d – Pipeline ID, cm;

p1, p2 – Gas pressure at start point and final point of pipeline section, MPa;

Z – Gas compression factor;

T – Average gas temperature, Kelvin (K);

L – Length of calculated section of pipeline, km;

G – Relative density of gas;

E –coefficient of efficiency of pipeline; DN=300~800, E=0.8~0.9; DN>800, E=0.91~0.94.

B.1.2 Calculation equation when the relative height difference between pipeline section start point and final point is ∆h>200m

Q=11522Ed2.53

)/(0683.0

)(2

1

)1(

51.0

11

961.0

22

21

ZTGa

LhhL

aZTLG

happn

iiii

=

⎪⎪⎭

⎪⎪⎬

⎫

⎪⎪⎩

⎪⎪⎨

⎧

⎥⎦

⎤⎢⎣

⎡++

∆+−

∑=

−

(B.2)

Where:

a – Coefficient, m-1;

∆h – Height difference between final point and start point of gas pipeline, m;

n – Calculated number of sections divided according to the change of height difference along the gas pipeline;

hi, hi-1 – Height of final point and start point of respective pipeline sections, m;

Li – Length of pipeline sections, km.

B.2 Pipeline operation pressure calculation

B.2.1 Calculation equation of average internal pipeline pressure (choking effect not considered)

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SY/T 5922-2003

pm = ⎟⎟⎠

⎞⎜⎜⎝

⎛+

+21

22

32

pppp (B.3)

Where:

pm – Average pressure of pipeline gas (absolute), MPa;

p1, p2 – Gas pressure at start point and final point in calculated pipeline sections (absolute), MPa;

B.2.2 Calculation equation of gas pressure at any point along the pipeline

px = LXppp )( 2

221

21 −− (B.4)

Where:

px – Gas pressure (absolute) at any point along the pipeline, MPa;

X – Length from the start point of calculated pipeline section to any point along the line, km.

B.3 Calculation of pipeline gas temperature (choking effect not considered)

B.3.1 Calculation equation of average pipeline gas temperature

tm = t0 + )1(01 aLeQL

tt −−− (B.5)

a = pQGC

KD610256.225 ×

Where:

tm – Average temperature of gas in calculated pipeline section,°C;

t0 – Soil temperature at pipeline burial point, °C;

t1 – Gas temperature at start point of calculated pipeline section, °C;

e – Natural base, e=2.718;

a – Calculation constant;

K- Overall transfer coefficient from pipeline gas to soil, W/ (m2·°C);

D – Pipeline OD, m;

Cp – Specific heat of gas at constant pressure, J/(kg·°C);

B.3.2 Calculation equation of gas temperature at any point along the pipeline

tx = t0+(t1-t0)e-aX (B.6)

Where:

tx – Gas temperature at any point along the pipeline, °C.

B.4 Calculation equation of pipeline gas storage

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SY/T 5922-2003

Q storage = ⎟⎟⎠

⎞⎜⎜⎝

⎛−

2

2

1

1

0

0

Zp

Zp

TpVI mm (B.7)

Where:

Q storage – Pipeline gas storage, (p0=0.101325MPa, T0=293.15K), m3;

V – Pipeline capacity, m3;

T0 – 293.15K;

p0 – 0.101325MPa;

T – Average gas temperature, K;

p1m – Maximum average pressure (absolute) of gas in calculated pipeline section, MPa;

p2m – Minimum average pressure (absolute) of gas in calculated pipeline section, MPa;

Z1, Z2 – Gas compression factor corresponding to p1m, p2m.

B.5 Calculation equation of gas delivery difference

B.5.1 Calculation equation of difference of gas delivery

Q Difference = (V1+Q1)-(Q2+Q3+Q4+V2) (B.8)

Where:

Q Difference – Average difference of gas delivery in gas pipeline at a time, m3;

Q1 – Input gas amount at the same time, m3;

Q2 – Output gas amount at the same time, m3;

Q3 – Gas consumption from production and living of the gas transmission organization at the same time, m3;

Q4 – Air release amount at the same time, m3;

V1 – Stored gas amount in the calculated pipeline section at the beginning of calculation, m3;

V1 –Stored gas amount in the calculated pipeline section at the end of calculation, m3;

Note: standard reference condition of gas volume is p0=0.01625MPa, T0=293.15k.

B.5.2 Calculation equation of relative measurement shortage

η=11 QV

Q+差 ×100% (B.9)

Where:

η - Relative measurement shortage.

B.6 Calculation equation of pipeline delivery capacity utilization rate

η1=设

实

QQ

×100% (B.10)

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SY/T 5922-2003

Where:

η1 – Annual pipeline delivery capacity utilization rate;

Q Actual – Actual pipeline air delivery (p0=0.101325MPa, T0=293.15K), m3/y);

Q Design – Designed pipeline air delivery (p0=0.101325MPa, T0=293.15K), m3/y);

B.7 Calculation equation of pipeline delivery efficiency

η2=计

实

QQ

×100% (B.11)

η2 – Pipeline delivery efficiency;

Q计 – Calculated pipeline gas delivery under the same operation conditions (p0=0.101325MPa, T0=293.15K), m3/d.

B.8 Pipeline pigging calculation equation

B.8.1 Estimation equation of maximum pigging pressure difference

p= (B.12) *3

*2

*1 ppp ++

Where:

p – Maximum pressure difference, MPa;

p - Cleaning pig startup pressure difference, MPa; *1

p - Gas transmission pressure difference between receiving station and sending station, MPa;

*2

p - Estimated maximum accumulated liquid elevation pressure in the pipeline, MPa; *3

B.8.2 Calculation equation of pigging gas amount

B.8.2.1 Estimation equation of ball-pushing gas transmission flow

Q Estimated = 240000F· vp ⋅ (B.13)

Where:

Q Estimated – Gas transmission flow (p0=0.101325MPa, T0=293.15K), m3/d);

F – Cross sectional area of pipeline ID, m2;

p - Average pressure after cleaning pig, MPa;

v - Average cleaning pig running speed, km/h.

B.8.2.2 Estimation equation of total pigging inlet gas amount

Q Total = 10000F·L*· p (B.14)

式中：

Q Total – Total inlet gas amount (p0=0.101325MPa, T0=293.15K), m3;

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SY/T 5922-2003

L* - Cleaning pig running distance, km.

B.8.3 Estimation equation of cleaning pig running time

t=v

L * (B.15)

Where:

t – Cleaning pig running time, h;

v – Average cleaning pig speed, km/h.

B.8.4 Estimation equation of cleaning pig running distance

l Estimated = pTd

TZQp

02

04π

进 (B.16)

Where:

l Estimated – Cleaning pig running distance, m;

p0 – 0.101325MPa;

T0 – 293.15K;

T – Average temperature of gas in the pipeline section after cleaning pig, K;

Q Inlet – Accumulated inlet gas amount after cleaning pig is sent (p0=0.101325MPa, T0=293.15K), m3;

d – Gas pipeline ID, m;

π - 3.1415926….

B.8.5 Estimation equation of cleaning pig running speed

B.8.5.1 Instantaneous speed equation if gas transmission flow is calculable

v =pF

Q⋅240000

(B.17)

Where:

v – Cleaning pig running speed, km/h.

B.8.5.2 Speed equation if gas transmission flow is not calculable

tlv = (B.18)

Where:

v - Average cleaning pig speed, m/s;

t – Actual time of running for distance l, s.

B.8.6 Calculation equation of air release

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SY/T 5922-2003

Q Release = 231.5G

pd 放放 ⋅2

(B.19)

Where:

Q Release –Instantaneous release amount of natural gas (p0=0.101325MPa, T0=293.15K), m3/d;

d Release – Vent pipe outlet end ID, mm;

p Release – Pressure (absolute) measured at four times ID of vent pipe, MPa.

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SY/T 5922-2003

Annex C Pipeline Pressure Test Process Calculation

(Normative)

C.1 Calculation equation of allowable pipeline pressure drop

[∆p] = %100500×

DN (C.1)

Where:

[∆p] –Allowable pressure drop;

DN – Nominal steel pipe diameter, mm.

C.2 Calculation equation of actual pressure drop of gas pipeline

[∆p] = ⎟⎟⎠

⎞⎜⎜⎝

⎛⋅⋅

−zs

sz

TpTp

1 ×100% (C.2)

ps = ps1+ps2

pz = pz1+pz2

Where:

[∆p] – Pressure drop;

Ts – Absolute temperature of pipeline gas at the beginning of pressure stabilization, K;

Tz –Absolute temperature of pipeline gas at the end of pressure stabilization, K;

ps –Absolute pressure of pipeline gas at the beginning of pressure stabilization, MPa;

pz –Absolute pressure of pipeline gas at the end of pressure stabilization, MPa;

ps1, pz1 – Pressure meter reading at the beginning and end of pressure stabilization, MPa;

ps2, pz2 – Local atmospheric pressure at the beginning and end of pressure stabilization, MPa;

Ts, Tz, ps, pz refer to average values of measuring points along the whole line.

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