SY/T 0078-1993 Standard for Internal Corrosion Control of Steel Pipelines
Some standard content:
Recommended Practices for The Control of Internal Corrosion in Oil and Gas Transmission and Distribution Steel Pipeliness Y/T0078-93
Editor: Survey and Design Institute of Sichuan Petroleum Administration Bureau Approval: China National Petroleum Corporation Effective date: May 1, 1994
Petroleum Industry Press
1994·Beijing
Design criteria for internal corrosion control
Design criteria
3 Corrosion inspection and measurement
Inspection methods
4 Methods for controlling internal corrosion bzxZ.net
Control methods
Item 1 Evaluation of the effectiveness of corrosion control methods
Evaluation methods
Internal corrosion Operation and maintenance of control systems
Operation and maintenance toilets·
7 Corrosion control records
Attached notes·
(5)
(5)
China National Petroleum Corporation Document:
(93) CNPC Technology No. 747:
Notice on the approval and release of 38 oil and gas industry standards including "Standard for Corrosion Control inside Steel Pipelines"
To all relevant units:
"Standard for Corrosion Control inside Steel Pipelines" and other 38 industry standards (draft) have been reviewed and approved and are now approved as oil and gas industry standards for release. The numbers and names of the various standards are as follows:
Serial number
SY/T 0078—93
SY/T 0079—93
SY/T 0080—93
SY/T 0524--93
SY/T 0526-93
SY/T 5026--93
SY/T 5027--93
SY/T 5080—93
SY/T 5043--93
Standard for internal corrosion control of steel pipelines
Technical standard for coal tar enamel outer covering layer of buried steel pipelines
Design specification for diesel engine power station in oil and gas fields
Technical conditions for indirect heating device of hot coal
Test method for coal tar enamel covering layer
Pneumatic components for oil drilling and production equipment
Model compilation method
(Replace SY5026-83)
Pneumatic components for oil drilling and production equipment
Basic parameters
(Replace SY5027-83)
Pneumatic components for oil drilling and production equipment
SY:5066.293
SY/T 5095--93
SY/T 5096-93
SY/T 5141--93
SY 5156---93
SY/T 5211-93
SY/T 5275.2---93
SY/T 5798—93
SY/T 5821.1--93
SY/T5828—93
SY/T 5829---93
SY/T 5830—93
SY/T 5831--93
SY/T 5832—93
SY/T 5833-93
SY/T 5834-93
SY/T 5835--93
SY/T 5836--93
General technical parts
(Replace SY5043--84)
Formation tester for oil and gas fields
Ground control device
(Replace SY:5066-91)
Pneumatic components for oil drilling equipment
Test method for reversing direction
(Replace SY5095-85)
Pneumatic components for oil drilling equipment
Test method for regulating valve
(Replace SY5096-85)
Centrifugal full-wheel wave torque converter oil (gas) parallel port device for petroleum equipment
High-pressure driving joint and high-pressure active elbow
Water distributor for water injection
Hollow movable water distributor
Efficiency test and calculation method of mechanical oil production system Water plugging operation method for oil well
Water glass-calcium chloride water plugging
and profile adjustment process
Quality inspection rules for petroleum geophysical survey results Naming rules for oil and gas field development wells
Reservoir description method for volcano
Hollow microsphere transfer agent SL-KX-I Sucker rod centralizer
Operation procedures for submersible electric pump wells
Method for determining the performance of low solid phase well killing fluid
and evaluation index
Wellhead ball valve for fracturing
Method for design and construction of fracturing in medium and deep wells
SY/T 5837-93
SY/T 5838--93
SY/T 5839--93
SY/T 5840--93
SY/T 5841--93
SY/T 5843--93
5844.3--93
SY 5845-93
SY/T 5846--93
SY/T 5847--93
SY/T 5848--93
SY/T 5850--93
Pneumatic components for petroleum drilling and production equipment
Test method for shuttle valve
Regulations on technical and economic evaluation of oil (gas) field (reservoir) reserves
Operation procedures for expandable formation tester
Indoor test method for bridging plugging materials for drilling Technical and economic indicators and calculation methods for drilling
Measurement method for relative permeability of gas and water
(Steady-state method)
Information code for oil and gas geological tests
Code for the name of paleontology
Regulations on safety management of special containers for oil fields
Process and practice of casing compensation
Use method of preparation of dynamic control diagram for pumping wells Pumping rod anti-drop device
Sulfonated asphalt (paste) for drilling
The above standards shall come into force on May 1, 1994. China National Petroleum Corporation
November 16, 1993,
1.0.1 This standard is formulated to control the internal corrosion of steel pipelines for collecting, transporting or distributing crude oil, petroleum products, natural gas and artificial gas. 1.0.2 This standard is applicable to source oil gathering and transmission pipelines, petroleum product transmission pipelines, natural gas gathering, transmission and distribution pipelines and artificial gas transmission and distribution pipelines. 1.0.3 This standard is a guide for formulating the minimum requirements for controlling the internal corrosion of steel pipelines. 1.0.4 This standard does not recommend practices for various substrate occasions. This is because the variety of pipeline media and the complex pipeline configuration hinder the standardization of internal corrosion control practices. 1.0.5 The provisions of this standard should be implemented under the guidance of corrosion engineers. The "corrosion engineer" referred to in this standard is a person who has undergone special training, has knowledge of corrosion and anti-corrosion, has practical experience in production, and is competent to control the internal corrosion of crude oil, petroleum products, natural gas and artificial gas steel pipelines. 1.0.6 If the pipeline medium does not cause harmful corrosion to the pipeline, the provisions of this standard may not be followed.
1.0.7 In addition to complying with this standard, the internal corrosion control of steel pipelines shall also comply with the provisions of the relevant current national standards (specifications). 2 Internal corrosion control design criteria
2.1 Introduction
2.1.1 This chapter is for crude oil gathering and transportation pipelines, petroleum product transportation pipelines , natural gas gathering, transmission, distribution pipelines, artificial gas transmission, distribution pipelines provide internal corrosion control design standards. 2.1.2 During the design and construction of steel pipelines, corrosion engineers should be consulted. 2.2 Design criteria
2.2.1 Requirements for the quality of pipeline media are as follows: 2.2.1.1 The content of the following corrosive impurities should be measured: (1) Bacteria.
(2) Carbon dioxide.
(3) Chlorides.
(4) Hydrogen sulfide.
(5) Organic acids.
(6) Oxygen.
(7) Solids or precipitates.
(8) Water.
(9) Other sulfur-containing compounds.
2.2.1.2 Based on the composition and content of corrosive impurities allowed in the pipeline medium, predict the possible harmful effects. The main harmful effects to be considered are: (1) Damage to the pipe body due to thinning, pitting, hydrogen bubbles, hydrogen embrittlement or stress corrosion cracking.
(2) Contamination of the pipeline medium by corrosion products. 2.2.1.3 When the impurities contained in the pipeline medium can cause harmful corrosion of the pipeline, additional treatment of the pipeline medium should be considered to reduce its corrosiveness. 2
2.2:1.4 The designer should understand the cost of treatment to reduce the corrosiveness of the pipeline medium and compare it with the cost of other corrosion mitigation measures, such as increasing the frequency of pipe cleaning, using corrosion inhibitors, using pipeline internal wing covers or a combination of these methods: 2.2.1.5 An excellent design should be one in which the pipeline medium maintains its quality throughout the transportation process and the internal corrosion of the pipeline is minimized. 2.2.2 Requirements for flow velocity are as follows:
2.2.2.1 The velocity of the medium being transported in the pipeline shall be controlled within the range where corrosion is minimized. The lower limit of the velocity range shall be such that impurities are suspended in the medium being transported and the accumulation of corrosive impurities in the pipeline is minimized. The upper limit of the velocity range shall be such that abrasion, cavitation or seed erosion are minimized.
2.2.3 Requirements for intermittent flow are as follows:
2.2.3.1 Intermittent flow shall be avoided whenever possible. If it cannot be avoided, the flow velocity of the medium shall be controlled so that it is sufficient to flush out the water and sediment accumulated in the pipe during the intermittent flow.
2.2.3.2 If the velocity of the medium being transported in the pipeline is expected to exceed the requirements of Section 2.2.3.1, the design shall consider the use of pigs, and a set of operating procedures and implementation practices shall be established to adequately remove the accumulated material.
2.2.4 Requirements for reducer pipes are as follows:
2.2.4.1 The reducer and reducer of the pipes are designed to have a flat hydraulic cross section to avoid the formation of algae stagnant areas where corrosive dirt accumulates.
2.2.4.2 The design should avoid dead ends formed by blind flange residual pipe sections, branch pipes, etc. If it cannot be avoided, a purge, collection or drainage device should be installed to discharge the accumulated corrosive dirt regularly.
2.2.5 Requirements for dehydration and dew point control are as follows: 2.2.5.1 During the transportation of the pipeline medium, when its water content reaches a level that can cause harmful corrosion, dehydration should be considered to reduce its water content to an allowable level. 2.2.5.2 If only reducing the water content cannot control the expected brain corrosion, other corrosion mitigation measures can be adopted at the same time as dehydration, such as cleaning or (and) adding corrosion inhibitors.
2.2.6 Requirements for unloading
2.2.6.1 Pipeline media containing oxygen may cause corrosion during transportation. Deoxygenation should be considered to reduce the oxygen content of the pipeline medium to an acceptable level. 2.2.6.2 While deoxygenating, it should also be ensured that air does not enter the pipeline during transportation.
2.2.6.3 If deoxygenation alone cannot control the expected corrosion, other corrosion inhibition measures should be used while deoxygenating. 2.2 Requirements for chemical inhibitors are as follows
2.2.1 Pipelines using chemical additives such as inhibitors, deoxygenators and fungicides: The design should include provisions for injection devices. The device must be placed in a location that allows the entire pipeline to be adequately protected.
2.2.8 Requirements for internal cover are as follows
2.2.81 For pipelines where the corrosion rate is expected to exceed the allowable range, internal cover may be considered. For some pipelines where exposed girth welds are allowed, or (and) where exposed areas are caused by defects in the cover, corrosion inhibitors may be used for protection. 2.2.9 Requirements for monitoring devices are as follows:
2.2.9.1 For pipelines that are subjected to corrosion mitigation treatment for the medium transported by the pipeline, especially for pipelines that are injected with chemicals, the design should include a monitoring device to measure the corrosiveness of the medium transported by the pipeline and evaluate the effectiveness of the corrosion mitigation method.
2.2.9.2 Monitoring devices generally include short pipes with flanges at both ends, pipeline medium samplers, online corrosion coupons, corrosion rate measurement probes, probes, etc. The monitoring device is usually installed on the detection bypass. The hydraulic conditions of the bypass pipeline should be similar to those of the main pipeline and can be cut off or opened at any time.
2.2.9.3 When it is possible to use a pig with an instrument to monitor corrosion, the design should also include the pipeline allowing the pig with an instrument to pass freely, and the installation of relevant time control pipes, valves and other technical collection devices. 3 Corrosion inspection and measurement
3.1 Introduction
3.1.1 This chapter describes the detection method for analyzing and determining the type, rate and corrosion factor of corrosion in the pipeline.
3.2 Detection method
3.2.1 Visual inspection. When the inner wall of the pipeline is exposed during the shutdown of the pipeline for repair: it should be inspected under the guidance of the corrosion engineer to determine the following contents: 3.2.1.1 Observe the morphology of corrosion damage and identify the type of corrosion. 3.2.1.2 Observe the distribution of corrosion along the circumferential and axial directions of the inner surface of the pipeline. 3.2.1.3 Measure the number of corrosion pits and pit depth per unit area, measure the wall thickness, i.e. the wall thickness of the deepest part of the corrosion, and calculate the annual corrosion rate. 3.2.1.4 The slope and slope of the corroded pipe section, and the relative position of the pipe connected to it.
3.2.1.5 Sediment and corrosion under the sediment. Take the sediment and corrosion products to analyze their components.
3.2.1.6 Take photos of the main corrosion sites. 3.2.2 Corrosion coupons and probes are widely used to determine corrosion, corrosion rate and corrosion type. Corrosion coupons and probes should meet the following requirements: Corrosion coupons and probes must be placed in representative and reproducible positions.
3.2.2.2 Corrosion coupons and probes should be similar to the inner surface of the pipeline. 3.2.2.3 The exposure time of the corrosion test piece and probe in the fluid should be determined according to the type of pipeline medium, flow rate, test items and expected corrosion rate. When the pipeline medium contains wax and other insoluble substances that are easily deposited on the test piece and probe, it will affect the test results of the corrosion test piece and probe. 3.2.2.5 Different probes should be selected according to different operations (such as regular or continuous sampling) and installation techniques.
3.2.3 Sampling and chemical analysis are used to determine the total iron content, pH value, corrosion components and their content or (and) performance tests in the pipeline medium. Sampling and chemical analysis should meet the following requirements:
3.2.3.1 The extracted samples should be representative and reflect the actual situation of the pipeline medium.
3.2.3.2 Sampling should be carried out by experienced personnel or professionally trained personnel. 3.2.3.3 In order to obtain reliable samples, the valves, pipes, containers and environment for sampling must be kept clean.
3.2.3.4 If the pipeline medium contains water, carbon dioxide, hydrogen sulfide, bacteria, acid and other corrosive components should be analyzed. 3.2.3.5 The impurities in the pipeline medium that are likely to cause scaling and blockage should also be analyzed regularly.
3.2.3.6 The frequency and items of chemical analysis should be determined according to the changes and quantity of the pipeline medium in the pipeline.
3.2.4 Internal detection tools can be used to detect internal corrosion of pipelines. Internal detection tools are of the following types:
3.2.4.1 Pipe cleaning device with magnetic and electronic devices. When using a pipe cleaning device with magnetic and electronic devices, the following should be noted:
(1) The relationship between the corrosion recorded and displayed by the detector and the actual position on the ground. This is essential for accurately determining the corrosion site. (2) The display on the detector record cannot clearly distinguish between internal corrosion and external corrosion, and excavation must be used to verify.
3.2.4.2 Mechanical calipers can also be used to penetrate various parts of the pipeline to detect corrosion damage.
Pressure drop measurement. By regularly measuring the changes in the pressure drop at both ends of a fixed pipe section, the presence of corrosion or (and) sediment can be determined. 6
4 Methods for controlling internal corrosion
4.1 Introduction
4.1.7 This chapter describes methods for controlling internal corrosion of steel pipelines. 4.2 Control methods
4.2.1 Pipe cleaning. Pipe cleaning can remove dirt and sediment inside the pipeline to improve and maintain the cleanliness of the pipeline. Pipe cleaning should meet the following requirements 4.2.1.F Pipe cleaning should avoid corrosion caused by the following factors: (1) Water and other liquids that settle or desorb from the pipeline medium due to insufficient flow rate, intermittent flow or conveying pressure, temperature changes, etc. These water and liquids often contain oxygen, ions, carbon dioxide, chloride ions, salts, acids and other corrosive impurities.
(2) When there are loose deposits such as corrosion products, rust, sand, ash, etc. in the conveying pipe, especially under the conditions of 4.2.1.1 (1), it often promotes the formation of local corrosion in the bottom quarter of the pipe. (3) Corrosion products, paraffin or other solid deposits adhering to the whole pipe may protect the active corrosion area, thereby limiting the effectiveness of other corrosion inhibition methods such as chemical corrosion inhibitors.
4.2.1.2. Pipe cleaners of different structures should be selected according to the requirements of pipe cleaning. To remove adhered dirt, pipe cleaners with spring-loaded blades, wire brushes, grinding sand and other types should be selected. Flat rigid non-metallic spheres can also be selected. To pass through variable diameter pipelines and elbows with small curvature diameters, pipe cleaners made of deformable rubber, plastic and other materials are often selected.
4.2.1.3 Basis for selecting pipe cleaners
() The ability of the pipe cleaner to remove accumulated dirt.
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