-- [ Page 1 ] --
UDC 622.691.4.620.193 / .197
As a manuscript
Askarov German R.
ASSESSMENT OF THE INFLUENCE OF UNSTABLE
TEMPERATURE REGIME ON CORROSIVE
STATE OF LARGE DIAMETER GAS PIPES
Specialty 25.00.19 Construction and operation of oil and gas pipelines, bases and storage facilities dissertation for the degree of candidate of technical sciences
supervisor Doctor of Technical Sciences, Professor Harris Nina Aleksandrovna Ufa
INTRODUCTION ………………………………………………………………………… 1. Modern ideas about the temperature effect on the corrosion state of a gas pipeline ………………………… …………………………………. 1.1 a brief description of corrosion processes in pipeline transport ………………………………………………………………………. 1.1.1 Typical corrosion defects on a steel pipe …………………. 1.2 Violation of the protective properties of the insulating coating ………………… .. 1.3 Corrosive aggressiveness of soils ……………………………………… ... Reasons for the formation of corrosive elements on the outer 1. surface of the gas pipeline ……… …………………………………………………. 1.4.1 Conditions for the formation of macro-corrosive elements on the outer surface of the gas pipeline …………………………………………………………. 1.4.2 Change in the electrical resistance of the soil adjacent to the pipeline when moisture moves in a corrosive soil layer…. 1.5 Influence of temperature and temperature fluctuations on the corrosion state of the gas pipeline ……………………………………………………………. 1.6 Diagnostics of gas pipelines using inline shells…. 1.7 Models for predicting corrosion processes …………………… Conclusions to chapter 1 Assessment of the impulse effect of humidity and temperature on 2.corrosiveness of soils surrounding the gas pipeline ...................... 2.1 Physical modeling and selection of control parameters ..................... 2.2 Short description experimental setup ………………………… ... 2.3 Experimental results and the effect of increasing the corrosive activity of soils under pulsed temperature exposure ………………………… 2.4 Study of the effect of the frequency of temperature fluctuations and thermal parameters on corrosive activity soils ……………………………… Corrosion rate versus average temperature at 2.
Unstable heat exchange ……………………………………………………. Conclusions to Chapter 2 …………………………………………………………………. 3. Prediction of the corrosion state of a gas pipeline based on the data of in-line flaw detection ……………………………………………………… 3.1 Corrosion hazard assessment criteria …………………………………………………………………………………………………………………………………………………………………………… 3.2 Analysis of the corrosion state of the gas pipeline section according to the in-line flaw detection data …………………………………………………… 3.2.1 Characteristics of the gas pipeline section …………………………………… … 3.2.2 Analysis of VTD results ……………………………………………………. 3.3 Formation and rate of development of corrosion centers on pipelines with film insulation …………………………………………. 3.4 Corrosion prediction of defectiveness of pipes of large diameter ……………. Conclusions to Chapter 3 …………………………………………………………………. 4. Development of a method for ranking gas pipeline sections according to the degree of danger for taking out for repair ………………………………………………… .. 4.1. Methodology for ranking gas pipeline sections according to the degree of danger ... 4.1.1 VTD of gas pipelines when ranking according to the degree of hazard ..................... ………………. 4.2 Comprehensive diagnostics of insulating coating and ECP facilities ……… 4.2.1 Hazard factors of corrosion damage to pipelines ………. 4.2.2 An example of calculating a complex indicator of corrosivity… .. 4.3 Taking into account temperature fluctuations on large-diameter gas pipelines… ..… .. 4.4 Total integral indicator …………………………………………. 4.4.1 An example of calculating the total integral indicator …………………. 4.5 Development efficiency …………………………………………………
INTRODUCTION
Relevance works The total length of the operated in the system of OAO "Gazprom"underground gas pipelines are about 164.7 thousand km.
Currently, the main structural material for the construction of gas pipelines is steel, which has good strength properties, but low corrosion resistance in the environment - soil, which, in the presence of moisture in the pore space, is a corrosive medium.
After 30 or more years of operation of main gas pipelines, the insulating coating is aging and ceases to perform protective functions, as a result of which the corrosion condition of underground gas pipelines significantly deteriorates.
To determine the corrosion state of main gas pipelines, in-line flaw detection (IND) is currently used, which with sufficient accuracy determines the location and nature of corrosion damage, which makes it possible to track and predict their formation and development.
The presence of groundwater (soil electrolyte) plays a significant role in the development of corrosion processes, and it should be noted that the corrosion rate increases to a greater extent not in constantly watered or dry soil, but in soil with periodic moisture.
an impulse change in the temperature of the gas pipeline and fluctuations in humidity in a corrosive soil layer. However, the quantitative parameters of the pulsed temperature effect on the activation of corrosion processes have not been determined.
the laying of main gas pipelines under pulsed heat exposure and the forecast of the corrosion state of pipelines are relevant for the gas transportation industry.
Development and improvement of methods for determining the corrosion state of sections of main gas pipelines for their timely withdrawal for repair.
The main tasks:
1 Determination of changes in the specific electrical resistance of the soil around the main gas pipeline and analysis of the features of corrosion processes in pipeline transport.
2 Investigation in laboratory conditions of the influence of the pulsed thermal effect of the pumped gas and moisture on the corrosiveness of the soil surrounding the underground gas pipeline.
3 Investigation of the formation and development of corrosion defects on the main gas pipeline and the forecast of its corrosion state according to the data of in-line flaw detection.
Development of a methodology for ranking sections of main gas pipelines based on a forecast of their corrosion state for taking out for repair.
Scientific novelty 1 The change was determined and diagrams of the specific electrical resistance of the soil were plotted depending on the moisture content along the perimeter of a large-diameter underground gas pipeline.
2 The fact of activation of corrosion processes with a pulsed change in the temperature of the pumped gas in comparison with a stable temperature effect has been experimentally proved, and the temperature range in which the maximum corrosion rate develops under an unstable (pulsed) temperature effect has been determined.
3 A functional relationship has been determined for predicting the formation and development of corrosion defects on main gas pipelines.
Practical value Based on the studies carried out, the enterprise standard RD 3-M-00154358-39-821-08 "Methodology for ranking gas pipelines of Gazprom transgaz Ufa" based on the results of in-line flaw detection for taking them for repair was developed. nodes in order to determine the sequence of their withdrawal for repair.
Research methods The problems posed in the work were solved using the similarity theory by modeling the conditions of heat and mass transfer of an underground gas pipeline with the surrounding soil.
The results of diagnostic work were processed using the least squares method with correlation analysis. The calculations were carried out using the StatGrapfics Plus 5.1 software package.
Are brought to the defense:
the results of studies of changes in the specific electrical resistance of the soil depending on moisture content along the perimeter of the main gas pipeline;
the results of laboratory studies of pulsed thermal effects on the activation of corrosion processes on a steel pipeline;
- a method for ranking sections of main gas pipelines for taking them out for repair.
Main results dissertation work published in 30 scientific works, of which four articles in leading peer-reviewed scientific journals recommended by the Higher Attestation Commission of the Ministry of Education and Science of the Russian Federation.
Structure and scope of work The dissertation work consists of an introduction, four chapters, main conclusions, applications, bibliographic list used literature, including 141 titles, is presented on 146 pages of typewritten text, contains 29 figures and 28 tables.
Approbation of work The main materials of the dissertation were presented at:
Scientific and Technical Council of JSC "Gazprom" "Development and implementation of technologies, equipment and materials for the repair of insulating coatings and defective pipe sections, including defects of SCC, on the main gas pipelines of JSC" Gazprom ", Ukhta, 2003;
- scientific and technical conference of young specialists of JSC "Gazprom"
"New technologies in the development of the gas industry", Samara, 2003;
Scientific-practical conference "Problems and methods of ensuring the reliability and safety of objects of pipeline transportation of hydrocarbon raw materials", State Unitary Enterprise IPTER, Ufa, 2004;
international scientific and technical conference synergetics II ", USNTU, Ufa, 2004;
2nd international scientific and technical conference "Novoselovskie readings", USPTU, Ufa, 2004;
Scientific and technical conference of young leaders and industry specialists in modern conditions ”, Samara, 2005;
Pipeline transport ", USPTU, Ufa, 2005, 2006, 2012;
Scientific-practical conference of young scientists and specialists of OJSC Gazprom "Innovative potential of young scientists and specialists of OJSC Gazprom", Moscow, 2006;
Conferences for the best youth scientific and technical development on the problems of the fuel and energy complex "TEK-2006", Moscow, 2006;
- conferences of the International Fuel and Energy Association (MTEA), Moscow, 2006.
international scientific-practical conference of the problem of the oil and gas complex of Kazakhstan ", Aktau, 2011.
The corrosion state of the pipeline gas pipeline was developed in theoretical and experimental studies of scientists who are directly involved in the problems of pipeline transport: A.B. Einbinder, M.Z. Asadullina, V.L. Berezina, P.P. Borodavkina, A.G. Gareeva, N.A. Harris, A.G. Gumerova, K.M. Gumerova, I. G.
Ismagilova, R.M. Zaripova S.V. Karpova, M.I. Koroleva, G.E. Korobkova, V.V.
Kuznetsova, F.M. Mustafina, N.Kh. Khallyeva, V.V. Harionovsky and others.
Thus, underground corrosion of metals is one of the most complex types of electrochemical and biological corrosion.
According to regulatory documents, there are various indicators for assessing metal corrosion (loss of metal mass for certain time, decrease in pipe wall thickness, shell growth rate, etc.). These values are indicators of the resistance of metals to corrosion in certain types of soil.
1.1.1 Typical Corrosion Defects on a Steel Pipe The paper considers corrosion defects detected by high-temperature thermal operation and the peculiarities of their manifestation associated with the state of the insulating coating.
Operational experience shows that damage in the form of extensive closing pits (general corrosion) develops in the zones of exfoliation of the film insulation, which are in the mode of periodic wetting with groundwater.
Cathodic protection of the peeling zones of the film insulation is hampered, on the one hand, by a dielectric screen in the form of a polyethylene film, and, on the other hand, by unstable electrolyte parameters that impede the passage of the cathodic polarizing current through the gap into the zone of nucleation and development of ulcers or cracks colonies. As a result, the development of underfilm corrosion is quite often observed in the form of a chain of closing cavities, the geometry of which repeats the path of the electrolyte advance under the insulation.
It is widely known that bitumen-rubber insulation, after 10-15 years of operation in watered soils, loses adhesion to the metal surface.
However, corrosion under bituminous insulation in many cases does not develop. It develops only in cases where cathodic protection does not work well or is absent. The protection effect is achieved due to the formation of ionic transverse conductivity of bitumen insulation during long-term operation of the gas pipeline. Direct evidence of this is the shift in the pH of the soil electrolyte under the bitumen coating to 10-12 units as a result of the reaction with oxygen depolarization.
A significant place in the number of damages is occupied by pitting localized corrosion in the form of separate cavities, which reaches 23-40% of the total number of damages. It can be argued that, all other things being equal, the depth of local corrosion damage integrally estimates the effectiveness of cathodic protection in through insulation defects.
1.2 Violation of the protective properties of the insulating coating The main requirement for protective coatings is the reliability of the protection of pipelines against corrosion during the entire service life.
Widely used insulating materials can be conditionally divided into two large groups:
Polymer, including insulating tapes, extruded and sprayed polyethylene, epoxy and polyurethane materials;
- bituminous mastics with wrapping materials, combined mastic coatings.
Polymer insulating tapes have been widely used to insulate pipelines during their construction and repair, since the 60s of the last century. According to 74% of all constructed pipelines are insulated with polymer tapes. Polymeric insulating tape coatings are multilayer systems consisting of a base film, an adhesive layer and an adhesive primer (primer) layer. These protective materials are only a diffusion barrier preventing the penetration of corrosive media to the metal surface of the pipeline, and therefore their service life is limited.
In addition, the disadvantages of film coatings are:
- instability of adhesion;
- fragility of the coating;
- relatively high cost.
The instability of adhesion and, as a consequence, the fragility of the coating is associated with the insignificant thickness of the adhesive layer.
The adhesive base of sticky film materials is a solution of butyl rubber in organic solvents with certain additives. In this regard, the aging of the adhesive layer occurs much faster than the polymer base.
With a decrease in the performance of insulation to 50% of the initial values, the effectiveness of the coating as an anti-corrosive barrier decreases sharply.
Research results show that 73% of all failures on main gas pipelines in Canada are caused by stress corrosion under the plastic sheeting. It has been established that five times more stress-corrosion cracks are formed under single-layer polyethylene coatings than under bituminous coatings. Under two-layer film coatings, the number of stress-corrosion crack colonies per meter of pipe is nine times higher than with bitumen-based coatings.
The service life of polymer insulating tapes is 7-15 years.
The limitation, and in some cases the exclusion of the use of polymer insulating tapes in accordance with GOST R 51164 is associated with their short service life.
Based on the experience of re-insulation of main gas pipelines, it was found that in areas with factory insulating coatings, SCC defects and corrosion were not revealed.
Consideration of the performance characteristics of the most widely used anti-corrosion coatings allows us to conclude that they do not have properties that would fully meet the requirements for insulating materials that protect the pipeline from soil corrosion:
- adhesion to metals;
- mechanical strength;
Chemical resistance to corrosive agents - oxygen, aqueous solutions of salts, acids and bases, etc.
The noted parameters determine the ability of the anticorrosive material to resist corrosion and stress corrosion of gas pipelines.
The violation of the protective properties of the insulating coating on gas pipelines, with a film insulating coating of route application, occurs for a variety of reasons that affect the quality of the protective properties both independently of each other and in a complex. Consider the reasons for the impact on the film insulating coating.
Vertical soil pressure on the gas pipeline.
Due to the fact that the soil pressure is distributed unevenly along the perimeter of the pipe, the most problematic zones of delamination and the formation of corrugations of the insulating coating fall at positions 3-5 o'clock and 7-9 o'clock in the course of gas, with a conditional breakdown of the pipeline perimeter into sectors (the upper generatrix is 0 o'clock , bottom 6 o'clock). This is due to the fact that the insulating coating of the upper half of the pipe is subject to the greatest and relatively uniform soil pressure, which stretches the film coating and prevents the formation of corrugations and delamination in this area. In the lower half of the pipe, the picture is different: at a position of about 6 o'clock, the pipe rests on the bottom of the trench, due to which the likelihood of corrugation is negligible. At the 3-5 o'clock position, the soil pressure is minimal, since the pipe in this place comes into contact with the soil backfilled from the edge of the trench (see Figure 1.1). Thus, in the region of 3-5 hours along the perimeter of the pipeline, a shift-displacement of the film coating occurs with the formation of corrugations. This area can be considered as the most prone to the emergence and development of corrosion processes.
Linear expansion of mating materials.
One of the reasons for the formation of corrugations on the film insulating coating is the different coefficient of linear expansion of materials, film tape and pipe metal.
Let us analyze how the effect of temperature on the pipe metal and film tape differs in the "hot" sections of a large-diameter gas pipeline (gas pipeline exit from the compressor station).
Figure 1.1 - Diagram of the appearance of corrugations on a film insulating coating 1 - gas pipeline; 2 - the place of the probable formation of corrugations; 3 - pipeline support zone Temperature values at the pipe metal and film insulation during application can be taken equal to the ambient temperature, and during operation - equal to the gas temperature in the gas pipeline.
According to the data, the increase in the length of the steel sheet and film insulation along the perimeter of a pipe with a diameter of 1420 mm when the temperature changes from 20 to C (gas temperature), respectively, will be 1.6 mm and 25.1 mm.
Thus, in the "hot" areas, the film insulation can be lengthened by tens of millimeters more than the steel sheet, creating real conditions for the formation of delamination with the formation of corrugations, especially in the directions of least resistance at positions 3-5 and 7-9 o'clock of the perimeter of a large-diameter gas pipeline.
Poor primer application to the pipeline.
The quality of adhesion of the insulation coating determines its service life.
Insufficient stirring of bitumen in a solvent during the preparation of the primer or storage in a contaminated container leads to thickening of the primer, and therefore, it is applied to the pipeline unevenly or with smudges.
In route conditions, when various types of primers are applied to the wet surface of pipes and in windy weather, air bubbles may form in the primer layer, which reduce the adhesion of the primer to the metal.
Insufficient or uneven application of the primer to the pipe, skewed tarpaulin towels, heavy dirt and wear can lead to gaps in the primer layer.
In addition, there is a significant drawback in the technology of applying roll insulating coatings. In insulating work, the time interval between the application of the primer to the pipe and the winding of the polyethylene tape is insufficient for the solvent present in the primer to evaporate.
The low-permeability polyethylene film prevents the evaporation of the solvent, and numerous bulges appear under it, which break the adhesive bond between the coating layers.
In general, the listed factors significantly reduce the quality of the insulating coating and lead to a reduction in its service life.
1.3. Corrosiveness of soils When an insulating coating loses its protective properties, one of the main reasons for the occurrence and development of corrosion and stress corrosion is the corrosive aggressiveness of soils.
The corrosion of metals in soils is directly or indirectly influenced by many factors: chemical and mineralogical composition, particle size distribution, humidity, air permeability, gas content, chemical composition pore solutions, pH and eH of the medium, amount of organic matter, microbiological composition, electrical conductivity of soils, temperature, frozen or thawed state. All of these factors can act both separately and simultaneously in a specific place. One and the same factor in various combinations with others can in some cases accelerate and in other cases slow down the rate of metal corrosion. Therefore, it is impossible to assess the corrosiveness of the environment by any one factor.
There are many methods for assessing soil aggressiveness. The set of determined characteristic parameters in overall assessment the aggressiveness of the soil includes such its characteristics as electrical resistance (see table 1.1).
Table 1.1 - The corrosive properties of soils are assessed by the value of the specific electrical resistance of the soil in Ohm · m According to the specific soil, Ohm · m, the resistance of the soil is not as an indicator of its corrosive activity, but as a sign that marks areas in which intense corrosion can take place. " A low ohmic resistance only indicates the possibility of corrosion. High ohmic resistance of soils is a sign of weak corrosiveness of soils only in neutral and alkaline media. In acidic soils with a low pH value, active corrosion is possible, but acidic compounds are often insufficient to lower the ohmic resistance. As a supplement to the above methods for studying soil corrosion, the authors propose a chemical analysis of water extracts, which quite accurately determines the degree of soil salinity.
The most important factors of soil corrosiveness are its structure (see table 1.2) and its ability to pass water and air, humidity, pH and acidity, redox potential (eH), composition and concentration of salts present in the soil. In this case, an important role is assigned not only to anions (Сl-; SO 2; NO 3, etc.), but also to cations, which contribute to the formation of protective films and electrical conductivity of the soil.
Unlike liquid electrolytes, soils have a heterogeneous structure both at the microscale (soil microstructure) and at the macroscale level (alternation of lenses and layers of rocks with different lithological and Table 1.2 - Corrosion activity of soils depending on their type physicochemical properties). Liquids and gases in soils have limited movement capabilities, which complicates the mechanism for supplying oxygen to the metal surface and affects the rate of the corrosion process, and oxygen, as is known, is the main stimulant of metal corrosion.
Table 1.3 provides data on the corrosiveness of soils depending on pH and the content of chemical elements.
SeverNIPIgaz carried out investigations linking the accidents. Data on accidents for 1995-2004 were analyzed. (39 accidents), the chemical composition of soil and ground electrolyte was investigated. Distribution of accidents due to SCC by enlarged soil types are shown in Figure 1.2.
Table 1.3 - Corrosion activity of soils depending on pH and the content of chemical elements As can be seen from Figure 1.2, most accidents (61.5%) occurred in areas with heavy refractory soils, much less of them (30%) - in lighter soils and only isolated accidents occur in sands and swampy soils. Therefore, in order to reduce the number of accidents due to SCC, it is necessary to control the composition of the soil, which can be done at the design stage of a new branch of the gas pipeline. This also shows the need for soil research in the analysis and selection of sites for construction and reconstruction.
Figure 1.2 - Distribution of accidents due to SCC for 1995 - 2004 by Soil moisture plays big role in the course of corrosion processes. At low humidity, the electrical resistance of the soil is high, which leads to a decrease in the value of the flowing corrosion current. At high humidity, the electrical resistance of the soil decreases, but the diffusion of oxygen to the metal surface is very difficult, as a result of which the corrosion process slows down. There is an opinion that the maximum corrosion is observed at a humidity of 15-20%, 10-30%.
1.4 Reasons for the formation of macro-corrosive elements on the outer surface of the gas pipeline.
1.4.1 Conditions for the formation of macro-corrosive elements on the outer surface of the gas pipeline Corrosion destruction of the metal occurs on the outer surface of the gas pipeline in places where the insulation coating is damaged, despite the presence of cathodic protection of the gas pipeline. Often these phenomena are observed at the initial sections of gas pipelines (10-20 km after leaving the compressor station), with rugged terrain, confined to ravines, gullies, places with periodic moisture.
Analysis and generalization of numerous materials shows that the activation of corrosion processes is influenced by the behavior of groundwater under the thermal effect of the gas pipeline, which intensifies as the combined influence (or coincidence) of at least three factors:
- impulse change in the temperature of the gas pipeline;
- violations of the insulating coating of the gas pipeline;
- large diameter of the pipeline.
1. The fundamental difference between the initial section and the final one (in the absence or stability of gas offtakes along the route) is that it is at the initial section of the gas pipeline that fluctuations or impulsive changes in gas temperature are most felt. These fluctuations occur both due to uneven gas consumption, and due to imperfections in the air cooling system of the gas supplied to the gas pipeline. When using air coolers, weather fluctuations in air temperature cause similar fluctuations in gas temperature and are transmitted directly to the initial section of the gas pipeline via a waveguide (this phenomenon is especially manifested in the first 20 ... 30 km of a gas pipeline).
In the experiments of Ismagilov I.G. It was recorded that a temperature wave of 5 ° C, artificially created by switching off the AVO gas at the Polyanskaya compressor station, passed to the next station of the Moskovo compressor station with a decrease in amplitude to 2 ° C. On oil pipelines, where the flow rate is an order of magnitude lower, due to the inertia of the pumped product, this phenomenon is not observed.
2. In case of violation of the insulating coating, the formation of macro-corrosive elements occurs on the outer surface of the pipeline. As a rule, this occurs in areas with a sharp change in environmental parameters: ohmic resistance of soils and corrosive environments (Figure 1.3 and Figure 1.4).
Figure 1.3 - Model of micro-corrosive element 3. Effect of "large diameter". The geometric parameters of the hot pipeline are such that both the temperature and moisture content of the soil, and therefore other characteristics: ohmic resistance of the soil, properties of soil electrolytes, polarization potentials, etc., change along the perimeter.
Humidity around the perimeter varies from 0.3% to 40% and up to full saturation. In this case, the soil resistivity changes by a factor of ... 100.
Figure 1.4 - Model of macro-corrosive elements Studies have shown that the temperature of the pumped gas affects the cathodic polarization of pipe steel in carbonate solutions. The dependence of the potentials of the anode current maximum on temperature is linear. An increase in temperature leads to an increase in the dissolution current and shifts the potential range of the anode current to the negative region. An increase in temperature leads not only to a change in the rate of electrochemical processes, but also changes the pH of the solution.
With an increase in the temperature of the carbonate solution, the potential of the maximum anodic current associated with the formation of oxide, with an increase in temperature by 10 ° C, shifts towards negative values of the potential by 25 mV.
Due to the heterogeneity of the soil, changes in its moisture content and aeration, uneven compaction, gleying and other effects, as well as defects in the metal itself, a large number of macro-corrosive elements arise. At the same time, the anode sections with a more positive potential than cathodic ones are more exposed to corrosion destruction, which is facilitated by the pulsed thermal effect of the gas pipeline on the migration processes in the soil electrolyte.
Oscillatory processes of temperature and humidity in the soil provoke general corrosion. Macro-corrosive elements localized on the surface develop according to the SCC scenario or pitting corrosion centers. The generality of the electrochemical process leading to the formation of corrosion pits and cracks is indicated in.
It is the nonequilibrium thermodynamic processes that occur more intensively and with the maximum effect of the manifestation of the main features. With a pulsed temperature impact on the soil, almost synchronously, the parameters that determine its corrosiveness change. Since this process occurs throughout the entire operation time of the gas pipeline under the strong influence of the dominant parameters, the place of localization of the macroelement becomes quite definite, fixed in relation to the geometric marks.
As shown in the continuous oscillatory motion of ground moisture, which can be explained from the standpoint of the thermocapillary-film mechanism of motion, occurs throughout the entire operation time of the gas pipeline.
Thus, even in the presence of cathodic protection of a gas pipeline, in places where the insulating coating of a large-diameter gas pipeline is damaged due to the uneven distribution of soil moisture along the pipe perimeter, macro-corrosive elements inevitably arise, provoking soil corrosion of the pipe metal.
One of the important conditions for the occurrence of corrosion processes is the presence of dissociated ions in the soil electrolyte.
A previously not considered factor that determines the course of non-equilibrium processes, the impulse temperature effect of the gas on the pipeline wall and the impulse change in the moisture content of the soil adjacent to the pipeline.
1.4.2 Changes in the electrical resistance of the soil adjacent to the pipeline during the movement of moisture in the corrosive soil layer provide a discrete increase in the defect. As shown in, this process is facilitated by the impulse thermal effect of the gas pipeline on the migration processes in the ground electrolyte.
As a result of solving the inverse problem of thermal conductivity for the conditions of the section of the Urengoi gas pipeline corridor on the Polyana - Moskovo stretch, the pattern of soil moisture W distribution along the pipeline perimeter in time was determined.
Studies have shown that with a pulsed increase in temperature, moisture outflow from the pipe, and with a subsequent decrease in the temperature of the pipeline wall, the moisture content of the adjacent active soil layer increases.
Humidity also changes along the perimeter of the pipe section (Figure 1.5). Most often, the highest humidity is observed along the lower generatrix of the pipe, at the 6 o'clock position. The greatest fluctuations in humidity are recorded on the lateral surfaces of the pipe, where migration processes are most pronounced.
In continuation of this work (with the participation of the applicant), studies were carried out and the electrical resistance of the corrosive layer of soil around the pipeline was determined and the diagrams were constructed.
electrical resistance of the soil along the perimeter of the DN 1400 gas pipeline. They were built at different points in time based on the results of an industrial experiment carried out on the PolyanaMoskovo gas pipeline section of the Urengoy corridor, which showed that at operating temperatures of 30 ... 40 ° C, the soil under the pipe always remains wet, while time, as above the top of the pipe, the soil moisture is significantly reduced.
03.24.00, 04.10.00, 04.21.00 - quasi-stationary mode 7.04.00 - after shutdown of one compressor shop Figure 1.5 - Redistribution of moisture W and soil resistivity on the gas pipeline circuit according to the results of an industrial experiment.
Table 1.4 - Change in humidity and resistivity soil along the pipe perimeter Date tr, gr tv, gr Q, W / m.gr The range of moisture change in the soil layer in contact with the pipeline varies from full saturation to almost dehydration, see table 1.4.
Figure 1.5 shows that the most favorable conditions for the occurrence of defects of general corrosion and SCC arise in the lower quarter of the pipe at positions 5 ... 7 o'clock, where el is minimal, and W is maximal, the mode of change is pulsating, aeration is insignificant.
When constructing a diagram of the soil resistivity el along the contour of the pipe, a graph of the dependence of the soil resistivity on moisture was used (Figure 1.6).
It is shown that in winter, at the initial section of the gas pipeline, where temperatures are maintained at 25 ... 30 ° C and above, snow melts and a zone of waterlogged soil is maintained over the pipeline for a long time, which provides recharge and also increases the corrosive activity of soils.
The time of action or passage of a heat pulse is measured by oscillations). This time is quite enough for microequalizing currents to pass over a small interval. The data shown in Figures 1.5, 1.6 and in Table 1.4, obtained under industrial conditions for a gas pipeline with a diameter of 1420 mm, show that due to a change in moisture content along the perimeter of the pipe, the local corrosiveness of soils changes, which depends on the ohmic resistance, see Table 1.5.
Table - 1.5 Corrosion activity of soils in relation to carbon steel, depending on their specific electrical resistance Resistivity, Ohm.m Figure 1.6 - Dependence of the electrical resistivity of clay soil on moisture Novopskov, which is located in a fairly dry place, at the highest point above the ravine. The insulation of the pipeline in this section was in a satisfactory condition.
In ravines and gullies, where the change in moisture is more significant, these effects should be more pronounced. This picture is typical for the case of homogeneous soil along the pipe perimeter. For dissimilar lumpy backfill soils, the ohmic resistance of the components will be very different. Figure 1.7 shows graphs of the dependence of the resistivity of various soils on moisture.
Therefore, when changing soils, there will be breaks on the electrical resistivity diagram and macro-corrosive elements will be clearly marked.
Thus, a change in the temperature of a trace element leads to a change in the potentials of moisture and electrical resistance. These phenomena are similar to those that occur when the mode of installation of the cathodic protection is changed. Potential displacement or crossing the "dead" point is equivalent to disabling the cathodic protection and causes microequalizing currents.
The development of corrosion processes in a pulsed temperature regime leads to erosion or corrosion cracking of the pipe metal.
A situation is created when the resistance to the movement of ions in the soil electrolyte is variable along the perimeter of the pipe. The higher the section under consideration is located on the pipe surface, the slower the anodic reaction proceeds, since the humidity of the adjacent soil decreases, the ohmic resistance increases, and the removal of positive metal ions from the anode section becomes more difficult. With a decrease or approach to the position on the pipeline circuit corresponding to 5 ... hours, the rate of the anodic reaction increases.
At the 6 o'clock position, the soil is compacted, often there is gleying, oxygen access to the pipeline is difficult, as a result of which the reaction of electron attachment Figure 1.7 - Dependence of the resistivity of soils on their moisture content:
1– marshy; 2 - sandy; 3 - clayey.
(hydrogen or oxygen depolarization) proceeds at a slower rate. In the area with difficult oxygen access, the potential of the corrosion element is less positive, and the area itself will be the anode.
Under such conditions, the corrosion process proceeds with cathodic control, which is typical for most dense moist soils (ravines, gullies).
Here it can be assumed that the nature of the micro-equalizing and equalizing currents is identical. But microequalizing currents are fleeting and low-inertia and therefore more destructive.
The soil is a capillary - porous body. In the isothermal regime, the movement of moisture in the soil occurs under the action of electroosmosis and hydromechanical filtration. When a significant anode current flows, there is an electroosmotic distillation of moisture from the anode to the cathode. Under certain conditions, an equilibrium can occur between electroosmotic and hydromechanical filtration.
The processes of movement of ground moisture (electrolytes) in non-isothermal areas, especially in non-stationary modes, are much more complicated. Here, near the pipe, in the presence of a temperature gradient, thermocapillary or thermocapillary film motion occurs. The direction of movement of water (electrolyte) practically coincides with the direction of the heat flow, and is observed mainly in the radial direction, from the pipe. Convective currents at temperatures of the order of 30 ... 40 ° C are insignificant, but they cannot be neglected, since they affect the distribution of moisture along the pipe contour, and, consequently, the conditions for the formation of galvanic pairs.
With a pulsed temperature effect, temperature gradients change, which leads to a redistribution of migration flows. In the zone where soil corrosion occurs, the movement of moisture occurs in an oscillatory mode under the action of the following forces:
- thermomotive, - capillary, - electroosmotic, - filtration, - convective, etc.
If there is no filtration at the 6 o'clock position, a "stagnant zone" is formed.
As a rule, this is an area of minimal gradients, from which the evacuation of moisture is difficult. The soil taken under the lower generatrix, from the 6 o'clock position, has characteristic signs of gleying, which indicates a low activity of corrosive processes without oxygen access.
Thus, causally - investigative liaison establishes that the potential field around the gas pipeline forms a polarization potential that is variable not only along the length of the pipeline, but also along the cross-section, and in time.
It is believed, from the point of view of the traditional carbonate theory, that the corrosion process can be prevented by accurately controlling the magnitude of the polarization potential along the entire length of the pipeline, which seems insufficient. The potential must also be constant in the cross section of the pipe. But in practice, such measures are difficult to implement.
1.5 Influence of temperature and temperature fluctuations on the corrosive state of a gas pipeline Temperature conditions change significantly during the operation of the main gas pipeline system. Over the annual period of operation, the temperature of the soil at a depth of H = 1.72 m of the pipeline axis (DN 1400) in an undisturbed thermal state in the area of the Bashkortostan gas pipeline route varies within + 0.6 ... + 14.4 ° C. During the year, the air temperature changes especially strongly:
- average monthly from –14.6… = +19.3 oC;
- absolute maximum +38 оС;
- the absolute minimum is 44 ° C.
Almost synchronously with the air temperature, the gas temperature also changes after passing through the air coolers (AVO). According to long-term observations, the change in gas temperature after the apparatus for technological reasons and recorded by the dispatching service fluctuates within + 23 ... + 39 ° C.
determines not only the nature of the heat exchange between the gas pipeline and the ground. Temperature fluctuations cause a redistribution of moisture in the soil and affect the corrosion processes of pipe steels.
There is every reason to believe that the activity of corrosion processes directly depends not so much on temperature as on its fluctuations, since the unevenness of thermodynamic processes is one of the reasons that activate corrosion processes.
In contrast to the brittle destruction of a pipeline under the influence of high pressures or vibration effects, which occur rapidly, corrosive destructive processes are inertial. They are associated not only with electrochemical or other reactions, but are also determined by heat and mass transfer and the movement of ground electrolytes. Therefore, a change in the temperature of the active medium, extended in time for several days (or hours), can be considered as an impulse for a corrosive micro- or macroelement.
Destruction of gas pipelines due to SCC, as a rule, occurs at the initial sections of the gas pipeline route, behind the compressor station, with potentially dangerous pipeline movements, i.e. where the gas temperature and its fluctuations are maximum. For the conditions of the gas pipelines of the Company Urengoy - Petrovsk and Urengoy - Novopskov on the section Polyana - Moskovo, these are, mainly, crossings over ravines and gullies with temporary streams. Under the influence of significant temperature differences, especially when the position of the pipeline axis does not correspond to the design one and insufficient adhesion of the pipe to the ground, pipeline movements occur.
Repeated movements of pipelines lead to a violation of the integrity of the insulating coating and open access to groundwater to the metal of the pipe. So, as a result of variable temperature exposure, conditions are created for the development of corrosion processes.
Thus, on the basis of previous studies, it can be argued that a change in the temperature of the pipe wall entails a change in moisture and electrical resistance of the soil around it. However, there are no data on the quantitative parameters of these processes in the scientific and technical literature.
1.6 Diagnostics of gas pipelines using inline shells.
In the system of diagnostic work on gas pipelines key role is assigned to in-line diagnostics, which is the most effective and informative method diagnostic examination. At Gazprom transgaz Ufa LLC, at present, NPO Spetsneftegaz carries out diagnostics of the technical condition of the linear part of gas pipelines, which has in its arsenal equipment for examining gas pipelines with a nominal diameter of 500 - 1400 mm - the DMTP complex (5 shells), which includes:
- cleaning tool (CO);
- magnetic cleaning (MOP);
- electronic profiler (PRT);
transverse (DMTP) magnetization.
The use of VTD makes it possible to identify the most dangerous category of defects - stress-corrosion cracks (SCC), with a depth of 20% of the wall thickness and more. Diagnostic examination of high pressure fuel is of particular importance for large-diameter gas pipelines, where the likelihood of occurrence and development of SCC defects is high.
Among all detected defects the largest number falls on metal loss defects, such as general corrosion, cavity, ulcer, longitudinal groove, longitudinal crack, longitudinal crack zone, transverse groove, transverse crack, mechanical damage, etc.
flaw detector with 95% probability, are determined relative to the pipe wall thickness "t" in three-dimensional coordinates (length x width x depth) and have the following parameters:
- pitting corrosion 0.5t x 0.5t x 0.2t;
- longitudinal cracks 3t x 0.1t x 0.2t;
- transverse cracks 0t x 3t x 0.2t;
- longitudinal grooves 3t x 1t x 0.1t;
- transverse grooves 1t x 3t x 0.1t.
The hazard assessment of the identified defects can be carried out according to WFD 39 Methodological recommendations for the quantitative assessment of the state of gas pipelines with corrosion defects, their ranking according to the degree of hazard and determination of the residual resource, JSC Gazprom,.
For defects of a corrosive type, the following hazard assessment parameters are determined:
- the level of safe pressure in the gas pipeline;
- resource of safe operation of a pipeline with defects.
possibilities. The passage of VTD projectiles allows one to reliably determine the quantitative parameters of pipe wall defects, repeated passes - the dynamics of their development, which makes it possible to predict the development of corrosion defects.
1.7 Models for predicting corrosion processes.
there have been attempts to model this process. According to the linear model of the process belongs to M. Faraday and has the form:
where: A-const (constant value);
A large group of researchers have put forward a power-law model:
where: A = 13, a = 0.25; 0.5; 1,0 .. Table 1.6 summarizes the results of earlier studies of the kinetics of electrochemical corrosion of metals - the classification of mathematical models by the general form of functions. There are 26 models in total, which include: linear; power-law; exponential; logarithmic;
hyperbolic; natural logarithms; ranks; integral; sinusoidal;
combined, etc.
The following were considered as comparative criteria: loss of metal mass, thinning of the sample wall, cavity depth, corrosion area, acceleration (deceleration) of the corrosion process, etc.
Corrosion processes are influenced by many factors, depending on which processes can:
- develop at a constant rate;
- speed up or slow down;
- stop in their development.
Let us consider the kinetic curve presented in the coordinates of the depth of corrosion defects - time (Figure 1.8).
The segment of the curve 0-1 allows us to establish that the destruction of this metal in an aggressive environment (electrolyte) for the period t1 is practically not observed.
Curve section 1-2 shows that intensive destruction of the metal begins in the interval t = t2 - t1. In other words, the most intense transient process of metal corrosion occurs, characterized by the maximum possible (for this particular case) loss of metal, as well as by the maximum rates and accelerations of electrolysis.
Point 2, which has special properties, is essentially the inflection point of the kinetic corrosion curve. At point 2, the corrosion rate is stabilized, the derivative of the corrosion rate becomes equal to zero v2 = dk2 / dt = 0, because theoretically, the depth of the corrosion cavity at this point is constant k2 = const. The section of the curve 2-3 allows us to conclude that during the time t = t3 - t2, the transient corrosion process begins to fade. In the interval 3-4, the decay process continues, behind curve 4, corrosion stops in its development until a new impulse starts this mechanism.
The performed analysis shows that during the natural course of the electrochemical corrosion process, the metal is passivated, which practically stops the corrosion destruction of the metal.
In the sections of the main gas pipeline that are subject to corrosion destruction, as a result of a pulsed temperature effect (when the gas temperature changes), the processes of passivation and activation of corrosion processes alternate.
That is why none of the considered models can be used to predict the corrosion rate on gas pipelines.
In the case of a lack of information, which usually constitutes the main problem when trying to predict the development of corrosion processes, you can use Table 1.6 - Classification of mathematical models of the kinetics of electrochemical corrosion of metals according to the general form of functions (loss of metal mass or depth of the cavity, speed and acceleration of the corrosion process).
I. Denison, E. Martin, G.
Thornes, E. Welner, W. Johnson, I. Upham, E. Mohr, A. Bikkaris F. Champion, P. Aziz, J.
L. Ya. Tsikerman y = y0 y0, A1 = t1 / (t1-t2) Yu.V. Demin 12 G.K.Shreiber, L.S. Sahakiyan, y = a0 + a1x1 + a2x2 + ... + a7x7 a1, a2, ... ..a7 x1, x2, ... x7 y = f (x1, 14 L.Ya. Tsikerman, Ya.P. Shturman, A.V. Turkovskaya, Yu.M. Zhuk I.V., Gorman I.V. Gorman.G.B. Clark, L.A. Shuvakhina, V.V.
Agafonov, N.P. Zhuravlev Figure 1.8 - Graph of the kinetic curve of corrosion activity based on the physical representations of the process (Figure 1.9) and using the operation of maximum and average defects. But this is unlikely to allow predicting the dynamics of the quantitative growth of corrosion defects.
The presented models describe corrosion processes in the framework of specific situations, subject to certain conditions, chemical environment, temperature, steels of various grades, pressure, etc. Special interest present models describing the corrosion processes of similar systems (trunk pipelines) with an insulating coating, operating in similar conditions to gas pipelines, and recording the results also on the basis of in-line diagnostics. For example, in the method of carrying out factor analysis on main oil pipelines, regardless of the diameter and type of insulation coating, the authors propose a model:
where L is the attenuation coefficient of the corrosion process;
Н - depth of corrosion damage, mm;
From the above formula 1.6, it can be seen that the authors accepted the assertion that at the beginning of pipeline operation, corrosion has the most intensive growth, and then it has a decaying character due to passivation. The derivation and substantiation of formula (1.6) are given in the work.
operation of the pipeline is rather controversial, since The new insulating coating provides much better protection than over time as the insulation ages and loses its protective properties.
Despite the abundance of studies, none of the models proposed for predicting corrosion processes allows the effect of temperature on the corrosion rate to be fully taken into account. do not take into account its impulse change during operation.
This statement allows us to formulate the purpose of the research:
to prove experimentally that the unstable temperature regime of the gas pipeline is the primary cause of the activation of corrosion processes on the outer surface of the gas pipeline.
1. The analysis of literary sources was carried out in order to reveal the effect of gas temperature on the corrosion state of the gas pipeline:
1.1. The features of corrosion processes in pipeline transport are considered;
1.2. The role of the corrosiveness of soils in the case of loss of protective properties by the insulating coating has been determined.
1.3. The technical feasibility of in-line flaw detection was studied to assess the defectiveness of pipelines.
1.4. Models of other researchers for predicting corrosion processes are considered.
2. The reasons for the formation of macro-corrosive elements on the outer surface of the pipeline have been investigated.
3. It has been proven that when moisture moves in a corrosive soil layer, there is a change in the electrical resistance of the soil adjacent to the pipeline.
2. ASSESSMENT OF THE IMPULSE IMPACT OF MOISTURE AND
TEMPERATURES ON CORROSIVE ACTIVITY OF SOILS,
SURROUNDING GAS PIPELINE
2.1. Physical modeling and selection of control parameters The fact that periodic moistening of the soil accelerates corrosion processes is indicated by the practice of operating main gas pipelines.Studying this phenomenon, Ismagilov I.G. proved that a large-diameter main gas pipeline is a powerful source of heat, exerting a pulsed temperature effect on the soil and causing oscillatory movements of moisture in a corrosive soil layer.
However, his suggestion that the pulsed temperature effect enhances the corrosiveness of the soil layer adjacent to the pipeline needs experimental confirmation.
Therefore, the purpose of the study is to set up an experiment to study and assess the corrosiveness of soils under pulsed temperature exposure.
The problems of studying corrosion processes are usually solved experimentally. There are various methods for assessing the effect of corrosion, including accelerated corrosion tests.
Thus, it is necessary to simulate the conditions of heat and mass transfer with the surrounding soil, typical for a section of a gas pipeline crossing a ravine, along the bottom of which a stream flows, and to determine the extent to which the corrosiveness of the soil changes under impulse exposure to temperature and humidity.
The most accurate investigation of the effect of each factor (pulse temperature and humidity) is possible in laboratory conditions, where the parameters of the corrosion process are fixed and highly accurately regulated.
The pulsed temperature regime of a gas pipeline with quasi-stationary heat exchange was modeled for gas pipelines passing through the territory of Bashkortostan and similar regions. According to the theory of similarity, if the similarity numbers characterizing the heat transfer process are equal, with the observance of the geometric similarity, the heat transfer processes can be considered similar.
The soil used in the experiment was taken from the Urengoy - Petrovsk gas pipeline route of the Polyana - Moskovo section from the 3 o'clock, 12 o'clock and o'clock positions along the perimeter of the gas pipeline. The thermophysical properties of the soil used in laboratory studies are the same as in the field, because
soil samples were taken from the corrosive section of the operating gas pipeline. For identical soils, the equality of the Lykov numbers Lu and Kovner Kv for nature and model was automatically fulfilled:
Subject to the equality of the temperature heads, the identity of the soils and the same level of their moisture content, the equality of the Kossovich Ko and Postnov numbers Pn was fulfilled.
Thus, the problem of modeling the conditions of heat and mass transfer, in this case, was reduced to such a selection of installation parameters to ensure the equality of the Fourier numbers Fo and Kirpichev Ki for nature and model.
operation of a pipeline with a diameter of 1.42 m, with equal thermal diffusivity coefficients a = a ", on the basis of (2.5) we obtain for the model:
(2.7) So, with a test tube diameter of 20 mm, the annual period on the installation should “pass” in 1.7 hours.
The heat transfer conditions were modeled by the Kirpichev criterion Considering, approximately, the heat flow according to (2.9) At the depth of the gas pipeline to the pipe axis H0 = 1.7 m and H0 / Rtr = 2, (the relative depth of the gas pipeline in the Polyana - Moskovo section), on the basis of equality (2.6), we obtain for the model:
To model the "stream" it is necessary to maintain the equality of the Reynolds numbers for nature and model:
Since the liquid is the same, water, then on the basis of (2.12) and taking into account the geometric similarity, we obtain the equality:
The corresponding calculations, taking into account (2.13), show that the supply of water simulating a stream on a given installation must be drip.
Since in the course of the experiment it is necessary to change the temperature of the pipe wall within the limits of its real change of 30 ... 40 ° C, and to regulate it while maintaining the pulse mode, the temperature ttr of the outer surface of the steel tube - sample Art. 3.
To determine the relative corrosivity of soil under pulsed temperature exposure, in comparison with stable temperature exposure, an accelerated test method was chosen, on the basis of which the corrosivity of soils is determined by the weight loss of steel samples.
2.2. Brief description of the experimental setup The experimental setup, the diagram of which is shown in Figure 2.1, consists of a tin box 1, dimensions 90x80x128 mm. A specially prepared soil 11 is poured into the box to a height H, calculated from the condition that the volume of soil should be equal to:
A steel tube is placed in the ground, previously weighed on an analytical balance with an accuracy of 0.001 g. Parameters of steel tubes:
diameter, length, weight and surface area of the tubes are given in table 2.1.
Figure 2.1 - Diagram of an experimental setup for studying the pulsed temperature effect on the corrosive activity of soils Table 2.1 - Parameters of steel tubes - samples, Art. 3.
No. Diameter, Length, Surface, Weight, Note The tube was isolated from the tin box with rubber stoppers.
Soil samples, in the initial state in contact with the main gas pipeline, were prepared as follows.
Each of the samples was dried in an oven. Since the soil samples contained organic compounds and, possibly, sulfate-reducing bacteria, the drying temperature did not exceed 70 ° C. The dry soil was crushed and sieved through a sieve with 1 mm holes. A soil sample prepared in this way was poured into a box with an installed tube and moistened to a moisture content of W = 20 ... 25%, which corresponds to the natural soil moisture in the areas where the gas pipeline route passes. Natural temperature tap water was used in the experiments.
Acceleration of the corrosion process was achieved by connecting the negative pole to the case, and the positive pole of a 6 V DC source to the metal sample.
The pulsed temperature regime was created by periodically turning on and off a thermoelectric heater (TEN) installed inside the sample tube. The duration of the cycle was established empirically. For example, for the conditions of the 1st experiment, during the control of the temperature regime, the cycle duration was determined equal to t = 22 min (heating time n = 7 min; cooling time o = 15 min). Temperature control was carried out using a HK - thermocouple installed above the upper generatrix of the tube, without disturbing the sample surface.
In the course of the experiment, water was supplied in droplets through a funnel into the ground at the level of the tube axis. A barrage effect was created, which is typical for transverse gutters. The water was drained through the perforated holes on the side wall of the box (5 symmetrical holes at the same level).
After turning off the current 24 hours after the start of the experiment, the sample was photographed, thoroughly cleaned of corrosion products with a dry cloth and a rubber eraser. Then it was washed with distilled water, dried and weighed on an analytical balance with an accuracy of 0.001 g.
activity of soils under pulsed temperature exposure A necessary condition for corrosion tests is the acceleration of the controlling stage of the process. In neutral electrolytes, the corrosion process is limited by the rate of oxygen depolarization; therefore, to accelerate the corrosion process, it is necessary to increase the rate of the cathodic process.
The test of samples should be carried out in such a way that with a periodic change in humidity, the metal is exposed to the longest possible exposure to thin layers of electrolyte.
It is important to select modes when the soil is not completely dehydrated due to soil drying, and the moisture remains in a film state.
At an ambient temperature tgr = 20 ° C and a tube wall temperature ttr = 30 ... 40 ° C, a temperature head is created at the installation. level of 18 ° C.
In winter, the temperature head t increases to 30 ° C. But, winter mode it is not simulated at the installation, since the conditions of heat exchange and soil corrosion in winter are qualitatively different: "streams"
freeze, and above the pipeline, the snow cover partially thaws, moistening the soil, the "thermos" effect is manifested. Nevertheless, due to sufficient soil moisture, there is every reason to believe that corrosion processes, including SCC, are also active during winter periods.
Temperatures of the order of 30 ° C - this is the threshold temperature level for summer period below which moisture does not move away from the pipe and, as shown by studies at measuring points No. 1 and No. 2 of the gas pipeline on the stretch of the Polyana compressor station - Moskovo compressor station, it accumulates at some small distance from the pipe, being in a nonequilibrium state (small is a distance of about 0.2 .0.3 m from the pipeline wall with a diameter of 1.42 m). Therefore, any slight decrease in temperature leads to the return of moisture.
When the soil in contact with the pipe is dehydrated in very thin layers, along with the facilitation of the cathodic reaction, the anodic reaction can be inhibited, which, as a result, slows down the corrosion process.
Similar processes take place on the upper generatrix of the gas pipeline, where stress corrosion cracking is practically not observed.
Table 2.2 shows the results of corrosion studies performed on steel tubes-samples No. 1-4. The experiments were carried out sequentially, in the order indicated in this table.
Soil samples were not reused. The ambient temperature did not go beyond 18 ... 20 ° С. Registration of temperature regimes was carried out in the observation log. These data are presented in Appendix 1.
Sample No. 1 Was exposed to a pulsed temperature action.
The actual mode was determined by the temperature of the steel sample, which varied within: tнi ... tоi, (Appendix 1). The heating temperature tn is the temperature to which the temperature of the sample wall increased during the heating n. Cooling temperature tо is the temperature to which the temperature of the sample dropped during about. Time of the i-th cycle i = ni + oi; the number of cycles during the experiment n = 66.
Table 2.2 Conditions and results of experiments No. 1-4 to determine the corrosiveness of soils Average temperatures were determined by the formulas:
During the experiment, lasting 24 hours. 30 min, the average values of the parameters were maintained:
During the test, 24 hours 30 minutes, a process was simulated that took place in natural conditions for 24.5 / 1.7 14 years. During the year, on average, 1.760 / 22.3 = 4, the temperature regime changed from 30 to 40 ° C.
The nature of corrosion damage is shown in the photographs (Figure 2.2).
The manifestation of general corrosion over the entire surface of the sample is noted, but not significant. Dominated by very extensive, concentrated and deep foci. Figure 2.2 - Corrosion destruction of sample No. 1 during pulsed pitting corrosion. The maximum depth of the ulcerative lesion is noted in the continuous dripping water supply through the funnel, see the installation diagram in Figure 2.1. Water was supplied to the central part of the sample at the level of the tube axis. Flowing through the ground, the "stream" deviated to the left. The water runoff was carried out mainly through the 2nd hole on the left (in the presence of uniformly perforated 5 holes). It was this part of the sample that underwent the maximum corrosion damage.
Due to the barrage effect and high humidity, the erosion on the oncoming side is deeper and more extensive. The sample also shows a "stagnant" zone, where erosion is practically absent. This can be explained as follows.
Since, under the experimental conditions, a stream flowing down a ravine was simulated, and water was supplied without pressure, then away from the channel, with a tight adhesion of the soil to the surface of the sample, due to the high hydraulic resistance, water did not wash over the surface of the tube in the zone of tight contact and the intensity of corrosion processes was significantly less. Similar phenomena are observed in industrial conditions along the gas pipeline route.
Due to evaporation and rising streams of moisture from the "stream"
corrosion processes intensified in the upper left part of the sample.
This phenomenon can be explained by a large-scale factor, which is due to the small size of the tube, capillary rise in moisture and barrage effect.
With a pulsed temperature effect and unevenness of temperature, humidity, ohmic resistance and other parameters along the perimeter of the tube, the conditions created predispose to the formation of micro- and macro-corrosive elements.
It should be noted that a large amount of hydrogen was released during the entire experiment. The corresponding measurements were not carried out, but there was a constant sound effect, which was well heard.
Sample No. 2 The material of the second sample is the same. The soil is the same:
the sample was taken from the position of 3 o'clock. Soil moisture W = 22%. The experimental conditions differed in the temperature regime and the absence of a "stream". Throughout the experiment, the duration of which was 24 hours. 30 min., The temperature was kept constant:
Corrosion damage is much less here (Figure 2.3).
Sample weight loss is 7 times less (in relative units). General corrosion predominates. The sample surface is uniformly affected. One small focal lesion is noted in the lower part of the specimen.
Note the fundamental difference in the nature of corrosion damage of samples No. 1 and No. 2.
Figure 2.3 - Corrosion lesions of sample No. 2 at constant temperature ttr = 33 ° C Under a pulsed temperature effect on the process and the presence of running water, extensive pronounced pitting corrosion of the steel surface develops with maximum damage along the "stream".
At a stable temperature and the absence of a drain, but at the same initial moisture content, soil drying and the development of general corrosion with minimal ulcerative damage are observed. The rate of corrosion processes and metal loss is 7 times less.
Sample No. 3 The material of samples No. 3 and No. 4 is the same: Art. 3, but the samples are made from a different piece of pipe. Soil moisture was within natural limits W = 20 ... 25%. The experiment lasted 24 hours.
The temperature during the experiment was maintained equal to tfr = 33.12 33 ° C.
A soil sample was taken from the 6 o'clock position. The soil had a significant difference, which is typical for pipes exposed to SCC, gleying. (Gleying is the process of chemical recovery of the mineral part of the soil or rocks of deeper horizons, supersaturated with water, when iron oxide compounds are converted into ferrous ones and are carried away by water, and horizons depleted in iron are painted in greenish, black and grayish tones.).
Water, with a small drip feed (6 drops per minute), practically did not seep under the sample pipe, causing waterlogging in the zone of contact between the soil and the metal, at times rising in the funnel and creating a static head. Water was supplied asymmetrically, with an offset to the right side of the sample.
For sample No. 3 (Figure 2.4), corroded, under stable conditions of heat transfer, when the temperature of the sample was maintained constant at a level of ttr = 33 ° C, the following signs are noted:
1) General corrosion is characteristic, practically over the entire surface;
2) The characteristic signs of pitting corrosion were not revealed during the general examination;
3) In the area of scratches:
2 scratches 30 mm each 2 scratches 30 mm each 2 scratches 30 mm no signs of ulcerative lesion were found.
4) the maximum corrosion damage, determined by the thickness of the corrosion crust, was observed from the side of the spring, i.e., from the right side of the sample, and along the lower generatrix of the tube, where the humidity was maximum;
5) it is clearly seen that the color of the corrosion crust at the 6 o'clock position along the entire lower generatrix of the tube and in the area of the dampening is darker, most likely of a dark brown color;
6) the presence of 3 scratches in the waterlogged zone (on the right) and 3 of the same scratches in a less moist soil (on the left) did not in any way affect the nature of the development of the corrosion process;
7) it should be noted that after processing the sample tube on a lathe, traces of plastic deformation from the clamping point (in the form of light work hardening) were visible on its right side, which did not affect the nature of the corrosion damage.
Sample No. 4 The sample was cut from the same piece of pipe as the sample No. 3, Art. 3. Soil, the conditions of the experiment are the same as in experiment No. 3. The only difference: the pulse temperature regime, according to the scenario: 30/40 ° С. In the course of the experiment, lasting 24 hours, the average values of the parameters determined by the formulas (2.14 - 2.16) were maintained:
The flow of a "stream in a ravine" was simulated by the drip supply of water through a funnel, asymmetrically, to the right side of the sample. The number of cycles n = 63.
The sample has the same scratches as sample No. 3:
2 scratches 30 mm each 2 scratches 30 mm each 2 scratches 30 mm The nature of corrosion damage is shown in Figure 2.5.
Comparing the results of experiments No. 3 and No. 4, which were also carried out under identical conditions, but with a difference in temperature conditions, we note that in a soil that has signs of gleying, a pulsed temperature effect also intensifies the process. According to the relative mass loss, the difference is 11 times! (table 2.2).
Figure 2.4 - The nature of the corrosion damage of the sample No. 3 at a constant temperature ttr = 33 ° C 1 and # 2.
In experiment No. 4, a special phenomenon is noted that makes it possible to explain physical processes occurring in the soil under pulsed temperature exposure.
The fact of activation of the corrosion process indicates that the "swinging" of moisture, which occurs in a pulsed mode, under the influence of thermomotive forces, eventually leads to a change in the structure of the soil, smoothing of the bumps and the movement of particles of the dusty fraction in the capillaries, i.e.
in fact, improved ducts are formed through which the ground electrolyte moves unhindered. During the experiment, at the moment when water began to flow through the perforated holes, the movement of H2 bubbles along the capillaries and their removal along with the water (visually) was also noted.
In experiment No. 3 (t = const), the water supplied through the funnel practically did not seep through the perforated holes, causing at times even a rise in the water level in the funnel with the creation of a static head. No water leaked through the perforated holes. Soil electrolyte differs from liquid electrolyte by its high resistance to ion movement.
In experiment No. 4 (t = 31/42 ° C), the soil was used the same with gleying, with an hour. The only difference is the pulsed temperature regime. Moving in a non-pressurized mode, the water overcame the resistance of the ground in about 8 hours from the beginning of the experiment. After another hour, a balance was established: the inflow of water became equal to the outflow. The unit was shut down at night. In the morning, after turning on the unit, water dripped through the drainage holes after 50 minutes.
This fact indicates a decrease in the hydraulic resistance of the capillaries due to the formation of improved ducts. In such an environment, electrolyte ions are more mobile, which undoubtedly contributes to the corrosion of the metal, since it provides the renewal of the soil electrolyte with running water.
In this case, each impulse provides a change in the 1st and 2nd stages of formation, as if strengthening, adjusting the discrete growth of corrosion processes.
Naturally, this not only intensifies the development of corrosion processes, but also intensifies focal corrosion, point and surface, since they are characterized by general electrochemical processes.
Thus, the experiments carried out show that, other things being equal, pulsed temperature exposure and variable humidity increases the corrosiveness of the soil by 6.9 times (experiments No. 1 and No. 2), and with a deterioration in the physical characteristics of the soil by 11.2 times (experiment No. 3 and 4).
2.4. Investigation of the influence of the frequency of temperature fluctuations and thermal parameters on the corrosive activity of soils (second series of experiments) Frequent temperature fluctuations are characteristic of the operating modes of main gas pipelines. Within a month, only the number of starts of AVO fans at natural gas cooling sites reaches 30 ... 40.
During the year, taking into account technological operations (shutdown of the compressor shop, GPU, etc.) and climatic factors (rains, floods, changes in the air temperature, etc.), these are hundreds of fluctuations, and during the entire service life - thousands and tens of thousands.
In order to study the effect of the frequency of temperature pulses and an increase in the average temperature on the corrosive activity of soils, a second series of experiments (No. 5 - No. 8) was carried out on steel samples, in a soil electrolyte. Registration of temperature regimes was carried out in the observation log. These data are presented in Appendix 2.
The experiments were carried out on the same experimental setup.
Long-term thermodynamic processes were simulated taking place in the cross-section of the main gas pipeline with damaged insulation and periodic moisture (Figure 2.1).
exposed to pulsed temperature (humidity) exposure showed that when flowing water around the sample, extensive, pronounced ulcerative corrosion of the steel surface develops with maximum damage along the passage of moisture.
This fact indicates the effect of summation or superposition of the effects of temperature and humidity on corrosion processes with sharp increase corrosiveness of the environment.
With a stable temperature and no drain, with the same initial soil moisture, ulcerative lesions on the surface are minimal or absent, and metal losses due to corrosion are an order of magnitude less.
The results of the first series of experiments also gave grounds to assume that an increase in the number of temperature pulses leads to an increase in the weight loss of the prototypes. The basis for this statement was also the fact that ground electrolytes in a corrosive soil layer around a large-diameter gas pipeline behave in a very special way, namely:
1. They work in a porous soil environment, which prevents the movement of ions in the skeletal forms of the soil.
2. Are in oscillatory motion under the action of thermomotive forces, since the temperature gradients are constantly changing. At the same time, moisture "breaks through" its optimal path in a porous medium, smooths out irregularities and bumps in the capillary duct, which over time significantly reduces the hydraulic resistance of the capillaries.
3. An increase in the mobility of soil moisture and its oscillatory movement activate corrosion processes. In the presence of gutters (ravines, beams, etc.), active evacuation of corrosion products from the active soil layer to the periphery occurs and the electrolyte is renewed.
In this mode, corrosion defects develop rapidly, merge, forming a vast area of damage, which leads to a weakening of the bearing capacity of the gas pipeline wall, from this it can be assumed that an increase in the number of temperature cycles contributes to this process.
Experiments No. 5-No. 8 were carried out on a mixture of clay and loamy soils on samples identical to the samples of the first series of experiments (Table 2.3).
Table 2.3 - Parameters of the samples of the second series of experiments, with a cyclic heating mode The soils for the experiments were taken from the pits during the identification of SCC defects on the Urengoy - Petrovsk Du 1400 gas pipeline PK 3402 + 80. Soil samples taken from the 6 o'clock position have traces of gleying. The section of the gas pipeline in the PK 3402 + 80 pit was exposed to corrosive and stress-corrosive effects and was replaced during the repair work.
The temperature regime was set to pulse, according to the worked out scheme 45/35 ° C. Water was supplied to all samples in the same mode. The average temperature on the sample surface and the specific heat flux are shown in Table 2.4.
The samples of the second series of experiments were tested on the same experimental setup, but in contrast to the first, under identical conditions. Those. The soils were taken the same, the same water supply through the funnel was ensured, the same water and air temperatures were provided.
In these experiments, the temperature range of exposure is maintained at a higher level: 35..40 ° C (in the first series of experiments, the temperature varied in the range of 30 ... 35 ° C).
Table 2.4 - Heating modes for samples No. 5-No. Voltage Force Power Specific Average Variable was only the number of cycles n during each experiment.
was maintained within 24 ± 0.5 hours, which corresponded to approximately 14 years of gas pipeline operation in natural conditions (see clause 2.1).
The variation of the cycles in this series of experiments was achieved by changing the voltage across the heating element, and, consequently, by changing the specific heat flux supplied to the samples. Sample heating parameters are given in Table 2.7.
With the same duration of the compared experiments, the number of heating cycles of the samples is different: n = 14 (experiment No. 6) and n = 76 (experiment No. 8). Therefore, the heating rate of the sample in experiment No. 8 is very high, and the cooling is slowed down. In experiment No. 6, on the contrary, cooling occurs rapidly, and heat is accumulated in the soil gradually. Due to the qualitatively different heat transfer, the average temperatures tav in these experiments are different.
Table 2.5 - Parameters of heating samples in a cyclic mode 35/45 ° С Sample No. From table 2.5 it can be seen that the ratio of heating time n and cooling time o changes with a change in the number of cycles. And this is reflected in the nature of the temperature change ttr, determines the difference in average temperatures tav, electrolytes and, ultimately, on the rate of corrosion of the samples.
The nature of the temperature change ttr is shown in Figure 2.6. Analysis of the graphs shows that with an increase in the number of cycles, the ratio of the duration of heating and cooling changes. Figure 2.7 shows a fragment of experiment No. with a low power of the heating source, and in Figure 2.8, a fragment of experiment No. 8 with a high power of the heating source. In experiment No. 5 (82 cycles) and No. 8 (76 cycles), the heating time is shorter than the cooling time, and in experiments No. 6 and No. 7, vice versa.
The results of the experiments No. 5-8 show that the corrosion loss of the mass of the samples is different, see Table 2. Table 2.6 - The loss of the mass of the samples No. 5-No. 8 with a cyclic heating mode according to the 45/35 ° C scheme chemical processes. The biochemical nature of the acceleration or activation of corrosion processes in such an experimental setup is practically excluded.
Figure 2.6 - The nature of the pulsed temperature regimes of heating samples in experiments No. 5 - Figure 2.7 - Fragment of experiment No. 6, illustrating the rates of heating and cooling at a low power source (q = 46.96 W / m) Figure 2.8 - Fragment of experiment No. 8, illustrating the heating and cooling rates at a high source power (q = 239.29 W / m) Figure 2.9 shows a graphical dependence of the sample mass loss on the number of heat pulses in the experiments.
Sample weight loss, g / cm2 0, Figure 2.9 - Dependence of sample weight loss on the number of heat impulses Sample weight loss, g / cm Figure 2.10 - Sample weight loss dependence on thermal power Sample weight loss, g / cm that with an increase in the number of cycles for the same period of time, the activity of corrosion processes increases, as evidenced by an increase in the relative weight loss of the samples. This relationship is non-linear and progressive.
It should be noted that in spite of the fact that in experiment No. 8 a sample with a lower mass and a lower surface area was used in comparison with the rest of the samples, its specific weight loss was large. This can be explained by the fact that sample No. 8 was exposed to a higher specific heat flux, see Figure 2.10. Compared with sample No. 6, which was subject to the lowest specific heat flux, sample No. 8 has a specific weight loss of 6% more.
The corrosion rate, expressed in the loss of metal mass, depends on the average temperature tav of the outer surface of the samples (Figure 2.11, Figure 2.12). With an increase in temperature to values of 43..44 ° C, the corrosion rate decreases. This can be explained by a decrease in soil moisture around the pipe and its "drying" at higher temperatures. With a decrease in humidity, the activity of corrosive electrochemical processes decreases.
impulse temperature effect (n), but also from the thermal power of the source (q) and its average temperature tav.
2.5 Dependence of the corrosion rate on the average temperature with unstable heat transfer.
The analysis of the results of the experiments, including the consideration of the qualitative characteristics and quantitative relationships, made it possible to select the factor attributes that affect the effective attribute of the model.
turned out to be insufficient for performing multiple correlation-regression analysis of the results. Nevertheless, the analysis of the matrix of paired correlation coefficients obtained at the first stage of selection revealed factors that are closely related to each other, Table 2.7.
Table 2.7 - Ratio of parameters х1 (n) and х2 (tср) in relation to у (G / s) The closest relationship was found between the average temperature of the sample tср and the loss of its mass G / s. Paired correlation coefficient rх2 = -0.96431.
Factors that were closely related to each other appeared, which were discarded.
As a result, it was decided to consider the dependence of the form:
classifying the parameter х1 (n) as expressing the instability of the heat and mass transfer process.
This made it possible to consider both series of experiments together. To the four experiments of the second series No. 5..8, two more experiments No. 1 and No. 4 of the first series were added.
The resulting graphical dependence is shown in Figure 2.13.
The graphs in Figure 2.13 clearly illustrate the process of metal corrosion losses.
unstable heat and mass transfer of the pipe with the ground (and in the natural conditions of the gas pipeline with the ground), increases the corrosion loss of the pipe metal by an order of magnitude compared to stable modes when the pipe temperature is kept constant.
Secondly, with an increase in temperature in the region exceeding the temperature of 33 ° C, the corrosion rate slows down. This is due to the fact that at high temperatures, reaching 40 ° C and more, there is an outflow of moisture, its migration to the periphery, which causes the soil to dry out. With dehydration of the soil adjacent to the pipeline, the activity of corrosion processes decreases.
Thirdly, it can be assumed that the maximum corrosive activity falls on the temperature range in the region of 30 ... 33 ° C. Since it is known that with a decrease in temperature from 30 ° C to 10 ° C, the corrosion rate slows down, and at 0 ° C it practically stops.
When the temperature drops from +20 ° C to -10 ° C, the corrosiveness decreases by about 10 times.
That. the most dangerous, from the point of view of corrosion, can be considered operating temperatures of the order of + 30 ... + 33 ° C. It is in this range that large-diameter gas pipelines are operated.
A comprehensive survey of the corrosion state of the operating main gas and oil pipelines and their electrochemical protection systems was carried out in order to determine the dependence of the presence of corrosion and stress-corrosion damage on the external SCC on the operating modes of the ECP, to identify and eliminate the causes of the occurrence and growth of corrosion and stress-corrosion damage. Indeed, the main gas and oil pipelines are practically not subject to obsolescence due to their operation. The reliability of their operation is determined mainly by the degree of corrosive and stress-corrosive wear. If we consider the dynamics of the accident rate of gas pipelines for the period from 1995 to 2003, it becomes obvious that there is a process of increasing accidents over time due to the formation of corrosion and stress-corrosion defects at the KZP.
Rice. 5.1.
When considering the dynamics of elimination of especially dangerous defects on existing gas pipelines, it becomes obvious that during operation there is an increase in especially dangerous defects requiring priority repairs caused by external corrosion and stress-corrosion cracks (Fig.5.1). From what is shown in Fig. 5.1 of the graph it can be seen that almost all eliminated especially dangerous defects are of a corrosive or stsss-corrosive nature. All these defects were found on the outer cathode-protected surface.
The results of comprehensive surveys of the anticorrosive protection of gas and oil pipelines (the presence of pits and stress-corrosion cracks, adhesion and continuity of the insulating coating, the degree of electrochemical protection) indicate that the solution of the problem of anticorrosive protection of gas and oil pipelines using insulating coatings and cathodic polarization is still relevant. Direct confirmation of the above is the results of in-line diagnostics. According to the data of in-line diagnostics, in some sections of the main oil and gas pipelines with a service life of more than 30 years, the proportion of defects external corrosion(including stress corrosion) reaches 80% of the total number of detected defects.
The quality of the insulation of the main gas and oil pipelines is characterized by the value of the transient resistance, which is determined on the basis of the parameters of electrochemical protection. One of the main parameters of the electrochemical protection of pipelines, which characterizes the quality of the insulating coating, is the value of the cathodic protection current. The data on the operation of ECP means indicate that the value of the protective current of the RMS on the linear part D at 1220 mm over 30 years of operation due to aging of the insulation has increased almost 5 times. Current consumption to ensure electrochemical protection of 1 km of the oil pipeline in the area of protective potentials 1.2 ... 2.1 V at m. S. NS. increased from 1.2 to 5.2 A / km, which indicates a proportional decrease in the transient resistance of the oil pipeline. The transient insulation resistance after 30 years of operation of gas and oil pipelines has the same order (2.6-10 3 Ohm - m 2) along the entire length, except for the sections where the gas and oil pipelines were repaired with the replacement of insulation, while the number of corrosive and strsss - corrosion damage on the external cathode-protected surface varies within significant limits - from 0 to 80% of the total number of defects detected using in-line flaw detection, which are localized both at the joints of the protective zones, as well as near the drainage points of the SCZ in lowlands and on swampy sections of the route ... The ground waters of the wetlands of the central part of Western Siberia are characterized by low mineralization (0.04% by weight) and, as a consequence, high ohmic resistance (60 ... 100 Ohm m). In addition, bog soils are acidic. The pH value of bog waters reaches 4. The high ohmic resistance and acidity of bog electrolyte are critical factors affecting the rate of corrosion of gas pipelines and the effectiveness of their electrochemical protection. Attention is drawn to the fact that in the pore solutions of bog soils, the content of hydrogen sulfide reaches 0.16 mg / l, which is an order of magnitude higher than in ordinary soils and flowing water bodies. Hydrogen sulfide, as shown by survey data, also affects the corrosion state of gas and oil pipelines. The occurrence of hydrogen sulfide corrosion due to the activity of sulfate-reducing bacteria (SRB) is indicated, for example, by the fact that, other conditions being the same, the maximum penetration depth of external corrosion in through defects in the insulation of gas and oil pipelines in stagnant swamps is greater than that in flowing water bodies by an average of 70%. on the one hand, and practically everywhere, strss-corrosion cracks on the external SCB are also found in stagnant bogs with an increased content of H 2 S - on the other. According to modern concepts, molecular hydrogen sulfide stimulates the hydrogenation of steels. Electroreduction of H 2 S at the KZP of the pipeline proceeds according to the reactions H, S + 2- »2H als + S a ~ c and H, S + v- ^ H ads + HS ”ac, which increases the degree of filling of the chemisorbed layer with atomic hydrogen in c diffusing into the structure of pipe steel. An effective stimulant of hydrogenation is also carbon dioxide: HC0 3 + e-> 2Н ads + С0 3 ". The problem of corrosion and
The strss-corrosion destruction of oil and gas pipelines on the swampy sections of the route has not yet been fully explained and remains relevant. The results of corrosion inspection of main gas and oil pipelines in swampy areas showed that almost the entire outer surface, both on oil pipelines and on gas pipelines, is covered with insulation defects and under exfoliated insulation with brown (resembling aluminum powder) deposits. Corrosion ulcers with the maximum depth are localized in penetrating damage to the insulation. The geometrical parameters of corrosion damage almost exactly correspond to the geometry of through insulation damage. Under the exfoliated insulation, in the zone of contact of the pipe wall with soil moisture, there are traces of corrosion without visible corrosion pits with traces of stress corrosion cracks.
Experimentally, on samples of pipe steel installed at the wall of the main oil pipeline D at 1220 mm (at its upper, side and lower generatrix), it was determined that in the soils of the taiga-bog region of the central part of Western Siberia, the corrosion rate of samples without cathodic protection in through insulation defects reaches 0.084 mm / year. Under protective potential (with ohmic component) minus 1.2 V in m. S. e., when the cathodic protection current density exceeds the limiting oxygen current density by 8 ... 12 times, the residual corrosion rate ns exceeds 0.007 mm / year. This residual corrosion rate corresponds to the corrosion state according to a 10-point corrosion resistance scale. very persistent and for main gas and oil pipelines is permissible. In this case, the degree of electrochemical protection is:
A comprehensive examination of the corrosion state of the external cathode-protected surface of gas and oil pipelines in pits in through-hole insulation defects reveals corrosion pits with a depth of 0.5 ... 1.5 mm. It is not difficult to calculate the time during which the electrochemical protection did not ensure the suppression of the soil corrosion rate to the permissible values corresponding to very persistent corrosive state of gas and oil pipelines:
at a corrosion penetration depth of 0.5 mm at a corrosion penetration depth of 1.5 mm
This is for 36 years of operation. The reason for the decrease in the efficiency of electrochemical protection of gas and oil pipelines against corrosion is associated with a decrease in the transient insulation resistance, the appearance of through defects in the insulation and, as a result, a decrease in the cathodic protection current density at the joints of the protective zones of the SCZ to values that do not reach the values of the limiting current density for oxygen, which do not provide suppression soil corrosion to permissible values, although the values of the protective potentials measured with the ohmic component correspond to the standard. An important reserve, allowing to reduce the rate of corrosion destruction of gas and oil pipelines, is the timely identification of areas of underprotection when L 1 1 Lr
Correlation of external corrosion defects of an oil pipeline with the duration of outages on along-route overhead lines indicates that it is during shutdowns of along-route overhead lines and downtime of the CPS that pitting corrosion occurs in through insulation defects, the rate of which reaches 0.084 mm / year.
Rice. 5.2.
In the course of a comprehensive examination of the electrochemical protection systems of main gas and oil pipelines, it was found that in the field of cathodic protection potentials 1.5 ... 3.5 V at m. S. NS. (with ohmic component) cathodic protection current density j a exceeds the limiting current density of oxygen j 20 ... 100 times or more. Moreover, with the same cathodic protection potentials, the current density, depending on the type of soil (sand, peat, clay), differs significantly, almost 3 ... 7 times. In the field, depending on the type of soil and the depth of laying the pipeline (the depth of immersion of the corrosion indicator probe), the limiting current density for oxygen, measured on a working electrode made of 17GS steel with a diameter of 3.0 mm, varied within 0.08 ... 0, 43 A / m ", and the cathodic protection current density at potentials with an ohmic component from
1.5 ... 3.5 V per m. S. e., measured on the same electrode, reached values of 8 ... 12 A / m 2, which causes an intense release of hydrogen on the outer surface of the pipeline. Some of the hydrogen adatoms under these cathodic protection modes pass into the near-surface layers of the pipeline wall, hydrogenating it. On increased content hydrogen in samples cut from pipelines subject to stress-corrosive destruction is indicated in the works of domestic and foreign authors. Hydrogen dissolved in steel has a softening effect, which ultimately leads to hydrogen fatigue and the appearance of stress-corrosion cracks on the SCC of underground steel pipelines... The problem of hydrogen fatigue of pipe steels (strength class X42-X70) in recent years has attracted Special attention researchers in connection with the increased frequency of accidents on main gas pipelines. Hydrogen fatigue at cyclically changing operating pressure in the pipeline is observed in almost pure form during cathodic overload, when j KZ / j> 10.
When the current density of cathodic protection reaches the values of the limiting current density for oxygen (or slightly, not more than 3 ... 5 times, exceeds ce), the residual corrosion rate ns exceeds 0.003 ... 0.007 mm / year. Significant excess (more than 10 times) j K t above j practically does not lead to further suppression of the corrosion process, but it leads to hydrogenation of the pipeline wall, which causes the appearance of stress-corrosion cracks at the SCC. The appearance of hydrogen embrittlement during a cyclic change in the operating pressure in a pipeline is hydrogen fatigue. Hydrogen fatigue of pipelines is manifested under the condition that the concentration of cathodic hydrogen in the pipeline wall does not decrease below a certain minimum level... If the desorption of hydrogen from the pipe wall occurs faster than the development of the fatigue process, when yc exceeds / pr by no more than 3 ... 5 times, hydrogen fatigue
not visible. In fig. 5.3 shows the results of measuring the current density of hydrogen sensors with enabled (1) and disabled (2) SCZ on the Gryazovets pipeline.
Rice. 5.3.
and disabled (2) SKZ at KP I; 3 - potential of the cathodic protection when the SCZ is on - (a) and the dependence of the currents of the hydrogen sensors on the potential of the pipe with the on and off SCZ at KP 1 - (b)
The cathodic protection potential during the measurement period was in the range of minus 1.6 ... 1.9 V m. S. NS. The course of the results of trace electrical measurements, presented in Fig. 5.3, a, indicates that the maximum density of the hydrogen flux into the pipe wall with the SCZ turned on was 6 ... 10 μA / cm 2. In fig. 5.3, b the areas of variation of the currents of hydrogen sensors and cathodic protection potentials with the RMS on and off are presented.
The authors of the work note that the potential of the pipeline with the RMS off did not decrease below minus 0.9 ... 1.0 V m. S. Oe., which is due to the influence of adjacent RMS. In this case, the current densities of hydrogen sensors with the RMS on and off differ in
2 ... 3 times. In fig. 5.4 shows the curves of changes in the currents of hydrogen sensors and cathodic protection potentials at KP 08 of the Krasnoturinsky unit.
The progress of the experimental studies presented in Fig. 5.4 indicates that the maximum hydrogen flux density into the pipe wall did not exceed 12 ... 13 μA / cm 2. The measured potentials of the cathodic protection were in the range from minus 2.5 ... 3.5 V m. S. NS. It was shown above that the volume of hydrogen released at the QPC depends on the value of the dimensionless criterion j K s / y etc. In this regard, it is of interest to compare the results of in-line diagnostics of operating oil and gas pipelines with cathodic protection modes.
Rice. 5.4.
Table 5.1 presents a comparison of the results of in-line diagnostics with the results of a comprehensive survey of ECP systems of operating oil and gas pipelines in the central part of Western Siberia. The results of electrochemical measurements on the linear part of operating oil and gas pipelines indicate that in different soils at the same values of the measured potential, the current density of cathodic protection varies within wide limits, which makes it necessary to select and adjust protective potentials underground pipelines additionally monitor the cathodic protection current density in relation to the limiting oxygen current density. Additional electrochemical measurements on the route of existing main gas and oil pipelines will prevent or minimize the formation of high local stresses in the pipeline wall caused by hydrogen molization (with high figurativeness). An increase in the level of local stresses in the pipeline wall is associated with a change in the triaxiality of the stress state in local areas enriched in cathode hydrogen, where microcracks form, precursors of stress-corrosion cracks on the external SCC.
Comparison of the results of intratubal diagnostics with the results of a comprehensive examination of systems
electrochemical protection of operating gas and oil pipelines in the central part of Western Siberia
|
Distance, |
Distribution of protective potential (0WB) (Person A / m 2) |
Meaning criterion j k.z ^ Jxvp |
operation, mm |
Density defects a loss methane, |
Density defects bundle, | |||
|
Linear part of the main oil pipeline D u 1220 mm |
||||||||
|
Distance, |
Limiting current density for oxygen (ЛрХА / m2 |
Distribution of protective potential and cathodic protection current density (Lash> A / m 2) |
Meaning criterion Ukz ^ Control |
Maximum depth of corrosion penetration for the entire period operation, mm |
Density defects a loss metal, |
Density of defects delamination, pcs / km |
The total duration of the downtime of the RMS for the entire period of operation (according to the operating organization), days |
|
Analysis of the results presented in table. 5.1, taking into account the duration of the downtime of the RMS, indicates an inverse proportional relationship between the density of corrosion defects and the value of the dimensionless criterion j K s / j, including when this ratio was equal to
zero. Indeed, the maximum defect density external corrosion observed in areas where the duration of the downtime of electrochemical protection means (according to the operating organizations) exceeded the standard values. On the other hand, the maximum density of defects of the type delamination observed on swampy floodplain sections of the route, where the duration of the downtime of the ECP means did not exceed the standard values. An analysis of the operating modes of the SCZ in areas with a minimum duration of their downtime against the background of a large scatter of data indicates an almost proportional relationship between the density of defects of the type delamination and criterion j K 3 / /, when the current density of the cathodic protection exceeded the limiting current density for oxygen ten or more times during a long period of operation (with the minimum duration of the RMS downtime). The performed analysis of the modes of cathodic protection in comparison with corrosion and stress-corrosion defects at the SCC confirms the earlier conclusions that the ratio j K 3 / j np can serve as a dimensionless criterion for monitoring the residual corrosion rate of a pipeline at various cathodic protection potentials, on the one hand, in order to prevent the formation of defects on the SCC external corrosion and to determine the intensity of electrolytic hydrogenation of the pipeline wall - on the other hand, in order to exclude the formation and growth of defects of the type delamination near the cathode-protected surface.
Table data. 5.1 indicate that the maximum duration of downtime for almost all RHCs over the entire period of operation of main oil and gas pipelines, for 36 years, averaged 536 days (almost 1.5 years). According to the operating organizations, over the year, the downtime of the VHC averaged 16.7 days, and for the quarter - 4.18 days. This duration of the downtime of the SCZ on the linear part of the inspected oil and gas pipelines practically meets the requirements of regulatory and technical documents (GOST R 51164-98, p. 5.2).
Table 6.2 shows the results of measuring the ratio of the cathodic protection current density to the limiting current density for oxygen at the upper generatrix of the main oil pipeline D at 1220 mm. The calculation of the residual corrosion rate of the pipeline at the given cathodic protection potentials is determined by the formula 4.2. Given in table. 5.1 and 5.2 the data indicate that for the entire period of operation of the main oil pipeline, taking into account the downtime of the means of elctrochemical protection
(according to the operating organization) the maximum depth of corrosion penetration at the external KZP should not exceed 0.12 ... 0.945 mm. Indeed, the density of the limiting current for oxygen at the level of laying the surveyed sections of oil and gas pipelines varied from 0.08 A / m 2 to 0.315 A / m 2. Even with the maximum value of the limiting current density for oxygen of 0.315 A / m 2, the maximum depth of corrosion penetration over 36 years of operation with a planned idle RMS of 1.15 years will not exceed 0.3623 mm. This is 3.022% of the nominal pipe wall thickness. In practice, however, we see a different picture. Table 5.1 presents the results of in-line diagnostics of the section of the main oil pipeline D at 1220 mm after its operation for 36 years. The results of in-line diagnostics indicate that the maximum corrosive wear of the pipeline wall exceeded 15% of the nominal pipe wall thickness. The maximum corrosion penetration depth reached 2.0 mm. This means that the duration of the downtime of the ECP means does not meet the requirements of GOST R 51164-98, clause 5.2.
The performed electrometric measurements, presented in table. 5.2, indicate that at a given mode of cathodic protection, the residual corrosion rate did not exceed 0.006 ... 0.008 mm / year. This residual corrosion rate corresponds to the corrosion state according to a 10-point corrosion resistance scale. corrosion-resistant and for main oil and gas pipelines is permissible. This means that for 36 years of pipeline operation, taking into account information about the idle time of ECP, according to the operating organization, the depth of corrosion penetration would not exceed 0.6411 mm. Indeed, for the period of planned downtime of ECP facilities (1.15 years), the depth of corrosion penetration was 0.3623 mm. Over the period of operation of the ECP facilities (34.85 years), the depth of corrosion penetration was 0.2788 mm. The total depth of corrosion penetration at the KZP would be 0.3623 + 0.2788 = 0.6411 (mm). The results of in-line diagnostics indicate that the actual maximum depth of corrosion penetration over 36 years of operation on the surveyed section of the main oil pipeline D at 1220 mm was 1.97 mm. Based on the available data, it is easy to calculate the time during which the electrochemical protection ns ensured the suppression of the soil corrosion rate to permissible values: T = (1.97 - 0.6411) mm / 0.08 mm / year = 16.61 years. The duration of the downtime of the ECP facilities on the main gas pipeline D, passing in one technical corridor, is 1020 mm, on which, in the floodplain of the river. Obi, stress-corrosion cracks were found, coinciding with the duration of the downtime of the RPS on the main oil pipeline, since the RPS of the gas pipeline and the oil pipeline are powered from the same along-route overhead line.
Table 5.3 presents the results of determining the real downtime of the RMS during the entire period of operation (36 years) of trunk oil and gas pipelines based on electrometric measurements.
Table 5.2
Distribution of the residual corrosion rate in sections of operating gas and oil pipelines in the central part of Western Siberia
Table 5.3
Results of determining the true downtime of the RMS during the entire period of operation (36 years) of main gas and oil pipelines based on electrometric measurements
|
Distance, |
Maximum possible corrosion rate of a pipeline without short circuit, mm / year |
Residual corrosion rate of the pipeline at a given SC mode, mm / year |
Maximum depth of penetration of corrosion on a cathode-protected surface, mm |
The real |
|
Linear part of the main oil pipeline D u 1220 mm |
||||
|
Linear part of the main gas pipeline D u 1020 mm |
||||
Analysis of the results presented in table. 5.3, indicates that the real downtime of electrochemical protection means significantly exceeds normative value, which is the cause of intensive corrosion wear of the pipeline wall from the outer, cathode-protected side.
B. V. Koshkin, V. N. Shcherbakov, V. NS. Vasiliev, GOUVPO "Moscow state Institute of Steel and Alloys (technological the university) » ,
SUE Mosgorteplo
Electrochemical methods for assessing, monitoring, diagnosing, predicting corrosion behavior and determining corrosion rates, which have been well developed theoretically for a long time, and are widely used in laboratory conditions, have begun to be used to assess the corrosion state under operating conditions only in the last 5-10 years.
A distinctive feature of electrochemical assessment methods is the ability to determine the corrosion state (including continuously) in real time with a simultaneous response of the material and corrosive environment.
The methods of polarization resistance (galvanic and potentiostatic), resistometric and impedance methods are most widely used for assessing the corrosion state in operating conditions. Practical use got the first two. The galvanostatic method of measurement is used in portable portable devices, the potentiostatic method is used mainly in laboratory studies due to more complex and expensive equipment.
The polarization resistance method is based on the measurement of the corrosion rate by determining the corrosion current.
Existing foreign instruments for measuring corrosion rates are based mainly on the principle of polarization resistance and with a sufficient degree of accuracy can determine the corrosion rate only under conditions full immersion the measured object into a corrosive environment, i.e. the corrosiveness of the medium is practically determined. Such a measurement scheme is implemented in foreign devices for assessing the corrosion rate (devices from ACM, Ronbaks, Voltalab, Magna, etc.). The devices are quite expensive and not adapted to Russian conditions. Domestic corrosion meters determine the aggressiveness of the environment, regardless of the real steels from which the pipelines are made, and therefore cannot determine the corrosion resistance of pipelines under operating conditions.
In this regard, a corrosion meter was developed at MISiS, designed to determine the corrosion rates of pipelines of heating networks made of actually operating steels.
The small-sized corrosion meter "KM-MISiS" (Fig. 1) is developed on a modern element base on the basis of a precision digital microvoltmeter with zero resistance. The corrosimeter is designed to measure the corrosion rate by the polarization resistance method with current-free IR compensation. The device has a simple, intuitive interface for control and input / output of information on the liquid crystal display.
The program of the corrosion meter provides for the possibility of entering parameters that allow evaluating the corrosion rate of various steel grades and setting the zero. These parameters are set during the manufacture and calibration of the corrosion meter. The corrosimeter shows both the measured value of the corrosion rate and the current values of the potential difference "E 2 - E1» to control parameters.
The main parameters of the corrosion meter are in accordance with Unified System Corrosion and Aging Protection (ESZKS).
Corrosimeter "KM-MISiS" is designed to determine the rate of corrosion by the method of polarization resistance in electrolytically conductive media and can be used to determine the rate of corrosion of metal parts and equipment in the energy sector, chemical and petrochemical industry, construction, mechanical engineering, environmental protection, for educational needs.
An experienceexploitation
The corrosimeter has passed pilot tests in the operating conditions of Moscow heating networks.
Tests on Leninsky Prospekt were carried out in August - November 2003 on the first and second circuits of heating networks (subscriber 86/80). In this section, nozzles were welded into the I and II circuit of pipelines of heating networks, into which sensors (working electrodes) were installed and daily measurements of the corrosion rate and electrochemical parameters were carried out using a prototype corrosion meter. The measurements were carried out in the inner part of the pipelines with registration of the parameters of the coolant. The main parameters of the coolant are shown in Table 1.
For measurements with different durations from 5 to 45 min. recorded the main parameters of the corrosion state of pipelines of heating networks during long-term tests. The measurement results are shown in Fig. 2 and 3. As follows from the test results, initial values corrosion rates correlate well with long-term tests both in tests in I and II circuits. The average corrosion rate for the primary circuit is about 0.025 - 0.05 mm / year, for the second circuit, about 0.25 - 0.35 mm / year. The results obtained confirm the available experimental and literary data on the corrosion resistance of pipelines of heating networks made of carbon and low-alloy steels. More accurate values can be obtained by specifying the steel grades of the pipelines in use. Inspection of the corrosion state of heating networks was carried out on the section of the Entuziastov highway - Sayanskaya street. Heating main sections in this area (No. 2208/01 - 2208/03) often fail, pipelines in this area 
stke were laid in 1999 - 2001. The heating main consists of a straight line and a reverse line. The temperature of the straight line of the heating main is about 80-120 ° C at a pressure of 6 atm, the return temperature is about 30-60 ° C. In the spring-autumn period, the heating main is often flooded with groundwater (near Terletskie ponds) and / or sewage. The nature of laying the heating main in this area is channel, in concrete gutters with a cover, and a laying depth of about 1.5-2 m. The first leaks in the heating main were noticed in the spring of 2003, failed and were replaced in August - September 2003. During the inspection, the heating main channel was flooded by about 1/3 - 2/3 of the pipe diameter with groundwater or runoff. Heating pipes were insulated with fiberglass.
Plot No. 2208/01 - 22008/02. The heating main was laid in 1999, pipes are welded, longitudinal-seam, 159 mm in diameter, presumably made from st. 20. The pipelines have a heat-insulating coating of Kuzbass varnish, mineral wool and glassine (roofing material or fiberglass). In this area, there are 11 defective zones with through-corrosive lesions, mainly in the flooded zone of the channel. The density of corrosive lesions along the length of the straight line is 0.62 m-1, the reverse is -0.04 m -1. Out of order in August 2003.
Plot No. 2208/02 - 2208/03. Installed in 2001. Preferential corrosion of the heating main line. The total length of defective sections of the pipeline to be replaced is 82 m. The density of corrosive lesions of a straight line is 0.54 m -1. According to GUP Mosgorteplo, the pipelines are made of 10KhSND steel.
Section No. 2208/03 - Central Heating Station. Laid in 2000, seamless pipes, presumably from st. 20. Density of corrosive lesions of a straight line -0.13 m -1, a reverse line -0.04 m-1. The average density of through-corrosive lesions (such as delocalized pitting corrosion) of the outer surface of straight-line pipelines is 0.18 - 0.32 m -1. The cut pipe samples are not coated on the outside. The nature of corrosive lesions on the outer side of the pipe of the samples is mainly general corrosion in the presence of through lesions such as pitting corrosion, which have a conical shape with a size of about 10-20 cm from the outer surface, turning into through lesions with a diameter of about 2-7 mm. On the inside of the pipe there is a slight general corrosion, the condition is satisfactory. The results of determining the composition of pipe samples are shown in Table 2.
In terms of composition, the material of pipe samples corresponds to steels of type "D" (or KhGSA).
Since some of the pipelines were in a channel in the water, it was possible to estimate the corrosion rate of the outer part of the pipe. The assessment of the corrosion rate was carried out in the places where the canal laying exits, in the ground water in the immediate vicinity of the pipeline, and in the places with the most fast flow groundwater. The groundwater temperature was 40 - 60 ° C.
The measurement results are shown in table. 3-4, where calm water data is highlighted in red.
The measurement results show that the rates of general and localized corrosion increase 
They vary over time, which is most pronounced for localized corrosion in calm water. The rate of general corrosion tends to increase in the current; in calm water, the rates of local corrosion increase.
The data obtained make it possible to determine the corrosion rate of heat supply pipelines and predict their corrosion behavior. The corrosion rate of pipelines in this area is> 0.6 mm / year. The maximum service life of pipelines under these conditions is no more than 5-7 years with periodic repairs in places of local corrosion damage. A more accurate prediction is possible with continuous corrosion monitoring and with the accumulation of statistical data.
Analysisoperationalcorrosive lesionsT
- 1. Basic concepts and indicators of reliability (reliability, reliability, maintainability, durability, etc.). Characteristic.
- 2. The relationship between the quality and reliability of machines and mechanisms. Possibility of an optimal combination of quality and reliability.
- 3. Methods for determining quantitative values of reliability indicators (calculated, experimental, operational, etc.). Types of tests for reliability.
- 4. Ways to improve the reliability of technical objects at the design stage, in the process of production and operation.
- 5. Classification of failures according to the level of their criticality (according to the severity of the consequences). Characteristic.
- 7. The main destructive factors acting on objects during operation. Types of energy that affect the reliability, performance and durability of machines and mechanisms. Characteristic.
- 8. Influence of physical and obsolescence on the limiting state of pipeline transport facilities. Ways to extend the period of good operation of the structure.
- 9. Acceptable and unacceptable types of damage to parts and interfaces.
- 10. Scheme of loss of performance by an object, a system. Characteristics of the limiting state of the object.
- 11. Failures are functional and parametric, potential and actual. Characteristic. Conditions under which failure can be prevented or delayed.
- 13. The main types of structures of complex systems. Features of the analysis of the reliability of complex systems on the example of a main pipeline, a pumping station.
- 14. Methods for calculating the reliability of complex systems for the reliability of individual elements.
- 15. Redundancy as a way to improve the reliability of a complex system. Types of reserves: unloaded, loaded. System redundancy: general and separate.
- 16. The principle of redundancy as a way to improve the reliability of complex systems.
- 17. Reliability indicators: operating time, technical resource and its types, failure, service life and its probabilistic indicators, operability, serviceability.
- 19. Reliability and quality as technical and economic categories. Selection of the optimal level of reliability or resource at the design stage.
- 20. The concept of "failure" and its difference from "damage". Classification of failures by the time of their occurrence (structural, production, operational).
- 22. Division of MT into operational sections. Overpressure protection of pipelines.
- 23. Causes and mechanism of pipeline corrosion. Factors contributing to the development of corrosion of objects.
- 24. Corrosion damage of pipes of main pipelines (mt). Varieties of corrosion damage to pipes mt. The influence of corrosion processes on the change in the properties of metals.
- 25. Protective coatings for pipelines. Requirements for them.
- 26. Electro-chemical. Protection of pipelines against corrosion, its types.
- 27. Fixing pipelines at design elevations as a way to increase their reliability. Methods of bank protection in the sections of underwater crossings.
- 28. Prevention of pipeline floatation. Methods for fixing pipelines at design elevations on water-bearing sections of the route.
- 29. Application of the system of automation and telemechanization of technological processes to ensure reliable and stable operation of mt.
- 30. Characteristics of the technical condition of the linear part of the MT. Hidden defects of pipelines at the time of commissioning and their types.
- 31. Failures of shut-off and control valves mt. Their causes and consequences.
- 32. Failures of mechanical and technological equipment of NPC and their causes. The nature of the failure of the main pumps.
- 33. Analysis of damage to the main electrical equipment of the NPS.
- 34. What determines the bearing capacity and tightness of tanks. Influence of hidden defects, deviations from the design, operating modes on the technical condition and reliability of tanks.
- 35. Application of the system of maintenance and repair (tor) during the operation of MT. Tasks assigned to the system torus. Parameters diagnosed when monitoring the technical condition of mt.
- 36. Diagnostics of MT objects as a condition for ensuring their reliability. Monitoring the condition of pipe walls and fittings using destructive testing methods. Pipeline testing.
- 37. Monitoring the state of pipeline walls by non-destructive testing methods. Diagnostic devices: self-propelled and moved by the flow of the pumped liquid.
- 38. Diagnostics of the stress-strain state of the linear part of the pipeline.
- 39, 40, 41, 42. Diagnostics of the presence of fluid leaks from pipelines. Methods for diagnosing small leaks in MNP and MNP.
- 1. Visual
- 2. Pressure reduction method
- 3. Method of negative shock waves
- 4. Cost comparison method
- 5. Linear balance method
- 6. Radioactive method
- 7. Acoustic emission method
- 8. Laser gas analysis method
- 9. Ultrasonic method (probe)
- 43. Methods for monitoring the state of insulating coatings of pipelines. Factors leading to the destruction of insulating coatings.
- 44. Diagnostics of the technical condition of tanks. Visual control.
- 45. Determination of hidden defects in the metal and welded seams of the tank.
- 46. Control of the corrosion state of tanks.
- 47. Determination of the mechanical properties of metal and welded joints of tanks.
- 48. Control of the geometric shape and settlement of the base of the tank.
- 49. Diagnostics of the technical condition of pumping units.
- 50. Preventive maintenance of MT as a way to improve reliability during its operation. Repair strategies.
- 51. The system of scheduled preventive maintenance (PPR) and its impact on the reliability and durability of MT. Types of that and repair.
- 52. The list of activities included in the PPR system of pipeline systems.
- 53. Disadvantages of the PPR system for operating time and the main directions of its improvement.
- 54. Overhaul of the linear part of the MT, its main stages. Types of overhaul of oil pipelines.
- 55. The sequence and content of work during the repair of the pipeline with the rise and laying it on the bed in the trench.
- 56. Accidents at MT, their classification and organization of emergency response.
- 57. Causes of accidents and types of defects on mt.
- 58. Technology of emergency recovery work of pipelines.
- 59. Methods for sealing pipelines. Requirements for sealing devices.
- 60. The method of sealing the pipeline through the "windows".
The thickness of the sheets of the upper belts, starting from the fourth, is checked along the generatrix along the mine ladder along the height of the belt (bottom, middle, top). The thickness of the lower three belts is checked against four diametrically opposite generatrices. The thickness of the nozzles located on the sheets of the first chord is measured at the bottom, at least at two points.
The thickness of the bottom and roof sheets is measured in two mutually perpendicular directions. The number of measurements on each sheet should be at least two. In places where there is a corrosive destruction of the roofing sheets, holes of 500x500 mm are cut out and measurements of the sections of the elements of the supporting structures are made. The thickness of the pontoon and floating roof sheets is measured on the carpet, as well as on the outer, inner and radial stiffeners.
The measurement results are averaged. When the sheet thickness changes at several points, the arithmetic mean value is taken as the actual value. Measurements that give a result that differs from the arithmetic mean by more than 10% downward are indicated additionally. When measuring the thickness of several sheets within one belt or any other element of the tank, the actual thickness is taken to be the minimum measured thickness of an individual sheet.
The measurement results are compared with the maximum permissible thicknesses of the wall, roof, supporting structures, pontoons.
The maximum permissible wear of the sheets of the roof and bottom of the tank should not exceed 50%, and of the colors of the bottom - 30% of the design value. For load-bearing structures of the covering (trusses, beams), wear should not exceed 30% of the design value, and for pontoon sheets (floating roof) - 50% in the central part and 30% for boxes.
47. Determination of the mechanical properties of metal and welded joints of tanks.
To determine the actual bearing capacity and suitability of the tank for further operation, it is very important to know the mechanical properties of the base metal and welded joints.
Mechanical tests are carried out when there is no data on the initial mechanical properties aх of the base metal and welded joints, with significant corrosion, with the appearance of cracks, as well as in all other cases when there is a suspicion of deterioration of mechanical properties, fatigue under the action of alternating and alternating loads, overheating, excessively high loads.
Mechanical tests of the base metal are performed in accordance with the requirements of GOST 1497-73 and GOST 9454-78. They include determination of ultimate strength and yield strength, elongation and impact strength. During mechanical tests of welded joints (according to GOST 6996-66), tensile strength, static bending and impact strength tests are performed.
In cases when it is required to determine the reasons for the deterioration of the mechanical properties of metal and welded joints, the appearance of cracks in various elements of the tank, as well as the nature and size of corrosion damage inside the metal, metallographic studies are performed.
For mechanical tests and metallographic studies, the base metal with a diameter of 300 mm is cut out in one of the four lower chords of the tank wall.
In the process of metallographic studies, the phase composition and grain size, the nature of heat treatment, the presence of nonmetallic inclusions and the nature of corrosion destruction (the presence of intercrystalline corrosion) are determined.
If there is no data on the grade of the metal from which it is made in the passport of the tank, they resort to chemical analysis. To determine the chemical composition of the metal, samples cut for mechanical testing are used.
The mechanical properties and chemical composition of the base metal and welded joints must comply with the project guidelines, as well as the requirements of standards and technical specifications.
The assessment of the corrosion state of the pipeline located in the electric field of the PT transmission line is carried out according to the potential difference between the pipe and the ground and the value of the current in the pipeline.
Block diagram of a comprehensive assessment of the technical condition of the LP MG. In the future, the assessment of the corrosion state of the MG LP should become an integral part of the comprehensive assessment of the technical condition of the MG LP.
Scheme of the emergence and distribution of wandering. When assessing the corrosion state of a gas pipeline, it is important to know both average and maximum values difference in potentials.
Corrosion assessment instruments should include sensors, a recording system and associated energy sources. When using magnetic and electromagnetic methods, it is possible to use various magnetizing systems. The scanning problem is solved either by a small number of sensors moving inside the pipe along a helical line, or by a large number of sensors moving translationally along with the magnetizing system and located along the perimeter of the device. In this case, it is most expedient to use a two-ring checkerboard system for the location of sensors to eliminate possible omissions of defects on the pipe. Linealog devices manufactured in the USA consist of three sections connected by hinges. In the first section there are power supplies and sealing cuffs, in the second - an electromagnet with a system of cassettes for sensors, in the third - electronic assemblies and a recording device.They are used for pipeline inspections.
Pitting to assess the corrosion state of the pipeline must be carried out with complete opening of the pipe and the possibility of inspecting its lower generatrix. The length of the opened part of the pipe must be at least three of its diameters.
Effective way assessment of the corrosion state of equipment (at the stages of its design, operation, renovation) is corrosion monitoring - a system for monitoring and predicting the corrosion state of an object in order to obtain timely information about its possible corrosion failures.
Table 6 provides an assessment of the actual corrosion state of hot water supply systems from black pipes in a number of cities. In addition, for comparison, the calculated indices of water saturation at 60 C, data on the content of dissolved oxygen and free carbon dioxide in water, and an assessment of corrosiveness are given.
Distribution of areas of speed of movement of water-gas-oil flow for pipelines of various diameters. Corrosion surveys of casing strings are carried out to assess their corrosion state (both in depth and in the area of the field), to determine the parameters of electrochemical protection, to identify the reasons for leakage of the casing strings during operation and to control the security.
Based on the analysis of the above data on the assessment of the corrosion state and reliability of equipment and TP of the OOGCF, the results of in-line and external flaw detection, full-scale and laboratory corrosion-mechanical tests, metallographic studies of templates and samples, the results of technical diagnostics of structures, as well as taking into account the current regulatory and technical documents (NTD), a method for diagnosing equipment and TP of hydrogen sulfide-containing oil and gas fields was developed.
In our country and abroad, methods and devices are being developed for assessing the corrosion state of a pipeline without opening it. The most promising methods are based on passing a specially equipped device through the pipeline, which fixes the centers of corrosion damage to the pipe wall from the inner and outer sides. The literature provides data on methods for monitoring the state of pipelines. The main focus is on magnetic and electromagnetic methods, with the latter being preferred. Ultrasound and radiographic techniques are briefly described here.
Models that are not described by any mathematical equations and are represented as a set of tabular coefficients or nomograms recommended for assessing the corrosion state of metals.
To assess the state of the coating on the pipeline during operation, it is advisable to use the transient resistance of the insulated pipeline, the parameters characterizing the permeability of the coating material, and the amount of antioxidant (for stabilized compositions) remaining in the coating. To assess the corrosion state of the pipe wall, one should use the data of measurements of corrosion losses of metal under the coating or in the places of its defect, as well as the size and position of corrosion damage on the pipe wall. The second - local corrosion (caverns, pits, spots), single (with a distance between the nearest edges of adjacent lesions more than 15 cm), group (with a distance between the nearest edges of adjacent lesions from 15 to 0 5 cm) and extended (with a distance between the nearest the edges of adjacent lesions are less than 0 5 cm) of the lesion. Single corrosive lesions do not lead to pipeline failures.
To assess the state of the insulation coating on the pipeline during operation, it is necessary to use the values of the transient resistance of the pipeline, the parameters characterizing the permeability of the coating material, and the amount of antioxidant (for stabilized compositions) remaining in the insulation. To assess the corrosion state of the pipe wall, it is necessary to use the data of measurements of corrosion losses of the metal under the coating or in the places of its defect, as well as the size and position of corrosion damage on the pipe wall.
When assessing the corrosion state of the pipeline, the types of corrosion, the degree of corrosion damage to the outer wall of the pipes with a generalized characteristic of the sections are determined, the maximum and average corrosion rate is estimated, and the corrosion state of the section is predicted for 3 - 5 years.
Table 9.12 provides an assessment of the corrosion state of the pipeline with a full set of influencing factors and the corresponding recommendations.
In practice, to quantify the corrosion resistance of metals, you can use any property or characteristic of a metal that significantly and regularly changes during corrosion. So, in water supply systems, an assessment of the corrosion state of pipes can be given by the change in time of the hydraulic resistance of the system or its sections.
To find the possibility of reducing metal losses as a result of corrosion and reducing significant direct and indirect losses from corrosion, it is necessary to assess the corrosion state of apparatus and communications of chemical-technological systems. In this case, it is necessary to assess both the corrosion state of the chemical technological system and predict the possible development of corrosion and the effect of this process on the performance of devices and communications of chemical technological systems.
The measurement procedure is given in section II. The volume and complex of measurements required to assess the corrosion state of a structure are provided for by departmental instructions approved in accordance with the established procedure.
The complexity and originality of the process of corrosion of underground metal and reinforced concrete structures are due to the special conditions of the underground environment, where the atmosphere, biosphere and hydrosphere interact. In this regard, special attention is paid to the development and creation of equipment and systems for assessing the corrosion state of objects located underground. Such an assessment can be made by measuring the time-averaged potential of the metal structure relative to the ground. To determine the average value of the potential, devices have been developed - integrators of stray currents. They are easy to manufacture, do not require special power supplies and are reliable in operation. The use of these devices provides information on the nature of the spatial distribution of anodic, cathodic and alternating zones for choosing a place for connecting electrochemical protection means and integral accounting of the effectiveness of its work. This information can be used both during the design, construction and installation of new equipment, and during operation. It becomes possible to carry out planned measures to ensure high reliability of metal and reinforced concrete structures in conditions of long-term operation.
The assessment of the risk of corrosion of underground steel pipelines caused by the influence of electrified vehicles operating on alternating current should be based on the results of measurements of the potential difference between the pipeline and the environment. The measurement procedure is given in section II. The volume and complex of measurements required to assess the corrosion state of the pipeline are determined by departmental instructions approved in the prescribed manner.
The regime is monitored on the basis of the results of analyzes of water and steam samples, readings of pH-meters of feed and boiler water, periodic determinations of the quantitative and qualitative composition of deposits, as well as an assessment of the state of the metal of the boiler in a corrosive relation. The operational staff especially monitors two main indicators of the regime: the dose of the complex (according to the decrease in the level in the measuring device of the working solution 7, converted to consumption feed water) and the pH of the boiler water in the clean compartment. Cutting of representative samples of pipes of the heating surface, qualitative and quantitative analysis of deposits, assessment of the corrosion state of the metal in comparison with its initial state in the first 1 - 2 years of working off the mode are performed every 5 - 7 thousand hours of operation.
Therefore, there are cases when, due to inaccurate determination of the location of corrosion defects on the surface and inside the pipeline due to reinsurance, an unjustified replacement of the pipeline in significant sections is allowed, which leads to a large cost overrun of public funds. Consequently, a reliable assessment of the corrosion state of pipelines and timely and correct repair of them based on the data obtained are required. For this purpose, in our country, flaw detectors have been developed, designed and are being tested for assessing the corrosion state of pipelines without opening them from a trench.
