When transporting unprepared hydrogen sulfide-containing petroleum gas, the inner surface of gas pipelines is subject to intense corrosion destruction. Basically, corrosion damage occurs along the lower generatrix of pipelines, and the corrosion rate reaches 2-3 mm/year.
The corrosive activity of the transported gas is imparted by liquid condensate, the appearance of which in the crude oil gas pipeline is due to two reasons: the removal of liquid (oil and water) from the separation units and the condensation of gas hydrocarbons and water vapor. Condensation occurs when the gas temperature along the gas pipeline route drops to ground temperature.
Various forms of destruction of gas pipelines caused by hydrogen sulfide and carbon dioxide contained in gas in the presence of moisture can be divided into the following types.
General corrosion is the electrochemical dissolution of metal from the surface in contact with the electrolyte, manifested in the form of cavities, fistulas, a decrease in the thickness of pipe walls with the formation of black corrosion products deposited on the corroding surface (with sufficient high values pH of the electrolyte) or soluble in the electrolyte (at low pH values). All carbon and low alloy pipe steels are susceptible to this type of failure if unprotected. General corrosion can be caused by both hydrogen sulfide and carbon dioxide in the presence of moisture.
Hydrogen sulfide stress corrosion cracking (HSCC) is caused by the penetration of atomic hydrogen into the metal in the presence of H2S, which is released on the metal surface and the process of hydrogen sulfide general corrosion, and causes a decrease in the plastic properties of steel, the initiation and rapid development of individual cracks located in a plane perpendicular to the direction of the acting ones. tensile stresses and leading to rapid destruction of pipes operating under pressure.
This type of destruction is more typical for hardened low-plasticity steels and is practically uncontrollable under the operating conditions of pipelines of considerable length. In this regard, stress cracking is the most dangerous type of failure, which occurred even on gas pipelines built from pipes that had high plastic properties in the original state.
Pipes made of different steels, depending on the chemical composition of the steel, the technology of pipe manufacturing and the technology of welding and installation work during the construction of the facility, have different resistance to hydrogen sulfide stress cracking.
IN recent years emit destruction caused by hydrogen sulfide that occurs in the volume of unstressed metal in the form large quantity small cracks located, as a rule, in planes parallel to the plane of the sheet from which the welded pipe is made, or parallel to the cylindrical surface of the seamless pipe. A series of such small cracks, when connected, can form “steps” or “stairs”. Steps, located at different distances from the surface of the pipe, can form a transverse crack, weakening the cross-section of the pipe and its structural strength. The occurrence of such cracks in unstressed metal is associated with the presence of discontinuities in it that were rolled out during the pipe manufacturing process (sulfide and other non-metallic inclusions, gas pores, etc.). Atomic hydrogen, released during general electrochemical corrosion, recombines into molecular hydrogen and accumulates in discontinuities that have an elongated shape, develops significant local pressure and causes the initiation of cracks at the tips of discontinuities. Crack propagation (growth) can occur along solid segregations in the metal and adjacent discontinuities.
According to the reason causing this type of destruction,
it is called HIR (hydrogen induced cracking), often this type of destruction is accompanied by the formation of blisters on the internal surface of the pipes in contact with the hydrogen sulfide-containing medium. The swelling is caused by the pressure of molecular hydrogen accumulated in the subsurface layer of the metal.
To assess the resistance to hydrogen sulfide cracking of pipes, the most common methods proposed by the US National Association of Corrosion Engineers (NACE) are used: the TM-01-77 method for determining the threshold stress when testing resistance to stress cracking for a given test time and the T-1F- method 20 - when testing resistance to hydrogen-induced cracking of unstressed metal, where the parameters are percentages:
- the length of cracks located in the cross section of the sample in relation to the width of the tested sample;
- thickness of cracks (including “steps”) located in the cross section of the sample in relation to the thickness of the tested sample.
The rate of specific corrosion damage caused by hydrogen sulfide and carbon dioxide corrosion depends on many factors, the joint influence of which is very complex and insufficiently studied.
For corrosion damage inner surface pipelines transporting wet hydrogen sulfide-containing petroleum gas are influenced by: partial pressure of hydrogen sulfide and carbon dioxide, temperature, degree and nature of mineralization of the aqueous phase of the condensate, pH of the aqueous phase of the liquid, gas humidity, environmental pressure, mechanical stress in the metal of the pipes.
It is known that with increasing partial pressure of hydrogen sulfide and carbon dioxide, the rate of general corrosion increases. The cracking of steels under stress and VIR increases with increasing . Therefore, hydrogen sulfide-containing environments can be divided into 3 types:
Humid environments where the partial pressure of carbon dioxide exceeds 2 MPa are considered corrosive, and, conversely, corrosively inactive if it is below 2 × 105 Pa.
VNIIGaz has developed a special table for predicting the process of carbon dioxide corrosion, taking into account the partial pressure of carbon dioxide and temperature.
In the combined presence of hydrogen sulfide and carbon dioxide, the highest corrosion rate is observed with a ratio of H2S: CO2 = 1: 3.
The temperature of working media has a complex effect on various types of corrosion damage. With increasing temperature (in the range possible for gas pipeline conditions) from 273 to 333-353 K, the rate of general corrosion increases. This pattern is explained by the laws of electrochemical kinetics and confirmed by experimental data. However, hydrogen sulfide stress cracking has a maximum intensity in the temperature range from 293 to 313 K. As the temperature increases and decreases from this range, the intensity of hydrogen sulfide cracking decreases.
When the temperature of the transported gas increases above the dew point, its aggressiveness decreases, since this changes the conditions for condensation of the liquid phase from the gas. One of the technological methods to prevent corrosion destruction of gas pipelines has been successfully used - heating the gas and then maintaining its temperature above the dew point during the transportation of gas and liquid liquids.
The degree and nature of mineralization of the aqueous phase of a gas-liquid flow can have a significant impact on both the process of general corrosion and hydrogen sulfide cracking. In most cases, an increase in the degree of mineralization leads to an increase in the rate of general corrosion with its simultaneous localization (ulcerative, pitting corrosion). A significant increase in the rate of corrosion processes can be caused by the presence of organic acids (acetic, formic, propionic) in the water coming from the formation, which is more typical for environments in gas field equipment.
The presence of chlorine ions, which cause corrosion cracking of alloy steels, is especially dangerous. However, sometimes a reverse effect of mineralization on the rate of general corrosion is possible, when corrosion slows down due to the formation on the corroding surface of a dense, weakly permeable layer of corrosion products insoluble in the working medium, for example, the formation of a film of carbonates at a sufficiently high pH of the aqueous phase.
The aqueous phase of the condensate is a slightly mineralized electrolyte containing 50-300 mg/l of salts. Such an environment, in the presence of hydrogen sulfide, carbon dioxide and oxygen, is characterized by high corrosive aggressiveness, and the corrosion process occurs with mixed hydrogen-oxygen depolarization.
The hydrocarbon phase consists of light gas gasoline with a density of 0.6-0.7 kg/m3 containing oil. This phase enhances the corrosion destruction of steel, especially in the presence of hydrogen sulfide. It should be noted that the hydrocarbon phase significantly affects the desorption of film-forming oil-soluble corrosion inhibitors, significantly reducing the effect of their consequences.
The pH value of the aqueous phase of the flow has a great influence on the rate of general corrosion and has a decisive influence on hydrogen sulfide cracking of pipe steels. As pH decreases below the neutral level (pH-7 is considered neutral), the intensity of all types of corrosion damage increases.
Gas humidity determines the possibility of electrochemical corrosion processes. When the relative humidity of the gas is below 60%, an electrolyte film does not form on the surface of the pipes, which can ensure the occurrence of significant corrosion processes.
When the relative humidity of the gas is more than 60%, moisture sorption from the gas is possible, sufficient to form an electrolyte film on the surface of the pipes.
The humidity of the transported gas has a significant impact on the corrosion destruction of gas pipelines. According to V.V. Scorcelletti, to begin the corrosion process and the penetration of hydrogen into the metal, it is sufficient to form a layer of water 20-30 molecules thick on the surface of the corroding metal. It should be noted that in thin electrolyte films the corrosion process occurs with more high speed than in the volume of the medium, due to the intensification of the process of diffusion of depolarizers of the corrosion process to the metal surface.
The pressure of the medium influences in two ways: as a factor that determines the partial pressure of aggressive components (H2S, CO2) at a certain content in the gas, and as a factor that determines the tensile stress at certain pipeline sizes (diameter, wall thickness). With a constant CO2 content in the gas and a certain pipeline size, an increase in pressure in the pipeline means an increase in the partial pressures of these components and an increase in tensile stresses in the pipe metal, which leads to an increase in the rate of general corrosion and the intensity of hydrogen sulfide cracking. At certain constant partial pressures of H2S and CO2 and specific stress in the pipe metal, an increase in the total gas pressure has virtually no effect on the rate of general corrosion and hydrogen sulfide cracking.
Mechanical stresses in pipe metal are the determining factors in the occurrence and development of hydrogen sulfide cracking. As tensile stress increases, the possibility of hydrogen sulfide cracking increases. At tensile stresses reaching or exceeding the yield strength of the metal, all carbon and low-alloy steels are susceptible to rapid hydrogen sulfide cracking. The intensity of general corrosion also increases with increasing stress due to mechanochemical corrosion. Particularly dangerous is the effect of cyclic stresses, which cause corrosion fatigue of steel. The cyclicity of stress occurs due to fluctuations in gas pressure and temperature, as well as due to seasonal soil movements. The chemical composition of steel determines the possibility of producing metal with a given structure, mechanical properties, weldability and corrosion resistance using a certain technology for steel smelting and pipe manufacturing. Pipes used for main gas pipelines and gas collection networks are made of carbon or low-alloy steels, often with the introduction of special microadditive elements (niobium, vanadium, etc.) that improve the structure and mechanical properties. Such alloying has little effect on the resistance of steels to general corrosion, which can be significantly slowed down only by introducing in large quantities alloying elements such as chromium, nickel, etc. However, the resistance of steels to hydrogen sulfide cracking depends on the chemical composition of carbon and low-alloy steels and on technology pipe manufacturing.
The influence of each individual alloying element with different contents on the resistance of steel to cracking is complex and ambiguous, depending on the general chemical composition of the steel and the subsequent pipe manufacturing technology. In general, it is advisable to have a chemical composition that ensures that during the manufacture of pipes a fine-grained equilibrium is obtained (with minimal internal stresses) structure and required mechanical properties. There is clearly a negative impact on the resistance of steels to cracking by sulfur and phosphorus, the content of which is sought to be reduced as much as possible.
Alloying pipe steels with a small amount of molybdenum, limiting the content of carbon and manganese, as well as adding copper to reduce hydrogen absorption have a positive effect on resistance to hydrogen sulfide cracking.
The mechanical properties of pipe metal largely determine resistance to cracking. The higher ductility of steel and low hardness are usually combined with increased resistance to hydrogen sulfide cracking. As the hardness and strength class of steel increases, as a rule, it becomes more difficult to ensure resistance to cracking.
Internal stresses in steels, formed during rapid cooling after hot rolling, welding, and cold deformation, increase their susceptibility to hydrogen sulfide cracking.
The structure of the metal, depending on the chemical composition of the steel, the manufacturing technology of pipes and products, in combination with the chemical composition of the mixture, is the determining factor in the resistance to cracking; the nonequilibrium martensitic structure with high internal stresses resulting from hardening. The most resistant to cracking at a sufficiently high strength is the fine-grained structure obtained by hardening followed by high tempering and which is tempered martensite.
The structures of carbon and low-alloy pipe steels can be ranked in order of increasing resistance to hydrogen sulfide cracking (with the same chemical composition): untempered martensite; untempered bainite; ferrite-pearlite normalized; ferrite-pearlite normalized and tempered; tempered martensitic and bainite.
It should be noted that tempering should be carried out at a temperature slightly below the temperature of phase transformations. With a further decrease in the tempering temperature, the resistance of steel to hydrogen sulfide cracking decreases with a simultaneous increase in strength and hardness.
Moist hydrogen sulfide-containing petroleum gas transported through gas pipelines stimulates the occurrence and development of local corrosion due to the functioning of the microgalvanic couple iron sulfide (cathode) - iron (anode). Iron sulfide films are easily permeable to water molecules and chlorine ions, which leads to local corrosion at a significant rate.
To study local corrosion of the inner surface of gas pipelines, it is important to study the kinetics of the formation and destruction of iron sulfide films, as well as the structure of sulfide films and the changes occurring in them, depending on the composition of the medium and the conditions under which the corrosion process occurs.
Below are the results of a study of the structure of the sulfide film formed during the corrosion of iron-Armco and St.Z steel in a 3% solution of sodium chloride containing hydrogen sulfide in the concentration range of 0-1800 mg/l. For X-ray structural studies, a DRON-1.5 X-ray diffractometer was used. X-ray microanalysis was carried out on a Cameka MS-4 device, as well as on an EMR-100 electron diffraction system.
Analysis of diffraction patterns showed that, over the entire range of hydrogen sulfide concentrations, iron sulfide films are a two-phase mixture of mackinawite and kansite. In the initial stages, mackinawite is formed. Measurements of the growth of sulfide films in a corrosive environment showed that in the first hours the growth rate of iron sulfide films is high, then it decreases and is strictly linear. The obtained kinetic dependence indicates different protective properties of the films formed in the system under study, which is typical for the loose structure of the sediment. This, in turn, indicates an increased tendency of steel under these conditions to intense corrosion destruction.
It was noted that the layer of iron sulfide adjacent to the metal surface is different high density. Subsequent layers of iron sulfide, having a defective structure, facilitate the penetration of aggressive components of the environment with subsequent peeling of the iron sulfide film from metal surface, which leads to stimulation of local corrosion processes.
With increasing mineralization of the aquatic environment, the permeability of the sulfide film increases.
On Armco iron, the sulfide film formed unevenly - in certain areas of the coarse-grained structure of the metal, its growth became more intense than in others. The peeling of the film in the washing solution was also uneven, which indicates different adhesion to the metal surface with different crystallographic orientation of the grains. This can, in turn, lead to the localization of corrosion damage.
During the oxidation of iron sulfide films, the formation of two compounds was discovered - Fe3O4 and γ-F2O3H2O. The results of electron diffraction studies indicate that wet sulfide is immediately oxidized in a thin surface layer. In the absence of moisture, this process proceeds very slowly; practically no decrease in sulfide content was observed after 10 days. However, in the presence of moisture, the destruction of the sulfide film as a result of oxidation occurs quickly. With an excess of oxygen (in water vapor), it practically ends in 2 days. When oxidized in distilled water, the sulfide content decreases exponentially. The process ends after 18-20 days at the same initial film thickness. These data are correlated with the results of changes in the content of iron oxides during the oxidation process on the surface of the samples. X-ray microanalysis revealed the presence of elemental sulfur in the partially oxidized surface film of sulfides.
The influence of iron sulfides on the rate of local corrosion was assessed using the following method. An iron sulfide film was formed in a glass cell on an electrode made of steel grade St.3 in artificial formation water containing hydrogen sulfide. Then an electrode with a freshly cleaned surface was placed into the cell, the working surface of which was 10 times smaller than the area of the electrode coated with the sulfide film. Both electrodes were short-circuited, creating a model of an iron-iron sulfide microgalvanic couple. The duration of the experiment depended on the time of establishing a constant electrode potential. Based on the mass loss of the electrodes, the corrosion rates of clean and sulfidized electrodes were calculated and the corrosion enhancement factor γ on a clean surface was determined as the ratio of these rates.
Experiments have shown that, depending on the experimental conditions, the corrosion rate of an electrode with a clean surface increases by 5-20 times, and maximum values coefficient γ are observed when a galvanic couple operates in an environment containing oxygen.
Thus, in the mineralized aqueous phase of liquid condensate, a sulfide film with increased permeability to a corrosive environment is formed on the steel surface, which contributes to the localization of the corrosion process as a result of the operation of steel-steel galvanic couples with a sulfide film. When the sulfide film breaks down and then separates from the metal surface, the metal surface is exposed. Intense pitting occurs in the bare areas - the anodes. Exposure of the metal surface of gas pipelines transporting hydrogen sulfide-containing crude oil gas is possible due to exposure to corrosion products and sand, which have high abrasive activity.
To clarify the mechanism of local corrosion and subsequent development of effective technology for anti-corrosion protection of gas pipelines, it is important to know the distribution of corrosion currents across the cross-section of the pipe.
Let's consider a model of a gas pipeline partially filled with an electrically conductive medium - liquid condensate. Let us assume that on the inner surface of the pipe a galvanic heterogeneity has arisen due to the abrasive action of solid particles - the anode in the form of a scratch.
The groove nature of corrosion in a pipeline allows us to limit ourselves when choosing a design scheme to two coordinate axes, i.e. consider the problem flat.
The mathematical formulation of problems for calculating electric fields in electrolytes, which makes it possible to solve problems of electrochemical heterogeneity, is considered in the works of V.M. Ivanova.
In this case, the task of finding corrosion currents distributed over the cross-section of the pipeline is posed as an edge problem on the plane:
on the surface S = it is required to find solutions to the Laplace equation
, r Є S under nonlinear boundary conditions of the third kind on the pipe surface
(U – R1(p)γ ) / (S1 + S3) = φ1,
(U – R2(p)γ ) / S2 = φ2,
Where U - potential of the medium at the point under study; R- linear approximation of polarization resistance, with R1 - at the cathode, R2 - at the anode; γ - surface conductivity of the corrosive environment; φ1 - electrode potential of the pipe body; φ2 - electrode potential of galvanic heterogeneity; n- outer normal to the surface.
IN general case We will assume that the stationary potential is distributed arbitrarily over the surface of the anode and cathode. This can determine the heterogeneity of the metal structure and take into account the influence of reaction products.
Using the method of integral equations, we will look for a solution using the concept of the potential of a simple layer and the theorem on the jump of the normal derivative of the potential of a simple layer, which makes it possible to construct a solution in the form of a system of integral equations. The system is solved using numerical methods.
To calculate the distribution of current density along the inner surface of a pipeline partially filled with electrolyte, a program was developed, implemented on an EC series computer.
Since the nonlinearity of the polarization characteristics of the corrosion pair is taken into account, any real polarization characteristics can be entered into the computer program.
As a result of the program, many distributions of current densities were obtained depending on the anode share, which makes it possible to trace the development of the corrosion process.
In the range of hydrogen sulfide concentrations of 0-300 mg/l, the local electrode potentials of steel with and under the sulfide film were determined using a capillary microelectrode. The dependence Δφ - in the specified concentration range (H2S) is extreme with a maximum at a hydrogen sulfide concentration of 30-100 mg/l.
Taking into account the dependence of Δφ on the H2S concentration, according to the developed program, a graphical dependence of the corrosion rate, represented by the anodic current density (iв) on the anode fraction, was obtained (Fig. 4).
Rice. 4. Dependence of the anodic current density on the anode fraction in the corrosion pair η.
Based on the calculated values of the anodic current, a graph was drawn up of the dependence of the rate of the corrosion process on the concentration of hydrogen sulfide (Fig. 5).
Thus, an algorithm has been developed and tested for calculating corrosion currents associated with the functioning of a galvanic couple inside a gas pipeline transporting untreated hydrogen sulfide-containing petroleum gas.
Rice. 5. Dependence of corrosion rate on H2S content
Taking into account specific operating conditions (different nature of pipe metal, different aggressiveness of the environment, operating modes, etc.) can be carried out directly through their influence on the course of polarization curves, from which the quantitative relationship of electrochemical parameters (corrosion potential and current strength) is determined.
During the transport of wet gas, there are two main flow regimes: dispersed annular and stratified. In the case of a dispersed annular flow regime, only the outer layer of flow is significant for the mathematical model of the corrosion process, since the corrosion is uniform.
Mathematically, this problem is a boundary value problem of the third kind. It is assumed that there are several damaged and corroded areas on the inner surface of the pipeline. The state of the selected areas is taken into account through polarization curves. When solving this problem, the differential-difference method is effective, allowing one to obtain numerical calculations of the current density distribution with a high degree of accuracy. For calculations, a computer program ES-1022 is compiled.
In the stratified flow regime of the gas-liquid mixture, a local type of corrosion is observed, mainly along the lower generatrix. In this case, the problem becomes mathematically much more complicated, since the electrical conductivity of the medium is a function, more precisely, a piecewise constant function σ(r,z) = σ(r). The task of elucidating the mechanism of local corrosion comes down to calculating the strength of corrosion currents along the cross section of the pipe.
Polarization characteristics are not linear p=p(t, v), Where t- time; v- flow speed.
Electrochemical potential φ = φ(t, v). These dependencies are established experimentally in the form of tabular functions.
Computer calculations showed a significant increase in the rate of the corrosion process in the stratified flow regime of gas-liquid mixtures.
The electrochemical heterogeneity of the metal along the axis of the pipeline in the zone of the ring welded joint was not considered above. However, due to the continuing increase in oil water cut and the increase in the length of field pipelines, the requirements for the quality and reliability of pipelines are becoming more stringent, in particular, for the most vulnerable link of the pipeline system - butt welded joints, in terms of resistance to operational loads.
The heterogeneity of the physical and mechanical state of the metal in different zones of the welded joint under the combined influence of a corrosive environment and regular or random mechanical loads during operation is manifested in increased electrochemical heterogeneity, which leads to a change in the nature of corrosion and the emergence of local zones of destruction.
Kamil Razetdinovich Nizamov, Rustam Rasimovich Musin
Annotation
Introduction The most noticeable complications during oil production in the oil fields of Western Siberia are sand removal, metal corrosion and scale deposits. The percentage of underground equipment failures for these reasons reaches 60% of all failures. Therefore, the development of scientifically based mechanisms of these processes allows the use of effective measures to combat complications. Goals and objectives Based on studying the influence of the composition of the produced fluid on the processes of corrosion and scaling and the laws of chemical kinetics, propose an explanation for the local destruction of equipment under the conditions of carbonate scaling characteristic of operation oil fields Western Siberia. Methods Analytical research and the study of scientific and technical literature and comparison of their results with generalizations of geological and field information on oil fields of Western Siberia. Results The relationship between the processes of salt deposition of Ca carbonates has been established
2+ and Fe
2+ and corrosion of steel in environments containing CO
2, traces H
2S and (or) sulfate-reducing bacteria, sediment-forming Ca ions
2+ and NSO
-
3. Regeneration H
2S when exposed to carbonic acid on iron sulfide precipitates allows maintaining effective action cathode deposit Fe
xS
y at initially low concentrations of H
2S. Conclusion The substantiation of the mechanism of electrochemical corrosion of metal in water and water-oil environments of fields in Western Siberia allows us to recommend the use of the most effective methods for preventing complications associated with local destruction of equipment and salt deposition of carbonates.
Keywords
electrochemical corrosion; cathodic and anodic zones; electrolyte; alkalization and acidification; dissociation constant; solubility product; heterogeneity of the metal and electrolyte surface; carbonate and sulfide deposits; crack resistance; residual life; embrittlement; durability; endurance limit;strain hardening coefficient; amplitude of plastic deformation;
Literature
Arzhanov F.G., Vakhitov G.G., Evchenko S.V. and others. Development and operation of oil fields in Western Siberia. M.: Nedra, 1979. 335 p.
Markin A.N., Podkopai A.Yu., Nizamov R.E. Corrosion damage to pump and compressor pipes in the fields of Western Siberia // Oil industry. 1995. No. 5. P. 30-33.
Markin A.N., Nizamov R.E. CO2 - corrosion of oilfield equipment. M.: OJSC “VNIIOENG”, 2003. 188 p.
Nizamov K.R. Increasing the operational reliability of oil field pipelines: dissertation. ... Dr. Tech. Sci. Ufa: BashNIPIneft, 2001. 300 p.
Zavyalov V.V. Problems of operational reliability of pipelines in late stage field development. M.: OJSC “VNIIOENG”, 2005. 332 p.
Markin A.N., Nizamov R.E., Sukhoverkhov S.V. Oilfield chemistry: a practical guide. Vladivostok: Dalnauka, 2011. 288 p.
Murzagildin Z.G. Development and improvement of methods for reducing the accident rate of oil-gathering pipeline systems: abstract of thesis. ...cand. tech. Sci. Ufa: UNI, 1989. 23 p.
Zhuk N.P. Course on the theory of corrosion and protection of metals. M.: Metallurgy, 1976. 472 p.
Rosenfeld I.L. Corrosion inhibitors. M.: Publishing house "Chemistry", 1977. 352 p.
Gonik A.A. Hydrogen sulfide corrosion and measures to prevent it. M.: Nedra, 1966. 176 p.
Lurie Yu.Yu. Handbook of Analytical Chemistry. M.: Khimiya, 1972. 228 p.
DOI: http://dx.doi.org/10.17122/ntj-oil-2014-3-96-102
Links
- There are currently no links.
(c) 2014 SCIENTIFIC AND TECHNICAL JOURNAL “PROBLEMS OF COLLECTION, PREPARATION AND TRANSPORTATION OF OIL AND PETROLEUM PRODUCTS”
The main reasons for the reduction in service life of almost all types of oil refining equipment are corrosion damage and their erosion-mechanical wear.
In the oil and gas industry, corrosion is a huge problem, just like in any other industry.
The wide range of environmental conditions inherent in the oil and gas industry makes it necessary to prudently and economically effective selection materials and measures to combat corrosion. Equipment failures caused by corrosion account for 25% of all accidents in the oil and gas industry. More than half of them are associated with sweet (CO 2) and acidic (H 2 S) working fluids.
The presence of sulfur dioxide and hydrogen sulfide in produced fluids and oxygen in injected seawater are the main sources of corrosion in the oil and gas industry.
Carbon dioxide corrosion
This type of corrosion is the most common in wet production. It is the cause of more than 60% of accidents. Carbon dioxide (CO2) injection is one of the emissions that cannot be extracted using conventional (primary or secondary) technologies. CO 2 is present in the resulting liquid.
Although it does not in itself cause catastrophic situations like hydrogen sulfide, carbon dioxide can lead to very rapid localized corrosion (mesocorrosion).
Dry CO 2 gas itself is not corrosive at the temperatures prevailing in the oil and gas industry, but must be dissolved in the aqueous phase. Only in this way can it promote the electrochemical reaction between the water phase and the steel. Carbon dioxide is highly soluble in water and saline solutions. However, it should be borne in mind that it has even better solubility in carbohydrates - usually in a 3:1 ratio. When CO2 dissolves in water, it forms carbonic acid, which is weak compared to other inorganic acids and does not completely dissociate:
What does oil consist of?
CO2 + H2O = H + HCO3 = H2CO3
Corrosion by sour oil
represents a more serious problem associated with the oil and gas industry. If in case of carbon dioxide corrosion we're talking about If there is a slow, localized loss of metal, then sour oil corrosion can lead to crack formation. These damages are difficult to notice on early stage and begin to closely monitor them, and therefore they can lead to a catastrophic and - quite possibly - dangerous accident. Thus, the primary goal is to identify the risk at the design stage and select materials that are not prone to cracking, rather than controlling the situation with corrosion inhibitors.
Oxygen corrosion in seawater
A common type of corrosion that mainly affects areas of high turbulence, high velocities, crevices and damaged areas. Carbon steel has been successfully used in water injection systems as long as the water quality is maintained at a certain level.
But these systems can also experience severe corrosion, requiring frequent and often unexpected repairs. The damage caused largely depends on the concentration of oxygen and chlorine in the water and the flow rate. At the same time, oxygen dissolved in the water passing through the system undoubtedly causes more damage than all other factors.
Carbon and low-alloy steels continue to be used in the oil and gas industry to construct transportation equipment such as pipelines. This occurs due to their versatility, availability, mechanical properties and cost. However, the ability of these steels to resist corrosion when in contact with petroleum products and sea water is insufficient and is one of the main sources of problems.
By the way, read this article too: Oil extraction methods
Carbon steel, however, due to its low initial capital costs, is still the material of choice for long, large diameter export pipelines.
Despite its relatively high price, the 13% chromium alloy has become the standard material used for downhole equipment to avoid carbon dioxide corrosion problems. In addition, corrosion-resistant alloys have become an important material for processing equipment, especially in offshore applications. An intermediate option between resistant alloys and carbon steel combined with corrosion inhibitors is carbon steel coated with a thin layer of corrosion resistant alloy. This technique is often used in areas with high fluid velocity, such as forks and bends.
Corrosion can cause serious damage, production hazards, loss of production, and pose a safety hazard.
YOU MAY BE INTERESTED IN:
Abstract of the dissertation on the topic "Carbon dioxide corrosion and inhibitor protection of gas and oil gathering pipelines complicated by the formation of salt deposits"
ALL-RUSSIAN RESEARCH INSTITUTE OF NATURAL GASES AND GAS TECHNOLOGIES (ZNSH5GAZ)
As a manuscript
MARKIN ANDREY NIKOLAEVICH
UDC 620.197.3
CARBON ACID CORROSION AND INHIBITOR PROTECTION OF GAS AND OIL FACTORY PIPELINES
COMPLICATED BY FORMATION OF SALT DEPOSITS
Specialty 05.17.14- - Chemical resistance
dissertation for the degree of candidate of technical sciences
Moscow - 1992
ALL-RUSSIAN RESEARCH INSTITUTE OF NATURAL GASES AND GAS TECHNOLOGIES (VNIIGAZ)
As a manuscript
MARKIN ANDREY NIKOLAEVICH
UDC 620.197.3
UGC-ACID CORROSION AND INHIBITORY PROTECTION OF GAS AND FLUID COLLECTION PIPELINES COMPLICATED BY THE FORMATION OF SALT SEDIMENTS
Specialty 05.17.14 - Chemical resistance
dissertations and competition for the scientific degree of candidate of technical sciences
Moscow - 1992
The work was carried out at the Nizhnevartovsk Research Institute-CKQU and Design Institute of the Oil Industry (NizhnevartovskNIPIneft).
Scientific supervisor - Ph.D., senior researcher Legezin N.K.
Official opponents - D.G.V., Prof., Saakiyav L.S.
Ph.D. Mikheychik A.P.
Leading organization - VNSHSSHBeft, Ufa
The dissertation defense will take place on 7 1992.
at 13:30 at a meeting of the specialized council K 070.01.01 for the award of the scientific degree of Candidate of Sciences at the All-Russian Research Institute natural gases and gas technologies at the address: 142717, Moscow region, Leninsky district, pos. Fork, VNIIGAZ.
The dissertation can be found in the VNIIGAZ library.
Scientific secretary of the specialized council, l
Ph.D. N.N. Kislenko
GENERAL CHARACTERISTICS OF WORK
Relevance of the problem.
The development of the oil industry, the development of new fields, the products of which contain such aggressive components as carbon dioxide and mineralized water, increases the requirements for the reliability of pipelines and equipment, which, under these conditions, are subject to intense corrosion. Along with the development of new fields, production occurs resource of exposed oil and gas pipelines, which also increases the requirements for their reliability. For these reasons, there is a constant increase in the use of corrosion inhibitors in the oil industry. For example, in the Nizhnevartovskneftegaz production association, inhibitors were used: in 1989 - 7920 g, in 1990 - 8403 g, l 1991 - I0I24 tons.
Therefore, increasing the efficiency and inhibition of gas-oil gathering pipelines is an important national economic task. For Western Siberia, where carbon dioxide corrosion is complicated by the formation of precipitation of iron and calcium salts, the goal is achieved by scientifically based selection of the most effective corrosion inhibitors under given conditions and improvement of technologies for their use, which can only be done by first solving a number of theoretical, methodological and technological problems. In this regard, the study of carbon dioxide corrosion under conditions of the formation of salt deposits seems to be an urgent task.
Purpose of the work.
Study of carbon dioxide corrosion of steel and its inhibition during the formation of salt deposits and development of recommendations for inhibitor protection of gas and oil collection pipelines under these conditions.
Main research objectives.
1. Study of the characteristics of carbon dioxide corrosion of pipe steel under conditions of the formation of salt deposits on its surface.
2. Magical modeling of the corrosion process
in conditions of formation of salt precipitation in order to predict its
speed and nature of development.
3. Development of a method for assessing the protective effect of corrosion inhibitors.
Study of the behavior of corrosion inhibitors during the formation of salt deposits and development of recommendations for increasing the effectiveness of protection.
Scientific novelty.
1. A dynamic mathematical model of the electrochemical corrosion process has been developed; It has been established that the electrochemical heterogeneity of the surface of a corroding metal, caused by the formation of sediments, can lead to both a decrease in corrosion and the development of corrosion lesions such as pitting and ulcers.
2. For the first time, it was shown that a large spread in the rates of carbon-acid corrosion of steel under constant external factors and the presence of a maximum corrosion rate depending on pH are associated with the formation of an isomorphic phase in the composition of siderite and with the ratio of phases (siderite and a phase isomorphic to its structure) in the resulting draft.
3. It has been established that carbon dioxide corrosion of steel under sedimentation conditions varies widely (+50%) and therefore one cannot use the term “constant corrosion rate”, but should only talk about its most probable values for given external conditions.
For the first time, it was established that the effectiveness of a number of inhibitors cannot be judged only by the protective effect, since the corrosion rate of inhibited steel for them is not related to the corrosion rate in an uninhibited environment. It is proposed to use the term “residual corrosion rate” (RCR) as a parameter that determines the effectiveness of such inhibitors: the values of the corrosion rate of a particular steel in an environment inhibited by a certain concentration of inhibitor.
A new classification of inhibitors has been proposed, taking into account the possibility of using the concepts of protective effect and OSC to assess the effectiveness of their use under conditions of carbon dioxide corrosion complicated by sedimentation.
Practical value of the work and implementation in industry
The developed methodology for laboratory tests of the protective effect of corrosion inhibitors, simulating the physicochemical equilibrium of formation water under carbon dioxide pressure, made it possible to identify the reagents that are most effective in the specific conditions of a given field. As a result, the volume of expensive pilot testing has been significantly reduced.
Based on research conducted in 1987-1990. In a number of oil and gas production departments (OGPD) of the Nikn.evartovsk-neftegaz PA, domestic corrosion inhibitors SNPKH-bOPB and SNPKH-6301 were introduced for comprehensive protection of equipment in production wells and gas and oil collection reservoirs. The implementation of technological processes developed using research results in NGDU Belozerneft alone gave an economic effect of 1.2 million rubles in 1987-1990.
Approbation of work.
The main provisions and results of the dissertation were reported:
At the non-international seminar "Problems of collecting, preparing and mainline transport oil" (Ufa, 1988);
At the All-Union Meeting - Fair "Modern affinities and methods of chemical protection of oil and gas field equipment from corrosion and damage" (Kazan, 1989);
At the industry scientific and technical conference "Problems of corrosion protection of oil and gas production equipment in the fields of Western Siberia" (Tyumen, 1589).
Publications.
Scope and structure of the dissertation.
The dissertation consists of an introduction, five chapters, a conclusion, and a list of references. The work is presented on 176 pages of typewritten text and illustrated with 22 tables and 30 resources. The bibliography contains 136 titles.
The introduction substantiates the relevance of the research, defines the goals of the research, and shows the scientific novelty and practical significance of the work.
In the first chapter, based on published works, an analysis and generalization of the state of work on the study of the mechanism of carbon acid corrosion, the influence of sedimentation on the corrosion process, and methods of anti-corrosion protection in the oil and gas industry are carried out.
The first works on the study of carbon dioxide corrosion were published by the American Gasoline Association in the forties. “However, at that time, carbon dioxide corrosion of oil equipment was not a serious problem both abroad and in the USSR.
In our country, the situation changed dramatically in 1965-1970. with the start of development in the Krasnodar and Stavropol territories of deep gas condensate fields with a reservoir temperature of 80-140 ° C, pressure up to 35 MPa and gas content up to 5%. During this period, the VSHSHGAZ Institute and its branches carried out detailed studies carbon dioxide corrosion in gas condensate systems. Teams of authors led by N.E. Legezina, A.A. Kutova, based on laboratory research and practical data, a classification of gas condensate systems was proposed according to their aggressiveness depending on the temperature and partial pressure of carbon dioxide.
Subsequently, theoretical and experimental studies of carbon dioxide corrosion of oilfield equipment were carried out by A.A. Gonik, A.I. Ovodov, V.P. Kuznetsov, Yu.G. .Rozhdestvensky, L.S. Saakiyan, A.G., Khurshudov, E.P. Mingalev, M.D. Getmansky, as well as foreign scientists Hausler, Burke, Crolet, Bonnet, Smith, Ikeda and others.
With the beginning of the development of oil fields of the Tyumen North, which are characterized by low (0.05-0.10 MPa) partial pressures of COg and weak (up to W g/l) mineralization of the aqueous phase of well production, related to calcium chloride type waters, systems emerged , where carbon dioxide corrosion of oil
equipment is complicated by the formation of salt deposits. There is a low level of knowledge about corrosion processes and corrosion inhibition under these conditions, and the lack of a sufficient range of carbon dioxide corrosion inhibitors.
The targeted selection of carbon dioxide corrosion inhibitors for the oil fields of Western Siberia represents, therefore, a serious task, since the corrosion process in real conditions is always complicated by sedimentation, and, as a consequence, the rate of even uniform corrosion can reach significant values, most often it is uneven in nature , which leads to corrosion rates of 1.5-2.5 gDm^.h).
At the end of the chapter, the main research objectives are formulated.
The second chapter outlines the methodology and algorithm for calculating the physical, physicochemical equilibrium of water under carbon dioxide pressure. The technique allows you to calculate, and based on the calculation model in the laboratory, the ionic composition and pH of the aqueous phase of well production with known initial data - partial pressure of CO2, general content ions Co., Md, Fe, bicarbonate ion, etc., temperature. The technique is based on chemical equilibrium equations between individual ions, which, together with the temperature dependences of the corresponding dissociation constants and solubility products, as well as taking into account the ionic value of the solution, calculated on the basis of average ion activity coefficients, are combined into a nonlinear system of 32 equations. This system is solved numerically using a non-standard algorithm using an ES-1066 computer. An experimental verification of the calculation accuracy was carried out at different temperatures, salinity* and partial pressures of CO^ on model waters in the laboratory.
The indices of water saturation with these carbonates are used as a criterion for the ability of a solution to release sediments of calcium, magnesium and iron carbonates. The index of water saturation with calcium carbonate is called the Langel saturation index (Langelia index). This parameter, as well as its numerous refined codifications, has been successfully used to predict calcium carbonate deposits since 1936. It has been shown that the indices of solution saturation with iron and magnesium carbonates, similar to the Langelier index,
Can! be applied to predict the precipitation of the corresponding salts.
The forecast for precipitation of magnesium carbonate from calcium chloride waters characteristic of the Samotlor deposit is negative. The possibility of using the index of solution saturation with iron carbonate has been confirmed experimentally.
The third chapter describes the results of mathematical modeling of electrochemical corrosion processes during the formation of deposits on a corroding surface. »
A mathematical model of the corrosion process is built on the basis of ideas about microgalvanic (local) elements and electrochemical heterogeneity of the metal surface. Electrochemical heterogeneity is caused by various reasons (structural and chemical heterogeneity of the metal, adsorption, the stressed state of individual areas and mechano-chemical effects, etc.) and manifests itself in the uneven distribution of the rates of electrode reactions over the corroding metal surface. As a result of the occurrence of electrode reactions, the surface charge changes in the area of the metal where these reactions take place. The anodic reaction makes the charge of the site more negative, the cathodic reaction makes it more positive.” A change in charge leads to a change in the electrical double layer, and the electrical layer changed by the double, in turn, affects the intensity of both electrode reactions. In the mathematical model, the change in the charge of a surface area and the resulting change in the rates of electrode reactions are described through the values of the instantaneous potentials of the areas. Sedimentation is modeled by shifting the potentials of metal sections in a positive direction. That is, when a deposit forms on a piece of metal, the anodic reaction slows down and the cathodic reaction intensifies.
To implement the mathematical model, a program was compiled for the ES-1066 computer.
The mathematical model qualitatively reproduces the change in corrosion kinetics depending on external factors: the cleanliness of the surface treatment of the sample, the formation of protective or stimulating deposits; demonstrates that the electrochemical heterogeneity of the surface of a corroding metal, caused by the formation of sediment, io&erg, with intense sedimentation and 8
slowing down the anodic stage leads to the development of corrosion lesions such as pigments, ulcers, cavities. There is numerous evidence of this under conditions of carbon dioxide corrosion.
Based on mathematical modeling, it is shown that at each given moment in time, the distribution of corrosion rates over the surface of a uniformly corroded sample has the following features: the average value is not the most probable, the probability of deviation from the average corrosion rate is high:
sections at any given moment of time corrode at rates significantly lower than the average, and ~20% corrode at rates 3-8 times higher than the average. The type of distribution resembles the Poisson distribution.
Thus, the mathematical model describes the kinetics and a number of characteristic features of corrosion under conditions of sediment formation on the corroding surface.
The next chapter presents the results of studies of the characteristics of carbon dioxide corrosion of carbon steel, complicated by the formation of salt deposits,
Electron microscopic studies of steel samples corroded in real pipelines showed that carbon dioxide corrosion of field equipment at the Samotlor field occurs under conditions of precipitation, mainly of iron and calcium carbonates. The deposition of these salts on a corroding surface was simulated in laboratory experiments.
The following were identified characteristic features carbon dioxide corrosion under sedimentation conditions, which are illustrated in Fig. I:
Significant (+30-50%) spread in corrosion rates under constant external conditions;
The magnitude of the scatter depends little on the concentration of bicarbonate ion in the formation water and decreases with increasing pH;
In a certain pH range, a maximum is observed both in the absolute value of the corrosion rate and in the ae changes;
Average, maximum and minimum corrosion rates
in waters with different concentrations of bicarbonate ion decrease. with increasing pH, and at pH ~ 8.5 they coincide for waters with low (90 mg/l) and high (450 mg/l) HCO3 contents.
Rice. I. Dependence of the corrosion rate of steel 40 on the pH of synthetic water from the Samotlor deposit with the composition g/l: NaCl - 17.00; Cace2- 0.14;- MgCe^- 0.20; UüHtüs- 0.633; (HCO3 = 450 mg/l), t = 50°C. The dots show the corrosion rates in the absence of sedimentation.
In the composition of sediments, the basis of which is siderite, a cubic phase (spinel type) with a structure iso-morphic to the structure of siderite, as well as cementite Rae^C, was discovered. This heger-phase structure, in accordance with previously accepted terminology, is further called corrosion .
The conducted research allows us to draw the following mechanism of carbon dioxide corrosion of steel.
When a metal is immersed in an electrolyte, corrosion begins with hydrogen depolarization, and undissociated carbonic acid plays the role of a buffer supplying H* ions spent on depolarization. The corrosion rate of steel in this case is ~0.6 g/(1G.h) and depends little on the concentration of HCO^ in the solution, since the concentration of undissociated HCO^ is constant at a constant partial pressure of carbon dioxide. As a result of corrosion, the near-electrode layer is enriched with iron ions, due to which conditions for corrosion deposition are achieved. The siderite and the phase isomorphic to its structure, which are part of the corrosion composition, are formed simultaneously and the stimulating or protective properties draft. Siderit, as you know! has protective properties, and an increase in the content of the phase described above in corrosion leads to the fact that it becomes loose, easily permeable, increases the electrochemical heterogeneity of the steel surface and stimulates its corrosion.
With an increase in the concentration of HCO^ in the solution, the formation of both siderite (due to an increase in the concentration of Co| during the dissociation of HCOd) and the second phase formed through intermediate complexes of Fe with HCO^ are facilitated. Therefore, there is a correlation between the concentration of NS LPG and the corrosion rate. On the other hand, with increasing pH, at a constant concentration of HCO^", lower concentrations of Fe in the near-electrode layer are required for the formation of siderite. Consequently, an increase in pH, other things being equal, contributes to the enrichment of corrosion with siderite, which leads to a slowdown in corrosion.
Uneven concentrations of E"- in the near-electrode layer over the metal surface, flow fluctuations, local alkalization of the medium and other uncontrollable factors lead to the fact that sedimentation, both on a separate section of the metal and on the entire metal surface, is largely random in nature . In the sense that, under constant external conditions,
The ratio of phases in corrosion cannot be accurately calculated or predicted. Therefore, during carbon dioxide corrosion of steel under sedimentation conditions, it is impossible to obtain a constant corrosion rate, which varies over a wide range, but we can only talk about its most probable value under given external conditions.
Using mathematical planning of the experiment, it is shown that carbon dioxide corrosion in the deaerated aqueous phases of well production is stimulated by the joint deposition of corrosion and calcium carbonate on the corroding surface.
A decrease in pH reduces the intensity of sedimentation and at high partial pressures of carbon dioxide and low pH, no precipitation is observed.
The presented mechanism makes it possible to explain the characteristic features of carbon dioxide corrosion of steel under conditions of sedimentation by different phase ratios in the resulting sediment.
The fifth chapter presents the results of studies on the inhibition of carbon dioxide corrosion of gas and oil collection pipelines under conditions of the formation of salt deposits.
The previous chapter shows that during carbon dioxide corrosion of steel under conditions of sedimentation of various compounds on the corroding surface, the control corrosion rate varies widely under constant external conditions. Consequently, the small magnitude of the protective effect of inhibitors is often associated with a small control corrosion rate. Similarly, the parameters , obtained from electrochemical measurements and characterizing the inhibited state of the metal, which includes values corresponding to the uninhibited state, are determined with a significant error.
Based on detailed studies of 34 corrosion inhibitors, it was established that for 18 of them the corrosion rate in the inhibited aqueous phase of well production from the Samotlor field is constant at a constant concentration of reagent 1; does not depend on the control corrosion rate. Therefore, it was proposed to characterize the effectiveness of reagents not only by the magnitude of the protective effect, but also by a parameter called “residual corrosion rate” (RCR). OSK.asg rate of corrosion (general, local, pitting, etc.) of a specific metal in a given environment, inhibited
bath with a certain concentration of inhibitor.
Thus, it is OSC, as a characteristic of the metal-environment-inhibitor system (along with the potential for corrosion in an inhibited environment), that is a parameter that allows one to reliably record the inhibition of carbon dioxide corrosion of steel under sedimentation conditions. At the same time, it is important that there are such inhibitors that if the corrosion rate in an uninhibited environment is greater than the TSC of a given reagent, it has a protective effect, and if the control corrosion rate is less than the TSC, then the corrosion rate of the metal in an inhibited environment becomes equal to the TSC.
For four inhibitors (out of 34 studied), it is not the TCR values that are consistent, but the protective effect (for the other 10 inhibitors, additional research). Obviously, for them, the OSC values do not characterize corrosion inhibition. Here you should use the value of the protective effect or the braking coefficient.
From a practical point of view, the difference between the first 18 and the last 4 inhibitors (called type I and type II reagents, respectively) is as follows. Since inhibitors are used in highly aggressive environments, when uniform corrosion rates are 0.5 g/(m^.h) or more, reagents that have a constant protective effect, rather than OSK, do not always allow achieving low corrosion rates in an inhibited environment. Wednesday So, if the protective effect of any inhibitor is 80%, then with a control corrosion rate of 0.5 g/O^.h), the corrosion rate in the inhibited environment will be 0.1 g/(n^.h), and with a control the corrosion rate is 2.0 g/(u^.h), the corrosion rate in an inhibited environment will be 0.4 g/(u^.h). On the contrary, for type I inhibitors the corrosion rate in an inhibited environment is constant and equal to the residual corrosion rate. On the other hand, if the tantrol corrosion rate is low or less than the OSC of the type I reagent, then corrosion will not be inhibited and an increase in the metal corrosion rate in an inhibited environment can be observed. In this case, either reagents with lower OCX values or reagents P p;pz should be used.
In terms of their composition, type II inhibitors differ from type I reagents. There are no nitrogen-containing compounds with long hydrocarbon radicals, 2 of them contain non-molastic amines."
Among organic corrosion inhibitors of complex composition, those have been identified whose adsorption on a “clean” (i.e., without precipitation) steel surface and on a steel surface covered with deposits of salts formed as a result of carbon dioxide corrosion, the stationary potentials (free corrosion potentials) of these surfaces in synthetic water of the Samotlor oil field differ by tens of millivolts. Electrical metal contact between such surfaces leads to the formation of galvanic cells with emf. up to 80 mV, in which the “clean” steel surface can be both a cathode and an anode. In the latter case, instead of inhibiting corrosion, anodic dissolution of steel is possible at rates of 2-8 gDg.h) or more.
MAIN RESEARCH RESULTS AND CONCLUSIONS
1. The features of carbon dioxide corrosion of carbon steel, complicated by the formation of salt deposits, have been studied. X-ray and electron microscopy studies have established that the basis of sediments formed in the near-electrode layer is siderite and a phase of high symmetry isomorphic to its structure. Its stimulating or protective properties depend on the quantitative ratio of these components of the sediment, and the change in the phase ratio is largely random. The consequence is a large variation in steel corrosion rates under constant external conditions.
Carbonic acid corrosion in deaerated calcium chloride waters is stimulated by the joint precipitation of the above compound and calcium carbonate on the corroding surface.
2. A dynamic mathematical model of the electrochemical corrosion process under sedimentation conditions has been developed. The model qualitatively reproduces the change in corrosion kinetics depending on the cleanliness of the surface treatment. Predicts that with the formation of corrosion-stimulating precipitation, a change, within certain limits, in external conditions has little effect on the corrosion process, while under constant external conditions, depending on the type of precipitation, the corrosion rate changes more than 8 times. This is in good agreement with experimental data on the corrosion of carbon steel in synthetic plastic
water of the Samotlor oil field.
The model clearly demonstrates the transition of uniform corrosion to local and pigging with intense sedimentation and slowing down of the anodic stage; allows one to study the instantaneous distribution of corrosion rates over the surface of a uniformly corroded sample.
3. A methodology and algorithm for calculating the physical-chemical equilibrium of the aqueous phase of well production under pressure has been developed
The possibility of using the index of water saturation with iron carbonate to predict the precipitation of FeCO^ has been shown and experimentally confirmed.
The features of inhibition of carbon dioxide corrosion of carbon steel under sedimentation conditions have been studied.
It has been determined that corrosion inhibitors, according to their action, can be divided into two types. For type 1 reagents, the corrosion rate in inhibited formation water, called the “residual corrosion rate,” is constant (at a given reagent concentration) and does not depend on the control corrosion rate. Type I inhibitors show a consistent protective effect.
It has been shown that the choice of inhibitor for specific conditions should be carried out depending on the control corrosion rate, the values of the residual corrosion rate for type II reagents and the magnitude of the protective effect for P type reagents.
5 “Organic corrosion inhibitors have been identified that protect a relatively clean steel surface less than one covered with salt deposits formed as a result of carbon dioxide corrosion. The potentials of free corrosion of such surfaces in the inhibited aqueous phase of production from wells of the Samotlor oil field differ by tens of millivolts, and the electrical contact between them creates galvanic couples in which pure user material can be an anode, the local speed of solutions of which reaches 2-8 g/Og .ch).
Based on the proposed classification of reagents, which takes into account the concepts of protective effect and residual corrosion rate, 1 research conducted, the most effective corrosion inhibitors under sedimentation conditions were selected. Technologies for their use have been developed and implemented, reducing the accident rate of oil and gas-1rosodoz by 2.5-6.6 times. The proposed method for calculating the physical equilibrium of the aqueous phase of well production under pressure
NIAM COg made it possible to develop and implement a technology for comprehensive protection of field equipment at the Samotlor field from salt deposits and corrosion.
1. Khurshudov A.G., Markin A.N., Sivokon I.S. Efficiency of inhibition of carbon dioxide corrosion under conditions of formation of secondary deposits. //Oil industry. Ser.: Corrosion control and protection environment. Z.I. Domestic experience.
M.: VNIIOENG^ 1988. Issue. 2. - pp. 1-4.
2. Markin A.N., Sivokon Y.S., Khurnudov A.G. Mathematical modeling of electrochemical corrosion processes.
M.: 1988. - Add. in VNIIOENG, 08/24/88, "1628-kg. - 12 s.
3. Sivokon I.O., Markin A.N., Markina T.T. Methodology
and an algorithm for calculating the physical and chemical equilibrium of formation waters of the Samotlor field, - M.: 1988. - Add. in VNIIOENG, 09/30/88, No. 1634-ng. - 14 s.
4. Khurshudov A.G., Markin A.N., Vaver V.I., hSiokon I.O. Modeling of processes of uniform carbon dioxide corrosion in relation to the conditions of the Samotlor deposit, // Protection of metals. - M. 1988. T. 24. 1st 6. - C" 1014-1017.
5„Markin A.N., Sivokon I.O. Methodology for calculating the physicochemical equilibrium of the oil-gas-water system and predicting salt deposition. //Tatar Board of VHO named after. DI. Mendeleev. NPO "Soyuzneftapromkhim" Modern affinities and methods of chemical protection of oilfield equipment and from corrosion and biodamage. Abstracts of reports. - Kazan. 1989. - pp. 38-39.
6. Khurshudov A.G., Sivokon I.S., Markin A.N. Prediction of carbon dioxide corrosion of oil and gas pipelines. //Oil industry. 1989. - to II. - P. 59-61.
7. Markin A.N., Gutman E.M., Sivokon I.S., Ermakova L.P. Low-amplitude cyclic amparometry of corrosion inhibitors. //Protection of metals. - M. 1991. T. 27. No. 3. - P. 368-372.
8. Gutman E.M., Markin A.N., Sivokon I.S. and others. On the choice of parameters characterizing the inhibition of carbon dioxide corrosion of steel under conditions of salt deposition. //Protection of metals. - M, 1991. T. 27.)y 5. - P. 767-774.
9. RD 39P-0I484-63-0008-89. Instructions for the technology of complex protection of oilfield equipment from oil deposits and corrosion. Kurolesov V.I., Lvov P.G.^ Bannykh D.V. and others. PA "Sovznefteproikhim". - NizhnevartovskShShnefg. - 1989.
Yu. A.W. MarKia, I. S, SivoKon., and A. Q. Khmrshadov HatKemtL-lical Sifliutation o( Corrosion.- EieetirocKemica.fi Proeessea.// CORROSION - Vot. No. 9 -1991.-PP. 659-66A.
Applicant i&A^. A.H. Markin
Order No. 78 Signed for printing May 1992,
"Irage - 100 copies. F-g: 84x108/32. Volume: I edition sheet
Printed on VNIIGAZ rotaprint at the address: 142717, Moskovskaya zblasg, Leninsky district, pos. Fork, VNIIGAZ.
Currently, 350 thousand km of field pipelines are operated in Russia. Every year, about 50-70 thousand failures occur in oil field pipelines. 90% of failures are the result of corrosion damage. Of the total number of accidents, 50-55% occur in oil collection systems and 30-35% in communications for maintaining reservoir pressure. 42% of pipes do not withstand five years of operation, and 17% do not even withstand two years. The annual replacement of oil field networks requires 7-8 thousand km of pipes or 400-500 thousand tons of steel.
What is the reason and what is the mechanism of the process of internal corrosion of pipelines transporting oil and water?
1. THEORETICAL FOUNDATIONS OF THE PROCESS OF ELECTROCHEMICAL CORROSION OF METALS
Corrosion is the destruction of metals as a result of chemical or electrochemical exposure to the environment; it is a redox heterogeneous process occurring at the interface.
Although the corrosion mechanism is different under different conditions, the type of destruction of the metal surface is divided into:
1. Uniform or general corrosion, i.e. evenly distributed over the metal surface. Example: rusting of iron, tarnishing of silver.
2. Local or localized corrosion, e.g. concentrated on individual areas of the surface. Local corrosion occurs various types:
· In the form of spots - the lesion spreads relatively shallowly and occupies relatively large areas of the surface;
· In the form of ulcers - deep lesions are localized on small areas of the surface;
· In the form of dots (pitting) - the dimensions are even smaller than ulcerative corrosion.
3. Intercrystalline corrosion - characterized by the destruction of metal along the boundaries of crystallites (metal grains). The process occurs quickly, deeply and causes catastrophic destruction.
4. Selective corrosion - selectively dissolves one or more components of the alloy, leaving behind a porous residue that retains its original shape and appears intact.
5. Corrosion cracking occurs when a metal is subjected to constant tensile stress in a corrosive environment. CR may be caused by the absorption of hydrogen generated during the corrosion process.
Fig.1. Types of corrosion damage
According to the mechanism of occurrence, chemical and electrochemical corrosion are distinguished.
Chemical corrosion is typical for environments that do not conduct electrical current.
Corrosion of steel in aquatic environment occurs due to the occurrence of electrochemical reactions, i.e. reactions accompanied by the occurrence electric current. At the same time, the corrosion rate increases.
Electrochemical corrosion occurs as a result of the operation of many macro- or microgalvanic couples in the metal in contact with the electrolyte.
Reasons for the occurrence of galvanic couples in metals:
· Contact of two dissimilar metals;
· Presence of impurities in the metal;
· Presence of areas with different crystal structures;
· Formation of pores in the oxide film;
· Presence of areas with different mechanical loads;
Presence of areas with uneven access of active components external environment, for example, air,
and, thus, galvanic elements, micropairs are formed, that is, anodic and cathodic sections are formed. The anode is the metal with a higher negative potential, the cathode is the metal with a lower potential. An electric current arises between them.
The corrosion process can be represented as follows.
At the anode: (oxidation reaction)
Fe - 2 e ® Fe 2+ (1)
In the anodic areas, iron atoms go into solution in the form of hydrated Fe 2+ cations, that is, anodic dissolution of the metal occurs and the corrosion process spreads deep into the metal.
The remaining free electrons move through the metal to the cathode sites.
At the cathode: (reduction reaction)
2 H+ + 2 e ® 2 Nads. (2)
At pH< 4,3 происходит разряд всегда присутствующих в воде ионов водорода и образование атомов водорода с последующим образованием молекулярного водорода:
H + H ® H2 -. (3)
At pH > 4.3, the interaction of electrons with oxygen dissolved in water dominates:
O2 + 2 H2O + 4 e ® 4 OH-- (4)
Fig.2. Corrosion process diagram
Fe 2+ cations and OH- ions interact to form Fe oxide:
Fe2+ + 2 OH--® Fe(OH)2. (5)
If there is enough free oxygen in the water, Fe oxide can oxidize to Fe oxide hydrate:
4Fe(OH)2 + O2 + 2 H2O ® 4Fe(OH)3¯ , (6)
which falls out as a sediment.
So, as a result of the flow of electric current, the anode is destroyed: metal particles in the form of Fe 2+ ions pass into water or an emulsion flow. The anode, when destroyed, forms a fistula in the pipe.
Let's consider what factors the corrosion rate depends on.
FACTORS OF CORROSIVE DESTRUCTION OF PIPELINES
1. Water temperature and pH
Fig.3. Dependence of corrosion intensity on pH and water temperature
There are 3 zones:
1) pH< 4,3 . Скорость коррозии чрезвычайно быстро возрастает с понижением рН. (Сильнокислая среда).
2) 4,3 < рН < 9-10. Скорость коррозии мало зависит от рН.
3) 9-10 < рН < 13. Скорость коррозии убывает с ростом рН и коррозия практически прекращается при рН = 13. (Сильнощелочная среда).
In the first zone at the cathode, the reaction of the discharge of hydrogen ions and the formation of molecular hydrogen occurs (reactions 2,3); in the second and third zones, the reaction of formation of hydroxyl ions OH-- takes place (reaction 4).
An increase in temperature accelerates the anodic and cathodic processes, as it increases the speed of movement of ions, and, consequently, the rate of corrosion.
As noted above, iron pipes undergo intense corrosion in an acidic environment at pH< 4,3 и практически не корродирует при рН >4.3, if there is no dissolved oxygen in the water (Fig. 4., curve 4).
If there is dissolved oxygen in the water, then corrosion of iron will occur in both acidic and alkaline environment(Fig. 4, curves 1-3).
Fig.4. Dependence of corrosion intensity on oxygen content in water
3. CO2 partial pressure
Free carbon dioxide (CO2) contained in formation waters has a huge impact on the destruction of pipe metal by corrosion. It is known that at the same pH, corrosion in a carbon dioxide environment occurs more intensely than in solutions of strong acids.
Based on research, it has been established that systems with РСО2 <0.02 MPa are considered non-corrosive, with 0.2 ³РСО2 >0.02, average corrosion rates are possible, and with РСО2 > 0.2 MPa, the environment is highly corrosive.
The explanation of the influence of CO2 on the corrosive activity of the environment is associated with the forms of CO2 in aqueous solutions. This:
Dissolved CO2 gas;
Undissociated H2CO3 molecules;
Bicarbonate ions HCO3-;
Carbonate ions CO32-.
In equilibrium conditions, a balance is maintained between all forms:
CO2 + H2O Û H2CO3 Û H+ + HCO3- Û 2H+ + CO32- . (7)
CO2 can have an effect for two reasons:
1. H2CO3 molecules are directly involved in the cathodic process:
H2CO3 + e ® Nads + HCO3- (8)
2. Bicarbonate ion undergoes cathodic reduction:
2НСО3- + 2e ® Н2- + СО32- (9)
3. H2CO3 plays the role of a buffer and supplies hydrogen ions H+ as they are consumed in the cathodic reaction (2):
H2CO3 Û H+ + HCO3- (10)
When Fe2+ interacts with HCO3- or H2CO3, a precipitate of iron carbonate FeCO3 is formed:
Fe2+ + HCO3 - ®FeCO3 + H+ (11)
Fe2+ + H2CO3 ® FeCO3 + 2H+ (12)
All researchers pay attention to the enormous influence of iron corrosion products on the rate of the corrosion process.
4FeCO3 + O2 ® 2Fe2O3 + 4CO2- (13)
These deposits are semi-permeable to corrosive components of the environment and slow down the rate of metal destruction.
Thus, two characteristic features of the action of carbon dioxide can be distinguished.
1. Increased hydrogen evolution at the cathode.
2. Formation of carbonate-oxide films on the metal surface.
4. Water mineralization
Rice. 5. Dependence of corrosion rate on water salinity
Salts dissolved in water are electrolytes, so increasing their concentration to a certain limit will increase the electrical conductivity of the medium and, therefore, accelerate the corrosion process.
The decrease in corrosion rate is due to the fact that:
1) the solubility of gases, CO2 and O2, in water decreases;
2) the viscosity of water increases, and, consequently, diffusion and the supply of oxygen to the surface of the pipe (to the cathode sections, reaction 4) become more difficult.
5. Pressure
Increasing the pressure increases the process of hydrolysis of salts and increases the solubility of CO2. (To predict the consequences, see paragraphs 3 and 4).
6. Structural form of flow
Relative flow rates of phases (gas and liquid) in gas-liquid mixtures (GLM) in combination with their physical properties(density, viscosity, surface tension, etc.) and the dimensions and position in space of the pipeline are determined by the structures of two-phase (multiphase) flows formed in them. Seven main structures can be distinguished: bubble, cork, layered, wave, projectile, ring and dispersed (Fig. 6).
Fig.6. GHS structures in a horizontal pipeline
Each structure of the GLS influences the nature of the corrosion process.
The question of the connection between corrosion processes in pipelines and the structures of flows transported through them by gas and liquid liquids has always been and continues to be of interest to corrosion specialists. The available information on the connection between the flow structures of hydraulic fluid and corrosion is still insufficiently complete.
But nevertheless, it is known, for example, that the annular (dispersed-ring) structure of the gas liquids reduces the intensity of pipeline corrosion; slug (plug-dispersed) can contribute to corrosion-erosive wear of the pipeline along the lower generatrix of the pipe in the ascending sections of the route, and stratified (smooth stratified) can contribute to the development of general and pitting corrosion in the zone of the lower generatrix of the pipe and in the so-called “traps” of liquid ( especially when salt water separates into a separate phase).
6. Biocorrosion, corrosion under the influence of microorganisms.
From this point of view, sulfate-reducing anaerobic bacteria (reduce sulfates to sulfides), usually living in waste water ah, oil wells and productive horizons.
As a result of the activity of sulfate-reducing agents, hydrogen sulfide H2S is formed, which is highly soluble in oil and subsequently interacts with iron, forming iron sulfide, which precipitates:
Fe + H2S ® FeS¯ + H2- (14)
Under the influence of H2S, the wettability of the metal surface changes, the surface becomes hydrophilic, that is, it is easily wetted by water, and a thin layer of electrolyte is formed on the surface of the pipeline, in which the accumulation of iron sulfide FeS precipitate occurs.
Iron sulfide is a corrosion stimulator, as it participates in the formation of a galvanic micropair Fe - FeS, in which it is the cathode (that is, Fe as an anode will be destroyed).
Some ions, such as chlorine ions, activate metals. The reason for the activating ability of chlorine ions is its high adsorbability on metal. Chlorine ions displace passivators from the metal surface, promote the dissolution of passivating films and facilitate the transition of metal ions into solution. Chlorine ions have a particularly great influence on the dissolution of iron, chromium, nickel, stainless steel, and aluminum.
So, the corrosive aggressiveness of water is characterized by the nature and amount of dissolved salts, pH, water hardness, and the content of acid gases.
The degree of influence of these factors depends on temperature, pressure, flow structure and the quantitative ratio of water and hydrocarbons in the system.
Markin (JV Vanyeganneft) proposed an equation for calculating the rate of uniform (total) carbon dioxide corrosion of carbon steel in water for the case when the carbonate equilibrium is not disturbed, i.e. no salt precipitates are released.
For formation water of the Samotlor field: A=3.996; B=1730.
The equation is valid for the following conditions:
10 < t < 60 (0С);
5,4 < рН < 7,6;
0,001 < Рсо2 < 0,1 (МПа);
85 < НСО3- < 600 (мг/л).
These are the most typical indicators for real oil field systems in the Nizhnevartovsk region.
Methods for preventing internal corrosion of pipelines are divided into technical (mechanical), chemical and technological.
2. MAIN DIRECTIONS AND RESULTS OF WORK TO PROTECT PIPELINES FROM INTERNAL CORROSION
The existing scheme of exploitation of most fields with the maintenance of reservoir pressure due to the injection of waste water into the reservoir contributes to an increase in the aggressiveness of the environment in which the pipes “operate” during the extraction and transportation of raw materials. According to JSC VNIITneft, over the past five years, due to an increase in the water cut of produced oil, the corrosion rate of pipelines has increased from 0.04 to 1.2 g/m2/hour.
Now oil workers consider pipelines to be a time bomb that can “explode” at any moment.
It is obvious that currently used inhibitory protection methods cannot solve the problem completely. Increasing the reliability and reducing the accident rate of field pipelines can only be achieved through the use of comprehensive measures. Among them, the main one, apparently, can be considered the change of pipe material to a corrosion-resistant one, as well as the use of pipes with anti-corrosion coating, that is, technical methods of protection.
2.1. Technical methods of protection
A fundamental means of combating corrosion damage to steel pipes is to replace them with plastic ones.
In foreign practice, two types of plastic pipes are used for oil and gas field pipelines:
For low pressures up to 1.0 MPa - from low-density polyethylene (HDPE, as well as from polypropylene, polyvinyl chloride, polybutene, acrylonitrile butadione;
For pressures of 4.0-6.0 MPa and above - from composite materials: fiberglass, biplastic, reinforced, thermoplastic.
Polyethylene pipes weigh 7 times less than steel pipes. Their installation does not require heavy lifting and transport equipment. They have great elasticity and high smoothness, as a result of which their throughput increases by 2-3%.
From Figure 8 it follows that for steel pipelines hydraulic losses increase with increasing service life (curve 1), for metal-plastic pipes and pipes with protective coatings there is no increase in hydraulic losses (curves 2,3).
Polyethylene pipes can be used to transport mineralized waters of any aggressiveness (GOST 18599-83).
Fig.8. Dependence of hydraulic losses on the operating time of pipes:
1 - steel; 2- metal-plastic and flexible; 3 - with epoxy and polymer internal coatings
As for the transport of oil, oil emulsion, and gas condensate through pressure pipelines made of polyethylene pipes, the swelling effect of polyethylene should be taken into account.
It was installed:
1. The process of oil diffusion into polyethylene, polyethylene swelling, depends on temperature.
Fig.9. Oil sorption by low pressure polyethylene:
1 - 60, 2 - 40, 3 - 20 оС
At a temperature of 60°C, the equilibrium oil concentration (saturation) occurred at 8% wt.
2. With increasing concentration of sorbed oil, the strength of polyethylene decreases (Fig. 10).
For example, when the oil concentration in polyethylene increases to 5%, its strength decreases by 10%.
Thus, the main disadvantage of polyethylene pipes is their low strength. Therefore, research is being conducted all over the world to create plastic pipes, on the one hand, chemically resistant to aggressive environments, and on the other, having strength comparable to steel pipes.
Fig. 10. Change in polyethylene strength depending on oil concentration at 20 °C.
The solution to this problem is pipes made of composite materials: fiberglass, reinforced thermoplastics.
In the United States, fiberglass pipes occupy third place in the volume of consumption of oilfield pipes, behind steel and metal with anti-corrosion factory coating. In some fields containing highly aggressive components, plastic pipes make up 60-70% of the total volume of pipes used. Exxon and Esso Resources Canada also replaced some of the steel pipes in their fields with composite ones due to high water content and high concentration of hydrogen sulfide in the transported medium.
The share of fiberglass pipes used by Shell exceeds 30%.
Fiberglass pipes have high corrosion resistance in contact with a medium containing hydrogen sulfide and carbon dioxide, and high strength over a wide pressure range. By selecting the appropriate resin, fiberglass pipes can operate at high temperatures.
The thermal conductivity of fiberglass is 250 times less than that of metal, that is, it has increased thermal insulation characteristics.
Back in the 70s, VNIIST developed the design of a fiberglass pipe, the technology and equipment for its production, as well as the technology for connecting such pipes.
The pipe was a sandwich consisting of a fiberglass load-bearing shell, clad on the inside with a gas-tight polypropylene film 0.8 mm thick.
The pipe was manufactured in a continuous process and could be of almost any length. Currently, conversion enterprises in Perm, Khotkovo, Lyubertsy produce small batches of fiberglass and reinforced plastic pipes for high (up to 4.0-6.0 MPa) pressures. Moreover, there are design options for fiberglass pipes with a permissible temperature limit of up to 60 ° C (diameter 75 and 150 mm).
Such pipes successfully operate at Udmurtneft JSC in the RPM system with the following characteristics of the transported medium:
mineralization 280 mg/l;
pressure 6-8 MPa;
temperature 40 oC.
At Permneft JSC, fiberglass pipes are installed on flow lines where highly water-cut oil (83%) is pumped. During operation since 1994, no leaks were observed.
Fiberglass pipes produced by Ameron and Vavin were used on pipelines in Tatneft and Western Siberia and gave positive results.
It is of interest to dwell in more detail on the results of work at OAO Tatneft on corrosion protection of oilfield equipment. For the first time in world practice, the problem of protecting oil field equipment (pipelines of oil collection systems, water conduits, tubing, technological tanks and reservoirs) at OAO TATNEFT was solved on the basis of creating its own bases for applying internal and external insulation, close to the places of their application, that is, oil deposit).
It took about 15 years to implement this program. As a result, an entire industry has been created comprehensive solution problems of reliability of wells and underground oilfield communications. It includes:
Incoming inspection of pipes coming from manufacturers;
Preparing pipes for coating (preparing ends, cleaning surfaces);
Technique and technology for connecting pipes into a string (about 30 m long) and into a pipeline;
Application of internal and external insulation;
Protection of welded joints;
Control over the quality of construction and operation of pipelines;
Production of materials and non-standard equipment.
The practice of operating pipelines with internal protective coatings has shown that in order to completely reduce failures, three main problems must be solved:
* reliable internal coating;
* reliable external insulation;
* protection of welded joints on both sides.
Together with the companies Tubeskop Vetco (USA) and Bandera (Italy), a plant was built to produce coated pipes with a capacity of up to 2000 km/year.
It should be emphasized that applying insulation precisely in a factory environment makes it possible to control the quality of all technological operations and to introduce insulating coatings that cannot be implemented in field conditions.
The problem of reliable protection against internal corrosion was solved using the technology of lining pipe strands with polyethylene and a special joint design.
External insulation is carried out using factory technology using polyethylene.
Fig. 11. Application of external insulation
Since 1986 About 10,000 km of metal-plastic (MPT) pipelines were produced and built, which is 100% for distribution and 80% for supply water pipelines for pumping waste water. (Pipe diameters 89,114,159,219,273 and 325 mm; operating temperature - up to 40°C). The greater the share of MPT in the general fund, the more intense the reduction in the number of pipeline failures (Fig. 12).
Fig. 12. Dependence of the number of pipeline failures on the volume of introduction of pipes with protective coatings
Thanks to the joint efforts of science and industry, pipeline failures in the wastewater injection system decreased in 1997. 400 times compared to 1984. The economic effect from the use of lined pipes reached 2.5 trillion rubles. (1997), and the payback period for capital investments does not exceed 1.5 years.
To prevent internal corrosion of oil-gathering pipelines, OAO TATNEFT has chosen the following directions:
For pumping wax-free sulfur-containing oils, MPT, corrosion-resistant flexible tubes produced by KVART (Kazan) are used;
For paraffinic oils, pipes with a special protective coating are used that can withstand operating temperatures of up to 150 °C.
The presence of production of polyethylene pipes made it possible to carry out work on the restoration of inactive pipelines. 460 km of pipes with a diameter of 89-530 mm were restored by pulling polyethylene pipes inside steel pipes (with or without cementing the interpipe space). These operations are effective for quickly restoring the functionality of pipelines in critical situations, since a section up to 600 m long can be restored in one step. This is important when crossing water barriers, swamps, and road surfaces using trenchless technology.
OAO Tatneft has 10 years of experience in the use of fiberglass pipes from the Dutch company Wavin.
Since 1988 fiberglass pipes work flawlessly as tubing, diameter 89 mm. Positive results obtained using an oil collection system: diameter 159 mm and pressure 2.8 MPa. Negative results were obtained when testing fiberglass pipes in the PPD system as a distribution water conduit (pressure 12.5 MPa): adhesive joints and turns (elbows) could not withstand the pressure.
Thus, many years of experience in the production and use of pipes with protective coatings allowed OAO Tatneft to practically solve the problem of reliability of oil field communications and save more than 6600 million kWh of electricity (by reducing hydraulic losses) when operating metal-plastic pipes.
The entire range of work meets international standards.
ANK Bashneft also applies protective coatings and the use of non-metallic pipes to protect pipelines from corrosion. There is a workshop for lining pipes with a diameter of 114x9 and 89x4 mm, and a workshop for the production of flexible polymer-metal pipes with a diameter of 60 mm. Total productivity 650 km/year. One of four lines for the production of metal-plastic pipes with a capacity of 150 km/year was launched.
Once all workshops reach their design capacity, Bashneft will produce approximately 1,500 km/year of corrosion-resistant pipes and in the future it is planned to completely replace metal pipes with them.
The latest development by Ameron (Netherlands), which specializes in the production of fiberglass pipes for the oil industry, is based on the steel strip technology used by British Aerospace to produce high-strength shells for space rocket engines. The new SSL material is a laminated composite material that combines the benefits of high-strength steel with the corrosion resistance of fiberglass. It produces light, smooth, anti-corrosion pipes, withstanding pressure of almost 40 MPa - for small diameters and up to 4 MPa - for large diameters and temperatures up to 110 °C.
temperature up to 110 oC.
.
Fig. 13. Bondstrand SSL pipe
Bondstrand SSL pipes consist of layers of steel tape enclosed within a glass fiber reinforced epoxy sheath. They can be used to construct flowlines, oil recovery lines, subsea and injection pipelines, as well as tubing and casing.
The wall thickness of the Bondstrand SSL pipe is (several times) smaller than the wall thickness of a conventional fiberglass pipe, which provides higher throughput (at the same pressure).
The Coil-Lock connecting system - a conical threaded connection with a plastic spiral key - provides Bondstrand SSL pipes with strength and tightness, and quick installation. The new pipes have another valuable feature: the electrically conductive steel layer allows electrical monitoring of the pipeline laid underground.
The minimum service life in Siberian conditions is 20 years, the standard period is more than 50 years.
In Russia, the pioneer in the use of Bondstrand SSL pipes is the Slavneft-Megionneftegaz company. She started using them in 1995. For 2000 Russian companies We ordered 262 km of such pipes from Ameron. Over the past 2 years, 116 km of pipes have been supplied to Kazakhstan.
Consumers are Tyumen Oil Company, Megionneftegaz, Chernogorneft, Vanyeganneft, etc.
Depending on the operating conditions in different fields, pipes with an internal coating of different materials are required. But to date, factories have practically not mastered the mass production of pipes with anti-corrosion coating. Only certain manufacturers have areas for coating pipes or produce pipes with one a certain type coverings.
Thus, the Volzhsky Pipe Plant produces pipes only with an external epoxy coating, the Almetyevsky Pipe Plant - with an internal epoxy and external polyethylene coating, JSC Penzazavodprom - an enamel coating, etc.
In the current situation, oil and gas producing enterprises are forced to organize their own production for anti-corrosion coating of pipes. In addition to the already mentioned NK "Tatneft" and "Bashneft", sites have been created and are operating at JSC "Nizhnevartovskneftegaz" - equipment and technologies of the French company "CIF-IZOPIPE", at the TPP "Langepasneftegaz" - the supplier is the Dutch company "Selmers". Pipes with enamel coated and lined with polyethylene are produced by OJSC LUKOIL-Permneft (Krasnokamsk). Joint production of fiberglass pipes has been mastered by OJSC LUKOIL-Permneft and JSC Kompozitneft (Chernushka).
Currently, a number of companies, domestic and foreign, offer oil companies their services for the construction of turnkey lines for various options for anti-corrosion coating of oil field pipes. Data on some of them are given in Table 1.
As follows from this table, companies offer lines for applying almost all types of insulation. The production price fluctuates widely. There is a choice. But here each oil and gas producing company acts at its own peril and risk. All companies guarantee a service life of insulated pipes of at least 15-20 years. But in practice, a different picture often emerges. As shown by inspections of some pipelines assembled abroad technological lines, the integrity of the coating is compromised within a short period of operation.
Table 1
Comparative indicators of some manufacturers of lines for anti-corrosion coating of oil field pipes
|
Type of coverage |
Materials |
Estimated cost, thousand dollars* |
|
|
JSC VNIITneft, Samara |
Internal, Single layer, 250 µm |
Polyurethane with zinc powder |
|
|
External, Double layer, 2.5 mm |
Sevilene (adhesive) + polyethylene (extruded) |
||
|
Westintercom LLC, Samara |
Internal, Single layer, 4.5 mm |
Polyethylene |
|
|
External, Double layer, 1.5 mm Double layer, 2.2 mm Double layer, 2.0 mm Single layer, 1.5 mm |
Primer+polymer tape+polymer wrap Primer + polymer tape + polyethylene (extrud.) Polymer sublayer (adhesive) + polyethylene (ext.) Heat shrinkable Polymer tape |
||
|
Truboplast LLP, Yekaterinburg |
Internal, Single layer, 400 µm |
Epoxy powder or liquid two-component (solvent-free) paints |
|
|
External, Double layer, 2.0 mm |
Polymer sublayer (adhesive)+polyethylene (ext.) |
||
|
JSC "ANCORT", Moscow |
Internal, Single layer, 400 µm |
Epoxy liquid two-component (solvent-free) paints |
|
|
External, Double layer, 2.2 mm |
Adhesion primer + polymer adhesive tape + polyethylene |
||
|
JSC "UralNITI" Chelyabinsk |
Internal, Single layer, 300 µm Single layer, 120 µm Single layer, 400 µm |
Epoxy (powder paint) Zinc ethyl silicate Glass enamel |
|
|
External, Three-layer, 2.5 mm |
Epoxy (powder paint) + epoxy mixture composition (powder) + polyethylene (extruder) |
||
|
JSC "Tatneft" Almetyevsk |
Internal, Single layer, 5 mm |
Polyethylene (stocking) |
|
|
External, Double layer, 2.0 mm |
Adhesive + polyethylene (extruded) |
||
|
"Bredero price" |
Internal, Double layer, 250 µm |
Primer + epoxy powder |
|
|
External, Three-layer, 2.5 mm |
Epoxy coating (powder) + adhesive (copolymer) + polyethylene (extruder) |
||
|
Internal, Double layer, 120 µm |
Adhesive (primer) + epoxy |
||
|
External, Double layer, 1.2 mm |
Primer + polyethylene (extrusive) |
||
|
Internal, Single layer, 150 µm |
Primer (phenolic) + epoxy powder |
||
|
External, Double layer, 1.0 mm |
Epoxy (fused) coating + epoxy powder |
*Including supervision of installation, commissioning and, in some companies, personnel training.
Pipes are produced with an internal diameter of 50, 75 and 100 mm for a working pressure of up to 20 MPa, a weight of 1 m of no more than 12 kg, a maximum section length of up to 350 m. The production of pipes with a diameter of 150 mm is being prepared.
Fig. 14. Flexible pipe design
Flexible pipes consist of an internal polymer chamber 1, reinforcing layers 2, an outer polymer shell 3 and end connections 4.
Flexible pipes "Rosflex" are designed for trench laying and laying on the ground surface.
Capital costs for laying 1 km of pipeline from steel and flexible pipes of various diameters are given in Table 3. It follows from it that when using flexible pipes, the costs of construction and installation work are reduced by 50%: 1 km of pipeline is installed in 5 - 6 hours due to the large section length, flexibility, elimination of fitting, welding and insulating work, which is especially valuable for the fields of Western Siberia in swamps and off-road conditions.
