Analysis of regulatory requirements for the assessment of carbon dioxide corrosion at gas production facilities

2021 ◽  
Vol 18 (2) ◽  
pp. 60-71 ◽  
Author(s):  
D. N. Zapevalov ◽  
R. K. Vagapov
Keyword(s):  
Carbon Dioxide ◽  
Corrosion Rate ◽  
Gas Production ◽  
Operating Conditions ◽  
Local Corrosion ◽  
Design Stage ◽  
General Corrosion ◽  
Carbon Dioxide Corrosion ◽  
Internal Corrosion ◽  
Production Facilities

Aim.In many fields, the produced gas contains corrosive CO2, which, in combination with moisture and other factors, stimulates the intensive development of corrosion processes, including local ones, which requires careful attention to the assessment of the corrosiveness of operating fluids in order to select effective anti-corrosion protection. Ensuring reliable and safe operation of equipment and pipelines prevents not only man-made risks, but also no less important environmental risks, which are especially dangerous for marine underwater facilities for Arctic coastal facilities.Methods.The analysis of normative and technical documentation in the field of assessment of corrosion risks, aggressive factors of internal corrosion and operating conditions of gas and gas condensate fields has been carried out.Results.One of the criteria for assessing the corrosion hazard is the corrosion rate of steel under operating conditions. However, the normative documents predominantly regulate the general corrosion rate, which evaluates the uniform thinning of the metal. But the rate of local corrosion is in no way taken into account, which is most relevant precisely for the conditions of carbon dioxide corrosion of steel. Another tool for identifying risks can be a corrosion allowance to the pipe wall thickness, which should be selected at the design stage and which is provided to compensate for corrosion losses during the operation of gas pipelines. It is shown that the minimum corrosion allowance (3 mm) specified in the main regulatory documents is insufficient, especially for offshore facilities.Conclusion.The experience of operating gas production facilities confirms that the rate of local corrosion can reach several mm/year. To limit this, effective anti-corrosion measures should be chosen, for example, the use of corrosion inhibitors, and a reasonable level of corrosion allowance should be provided that would take into account the corresponding level of corrosion risks at the gas production facility.

Hazard Assessment of the Internal Carbon Dioxide Corrosion of the Field Pipelines at the Gas and Gas Condensate Fields

2021 ◽  
pp. 56-62
Author(s):  
R.R. Kantyukov ◽  
◽  
D.N. Zapevalov ◽  
R.K. Vagapov ◽  
◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Gas Condensate ◽  
Design Stage ◽  
Carbon Dioxide Corrosion ◽  
Safe Operation ◽  
Internal Corrosion ◽  
Operating Environments ◽  
Facilities Design ◽  
Equipment And Pipelines ◽  
Intensive Development

At many gas and gas condensate fields in operation, carbon dioxide (СО2) is present in the scope of the produced products, which, in combination with the natural and technological factors, stimulates intensive development of the internal corrosion processes in the pipelines and equipment. The relevance of the development of native regulatory documentation aimed at the assessment of the corrosion effects and development of the practical recommendations for protection against carbon dioxide corrosion in the last decade is due to the development of new gas fields in Russia with a high CO2 content (including on the Russian offshore), where there is a risk of local corrosion development with a high flow rate. The presence of CO2 in the produced gas in combination with the moisture and other factors stimulates the intensive development of corrosion processes and requires careful attention to the assessment of the corrosion aggressiveness of operating environments for selecting an efficient anti-corrosion protection. This is required to ensure reliable and safe operation of the equipment and pipelines made of carbon steel. Pipe low-alloy steel of 09G2S (09Mn2Si) grade, which is the most widely used at the domestic gas facilities, is not resistant to carbon dioxide corrosion. The experience of operating foreign deposits under conditions of carbon dioxide corrosion confirms the need and efficiency of considering this corrosion aspect at the facilities design stage. Incorrect assessment and underestimation of CO2 hazard in the produced hydrocarbons in relation to steel equipment and pipelines can lead to unaccounted corrosion risks (up to the facility shutdown), significant costs for the elimination of corrosion consequences (repairs, etc.), and the need to select and justify urgent corrective measures. Accounting the Russian and international experience allows to make a reasonable choice of rational technical solutions for efficient and safe operation of the deposits in conditions of carbon dioxide corrosion.

ANALYSIS OF THE USE OF ULTRASONIC TESTING METHODS IN THE FRAMEWORK OF CORROSION MONITORING OF INTERNAL CORROSION AT GAS PRODUCTION FACILITIES IN THE PRESENCE OF CARBON DIOXIDE

2020 ◽  
pp. 30-35
Author(s):  
D. N. Zapevalov ◽  
R. K. Vagapov
Keyword(s):  
Carbon Dioxide ◽  
Oil And Gas ◽  
Thickness Measurement ◽  
Gas Production ◽  
Corrosion Monitoring ◽  
Internal Corrosion ◽  
Ultrasonic Methods ◽  
Ultrasonic Thickness Measurement ◽  
Gas Fields ◽  
Production Facilities

The use of various intrusive and non-intrusive methods of corrosion monitoring makes it possible to assess the corrosion situation and the effectiveness of the applied corrosion protection agents in conditions of internal corrosion at gas production facilities due to the presence of aggressive gases. The analysis of the application of ultrasonic testing methods as part of corrosion monitoring of internal corrosion at gas production facilities in the presence of corrosive components is carried out. Ultrasonic thickness measurement is widely used as a non-intrusive method for monitoring internal corrosion and detecting corrosion defects in promising gas fields. Many gas fields (Bovanenkovskoye oil and gas condensate field, Urengoy oil and gas field and others) revealed corrosion defects due to cases of internal corrosion due to the presence of increased amounts of carbon dioxide in the produced hydrocarbons. Under conditions of corrosion in the presence of carbon dioxide, ultrasonic methods for measuring the thickness of a metal have certain limitations associated with the unpredictable local nature of carbon dioxide corrosion, which should be considered when used in gas facilities. The main method for measuring thickness under operational conditions is ultrasonic thickness measurement, which is used in conjunction with radiographic monitoring. Using these two main non-intrusive methods, corrosion monitoring monitors the thinning of the metal, the size and depth of local defects and the dynamics of their change over time. Based on the results of measuring the residual wall thickness of the pipe and equipment, the possibility of their further work is determined, and recommendations are made on extending the safe life of gas facilities. The authors analyzed the literature data on new options and technical solutions for the use of ultrasonic methods in the measurement of the thickness of a metal surface.

Сравнение и интерпретация результатов обработки данных внутритрубной диагностики для условий транспортировки коррозионно-агрессивного газа

2021 ◽  
pp. 62-71
Author(s):  
Р.К. Вагапов
Keyword(s):  
Carbon Dioxide ◽  
Corrosion Damage ◽  
Gas Production ◽  
Operating Conditions ◽  
Corrosion Monitoring ◽  
Data Set ◽  
Internal Corrosion ◽  
Subsea Pipelines ◽  
Flux Leakage ◽  
Corrosion State

Many gas and gas condensate fields (Bovanenkovskoye, Urengoyskoye, Kirinskoye, etc.) are distinguished by the presence of corrosive carbon dioxide in the extracted products, which, in the presence of moisture, leads to the formation of local corrosion damage (pits, ulcers and their accumulations). One of the methods for monitoring the corrosion state of pipelines is in-line inspection (ILI), carried out by the magnetic flux leakage method. ILI is especially relevant for underground and subsea pipelines when the use of other methods of corrosion monitoring is limited or costly. Under conditions of gas production, in contrast to oil, corrosion can occur both along the lower generatrix of the pipe (bottom-of-line corrosion) and during condensation of moisture on the upper generatrix of the pipe (top-of-line corrosion). An important process is the correct planning of the ILI, the subsequent processing and interpretation of the obtained data set, which should be carried out taking into account the peculiarities of the development of carbon dioxide corrosion in the gas pipeline and in a comparative analysis with other data of corrosion control. When interpreting ILI data, one should take into account the mechanisms of corrosion development, operating conditions (route relief, etc.) and corrosion monitoring data obtained by other research methods (simulation tests, results obtained at other adjacent sections of pipelines, etc.). Correct and useful information according to ILI data will ensure reliable protection of gas pipelines and planning of measures to protect against internal corrosion.

scholarly journals A Novel Low-Temperature Non-Corrosive Sulfate/Sulfide Scale Dissolver

2020 ◽  
Vol 12 (6) ◽  
pp. 2455
Author(s):  
Hany Gamal ◽  
Salaheldin Elkatatny ◽  
Dhafer Al Shehri ◽  
Mohamed Bahgat
Keyword(s):  
Low Temperature ◽  
Corrosion Rate ◽  
High Performance ◽  
Oil And Gas ◽  
Ethylenediaminetetraacetic Acid ◽  
Gas Production ◽  
Operating Conditions ◽  
Superior Performance ◽  
X Ray ◽  
Dissolution Efficiency

The oil and gas production operations suffer from scale depositions. The scale precipitations have a damaging impact on the reservoir pores, perforations, downhole and completion equipment, pipeline network, wellhead chokes, and surface facilities. Hydrocarbon production possibly decreased because of the scale accumulation in the well tubular, leading to a well plugging, this requires wells to be shut-in in severe cases to perform a clean-out job. Therefore, scale deposition is badly affecting petroleum economics. This research aims to design a scale dissolver with low cost, non-damaging for the well equipment and has a high performance at the field operating conditions. This paper presents a novel non-corrosive dissolver for sulfate and sulfide composite scale in alkaline pH and works at low-temperature conditions. The scale samples were collected from a production platform from different locations. A complete description of the scale samples was performed as X-ray diffraction (XRD) and X-ray fluorescence (XRF). The new scale dissolver was prepared in different concentrations to examine its dissolution efficiency for the scale with time at low temperatures. The experimental design studied the solid to fluid ratio, temperature, solubility time, and dissolution efficiency in order to achieve the optimum and most economic performance of solubility in terms of high dissolution efficiency with the smallest possible amount of scale dissolver. A solubility comparison was performed with other commercial-scale-dissolvers and the corrosion rate was tested. The experimental work results demonstrated the superior performance of the new scale dissolver. The new scale dissolver showed a solubility efficiency of 91.8% at a low temperature of 45 °C and 79% at 35 °C. The new scale dissolver showed a higher solubility ratio for the scale sample than the ethylenediaminetetraacetic acid (EDTA) (20 wt. %), diethylenetriamine pentaacetic acid (DTPA) (20 wt. %), and HCl (10 wt. %). The corrosion rate for the new non-corrosive dissolver was 0.01357 kg/m2 (0.00278 lb./ft²) which was considered a very low rate and non-damaging for the equipment. The low corrosive effect of the new dissolver will save the extra cost of adding the corrosion inhibitors and save the equipment from the damaging effect of the corrosive acids.

Evaluation of Carbon Dioxide Corrosion on N80 Steel

2014 ◽  
Vol 490-491 ◽  
pp. 311-314
Author(s):  
Zhen Zhong Fan ◽  
An Qi Tong ◽  
Yan Cui ◽  
Jun Feng Yang
Keyword(s):  
Carbon Dioxide ◽  
Liquid Phase ◽  
Corrosion Rate ◽  
Partial Pressure ◽  
Gas Phase ◽  
Test Temperature ◽  
Microscopic Analysis ◽  
Carbon Dioxide Corrosion ◽  
Large White ◽  
N80 Steel

The carbon dioxide corrosion on N80 steel was evaluated under the gas phase and the liquid phase. With the test temperature improved, the corrosion rate increases. Under the condition of gas phase, the corrosion peak is 0.2942mm/a when the temperature is 110°C and pressure is 24 MPa. Under the condition of liquid phase, the corrosion peak is 26.5325mm/a when the temperature is 50°C and pressure is 24 MPa. With the increase of CO2 partial pressure, the corrosion rate of N80 steel was falling. Microscopic analysis shows that the corrosion products of CO2 on N80 steel have a large white flocculent compounds and the corrosion surface have a lot of cracks and holes.

scholarly journals Investigation of Carbon Dioxide Corrosion Inhibitors for Steel for Use in Oil and Gas Production

2020 ◽  
Vol 129 (4) ◽  
pp. 14-18
Author(s):  
L. A. Magadova ◽  
◽  
K. A. Poteshkina ◽  
V. D. Vlasova ◽  
M. S. Pilipenko ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Corrosion Inhibitors ◽  
Oil And Gas ◽  
Produced Water ◽  
Gas Production ◽  
Gravimetric Analysis ◽  
Carbon Dioxide Corrosion ◽  
Oil And Gas Production ◽  
Protective Properties ◽  
Industrial Samples

The effect of carbon dioxide corrosion on the pipeline transport system and its protection methods are considered in this article. The corrosion inhibitors represented by imidazoline-based compositions and industrial samples of corrosion inhibitors are used as protective reagents, and the model of produced water saturated with carbon dioxide is used as an aggressive environment. The protective properties of inhibitors and the corrosion rate were evaluated by gravimetric analysis. The paper presents the results of the study of industrial samples and inhibitory compositions developed on the basis of the REC “Promyslovaya himiya”. According to the results of the work, a positive effect of additives of nonionic surfactants on the protective properties of inhibitors was noted.

scholarly journals Aspects of protection against carbon dioxide corrosion of gas production facilities

2019 ◽  
Vol 121 ◽  
pp. 02013 ◽  
Author(s):  
Dmitry Zapevalov ◽  
Ruslan Vagapov
Keyword(s):  
Carbon Dioxide ◽  
Gas Production ◽  
Gas Condensate ◽  
Safe Operation ◽  
Hydrocarbon Production ◽  
Stage Of Development ◽  
The Media ◽  
Technical Solutions ◽  
Intensive Development ◽  
Production Facilities

The modern stage of development of many onshore and offshore gas and gas condensate fields is associated with objects in which carbon dioxide (CO2) gas is present in the production. The presence of CO2 in the produced gas in combination with other factors stimulates the intensive development of corrosion processes, which requires careful and reasonable attitude both to assess the degree of aggressiveness of the media and to choose technical solutions to ensure reliable and safe operation of hydrocarbon production facilities. The authors analyzed the existing approaches to the assessment of the danger of corrosion produced media, selection and implementation of protection against corrosion in the presence in them of aggressive CO2.

scholarly journals Media corrosiveness and materials resistance at presence of aggressive carbon dioxide

2021 ◽  
Vol 64 (11) ◽  
pp. 793-801
Author(s):  
R. R. Kantyukov ◽  
D. N. Zapevalov ◽  
R. K. Vagapov
Keyword(s):  
Carbon Dioxide ◽  
Oil And Gas ◽  
Gas Production ◽  
Carbon Dioxide Corrosion ◽  
Gas Field ◽  
Hydrocarbon Production ◽  
Field Development ◽  
Wide Range ◽  
Corrosive Effect ◽  
Equipment And Pipelines

At the present stage of gas field development, the products of many mining facilities have increased content of corrosive CO2 . The corrosive effect of CO2 on steel equipment and pipelines is determined by the conditions of its use. CO2 has a potentially wide range of usage at oil and gas facilities for solving technological problems (during production, transportation, storage, etc.). Simulation tests and analysis were carried out to assess the corrosion effect of CO2 on typical steels (carbon, low-alloy and alloyed) used at field facilities. Gas production facilities demonstrate several corrosion formation zones: lower part of the pipe (when moisture accumulates) and top of the pipe (in case of moisture condensation). The authors have analyzed the main factors influencing the intensity of carbon dioxide corrosion processes at hydrocarbon production with CO2 , its storage and use for various technological purposes. The main mechanism for development of carbon dioxide corrosion is presence/condensation of moisture, which triggers the corrosion process, including the formation of local defects (pits, etc.). X-ray diffraction was used for the analysis of corrosion products formed on the steel surface, which can have different protective characteristics depending on the phase state (amorphous or crystalline).

The Local Corrosion Rate Determination According to Weight Measurements Corrosion Coupons in Oilfield Conditions

2021 ◽  
Author(s):  
Valeriya Eduardovna Tkacheva ◽  
Andrey Nicolaevich Markin ◽  
Ignaty Andreevich Markin ◽  
Alexandr Yuryevich Presnyakov
Keyword(s):  
Carbon Dioxide ◽  
Maximum Rate ◽  
Oil And Gas ◽  
Gas Production ◽  
Oil Wells ◽  
Corrosion Monitoring ◽  
Carbon Dioxide Corrosion ◽  
Oil And Gas Production ◽  
Complicating Factors ◽  
Oilfield Equipment

Abstract Complications associated with a corrosive environment, according to Rosneft's data as of 01.01.2020, are among the prevailing at oil and gas production facilities and rank fourth among other factors complicating production - 12% the complicated mechanized wells. Failures due to corrosion are the second largest complicating factors. Based on the results of approbation, the article proposes a method for calculating the maximum rate of local carbon dioxide corrosion, applicable in oilfield conditions, including to complicated stocks of oil wells and pipelines of oil gathering systems. Based on the approbation results, a method for calculating the maximum rate of local carbon dioxide corrosion, applicable in oilfield conditions, including to complicated stocks of oil wells and oil gathering pipelines systems is proposed in the article. The proposed technique is realizable according to the results one of "traditional" methods the corrosion monitoring - weight (or gravimetric). The approbation results and application possibility the technique in the pilot tests process in assessing the protective ability of corrosion inhibitors and the selection the effective dosages in relation to local damages, which are the main cause the oilfield equipment failures according the factor "Corrosive aggressiveness" (one of the complicating factors in terms of gradation, adopted in the Rosneft Company regulations). On practical examples the oilfield equipment operation, the results of corrosion monitoring and the summary statistics the corrosive stock of wells (using the example of an oil Company), the current situation with respect to this type of complication and relevance the issue under consideration is shown.

Performance Evaluation of the Carbon Dioxide Corrosion Inhibitor IMC-1

2014 ◽  
Vol 490-491 ◽  
pp. 150-154
Author(s):  
Zhen Zhong Fan ◽  
Hui Ming An ◽  
Shu Yi Wang ◽  
Jun Feng Yang
Keyword(s):  
Carbon Dioxide ◽  
Corrosion Rate ◽  
Corrosion Inhibitor ◽  
Caprylic Acid ◽  
Acid Amide ◽  
Steel Corrosion ◽  
Electrode Reaction ◽  
Carbon Dioxide Corrosion ◽  
Electrochemical Polarization ◽  
N80 Steel

The carbon dioxide corrosion inhibitor IMC-1 was composed by caprylic acid amide polyoxyethylene ethers (n=4-5) and a small amount of the TX-10(5%). When the concentration was 200 mg/L, N80 steel corrosion rate was less than 0.125mm/a. With the CO2 partial pressure and temperature increased, N80 steel corrosion rate was decreased. From the electrochemical polarization curve, the adding corrosion inhibitor prevented the electrode reaction. The corrosion inhibitor IMC-1 was anodic inhibitor.

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