Influence of calcium and magnesium ions on CO2 corrosion of carbon steel in oil and gas production systems - A review

CO2 corrosion in carbon steel piping systems can be severe depending on a number of factors including CO2 content, water chemistry, temperature, and percent water cut. For many oil and gas production conditions, corrosion products can form a protective scale on interior surfaces of the piping. In these situations, metal loss rates can reduce to below design allowances. But, if sand is entrained in the flow, sand particles impinging on pipe surfaces can remove the scale or prevent it from forming at localized areas of particle impingement. This process is referred to as “erosion-corrosion” and can lead to high metal loss rates. In some cases, penetration rates can be extremely high due to pitting. This paper combines laboratory test data on erosion-corrosion with an erosion prediction computational model to compute flow velocity limits (“threshold velocities”) for avoiding erosion-corrosion in carbon steel piping. Also discussed is how threshold velocities can be shifted upward by using a corrosion inhibitor.

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Corrosion Investigation of Commercially Available Linepipe Steel in CO2 Environment

International Journal of Engineering & Technology ◽

10.14419/ijet.v7i3.32.18382 ◽

2018 ◽

Vol 7 (3.32) ◽

pp. 15

Author(s):

Muhammad Haris ◽

Saeid Kakooei ◽

Mokhtar Che Ismail

Keyword(s):

Carbon Steel ◽

Corrosion Rate ◽

Oil And Gas ◽

Corrosion Behaviour ◽

Complex Problem ◽

Gas Production ◽

Co2 Corrosion ◽

Oil And Gas Production ◽

The Difference ◽

Co2 Environment

CO2 corrosion has been the most prevalent form of corrosion and is considered as a complex problem in oil and gas production industries. The CO2 in presence of water causes sweet corrosion that is responsible for failure of pipeline during transportation of Oil and Gas. This work studies the corrosion behaviour of carbon steel specimens in CO2 environment at different temperatures but at constant pressure. The effect of CO2 on Carbon Steel specimens (X65, A106) were studied in simulated solution of 3 wt.% NaCl. The specimens were immersed into the CO2 containing solution for 48 hours and corrosion behaviour was investigated by using electrochemical test like Linear Polarization Resistance and Tafel plot. The results indicate that the temperature has an important effect of corrosion rate of carbon Steel in CO2 environment. Corrosion rate of 1.5-2 mm/yr was reported for both steels at lower temperature while at higher temperature the difference can be observed due to difference in protective nature of steels. Similar Corrosion rate around 1.5 -2 mm/yr was observed at 25°C for both A106 and X65 while at 50°C and 75°C the corrosion rate varies significantly 1.5-3 mm/yr and 3.5-6 mm/yr.

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The Use Of Carbon Steel Tubulars In Highly Sour Oil And Gas Production Systems

10.2118/114140-ms ◽

2008 ◽

Author(s):

Graeme Dicken ◽

Ken Bruce ◽

Barry Johnson ◽

Mohamed Juma Al-ghafri

Keyword(s):

Carbon Steel ◽

Oil And Gas ◽

Production Systems ◽

Gas Production ◽

Oil And Gas Production

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The inhibition performance of mono-ethylene glycol on corrosion rate of x-80 grade carbon steel in saturated brine environment.

African Journal of Engineering and Environment Research ◽

10.37703/ajoeer.org.ng/q12020/03 ◽

2020 ◽

Vol 1 (1) ◽

Keyword(s):

Acetic Acid ◽

Charge Transfer ◽

Carbon Steel ◽

Corrosion Rate ◽

Ethylene Glycol ◽

Oil And Gas ◽

Gas Production ◽

Electrochemical Measurements ◽

Co2 Corrosion ◽

Formation Water

The formation/deposition of hydrate and scale in gas production and transportation pipeline has continue to be a major challenge in the oil and gas industry. Pipeline transport is one of the most efficient, reliable and safer means of transporting petroleum products from the well sites to either the refineries or to the final destinations. Acetic acid (HAc), is formed in the formation water which also present in oil and gas production and transportation processes. Acetic acid aids corrosion in pipelines and in turn aids the formation and deposition of scales which may eventually choke off flow. Most times, Monethylene Glycol (MEG) is added into the pipeline as an antifreeze and anticorrosion agent. Some laboratory experiments have shown that the MEG needs to be separated from unwanted substance such as HAc that are present in the formation water to avoid critical conditions in the pipeline. Internal pipeline corrosion slows and decreases the production of oil and gas when associated with free water and reacts with CO2 and organic acid by lowering the integrity of the pipe. In this study, the effect of Mono-Ethylene Glycol (MEG) and Acetic acid (HAc) on the corrosion rate of X-80 grade carbon steel in CO2 saturated brine were evaluated at 25oC and 80oC using 3.5% NaCl solution in a semi-circulation flow loop set up. Weight loss and electrochemical measurements using the linear polarization resistance (LPR) and electrochemical impedance spectroscope (EIS) were used in measuring the corrosion rate as a function of HAc and MEG concentrations. The results obtained so far shows an average corrosion rate increases from 0.5 to 1.8 mm/yr at 25oC, and from 1.2 to 3.5 mm/yr at 80oC in the presence of HAc. However, there are decrease in corrosion rate from 1.8 to 0.95 mm/yr and from 3.5 to 1.6mm/yr respectively at 25oC and 80oC on addition of 20% and 80% MEG concentrations to the solution. It is also noted that the charge transfer with the electrochemical measurements (EIS) results is the main corrosion controlling mechanism under the test conditions. The higher temperature led to faster film dissolution and higher corrosion rate in the presence of HAc. The EIS results also indicate that the charge transfer controlled behaviour was as a result of iron carbonate layer accelerated by the addition of different concentrations of MEG to the system. Key words: CO2 corrosion, Carbon steel, MEG, HAc, Inhibition, Environment.

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Evaluation of Calcium Carbonate Inhibitors Using Sintered Metal Filter in a Pressurized Dynamic System

Materials ◽

10.3390/ma12111849 ◽

2019 ◽

Vol 12 (11) ◽

pp. 1849 ◽

Cited By ~ 1

Author(s):

Adriana Velloso Alves de Souza ◽

Francisca Rosário ◽

João Cajaiba

Keyword(s):

Calcium Carbonate ◽

Dynamic System ◽

Heterogeneous Nucleation ◽

Oil And Gas ◽

Production Systems ◽

Dynamic Test ◽

Gas Production ◽

Oil And Gas Production ◽

Sintered Metal ◽

Organophosphorus Inhibitors

Calcium carbonate scale is formed during oil and gas production. Tube-blocking tests (TBTs) are used to define the minimum inhibitory concentration (MIC) in order to prevent scale adhesion in the petroleum production system equipment. However, non-adhered crystals may favor heterogeneous nucleation to other deposits such as calcium naphthenates, causing a more severe scale problem, increasing production losses and treatment costs. The objective of the present work was to develop a new dynamic test methodology to determine the MIC for CaCO3 using a sintered metal filter. Organophosphorus inhibitors were selected for comparison with the conventional dynamic tube-blocking system. The results demonstrated that the use of the filter allowed an MIC of the inhibitors to be obtained considering the precipitation prevention. The inhibitor concentration in the conventional tube-blocking system does not prevent precipitation, acting only on adhesion and crystal growth on the capillary wall. Tests to evaluate the potential of calcium naphthenates formation in a naphthenate flow rig dynamic system demonstrated the influence of heterogeneous nucleation from non-adhered carbonate crystals, potentially aggravating deposition problems in oil and gas production systems.

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Exergoeconomic Optimization of Oil and Gas Production Systems

10.2118/200607-ms ◽

2020 ◽

Author(s):

Meziane Akchiche ◽

Jean-Louis Beauquin ◽

Sabine Sochard ◽

Sylvain Serra ◽

Jean-Michel Reneaume ◽

...

Keyword(s):

Oil And Gas ◽

Production Systems ◽

Gas Production ◽

Oil And Gas Production

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Erosion of Elbows in Oil and Gas Production Systems

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.479-481.1129 ◽

2012 ◽

Vol 479-481 ◽

pp. 1129-1132

Author(s):

Wang Ming Bo

Keyword(s):

Oil And Gas ◽

Production Systems ◽

Oil And Gas Industry ◽

Gas Production ◽

Gas Industry ◽

Oil And Gas Production ◽

Sand Erosion ◽

The Subject ◽

Erosion Mechanisms ◽

Definitive Methods

This paper gives an overview of erosion mechanisms in elbows in oil and gas production systems. The nature of the erosion process itself makes it very difficult to develop some definitive methods or models to prevent or predict the erosion in elbows in all conditions. This paper provides a review of the subject which will help petroleum engineers to handle the erosion problems in oil and gas industry. This review is given of different erosion mechanisms connected with sand erosion and the factors that influence them, and then the review goes on to look at particulate erosion in elbows in more details. Conclusions are then drawn based on the above analyses.

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A Method for the Verification of Subsea Equipment Subject to Hydrogen Induced Stress Cracking

29th International Conference on Ocean, Offshore and Arctic Engineering: Volume 5, Parts A and B ◽

10.1115/omae2010-20149 ◽

2010 ◽

Author(s):

Michelangelo Fabbrizzi ◽

Paolo Di Sisto ◽

Roberto Merlo

Keyword(s):

Oil And Gas ◽

Production Systems ◽

Local Stress ◽

Gas Production ◽

Stress And Strain ◽

3D Analysis ◽

Oil And Gas Production ◽

Safety Issues ◽

Stress Cracking ◽

Induced Stress

Subsea oil and gas production systems can be subject to Hydrogen Induced Stress Cracking (“HISC”) depending on the material, cathodic protection and other factors. A failure in this kind of systems can lead to safety issues as well as environmental hazards and high repair costs. The analysis of recent failures has led to the recognition of HISC as a very important issue related to local stress and strain. This has necessitated the extensive use of Finite Elements Methods for the analysis of all system components. Since HISC is a recent issue, there are very few cases of such assessments reported in the literature. This paper is based on the assessment of the susceptibility of subsea piping manifolds of Duplex stainless steel to Hydrogen Induced Stress Cracking, which was conducted during the Skarv project by General Electric Oil & Gas. A variety of cases consisting of different loads and configurations were considered to give a broad assessment using a recently developed code (DNV-RP-F112-October2008). This work has led to the development of a set of procedures and models for the assessment of the entire system which is described in the current paper. The proposed methodology is useful for both design purposes and also for the verification of parts, which, if found to be non-compliant, would require redesign. In general, parts that were determined to be non-compliant using a linear assessment were found to be compliant through non-linear analysis, in fact 3D plastic analysis leads to a redistribution of stress and strain and hence, to lower values. “Cold creep” was not considered since the levels of stress and strain were considered to be low enough to avoid this phenomenon. As a consequence of this experience, a new methodology was developed, which is able to speed up the analysis process and to predict local stresses from only pipe elements. The latter permits the use of a linear assessment for bends, T junctions and weldolet even with misalignment and erosion, avoiding the need to perform 3D analysis. The second part of the paper describes this method.

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Experience With Qualification and Use of Stainless Steels in Subsea Pipelines

23rd International Conference on Offshore Mechanics and Arctic Engineering, Volume 2 ◽

10.1115/omae2004-51536 ◽

2004 ◽

Cited By ~ 3

Author(s):

Per Egil Kvaale ◽

Tore Ha˚brekke ◽

Gisle Ro̸rvik

Keyword(s):

Stainless Steels ◽

Oil And Gas ◽

Production Systems ◽

Gas Production ◽

Inconel 625 ◽

Oil And Gas Production ◽

Internal Corrosion ◽

Carbon Manganese Steels ◽

Subsea Pipelines ◽

Incoloy 825

Use of stainless steels in subsea oil and gas production systems have been common through the development of remote controlled subsea oil and gas production systems. Stainless steels are mainly selected to minimize the corrosion due to unprocessed oil and gas and thereby simplifying the internal corrosion protection challenges. Different materials and principles have been implemented from cladding of Carbon Manganese steels to the use of solid stainless steels. For cladding Incoloy 825 or Inconel 625 is common, while the solid stainless steels have been duplex, superduplex or 13%Cr steels in pipes and pipe fittings. Experience from service has shown that these materials have limits in their use, and it is reported various cases where the stainless steels have failed. The present paper will deal with a few examples of failures and possible reasons for these failures.

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