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Oxygen Corrosion Control for Multiphase and Gas Phase Pipelines

Picture for Oxygen Corrosion Control for Multiphase and Gas Phase Pipelines
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Produced fluids in O&G sector in general do not contain oxygen, but oxygen ingress can occur at locations. Examples of such spaces can include but not limited to vapor space in tanks, custody transfers, injection pumps, vapor recovery systems, operating pumps with faulty seals, pipelines that are not properly purged of oxygen during commissioning operations, gas lift operations, methanol use or pigging operations.
This contamination of O2 in sweet/sour systems can lead to oxygen induced corrosion and may cause high general and pitting corrosion rates and failures.

Product Number: MECC23-20154-SG
Author: Geeta Rana; Henry Garlick; Caleb Clark; Jeremy Moloney
Publication Date: 2023
$20.00
$20.00
$20.00

The presence of small amounts of oxygen can pose a severe threat to the integrity of oil & gas pipelines and contribute to sharp increase in corrosion rates and metal loss in gas pipeline infrastructure. In general technologies such as catalytic oxidation and the solid beds towers can be used along with engineering solutions to control oxygen ingress. However, many operators prefer to use chemical treatment for mitigating oxygen corrosion, but commercially available oilfield corrosion inhibitors do not provide adequate corrosion protection under elevated levels of oxygen; hence, a new product was developed.


This work highlights the development and qualification of a corrosion inhibitor that can provide excellent corrosion protection in gas and multi-phase applications where oxygen can be of concern. Performance evaluations were performed in sweet systems containing oxygen using O2 + CO2 gas mixtures in rotating cylinder electrode (RCE) testing. The oxygenated RCE test matrices varied the temperature, shear, and pH; the product was successful at mitigating corrosion at about 90% protection (under the conditions evaluated. Blank corrosion rate ranged from (100mpy -25mpy) at different shear, temperature and pH, while inhibited corrosion rates ranged from (10mpy -20mpy). Both localized corrosion and general corrosion measurements were conducted.


Laboratory evaluations were also conducted under sour conditions in the presence of oxygen in rotating cage autoclave (RCA) and the product passed with general corrosion rate (<4mpy) and localized corrosion criteria (no features above 20 μm), which translates to 3.59 mpy in pit rate. Field trial results with the product will also be discussed.

The presence of small amounts of oxygen can pose a severe threat to the integrity of oil & gas pipelines and contribute to sharp increase in corrosion rates and metal loss in gas pipeline infrastructure. In general technologies such as catalytic oxidation and the solid beds towers can be used along with engineering solutions to control oxygen ingress. However, many operators prefer to use chemical treatment for mitigating oxygen corrosion, but commercially available oilfield corrosion inhibitors do not provide adequate corrosion protection under elevated levels of oxygen; hence, a new product was developed.


This work highlights the development and qualification of a corrosion inhibitor that can provide excellent corrosion protection in gas and multi-phase applications where oxygen can be of concern. Performance evaluations were performed in sweet systems containing oxygen using O2 + CO2 gas mixtures in rotating cylinder electrode (RCE) testing. The oxygenated RCE test matrices varied the temperature, shear, and pH; the product was successful at mitigating corrosion at about 90% protection (under the conditions evaluated. Blank corrosion rate ranged from (100mpy -25mpy) at different shear, temperature and pH, while inhibited corrosion rates ranged from (10mpy -20mpy). Both localized corrosion and general corrosion measurements were conducted.


Laboratory evaluations were also conducted under sour conditions in the presence of oxygen in rotating cage autoclave (RCA) and the product passed with general corrosion rate (<4mpy) and localized corrosion criteria (no features above 20 μm), which translates to 3.59 mpy in pit rate. Field trial results with the product will also be discussed.

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AMPP Guide 21532-2023, Guideline for Materials Selection and Corrosion Control for CO2 Transport and Injection

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The purpose of this document is to provide guidance on materials selection and corrosion control for engineers in the design and identification of operating limits for projects that involve CO2 transport and injection. It should be used as a guide to help identify specific requirements which can be tailored for each project rather than as definitive requirements used straight from the document. References are also made to other relevant documents and standards. The guidance provided for an initial design should help the engineer focus on the most critical issues related to CO2 transport and injection. It is a rapidly growing subject area and much exploratory technical work is still being executed, and as such this document should be seen as a starting point with future updates and new insights to be expected.
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AMPP TM21451-2023, Evaluation of Carbon and Low-Alloy Steels for Resistance to Stress-Oriented Hydrogen-Induced Cracking (SOHIC)

Product Number: AMPP TM21451-2023
Publication Date: 2023
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Carbon and low-alloy steels in plate form and their welded products may be susceptible to one or more forms of environmental cracking when exposed to wet H2S service conditions. These include, for example, (1) sulfide stress cracking (SSC) of hard zones and welds; (2) hydrogen-induced cracking (HIC) in the parent metal; and (3) stress-oriented hydrogen-induced cracking (SOHIC) in the region adjacent to welds of nominally acceptable hardness. Extensive work has been conducted over many years to understand various fundamental and applied aspects of these phenomena. Experiences in refinery wet H2S operations have directed particular attention to understanding SOHIC and the various metallurgical and environmental parameters that govern its occurrence.

 

Scope

 

This standard was prepared to provide a test method for consistent evaluation of pipeline and pressure vessel steels to SOHIC caused by hydrogen absorption from aqueous sulfide corrosion. The test conditions are not designed to simulate any specific service environment. The test is intended to evaluate resistance to SOHIC only, and not to other adverse effects of sour environments such as sulfide stress cracking (SSC), pitting, or mass loss from corrosion.

 
Picture for NACE SP0113-2023, Pipeline Integrity Management: Methods Selection and Implementation
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NACE SP0113-2023, Pipeline Integrity Management: Methods Selection and Implementation

Product Number: NACE SP0113-2023
Publication Date: 2023
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This standard practice provides guidance on selecting and implementing the Pipeline Integrity Management (PIM) methods (i.e., technologies and processes) to assess and to mitigate threats to pipeline integrity. Predominant threats to pipeline integrity are external corrosion (EC), internal corrosion (IC), stress corrosion cracking (SCC), mechanical damage (first, second, and third party or vandalism), equipment malfunctioning, manufacturing anomalies, construction anomalies, incorrect operations, weather-related, and external forces. The standard is focused on the “selection” and “implementation” of methods and best practices to manage pipeline integrity, but not necessarily on defining all aspects of PIM programs. 
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