Save 20% on select titles with code HIDDEN24 - Shop The Sale Now
The corrosion behaviour of X65 steel in a mixed 1% H2S (in CO2) brine after exposure to a pure CO2-saturated brine at 40°C. The objective was to identify the scales formed and understand their effect on the corrosion performance of X65 steel upon transition from pure sweet to sour conditions.
We are unable to complete this action. Please try again at a later time.
If this error continues to occur, please contact AMPP Customer Support for assistance.
Error Message:
Please login to use Standards Credits*
* AMPP Members receive Standards Credits in order to redeem eligible Standards and Reports in the Store
You are not a Member.
AMPP Members enjoy many benefits, including Standards Credits which can be used to redeem eligible Standards and Reports in the Store.
You can visit the Membership Page to learn about the benefits of membership.
You have previously purchased this item.
Go to Downloadable Products in your AMPP Store profile to find this item.
You do not have sufficient Standards Credits to claim this item.
Click on 'ADD TO CART' to purchase this item.
Your Standards Credit(s)
1
Remaining Credits
0
Please review your transaction.
Click on 'REDEEM' to use your Standards Credits to claim this item.
You have successfully redeemed:
Go to Downloadable Products in your AMPP Store Profile to find and download this item.
In the present study, the precipitation kinetics of iron carbonate (FeCO3) and iron sulfide (FeS) were studied over a range of temperatures to gain a better understanding of their effect on corrosion resistance.
Oil and gas production in a CO2 saturated environment is known to lead to corrosion due to dissolved carbonic acid. However, when the conditions are favorable, a protective FeCO3 layer can also form which reduces the material degradation of the underlying steel by up to ten or a hundred times.1 The formation of FeCO3 is possible via the reaction shown in equation 1.
Sweet (CO2) and sour (H2S) corrosion have continuously been a challenge in oil and gas production and transportation. Yet, some key issues are still not well understood, especially at high temperature production conditions. A CO2/H2S ratio of 500, which has been used (often inaccurately) to determine which corrosion mechanism is dominant, is probably even less valid at high temperature. The nature of the corrosion products forming at high temperature in CO2/H2S environments and their effects on the corrosion rate are not known. Finally, the impact on pipeline integrity of environmental changes between sweet and sour production conditions (simulating reservoir souring) has not been well documented. CO2, H2S, and CO2/H2S corrosion experiments were conducted at 120oC to investigate corrosion mechanisms and corrosion product layer formation at high temperature. The results show that the corrosion products were still clearly dominated by H2S under the pCO2/pH2S ratio of 550. Formation of Fe3O4, FeCO3, and FeS corrosion product layers had a direct impact on the measured corrosion rates and was dependent on the gas composition and on the sequence of exposure (CO2 then H2S and vice versa). Compared with H2S corrosion alone, the presence of CO2 could retard Fe3O4 formation in CO2/H2S mixture environment. No obvious change in steady state corrosion rate was observed when the corrosion environment was switched from CO2 to H2S and vice versa.
In aqueous carbon dioxide (CO2)-saturated environments, such as those found in geothermal energy, oil and gas and carbon abatement industries, various naturally occurring layers can be found on the internal surface of carbon steel infrastructure, such as pipelines, as they corrode in the mildly acidic conditions. Amongst the most commonly found layers are iron carbonate (FeCO3), iron carbide (Fe3C) and magnetite (Fe3O4). FeCO3 can offer corrosion protection to the underlying steel when formed under certain conditions, as too can Fe3O4. Fe3C is typically associated with enhancement of electrochemical activity of carbon steel and is revealed due to preferential dissolution of ferrite in the steel microstructure – through the formation of a porous network at the steel surface. Each of these layers play a fundamental role in the uniform and localized corrosion of the underlying carbon steel.
Hydrocarbons still remain as a fundamental contributor towards meeting the worldwide demand for energy, despite the growth of other alternative sources such as renewable and nuclear options. Due to low cost and availability, carbon steel, remains as the most commonly used material for pipelines in down and upstream activities within the oil and gas industry. However, carbon steel is not an exceptional metal alloy from the perspective of internal corrosion resistance. The economical cost for its degradation and related failures represent 10% to 30% of the maintenance budget in petroleum industry. It is therefore crucial that the corrosion of such a susceptible steel is managed and controlled accordingly.
Unbonded flexible pipes used for transporting process fluids in offshore oil and gas production systems have a complex structure, with alternate polymer and metallic layers. Tensile armors are metallic layers constructed by the helical wrapping of high strength carbon steel wires, and they are responsible for the integrity of the pipe. These armors provide axial strength and torsion resistance to the pipe so that it can sustain its own weight and resist to stresses associated to environmental conditions and vessel motion.