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Results
Top of Line Corrosion Testing for a Gas Field with Acetic Acid and Low CO2
Svenningsen, Gaute (Institute for Energy Technology) | Nyborg, Rolf (Institute for Energy Technology) | Torri, Lucia (ENI, Materials and Corrosion Technologies Dpt) | Cheldi, Tiziana (ENI, Materials and Corrosion Technologies Dpt) | Cavassi, Paolo (ENI, Materials and Corrosion Technologies Dpt)
Abstract Top of line corrosion (TLC) was studied in a flow loop under conditions representative for a gas field with a low CO2 partial pressure of 0.35 bar and presence of acetic acid in the gas. The temperature in the experiments was 60 and 90 °C, and Mono Ethylene Glycol (MEG) was present in the bulk aqueous phase. The water condensation rates used in the experiments were calculated from multiphase flow simulations for the planned pipelines. The experimental results showed that the condensed water contained both MEG and acetic acid. With this low CO2 partial pressure, the organic acids gave a significant contribution to the overall TLC rate. At 80 – 90 °C and high acetic acid, the TLC rates were 0.13 mm/y. When the organic acid content was reduced by 90 % the TLC rates were reduced with approximately 50 %. At 60 °C the condensation rates were lower but the iron solubility higher, and the TLC rate was 0.11 mm/y. Investigation of exposed corrosion coupons showed that a partly protective film of iron carbonate corrosion products had formed on the surface. The surface film reduced the TLC rate but did not provide full protection. The TLC rates measured in the experiments were lower than modelled TLC rates for cases with high organic acid content, showing that the TLC model was on the conservative side for such cases. Introduction Background This paper presents TLC work that was carried out in connection with a gas field with a low CO2 partial pressure of 0.35 bar and presence of organic acid. It is planned to use mono ethylene glycol (MEG) to prevent hydrate formation. Organic acids may accumulate in the MEG cycle, and this effect was included when the experimental content of organic acids was selected.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.94)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Abstract The occurrence of localized corrosion in Top of the Line Corrosion (TLC) was investigated in a sweet (CO2-dominated) environment, with a focus on understanding the influence of the environmental parameters on localized TLC in order to develop a narrative for the mechanism. A unique setup was developed for the experimental work, involving the use of carbon steel inserts exposed to three different levels of cooling at the same time. This concept was quite successful in simulating realistic localized features. A series of long term exposure (one- to three-month) experiments was conducted to investigate the controlling parameters. The occurrence of localized corrosion could be very clearly correlated to the condensation rate, the gas temperature and the organic acid content. Additional statistical information related to the morphology of localized TLC features could be made, providing useful insight on the mechanisms involved. Introduction When significant heat exchange is present between the wet gas pipelines and the surroundings (frozen land, deep-sea water, etc.), water and hydrocarbon vapor can condense on the inner pipe wall and lead to severe corrosion issues [1]. This phenomenon called Top of the line corrosion (TLC) is inherently a localized process. Corrosion occurs in specific areas along the line and the attack is not usually extended to large sections. This localized aspect is often related to situations where high condensation rates occur, i.e. where the gradient of temperature between the produced fluid and the outside environment is large. In sweet environments (CO2-dominated), the corrosion process is often characterized as a mesa attack: the steel is not uniformly corroded but the pits are usually wide, often flat-bottomed and bare of any layers, surrounded by areas with intact corrosion product layers. The localized nature of TLC is still not well understood. The corrosion features observed in the field can be so large that the corrosion process is often referred to as “localized uniform corrosion” instead of a just “localized corrosion”. The unique TLC scenario where droplets of condensed water appear and are renewed continuously at the metal surface must play a crucial role. It is likely that the condensation process initiates and promotes the localized corrosion at the top of the line by challenging the protectiveness of the iron carbonate layer.
Abstract In wet gas pipelines, Monoethylene glycol (MEG) is a widely used hydrate inhibitor which has been shown to decrease the corrosion rate of carbon steel in CO2 environments. In a top of the line corrosion (TLC) situation, MEG is also known to affect both water condensation and TLC rates. However, the extent of its effect on corrosion depends mainly on the concentration of MEG present in the condensed water. Until now, rather scarce and conflicting information exist on this topic. This work presents a mechanistic water/MEG co-condensation model in the presence of a noncondensing gas (CO2). The model predictions of condensation rate and MEG concentration in the condensing phase are compared with loop test results, showing good agreement. The results show that an increase of the MEG content at the bottom of the line decreases the water condensation rate and increases the MEG content of the condensing phase at the top of the line. However, this effect is not significant unless the MEG content in the bulk liquid phase is higher than 70-80 wt%. Long term corrosion experiments are also presented showing that the injection of 50 wt% and 70 wt% MEG at the bottom have a minimal effect on both general and localized corrosion rates. On the other hand, the presence of 90 wt% MEG at the bottom of the line decreased the top of the line corrosion rate significantly due to a sharp decrease in condensation rate and a significant increase in MEG content in the condensing phase. Introduction For economic reasons and operational flexibility, unprocessed wet gas is often directly transported in subsea pipelines to onshore processing plants for dehydration, rather than being dried on offshore platforms. During wet gas transportation, the water vapor in the gas phase will condense on the internal pipeline surface due to the difference of temperature between the wet gas stream and the outside environment, leading to top of the line corrosion (TLC). TLC is caused by the dissolution of corrosive gases, like carbon dioxide and hydrogen sulfide, in the condensed water. The presence of acetic acid can also enhance TLC. In sweet environment, the initially high rates of iron dissolution lead to the rapid development of a corrosion product layer (FeCO3) on the steel surface. The protectiveness of this layer is constantly challenged by the continuous condensation of water vapor and renewal of water droplets. At low water condensation rates, TLC rates remain manageable. At high water condensation rates, TLC can become a serious issue, leading to pipe failures. The water condensation rate has long been recognized as the key factor influencing the rate of top of the line corrosion in CO2 environments. In addition, top of the line corrosion can be a serious concern in the oil and gas industry due to the limited options for corrosion mitigation. The traditional corrosion inhibitors injected in the liquid phase at the bottom of the pipeline are often non-volatile and cannot reach the condensed water at the top of the line.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)