The corrosion-fouling cycle in amine systems
Recommendations to reduce the impact of the mechanisms of corrosion in amine systems.
ROBERT JAMES, Pall (Canada)
ALI ARSHAD, Pall Corporation
Viewed : 2292
Corrosion is a costly problem in the oil and gas production industry, estimated at almost $1.4 billion,1 with significant safety and exposure risk. It continues to be an industry challenge due to its complexity and difficulty to fully resolve. Revenue loss from an amine plant shutdown due to corrosion is significant. Consider a 100 MMSCFD gas plant offline due to corrosion-related repairs, with natural gas selling at $3.25/MMBTU, the gas revenue loss is $335 000 per day. In a refinery, inability of the acid gas removal unit (AGRU) to treat acidic refinery fuel gas (RFG) coming from unit operations may reduce the ability of the refinery to run at capacity, cutting back on refinery output of final products such as gasoline and diesel. If a 100000 b/d refinery is forced to run 10% (10000 b/d) below capacity due to AGRU issues, and assuming refinery products are averaging a selling price of $2/gal, revenue loss is in the range of $840 000/day.
To minimise amine unit corrosion, many factors need to be considered, from original design to operation, maintenance and troubleshooting. Effective corrosion management is an important aspect of amine system management. In this article, we will review a range of amine system corrosion management issues and focus on the ability of effective solids management to reduce corrosion issues.
Amine loop corrosion
Hydrogen sulphide (H2S) and carbon dioxide (CO2) are the most common sour components in need of removal from sour gas streams. Each has a different corrosive action. H2S corrosion seeks to form a protective iron sulphide layer on the metal surface that is relatively robust. CO2 forms an iron carbonate (FeCO3) layer that is more fragile and prone to erosive damage.
The basic corrosion reactions for dissolved H2S species are:11
H2S(aq) + Fe(s) → FeS(s) + H2(g) (1)
2HS-(aq) + Fe(s) → FeS(s) + H2(g) +
And for CO2:
CO2(aq) + Fe(s) +H2O → FeCO3(s) + H2(g) (3)
2HCO3-+ 2Fe(s) → 2FeCO3(s) + H2(g) + 2e- (4)
Mechanisms of corrosion and industry recommendations
Actual amine system corrosion manifests itself in many ways. A sampling of the corrosion mechanisms and industry or Pall recommendations for mitigation are noted in the following sections.
Amine solution carbon steel corrosion
Nielsen et al2 offer an expansion on the subject of amine solution corrosion of carbon steel discussed below. It is a broad area that can include many issues such as:
• High operating temperatures
• Amine type and concentration
• High rich and lean amine loadings
• Acid gas type and CO2 to H2S ratio in the acid gas
• Amine solution contaminants including amine degradation products and heat stable salts (HSS).
High operating temperatures/amine type
Move to secondary and tertiary amines for reduced corrosion. Primary amines such as MEA and DGA regenerate at the highest temperatures, leading to greater corrosion as high concentrations of acid gases are present in the hottest areas of the process. Secondary and tertiary amines are more easily stripped of H2S and CO2 at a lower temperature, and so are less corrosive, with a tertiary amine such as MDEA being the lowest.
High rich and lean amine loadings
Richer amine solutions have been found to be more corrosive than leaner solutions. Look to recognised guidelines for maximum rich and lean solution loadings. Undegraded MEA solutions are more corrosive because of their stronger base properties, so consider a move to secondary or tertiary amines. HSS and amine degradation products have been shown to strongly affect corrosion rates, so (a) seek to keep HSS below 1 wt%, (b) select activated carbon with higher iodine number for increased adsorptive capacity, and high molasses number, indicative of a larger average carbon pore size that more effectively remove degradation products versus hydrocarbons, and (c) look to alternative equipment such as high efficiency liquid/liquid coalescers for hydrocarbon removal. Control amine regenerator corrosion by controlling the stripping operation – for instance, a maximum amount of steam per unit of rich amine, and proper reflux ration in the overhead. Work with your amine supplier for optimum values. Avoid high rich amine loadings by increasing amine concentrations as long as there is enough reboiler capacity to regenerate the solution.
CO2 to H2S ratio
API 9453 “Avoiding Environ-mental Cracking in Amine Units” advises to maintain the H2S to CO2 ratio to be greater than 1:19 (>5% H2S) to drive formation of the more protective iron sulphide layer versus the weaker FeCO3 layer. For higher CO2 loadings, stay within maximum amine velocity limitations and consider solids control to reduce particulate erosion of the weaker FeCO3 protective layer. API 9453 recommends a maximum amine velocity of 1.8 m/sec (5.5 ft/sec) for carbon steel internals. Velocities at or below this recommended value, along with maintaining clean amine solutions in the 1-5 wppm range to reduce erosive wear, may allow for retention of the weaker FeCO3 layer to reduce system corrosion. The section on ‘Erosion-corrosion’ deals with this in more detail.
Amine solution contaminants
Strong acids react with amines to form HSS; that is, not thermally reversible salts. Keep them from entering the amine system with upstream water washes and/or high efficiency liquid/gas coalescers. When present in the amine solution, consider removal via operations such as reclaiming or ion exchange, or via neutralisation with products such as soda ash or caustic soda.
Wet CO2 corrosion
When an aqueous phase is present and if only CO2 is present, CO2 will dissolve in water to form carbonic acid (H2CO3). Direct reduction forms the weak FeCO3 protective layer on carbon steel surfaces as per Equation 3. CO2 corrosion rates rise with increasing partial pressure of CO2 and temperature of the system up to 71°C (160°F), after which a protective Fe3O4 corrosion product forms that decreases corrosion rate with increasing temperature. This temperature is often referred to as the scaling temperature. These findings have been correlated into an equation by DeWaard and Lotz.4 The equation incorporates a wide range of corrosion rate factors that can reduce the base rate of corrosion in CO2 systems – temperatures above 71°C (160 °F), presence of H2S in the ppm range, higher water pH, and others. Use of corrosion predictive software, described later in the article, provides state-of-the-art capability in calculating expected rates of corrosion.
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