Pan Shi Case Library – Case Sharing | Ammonia Extraction System on the Side Line of an Acidic Water Stripping Unit: Alkaline‑Acidic Water Corrosion

Background

The secondary and tertiary condenser‑cooler units of an enterprise’s acidic water vapor stripping system have experienced leaks: the secondary condenser‑cooler has leaked seven times, and the tertiary condenser‑cooler has leaked five times. Consequently, the tube bundle material of both heat exchangers was upgraded from 10# steel to S22053. After eight months of operation, the tertiary condenser‑cooler leaked again. The basic equipment information is as follows:

 

Corrosion Inspection and Testing Status

1. Corrosion Inspection Status on the Shell Side

Upon opening the equipment for inspection, it was found that the upper half‑tube bundle and tube sheets on the west side, as well as the tube openings, exhibited significant scaling—viscous and gray in appearance. In some tube openings, scale had accumulated to nearly one‑third of the cross‑section. By contrast, scaling on the lower half‑tube bundle and on the east‑side tube sheets and tube openings was minor, as shown in Figure 2‑1.

 

Figure 2-1 Morphology of Scale Deposits on the Tube Sheet and Tube Ends Prior to Cleaning

Following a simple rinse, no obvious corrosion was observed on the tube sheet or tube ends, as shown in Figure 2-2.

Figure 2-2 Morphology of the tube sheet after cleaning

A layer of white fouling is adhering to the inside of the tube bundle, as shown in Figure 2-3.

Figure 2-3 Morphology of the tube bundle interior

Inspection and pressure testing revealed a total of six leaking heat exchange tubes, with three in each of the first and second tube passes. Based on the leakage morphology, the perforations were primarily caused by external surface corrosion of the tubes. The identified perforation locations ranged from near the west‑side tube sheet to near the east‑side tube sheet, at distances of 410–2050 mm from the tube sheets, and the hole sizes varied; see Figures 2–4.

   

 

Figure 2-4: Location and Morphology of Perforations in Leaking Heat Exchange Tubes

2. Corrosion Inspection Status on the Shell Side

Localized black deposits are adhering to the outer surface of the tube bundle in the third‑stage condenser cooler, with a thicker fouling layer near the bottom. In addition, white spotted deposits are present in certain areas on the tube bundle surface. Visual inspection of the tube bundle exterior revealed no obvious signs of corrosion (see Figure 2‑5). Thickness measurements of the heat exchange tubes yielded values ranging from 2.3 to 2.5 mm (design wall thickness: 2.5 mm), with no significant wall thinning detected.

Figure 2-5: Surface morphology of the tube bundle exterior

The mid‑lower portions of the shell at both end inlets exhibit distinct, uniform corrosion‑induced wall thinning, with multiple vertical grooves accompanied by pitting. Black deposits are observed on the surface; the deepest grooves measure approximately 3–8 mm in depth. Corrosion‑induced wall thinning diminishes as one moves toward the interior from both ends, and no significant corrosion is evident at the top inlet. See Figure 2‑6 for details.

Figure 2-6 Corrosion Morphology of the Housing

3. Tube Bundle Eddy Current Inspection Results

Based on the eddy‑current inspection results for this third‑stage condenser cooler, a total of 582 heat‑transfer tubes were examined out of 588. Among these, 110 tubes exhibited wall‑thickness loss exceeding 60%, 51 tubes showed wall‑thickness loss between 40% and 60%, and 22 tubes had wall‑thickness loss ranging from 30% to 40%. The remaining tubes all had wall‑thickness loss below 30%. Heat‑transfer tubes with wall‑thickness loss greater than 40% and exhibiting perforations accounted for 28.4% of the total; however, the vast majority of these were located in the lower tube bundle, representing 55.1% of the total tubes in that section, as detailed in Figure 2‑7.

 

Figure 2-7 Eddy Current Inspection Results of the Three-Stage Condenser Cooler Species distribution map and selected illustrations

4 Macroscopic and Low-Magnification Morphological Observation

A 1700‑mm‑long tube bundle was extracted from the third‑stage condenser cooler for inspection, and it was divided into 17 zones from left to right (each zone spanning 100 mm). The outer surface of the inspected tube bundle exhibited varying morphologies (damage conditions) across different regions, as shown in Figure 2‑8.

 

The outer surfaces of the tube bundles in Zone 1 are generally smooth, with no obvious pitting or cracks observed, as shown in Figure 2-9.

 

Small pitting corrosion was observed on the outer surface of the tube bundle, resulting in variations in wall thickness, as shown in Figure 2-10.

 

Obvious circumferential grooves and significant variations in the outer wall thickness were observed on the tube bundle in Zone 7, as shown in Figure 2-11.

 

The outer wall of the tube bundle in Zone 9 exhibits distinct pitting, with evidence of fluid erosion, as shown in Figure 2-12.

 

Honeycomb‑like corrosion pits and wall thinning were observed on the outer surfaces of the tube bundles in Zones 10 and 15, as shown in Figures 2‑13 and 2‑14.

 

Overall, the damage to the tube bundle occurs on its outer wall surface, manifesting as pitting corrosion at various locations along the outer wall. These pits are either densely clustered or sparsely distributed, and their morphologies exhibit both under-deposit corrosion and erosion‑corrosion characteristics. The initiation and progression of these pits lead to varying degrees of wall thinning—from the exterior toward the interior—eventually resulting in perforation and leakage.

 

 

Figure 2-8 Macroscopic morphology of the outer surface of the tube bundle submitted for inspection

 

 

Figure 2-9 Low-magnification morphology of the outer surface of the tube bundle (Zone 1)

 

Figure 2-10 Low-magnification morphology of the outer surface of the tube bundle (Zone 3)

 

Figure 2-11 Low-magnification morphology of the outer surface of the tube bundle (Zone 7)

 

Figure 2-12 Low-magnification morphology of the outer surface of the tube bundle (Zone 9)

 

Figure 2-13 Low-magnification morphology of the outer surface of the tube bundle (Zone 10)

 

Figure 2-14 Low-magnification morphology of the outer surface of the tube bundle (Zone 15)

Process Flow Overview

The side‑draw gas from the acidic water stripper is withdrawn from trays 18, 20, and 22 of the main stripper. After undergoing three stages of condensation and cooling—first by heat exchange with the feed water, second by cooling with purified water, and third by cooling with circulating water—and three stages of fractional condensation, it yields high‑concentration crude ammonia gas. The process flow is shown in Figure 3‑1.

Figure 3-1 Process Flow Diagram of the Three‑Stage Condenser Cooler E‑0207

Corrosion Analysis

The failure mode of the tube bundle is attributed to H2S–NH3–H2O corrosion in the shell-side fluid and under‑deposit corrosion caused by ammonium salts. Based on the corrosion morphology, the damage is primarily initiated by pitting and localized corrosion on the outer surface of the tubes; following perforation, the shell-side fluid leaks into the tube side and induces erosion‑corrosion.

 

The condenser shell-side feed is ammonia-rich gas at approximately 90°C, and the outlet consists of ammonia‑rich gas and condensate at around 40°C, with the vapor-phase ammonia mass fraction exceeding 70%. In systems where ammonia and hydrogen sulfide coexist, the hydrogen sulfide mass fraction in the vapor phase is very low, leading to the formation of ammonium hydrosulfide (NH4HS), which can corrode acid‑water stripping units. The concentration and flow rate of the NH4HS aqueous solution influence the corrosion rate; increasing the flow rate not only accelerates corrosion but also induces erosion‑corrosion by ammonium salts. At temperatures below 120°C, ammonium hydrosulfide precipitates as crystals, and areas with lower flow rates are prone to scaling, which can cause equipment blockage and under‑deposit corrosion.

 

Within the equipment, a rich ammonia‑rich gas–liquid two‑phase flow is present, and corrosion is primarily concentrated in the initial condensation zone, along the liquid‑phase flow paths—especially at locations where the flow direction changes—and in areas prone to fouling. When the NH4HS concentration is high and the fluid velocity is also elevated, even materials with relatively good corrosion resistance can experience significantly elevated corrosion rates. Erosion caused by the scouring action of ammonium salt solutions leads to the detachment of corrosion products; the stronger the erosion, the more extensive the detachment, exposing fresh, active surfaces that in turn promote further corrosion. This cyclical process accelerates equipment degradation, resulting in continuous pitting, material loss, and thinning of wall thickness, ultimately culminating in perforation and failure.

 

Although the condenser‑cooler tube bundle is made of highly corrosion‑resistant 2205 duplex stainless steel, the increasing H₂S concentration in the condensate and the elevated flow velocity both exacerbate corrosion. Moreover, factors such as pH, temperature, chloride ions, CO₂, and cyanide also exert significant influence on corrosion. In addition, the shell‑side geometry is complex; when the flow rate is insufficient, chloride ions can become highly concentrated in stagnant or fouled regions, potentially exceeding the pitting‑corrosion resistance limit of 2205. Based on a review of international literature and analysis of experimental results, industry experts have determined that, under a high‑concentration NH₄HS‑dominated corrosion regime (pH > 9), the corrosion resistance of common metallic materials ranks as follows: 2205 < 316 < carbon steel < 825 < C276. Consequently, 2205 cannot withstand the corrosive effects of the acidic water medium within the condenser‑cooler. This finding is consistent with the observed reduction in tube‑bundle life following the upgrade to duplex stainless‑steel tubing.

 

Conclusions and Recommendations

1. Conclusion

Based on the above analysis, it is determined that the corrosion‑induced leakage of the third‑stage condenser–cooler in the hydrogenation‑type acidic water stripping unit is primarily attributable to hydrogen on the shell side. ₂ S+NH ₃ +H ₂ It is caused by pitting corrosion and under-deposit corrosion, with the corrosion primarily occurring in the primary condensation zone, along the liquid-phase flow paths, and at locations where deposits accumulate. Corrosion is exacerbated at flow‑direction changes and in stagnant regions.

2. Recommendations

(1) Due to severe wall thinning of the tube bundle in the third-stage condenser cooler, it is recommended to stock a new tube bundle for replacement. The material for the new tube bundle is advised to revert to the previous 10#+ coating; coating quality must be ensured. In the short term, the lower half of the tube bundle may be temporarily bypassed and put into service.

(2) It is recommended to recalculate the process operating parameters of the three‑stage condenser–cooler and implement technical upgrades to the equipment, particularly regarding the diameters of the circulating water inlet and outlet pipes. Under operating conditions at the lower end of the design range, these pipe diameters must ensure compliance with process requirements as well as the specified single‑pipe flow velocity and outlet temperature of the circulating water. This will reduce the risk of scaling and corrosion on the tube side of the new tube bundle and extend the equipment’s service life.

(3) It is recommended to consider adding water injection at the shell‑side inlets of the second‑stage and third‑stage condenser coolers (which has already been implemented) to mitigate severe under‑deposition corrosion on the shell side and corrosion in the primary condensation zone.

(4) Due to severe localized corrosion and wall thinning of the shell of the third-stage condenser cooler, internal localized patching and external carbon-fiber reinforcement have been implemented. It is recommended to stock spare parts for replacement during the major overhaul.

(5) It is recommended to install an online corrosion‑monitoring probe on the pipeline between the third‑stage condenser and the third‑stage fractionator.

 

Zhongke Weier Anticorrosion Technology Center

 

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