Panyi Case Library Case Sharing | Crude Oil Distillation Unit – Atmospheric Tower Top —— Leakage in the Tube Bundle of the Atmospheric Tower Top Gas–Crude Oil Heat Exchanger

Background

A leak occurred in the tube bundle of the atmospheric‑vacuum tower overhead gas–crude oil heat exchanger at a petrochemical company’s atmospheric‑vacuum distillation unit. Upon removal of the heat exchanger tube bundle, oil sludge was found inside the tubes. The tube bundle was designed for a 10‑year service life and has now been in operation for more than nine years.

The basic information of the device is as follows:

 

 

Physicochemical Testing and Analysis

1. Macroscopic and Low-Magnification Morphological Observation

The manufacturer submitted two heat exchange tubes for inspection; one exhibited perforation failure, while the other remained intact. The two tubes were designated as Tube No. 1 and Tube No. 2, respectively, as shown in Figure 1.

Tube No. 1 failed by perforation. The cracking and perforation of Tube No. 1 exhibited no obvious plastic deformation, indicating brittle fracture. Furthermore, the outer wall showed raised corrosion products, delamination‑induced cracking, and localized perforations, as illustrated in Figures 2 through 5.

Pipe No. 1 was longitudinally sectioned, and at the locations of cracking and perforation on its inner wall, corrosion product–induced bulging, delamination, and perforation were observed, as shown in Figures 6 through 10; by contrast, no corrosion product–related bulging, cracking, or perforation was detected on Pipe No. 2.

 

 

Figure 1. Macroscopic morphology of the outer surface of the titanium heat-exchanger tube bundle submitted for inspection.

 

Figure 2: Low-magnification morphology of the outer surface of tube bundle No. 1 (location 1 in Figure 3-1, showing a protrusion)

 

Figure 3: Low-magnification morphology of the outer surface of tube bundle No. 1 (two locations marked as 2 in Figure 3-1, showing cracking and spalling)

 

Figure 4: Low-magnification morphology of the outer surface of tube bundle No. 1 (three locations indicated in Figure 3-1, exhibiting cracking, spalling, and perforation).

 

Figure 5: Low-magnification morphology of the outer surface of tube bundle No. 1 (four locations shown in Figure 3-1, exhibiting cracking, spalling, and perforation)

 

Figure 6 Macroscopic morphology of the inner wall of tube bundle No. 1

 

Figure 7: Low-magnification morphology of the inner wall of tube bundle No. 1 (location 1 in Figure 6, protrusion)

 

Figure 8: Low-magnification morphology of the inner wall of tube bundle No. 1 (locations 2 in Figures 3–6, exhibiting cracking, spalling, and perforation)

 

Figure 9: Low-magnification morphology of the inner wall of tube bundle No. 1 (three locations shown in Figures 3–6, exhibiting cracking, spalling, and perforation).

 

Figure 10: Low-magnification morphology of the inner wall of tube bundle No. 1 (four locations shown in Figures 3–6, exhibiting cracking, spalling, and perforation)

 

2. Metallographic Examination and Hardness Test Results

Metallographic samples were taken from pipes No. 1 and No. 2, respectively. After preliminary grinding, polishing, and etching, the samples were examined and analyzed under a microscope, and their hardness was measured using a microhardness tester.

 

Corrosion pits have formed on the wall of tube #1, and corrosion products are present within these pits. Corrosion initiates and progresses on both the inner and outer surfaces of the tube bundle, with the inner-wall corrosion being more severe than that on the outer wall. The corrosion products exhibit lamellar cracking and spalling, leading to progressive thinning of the heat‑transfer tube walls and eventual perforation. In the microstructure of the tube wall at the corrosion pit, numerous acicular precipitates are observed; moreover, the closer one examines the region near the base of the pit, the greater the density of these acicular features. These acicular structures display characteristics typical of titanium hydrides, as shown in Figures 11 and 12.

 

No corrosion pits were observed on the inner or outer surfaces of pipe No. 2, indicating that hydrogen embrittlement did not occur in this pipe; its microstructure consists of the α phase, as shown in Figures 13 and 14.

 

The hardness of the bundle is:

The base metal (α phase) of pipe No. 1 has a Vickers hardness of HV0.3/15s = 138.8 (135.9, 139.0, 141.6), which is equivalent to HB 133.

 

The acicular microstructure of pipe No. 1 has an HV0.3/15s value of 209.2 (210.0, 207.7, 210.0), which corresponds to HB 199.

 

The corrosion products in the pitting on the inner wall of pipe #1 have a Vickers hardness of 420.1 (413.3, 403.1, 443.9) at 15 s, corresponding to a Brinell hardness of HB 399; see Figures 15 and 16.

 

Figure 11: Low-magnification metallographic microstructure of heat exchange tube No. 1

 

 

 

 

Figure 12 Metallographic microstructure of heat exchange tube No. 1

 

 

 

Figure 13: Low-magnification metallographic microstructure of heat exchange tube No. 2

 

 

Figure 3-14 Metallographic Microstructure of Heat Exchanger Tube No. 2

 

 

Figure 3-15 Metallographic Microstructure and Hardness of Heat Exchanger Tube No. 1

 

Figure 3-16 Metallographic Microstructure and Hardness of Heat Exchanger Tube No. 1

 

3. Results of Electron Microscopy and Energy-Dispersive Spectroscopy Analysis

Scanning electron microscopy was employed to examine the morphology and perform elemental analysis of the inner wall, outer wall, and cross-section at the perforation site of pipe No. 1.

(1) Inner wall

Corrosion occurred on the inner wall of pipe #1, with corrosion products in a flaky, layered form continuously spalling off, thereby accelerating the corrosion process until the pipe wall eventually developed a perforation. Energy-dispersive spectroscopy (EDS) analysis revealed that the corrosion products within the pitting on the inner surface of the heat-exchanger tube are primarily composed of carbon (C), oxygen (O), sulfur (S), chlorine (Cl), titanium (Ti), and iron (Fe). Among these, carbon originates from the oil–gas medium, while the concentrations of sulfur and chlorine are very low; the dominant elements are oxygen and titanium. The presence of iron indicates that the heat-exchanger tube has been contaminated by iron, as shown in Figure 17.

 

Figure 17 SEM+EDS of the inner wall at the perforation site of the heat exchange tube

 

(2) Outer wall.

The outer wall of pipe #1 also exhibited corrosion, with corrosion products in a laminar, flaky form continuously spalling off, thereby accelerating the corrosion process until it ultimately led to perforation of the pipe wall. Energy-dispersive spectroscopy (EDS) analysis revealed that the corrosion products within the pitting on the outer surface of the heat-exchanger tube are primarily composed of carbon (C), oxygen (O), sulfur (S), chlorine (Cl), titanium (Ti), and iron (Fe). Among these, carbon originates from the oil–gas medium, while the concentrations of sulfur and chlorine are very low; the dominant elements are oxygen and titanium. The presence of iron indicates that the heat-exchanger tube has been contaminated by iron, as shown in Figures 18–20.

Analysis of the energy-dispersive X-ray spectroscopy results indicates that the iron content on the outer wall of the heat exchanger tube—particularly at and near the perforation—is significantly higher than that on the inner wall, suggesting more severe iron contamination on the outer surface.

 

Figure 18 SEM+EDS of the outer wall at the perforation site of the heat exchange tube

 

Figure 19 SEM and EDS of the outer wall at the perforation site of the heat exchange tube

 

Figure 20 SEM+EDS of the outer wall near the perforation in the heat exchange tube

 

(3) Cross-section.

On the cross-section of the heat-exchanger tube, corrosion is observed to propagate continuously from both the inner and outer surfaces toward the tube wall, progressively eroding the wall material. Corrosion products exhibit a layered structure and undergo repeated spalling. Within the residual matrix embedded in the corrosion products and in the tube wall substrate near the pit bottom, needle‑like microstructures are present, showing a cracked morphology. Energy-dispersive spectroscopy reveals that the dark‑colored corrosion products within the pits consist of oxygen and titanium, identifying them as titanium oxides, whereas the needle‑like structures are primarily composed of titanium, with minor amounts of nitrogen and hydrogen, corresponding to titanium hydrides, as shown in Figure 21.

Electron microscopy analysis reveals that, at the corrosion sites of the heat-exchanger tubes, needle-like precipitates (hydrides) continuously erode the tube wall matrix, while titanium oxides are present on the outer surface of these needle-like structures.

 

Figure 21 BEM+EDS of the cross-section near the perforation in the heat exchange tube

 

4. Phase analysis results of the product

A number of corrosion products were scraped from the perforation site of pipe No. 1, and phase analysis was performed on these corrosion products.

XRD analysis of the corrosion products indicates that the corrosion products at the perforation site of Pipe No. 1 consist primarily of TiH2 and TiO2, as shown in Figure 22. The presence of TiH2 confirms the occurrence of hydrogen‑induced cracking in Pipe No. 1.

 

Figure 22 XRD spectra of corrosion products at the perforation site of the heat exchange tube

Failure Cause Analysis

1. Corrosion Mechanism Identification and Analysis

Studies [1–4] indicate that the corrosion of titanium equipment used in the chemical industry can be broadly categorized into four types: crevice corrosion, hydrogen embrittlement, stress corrosion, and iron contamination. These corrosion phenomena are influenced by factors such as material composition, design and fabrication, and process conditions. In general, stress corrosion of titanium is relatively rare, whereas iron contamination and hydrogen embrittlement are more common.

 

Titanium is a highly reactive metal that, in hydrogen‑rich corrosive environments, absorbs hydrogen and forms hydrides—titanium hydride. When the hydride content reaches a critical level, the metal’s impact toughness and elongation drop sharply, leading to failure under yield stress; this phenomenon is known as hydrogen embrittlement.

 

Titanium hydride is a compound formed when titanium reacts in a hydrogen‑containing environment. When the titanium surface is contaminated with iron or its oxide film is scratched, the electrode potential of titanium drops below the hydrogen evolution potential. Under such conditions, hydrogen generated by corrosion‑induced electrochemical reactions can be absorbed by the titanium, leading to hydrogen embrittlement. The likelihood of hydrogen embrittlement increases with rising temperature and pressure, and prolonged service in chemical processing equipment further promotes the gradual accumulation of absorbed hydrogen.

 

Titanium hydrogen embrittlement typically requires the fulfillment of three conditions:

1. The pH of the solution must be either less than 3 or greater than 12, or the metal surface must be damaged.
2. The temperature must be above 80°C.
3. There must be a mechanism for hydrogen production.

 

Titanium is essentially resistant to corrosion in reducing acids, but it exhibits significant hydrogen absorption, a phenomenon that can occur regardless of whether hydrogen is present in the corrosive environment. Hydrogen uptake renders titanium brittle. When iron or iron-rich phases form galvanic cells with the titanium matrix, localized dissolution ensues. During corrosion, the hydrogen atoms generated at the micro‑cathode are reluctant to recombine into molecular hydrogen and desorb from the metal surface; instead, nascent atomic hydrogen diffuses into the surface layer of titanium, leading to hydrogen embrittlement. Consequently, the higher the iron content in the corrosive medium, the faster the hydrogen diffusion rate, and the more severe the hydrogen absorption by titanium.

 

If iron contaminants—such as iron filings or rust—adhere to the surface of titanium, they can significantly accelerate the formation and diffusion of hydrogen at the titanium surface, leading to severe hydrogen absorption. This effect is particularly pronounced when titanium undergoes galvanic corrosion with iron; in such cases, hydrogen sulfide markedly enhances hydrogen uptake by the titanium. The embrittlement and flaky spalling that occur on the surface of titanium tubes due to hydrogen absorption are the primary causes of perforation failure. Following hydrogen absorption, the titanium surface typically turns gray‑black, while the inner surface becomes coated with a thick, flaky, loosely structured layer—resulting from the formation of hydrides. Titanium hydrides are highly brittle, readily fracturing, pulverizing, and peeling off. Hydrogen‑induced corrosion of titanium can generally be classified into three distinct scenarios:

1. Under conditions where hydrogen diffusion is relatively slow (below 300°C), brittle hydrides are localized exclusively at the titanium surface, leading to surface spallation and failure.
2. Hydrogen in the titanium matrix diffuses under stress, forming hydrides at regions of high stress intensity and generating microcracks within the hydrides or at the hydride–matrix interface; these cracks are further accelerated by the applied stress, ultimately leading to hydrogen‑induced cracking.
3. The titanium substrate undergoes severe hydrogen embrittlement upon substantial hydrogen absorption (>300°C).

 

In certain environments, titanium exhibits excellent corrosion resistance; however, if iron contamination is present on its surface and an oxide film has formed, the titanium becomes passive, acting as the cathode in galvanic corrosion while the iron serves as the anode, thereby initiating galvanic corrosion. Under these conditions, the oxidized titanium surface undergoes hydrogen evolution–induced corrosion, leading to hydrogen embrittlement.

 

Anode: Fe → Fe²⁺ + 2e⁻

Cathode: 2H⁺ + 2e⁻ → H₂ (using titanium with a passivation film on its surface as an inert electrode)

 

If the passive film on titanium is damaged at a site contaminated with iron, and the electrode potential of the surface‑covered titanium differs from that of the unpassivated titanium, electrochemical corrosion will occur. Furthermore, when titanium is in an active state, its standard electrode potential (−1.63 V) is lower than that of iron (−0.44 V), which accelerates titanium’s corrosion.

 

Titanium readily absorbs hydrogen, oxygen, and nitrogen, particularly hydrogen. Due to the small size of hydrogen atoms and their relatively rapid diffusion rate, titanium can easily absorb hydrogen even at moderate temperatures, forming titanium hydride (TiH2). This leads to embrittlement of the titanium, causing volumetric expansion, generating intergranular stresses, and ultimately resulting in crack formation.

 

The fluid inside the tube bundle of heat exchanger E2002 is overhead oil and gas, which contains significant amounts of HCl, H2S, NH3, and H2O. Moreover, HCl and NH3 can form ammonium chloride, a compound with extremely severe corrosive properties. The fluid outside the tube bundle of heat exchanger E2002 is Russian crude oil, a light‑weight crude characterized by high sulfur and high salt content and low acidity, which also exhibits a certain degree of corrosivity.

 

The operating temperature of the E2002 heat exchanger’s tube bundle exceeds (or approaches) 80°C (125°C at the inlet and 70°C at the outlet). The heat exchanger’s end caps, tube sheets, and shell are fabricated from carbon steel, which exhibits corrosion; consequently, this can lead to a certain degree of iron contamination of the titanium heat exchange tubes. Over prolonged service, both the inner and outer surfaces of the tubes develop scaling. Such scaling exacerbates iron contamination on the tube walls, giving rise to under-deposit corrosion. Under-deposit corrosion is, in fact, a form of crevice corrosion [7], and as it progresses, it also increases the amount of hydrogen absorbed by the titanium.

 

When the inner and outer surfaces of a heat-exchanger tube are in prolonged contact with a corrosive medium and are also subject to iron contamination, hydrogen absorption occurs, leading to the formation of substantial hydrides and resulting in hydrogen embrittlement of the titanium tube. As hydrogen diffuses, the hydrides continue to grow inward; meanwhile, the hydrides on the exterior, upon exposure to oxygen in the air or in the process medium, give rise to significant oxide layers. Consequently, XRD analysis of the corrosion products on the titanium tube reveals the presence of TiH2 and TiO2. Additionally, trace amounts of nitrogen are detected within both the TiH2 phase and the titanium matrix; however, according to the literature, such minor nitrogen content has not been reported to exert any influence on the initiation or progression of hydrogen embrittlement in titanium.

 

In summary, the corrosion‑induced perforation of titanium heat exchange tubes is attributable to hydrogen‑embrittlement corrosion.

 

Conclusions and Recommendations

1. Conclusion

(1) Corrosion‑induced pitting of the heat exchanger tube bundle occurs and progresses on both the inner and outer surfaces of the tubes; hydrogen embrittlement is the primary failure mechanism underlying this pitting; the corrosion products are TiH2 and TiO2.

(2) The service environment, operating temperature, iron contamination, and scaling of the heat exchanger tube bundle are the primary factors contributing to the initiation and progression of hydrogen embrittlement in titanium heat exchange tubes.

(3) No hydrogen‑embrittlement corrosion damage was detected in the #2 tube bundle of the heat exchanger submitted for inspection.

(4) The presence and accumulation of deposits—such as oil sludge and other contaminants—on both the inner and outer surfaces of heat exchanger tube bundles can lead to oxygen depletion beneath the deposits, thereby promoting under-deposit corrosion (crevice corrosion). In particular, when the deposits contain a high iron content, they can readily cause iron contamination on both the inner and outer surfaces of the heat exchange tubes, resulting in galvanic corrosion and subsequent hydrogen uptake at the surface of the titanium (cathodic) tubes.

(5) Although the design service life of the heat exchanger tube bundle is ten years, its actual service life—under normal operating conditions—should exceed ten years. In some cases, tube bundles subjected to over nine years of service have experienced hydrogen‑embrittlement corrosion, which is likely related to their prolonged hydrogen uptake. This does not mean that the tube bundles will inevitably fail after ten years of operation; provided that process conditions are properly controlled, such tube bundles will not suffer hydrogen‑embrittlement failure.

2. Recommendations

(1) Select titanium materials appropriately and rationally based on the equipment’s process conditions. The selection of titanium equipment must be compatible with the operating environment and should not exceed the material’s specified service limits. It is essential to thoroughly account for hydrogen‑evolution conditions in the production environment, including both process‑related side reactions and various localized corrosion scenarios.

(2) Strictly implement the “one‑stripping, three‑injection” corrosion‑prevention process, reducing the concentration of corrosive media at the source. Appropriately control the dosing of neutralizing agents, corrosion inhibitors, and injection water volumes to neutralize H₂S and HCl, thereby preventing their corrosive effects on associated equipment and pipelines. This also helps prevent contamination of titanium materials by iron‑based impurities and rust, while eliminating the formation of ammonium salts and averting under‑deposit corrosion caused by their deposition.

(3) Increase the frequency of fixed-point thickness measurements for relevant equipment and pipelines, strengthen monitoring by online corrosion detection systems, and closely track key parameters such as pH and iron ion concentrations in acidic water, so as to promptly detect any changes and adjust production operations accordingly.

 

 

Zhongke Weier Anticorrosion Technology Center

2026.05.18