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WHAT DO I NEED.

Below is a text of a discussion of results I did for a failure analysis report for Company 1 (SECTION 2). I need to do the same type of section, with the same writing style and structure but for a new investigation for a different Company 2. The two investigations do not relate to each other, neither the companies or components. SECTION 2 serves only as an example. I need to do the same type of text from the previous investigation but this time for for the new investigation. The structure must remain the same, unless, this time the text is adapted with the new data that applies to the new investigation mentioned in SECTION 1. 

Can you modify / adapt the text of the first investigation (SECTION 2) with the information and data for the new second investigation (SECTION 1)? 

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INSTRUCTIONS TO FOLLOW. 

- Explicitly stating the desired level of similarity: Quite some. 

The goal is to closely replicate the structure and style of the provided text from Section 2, ensuring that the adaptation maintains consistency with the original document.

- If you find any missing information in section 1, that is covered in the text of section 2, state that such information was not provided (or similar ways of saying it)

EXAMPLES.

* Write in this way:

"No further specifications on the material and or production process were submitted. Information about the process the pipeline was in service for was also not specified. The operating hours and service time were not specified."

* Do not sumarize like this:

"This will involve investigating whether factors such as pipe stress, exposure to heat on-site, or the nature of the transported substance have contributed to the observed crack."

or

"Potential causes considered include pipe stress and exposure to heat on-site, possibly for bending purposes. Additionally, it is noted that the pipe carries hydrochloric acid (HCL), which could potentially contribute to cracking in HDPE materials."

* Write like this:

"The client informed that ...babablabla", "According to the client, possible causes .....bblablabalbla"

- Do not use pompous words, keep it formal but use common words in english. 

- Write in third person, you are talking about what information has been given to you by Company 2. 

- Keep it readable. 

- Try to stay limited to one page, not too extended. 

- DO NOT use bullet points. Write in paragarphs. Again: Do not use bullet points.

- Key point of adaptation:

The last paragraph were it states about "Element", must be kept almost identical, but adapted to the received information.

- You should not in any way write anything about company 1. This all has to be done only for company 2 with the information in hand (section 1).

-Specifying the level of replication: is necessary to replicate well for all aspects of the text, including sentence structure, wording, and formatting. There is flexibility in certain areas, but keep to the section 2 as the standard.

- The new investigation DOES NOT have most of the segments of the previous investigations. Take consideration on this.

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COMMON REMARK.

SECTION 2 is a template showing some subtitles in parts of the text structure. The subtitles show you what needs to be covered on each paragraph... so try to divide your text into these different parts, to get it resemble to this exmaple quite a lot.

NOTE on subtitlle "Main dominant factors":

This part is substantial. a list of the main dominant factors must be stated in a very very similar way and structure. This is the most importatn part of the entire text.

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SECTION 1 - The new information for the second investigation that must be used to adapt the text in section 2 is all contained in the following info sent by the client: 

*****Background information:*****
Following a leakage and fire incident in the reboiler furnace of the stabilizer column at the İzmir Refinery, damage was observed on one of the furnace pipes. 

According to the client, the rupture occurred in a pipe located in the radiant zone of the H-7302 reboiler furnace, which operates within the U-7000 crude distillation unit. The failed component is a 6” schedule 40 pipe, material grade ASTM A106 Gr. B carbon steel. The furnace was commissioned in April 2018 as part of a revamp project. The rupture occurred after approximately 6 years of service. The furnace is designed with six passes; each pass in the radiant zone consists of 10 pipes, forming a total of 60 pipes. Indications of wall-thickness reduction were observed on the inward-facing surface of the failed pipe, covering approximately one meter in length. Additional thinning has been detected on other pipes at the same level. Further thickness data are expected from an upcoming smart pigging inspection. The average surface hardness of the submitted material was measured at approximately 180 HB. No repair history for the pipes was reported.

The failed pipes were in service carrying a naphtha stream. Naphtha enters the furnace pipes at ~180°C and exits at approximately 205°C. The flow inside the pipes is a two-phase mixture of liquid and vapor. The outside of the pipes is exposed to direct heat from burners, as the radiant zone is the hottest section of the furnace. The furnace is equipped with combined-fuel burners, but has been operating on gas only for the past two years. No specific information on internal or external pressures, potential overloading, or cyclic loading was provided. Details regarding flow velocity, pressure variations, or possible solid content in the naphtha stream have not been submitted. According to the client, the rupture occurred suddenly. No abnormal operating incidents prior to the failure were reported. 

A section of the failed pipe and a section of the same pipe from a postion was submitted to Element Materials Technology Rotterdam B.V. (“Element”, location Amsterdam) for investigation. An additional section from the same pipe, but from a lower position, has also been made available for comparison. Element was requested to determine the nature and, if possible, the cause of the damage observed in the ruptured pipe.
 
*****Visual examination:*****
The received specimens were two pipe sections: one containing the area of rupture, and a section from the same pipe line cut away from the area of rupture (reference). 
For the purposes of this document, these were identified as "Pipe Section 1" (containing the rupture) and "Pipe Section 2" (the reference, cut away from the rupture). For pipe section 2 (reference), no indication was given or marked on the pipe surface that could indicate which cut end was pointed in the direction of the rupture.   

For reference in this document, the rupture area on Pipe Section 1 was established as the 12 o'clock position.  
The rupture itself had a slightly bulged profile with an elongated shape in the longitudinal direction, measuring 123.66 mm in length and 53.45 mm in width.

Preliminary thickness measurements on Pipe Section 2 revealed a slight decrease on one side of the pipe circumference. This thinner region was established as the 12 o'clock position. 

The ruptured pipe section 1 measured ~585.50 mm in length and had an outer diameter of Ø~166.50.
The reference pipe section 2 measured ~583.50 mm in length and had an outer diameter of Ø~166.60 mm (similar to pipe 1). 

Thickness measurements were taken along various clock positions on both pipe sections using a calibrated calliper. For pipe section 1, measurements were performed on both pipe cut ends, one side being immediately adjacent to the rupture. 
For pipe section 2 (reference), thickness measurements were performed only on one arbitrary cut end. 
These measurements confirmed significant wall thinning at the 12 o’clock position in pipe 1, where the rupture was located. The remaining wall thickness at this position was measured at 1.08 mm, while at the center of the rupture it reached a minimum of 0.42 mm. On the opposite end of the same pipe section, thickness measurements confirmed similar thinning at corresponding clock positions. 

The measurements in pipe section 2 confirmed a slight wall thickness decrease at the established 12h position. This results suggested alignment of thickness reduction at such clock positon.

Here is a summary focusing on the **main aspects** and **dominant factors** of the analysis:

**Main Aspects:**

1. **External Surface Condition:**

   * Both pipe sections had smooth, dark brown outer surfaces.
   * No visible damage or deformation except at the rupture site.

2. **Rupture Characteristics:**

   * The rupture bulged outward, indicating **failure initiated from inside** the pipe.
   * Significant **internal material loss** was observed near the rupture, with **gradual wall thinning**.

3. **Internal Surface Observations:**

   * **Black and orange-toned deposits** were found inside, particularly near the rupture and at the 6 o’clock position.
   * Another area opposite the rupture (12 o’clock) also showed **wall thinning and black deposits**, indicating **a second degradation site**.

4. **Flow-related Features:**

   * **Spiral-shaped markings** and pitting suggest **flow-induced erosion or turbulence**.
   * Flow direction and turbulence patterns inferred from **linear striping and product accumulation**.

5. **Comparison Pipe Section:**

   * Covered in **thicker, more adherent dark deposits**.
   * **Localized bulging and striping** near 12 o’clock side, matching flow direction.
   * **Fine pitting** and **thickness loss** confirmed at 6 o’clock side.

* **Internal corrosion** with progressive **material thinning** was the primary failure mechanism.
* **Flow-induced erosion or turbulence** contributed to localized thinning and pitting.
* **Product buildup and flow patterns** influenced the distribution and severity of internal degradation.
* The rupture was a result of long-term, **preferential wall loss along specific orientations (6 and 12 o'clock positions)**.

The rupture occurred at a location with the most severe wall-thickness loss from the inner surface side, which was limited to a specific clock position, 12h. The thinning in pipe 1 occurred progressively, affecting two main areas along the same axial line 12h of the pipe section, and one of these areas ruptured. 
The damage morphology, spiral surface markings with directionally component, suggest that flow conditions played a role in the wall loss. The presence of localized product accumulation, combined with the internal two-phase flow of naphtha and resulting turbulence, is consistent with flow-assisted degradation. 


*****UT examination:*****
MAIN FACTORS UT:
The phased array UT scans reveal that both pipe sections exhibit patterns of gradual wall thinning, more pronounced in Pipe 1. In Pipe 1, the thinning culminated in a full-wall rupture, with circumferential material loss clearly visible at the failure location. Pipe 2, although intact, displays similar signs of erosive or corrosive degradation, especially near the 12 o’clock region. These results suggest a shared degradation mechanism—potentially related to fluid flow dynamics or thermal gradients—acting preferentially along specific longitudinal and circumferential zones of the pipe.

*****Stereomicroscopy examination:*****
The observations support that the damage mechanism is driven by an internally acting process, with features consistent with chemically-induced attack progressing from the inside wall surface. The key morphological indicators observed—such as the presence of generalised shallow pitting, directional alignment into diagonal bands, and the absence of external damage—suggest that the degradation is related to fluid flow and internal surface exposure. The pattern formed by the pits indicates a significant directionality component to the attack. There is no evidence of mechanical overload or external impact contributing to the damage.

This directional pattern suggested a flow-driven mechanism behind the observed internal degradation.

Both pipe sections examined display the same internal surface degradation features, despite only one section containing the rupture. This suggests that the same degradation process was occurring throughout the pipeline, even though it had not yet led to failure in the second section. The directionality of the attack, evidenced by the spiral alignment of shallow pits in both sections, reinforces the interpretation of a flow-related degradation mechanism acting internally over time.

*****Chemical analyses:*****
 The material chemical composition satisfy the requirements of the typical composition of the pipe material as informed in the submitted material certificates. This for both pipe sections; no difference in material chemistry was found.

*****SEM-EDX examination:*****
The results from the EDX analyses yielded, in general, similar trends (spectra) for the examined products. 

The approximate chemical composition of the products at the position of rupture, away from it and on the reference pipe was comprised of the same main constituents. For all cases, the main detected elements were: iron (Fe), oxygen (O) and sulphur (S). The detected elements indicated that the products mainly consisted of oxides and/or hydroxides (corrosion products) of the pipe's material. 

The corrosion products were significantly enriched in (compounds of) sulphur (S). Sulphur (S), foreign to the chemical composition of the pipe material, yielded notably high levels and clearly indicating a sulphur enriched flowing medium. Sulphur is well known to impair the corrosion resistance of low alloyed steels, such in this case. The notably high levels are clear evidence that the pipe material operated in an agressive flowing medium. According to the submitted information, the medium was comprised of naphtha, and the results suggest high amount of sulphur compounds were contained in it. 

Other elements foreign to the chemical composition of the pipe material were detected in trace amounts. These were: sodium (Na), magnesium (Mg), aluminium (Al), silicon (Si), chlorine (Cl), potassium (K), calcium (Ca), manganese (Mn), nickel (Ni), copper (Cu) and zinc (Zn). The presence of these elements most likely related to dried products containing salts and/or contaminants from the medium or handling.

*****Macroscopic examination:*****
A section across the rupture was extracted, cut along the 3h and 9h positions, and prepared for macroscopic examination as ground. The examination clearly revealed the gradual thickness thinning towards the area of rupture. The rupture clearly displays bulging outwards , originating from the inner surface side. At this position the wall thickness has been completely tarnished away.

*****Microscopic examination:*****
### **Main Aspects:**
1. **General Material Condition:**
   * The microstructure across all samples was **clean**, with **no defects or discontinuities**.
   * Some **scattered non-metallic inclusions** were present but not problematic.
   * The **ferrite-pearlite structure** typical of low-alloy steel was **uniform** and **unchanged across the wall thickness**.

2. **Internal Surface at Rupture Area (12 o’clock):**
   * **Shallow, crater-like features** were observed, formed by **coalesced lateral pits**.
   * Pits were **wider than deep**, indicating **lateral corrosion spread**.
   * Remaining **wall thickness** at this location was significantly reduced (**663 μm**).

3. **Oxide and Crack Findings:**
   * **No oxides** were present on the **internal surface**, aligning with earlier visual results.
   * The **outer surface** had a **grey oxide layer**.
   * Some **minor microcracks** near the outer surface were likely caused by the **rupture event**, not by prior degradation.

4. **Etched Metallography Results:**
   * Confirmed **no internal degradation**, **grain boundary attack**, or **phase-specific corrosion**.
   * The attack progressed **evenly across the internal surface**.

5. **Rupture Tip Analysis:**
   * Showed **plastic deformation flow lines**, confirming **final failure due to overload**.
   * Overload occurred at a **severely thinned wall**, consistent with internal attack.

* **Internal corrosion** (mainly pitting with lateral spread) caused **gradual wall thinning**.
* **Even corrosion morphology**, no signs of localized material weaknesses or selective attack.
* **Final rupture** resulted from **mechanical overload** at a point where the wall had already been **critically thinned by internal corrosion**.

Both pipe sections were confirmed to present similar internal features, even though only Pipe 1 contained the rupture. The microstructure remained consistent in all sampled positions. The thinning due to internal pitting in Pipe 1 had progressed to a point where final rupture occurred due to localised mechanical overload. Pipe 2, despite not having failed, displayed similar internal morphology, indicating that the same internal degradation process had extended along the pipeline.

*****Hardeness tests:*****
According to the submitted information (XX/ASTM AX), the results confirmed that the average hardness of ~131 and 134 HV1 for both examined sections satisfy the permissible hardness requirements for the examined pipe material. The results confirmed that the hardness properties, independently of the position of sampling, remained constant throughout the ruptured pipe section 1 and reference pipe 2 . No signs were found that could suggest apparent degradation in the mechanical properties of the examined pipe sections 1 and 2.

*****Preliminary Discussion of results and Investigation*****
The combined results indicated that along the pipe line, the established 12h positon was subjected to more aggressive conditions, resulting in material loss. 

*****Preliminary Discussion of results and Investigation 2*****
Based on **EDX results** (16–22 wt% sulfur, 16–24 wt% oxygen) and the observed **gradual wall thinning, pitting, and swirl patterns**, the failure mechanism is **high-temperature sulfidation corrosion exacerbated by flow-assisted degradation**—not classic FAC, but a similar/related **erosion-sulfidation process**. Some important points:

### **1. Key Clues from Your Findings**
| Observation | Interpretation |
|-------------|----------------|
| **16–22 wt% sulfur (EDX)** | Confirms **iron with sulfide compounds like (FeS) scale formation** (sulfidation). |
| **16–24 wt% oxygen (EDX)** | Fe oxidation (like **Fe₃O₄/Fe₂O₃ mixing with FeS**). |
| **Gradual wall thinning** | Consistent with **flow sulfidation** (material loss due to scale spallation?). |
| **Swirl-pattern pitting** | Turbulent flow stripping scales → ** potential localized erosion-corrosion**. |
| **Two-phase naphtha flow** | creating a more turbulent flow (?)|

### **2. Most Likely Mechanism: Erosion-Sulfidation Corrosion**
#### **Why?**
- **Sulfur in naphtha** reacts with steel at 180–205°C to form **FeS scales** (brittle, poorly adherent).  
- **High(?)-velocity two-phase flow** (liquid + vapor) **mechanically removes FeS**, exposing fresh metal to further attack → **accelerated thinning**.  
- **Swirl patterns** indicate **turbulence-driven scouring** (common in bends, welds, or downstream of flow disturbances).  

#### **Supporting Evidence**
- **EDX sulfur levels (16–22%)**: Far higher than typical FAC (which has near-zero sulfur).  
- **Oxygen presence**: Likely due to **air ingress during shutdowns** or minor water contamination forming oxides alongside sulfides.  

### **3. Contributing Factors**
#### **A. Naphtha Composition**
- **High sulfur content**: Promotes FeS formation.  
- **Possible trace water/oxygen**: Accelerates mixed sulfide-oxide scale growth (less protective than pure Fe₃O₄).  

#### **B. Flow Dynamics**
- **Two-phase flow regimes** create **bubble collapse erosion** (cavitation-like damage).  
- **High velocity** increases shear forces, stripping scales faster than they can reform.  

#### **C. Temperature Gradient**
- **External radiant heating** (burner side) may create **hot spots** → higher sulfidation rates.  

### **4. Distinguishing from FAC**
| Feature | FAC (Water Systems) | Your Case (Naphtha) |
|---------|--------------------|---------------------|
| **Primary Corrodent** | Water (dissolves Fe₃O₄) | Sulfur (forms FeS) |
| **EDX Signature** | High O, near-zero S | High S + moderate O |
| **Scale Type** | Magnetite (Fe₃O₄) | Iron sulfide (FeS) + mixed oxides |
| **Flow Role** | Mass transfer of dissolved Fe²⁺ | Mechanical scale removal |

### **6. Potential Conclusion**
failure is **not FAC** but a sort of **flow sulfidation corrosion**—a synergistic effect of **sulfur attack + mechanical scale removal by two-phase flow**. The swirl patterns and thinning are classic hallmarks of **erosion-corrosion in sour hydrocarbon service**.  




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SECTION 2 - Text of first investigation for Company 1, to use ONLY AS TEMPLATE and example to adapt with information in section 1: 

Overall discussion.

Material condition

The results of the chemical analyses in combination with the metallography showed that the tube’s material corresponded to stainless steel grade 254 SMO according to ASTM A213 (UNS S31254). The tube’s material showed a common austenitic matrix with twin boundaries. No evidence was found for material defects and/or degradation that might relate to the occurred pitting.

Visual examination and relation between all specimens and the type of damage

The results of the visual examinations and metallography showed that the reported wall thickness thinning corresponded to localized attack (pitting) initiating from the tube’s inner surface. The found pitting (~11% of the nominal wall-thickness) in the submitted tube section (examined sections), however, was not as deep as the reported wall-thickness thinning (up to 70%) as indicated by the performed ET testing. 

The examination results also showed a shallow pit morphology with wide pit-mouths of varying sizes and shapes. The morphology of the attack did not show signs characteristic for MIC.

Specifics of the nature of the damage, what is it what are the main features that descrive this type of damage

The localised attack was only confined to the area found containing darker brown corrosion products. This area coincided with a band on the outer surface that suggested the position of contact with a heat-exchanger baffle. Such likely might have very well produced a localised increase in temperature (local heat-flux), contributing to the localised attack. The straight zone of attack would also suggest influence of gravity, i.e. possible deposition of dirt from the water leading to under deposit corrosion (due to differential aeration and salt concentration).  

The SEM-EDX analyses confirmed the presence of corrosion products enriched with halides (i.e.: chlorides) coming from the medium. Halides are well known to cause pitting corrosion of stainless steels. 

Relation of the type of damage and service conditions

It is known that stainless steel in contact with chloride solutions is sensitive to pitting (and crevice corrosion, like under deposit corrosion relating to differential aeration). Pitting corrosion is the result of the local breach of the protective passive skin of the stainless steel. The chloride concentration, in combination with surface defects, plays a major role in this. If the passivity is broken locally, accelerated attack occurs on the spot (small active area, large passive area). The process is autocatalytic, the acidity in the pit drops and chlorides diffuse to the pit (electron neutrality), causing the process to accelerate itself over time. Pitting corrosion also increases as temperature increases.

Main dominant factors

For chloride pitting to occur, several combined factors must be present. In this case, the following factors are regarded as the main contributors:

1.	A medium containing chloride ions,

2.	A temperature which allows localised attack in the presence of chlorides.

3.	An alloy that is susceptible to the localised corrosive environment. 

Ad.1.- Corroborated by EDX-SEM. 

Ad.2.- Localised heat-flux (rise in temperature), assumed to be at the contact area with the baffle.

Ad.3.- According to the literature the tube’s alloy (254 SMO) is known to be susceptible to pitting attack in the presence of chlorides, with a critical pitting temperature of ~90°C (CPT, in 1 M NaCl) and pitting resistance equivalent number PREN (=% Cr + 3.3.% Mo + 30.% N) of 43. 

It is clear that the medium might be slightly brackish. Brackish is defined as containing about 0.3 up to 14 grams of chlorine per kg, i.e.: maximum 0,43 M. With the CPT from literature, normal operating conditions thus would not lead to pitting. In this case, additional factors likely played a role: the local higher heat flux at the position of attack, possibly in combination of deposition of dirt and concentration of chlorides leading to under deposit conditions (contribution of differential aeration). Such might have been influenced by the (unknown) flow rates.  

No evidence was found pointing to microbiologically induced corrosion (MIC). However, a slimy layer caused may lead to under deposit conditions (differential aeration) and contribute to corrosion.