M. B. MATAR, Kuwait National Petroleum Co., Kuwait City, Kuwait
Disclaimer: This work is a fictionalized account based on operational experience. Names, dates and places have been modified to preserve anonymity and to focus on technical learning. No identification with actual persons (living or deceased), companies or real events is intended or should be inferred.
In the refining industry, corrosion is an ever-present adversary, often exacerbated by operational compromises and misdiagnosed root causes. This article chronicles the decades-long battle at Coastal Refining’s crude distillation unit (CDU-1), where recurring ammonium chloride (NH₄Cl) corrosion in the overhead system defied conventional fixes. What began as a routine maintenance issue evolved into a costly saga of ignored data, flawed process adjustments, and ultimately, a catastrophic failure—all stemming from a fundamental misunderstanding of thermodynamics, material science and the self-perpetuating chemistry of under-deposit corrosion. This article is based on operational experience in refining and reliability engineering.
Problem statement. The CDU-1 overhead system suffered severe corrosion, with tray vapor lines thinning by 60% in 18 mos and condenser tubes plugging with NH₄Cl deposits. Initial blame fell on desalter carryover and excessive ammonia injection, but the real culprit lay deeper: a combination of dewpoint violations, misplaced ammonia injection and carbon steel’s incompatibility with acidic service.
Technical analysis confirmed that the dewpoint (calculated per Maxwell’s methodology) was being consistently violated in the return headers.1 Despite clear evidence—including lab results showing pH 4.2 acidic water and 58 mils/yr corrosion rates—operational priorities and budget constraints delayed critical fixes, leading to repeated failures.
The ghost in the machine: Coastal Refinery’s recurring nightmare. It was the summer of 1987 at Coastal Refining's flagship facility when veteran corrosion specialist Walt Kowalski first laid eyes on the CDU-1 overhead system’s (FIG. 1) autopsy report. The numbers told a grim story:
Tray 42 vapor lines: Thinned from 0.28 in. to 0.11 in. in just 18 mos
Condenser E-301B tubes: Plugged with white, feathery deposits (lab confirmed as NH₄Cl)
Product quality: On and off brown, off-spec kerosene draw
Corrosion rates: A jaw-dropping 58 mils/yr in the top pump around the return header.
The operations team, led by hotshot Superintendent Mike O'Leary, had its usual suspects lined up: "It's gotta be the desalters," argued O'Leary, pointing to chloride readings of 1.2 pounds per thousand barrels (ptb) vs. the design spec of 0.5 ptb. "And we're injecting too much ammonia up in Tray 42."
But Kowalski noticed something peculiar in the temperature logs. The pumparound return stream (PA-302) was coming back at 145°F (63°C) into a tower section where the water dewpoint was 183°F (84°C). "You're 38 degrees below dewpoint!" he shouted. "Water condensation was inevitable at this temperature differential." This 38°F subcooling guaranteed localized water condensation wherever metal temperatures fell below the dewpoint, creating ideal conditions for hydrochloric acid (HCL) formation and under-deposit corrosion.
The refinery's star process engineer, fresh university graduate Sarah Chen, crunched the numbers. Her thermodynamic models showed the NH₄Cl deposition zone was precisely between 176°F and 248°F (80°C and 120°C)—right where the PA-302 spray distributor lived.
Yet the report's one recommendation? "Reduce ammonia injection."
"It addressed the symptom, not the root cause," Kowalski muttered, flipping to the material specs. The carbon-steel tubes in E-301 experienced aggressive wall loss, while the titanium tubes in E-312 overhead condensers looked brand new after 8 yrs.
That is when the phone rang. The night shift had found another leak in PA-302's 12-in. carbon-steel return line. Kowalski grabbed his hard hat, knowing this would be another decade long battle between short-term ops and long-term integrity.
Technical notes:
NH4Cl sublimation science: Deposits form where vapor temperatures fall below 248°F (120°C)—exactly the PA-302 operating range.
Dewpoint math: Calculated using Maxwell's methodology with 11.5 mol% water in overhead vapor at 65 psig0
Material incompatibility: Carbon steel corrosion rates exceed 50 mils/yr in pH < 4 environments with hydrogen sulfide (H2S) present.
Human drama elements:
O'Leary's conflict: His bonus depended on throughput targets.
Chen's frustration: Her models were dismissed as "theoretical".
Reynolds’ budget fear: Maintenance Superintendent Hank Reynolds refused titanium tubes due to "budget constraints."
"Corrosion never sleeps, but operations managers sure try to make it nap."—Anonymous corrosion engineer.
Technical diagnosis. The corrosion mechanism was a textbook case of NH₄Cl sublimation and hydrochloric acid (HCl) regeneration:
NH₄Cl formation: Ammonia (NH₃) from tray injection reacted with HCl to form solid NH₄Cl, depositing in the 176°F–248°F (80°C–120°C) range, the zone where the pumparound return (PA-302) operated.
Dewpoint violation: The PA-302 return temperature [145°F (63°C)] was 38°F below the water dewpoint [183°F (84°C)], ensuring water condensation and HCl dissolution into acidic droplets.
Self-perpetuating cycle: Under deposits, iron sulfide (FeS) and HCl recycled, accelerating corrosion in carbon-steel components.
Early troubleshooting efforts emphasized cold reflux control (or stopping it completely), though later analysis highlighted the greater impact of NH3 chemistry and metallurgy.
The data they ignored when numbers told the truth nobody wanted to hear. Kowalski stood in the dim light of the lab, staring at the failed tube samples from E-301B under the microscope. The cross-section showed the telltale “under-deposit corrosion” pattern—deep, jagged pits beneath layers of NH₄Cl and FeS.2
The lab tech, a sharp-eyed woman named Rosa, handed him the latest water analysis from the overhead accumulator:
Chlorides: 89 ppm (Chevron’s best practice limit: 20 ppm)
pH: 4.2 (Target: 6–7)
NH3: 22 ppm (traced back to Tray 42 injection).
The corrosion resulted from a self-perpetuating cycle:
NH₄Cl formation (Eq. 1): NH3 + HCL —> H4CL (1)
NH3 from tray 43 desalters
Salts sublimed in
80°C–120°C zones (T/P circuit)
HCl regeneration under deposits (Eq. 2): NH4CL + H2O —> H3 + HCL (2)
Fe + 2HCL —> eCL2 + H2
FeCL2 + H2S —> eS + 2HCL
Net Result
HCl recycled, accelerating corrosion
Design flaws:
No water knockout in the treater/processing circuit
Carbon steel materials in acidic service.
Inadequate water wash: This was below recommended levels (Chevron best practices: 130% of salt saturation and unfirm coverage).3
"This isn’t a mystery," Rosa said. "It’s a chemistry textbook case." At 22 ppm, the NH3 concentration exceeded typical operating limits by 4–5 times, guaranteeing excessive NH₄Cl formation throughout the overhead circuit.
When Kowalski presented the data at the next morning’s meeting, Operations Superintendent O’Leary barely glanced at the report.
"It’s not ideal timing for a shutdown, Kowalski," O’Leary remarked. "We need to balance risk with production demands."
Across the table, Chen unfolded her latest simulation.
"Look," she said, pointing at her temperature profile model. "The PA-302 liquid return is at 145°F (63°C), but the water dewpoint here is 183°F (84°C). Water must condense in the header. No amount of ammonia reduction will fix that."
Hank Reynolds leaned back in his chair. “We’ve always used carbon steel—are we really ready to commit to exotic alloys across the system?”
Kowalski sighed and pulled out Exhibit A: a titanium tube sample from E-312, the overhead condenser. After 8 yrs of service, it was pristine—0.002-in. corrosion loss, compared to 0.12 in. in E-301’s carbon-steel tubes.
“This is less about premium materials and more about finally solving a repeat failure mode,” he said.
But the real bombshell came when Rosa walked in with the ion chromatography results.
"The NH₄Cl deposits in E-301? They’re not coming from the desalters. They’re coming from Tray 42, where Operations had been injecting 3% NH3 solution for pH control.”
"You’re feeding the corrosion," Kowalski said. "Every gallon of ammonia you pump in there makes two pounds of NH₄Cl salt.”
Technical deep dive. Operational conditions vs. design are shown in TABLE 1. Design flaws identified included:
Carbon steel materials in acidic service
Inadequate water wash: This was below recommended levels (Chevron best practices: 130% of salt saturation and uniform coverage).
Material performance:
Carbon steel (A106 Gr B): 58 mils/yr corrosion rate in pH 4.2, H₂S-rich environment
Titanium Grade 2: 0.5 mils/yr in identical service (120x more resistant).
The fix that came too late: A $MM lesson in reliability. The refinery’s failure to act created a predictable timeline of disaster:
1987: First corrosion report identifies dewpoint violation (ignored)
1991: Cold reflux stopped (misdiagnosed fix)
1992: Sarah Chen’s titanium tube proposal (rejected by Reynolds as "too expensive")
1995: Kowalski’s memo predicts rupture
November 1995: Catastrophic failure.
The big leak finally hit on a rain-soaked Tuesday. Kowalski was elbow-deep in a failed tube bundle autopsy when the radio crackled: "All units, emergency shutdown—PA-302 header rupture at Column 42!"
By the time he reached the unit, a 20-ft. geyser of naphtha and steam was erupting from the 12-in. carbon-steel return line. The release dumped hundreds of barrels of product into the environment before the system could be isolated.
Cost of the outage:
Lost production: $6.2 MM
Environmental fines: $1.8 MM
Emergency repairs: $2.4 MM
Total: $10.4 MM.
"We told you," Kowalski later said quietly to the VP of Operations. "Every time, the answer was the same: ‘Run it until it breaks.’ Well, Jim…it broke."
Process engineering fails and the cold reflux debacle. The process team’s gravest mistake was misdiagnosing cold reflux as the root cause—a classic case of solving the wrong problem. Stopping the 105°F (41°C) cold reflux (a 5% flowrate adjustment) did nothing to address the NH3 injection points still feeding Tray 42, nor did it fix the dewpoint violations in PA-302.
By the time the titanium retrofit finally happened, the unit had bled in avoidable failures.
"When you blame the wrong variable, your ‘fix’ becomes the next failure mode."—Walt Kowalski’s Law of Misplaced Causation.
The fix that finally happened. Under threat of corporate oversight, Coastal implemented what it should have done decades earlier:
Material upgrade: Replaced all PA-302 carbon-steel components with titanium Grade 2
Cost: $3.1 MM
Result: Corrosion rate dropped from 58 mils/yr to 0.5 mils/yr.
When the unit restarted, Chen (now at a different operator) sent Kowalski an email: "Heard about the blowout. Guess they finally proved your math was right—the expensive way."
As he clocked out for the last time, Kowalski left a note on the whiteboard:
“Corrosion never compromises. People do.”
Takeaways: Systemic failures and the cost of short-term thinking. The recurring theme in this fictional case—and many like it across the refining industry—is the tendency to prioritize quick, capital-intensive fixes over sustainable process solutions. While upgrading to titanium tubes may seem like a decisive action, it masks deeper issues: a lack of technical rigor in addressing root causes and a culture that prioritizes immediate production over long-term reliability. The case correctly identifies key factors like desalter inefficiency, NH3 presence and dewpoint violations, yet the proposed solutions disproportionately focus on metallurgy rather than process optimization. This suggests a troubling pattern where engineering teams default to material upgrades because they are tangible, measurable and easier to justify in budgets—even when they fail to resolve the underlying chemistry.
The reluctance to implement fundamental corrections—such as relocating NH3 injections (or change to amins), enforcing dewpoint compliance or automating wash water (130% flow rate) systems—reflects a broader organizational inertia. Operations teams, pressured to meet throughput targets, often dismiss process adjustments as "theoretical" or "disruptive," while management, insulated by layers of accountability, approves costly material upgrades without demanding proof that they address the real problem. The result is a cycle of preventable failures, where each incident is treated as an isolated event rather than a symptom of systemic dysfunction. The fact that this unit had already experienced fouling and tube plugging in previous years—yet no meaningful process changes were made—speaks to a failure of institutional learning.
Worse still, this approach perpetuates a culture where technical staff grow accustomed to superficial solutions, knowing that deeper fixes require political capital and operational patience that few leaders are willing to expend. When corrosion inevitably recurs, the blame falls on "unavoidable" conditions rather than the decisions that allowed them to persist. The refinery’s willingness to spend millions on titanium but not on process controls reveals a fundamental misalignment: reliability is treated as a capital expense rather than an operational discipline.
In the end, the real cost is not just the price of titanium tubes or emergency shutdowns—it is the erosion of engineering credibility and the normalization of avoidable risk. Until refineries recognize that corrosion control is a function of chemistry, thermodynamics and operational discipline—not just material selection—these failures will continue. The lesson here is not that titanium is unnecessary, but that it is insufficient without the process controls to make it redundant. Management must choose whether to keep paying for symptoms or finally cure the disease. HP
LITERATURE CITED
Perry, R. H., D. Green and M. Z. Southard, Perry's Chemical Engineers’ Handbook, 9th Ed., McGraw-Hill, 2018.
White, R. A. and C. E. Norman, “Controlling ammonium chloride corrosion in distillation overheads,” Hydrocarbon Processing, March 1998.
Chevron ETC, “Overhead systems best practices manual,” Internal Document, 2009.
Mohammad B. Matar is a chemical engineer and Technical Coordinator at Kuwait National Petroleum Co. (KNPC) with more than 25 yrs of expertise in operations, process engineering and operational planning. He earned a BS degree in chemical engineering and an MBA from Kuwait University.