California Emphasis Program - Naphtha Hydrotreater Units - High Temperature Hydrogen Attack

On April 6, 2010, a tragic accident occurred at the Tesoro Refinery in Anacortes, WA, in the Naphtha Hydrotreater process unit (NHT). During routine operations involving an on-line switching of unit heat exchanger feed trains, seven employees were killed immediately, or died later of thermal burn injuries sustained when a feed-effluent heat exchanger catastrophically failed due to high temperature hydrogen attack (HTHA), releasing a hot, pressurized flammable hydrocarbon/hydrogen mixture which ignited. Tesoro released its investigative results to the media on September 01, 2010.

Rather than await the final report, the Northern and Southern California Process Safety Management district managers proactively initiated a California Emphasis Program (CEP) in April, 2010, under which Program Quality Verifications (PQV) were conducted in every California petroleum refinery to examine each refiner’s procedures and practices for identifying and mitigating corrosion damage known to be produced in the NHT process environment. The PQV focused on the NHT process units in general, and on NHT feed-effluent heat exchangers in particular. At the time the CEP began, the exact cause of the heat exchanger failure in Anacortes was yet unknown. What was known based on the documented historical experience of the refining industry, and published in its own technical literature is that the NHT operating environment can increase process equipment susceptibility to various forms of chloride corrosion and hydrogen attack.

The NHT process unit removes sulfur and nitrogen from straight run naphtha downstream of the Crude Distillation process unit (CDU). Removing these impurities involves treating the naphtha with hydrogen to create a suitable feed stock. The process poses operating and mechanical integrity challenges due to the presence of inorganic salts such as sodium chloride, magnesium chloride, and calcium chloride. Hydrogen is absorbed into metal, becomes trapped, and can cause embrittlement, cracking, and blisters.

While each refiner operates its NHT differently, consistent with defined business objectives, a feed-effluent heat exchanger nevertheless serves essentially the same purpose throughout the refining industry. Namely, to transfer the heat produced in a reactor pressure vessel to a feed stock. Typically, NHT feed-effluent exchangers are designed with consideration for potential sulfidation, high temperature H2/H2S corrosion, ammonium chloride corrosion, and high temperature hydrogen attack.

Additional corrosion phenomena found in the NHT include ammonium bisulfide and hydrochloric acid corrosion. Chlorides are difficult to control, and various types of aggressive corrosion phenomena present at varying operating temperatures and pressures downstream of the CDU.

Salt corrosion is caused by the hydrolysis of some metal chlorides to hydrogen chloride (HCI) and the subsequent formation of hydrochloric acid when crude is heated. Hydrogen chloride may also combine with ammonia used in chemical injection to form ammonium chloride (NH4CI), which causes fouling and corrosion.

Sulfur and nitrogen compounds are converted by a catalyst in the first stage reactor to hydrogen sulfide and ammonia. As the effluent stream from the reactor· cools down, the ammonia and hydrogen sulfide combine to form solid ammonium bisulfide (NH4HS) salts. Both concentrated NH4CI and NH4HS are highly corrosive to carbon steel and low alloys when wet. Dry, they are foulants that can inhibit heat transfer.

A comprehensive program for chlorides control should include monitoring of chloride levels in incoming crude in accordance with established acceptance criteria, effective desalting upstream of the CDU, effective water wash procedures and practices, effective chemical injection, appropriate materials selection and design, and rigorous monitoring.

Carbon and C-1/2 Mo steels in hydrogen service at temperatures above 450o F and pressures above 100 psia are susceptible to high temperature hydrogen attack (HTHA), a brittle fracture of a normally ductile material that occurs partially due to the corrosive effect of an environment. Under these operating parameters atomic and molecular hydrogen permeate the steel and react with dissolved carbides to form methane gas. The reaction decarburizes the steel, creating high localized stresses and resulting in voids and micro cracks that do not necessarily produce a tell-tale reduction in metal wall thickness.

Damage to welds, weld heat affected zones (HAZ), and/or base metal is undetectable· by conventional nondestructive examination methods during an incubation period during which time methane pressure builds in submicroscopic voids. HTHA is a long-term corrosion phenomenon that can be selective in location and degree of damage.

These corrosion phenomena are generally well understood, along with the mechanisms by which they degrade process equipment. Detection of each type of corrosion can be elusive given variability in process operating conditions, limitations in the monitoring equipment, and difficulty interpreting the data gathered.

The Northern and Southern California PSM district offices performed PQV compliance inspections in 11 refineries throughout California. On average, the NHTs had been in service from 25 to over 30 years. In every facility the metallurgy in its NHT(s) had been upgraded over time both in response to, then in anticipation of the effects of the types of corrosion discussed earlier.

The CEP focused on a review of each employer’s inspection, maintenance and operating procedures, practices, and experience specific to NHT feed-effluent heat exchangers. The Compliance personnel who conducted the inspections anticipated that these data collectively would chronicle equipment failures, near misses, and degradation. And that each facility’s historical record would reflect an evolving understanding of NHT corrosion phenomena and their control.

The inspectors expected to find documentation of the effects of hydrogen-induced damage, HTHA, and chloride corrosion in equipment whose metallurgy was vulnerable in an operating environment now processing sourer, higher acid crude slates, and more “opportunity crude”, which contains higher levels of contaminants and water. And they expected to find appropriate administrative, operational, and technical responses to the challenges presented. Such responses should include increased inspection, process changes, operating procedure modifications, and upgraded metallurgy. The costs of metallurgical upgrades are significant, and in some cases, facilities opted to modify process parameters and operating procedures in order to obviate “alloying up.”

Older process units used carbon steel, low chrome steels, 400 series stainless steel and non-stabilized 300 series stainless steel at temperatures higher than is considered safe today. In addition, these units used metallurgy such as C-1/2 Mo, which is now avoided as a result of industry experience. Operating limits for steels operating in a hydrogen environment are given in API Recommended Practice 941 Steels for Hydrogen Service at Elevated Temperatures and Pressure in Petroleum Refineries and Petrochemical Plants. The limits for C-1/2 Mo steels have been lowered twice because of unfavorable service experience; the first time in 1977.

After additional instances of HTHA occurred as much as 200o F below the revised 1977 Nelson Curve, the C- 1/2 Mo curve was removed altogether in 1990 and its specifications became identical to carbon steel. Equipment built before 1990 operating above the Carbon Steel Curve was suddenly at risk. New or replacement equipment base materials for heat exchanger shells and nozzles should be either 1.25 Cr-0.5 Mo or 2.25 Cr-0.5 Mo based on API 941 Nelson Curves. Cladding should be 300 series stainless steel, dependent on operating temperature and presence of hydrogen.

The CEP discovered that a common practice among at least some of the major oil refiners is to permit operation at 50o F above the Carbon Steel curve for C-1/2 Mo equipment. However, the equipment is prioritized for appropriate assessment, inspection and maintenance based on temperature, hydrogen partial pressure, operating time, thermal history of steel during fabrication, stress, cold work, age, and presence of cladding. California refiners recognize that cumulative operating time above the Nelson Curve increases equipment susceptibility to HTHA. While the equipment is in service at elevated temperature, the solubility of hydrogen in the Cr-Mo steels is higher, and the ductility of the material is greater, which prevents cracking phenomena. If temperatures are reduced at a rate which is too fast for diffusion, the diffusible hydrogen can localize at so-called trap sites such as dislocations, carbides, and non-metallic inclusions.

This can result in hydrogen “supersaturation” and hydrogen induced damage. The reduced ductility of the metal at the lower temperatures and the existence of applied, residual or thermal stresses may induce crack initiation. Such equipment must be inspected for HTHA using at least two inspection methods in combination. Base metal HTHA can be detected in its early stages using ultrasonic backscatter, velocity ratio, attenuation, and/or spectral analysis techniques. Use of ultrasonic shear wave inspection can reliably detect HTHA in welds only after cracks have formed. Higher frequencies can enhance detection capability.
The California Emphasis Program was initiated in response to a tragedy that, like most workplace injuries, likely could have been avoided. While it might be axiomatic that corrosion is inherent in the petroleum refining process, the direct costs of which approach $4 billion annually, the technology exists to manage its effects. The California refining industry collectively meets the challenges presented by corrosion phenomena known for decades to exist in the Naphtha Hydrotreating process.

Each Refiner has developed and implemented its own proprietary strategies for controlling the constellation of damage mechanisms common to the complexities of crude oil refining. All of these programs incorporate recognized and generally accepted good engineering practices for managing and reducing risk.