Download 157954060 Refining Student Manual July2011 PDF PDF

Title157954060 Refining Student Manual July2011 PDF
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Ch 15 Appendix 1 Basic Guide to Ferrous Metallurgy
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Document Text Contents
Page 1

Corrosion Control in
The Refining

Industry

July 2011
 NACE International

Page 248

Hydroprocessing Units 7-19

©NACE International 2007 Corrosion Control in the Refining Industry Course Manual
6/2008

Every reactor will be affected by a variety of unique factors, and
remedies must be considered individually. Current practice in the
construction of new reactors is to require ultra-clean steels and to
carefully screen the materials being used to minimize temper
embrittlement. Keeping to the pressure restrictions and maintaining
minimum pressuring temperatures (MPTs) are essential elements in
preventing failures due to temper embrittlement in hydrotreating
reactors.

7.3.2 Hydrogen Embrittlement
Hydrogen embrittlement is often a concern in the reactors of
hydroprocessing units, due to the large concentrations of dissolved
hydrogen that can build up within the walls of a unit operating at the
required high temperatures and hydrogen partial pressures.

If the reactor walls are thick enough and are cooled rapidly when
shutting down, the dissolved hydrogen has no opportunity to escape
from the metal during cooling. If significant amounts of the
dissolved hydrogen remain in the steel after cooling, mechanical
properties may be temporarily affected. The degradation in
mechanical properties is called hydrogen embrittlement.

The condition exists only while the hydrogen remains in the steel,
and the steel will regain its original properties if the hydrogen is
allowed to escape. Even though hydrogen may be present in the
metal, the condition known as hydrogen embrittlement occurs only
at temperatures below about 149°C (300°F).

Special cooling procedures are often required when removing
reactors from service in order to let a significant amount of the
hydrogen diffuse out of the metal before the reactor is cooled below
149C (300F). Cooling rates of 28°C/hr to 56°C/hr (50°F/hr to
100°F/hr) are considered adequate to provide enough time for
degassing.

Heavy-walled reactors in hydrogen service are especially vulnerable
and should be inspected with particular care both after initial
construction and during any plant turnarounds to guard against
existing defects that might enlarge due to hydrogen embrittlement.

Page 249

7-20 Hydroprocessing Units

Corrosion Control in the Refining Industry Course Manual ©NACE International 2007
6/2008

7.4 Selection of Materials
Material selection is influenced by the equipment or piping location
within a hydroprocessor unit.

7.4.1 Reactor Loop – General
The materials of construction used in reactor loops of a hydrotreater,
single-stage hydrocracker or the first stage of a two-stage unit must
be resistant to the following forms of corrosion:

• High-temperature hydrogen attack

• High-temperature hydrogen sulfide corrosion

• Aqueous corrosion by ammonium bisulfide

• Stress corrosion cracking by chlorides, sulfur acids, or sulfides

• Naphthenic acid corrosion (at high concentrations).

7.4.2 Reactor Feed System
Up to the point of recycle hydrogen addition, the reactor feed
system can be vulnerable to corrosion if the feed contains hydrogen
sulfide (H2S) at temperatures over 260°C (>500°F) or naphthenic
acid at temperatures exceeding 232°C (>450°F).

H2S corrosion can be minimized by using alloys containing 5%
chrome or better. Naphthenic acids may necessitate the use of type
316 or type 316L stainless steel.

After the point of recycle hydrogen addition, progressively higher
alloys are required to resist both hydrogen attack and high-
temperature H2-H2S corrosion. In most plants, threshold
temperature for H2-H2S corrosion is 260°C (500°F), but depends on
the amount of H2S introduced with the recycle gas.

Austenitic steels are usually used for piping and exchangers in
environments where the temperature exceeds 260°C (500°F). Hot
piping is commonly constructed of type 321 stainless steel, since
type 347 piping is more costly and generally more difficult to weld.

Exchanger bundles are usually type 321 stainless steel, while shells
and channel sections are clad with type 321 or type 347 stainless
steel. For cladding thick-walled components, type 347 stainless steel

Page 495

Failure Analysis in Refineries 17-15

©NACE International 2007 Corrosion Control in the Refining Industry Course Manual
6/2008

Where  is the nominal applied stress and a is the crack length. For
a given crack length, the stress intensity equals zero when the stress
equals zero and increases linearly with the applied stress and square
root of the crack length.

This type of approach is also used when assessing fatigue failures to
estimate the number of cycles that the component was exposed to
prior to final failure. For many engineering alloys, the rate of crack
propagation, da/dN, can be expressed as a function of the range of
stress intensity ΔKI that the crack experiences during the stress
cycle.

da/dN = CΔKI
m

If the toughness of the material is known, knowing the length of a
flaw prior to final overloading can offer clues regarding the
magnitude of loading induced on the component. Conservative
estimations of toughness can be made for initial calculations. If
necessary, the material toughness can be further defined through
material testing.

17.2.8 Root Cause Analysis
Determining the root cause of a failure can be the most difficult
portion of the failure analysis. Certain failure mechanisms may
develop as a result of either another failure mechanism or a material
or fabrication discontinuity. It is the goal of the investigator to
analyze all pertinent data collected and to decide the proper order of
what precipitated the failure.

Cause analysis is the most vital part of a failure investigation. A
systematic method of processing the information obtained from the
metallurgical analysis and other sources of data leads to the:

• Identification of the problem

• Identification of the factors contributing to the problem

• Development of the corrective actions required to remedy the
problem.

The failure to follow an organized analysis method can result in
random guessing of the problem, which rarely defines the precise
cause of failure and seldom solves the problem.

Page 496

17-16 Failure Analysis in Refineries

Corrosion Control in the Refining Industry Course Manual ©NACE International 2007
6/2008

Depending on the complexity of the failure, determining the root
cause may be straightforward, or it may involve backtracking
through process and inspection data until the root cause is
discovered. The fact that a pipe internally corroded does not
necessarily mean that the root cause of the failure is corrosion. It
could be related to a change in process chemistry or an improperly
specified or installed material.

17.3 Recommendations
Once all the data has been collected and analyzed, and the root
cause has been identified, recommendations are developed to avoid
a recurrence of the problem. Possible recommendations may
include:

• Material change

• Process change (temperature, pressure, or chemistry)

• Change in inspection type or interval

• Design change

• Component replacement.

It should be remembered that not all recommendations may be
practical. A suggestion to lower the process temperature or reduce
the sulfur content of a process fluid is not a good recommendation if
the plant cannot change these parameters. Therefore, careful thought
should go into choosing the most practical and economic solution to
prevent or delay a similar failure.

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