Electrolysis: processes – compositions used therein – and methods – Electrolytic analysis or testing – For corrosion
Reexamination Certificate
2002-07-16
2004-11-09
Noguerola, Alex (Department: 1753)
Electrolysis: processes, compositions used therein, and methods
Electrolytic analysis or testing
For corrosion
C205S777000, C205S776000
Reexamination Certificate
active
06814854
ABSTRACT:
FIELD OF THE INVENTION
The invention relates to the in situ, or field measurement of hydrogen atom permeation into the walls of pipelines and vessels containing process streams and, particularly, petroleum process streams.
BACKGROUND OF THE INVENTION
Every corrosion process involves the two basic chemical reactions of oxidation and reduction. In the case of corrosion of carbon steel, the oxidative reaction that results in the destruction of the steel matrix can be represented as:
Fe°→Fe
+2
+2
e
−
(I)
In many petrochemical environments, the concurrent reduction reaction is the formation of atomic hydrogen,
H
+
+e
−
→H° (II)
Furthermore, in most chemical environments the atoms of hydrogen produced by (II) quickly undergo a reaction to form molecular hydrogen which, for the most part, mixes into the process environment and passes as dissolved gas:
2H°→H
2(g)
(III)
In the typical cases of general corrosion, the combination reaction forming molecular hydrogen occurs virtually concurrently with the reduction of hydrogen ions to atomic hydrogen. However, there are some chemical environments in which the combination reaction of atomic hydrogen to molecular hydrogen is impeded, which results in a higher concentration or lifetime of individual hydrogen atoms at, or very near the surface of the steel. A chemical environment common in the oil industry which causes this phenomenon is one in which hydrogen sulfide gas is present at a concentration of parts per million or greater levels. The presence of hydrogen cyanide and arsenic in the process stream are also known to cause this type of hydrogen corrosion phenomena to occur.
The presence of hydrogen sulfide in oil and gas production process streams can result in potentially destructive corrosion-related phenomena denominated by the general term hydrogen damage.
Hydrogen damage is caused by the permeation of atomic hydrogen into susceptible steels. Molecular hydrogen can become trapped in defects in the steel when highly soluble and mobile atoms of hydrogen that are diffusing through the steel matrix combine. When the molecular hydrogen is trapped in a void in the steel, pressure builds up over time, leading to blisters and cracks. Such hydrogen-induced cracking can eventually result in the failure of the pipeline or vessel.
The presence of hydrogen sulfide increases the number of hydrogen atoms permeating into the steel and therefore increases the potential for hydrogen damage. The adequacy of the measures undertaken to control the hydrogen permeation rate and hydrogen damage in oil production facilities that are sour in nature (i.e., where hydrogen sulfide gas is present), is one of the most significant concerns in the industry.
Various control methods have been used in an effort to counteract the potential damage of atomic hydrogen. Steel alloys have been developed that are resistant or immune to hydrogen damage. These alloys are quite expensive and are not a cost-effective solution for all applications. It is also possible to remove or to reduce the concentration of the hydrogen sulfide that is the catalyst for hydrogen damage by subjecting the crude petroleum to additional processing steps. This so-called sweetening process is used in many locations by the oil industry, but it is not always a cost-effective choice. A third control method is the introduction of chemical inhibitors into the process stream at a very low concentration. Since atomic hydrogen damage is a phenomenon that takes place in the interior of the steel matrix, chemical inhibitors and sweetening processes offer an indirect means of controlling the hydrogen gas formation.
The problem for the field engineer is quite significant, since no matter what atomic hydrogen permeation control method is employed, there are limited means available to enable him to evaluate the effectiveness of the control method chosen.
Several techniques have been developed over the years to measure the amount of atomic hydrogen that permeates steel process piping and vessels. Each of these techniques has limitations that detract from its accuracy and/or usefulness under field conditions existing in the petroleum and petrochemical processing industry.
Various in situ hydrogen probes have been developed that can be inserted into process facilities to measure atomic hydrogen permeation rate by measuring the increase in pressure produced by molecular hydrogen. A typical example of this type of probe is the Model 6400 hydrogen probe manufactured by Rohrback Cosasco. The probe consists of a sealed chamber made of the process facility material that is inserted through a 2″ access fitting into the process stream. An external pressure gauge or transducer measures the day-to-day buildup of pressure inside of the sealed probe that results when the atoms of hydrogen that are permeating the probe reach the inner surface where they combine to form molecular hydrogen in the probe chamber. The major disadvantage to this type of device is that the signal-to-noise ratio for pressure measurement of molecular hydrogen buildup caused by atomic hydrogen permeation in a field process environment is low due to the fact that the flux is approximately 6E12 atoms of hydrogen per second per cm
2
, or less. A typical hydrogen probe such as the Cosasco 6400 has an effective probe surface area of approximately 42 cm
2
and a minimum internal volume of approximately 20 cm
3
. This means that the measured pressure increase for this type of probe, under these conditions, will be less than 0.3 psi per day which is below the limit of detection for most pressure gauges or transducers. An additional consideration is the variation of internal pressure of a closed container due to temperature fluctuations. A ten degree variation in temperature will result in an observed pressure fluctuation of approximately 0.5 psi. It would not be possible to obtain reliable process information on a system at these levels at less than one week intervals.
Electrochemical measurement devices known as “patch probes” are designed to be attached to the exterior of the vessel being monitored. Their method of operation assumes that atoms of hydrogen which enter into the steel from the inside will eventually find their way to the exterior wall where they can be measured. They suffer from several limitations.
First, if the metal of the process vessel is susceptible to hydrogen damage (it must be assumed that it is or there would be no need to monitor it), then a certain fraction of the hydrogen atoms that enter the steel matrix will remain trapped there as molecular hydrogen leading to hydrogen damage. The entrainment of this hydrogen gas will result in fewer atoms of hydrogen reaching the external surface of the process vessel and consequently a smaller and nonreproducible signal available from the patch probe.
Additional problems arise from the method of measurement, which is to oxidize the atoms of hydrogen as soon as they appear at the external surface of the process vessel walls. The oxidation is therefore being performed at the surface of the steel walls of the process vessel. First, it has been shown that the efficiency of oxidizing hydrogen atoms from the surface of steel in this environment is only 20%. Since the signals are small to begin with, an 80% signal loss is catastrophic. Secondly, the background current caused by the oxidation of steel itself is larger than the magnitude of signal measured from the oxidation of hydrogen atoms (at the 6E12 atoms per second per cm
2
level). The signal-to-noise ratio is therefore less than poor. Some patch probe installations include machining the outer surface of the process vessel and then plating palladium on the surface. This has the potential of improving measurements by increasing the atomic hydrogen oxidation efficiency up to near 100% and eliminates the background signal due to oxidation of steel. However, not very many field engineers are willing to allow the external surfaces of their process vessels to be mach
Boah John K.
Lewis, II Arnold L.
Abelman ,Frayne & Schwab
Noguerola Alex
Saudi Arabian Oil Company
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