Gaseous Corrosion & Its Effects: Brief Study

An excerpt taken from a submission written for Fuel & Energy


Abstract— This article describes the effect from gaseous corrosion on equipment as well as on the processed product. It specifically includes the driving force of corrosion and its outcome from the gaseous contamination along with the cause by main source. Hence, corrosion by vapors and its generation is also discussed with parameters to overcome

Full article can be accessed here: Gaseous Corrosion & Its Effects: Full Article

Precisely, in petroleum industry the most common gases/vapors that cause corrosion to the equipment or transmission lines are those which come along with it naturally during extraction or some of them are naturally present in the liquid state in it and upon changing its state into gas/vapor, become corrosive in nature. This thing is common,
whether, there is an oil field or gas field, and the contaminants almost remain the same with some exceptions. Although, there are some additives that is added during the refining or purification process which may also form some by-products that should be removed as they are corrosive in nature also. Detailed explanation will be provided in the upcoming sections. The most common corrosion causing gases/vapors are: SOx, NOx, H2S, and CO2.

There are basically three main types of corrosion present in the gas/oil industry on the basis of the causing agent. This should not be confused with equipment corrosion. The types are as under:

 Sweet Corrosion
Sweet corrosion is mainly caused by Carbon dioxide (CO2), as it causes to form Carbonic Acid (H2CO3) and acts as an active proton donor causing acidic effect to propagate during the processing of gas/oil. Along with it also contaminates the piping system as well as the process equipment, forming deadspots.

 Sour Corrosion
Sour corrosion is mainly caused by Sulphur and its relevant compounds. So far, the biggest source is H2S which presents naturally in natural gas and crude. While during processing, it can cause to generate SOx which later may transform to Sulphuric Acid which acts as a strong dehydrating as well a corrosive agent.

 Oxygen Based Corrosion
While Oxygen is itself not so corrosive in nature but being an oxidizing agent, it contributes in increasing corrosion population. Bacterial growth in pipe due to excess deposition of moisture propagates more in the presence of Oxygen that is aerobic environment. Detail will be discussed shortly.

Natural gas and its constituents that is other gaseous fuels like Butane and Propane are not itself contaminant whether in raw form or refined form. The two main undesirable content are water vapor and hydrogen sulfide (H2S) which is corrosive in nature. Water condensate is corrosive for the process plant equipment but its severity becomes high when it dissolves acid in it, although, it is not as severe as H2S and other sulfur based compounds. Carbon dioxide is also objectionable in natural gas due to its acid forming nature and also because it lowers the heating value of the natural gas. Hence, proper removal is necessary.

The simplified process depicts that, in industry, there is a compression system that compresses the gas followed by a cooling system to remove the water content. Glycols are also widely used for its high affinity with water and chemical stability. Activated Alumina, Silica Gel and concentrated solutions of Sodium thiocyanate is widely used in this regard.
Monoethanolamine is widely used as a solvent to remove Hydrogen Sulfide followed by various scrubbing process.

If water present in most fuel gas is not removed, unduly high corrosion chances will occur in the transmission lines and trouble may also result in the form of Hydrates which can
cause line stoppage of various plant equipment. Freezing of valves and regulators in cold weather can also cause difficulty. The worst among this would be the formation of MIC** whose main cause of formation is excessive moisture environment but requires aerobic conditions to proceed its population.

It comes under the shadow of Oxygen based corrosion. It is actually bacterial population that forms in the transmission/pipelines. It is mentioned here because its cause of formation is gas and its outcome is in the form of corrosive gas too. In aerobic environment, the cultural growth leads to the formation of acidic gases like HCl and it also cause to metabolize Sulphur and its gases to accelerate attack on steel.

Usually, Sulphur based liquid or Merceptans is used as an odorant in the natural gas to identify leakages or to identify the gas. Under standard condition this isn’t corrosive but on distribution system this can cause corrosion. Hence non-sulfur based additive like Methethyl pyrazine is encouraged to use although, Dimethyl Sulfide and Ethan thiol is still used in this regard.

Crude Tower Overhead Corrosion Problem

Excerpt taken from the report based on internship experience at ORC-I, Byco Petroleum Pakistan Limited

Detailed explanation can be accessed here:  Full Report

What’re the important parameters to consider in desalter?

This is a very important question to raise as there are many but some certain compulsory parameters to consider that can depict the conditions and predicts the hurdles in further processing means. Following are the important points to consider must:
Water Quality: Dilution water that’s mixed with the oil in the desalter should be salt free to maximum extent as well as has pH to the prescribed level, means neither acidic nor basic. As the dissolved salts ay contribute in fouling of heat exchangers and further cause corrosion problems. At Byco, they are using Boot Water* (overhead product) from accumulator which ensures maximum possible low salt content.
Water Solubility in Crude: This is the most important parameter to counter. At elevated temperature, as rule of thumb, around 0.4% of water dissolve in oil and as the problem of this solubility become more severe when the crude passes through a pre – heat train just before entering the pre – flash fractionating tower. As the temperature rises, water tends to leave the residual salts in the oil which can cause severe damage to equipment. At Byco, they are maintaining the level of two phases inside the desalter in such a way to minimize this possibility.

*Boot Water: An important overhead component
One important factor shall be discussed in the next part i.e. Crude Tower Overhead Corrosion and the parameter that is connected with it is the Overhead water content. At Byco, this water is tested frequently to check the amount of Iron or any traces of contaminated components as well as due to the hydrolysis in desalter HCl vapors are produced which comes out as an overhead side product from the crude tower and pre – flash tower causing severe corrosion to the upper section as well as to the condenser tubes. Thus, the importance of testing is really significant to ensure safety as well as prevention from damages.

Crude Tower Overhead Corrosion Problem, How can it be prevented?
This is one of the most common problem usually encountered in Petroleum Refineries. The problem actually originates from the desalter, the three main salt content present in crude are NaCl, MgCl2, CaCl2 and out of these the heat stability are as under:

                          NaCl > CaCl2 > MgCl2

Hence, Sodium Chloride remains unaffected while Magnesium Chloride tends to hydrolyze at elevated temperature usually at crude tower’s flash zone releasing HCl vapors and the usual severe outcomes are in the form of:
o Loss of atmospheric distillation tower’s tray material/plugging
o Corrosion of condenser tubes and reflux drum

Since, at Byco, a single stage desalter is using currently which approximately removes around 90% of the salt content as compared to 99% removal from double stage removal. Here, the question arises, why don’t Byco utilize this to prevent corrosion? – The answer is – Magnesium Chloride is a troublesome salt and its removal is not that easy whether to use a single stage or multi stage. The HCl attack is continuously regenerated by reaction with H2S because usually there’s an excess of H2S inside the crude tower.

 First, HCl & Fe react to yield FeCl3 followed by a series reaction with FeCl3 & H2S react together to give FeS2 + HCl

This unfortunately leads to another factor to consider, HCl liberated out from the crude tower has usually a greater affinity for water and as long as no water is present the HCl vapors are non – corrosive in nature but as the overhead water droplets tend to condense, it dissolves all HCl and become highly corrosive in nature. The pH of HCl vapor without mixing with water condensate is about 2 while after dilution it increases to about 5.5 – 6.5.
On the similar manner, naturally crude oil contains Naphthenic Acid which is highly corrosive in nature whether in vapor form or condense form hence, at Byco, they frequently observe the acid content present in crude and for this they perform TAN (Total Acid Number) testing.

Glimpse of the location

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Gas-liquid flow: a prototype

Story of a successfully built prototype project describing the characteristics of two-phase flow under different conditons

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The prototype!
Two-phase flow or gas-liquid flow is an important measure to account when we study the behavior of fluids especially in gas/oil fields and wells where lifting is usually done through deep-well jet pump or where retrograde condensation happens or the most common example that we can easily observe is inside of a coffee maker and countless others.

Let us first examine the basic phenomenon and then we shall discuss the prototype we had made. The simplified Bernoulli’s equation suggests that at constant water flow-rate the pressure difference is mainly due to the energy losses but when air (precisely gas) is introduced into the tube the pressure difference decreases due to decrements in the average density of the fluid but when we increase the gas flow-rate a point (may) will reach where the decrements in the average density will be countered by the increase in the friction losses and this will cause the pressure difference to rise again. Through this whole process, we may encounter different flow patterns each corresponds to a different observation.

While making this prototype we had several difficulties, one of which was the non-consistency of the ASTM fittings’ standard among acrylic tube and UPVC and for the remedy, we had to make our own standard even we had made some of the components just because it weren’t available to fit it accordingly, like the inlet portion of the compressor just after the push-in fitting of moisture trap etc. and we did with the help of Machine Shop and Fluid Mechanics Lab in Mechanical Engineering Department. The earlier design included a NRV, which was installed just after the moisture filter but due to severe leakage problems and halting of gauges; we did multiple free flow tests by dis-engaging the NRV and finally decided to remove it permanently. Due to the fluctuations in the gauge reading and lack of finance we weren’t able to get the desired sensitive pressure gauge though we’d installed a globe valve to regulate the flow but in the end agreed on the installation of two valves i.e. one for the drain purpose and the second one for the generation of some back pressure. As this whole working is based on the recycle and somehow a by-pass cum drain; we’d used un-wound hose pipe to recycle the water stream but it dwindled and caused hindrance in the out-flow and in order to rectify this issue we’d removed the hose pipe and replaced it with the UPVC pipe.

2015-09-04 21.34.38 (2)


The demonstrative apparatus consists of two inlets as mentioned above i.e. for the water and air in-flow & two outlets i.e. one serves as a recycle stream and the other one acts for drainage as well as by-pass for the smoothness of flow. Besides some standard fittings it also has some custom pneumatic. We had intended to use the auto-drain moisture trap for its standard purpose but due to some unavoidable circumstances we couldn’t and it now plays the role of an intermediate medium between the water and air which can be better demonstrated and understand rather than explaining here. Precisely, fathom and a foot long acrylic tube (30mm O.D. 26mm I.D.) has been used for the flow visualization rest includes UPVC and couple of pneumatic pipes. The pressure gauge ranges to 10 bar and placed 3.5 foot apart from each other. The 2 HP air-compressor is a single-stage oil-cooled capable of producing 198 L/min at a maximum pressure of 115 psig and has a 24 L tank. It also had come with a built-in regulator apart from the opening valve so we didn’t need to put any further regulation after that. The ½ HP centrifugal pump has the capability to pump about 40 foot head at its standard operating point.

2015-09-04 21.36
The results obtained below are pretty much verifying this graph.


Fortunately, we have been remained successful to get the desired flow-patterns as well as the bulls and bears in pressure drop and somehow able to obtain the hold-up and ratio of gas-to-liquid flow from the graph:


Flow-pattern Pressure (1) (kPa) Pressure (2) (kPa) ∆P


Bubbles 6.89 14.47 7.58 0.724
Plug 9.65 15.16 5.51 0.526
Slug 13.78 18.95 5.17 0.493
Churn 18.61 23.43 4.82 0.461
Annular 26.88 33.08 6.2 0.592
Mist 30.32 38.60 8.28 0.791


All the above readings have been taken at (maximum possible) constant flow-rate but it might vary for the desired flow-pattern. Due to air-water flow the reading at the gauge fluctuates so we have picked the best possible value for explanatory purpose. As we haven’t placed any rotameter so the values mentioned here might not justify with the graph.

* ɣ = 9810 N/m3 & h = 1.067 m

There are a lot of improvements that can be made in this project. For the precise value of the gas-to-liquid ratio in the feed, rota meter should be installed. Also in order to keep the valve handling constant we have to consider controlling the flow-rate by using a variable frequency drive for the pump. These are just recommendations which may be implemented in the near future.


Actual picture of the demonstration showing slug along with bubbles



 p. 344; Smith/Van Ness/Abbott; Introduction to Chemical Engineering Thermodynamics

 p. 60/418; De Nevers; Fluid Mechanics for Chemical Engineers

p. 419; De Nevers; Fluid Mechanics for Chemical Engineers

p. 420; De Nevers; Fluid Mechanics for Chemical Engineers

p. 420; De Nevers; Fluid Mechanics for Chemical Engineers


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