Chemical & Process Technology

Earlier post “Seawater Treatment & Injection For Well Maintenance & Increase Productivity” discussed about the water source and its associated water injection treatment. Seawater will be filtered with coarse and fine filters to remove particles smaller than 2 micron with 98% removal efficiency. Filtered seawater will be deaerated to bring the Oxygen concentration down to 20 ppb. Oxygen scavenger is then injected to further reduce the Oxygen concentration down to 10 ppb in order to reduce corrosion to cost effective level. Chlorine is injected to injection water to avoid bacteria and alga growth.

Residue Oxygen in injection may still result corrosion in the pipeline. How much it affect the corrosion of Carbon steel pipeline ? Present of Chlorine is known further increase corrosivity of injection water. How this impact the corrosion water ? Increase of water velocity in pipeline will increase flow induced erosion of pipeline. Simultaneous erosion (flow induced) - corrosion (Oxygen & Chlorine) present in the pipeline. How water velocity affect corrosion ? What is the water velocity limit ? This post will present a water velocity limit with varies of oxygen concentration (and Chlorine content) in water .

Water injection is common applied in maintaining crude reservoir to increase crude productivity. For offshore facilities, seawater is commonly lifted and treated for water injection purpose. The water injection rate is subject to reservoir condition and crude production. Particle present in seawater potentially results formation blockage and reduce injectivity. Oxygen present in seawater potentially results severe corrosion of transfer pipeline and injection tubing. Alga and bacteria present in seawater may potentially growth result corrosion and formation blockage. Therefore seawater use for injection shall be treated prior transfer and injection.

Seawater lifted will pass through filtration package. The filtration package commonly consist of two levels of filtration. First level filtration is also known as Coarse Filtration where the filter is provided to remove particle with size larger than 80-100 micron. The common required removal efficiency is 98%. The filter is normally equipped with auto-backwash facilities e.g. rotational backwash motor. Second level filtration is also known as Fine Filtration where the filter is provided to remove particle with size large than 2 micron with removal efficiency of 98%. Similarly this filter is equipped with auto-backwash facilities with the assistance of blower.

Seawater is aerated in ambient contains high oxygen contents. Typically the seawater is considered saturated with oxygen and this quantity is sufficient to results significant corrosion in transfer pipeline and injection tubing. Corrosion is increased with increased in quantity of oxygen in seawater. The oxygen level in the seawater is commonly deaearated down to 20-40 ppb in the deaeration column. Oxygen scavenger is injected downstream of deaeration column to further bring the oxygen level down to 10-20 ppb. Two main methods are used for deaeration :

Bacteria presents in seawater may results corrosion and alga growth which release solid waste to promote formation plugging. Hypo-Chloride is injected to prevent bacteria and alga growth. One shall take note present Chlorine is seawater may also results corrosion. Concentration subject to type of Biocide, however 5 ppm level could be good guess.

Present of Chlorine, residue bacteria and residue oxygen promote corrosion. Therefore corrosion inhibitor (CI) is injected to prevent / minimize corrosion. Concentration subject to type of CI, however 5 ppm level could be good guess.

Sulfide -stress cracking is basically a hydrogen-embrittlement phenomenon .Atomic hydrogen enters the steel to cause cracking. The hydrogen is generated on the surface of the steel because of a corrosion reaction. Iron reacts with h2s to form iron sulfide and hydrogen .This hydrogen is generated in atomic form on the steel surface ,where it can either combine to form molecular hydrogen and leave the surface as bubbles or diffuse into steel .This latter process may result in hydrogen embrittlement .Hydrogen sulfide prevents hydrogen recombination & thus promote entry of atomic hydrogen into steel .It is important to note that water must be present for this mechanism to occur ;without it SSC will not be observed ,because the ionization of the hydrogen sulfide is required.

Following is a lecture presentation on NACE Standard MR0175  - Petroleum and Natural Gas Industries – Materials for use in H2S-containing Environments in Oil and Gas Production.

 

Download

• NACE MR0103 versus MR0175
• Common FAQs Related to NACE Standard MR0175 / ISO 15156
• Material Selection... USER Responsibility
• Error in NACE MR0175 / ISO 15156
• Guideline on Use of MR0175 / ISO15156
• What are the concerns related to H2S ?
• Safety Moment with H2S
• Pyrophoric Fire
• Pitting Corrosion - Mechanism & Prevention

NACE MR0103 "Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environments" was developed by Task Group 231 to provide a standard set of requirements for materials used in sour petroleum refinery equipment. In the past, NACE MR01752, "Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment", was frequently referenced for this equipment, even though refinery applications were outside the scope of MR0175. The process used to develop MR0103 is described, followed by a review of the requirements in the standard accompanied by highlights of the differences between MR0103 and the previous and current versions of MR0175.

An Overview of NACE International Standard MR0103 and Comparison with MR0175 

Recommended :Earlier post "Crevice Corrosion Mechanism & Prevention" has briefly discussed mechanism of crevice corrosion and its prevention. As discussed, one of the preventive measures is to select correct material to resist crevice corrosion. Stainless Steel (SS) is known to resist to general corrosion by forming a thin, protective oxide film on it external surface, SS still susceptible to localized corrosion i.e. Chloride stress corrosion cracking (CSCC), crevice corrosion, pitting corrosion, etc once this protective film is partly damage. Stainless steel once expose to water (present of Chloride) with temperature higher than 60 degC, CSCC is potentially occurred. On the other hand, temperature lower than 60 degC, crevice and pitting corrosion is potentially occurred.

There are different grade of Stainless Steel i.e. SS304, SS316, S31803, S32205, etc. How Chloride [Cl] concentration, Sulfate [SO4] concentration, pH level, temperature, oxygen level, etc affecting crevice corrosion for different Stainless Steel ?


The Crevice Corrosion Engineering Guide for Stainless Steels (CCEG) is a program available FREE to check type of Stainless Steel susceptible to crevice corrosion in water under particular conditions and impurities. The CCEG is a program with predictive mathematical model of crevice corrosion to assist with the selection of stainless steels for use in chloride and sulphate containing waters, including sea water. It was jointly developed by Nickel Development Institute (NiDI) and Sheffield Testing Laboratories Ltd.

Application Range
This program has been developed with the following application range :

• Fluid : Water
• Operating temperature : 5 - 85 degC
• Chloride [Cl] concentration : 1-30,000 ppm
• Sulphate [SO4] concentration : 0-10,000 ppm
• Total Dissolved Solids (TDS) concentration : 0 - 65000 ppm or mg/L
• * Can be calculated base on 1.65 [Cl] + [SO4]
• Alkalinity : 0 - 10000 mg/L (as concentration of CaCO3 in mg/L)
• Hardness : 0 - 20000 mg/L (as concentration of CaCO3 in mg/L)
• pH : 5 - 9

Stainless Steel Grade Can be Checked
The program will check for following material :

• S30400
• S31600
• S31700
• S31803
• S32205
• N08904
• 6% Mo SS

Example
Let take a water with following parameters :

• Chloride (ppm) : 1000
• Sulphate (ppm) : 100
• Hardness (as CaCO3 mg/L) : 100
• Alkalinity (As CaCO3 mg/L) : 100
• TDS (mg/L) : 1798
• pH : 7
• Temp (C) : 25
• Oxygen level (ppm) : 7

CCEG predict corrosion will not occur with S31803 however corrosion will initiate in days with S31600.

Download : Click here to download the program (1.17 MB).
Source : Nickel Development Institute (NiDI)

Related Topics

• Crevice Corrosion Mechanism & Prevention
• Pitting Corrosion - Mechanism & Prevention
• Chloride stress corrosion cracking and use of correct MOC for seawater
• How Chloride stress corrosion cracking Lookslike ?
• Unified Numbering System for Metals and Alloys

Recommended :
- Subscribe FREE - Energy Biz
- Tips on Succession in FREE Subscription

Crevice is location /area / space where normal fluid has less contact and access with it. Typical example of crevice are gaps between parts, space between gaskets and bolt, inside seals, inside cracks due to external impact or scratches, spaces filled with deposits, plastic paper lay on the metal plate, etc. In crevice, the environment is different than area expose to normal fluid. For example, gasket with bolt. Bolt surface expose to atmosphere is oxygen rich while wet air trapped between bolt and gasket is stagnant and with limited oxygen. Localized corrosion occur in the crevice is called crevice corrosion.

Crevice Corrosion Example
Following is an example of crevice corrosion at pipe support.


Crevice corrosion is pretty similar to pitting corrosion as discussed in "Pitting Corrosion - Mechanism & Prevention".



Mechanism
A metal surface with gasket at shown above will potentially experience crevice corrosion. Oxygen rich fluid enters crevice between gasket and metal surface.

- Genenal Oxidation Corroion
Normal corrosion (general oxidation corrosion) will occur through the metal surface outside and inside the crevice. As oxygen in trapped fluid consumed oxygen, environment within crevice is deoxygenated (low in oxygen level) increases the potential difference between crevice environment and oxygen rich environment.

Metal (E.g. FE) surface (expose to atmosphere) is oxygen rich will becomes the cathode whilst the metal surface in the crevice (gasket contacted area) is low in oxygen level will becomes anode

. This form a complete circuit where metal at the crevice (FE) will be ionized to release electron (e) and form ion Ferum (FE2+), this electron will travel to the metal surface expose to atmosphere to react with Oxygen (O2) and water (H2O) to form ion hydroxides (OH-). Ion Ferum (FE2+) will react with ion hydroxides (OH-) to form Ferum Oxide (Fe2O3) which typically a brown rust.

- Increases Acidity in Crevice Environment
The ions FE2+ formed potentially hydrolyze water (H2O) in tapped fluid and produced positive ion (i.e. H+) and FE (corrosion product). The corrosion product will further block the movement of trapped fluid and increase the corrosion potential. The H+ will further increase the acidity of the trapped fluid and this severely increases corrosivity of trapped fluid.

- Other Corrosion i.e. CSCC
Production of ion positive (H+) will also attract negative ions i.e Chlorides, Sulfates, etc outside crevice travel into the trapped fluid in crevice, accumulation of these negative ions will potentially results Chloride and Sulfate associated corrosion such Chloride stress corrosion cracking (CSCC).

Stainless steel is one type of material commonly used in oil & gas, refinery, petrochemical, pharmaceutical industries. Stainless steel is a material does not stain and corrosion resistance to many fluids. Stainless steel is rather "soft" and infact it is a cavitation resistance material. This has been discussed in "Stainless Steel SS316 resist to CAVITATION ?".

Recommended :
- Subscribe FREE - Processing Magazine
- Tips on Succession in FREE Subscription

Although Stainless steel is corrosion resistance to many corrosive fluids by formation of protective oxide film, it is still susceptible to pitting corrosion, one of the most destructive forms of corrosion which potentially cause equipment failures on perforation / penetration as discussed in "Pitting Corrosion - Mechanism & Prevention".

Beside pitting corrosion, stainless steel also susceptible to Chloride Stress Corrosion Cracking (CSCC) as discussed in "Chloride Stress Corrosion Cracking & Use correct MOC for seawater service". CSCC is initiation and propagation of cracks in a metal or alloy under tensile stresses and a corrosive environment contains Chloride compounds. Once the crack is initiated, it will propagate rapidly and potentially lead to catastrophic failure. There are more discussion on stainless steel can be found here.

Dr. David Jenkinson, Director of Nickel Institute has produced a series online training modules on "An Introduction to Selection of Stainless Steels for Corrosion Resistance". The online training modules are in audio format which can be read while listen to the explanation. Visual plus audio will quickly assist engineers in understanding the contents.

Click here to begin learning Stainless Steel and It Selection.

Following are complete listing of training module for Stainless Steel and It Selection.

01 - Disclaimer
02 - Module Abstract
03 - Module Information
04 - Chemical Symbols
05 - What Will We Cover?
06 - What Will We Cover? - What is Stainless Steel?
07 - How Stainless Steel Works
08 - Chromium is the Basic Building Block of Stainless Steels
09 - Damage to the Protective Oxide Film
10 - Penetration of the Protective Oxide Film
11 - Corrosion of Embedded Iron in a Stainless Steel Pipe Bend
12 - The protective passive film can be damaged mechanically or chemically in various ways.
13 - What Will We Cover? - Effect of Alloying Additions
14 - Effect of Alloying Additions
15 - 1. Corrosion Resistance
16 - Effect of Alloying Elements on Corrorsion Resistance - Chromium
17 - Effect of Chromium on Atmospheric Corrosion of Steels
18 - Pitting Resistance Equivalent Number (PRE)
19 - Effect of Alloying Elements on Corrosion Resistance - Nickel
20 - Addition of Nickel
21 - Nickel Provides Resistance to Reducing Chemicals
22 - Effect of Alloying Elements on Corrorsion Resistance - Molybdenum
23 - Effect of Alloying Elements on Corrorsion Resistance - Nitrogen
24 - Effect of Alloying Elements on Corrorsion Resistance - Carbon
25 - Hibernia Oil Production Platform
26 - 2. Crystal Structure
27 - Ferritic Stainless Steels
28 - Adding Nickel to Stainless Steels
29 - Austenitic Stainless Steel
30 - Duplex Stainless Steels
31 - List of Ferrite & Austenite Formers
32 - When Choosing a Stainless Steel
33 - What Will We Cover? - Families of Stainless Steels
34 - Families of Stainless Steels
35 - Ferritic Stainless Steels
36 - Typical Compositions of Common Stainless Steels
37 - Type 409 is hte most widely used ferritic stainless steel.
38 - Proprietary Grades
39 - Dishwashers
40 - Stainless Steel Refrigerators
41 - Hot Water Tank
42 - Austenitic Stainless Steels
43 - Typical Compositions of Common Stainless Steels
44 - Domestic Kitchen Sink
45 - Parliament House, Canberra, Australia
46 - Type 304 Stainless Steel Beer Kegs
47 - Chemical Plant
48 - Frederick R. Weisman Art Museum
49 - Wet Electrostatic Precipitator
50 - Duplex Stainless Steels
51 - Typical Compositions of Common Stainless Steels
52 - Type 316LN Stainless Steel - Example
53 - Pressurized Peroxide Reactor
54 - Stainless Steel Meat Racks
55 - Elevator Tower
56 - Families of Stainless Steels
57 - Martensitic Stainless Steels
58 - Typical Compositions of Common Stainless Steels
59 - Stainless Steel Products - Examples
60 - Martensitic Stainless Steel Blades
61 - Precipitation Hardening (PH) Stainless Steels
62 - Typical Compositions of Common Stainless Steels
63 - High Strength S45000 Precipitation Hardening Stainless Steel
64 - What Will We Cover? - Maximizing Corrosion Resistance
65 - Corrosion of Carbon Steel
66 - General Corrosion
67 - Localized Corrosion
68 - Pitting
69 - Once it gets started, pitting is difficult to stop and to repair.
70 - PRE Numbers for Some Ferritic, Austenitic & Duplex Grades
71 - Pitting Corrosion - Effect of Temperature and Chloride Level
72 - Crevice Corrosion
73 - Crevice Corrosion - Example
74 - Chloride Stress Corrosion Cracking (SCC)
75 - Chloride Stress Corrosion Cracking - Example
76 - Copson Curve
77 - Chloride Stress Corrosion Cracking - Effect of Temperature and Chloride Level
78 - What Will We Cover? - High Performance Stainless Steels
79 - High Performance Stainless Steels
80 - Pitting and Crevice Corrosion Resistance
81 - Three Families of High Performance Stainless Steels
82 - PRE Numbers for Some Ferritic, Austenitic & Duplex Grades
83 - Immersed in Seawater Without Cathodic Protection
84 - Heat Exchanger
85 - Flexible Hosing
86 - Heat Exchanger for Aggressive Chloride Service
87 - Zeron 100 Fittings
88 - Condenser Tubes
89 - What Will We Cover? - Nickel Alloys
90 - More Resistant Alloys
91 - Nickel Alloys
92 - Alloy C-276
93 - Summary

Further Reading

• Chloride Stress Corrosion Cracking & Use correct MOC for seawater service
• Pitting Corrosion - Mechanism & Prevention
• How Chloride stress corrosion cracking Lookslike ?
• Different Equation for Pitting Resistance Equivalent Number (PREN)
• Unified Numbering System for Metals and Alloys

Recommended :
Subscribe FREE - Processing Magazine

H2S dissolved in water to form weak acid promote corrosion and form free hydrogen. Free Hydrogen will penetrate the metal, reduce ductility of metal and potentially lead to stress failure below it yield stress, results Sulphide Stress Corrosion Cracking (SSCC).

Sulfide stress corrosion cracking (SSCC) is cracking of metal involving corrosion and tensile stress (residual and/or applied) in the presence of water and H2S. SSC is a form of hydrogen stress cracking (HSC) and involves embrittlement of the metal by atomic hydrogen that is produced by acid corrosion on the metal surface. Hydrogen uptake is promoted in the presence of sulfides. The atomic hydrogen can diffuse into the metal, reduce ductility and increase susceptibility to cracking. High strength metallic materials and hard weld zones are prone to SSC.

NACE Standard MR0175 / ISO 15156 - Petroleum and Natural Gas Industries – Materials for use in H2S-containing Environments in Oil and Gas Production was established to provides limits of H2S partial pressure for precautions against sulfide stress cracking (SSC) and guidance for the selection and specification of SSC-resistant materials.

Since the released of this NACE MR0175 / ISO 15156, it has introduced a few more elements into the "sour" service criteria i.e. pH, Chloride contents, etc. This may have created some level of difficulties in understanding and usage of this standard.

Canadian Association of Petroleum Producers (CAPP) has released a document entitle "GUIDE in Use of International Standard NACE MR0175/ISO15156" to provides a supporting document, which may be used as a reference tool to :

• provide a brief overview of the NACE / ISO publication, outlining the most significant changes and their implication to the industry,
• provide guidance and assistance on how to apply the new publication using simple to follow flowcharts, and clarification examples,
• provide sample forms which could be used to meet the intent of the publication.
  

This is a continuation post from "CO₂ Corrosion in Oil & Gas - Part 1" on the useful article related to CO₂ corrosion in Oil & Gas.

Electrochemical Impedance Spectroscopy (EIS) is a powerful transient technique which enables an insight into the corrosion process not easily obtained by other predominantly DC techniques. However the EIS technique presents a large challenge both from a theoretical as well as an experimental point of view. Collecting accurate EIS raw data is not easy as EIS is plagues with errors not seen by the DC techniques. Building mechanistic models to capture the EIS data is a very complex task which enables extraction of valuable information about the corrosion process, however the time and effort investment required is very large. In this study of CO₂/H₂S corrosion of mild steel it was found that a “minor” detail in the experimental set-up caused erroneous acquisition of EIS raw data. These data were “successfully” modeled by using a complex electrochemical theory, which appeared plausible. When the experimental mistake was discovered the EIS data were retaken, the analysis was redone and the conclusions about the corrosion process were completely revised.

Glass cell experiments were conducted to investigate kinetics of iron sulfide and mixed iron sulfide/carbonate scale precipitation in CO₂/H₂S corrosion. Weight gain/loss (WGL) method was used to investigate the scale formation using X65 carbon steel as substrates. Scanning Electron Microscopy (SEM/EDS), X-ray Diffraction methodology (XRD), X-ray Photoelectron Spectroscopy (XPS), and Electron Probe Micro-analyzer (EPMA) were used to analyse the scale. The experimental results show that the corrosion products formed in CO₂/H₂S system depend on the competitiveness of iron carbonate and mackinawite. At high H₂S concentration and low Fe²⁺ concentration, mackinawite was the predominant scale formed on the steel surface. At low H₂S concentration and high Fe²⁺ concentration, both iron carbonate and mackinawite form. It was also found that ferrous ions forming mackinawite scale mainly come from Fe²⁺ released from the steel surface.

Internal corrosion occurs only when corrosive water wets the pipe inner wall. However, water wetting is one of most important missing links of our current overall understanding of internal corrosion of oil and gas pipelines. In this study, extensive experimental studies on water wetting in large diameter horizontal oil water pipe flows were carried out. Four main techniques (wall conductance probes, Fe²⁺ concentration monitoring, wall sampling and flow pattern visualization) were used to determine phase wetting on the internal wall of pipe at different superficial oil and water velocities. Four flow patterns were observed : stratified flow, stratified flow with mixed layer, semi-dispersed and dispersed flows. Three types of phase wetting regimes (water wetting, intermittent wetting and oil wetting) were determined. A comprehensive phase wetting map was obtained based on the overlapping information from these techniques.

Recommended :
- Tips on Succession in FREE Subscription
- Subscribe FREE - Upstream magazine

CO₂ Corrosion of Carbon Steel in High Ionic Strength Brine Solution

The general CO₂ corrosion rates of C1018 carbon steel have been measured for NaCl concentrations 3 – 25 wt% at 5ºC, pH4.0. The corrosion process was monitored by linear polarization resistance and potential dynamic sweeps. Experimental results show that high salt concentrations affect the general CO₂ corrosion rate significantly and nonlinearly. Potentiodynamicsweep analysis shows that the high content of salt retards both cathodic and anodic process. No significant effects of velocity on corrosion rates are seen for various saline conditions

Glass cell experiments were conducted to understand kinetics of iron carbonate scale formation in pure carbon dioxide (CO₂) corrosion of mild steel. Weight gain and loss (WGL) method was used as a direct approach to investigate kinetics of scale formation. The experiments were done at the temperatures of 60oC to 90oC, and an iron carbonate supersaturation range of 12 to 350. It is found that the calculated results obtained by the previous kinetics expressions using the traditional dissolved ferrous ion concentration method are one to two orders of magnitude higher than the experimental precipitation rates obtained in the present study by the WGL method. The results show that the main source of the ferrous ions which are involved in formation of the protective iron carbonate scale is the iron dissolution process. It has been clearly demonstrated that the precipitation rate of iron carbonate is directly related to the conditions at the steel surface which can frequently be very different from the one in the bulk fluid.

An important aspect in corrosion prediction for oil and gas wells and pipelines is to obtain a realistic estimate of the corrosion rate. Corrosion rate prediction involves developing a predictive model that utilizes commonly available operational parameters, existing lab/field data and theoretical models to obtain realistic assessments of corrosion rates. The Case-based Reasoning (CBR) model for CO₂ corrosion prediction is designed to mimic the approach of experienced field corrosion personnel. The model takes knowledge of corrosion rates for existing cases and uses CBR techniques and Taylor series expansion to predict corrosion rates for new fields having somewhat similar parameters. The corrosion prediction using CBR model is developed in three phases: case retrieval, case ranking, and case revision. In case retrieval phase, the database of existing cases is queried in order to identify the group of cases with similar values of critical corrosion parameters. Those cases are ranked in the second phase, using a modified Taylor series expansion of the corrosion function around each case. The most similar case is passed to the third phase: case revision. The correction of the corrosion rate by using a mechanistic corrosion model is utilized in order to predict the corrosion rate of the problem under consideration. The (CBR) model has been implemented as a prototype and verified on a large hypothetical case database and a small field database with real data.

Localized CO₂ corrosion on mild steel is always associated with the partial breakdown of a protective corrosion product scale such as iron carbonate. The scale breakdown can happen for a variety of reasons many of them related to fluid flow. It is hypothesized that following the scale damage, a galvanic effect is established between the scale covered surface (cathode) and the scale free surface (anode) leading to propagation of localized attack. To test this hypothesis, in a series of laboratory experiments, an iron carbonate scale is formed by a repeatable process. Subsequently, in the so called “scale removal tests” the breakdown of the scale under flowing conditions is investigated. The results show that the iron carbonate scale can be partially removed by mechanical stresses, chemical dissolution or by both mechanisms acting simultaneously. In another series of experiments, a newly developed “artificial pit” test is used to investigate the propagation of localized CO₂ corrosion via a galvanic coupling. The artificial pit is composed of a large cathode covered by protective iron carbonate scale, and a small bare steel anode. The two are electrically isolated and connected by a zero resistance ammeter to measure the galvanic current during the tests. The results have confirmed the galvanic mechanism for localized CO₂ corrosion propagation. It has been demonstrated that pits will propagate only if the conditions are just right: the solution is neither under-saturated nor heavily supersaturated with respect to iron carbonate, i.e. they are in the so called “grey zone”.

In the majority of the published work related to organic acid corrosion of mild steel, the focus is on acetic acid due to its prevalence in a typical organic acid mix seen in the field. In this work, the electrochemical behaviour of X65 carbon steel in the presence of other important organic acids (formic and propionic) and the effect that these have in the growth and protectiveness of iron carbonate (FeCO₃) scale have been investigated. It was found that very little difference exists in electrochemical behaviour of the formic, acetic and propionic acids when it comes to CO₂ corrosion of mild steel, given that the pH and concentrations of the undissociated organic acids is the same. Just like the other two weak organic acids, formic acid increases the corrosion rate due to an additional cathodic reaction: direct reduction of undissociated formic acid; this reaction is very temperature sensitive and may be limited by diffusion. The presence of organic acids makes it harder for protective iron carbonate scales to form due to a “scale undermining” effect. The scale precipitation rate is not directly affected, however, the time it takes to reach low corrosion rates is.

Recommended :
Subscribe FREE - Utility Automation & Engineering T&D

equipment and piping contact with the oil and gas. Read more in "What are the concerns related to H2S ?". Presence of Hg in Aluminum material i.e. coldbox and MCHE would lead to mercury embrittlement whilst Cl in hot stainless steel surface would lead to Chloride Stress Corrosion Cracking (CSCC). Read more in "Chloride Stress Corrosion Cracking & Use correct MOC for seawater service".

CO₂ with presence of free water would lead to generation of Carbonic acid (H₂CO₃).

When Carbonic Acid contact with steel (Fe), reaction occur.

Since the initial studies by DeWaard and Milliams'(1975), there are many other follow-up studies on the corrosion phenomena. Videm & Dugstad (1989), Dunlop, Hassell & Rhodes (1983), DeWaard, Lotz & Milliams (1991), But Dugstad (1992), DeWaard & Lotz (1993), Efird, Wright, Boros & Hailey (1993), Dugstad, Lunde & Videm (1994), etc have further studies the CO2 corrosion phenomenon. Following is compilation of articles related to CO2 Corrosion :

Integrated CO2 Corrosion - Multiphase Flow Model
An integrated CO₂ corrosion – multiphase flow model was built which takes into account the effect of most important variables. The model is mechanistic in nature and resides on clear theoretical foundations. All the assumptions in the model are explicitly stated and are open to future adjustments and improvements. The overall model was extensively verified with a large experimental database and was able to perform reasonably well in all cases. The multiphase flow model was also benchmarked against a well-established commercial package.

CO₂ Corrosion Mechanistic Modeling and Prediction in Horizontal Slug Flow
This paper presents a CO₂ corrosion mechanistic model specifically developed for the horizontal multiphase slug flow. It covers electrochemical reactions at the steel surface, transport of reactive species between the metal surface and the bulk, and the chemistry in the bulk solution. The special mass transfer correlations in slug flow were applied in this model. The model can predict the corrosion rate in horizontal slug flow. Comparison with laboratory experimental corrosion results revealed that it could help the understanding of the internal corrosion of horizontal pipeline under slug flow condition. Furthermore, this model shows that the Froude number and the slug frequency are two important factors influencing the internal corrosion rates under multiphase slug flow. This provides an insight for the pipeline design and production under multiphase slug flow.

The Effect of CI- and Acetic Acid on Localized CO₂ Corrosion in Wet Gas Flow
Wet gas corrosion rates of C1018 and X65 steel have been measured at the top and bottom of a
high pressure, 10 cm diameter horizontal pipeline under stratified flow conditions with different chloride (Cl-) concentrations. Experiments were performed for 200 hours at 90°C, CO2 partial pressure of 3.8 bar using a superficial gas velocity (Vsg) of 10 m/s and a superficial liquid velocity (Vsl) of 0.1 m/s. Three measurement techniques; ER, LPR, and WL were used simultaneously in the experiments. Localized corrosion occurred at the bottom of the pipe around the iron saturation point. The top of line was well protected by a thin corrosion product film and no localized corrosion was detected. C1018 and X65 have different sensitivities to pitting with a variation in Cl- concentration. Thus the pitting density concept is proposed to describe localized corrosion behavior. Surface analysis on iron carbonate films, by SEM and XRD, revealed different film thicknesses and crystal structures from the top to the bottom of the pipe. Cross-sectional analysis indicates that the thin corrosion product film, usually less than 10 microns, attached to the metal surface, is responsible for the low corrosion rate on top of the line, while the thick and porous film formed on the bottom, generally detached from the metal surface, was responsible for the initiation of localized corrosion.


Subscribes to FREE Hydrocarbon Processing

Top of Line Corrosion in Presence of Acetic Acid and Carbon Dioxide (CO₂)
This paper deals with the phenomena of corrosion by acetic acid and carbon dioxide at the top of a horizontal pipeline under dewing conditions. The effect of different parameters known to influence the Top of the Line Corrosion (TLC), such as the condensation rate and the bulk temperature is studied. The free acetic acid concentration varies from 0 to 1000 ppm, the bulk temperature, is set mainly at 70oC, the condensation rate is varied while the partial pressure of carbon dioxide and the gas velocity are set at a fixed value. The presence of acetic acid increases the corrosion rate both at the top and at the bottom of the line in different ways. The condensation rate influences strongly the top of the line corrosion when it has a small influence at the bottom. Evidences of localized corrosion are found at the bottom of the line. The corrosion at the top is uniform in the experiments conducted.

CO₂ Corrosion in the Presence of Trace Amounts of H₂S
Experiments were conducted to determine the effect of an incremental change in the solution pH, from 4 to 6.6, on CO₂ corrosion rates of AISI 1018 steel in the presence of H₂S in both single phase flow (Vsl = 1 m/s) and multiphase flow (Vsg=3 m/s, Vsl= 1 m/s) in a large scale multiphase flow loop. Linear polarization probes, electrical resistance probes, and weight loss coupons were used to monitor corrosion rates during 4 to 10 day exposures to a CO₂ saturated solution with trace amounts of H₂S. The media for experimentation was a 1% NaCl solution at 60ºC, at 7.9 bar (100 psig) total pressure, with gas phase additions of H₂S up to 100 ppm. Protective adherent films, seen under these conditions, limited corrosion rates in both single phase and multiphase flow conditions.

Iron carbonate scale growth and the effect of inhibition in CO₂ corrosion of mild steel
Investigations were conducted to investigate iron carbonate scale precipitation, the interaction between a corrosion inhibition and the precipitating iron carbonate scale, and their effects on the corrosion rate. Both the effects of iron carbonate precipitation on inhibited and uninhibited surfaces and the effects of inhibition on surfaces with iron carbonate scale were studied. The experiments were done in glass cells at 80 °C and a iron carbonate supersaturation range of 7 – 150. A generic imidazoline based inhibitor was added at various points in the iron carbonate scale formation process. Both corrosion rates and precipitation rates were measured using electrochemical and weight gain/loss methods. The scale was later analyzed using scanning electron microscopy (SEM). It was found that the dissolved ferrous ion concentration method, used previously, overestimates the rate of iron carbonate precipitation. Although no antagonism was found under any of other conditions tested, it was seen that the addition of the inhibitor retarded the growth of the iron carbonate scale.

Effect of acetic acid, pH and MEG on the CO₂ top of the line corrosion
This research work presents a study of Top of the Line Corrosion (TLC) on carbon steels in the
presence of carbon dioxide and acetic acid. The influence of different parameters such as the presence of mono-ethylene glycol (MEG) and the use of pH control were studied in a 4” diameter flow loop. Two sets of experiments were conducted; one at 70ºC, high CO₂ partial pressure and a “critical” condensation rate and another one at 80ºC, low CO₂ partial pressure and a high condensation rate. Weight loss techniques and surface analysis were used to evaluate the corrosion rate and products. It was found that the presence of HAc at the concentrations evaluated does not affect the general corrosion rate at the top of the line. Top of the line corrosion rates correlate with the De Waard / Lotz estimate of 10% of bottom of the line rates15. It is believed that the corrosion mechanism is still controlled by CO₂ partial pressure at the experimental conditions evaluated in this study. The presence of MEG has not shown any effect on TLC due to the fact that the condensation rate was kept constant. The use of pH control in the supply is believed to limit the amount of HAc in the condensed water. No clear evidence of localized corrosion or pits can be reported at this stage of the study due to the short time of exposure.

CO₂/H₂S corrosion under scale forming conditions
Three different mild steel coupons with two different surface areas were exposed to a CO₂ saturated multiphase environment with a trace amount of hydrogen sulfide under supersaturated scale forming conditions designed to increase the probability of localized corrosion. Corrosion testing was conducted in the region of low supersaturation values for iron carbonate (SS_FeCO3 < 10) and three different supersaturation values for iron sulfide (2.5 < SS_FeS < 125) through adjustment of the partial pressure of H₂S during 30 day exposures to system conditions. Experiments were conducted in a 1% NaCl solution at 60ºC, pH 6.0, 0.77MPa partial pressure CO₂ with trace amounts of H2S in both single phase flow (Vsl = 1 m/s) and multiphase flow (Vsg=3 m/s, Vsl= 1 m/s). Under the conditions tested, both siderite and mackinawite films were developed as adherent corrosion product films. Localized corrosion was observed.

Click CO2 Corrosion in Oil & Gas - Part 2 to continue...

Related Post

• What are the concerns related to H2S ?
• Several Concerns in High CO2 Field Development
• How does Supercritical fluid looks like ?
• High Temperature Hydrogen Attack in metal & alloy
• Hydrogen Embrittlement TEST method
  
• Chlorride stress corrosion cracking and use of correct MOC for seawater
• Pitting Corrosion - Mechanism & Prevention
• How a Chloride Stress Corrosion Cracking Lookslike ?