Corrosion And Its Mitigation In The Oil And Gas Industry.pdf x4m4o

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Corrosion and its Mitigation in the Oil & Gas Industry – An overview By Mr. Nalli. K Introduction: The oil and gas industries – mainly concerning the exploration, production operations, the field operators normally would like to have uninterrupted supply of oil and gas to the export or processing points. The lines and the component fittings of the lines would undergo material degradations with the varying conditions of the well due to changes in fluid compositions, souring of wells over the period, changes in operating conditions of the pressures and temperatures. This material degradation results in the loss of mechanical properties like strength, ductility, impact strength etc; leads to loss of materials, reduction in thickness and at times ultimate failure. Hence it is imperative for the field operators, pipeline engineers, designers to have “Corrosion Awareness” concerning the oil and gas industries in their day to day activities to combat and mitigate corrosion and to ensure smooth and uninterrupted flow of oil and gas to the end s. The present brief is an attempt in this direction. Wealth of information is available on corrosion and it’s mitigation in the oil and gas industry through case histories, technical papers, published literature and corrosion institutes, however the present brief is summary and consolidated information pooled from various sources for the benefit of the process, operations, maintenance and integrity engineers involved in the oil and gas activities.

Well head Fluids: The reservoir fluids in oil and gas fields around the world vary greatly in composition. Some cases the fluid is in gaseous state, in others it is in liquid state. Frequently gas and liquid co-exist in a given reservoir. The reservoir fluids basically comprise of any one or combination of the following types of fluids with dissolved and suspended solids – based on the reservoir formation

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and locations. Liquid hydrocarbons and multiphase systems Gas and gas condensates Formation waters, Sea waters, Brackish waters The ageing reservoirs will be souring (increase in the acid gas-Hydrogen Sulfide level) and with the increase in the water cut the corrosivity of the fluids increases as the well is being drained of the fluids. Fig 1 indicates the general process scheme indicating the various functions in a typical oil and gas exploration and production facilities.

• • • • •

Corrosion and Corrosion morphology: Corrosion is defined as physiochemical reaction between the metal and the environment resulting in material degradation and thus leading to impairment of the intended function of the metal, environment or the integrity of the system. This can be general corrosion or regular loss of metal on the exposed surface or can be localized corrosion where only a limited portion of the surface is in .

Corrosion in Oil and Gas industry: Corrosion in oil and gas industry is mainly due to the reservoir and well fluids tapped during the exploration and production operations. Some of the contents present in the well fluid are represented in Table 1. These constituents few of them or all of them may be present in varying compositions. Each one of the component in the fluid will have influence on the corrorsivity of the fluid and will determine the performance of the materials in . Some of the corrosive mechanisms generally observed in the oil and gas industry and the impact of corrosion agents in the fluid are briefly discussed in the following sections.

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The presence of Bicarbonates in the phase improves the alkalinity of the fluid and thus reduces the corrorsivity of the environment. Acetates in the well fluids observed to affect the corrosion rate and rate of corrosion is observed to be low when acetate concentration in the fluid is low.

Hydrogen Sulfide Corrosion (Hydrogen Attack and Sour Corrosion) Though the presence of Hydrogen Sulfide corrosion is less significant, the primary concern with Hydrogen Sulfide is Hydrogen attack on the metal and causing the metal embrittlement. Fluids with high levels of H2S are termed as SOUR and NACE defines the H2S levels above 0.05 psi of partial pressure as sour condition. The Hydrogen attack mechanism is complex and is caused by absorption of atomic Hydrogen in steel depending upon certain pressure, temperature and the pH value of the fluid. The forms of sour corrosion are uniform, pitting, and step wise cracking as shown in Fig 3.

Table 1

Fig 1.Typical Processing Scheme for Oil and Gas Facility

CO2 Corrosion (Sweet Corrosion):

CO2 is one of the main corroding agents in the oil and gas production systems. CO2 will mix with the water forming Carbonic acid making the fluid acidic (reducing the pH value).CO2 corrosion is influenced by temperature and increase in pH value. At elevated temperatures Iron carbide (Siderite) scale will form on the material as a protective scale and corrosion rate is reduced. The metal starts corroding under these conditions and the forms of CO2 corrosion are ringworm corrosion, Mesa corrosion and pitting corrosion as shown in Fig 2. CO2 corrosion is enhanced in the presence of Oxygen and organic acids which dissolve the protective Iron carbide scale and prevent further scale formation.

Component

Symbol

Unit

Carbon Dioxide

CO2

Mole/mole %

Hydrogen Sulfide

H2S

Mole/mole %

Oxygen ( Dissolved )

O2

Mg/lit or ppb

Chlorides

Cl-

Mg/lit (ppm)

Bicarbonates

HCO3-

Mg/lit (ppm)

Iron

Fe2+

Mg/lit (ppm)

Magnesium

Mg2+

Mg/lit (ppm)

Potassium

K+

Mg/lit (ppm)

Sodium

Na+

Mg/lit (ppm)

Calcium

Ca2+

Mg/lit (ppm)

Sulfates

SO4-

Mg/lit (ppm)

Sulfur

S

Mg/lit (ppm)

Mercury

Hg

Mg/lit (ppm)

Lead

Pb

Mg/lit (ppm)

Zinc

Zn

Mg/lit (ppm)

Chromium

Cr

Mg/lit (ppm)

Barium

Ba

Mg/lit (ppm)

Total Hardness

As CaCO3

Mg/lit (ppm)

Total Suspended Solids

TSS

Mg/lit (ppm)

Total Dissolved Solids

TDS

Mg/lit (ppm)

pH value

pH

Number

Typical well fluid components Multiphase – Liquid Hydrocarbons

Corrosion due to Oxygen: Oxygen is strong oxidant and reacts with the metal very

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quickly. The dissolved Oxygen in the formation / produced water is one of the primary causes of corrosion in the production equipment. Although Oxygen is not present in the well fluids, Oxygen ingress takes place in the well fluids through leaking pump seals, casing and process vents, open hatches. The forms of corrosion associated with Oxygen is mainly uniform corrosion, pitting type corrosion as shown in Fig 4

Chlorides – Stress Corrosion cracking: The presence of Chlorides in the well fluids attack the material through the de-ivation effect induced by Chloride ions and is quite aggressive on 300 series of Austenitic Stainless steels. High Nickel alloys are practically immune to this attack and resist chloride corrosion. The chloride stress corrosion is influenced greatly by the temperature, chloride concentration and residual stresses in the metal. The presence of oxygen and low pH value accelerates the attack on the metal. This chloride corrosion is normally is indicated as pitting type on the metal surface as shown in Fig 4

Hydrogen ebrittlement is also possible on the more noble metal if it is susceptible. The presence of H2S and low temperatures encourages the galvanic type of corrosion. (Fig 5).

Erosion Corrosion: Erosion corrosion is a form of corrosion with mechanical removal of metal due to high flow rates of the media and is common in all metallic materials. The rate of corrosion increases with sand or solid suspended particles in the fluid and is dependent on fluid flow rate, the density and morphology of solids present in the fluid.

Crevice corrosion: Crevice corrosion is normally localized corrosion taking place in the narrow clearances or cervices in the metal and the fluid getting stagnant in the gap. This is normally in the form of pitting formed on the surface of the metal and gradually extending into the metal itself.

Fig 3: Corrosion due to H2S (Sour Corrosion)

Elemental Sulfur Corrosion: Elemental Sulfur will be present in some reservoir fluids and is very strong oxidant. It mixes with the water in the fluid and forms Sulfuric acid and reacts with Carbon and low alloy steels to form Sulfides. Corrosion due to elemental sulfur increases with temperature. Low alloy materials like CRA are quite susceptible to elemental Sulfur attach however highly alloyed Nickel CRA’s like Inconel / Incoloy are resistant to Sulfur attack. The Sulfur attack is by and large is localized and similar to pitting type of corrosion. Fig 2: Corrosion due to CO2 (Sweet Corrosion)

Uniform Corrosion

Pitting due to H2S

H2S corrosion

Microbial Induced Corrosion (MIC-Sulfate reducing Bacteria): This form of corrosion is induced due to the presence of sulfate reducing bacterium which grows in anaerobic conditions. This bacterium is normally present in reservoir fluids, formations waters and soils. The microbes tend to form colonies in a hospitable environment and allow enhanced corrosion under colony. The formation of these colonies is promoted by neutral water especially when stagnant. The form of microbial induced corrosion is pitting and the products of corrosion involve iron sulfates, slime,

Mesa Corrosion

Fig 4: Corrosion due to Oxygen and Chlorides

Galvanic Corrosion: This type of corrosion occurs when two metallic materials with different nobility (electrochemical potential) are in and are exposed to an electrolytic environment. In such situation the metal with less or most negative potential becomes anode and starts corroding. The most prominent type of galvanic corrosion occurs in a coupling between CRAs (Stainless steel or Nickel alloys) with Carbon or low alloy steels in a deaerated surroundings.

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Oxygen Corrosion

Pitting due to Chlorides

Fig 5: Galvanic and MIC Corrosion

Galvanic corrosion

MIC corrosion

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plugging and also bacterial growth. (Fig 5)

Methods to combat corrosion in Oil & Gas industry Fighting corrosion to improve the equipment and plant life continues to be a nightmare for many of the plant operating staff. While many methods have been advised to arrest these events, these methods can be broadly classed into three (3) main categories: • Change the material of construction for the specific application • Reduce the intensity of corrosive attack by modifications in corrosive media • Create a barrier layer between the material and media to avoid the direct .

Change in Materials of Construction: When it is observed that the existing material of construction is prone for corrosive attack, it is normally decided to change the materials of construction and select

alternate material to suit the specific need. Generally the materials used in the hydrocarbon applications can be broadly grouped as metals, non metals. Each variety of these materials has its specific applications and limitations. At times the change of material may have additional cost. However it is worthwhile to think in of life cycle costing, which may show a longer equipment life and lower maintenance cost in spite of high initial cost. A detailed study of process and operating conditions has to be carried out before selection of a new material. The new generation of Stainless Steels - Duplex stainless steels / Super Duplex Stainless steels by and large resist almost all types of corrosion. The steel mills all over the world have been continuously developing new materials with different metallurgies to resist almost any type of corrosion in the oil and gas industry. While exotic materials like Titanium, Zirconium etc will operate in almost all corrosive and high temperature environments, the initial cost is prohibitive to select materials unless the equipment downtime is critical to the process

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and the facility. Non ferrous materials like Copper, Nickel and Copper Nickel alloys also have found good use in the sea water environments when normal materials like carbon steel and stainless steels generally perform badly and fail. Selecting suitable grades of Stainless Steels like low carbon variety and stabilized grades will avert intergranular corrosion or weld decays if welding operations are involved. Table 2 shows some of the commonly used materials in the hydrocarbon and oil and gas industries. The table is for guidance only. Detailed study of flow conditions, corrosion mechanisms involved and the expected life of material is important before selecting a specific metal for the application It is all the time more important to understand that no single material is cure for all the corrosion evils. A material which is good for stress corrosion cracking may fail due to fatigue. Another material which can resist high temperature corrosion may fail due to pitting

Change of Corrosive media or the environment: At times it is necessary to reduce the intensity of corrosive attack of the environment by adding certain chemicals known as ‘Inhibitors’ to reduce the aggressiveness of the media. These chemicals are injected into the media at point–to point in the process. The chemicals, the concentration and the frequency of injection depend upon the process media and normally recommendations of the inhibitor manufacturer since most of the cases these chemical though generic in nature are proprietary items. The inhibitors are normally chromates, phosphates and silicates added as per the recommendations of the manufacturer. Also removal of the Oxygen from the fluid media improves the chances of corrosion resistance of materials in . Controlling and stabilizing the pH value of the media is another method of combating corrosion. There are many varieties of corrosion inhibitors available in the market, but judicious approach and recommendations of the

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manufacturer have to be followed while injecting these chemical in the well fluid streams.

Intermediate barrier to avoid direct with media: A protective layer or barrier on the material to avoid the direct with the process media will enhance the material and equipment life. The barrier layer can be paint, a coating or a lining, or a metallic lining or metallic sheets. There are also non metallic linings like fiber glass, glass flake, epoxy, rubber etc which are normally carried out on the equipment like separators, KO drums, storage tanks etc. Nickel, Zinc and Cium coatings are also preferred at times on certain components like flanges, bolting etc. Again it should be clearly understood that above arrangement is not permanent cure and only will extend the life of the bare materials underneath the barrier to some extent. The paints over prolonged exposure to atmosphere heat and sunlight may flake off. The tape or lining on a pipeline may get physically damaged, crack and delaminate exposing the bare material beneath to corrosive media. However this method of combating corrosion is cheap and less expensive than opting for a costly material of construction.

Corrosion Monitoring and Management The best way to check corrosion is by visual inspection and checking up the material degradation periodically. However it may be possible to check the material condition externally and it is impractical if not impossible to check the internal surfaces now and then. One of the methods is to carry out the on-streamInspection by doing the wall thickness measurements periodically on fixed and vulnerable locations on the equipment, piping and pipelines to assess the material conditions and corrosion rates. However this method has its own limitations since this check point under investigation may show lower corrosion which may not be true at some other point that might have corroded heavily and gone undetected. Also corrosion is monitored by placing electronic probes in the pipelines and by measuring the change in the electric resistance in the probe coil. However this method is indicative more of the process fluid than the wetted materials condition. The cross country pipelines are normally checked with intelligent pigging operations like magnetic flux or ultrasonic pigs. These pigs will detect the internal conditions of the pipeline, corrosion conditions on the pipe wall thickness and also indicate the wall thickness available on the pipe wall. Most of the equipment like separators, drums, heaters etc are checked for corrosion during annual shutdown and turnaround operations. Based on the physical assessment of the material conditions corrective action is initiated to change the material or replace the equipment or at times do temporary repair work before replacement is carried out. In practice it is observed that physical inspection is the best method of monitoring corrosion and assessing the material conditions.

Conclusion Undoubtedly understanding the corrosion mechanism is very important before considering various material options for the applications. However it should be clearly understood that no particular material is the cure for all the evils of corrosion. Each and every case has to be considered in it’s totality before a decision is made on the proper materials. Consultations with process, operations, materials and corrosion engineers are necessary in the fitness of things to save millions to fight the corrosion menace. PP

PetroMin PipeLiner would like to show appreciation to Mr. Nalli. K from Mott MacDonald Co LLC, Oman for this independent article.

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