34 Oilfield Review

Corrosion—The Longest War

Locations that host oil and gas operations often provide ideal conditions for corrosion.

Ongoing research and advances in coatings, cathodic protection, nondestructive

testing, corrosion analysis and inhibitors allow operators to safely produce oil and

gas in these corrosive environments.

Nausha AsrarBruce MacKaySugar Land, Texas, USA

Øystein BirketveitMarko StipanicevBergen, Norway

Joshua E. JacksonG2MT Laboratories, LLCHouston, Texas

Alyn JenkinsAberdeen, Scotland

Denis MélotTotalParis, France

Jan ScheieStavanger, Norway

Jean VittonatoTotalPau, France

Oilfield Review 28, no. 2 (May 2016).Copyright © 2016 Schlumberger.DS-1617 is mark of M-I LLC.Hastelloy is a registered trademark of Haynes International, Inc.Inconel and Monel are trademarks of Special Metals Corporation.

Corrosion validates the universal law of entropy; everything trends toward a state of greater chaos and disorder. The flecks of rust on an iron bar or the green patina on a copper fixture are evidence of the insidious effects of corrosion. These examples may be regarded as an annoyance, but taken to the extreme, the results of corrosion can lead to cata-strophic outcomes.

Corrosion has brought down bridges, downed aircraft, leveled chemical plants, parted drill-pipe and ruptured pipelines. Given sufficient time, this adversary has the potential to degrade any material. In certain environments, the unchecked effects of corrosion can come swiftly, and the consequences of failure to manage corro-sion can be costly.

Oilfield Review MAY 16Corrosion Fig OpenerORMAY 16 CRSSN Opener

May 2016 3535

According to the US Federal Highway Admin-istration, the approximate annual direct cost of corrosion for the US in 2015 was an estimated US$ 500 billion, representing around 3.1% of the nation’s gross domestic product.1 This figure amounts to six times the average annual cost of weather-related disasters for the US, which was about US$ 87 billion in 2011.2 Unlike weather events, corrosion can be controlled or at least managed; scientists estimate that 25% to 30% of corrosion costs could be avoided if good corrosion management practices and preventive strategies were employed.3

Throughout the ages, and despite an early lack of understanding concerning the fundamen-tal mechanisms involved, humans have attempted to control corrosion. In ancient times, corrosion resistance was sometimes imparted to materials as a matter of circumstance rather than design (Figure 1).4 Early corrosion control methods included the use of bitumen and lead-based paints by the Romans in the first century. Around 500 BCE, Chinese sword makers used copper sulfide coatings to inhibit corrosion on bronze swords. Centuries later, the copper sheathing used on British sailing vessels to reduce biofoul-ing—fouling of underwater surfaces by organisms such as barnacles and algae—and increase speed accelerated the corrosion of nails that held the ships together.5

Michael Faraday was one of the most impor-tant contributors to the early understanding of corrosion; in the early 1800s, he established a quantitative relationship between the chemi-cal action of corrosion and electric current.6 Although much more is known about the subject today, scientists continue to study the mecha-

nisms of corrosion and search for methods to manage and control it.

Combating corrosion is a significant source of expenditures for the oil and gas industry (Figure 2). British Petroleum (BP) conducted a study of its operations in the North Sea in 1995.7 The company found that outlays for corrosion

1. Koch GH, Brongers MPH, Thompson NG, Virmani YP and Payer JH: “Corrosion Costs and Preventive Strategies in the United States,” Washington, DC: US Department of Transportation Federal Highway Administration, Publication FHWA-RD-01-156, March 2002.

Jackson JE: “Corrosion Will Cost the US Economy over $1 Trillion in 2015,” G2MT Laboratories, http:// www.g2mtlabs.com/corrosion/cost-of-corrosion/ (accessed January 6, 2016).

Papavinasam S: Corrosion Control in the Oil and Gas Industry. Waltham, Massachusetts, USA: Gulf Professional Publishing, 2014.

2. The US$ 87 billion cost of weather-related disasters in 2011 was the highest on record. The average annual cost has been closer to US$ 10 billion in recent years. For more on the cost of weather-related disasters: Smith AB and Katz RW: “U.S. Billion-Dollar Weather and Climate Disasters: Data Sources, Trends, Accuracy and Biases,” Natural Hazards 67, no. 2 (June 2013): 387–410.

3. Chillingar GV, Mourhatch R and Al-Qahtani GD: The Fundamentals of Corrosion and Scaling for Petroleum and Environmental Engineers. Houston: Gulf Publishing Company, 2008.

4. Kumar AVR and Balasubramaniam R: “Corrosion Product Analysis of Corrosion Resistant Ancient Indian Iron,” Corrosion Science 40, no. 7 (July 1, 1998): 1169–1178.

Balasubramaniam R: Story of the Delhi Iron Pillar. Delhi, India: Foundation Books Pvt. Ltd, Cambridge House, 2005.

5. Groysman A: Corrosion for Everybody. Dordrecht, The Netherlands: Springer Science+Business Media, 2010.

6. Ahmad Z: Principles of Corrosion Engineering and Control, 1st ed. Burlington, Massachusetts: Butterworth-Heinemann, 2006.

7. Kermani MB and Harrop D: “The Impact of Corrosion on the Oil and Gas Industry,” SPE Production & Facilities 11, no. 3 (August 1996).

Figure 1. Delhi pillar. This iron pillar is located in the Qutub Complex in New Delhi, Delhi, India (inset). It is about 9.1 m [30 ft] tall and weighs approximately 6,000 kg [13,200 lbm]. Erected in 400 CE, the pillar is essentially free of the typical rusting that would be expected to take place over 1,600 years of exposure. Reasons for the lack of corrosion include New Delhi’s low humidity but are primarily attributed to the high concentration of phosphorus in the iron.

Oilfield Review MAY 16Corrosion Fig 1ORMAY 16 CRSSN 1

I N D I A

P A K I S

T A N

NEPAL

C H I N A

BANGLADESH

SRI LANKA

Mumbai

New Delhi

km

miles0

0 500

500

Oilfield Review MAY 16Corrosion Fig 2ORMAY 16 CRSSN 2

Production1.4

Pipelines7.0Tankers

2.7

Storage7.0

Refining3.7

Distribution5.0

US Oil and Gas Corrosion Expenditures, US$ billion/year

Figure 2. Corrosion expenditures. Corrosion expenditures in the US oil and gas industry are about US$ 26.8 billion/year. The downstream segment of the industry—production, pipelines and tankers—accounts for 41% of the total, or US$ 11 billion/year. (Adapted from Koch et al, reference 1.)

36 Oilfield Review

prevention and control averaged about 8% of the total capital expenditure for its projects. On the UK Continental Shelf, 25% to 30% of BP’s operating costs were related to the control and management of corrosion. Costs associated with replacing corroded equipment, lost production and corrosion-related contamination contributed to overall expenditures. In addition to the direct costs, the company found that corrosion had a significant indirect cost on health, safety and environmental concerns.

This article focuses on descriptions of cor-rosion, management techniques and advances in corrosion abatement technologies. Field examples from Gabon, deepwater Nigeria and the North Sea illustrate the ongoing battle waged against corrosion by oil and gas operators.

The Corrosion ProcessScientists and engineers today have a better understanding of corrosion processes than did the ancient Romans and Chinese. Fighting cor-rosion requires an understanding of the principal elements that cause and contribute to the corro-sion. There are several categories of corrosion; for the oil and gas industry, common types include exposure to carbon dioxide [CO2, sweet corro-sion], hydrogen sulfide [H2S, sour corrosion], oxygen [O2] and corrosion causing microbes, referred to as microbiologically influenced cor-rosion (MIC).8

Some forms of metal corrosion are related to stability; for example, galvanic corrosion is an electrochemical process associated with the movement of electrons between areas that have different electrochemical potentials. The corro-sion cell schematically describes oxidizing corro-sion, which is analogous to a battery in which two dissimilar metals are connected by an electrolyte (Figure 3).9 A metal that has a higher corrosion rate—more unstable—represents the negative part of the cell and acts as the anode; a second metal that has a lower corrosion rate—more stable—acts as the positive part of the cell, the cathode.10

During the galvanic corrosion process, metal oxides are formed as electrons flow from the anode to the cathode through the electrolyte—the fluid in contact with the anode and cathode. A simplified version of iron oxidation can be used to illustrate the galvanic corrosion process—the actual process is more complex. The presence of water [H2O] on the surface of the iron [Fe or Fe0] releases electrons to form ferrous iron [Fe+2] and ferric iron [Fe+3] ions, which act as the anode in our battery analogy. The liberated electrons flow to the cathode, where, in the presence of oxygen [O2], ferrous oxide [FeO] and ferric oxide [Fe2O3] form as scales of rust or precipitates. A byproduct of the reaction at the cathode is hydroxyl ions [OH–] from the reduction of oxygenated water.

Iron can also react with CO2 to form iron carbon-ate [FeCO3] and with H2S to form iron sulfides [FexSx]. In the absence of O2 but the presence of CO2 and H2S, the cathodic reaction can generate hydrogen gas.

These reactions can occur rapidly, but if the reaction rate can be reduced, the overall corro-sion rate will also be reduced. Many factors influ-ence the reaction rate. These include the type and quality of metal, electrolyte compositions, pH, temperature, pressure, presence of dissolved gases, liquid velocity, water salinity, applica-tion of cathodic protection and the presence of microbes.11 To manage corrosion and corrosion rate, knowledge of the metallurgy of the mate-rials to be used and the environments in which they will operate is important.

If CO2 comes into contact with water in the producing or transportation system of an oil and gas operation, areas typically affected include well internals, gathering lines and pipelines. In CO2 corrosion of iron, the products of reaction are carbonic acid, iron carbonate [FeCO3] and hydrogen gas [H2].12 For CO2 corrosion to occur, the partial pressure of the gas can be as low as 21 kPa [3 psi]. To prevent this type of corrosion, operators commonly use organic films that act as barriers and inhibitors that neutralize the acidity of the carbonic acid generated in the corrosion process. Operators may also use corrosion resis-tant alloys (CRAs), which are resistant to general and localized corrosion, in environments that are corrosive to carbon and low-alloy steels.

Hydrogen sulfide is often found in produced fluids or as a result of MIC.13 Although H2S is not corrosive, it becomes corrosive in the presence of water.14 Sour corrosion from H2S can affect any part of the producing system, including well internals and oil and gas gathering lines. Oilfield fluids are considered sour if the produced gas con-tains more than 5.7 mg of H2S per m3 [4 parts per million (ppm)] of natural gas or produced water has greater than 5 ppm H2S.15 At the anode, the H2S reacts with the iron to form several vari-ants of iron sulfide [FexS] such as mackinawite [(Fe,Ni)(1 + x)S], pyrrhotite [Fe(1 - x)S] and troilite [FeS].16 These iron sulfide species precipitate and can form localized microgalvanic corrosion cells.

The corrosion cells formed during sour corro-sion cause pitting, sulfide stress cracking (SSC) and hydrogen embrittlement.17 Stress corrosion cracking is a result of tensile stress combined with a wet environment and often causes shal-low, round pits that have etched bottoms accom-panied by branching cracks that can lead to rapid failure. Hydrogen embrittlement occurs when H2S and H2 diffuse into metal, recombine with

Figure 3. Corrosion cell. When steel in water rusts, several reactions take place simultaneously. At the anode, steel [Fe0] goes readily into solution to form ferrous iron [Fe2+] and ferric iron [Fe3+] (not shown) ions, and electrons move to the cathode. Electrons at the cathode react with water [H2O] to form oxygen [O2] and hydroxyl [OH–] ions. The OH– ions combine with the solubilized Fe2+ to form iron hydroxide [Fe(OH)2].

Oilfield Review MAY 16Corrosion Fig 3ORMAY 16 CRSSN 3

Fe0Fe0

Fe0Fe0

Anode

Water

Electron flow

Steel

Cathode

Fe2+ Fe(OH)2Fe(OH)2

OH–

OH–

OH–

Anodic reaction Fe0 Fe2+ + 2e–

Cathodic reaction H2O + 2e– 0.5 O2 + 2OH–

Fe2+ + 2OH– Fe(OH)2

May 2016 37

other molecules and create pressure within the metal matrix; byproducts of cathodic protection, galvanic corrosion and other mechanisms may lead to hydrogen embrittlement.

The failure mode during hydrogen embrittle-ment depends on the steel type; for example, low-strength steels exhibit blistering. The failure mode of high-strength steels can be catastrophic when the pressure of the trapped gas exceeds the tensile strength of the metal. To control sour cor-rosion, operators use organic film formers, H2S scavengers, metals resistant to SSC, flowline pig-ging, nitrate treatments and biocides that reduce the growth of microbes that cause MIC.18

Oxygen-related corrosion in oil and gas producing environments is often much more aggressive than corrosion caused by CO2 or H2S (Figure 4).19 Corrosion by oxygen is directly pro-portional to the concentration of the dissolved gas. If chlorides, CO2 or H2S are present, the cor-rosion rate can increase significantly.

Oxygen has the ability to induce corrosion throughout producing systems. Inhibition of oxy-gen corrosion is difficult, and corrosion reduction efforts for production and water handling facili-ties have usually been directed toward exclusion of oxygen from the system and the use of oxy-gen scavengers. Typical oxygen scavengers are ammonium bisulfite [NH4HSO3], sodium sulfite [Na2SO3] and sodium bisulfite [NaHSO3].20 In addition to scavenger stripping, vacuum deaera-tors are sometimes used to control the corrosive effects of oxygen on metals.

Exposure to oxygen is also a major source of drillpipe corrosion. While it is being run in and out of the well, drillpipe is exposed to atmo-spheric oxygen. During drilling, drillpipe comes into contact with oxygen in the mud system. Both instances can induce corrosion. The usual expression of oxygen-related corrosion is pitting. Pitting can even develop under mud left on and inside drillpipe, where pipe storage racks contact the pipe and at crevices. Deep corrosion pits in drillpipe can lead to the onset of fatigue failure. Drillpipe may be coated with epoxies or resins to stop corrosion, but the harsh downhole envi-ronment often quickly removes these protective coatings. Pipe dope, lubricating grease applied to threaded connections, may help prevent cor-rosion of these connections.

Corrosion Form and Appearance The word corrode comes from the Latin corrodere meaning to gnaw; it can carry the additional meaning of eat or wear away gradually.21 Corrosion typically leaves a visible signature that is characteristic of the agent and mechanism

8. Popoola LT, Grema AS, Latinwo GK, Gutti B and Balogun AS: “Corrosion Problems During Oil and Gas Production and Its Mitigation,” International Journal of Industrial Chemistry 4, no. 1 (2013).

Chillingar et al, reference 3. 9. Stansbury EE and Buchanan RA: Fundamentals of

Electrochemical Corrosion. Materials Park, Ohio, USA: ASM International, 2000.

Brondel D, Edwards R, Hayman A, Hill D, Mehta S and Semerad T: “Corrosion in the Oil Industry,” Oilfield Review 6, no. 2 (April 1994): 4–18.

10. Although the battery analogy is acceptable for explaining corrosion involving two dissimilar metals, corrosion processes also take place on single metals. In single metals, the mechanism for corrosion consists of small crystals with slightly different compositions. The anode and the cathode are located on different areas of the metal surface and, depending on the conditions, may be close to each other or far apart.

11. Heidersbach R: Metallurgy and Corrosion Control in Oil and Gas Production. Hoboken, New Jersey, USA: John Wiley & Sons, Inc., 2011.

12. At elevated temperatures, magnetite [Fe3O4] may also form.

13. In MIC, the H2S is produced as a byproduct of the activities of sulfate reducing bacteria (SRB).

14. Chillingar et al, reference 3.

Figure 4. Corrosion rates. The relative rates of corrosion in milli-inches/year (mpy) of carbon steel show pronounced differences when the steel is exposed to varying concentrations of O2, CO2 and H2S. At a concentration of 5 ppm, O2 is almost three times more corrosive than is H2S and 30% more corrosive than is CO2. Photographs near each curve show the effects of these corrosion agents on metal surfaces.

Oilfield Review MAY 16Corrosion Fig 4ORMAY 16 CRSSN 4

Corro

sion

rate

of c

arbo

n st

eel,

mpy

30

20

10

0

Oxygen1 2 3 4 5 6 7 8 9

O2

CO2

H2S5

15

25

Hydrogen sulfideGas concentration in water phase, parts per million

100 200 300 400 500 600 700 800 900

Carbon dioxide50 100 150 200 250 300 350 400 450

15. Stewart M and Arnold K: Gas Sweetening and Processing Field Manual. Waltham, Massachusetts. Gulf Professional Publishing, 2011.

16. Ning J, Zheng Y, Young D, Brown B and Nesic S: “A Thermodynamic Study of Hydrogen Sulfide Corrosion of Mild Steel,” paper NACE 2462, presented at the NACE Corrosion 2013 Conference and Exhibition, Orlando, Florida, USA, March 17–21, 2013.

17. Kvarekval J: “Morphology of Localized Corrosion Attacks in Sour Environments,” paper NACE 07659, presented at the NACE Corrosion 2007 Conference and Exposition, Nashville, Tennessee, USA, March 11–15, 2007.

18. Pipeline operators send mechanical devices called pigs through pipelines to clean the inner surface. This can be done without halting flow, and the flow stream pushes the pig through the piping.

19. Popoola et al, reference 8. Chillingar et al, reference 3.20. Chillingar et al, reference 3. Care must be taken when using NH4HSO3 as an oxygen

scavenger. This compound is corrosive in itself and can also act as a food source for bacteria, thereby potentially encouraging MIC.

21. Davis JR: Corrosion—Understanding the Basics. Materials Park, Ohio: ASM International, 2000.

38 Oilfield Review

that caused it. Although not an exclusive list, cor-rosion usually falls into one or more of the fol-lowing categories: general or uniform, localized, galvanic, erosion or flow induced, crevice, pitting, under deposit, cavitation, intergranular, stress cracking and corrosion fatigue (Figure 5). Other types of corrosion include environmental, top-of-line and microbial. Based on the observed char-acteristics of the corrosion, engineers can adopt appropriate preventive and mitigation measures.

Uniform corrosion is typical of low-alloy steels and may be observed over an entire exposed area. Initial evidence of uniform corro-sion is surface roughness. The metal becomes thinner as the corrosion progresses, and it will eventually fail from internal pressure or external forces. Because this type of corrosion is linked to surface exposure, it may be prevented by prop-erly protecting the surface. Uniform corrosion may occur in equipment used for oilfield opera-tions such as hydraulic stimulation and acidizing.

Localized corrosion occurs at specific sites rather than over a generalized area and may be more dangerous than some other types of cor-rosion because of its unpredictable nature and

the potential for rapid growth. Localized corro-sion, of which even CRAs such as stainless steels are susceptible, can be subdivided into pitting, crevice and under deposit corrosion. Pitting ulti-mately can cause holes in metal components and is one of the primary causes of failure in oilfield hardware, including tubing, casing, sucker rods and surface equipment.

Crevice corrosion occurs in constricted areas, wherein the metal at the crevice becomes anodic and the rest of the metal serves as the cathode. The crevice can form where two dissimilar metals come into contact or be created by microgalvanic cells that may occur in certain steel alloys.

Pitting corrosion rates are often much higher than those of other types of corrosion. Inhibitors may be applied to the surface to prevent initia-tion, but once a pit has formed the inhibitors are often unable to slow its growth.

Under deposit corrosion occurs when sand, corrosives or porous solids adhere to the metal surface. Although the area underneath the deposit is resistant to inhibitors and can corrode quickly, this type of corrosion can often be man-

aged by cleaning internal piping surfaces, for example, with the use of pipeline pigs.

Galvanic corrosion can be a problem when two dissimilar metals are in contact. The metal that has the least resistance to corrosion acts as the anode and the more resistant metal serves as the cathode. The anode typically corrodes pref-erentially. This form of corrosion is frequently observed in offshore platforms and pipelines. The galvanic series, which orders metals accord-ing to their anodic or cathodic tendencies, is a good predictor of corrosion severity (Figure 6). Galvanic corrosion is controlled and mitigated by use of the following:• good engineering design—to ensure that cor-

rosively active components present larger sur-face area than do less active components

• material selection—to avoid metals far apart in the galvanic series

• isolation—to provide pipelines coming from the sea with sacrificial anodes and protect those going into land with impressed current systems

• inhibitors and coatings—to control initiation of corrosion, although this method may be inef-fective once corrosion forms.

Figure 5. Generalized categories of corrosion. Corrosion can be categorized by appearance and the agent of causation. These eight corrosion types cover most of the observed corrosion mechanisms for metals.

Oilfield Review MAY 16Corrosion Fig 5ORMAY 16 CRSSN 5

Steel

General or Uniform

Pitting IntergranularStress

Corrosion Cracking Corrosion Fatigue

Galvanic Erosion or Flow Induced Crevice

Anode

Water

Water

Flow

Cathode

ForceSteel

May 2016 39

Flow-induced corrosion occurs when liquid flow accelerates corrosion. Wellheads and pumps are susceptible to this form of corrosion, which may occur as erosion or cavitation. Erosion cor-rosion results when fluid flow removes the pro-tective film that forms naturally or has been applied externally. Because of their abrasive properties, suspended solids will accelerate the process. Damage can be seen as grooves in the piping that correspond to the flow direction. Proper engineering design that allows for suf-ficient pipe diameter and removing solids from flow streams can minimize this type of corrosion. Inhibitors may be applied to replace protective films stripped away by the flowing fluids.

Cavitation is caused by collapsing bubbles that occur when the pressure changes rapidly in flowing liquids. Over time, cavitation may cause deep pits to form in areas of turbulent flow, espe-cially in pump impellers. Low-carbon steels are susceptible; stainless steels are more resilient.22

Intergranular corrosion results from cor-rosive attacks at metal grain boundaries in the form of cracks. The grain boundaries can become anodic with reference to the cathodic surround-ing surface, typically due to formation of chro-mium carbides or nitrides. Metal impurities can increase the effect, as can precipitates in the metal that form during heat treatments. When chromium combines with nitrogen or carbon, less free chrome is available locally for corro-sion protection, and cracks can form along the grain boundaries. Quenching—the rapid cool-ing after heat treatments—may be effective in reducing or eliminating intergranular corrosion. Material selection—avoiding metals that are susceptible to this condition—is the most reli-able method to preclude intergranular corrosion. Tests such as ASTM A262 can be used to evaluate susceptibility of materials to this mechanism.23

Environmental cracking occurs when cor-rosion coincides with tensile stress. It may be manifested as the following:

• hydrogen embrittlement—hydrogen enters the metal matrix and weakens it

• stress corrosion cracking—cracks form after corrosion has attacked a surface

• sulfide stress cracking—a failure of the metal caused by H2S.

Material selection—opting for materials that are resistant to hydrogen embrittlement and sulfide cracking—is the primary avoidance technique. Low-stress design practices and stress relief by heat treatment are also commonly used, and pre-venting corrosion in components subject to stress is another method.

Pipelines are subject to top-of-line corrosion (Figure 7). Water condenses at the top of the pipe as the fluid inside cools. The corrosion rate depends on the condensation rate and concen-tration of organic acids. Generally, this type of corrosion is controlled with inhibitors and pipe-line insulation that reduces condensation.

22. Port RD: “Flow Accelerated Corrosion,” paper NACE 721, presented at the NACE Corrosion 98 Annual Conference, San Diego, California, USA, March 22–27, 1998.

23. ASTM International: “Standard Practices for Detecting Susceptibility to Intergranular Attack in Austenitic Stainless Steels,” West Conshohocken, Pennsylvania, USA: ASTM International A262-15, 2015.

Oilfield Review MAY 16Corrosion Fig 6ORMAY 16 CRSSN 6

Magnesium

Anodic

Zinc

Cadmium

Aluminum

Steel

Chromium steel

Stainless steel

Lead

Tin

Nickel

Inconel

Hastelloy

Brasses

Copper

Bronzes

Monel

Chromium steel

Silver

Titanium

Graphite

Gold

Platinum

Cathodic

Figure 6. Galvanic series. Metals (not all shown) can be described by their anodic or cathodic tendencies arranged in a galvanic series. When dissimilar metals are connected electrically and submerged in an electrolyte, the anodic metal, rather than the cathodic metal, will preferentially corrode. The rate of corrosion is a function of the separation between the paired metals in the galvanic series. The series shown here is for seawater; the order may change based on the electrolyte.

Figure 7. Top-of-line pipeline corrosion. Top-of-line corrosion can result from the stratified multiphase flow of wet gas in horizontal pipelines. Liquids—including condensate and inhibitors such as monoethylene glycol—settle to the bottom of the pipe. Wet gas fills the pipe above the liquid line. If either CO2 or H2S are present in the gas, along with water, corrosive byproducts form at the top of the pipe and may not be controlled if the inhibitor remains at the bottom of the pipe.

Condensate

Wet gas

Pipe

Monoethylene glycol

Oilfield Review MAY 16Corrosion Fig 7ORMAY 16 CRSSN 7

40 Oilfield Review

Microbiologically Influenced CorrosionFrom the moment of immersion in a nonster-ile fluid that supports microbial development, microorganisms begin to attach to the material surface (Figure 8). Planktonic microorganisms become fixed at the fluid boundary, typically a pipe wall, or onto porous media such as preexist-ing corrosion.24

Attachment of microorganisms leads to the formation of biofilms—microbial communities

embedded in or on an attaching surface.25 Wher-ever biofilms are found in producing systems, MIC can occur, including inside production tub-ing, gravity and hydrocyclone separators, storage tanks, pipelines and water injection systems. Depending on the microbial species, the corro-sion mechanisms can take various forms.

Biofilms can trap ions and create localized electrochemical potentials analogous to a gal-vanic corrosion cell or may contribute to corro-

sion by taking a role in the formation of cathodic and conductive corrosion products on the metal surface (Figure 9). Sulfate producing prokaryotes (SPPs) are the chief offenders. Prokaryotes are microbes that have no cell nucleus or membrane-bound organelles. The most prominent group of SPPs are sulfate reducing bacteria (SRB) and sulfate reducing archaea (SRA). They contribute to corrosion by various means, for example, by taking a role in the formation of cathodic ferrous sulfide corrosion products and the formation of galvanic cells. The production of H2S by SPPs can also lead to sour corrosion.

Biofilms may develop local concentration cells that are created by oxygen depletion or may attach to a metal surface. Microbes can contrib-ute to corrosion by the direct effects of meta-bolic waste products such as organic acids that are capable of altering the local pH and forming pH cells. Some microbes are anaerobic and can tolerate extremes of pressure, temperature, pH and fluid salinity. These include methanogens—microbes that produce methane as a metabolic byproduct in anoxic conditions.

Regardless of the source of MIC, prevention measures in most cases attack planktonic and sessile populations.26 Methods include biocides to kill the microorganisms, coatings to inhibit biofilm formation, removal of nutrients from the flow stream to control microbial populations and mechanical removal of an established biomass via pigging.

Corrosion Control MethodsMetallurgical solutions can be effective deter-rents of corrosion, but their costs may be beyond the economic limit of many oilfield projects. Building every structure and tubular from irid-ium—the most corrosion resistant element—might win the battle against corrosion, but incur unsustainable expenses, and that would be assuming a sufficient supply of iridium exists in the world to attempt such a task. Aluminum is a corrosion-resistant metal used in many oilfield applications; however, it is unsuitable for high-pressure and high-temperature operations. In addition, although aluminum is considered cor-rosion resistant in seawater, the mechanism for resistance relies on the formation of a thin film of aluminum oxide on the surface of the metal. In environments that have high levels of acidity (low pH) or alkalinity (high pH), the aluminum oxide can become unstable and thus nonprotective. In many cases, steel alloys and CRAs are required to meet both strength and cost requirements.

Figure 8. Microbiologically influenced corrosion products. Softscale corrosion, referred to as schmoo (right ), can form in production systems if microbes are not controlled. The photograph shows a mixture of iron sulfide [FeS], asphaltenes and biomass that was collected at the sidestream outlet of a separator tank (top left ). Corrosion inhibitors form protective films around iron sulfide particles (bottom left ) inside the separator and prevent softscale formation in produced waters.

Water

Oil outletWater outlet

Sidestream Emulsion

Separator Tank

Oil layer

Iron sulfideparticle

Corrosioninhibitor film

Oilfield Review MAY 16Corrosion Fig 9ORMAY 16 CRSSN 9

Figure 9. Microbiologically influenced corrosion from byproducts. Biofilm on the surface of this metal piece produced H2S that damaged the piece and led to premature failure of the equipment.

Oilfield Review MAY 16Corrosion Fig 8ORMAY 16 CRSSN 8

May 2016 41

24. Stipanicev M: “Improved Decision Support Within Biocorrosion Management for Oil and Gas Water Injection Systems,” PhD thesis, Institut National Polytechnique de Toulouse, France (2013).

25. Madigan MT, Martinko JM, Bender KS, Buckley DH, Stahl DA and Brock T: Brock Biology of Microorganisms, 14th ed. San Francisco: Benjamin Cummings, 2014.

26. Sessile refers to fixed or immobile organisms.27. Lehmann JA: “Cathodic Protection of Offshore

Structures,” paper OTC 1041, presented at the First Annual Offshore Technology Conference, Houston, May 18–21, 1969.

28. Davy H: “On the Corrosion of Copper Sheeting by Sea Water, and on Methods of Preventing This Effect; And on Their Application to Ships of War and Other Ships,” Philosophical Transactions of the Royal Society of London 114 (January 1, 1824): 151–158.

29. von Baeckmann W: “The History of Corrosion Protection,” in von Baeckmann W, Schwenk W and Prinz W (eds): Handbook of Cathodic Corrosion Protection—Theory and Practice of Electrochemical Protection Processes, 3rd ed. Houston: Gulf Professional Publishing (1997): 1–26.

30. Amani M and Hjeij D: “A Comprehensive Review of Corrosion and Its Inhibition in the Oil and Gas Industry,” paper SPE 175337, presented at the SPE Kuwait Oil and Gas Show and Conference, Mishref, Kuwait, October 11–14, 2015.

Although materials selection is a major part of the corrosion control process, once the equip-ment is deployed, oilfield operations generally follow three methodologies to battle corrosion. Operators and service companies rely on surface coatings to protect susceptible metals, cathodic protection for active protection and inhibitors as a low-cost treatment option.

Surface coatings provide chemical and mechanical resistance. They may also offer ther-mal protection. For surface coatings to provide maximum effectiveness, good adhesion to the target surface is required. Coatings are available in organic and inorganic types. Organic coatings include epoxies, phenolic resins, polyurethanes, polyethylenes and polyesters. Metals applied as suspensions and electroplating are examples of inorganic coatings; inorganic ceramics may also be applied to protect surfaces. Although not normally an advanced-technology solution, the cement placed in the annulus between the wellbore casing and the formation can act as an inorganic coating that prevents corrosion.

Cathodic protection (CP) consists of two pri-mary forms: passive and active (Figure 10). In either form, it relies on a movement of electrons (current) from an external anode to the equip-ment being protected, which acts as a cathode. Both the cathode and anode must be in the same electrolyte and electrically connected. The most common uses of CP are protecting large struc-tures, piping, casing and equipment exposed to the elements. It may also be installed inside or outside tanks and pressure vessels.

Operators often use sacrificial anodes with CP to protect structures in areas where electrical power sources are not readily available such as in remote operations or on offshore structures. If the structure can be made to serve as the cathode in relation to an anode, the disposable sacrificial anode will corrode while the cathode remains unscathed. This type of CP has been referred to as fighting corrosion with corrosion.27

The first use of CP is attributed to Sir Humphry Davy, who described the process in a series of articles to the Royal Society of London in 1824.28 The technique was used in an attempt to prevent the corrosion of nails used in wooden oceangoing vessels. Accelerated corrosion of the nails occurred when copper cladding—used to prevent biofouling—was applied to the outside of vessels. Davy found that sacrificial anodes protected the iron nails. The actual processes were not well understood at that time, but it is recognized today that the contact of dissimilar metals—the copper cladding and the iron of the

nails—led to the corrosion. Davy and his assis-tant carried out a number of experiments on cor-rosion prevention techniques; that assistant was Michael Faraday, who would later establish the relationship between the chemical action of cor-rosion and electric current.

In the oil field, CP was first applied to land-based pipelines, and the first documented use was by Robert J. Kuhn in 1928.29 He established a negative 850 mV potential between the steel pipe of a pipeline and a copper-sulfate electrode. This example became the foundation of modern CP technology, although for many years the effec-tiveness was met with scientific skepticism.

Today, CP uses sacrificial elements made from aluminum, zinc and magnesium to protect the steel of large structures and piping. These dissimilar metals create the galvanic coupling that establishes a current path between the anode and the cathode, and, over time, the sacrificial anode rather than the protected structure experiences metal loss. Appropriate placement and distribution of the anodes is cru-cial to ensure that all parts of the structure are sufficiently protected.30

Because the direct current (DC) is exter-nally applied, this type of corrosion manage-ment is referred to as impressed cathodic protection. It is most frequently used for cases in which the electrolyte resistance is high, such as in soil or freshwater, and where a constant

Figure 10. Cathodic protection circuit. Cathodic protection methods may use naturally occurring galvanic current or employ a direct current (DC) source (impressed current) when the electrolyte is resistive. The protected element—a pipeline is shown—is the cathode. The sacrificial element, located some distance from the cathode, serves as the anode. The DC source may be batteries or solar panels in remote pipeline applications.

Cathode

Anode

Backfill

Galvanic DC current

Electrolyte

Oilfield Review MAY 16Corrosion Fig 10ORMAY 16 CRSSN 10

milliamp

42 Oilfield Review

source of current is readily available. The use of solar panels in remote locations has greatly increased the potential applications of impressed cathodic protection.

In the impressed CP technique, current of several amps from a low-voltage rectifier passes, or is impressed, from an inert anode (for exam-ple, graphite or iron) to the structure being pro-tected, which acts as the cathode. The anode is attached to the positive terminal of the DC source, and the cathode is attached to the nega-tive terminal. The anode and cathode are often some distance from each other, separated by an electrolyte.

To counteract corrosion, sufficient current density must be supplied to all parts of the pro-tected structure and the current density must always exceed what would be the measured cor-rosion rate under the same conditions. If the corrosion rate increases, the impressed current density must be increased.31 Although the initial equipment cost may be higher for impressed CP than it is for sacrificial protection, this technique may be less expensive over the long term because sacrificial anodes do not need to be replaced. Impressed CP also has the advantage of provid-ing information to the operator about the extent of corrosion over time.

Corrosion InhibitorsAnother line of defense against corrosion is inhibitors, of which there are a variety of types and applications. The primary goal of inhibitors

is to interrupt the electrochemical process by which the corrosion cell forms between the metal and the liquids in and around the equipment. Inhibitors can be a flexible and cost-effective method of fighting corrosion, and the inhibi-tor application can be altered when conditions change. Although acquiring and delivering the inhibitor incur an ongoing cost, the lower costs associated with using less corrosion resistant low-carbon steels usually more than make up the difference.

Inhibitors fall into four main categories: scav-engers, reactive agents, vapor phase and film formers. Oxygen scavengers are frequently used in operations in which oxygen poses a corrosive threat. These agents not only reduce oxidizing corrosion, but also control the growth of microbes that require oxygen to thrive. Examples of oxygen scavengers used in the oil and gas industry are sodium sulfite, sulfur dioxide, sodium bisulfite, sodium metabisulfite and ammonium bisulfite. Ammonium bisulfite and sodium bisulfite are commonly used in seawater injection systems. To speed reaction rates, a catalyst may be included in the chemical.

Hydrogen sulfide scavengers reduce the level of H2S in the flow stream. Examples of H2S scavengers are amines, aldehydes and zinc car-boxylates. Common forms of amines are mono-ethanolamine (MEA) and monomethylamine (MMA) triazine. In some situations, operators may be able to regenerate MEA and MMA for reinjection and reuse.

Reactive inhibition operates at the cathode level for the corrosion cell. The cations of the inhibitor react with the cathodic anions to form insoluble films, which adhere to the surface of the metals and prevent O2 from coming into contact with the metal. These films also prevent the evolution of H2, a byproduct of the corrosion cell. Examples are forms of calcium carbonate, magnesium carbonate and iron oxides. Reactive inhibitors can also serve as poisons to the corro-sion cell process by interfering with the forma-tion of H2 and reducing the reaction rates at both the cathode and anode.

Vapor phase inhibitors are primarily used for combating CO2 corrosion. These inhibitors neu-tralize CO2 and block the formation of carbonic acid [H2CO3]. They are transported via vapor phase in wet gas lines. To protect against future corrosion, they may also be used during hydro-static testing of components with water, espe-cially when the components are to be stored after fitness testing. Examples of these types of inhibi-tors include morpholine and ethylenediamine.

Film FormersFilm formers are the most widely used corrosion inhibitors in the oil and gas industry. They cre-ate a continuous layer between the metal and the reactive fluids, thus reducing the attack of corro-sive elements (Figure 11). They may also attach to the surface of corroded metal, altering it and reducing the corrosion rate. Although they are effective in reducing CO2 and H2S corrosion, film formers are not effective against O2 corrosion.

Film formers are available in oil-soluble, water-soluble and oil soluble–water dispersible forms. Oil-soluble inhibitors are used to treat oil- and gas-producing wells. Water-soluble inhibi-tors are used in high water-cut flow streams, including those found in producing wells, trans-mission lines and separators. Oil soluble–water dispersible inhibitors are used in oil and gas wells that are also producing water.

Film-forming inhibitors take various chemical forms but are typically composed of long carbon chains with nitrogen, phosphate esters or anhy-drides. Inhibitors may adhere to or be adsorbed on the metal surface, which prevents the corro-sives from attacking the metal. The most effec-tive film-forming inhibitors create a molecular bond at the metal surface in a process of charge sharing or charge transfer. For effective inhibi-tion, the surface of the metal being protected must be fully covered; injection of the proper concentrations of the inhibitor are crucial. After they interact with the corrosive elements, some

Figure 11. Film formers. Although they vary in composition and avenue of protection, film formers create barriers between corrosive elements (water and oil, top) and metal surfaces. Inhibitors may be adsorbed on the surface (alkyl chains, middle) or form a strong bond by sharing charges with the metal (polar head group, bottom). When molecules of the polar head group of film formers attach to the surface of the metal, a portion of the molecule extends into the fluid. This usually oil-soluble tail is hydrophobic, repelling water away from the metal surface.

Oilfield Review MAY 16Corrosion Fig 11ORMAY 16 CRSSN 11

Water

Oil

Alkylchain

Polar headgroup

Metal surface

Water

Oil

CH3

CnH2n

N+

May 2016 43

inhibitors are gradually removed from the metal surface and must be continuously replenished with new inhibitor.

In the petroleum industry, organic inhibitors are frequently used because they can form protec-tive layers even in the presence of hydrocarbons. Amides and imidazolines are examples of organic film-forming inhibitors that are effective over a wide range of conditions, especially in sweet (CO2) and sour (H2S) gas corrosion environments. They can be water or oil soluble. Amines, which are also organic inhibitors, are effective for sweet and sour corrosion but may exhibit biologic toxic-ity and are thus not as environmentally friendly as are amides.

Quaternary ammonium salt, or quaternary amine, inhibitors are effective against sour corro-sion.32 The corrosive element formed by sour gas is iron sulfide on the metal surface. Quaternary ammonium cations, or quats, are positively charged, and when they are adsorbed on the surface of the material to be protected, they dis-rupt the normal corrosion cell charge. However, at least one study indicated that quaternary ammonium inhibitors may actually increase the corrosion rate of sweet corrosion in the presence of brine.33 The biocide properties of quaternary ammonium salts may also prevent MIC.

Many additional film formers are used in the oil and gas industry, including phosphate esters, ester quats, dimer and trimer acids and alkyl pyr-idine quaternary compounds. Most film-forming applications include multiple inhibitors; labora-tory testing is used to establish optimum concen-trations, fluid tolerances, stability, effectiveness and persistency of the film. Inhibitor selection can be a complicated process and typically must be adjusted over time to meet the demands of changing fluid conditions.

Inhibitor SelectionLaboratory evaluation is the key to developing an effective program in inhibitor selection for corrosion control. Technicians begin the process using fluid samples that replicate field condi-tions—actual produced fluids are best if avail-able. Simulated and synthetic fluids are used when produced fluids cannot be obtained. From laboratory tests, corrosion rates can be mea-sured and predictions can be made for large- scale operations (Figure 12). Methods for test-ing corrosion inhibitors include the following tests: wheel, kettle (also called linear polariza-tion resistance (LPR) tests), rotating cylinder

31. Schweitzer PA: Corrosion of Linings and Coatings: Cathodic and Inhibitor Protection and Corrosion Monitoring. Boca Raton, Florida: CRC Press, 2006.

32. Binks BP, Fletcher PDI, Hicks JT, Durnie WH and Horsup DI: “Comparison of the Effects of Air, Carbon Dioxide and Hydrogen Sulphide on Corrosion of a Low Oilfield Review

MAY 16Corrosion Fig 12ORMAY 16 CRSSN 12

Use of corrosioninhibitor recommended

Predict corrosion ratefrom field data

Develop and executetesting program

Rotating CylinderElectrode Test

Sidestream Test

Kettle Test Autoclave Test

Recommend and implement corrosion

inhibitor addition

Conduct field trial

Analyze fieldtrial results

Make finalrecommendation

Figure 12. Laboratory testing of corrosion inhibitors. Operators usually develop corrosion control plans and then test inhibitors using conditions expected from the field. This flowchart follows a testing sequence. Three common testing methods are the rotating cylinder electrode, kettle and autoclave tests (middle). Even after laboratory testing, field trials should be conducted to validate the effectiveness of the program. A sidestream test (lower left ) acquires samples for analysis. If the proposed method provides acceptable results, the method is adopted, although the corrosion inhibition program must be reevaluated during the life of the well.

Carbon Steel under Water and Its Inhibition by a Quaternary Ammonium Salt,” paper NACE 05307, presented at the NACE Corrosion 2005 Conference and Exhibition, Houston, April 3–7, 2005.

33. Binks et al, reference 32.

44 Oilfield Review

electrode, autoclave, jet impingement and flow loop (Figure 13). The most common are the wheel and kettle tests.34

The wheel test measures the loss of metal during a specified period of exposure to corro-sive liquids. Corrosives include produced fluids, brines and refined oils. The test fixture includes a rotating wheel inside a sealed box that keeps the specimen, usually strips of metal or coupons, in constant motion. Temperature can be main-tained at a constant value or varied to simulate field conditions. The samples are tested with and without inhibitor and the results are compared.

The kettle test, or LPR test, measures corro-sion rates electrochemically. Metal electrodes are placed in the test vessel, which is heated while the corrosive fluid is continously agitated. Agitation attempts to replicate field conditions—mild agitation is similar to flow of two distinct sources, and high agitation replicates turbulent fluid flow that has dispersed hydrocarbons. To simulate the presence of gases, CO2 and H2S can be bubbled through the liquid in the vessel in a process referred to as sparging.35

To establish a control corrosion rate, the test is run with the electrodes exposed to the fluids in aqueous phase without an inhibitor and then followed by a series of tests on solutions that have increased inhibitor volumes. Linear polarization is performed by controlling the voltage potential and measuring the current then controlling the

Figure 13. Autoclave corrosion testing. A high-temperature autoclave is used to test the effectiveness of corrosion inhibitors on metal coupons (inset ). Hydrostatic pressure and temperature can be applied to simulate downhole conditions.

Rack

Pressure source(hydraulic pump)

High-temperature autoclave

Metal coupon container

Figure 14. Kettle test. To perform kettle tests, or linear polarization resistance tests, technicians use a test fixture (left ) and control the pressure and temperature. They submerge electrodes inside the fixture into the fluids expected downhole and then measure electrical properties of the electrodes. The tests are performed by controlling the voltage potential

and measuring the current then controlling the current and measuring the voltage. The electrolyte can be agitated using the stir bar. Gas can be injected into the test fixture, a process referred to as sparging. From the slope of the polarization resistance curve (right ), the corrosion rate can be computed.

Current, mA

Volta

ge p

oten

tial,

mV

Steel electrode

Heating mantel

Stir bar

Thermometer

Gas sparge

Corrosion rateVoltageCurrent

May 2016 45

34. NACE Task Group T-1D-34 on Laboratory Corrosion Inhibitor Test Parameters: “Laboratory Test Methods for Evaluating Oilfield Corrosion Inhibitors,” Houston, NACE International, NACE Publication 1D196, December 1996.

35. NACE Task Group T-1D-34 on Laboratory Corrosion Inhibitor Test Parameters, reference 34.

36. Efird KD: “Jet Impingement Testing for Flow Accelerated Corrosion,” paper NACE 00052, presented at NACE Corrosion 2000 Conference and Exhibition, Orlando, Florida, March 26–31, 2000.

37. Melot D, Paugam G and Roche M: “Disbondments of Pipeline Coatings and Their Effects on Corrosion Risks,” Journal of Protective Coatings and Linings 26, no. 9 (September 2009): 67–76.

current and measuring the voltage potential. The data are plotted, and the slope of the line is the polarization resistance, which is inversely proportional to the corrosion rate (Figure 14). This technique provides corrosion rate evalua-tion from external measurements, whereas other methods require technicians to physically mea-sure and evaluate corrosion.

The effectiveness of inhibitors is dependent on fluid velocity. For fluids containing little or no solid particles, high flow rates can lead to flow-accelerated corrosion. If the flow stream contains solid particles, the accelerated corro-sion is termed erosion corrosion. Several test methods have been developed to model corrosion in high-flow conditions and determine a film’s persistence, especially where turbulent flow is present.36 Test methods include jet impingement, rotating cylinder electrodes and flow loop testing.

The testing of inhibitors should determine the following:

• thermal stability• emulsification tendency• foaming tendency• metal compatibility• elastomer compatibility• compatibility with other chemicals used in the

same stream.Application methods should be evaluated as well. Injection may be continuous, batch or squeeze. The rate of film removal is a key concern when determining the optimal application mode.

Corrosion in the Oil FieldA recent example of pipeline corrosion from Gabon illustrates the need for thorough testing and understanding of the corrosion process.37 A pipeline transports oil from the Rabi field to Cape Lopez—a distance of approximately 234 km [145 mi]. The 18-in. pipeline comprises three sections: Section 1 from Rabi to Batanga, 105 km [65 mi]; Section 2 from Batanga to Tchengué,

100 km [62 mi] and then Section 3 from Tchengué to Cape Lopez, 29 km [18 mi] (Figure 15).

The inlet pressure at Rabi was about 40 bar [580 psi], and the flowing temperature was 60°C [140°F] at the inlet. Beyond the inlet, the line oper-ates at about 35°C [95°F]. Impressed cathodic pro-tection is used for the pipeline, which has sections that have solar cells to provide current. The pipeline was coated with three-layer polyethylene; each joint was brush cleaned and wrapped with heat-shrink

Figure 15. Corrosion in a pipeline from the Rabi field to Cape Lopez. A three-section, 18-in. pipeline carries oil from the inland Rabi field in Gabon to Cape Lopez on the coast. Cathodic protection stations are located along the pipeline. Because the incoming oil is hot (around 60°C), Section 1 of the pipeline (red and dark blue) is exposed to a higher temperature than is the remainder of the pipeline. The elevated temperature led to the disbondment

of the protective outer covering of the pipeline. Engineers concluded that corrosion observed in Section 1 resulted from a combination of the disbonding of the protective covering and ineffective cathodic protection. Although the pipeline’s safety was not compromised, the operator implemented new procedures to prevent the corrosion from recurring.

Cape LopezCathodic protection station

TchéngueCathodic protection station

BatangaCathodic protection station

Rabi FieldCathodic protection station

Input temperature 60˚ C

Cathodic protection stationspowered by two solar cells

Section 1

Section 2Section 3

GABONATLANTIC OCEAN

~ ~

46 Oilfield Review

sleeves and hot-melt adhesive that overlapped the polyethylene.38 The pipe was buried in wet, com-pacted sand that had a pH of approximately 5.4.

Problems began to develop in the first 15 km [9.3 mi] of pipe. Routine inspections found dis-bondment at the sleeves where they overlapped the polyethylene coating in the Rabi section. Disbondment allowed water under the protective coating, which negated the cathodic protection and allowed corrosion to develop (Figure 16). The remainder of the pipeline did not experience the same level of corrosion, although significant

disbondment occurred in the sleeves. The main difference between the sections that had differ-ing corrosion levels was that the temperature in the more corroded sections was higher. Further testing of pipe Sections 2 and 3 found no evidence of similar levels of disbondment or corrosion.

After a thorough examination, engineers recom-mended abrasive blast cleaning prior to applying heat-shrink sleeves for future installations rather than the standard brush cleaning of connections. Another possible solution was liquid polyurethane or epoxy applied at the joints. The disbonded coating

may have prevented cathodic current from reaching and protecting the surface of the exposed steel. Although engineers discovered corrosion as a result of disbonding of coatings, based on ASME standards, the degree of corrosion was deemed not mechani-cally dangerous. They also concluded that as long as coatings remain bonded to the steel and cathodic protection is correctly applied, monitored and main-tained, no corrosion risk existed for this pipeline.

Corrosion Inhibitors in DeepwaterDeepwater projects can pose unique challenges for corrosion control because the completions are usually located at the seafloor and flowlines must come to the surface or back to shore. A deepwater field located in the southern Niger delta demonstrates the use of inhibitors to com-bat CO2-induced corrosion (Figure 17).39

The production path for deepwater wells passes through cold water, which can subject the originally hot fluids in the flow stream to rapid cooling. Conversely, inhibitor injection is often through long umbilicals that are subjected to temperature contrasts between the surface and subsea wellheads. Injection of inhibitors is fur-ther complicated by the normally high flowing pressures associated with deepwater production.

Temperature extremes, pressure extremes and long umbilicals combine to affect inhibitor

Figure 16. An example of pipeline corrosion. After the protective coating disbonded on a pipeline in Gabon, corrosion formed as pitting (inset ).

Figure 17. Niger delta subsea operations and a floating production, storage, and offloading (FPSO) vessel. Production from subsea wellheads (yellow) at a field in the Niger delta off the coast of Nigeria (inset) is sent to an FPSO. Oil is transferred to tankers, and natural gas is piped directly to the mainland.

Niger Deltafield

NIGERIA

CAMEROON

BURKINA FASO

COTED’IVOIRE

GHANA

BENIN

GABON

FPSO vessel

Flowlines andumbilicals

Subseawellheads

Gulf of Guinea

May 2016 47

stability, performance and properties. Thorough testing of the inhibitors is required to ensure corrosion controlling properties are maintained, that the injected chemicals remain stable and that the inhibitors can be reliably delivered via the umbilicals into the flow stream.

Another risk in deepwater production is the formation of hydrates—ice-like solids of water and gas that form above the normal freezing point of water—that can plug flowlines. To ensure cor-rosion controlling properties are maintained, inhibitors must be thoroughly tested to confirm that the injected chemicals remain stable and that the inhibitors can be reliably delivered via umbilicals into the flow stream.

These conditions were faced by an operator of a deepwater production platform in Nigeria. The platform served nine wells drilled in water depth of 1,030 m [3,380 ft]. The operator used subsea completions that included five manifolds and eight production flowlines and risers. The flowlines were connected to a floating produc-tion, storage, and offloading (FPSO) vessel that had 320,000 m3 [2 million bbl] of onsite storage capacity. Produced oil flowed to the FPSO for transfer to tankers. Produced gas was directed to shore via pipelines.

The pipelines used to transport the oil and gas were constructed of carbon steel. The flow-ing pressure from the wells averaged 80 bar [1,160 psi], and the average temperature was 85°C [185°F]. The water cut was 45% and the natural gas contained about 1.4% CO2. The com-bination of produced water (brine) and CO2 presented a high corrosion-rate potential for the low-carbon steel. In wet gas pipelines such as these, produced water has a tendency to con-dense at the top of the pipe, allowing top-of-line corrosion; the presence of both water and CO2 accelerates corrosion.

Engineers installed chemical umbilicals of 1 to 20 km [0.6 to 12.4 mi] to inject corrosion inhibitor into the deepwater production flow-lines. As the project progressed, engineers at M-I SWACO, a Schlumberger company, reevalu-ated the initial inhibitor used in the project, which also protected the topside piping and storage vessels, and deemed it to be insufficient.

Engineers developed the DS-1617 deepwater corrosion inhibitor to meet the challenges of this facility.

To qualify this inhibitor, they tested the chemicals in accordance with the API TR 17TR6 standard, which requires replicating the temper-atures and pressures experienced by the inhibitor during deployment through the umbilicals.40 The evaluation included high-pressure flow-loop sta-bility tests. The engineers conducted additional tests to look at resistance to hydrate formation, thermal aging and compatibility with seawater. Because the operator was concerned about foam-ing in the glycol regeneration unit, the inhibitor was tested for foaming tendency.

Laboratory technicians performed kettle tests using the DS-1617 inhibitor at 20 ppm, which is a relatively low dosage; the corrosion rate was reduced by 99% (Figure 18). They also performed high-temperature autoclave testing on carbon steel coupons. The samples were sub-jected to test fluids that had corrosion inhibitor

and to pressurized CO2 heated to 120°C [248°F]. The results indicated a 98% reduction in the corrosion rate.41 The 20 ppm concentration yielded corrosion rates of about 0.00016 in./year [0.004 mm/year]. For corrosion rate, the stan-dard industry units are milli-inches/year, or mpy. For this test, the corrosion rate was equivalent to 0.16 mpy. Test technicians reported no foaming problems associated with the inhibitor.

The operator adopted the use of the DS-1617 inhibitor and monitored corrosion at six loca-tions on the FPSO. No corrosion monitoring was installed on the deepwater flowlines. The DS-1617 inhibitor was injected at a 100-ppm rate, which is a lower rate than the initial inhibi-tor that was deemed insufficient. Criteria for corrosion protection established by the opera-tor was a rate below 0.05 mpy [0.0013 mm/year]. Testing at all six locations indicated corrosion rates below the target rate (Figure 19). Based on the testing, the operator implemented the use of the DS-1617 inhibitor.

38. Roche M: “The Problematic of Disbonding of Coatings and Corrosion with Buried Pipelines Cathodically Protected,” presented at the 10th European Federation of Corrosion, Nice, France, September 12–16, 2004.

39. Jenkins A: “Corrosion Mitigation in a Deepwater Oilfield Case Study,” paper IBP1194_15, presented at the Rio Pipeline Conference and Exposition, Rio de Janeiro, September 22–24, 2015.

40. API: “Attributes of Production Chemicals in Subsea Production Systems,” Washington, DC: API, API Technical Report 17TR6, 2012.

41. Jenkins, reference 39.

Figure 18. Corrosion testing of the DS-1617 inhibitor. Technicians conducted kettle tests with fluids representative of field conditions to evaluate the effectiveness of the DS-1617 inhibitor (top). They also performed autoclave testing at high temperature (bottom). The corrosion rate is in milli-inches of penetration/year (mpy).

Inhibitor Dose Rate, ppm Uninhibited Corrosion Rate, mpy

Inhibited Corrosion Rate, mpy

Protection, %

DS-1617 inhibitor 10 173.01 4.18 97.58

DS-1617 inhibitor 20 156.43 0.98 99.37

Inhibitor Dose Rate, ppm Corrosion Rate, mpy Protection, %

None — 71.04 —

DS-1617 inhibitor 20 1.16 98.37

Figure 19. Corrosion monitoring at a production facility. The operator injected DS-1617 inhibitor into the flowlines of producing wells using underwater umbilicals. The corrosion rate of the flowlines was monitored at the low-pressure separator A (blue), low-pressure separator B (red) and the bulk oil treater (green) as well as at three other locations (not shown). The corrosion rate dropped below the target level (black) established by the operator. Corrosion rates remained below the threshold at all test sites for the duration of the testing period.

6.0Low-pressure separator A

Low-pressure separator B

Bulk oil treater

Target corrosion rate

0.5 1.00

0.0

1.0

2.0

3.0

4.0

5.0

1.5 2.0 2.5 3.0Time, hr

Corro

sion

rate

, mpy

3.5 4.0 4.5 5.0 6.0

48 Oilfield Review

North Sea Cathodic ProtectionNorth Sea production platforms routinely use cathodic protection. On one platform, the opera-tor installed 10 sacrificial anodes below the sur-face of the water and left them in place for eight years. The anodes were composed of zinc, silver and silver chloride and were located at various depths and locations on the plaform.42 The system was designed to protect the structure for a mini-mum of 20 years. Engineers monitored the output current from three of the anodes over the period. The anodes were removed and inspected at the end of eight years.

After retrieval, the sacrificial anodes were cleaned and weighed (Figure 20). Technicians

determined changes in physical dimensions and measured electrical properties. Four anodes were analyzed for the study. The reduction of anodes that had been placed in deeper water was greater than that of those placed in shallower water. Some of the anodes were so corroded that visual inspection was difficult (Figure 21).

The original 20-year design projected that at eight years, the anodes should be reduced by 40%; however, the average weight loss of the anodes was only 24%. The engineers concluded that the original design, although conservative, would protect the structure for at least 20 years. Based on the results of the study, a model was estab-lished for periodic inspections to be performed.

New Developments in Corrosion ControlControlling corrosion has been an ongoing battle between humans and nature for millen-nia. Since scientists such as Sir Humphry Davy and Michael Faraday discovered some of the underlying physics that explained corrosion, various methodologies have been adopted and adapted. Modern scientific understanding and new technologies are combining to improve the tools available to fight the unending battle with corrosion.

One area of emerging materials science is nanoparticles and nanostructures.43 Having sur-face thickness of 1 to 100 nm, these coating mate-rials have unique properties that may make them almost impervious to corrosion. Nanoparticles and nanostructures may be deposited on metal surfaces as films, similar to film-forming tech-niques, but because of nanoparticles’ greater persistence, reapplying them is unnecessary. The surfaces also become super-slick—exhibiting low friction coefficients—which reduces wear and increases durability. Such surfaces are also less likely to experience biofouling.44

The battle against corrosion will never be won; entropy will eventually win the war. Humans will, however, continue to search for effective means to combat this nemesis. The costs of ignoring the problem are too great and the consequences of failure can be potentially catastrophic. At least in the oil field, operators are armed with knowledge, science and effective tools that allow them to actively manage or miti-gate the effects of corrosion. —DEA/TS

42. Roche M: “Offshore Cathodic Protection: The Lessons of Long-Term Experience,” paper OMC-2005-020, presented at the 7th Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, March 16–18, 2005.

43. El-Meligi AA: “Nanostructure of Materials and Corrosion Resistance,” in Aliofkhazraei M (ed): Developments in Corrosion Protection. Rijeka, Croatia: InTech (2014): 3–23.

Figure 21. Cathodic protection on a North Sea platform. Anodes were recovered after eight years of service from a North Sea platform. After the anodes were cleaned and weighed, technicians were able to determine the effectiveness of the anodes at protecting the structure.

Figure 20. Anode corrosion after eight years of service in the North Sea.

Anode Water Depth, m Weight Loss, %

1 13 13

2 73 31

3 116 25

4 116 39

44. Tesler AB, Kim P, Kolle S, Howell C, Ahanotu O and Aizenberg J: “Extremely Durable Biofouling-Resistant Surfaces Based on Electrodeposited Nanoporous Tungstite Films on Steel,” Nature Communications 6, no. 8649 (October 20, 2015).

May 2016 49

Nausha Asrar is the Manager for Materials Support and Failure Analysis at the Schlumberger Houston Pressure and Sampling and Formation Evaluation Centers in Sugar Land, Texas, USA. He began his career with Schlumberger in 2005 as a senior materi-als scientist. He previously worked for Shell Global Solutions in the US, the Saudi Basic Industries Corporation Technology Center and Saline Water Conversion Corporation, both in Saudi Arabia, and as principal corrosion engineer at the Research and Development Center for Iron and Steel for the Steel Authority of India, Ltd. A NACE certified material selection and design specialist, Nausha is a member of NACE, ASM and SPE as well as a life member of the Indian Institute of Metals; he is the author of more than 60 technical papers and reviews on corrosion, phase diagrams, composite materials and failure cases. He received an MS degree in chemistry from Aligarh Muslim University, Uttar Pradesh, India, and a PhD degree in materials science and engineering from the Moscow State University.

Øystein Birketveit is Technical Manager for Production Technologies for M-I SWACO, a Schlumberger company, in Bergen, Norway. For the past 18 years, he has specialized in the field of corrosion. Prior to joining M-I SWACO, Øystein worked for Statoil and for Det Norske Veritas. He earned his MSc degree in materials and electrochemistry from the Norwegian University of Science and Technology, Trondheim.

Joshua E. Jackson is the CEO of G2MT LLC as well as the cofounder of G2MT Laboratories, LLC in Houston. G2MT Labs is a metallurgical consulting and analysis company that performs nondestructive materials char-acterization to evaluate residual stress mechanical properties and other critical parameters including the effects of corrosion. His scientific focus areas include corrosion analysis, high-temperature materials, hydro-gen absorption effects, failure analysis and statistics. Joshua is the coauthor of numerous papers in the field of materials science covering subjects including non-destructive testing, metallurgy, welding, corrosion and hydrogen. He obtained BS degrees in both mathemat-ics and physics from the Massachusetts Institute of Technology, Cambridge, USA, and MS and PhD degrees in metallurgical and materials engineering from the Colorado School of Mines, Golden, USA.

Alyn Jenkins, based in Aberdeen, serves as the Global Asset Integrity Manager for Schlumberger Production Technologies. He manages asset integrity product lines that include corrosion inhibitors, biocides, H2S scavengers and oxygen scavengers and is responsible for research and development projects related to corrosion. He began his career in 1998 with Clariant Oil Services in Aberdeen and then worked for Baker Hughes in Liverpool, England. Alyn joined M-I SWACO in 2005 as a corrosion specialist in Stavanger and then served as lead integrity management specialist. Alyn holds BS and MS degrees, both in chemistry, from the University of Wales, Bangor.

Bruce MacKay is Client Support Manager for the Schlumberger North America fracturing and cement-ing operations in Sugar Land, Texas. He has worked as a chemical problem solver in various capacities for Schlumberger for 10 years, spanning the R&D spectrum from research to product development to technology implementation. He has authored 12 peer-reviewed scientific journal articles and five SPE papers and has been granted several patents on chemical technologies related to oilfield applications. He has been a speaker on the importance of chemistry in oil-field development to a variety of audiences, including the US National Academy of Sciences, the American Chemical Society and the National Aeronautics and Space Administration Jet Propulsion Laboratory. Bruce was a Natural Sciences and Engineering Research Council of Canada postdoctoral research scholar at the California Institute of Technology, Pasadena, USA. He earned a BS degree in chemistry and a PhD degree in inorganic chemistry from the University of British Columbia, Vancouver, Canada.

Denis Mélot is a Nonmetallic Materials Expert with the technology department of Total Upstream, in Paris. Using his foundation of studies in polymer science, his focus is on nonmetallic materials and corrosion. Prior to beginning work with Total in 2003, he was a researcher in the R&D department of Elf Atochem, which is now Arkema, in Serquigny, France. He then spent six years as the technical manager for pipe coating products with the company. Denis chaired the ISO 12736 working group on wet thermal insula-tion systems, was a member of pipeline coatings work group ISO 21809 and holds certifications from the Association pour la Certification et la Qualification en Peinture Anticorrosion and Faglig Råd for Opplæring og Sertifisering av Inspektører innen Overflatebehandling . He holds numerous patents in his field and has coauthored several papers on the subject of coatings and corrosion. Denis has a degree in materials science from the École Universitaire D’Ingénieurs de Lille, France, and received his PhD degree in polymer science from Université de Lille.

Jan Scheie is a Project Leader and Account Manager for Production Technologies (PT) in Schlumberger Norge A/S in Stavanger, where he serves customers in Scandinavia. He has also been an account manager for production technologies, an international sales manager and an area manager for production chemi-cals in Stavanger. He has worked for M-I SWACO in market development for the eastern hemisphere, as technical manager in the Middle East and CIS, as sales manager in South Asia and as principal engineer for developing sales strategy in mainland Europe. He is a member of TEKNA, the Norwegian Society of Graduate Technical and Scientific Professionals, the SPE and the National Association of Corrosion Engineers. He received an MSc degree in chemical engineering from the Norwegian University of Science and Technology, Trondheim, Norway, and an MBA degree from Thunderbird School of Global Management, Glendale, Arizona, USA.

Marko Stipanicev is Corrosion Discipline Lead for Schlumberger Production Technologies in Bergen, Norway. Upon graduation from the University of Zagreb, Croatia, he worked as an external consultant on industry related projects at the Faculty of Chemical Engineering and Technology, in Croatia. Beginning in 2010, he worked as a research engineer for Det Norske Veritas in Bergen, investigating corrosion-based failures and performing root cause analysis studies. He joined M-I SWACO in 2013 as a corrosion specialist, working in Bergen, and in 2015, he was named the corrosion discipline lead. Marko is responsible for Schlumberger corrosion products, which include inhibitors, biocides, scavengers and nutrients. He has authored and coau-thored numerous papers and publications related to corrosion and corrosion management. He holds an MSc degree in chemical engineering and technology from the University of Zagreb and a PhD degree in environ-mental process and biocorrosion management from the Université de Toulouse, France.

Jean Vittonato, is Head of the Total E&P Technology Division corrosion department in Pau, France. He is responsible for the headquarters’ corrosion team and provides technical assistance to projects and operating subsidiaries worldwide. He started work in 1999 focusing on cathodic protection with COREXCO, an engineering cathodic protection company, where he was in charge of designing cathodic protection systems for both onshore and offshore and for installa-tion, monitoring and maintenance follow-up. In 2006, he joined Total as a corrosion specialist and was in charge of cathodic protection activities. He provided support for projects for both Total E&P and operating subsidiaries and was in charge of research projects related to cathodic protection. He spent three years in Republic of the Congo as the head of the Total cor-rosion department, where he supervised all projects related to corrosion. Jean is a certified Cathodic Protection Specialist with the National Association of Corrosion Engineers and with the Centre Français de la Protection Cathodique and is chair of the ISO TC 67 SC2 GW11 working group on cathodic protection of pipelines. He obtained an engineer-ing degree from Institut National Polytechnique de Grenoble, France.

Contributors