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Question 1

Score: 0/0

CO2 (sweet) corrosion of carbon steel in produced water involves:

Direct reaction with dry CO2 gas

Dissolved CO2 forming carbonic acid (H2CO3) that reduces pH and attacks the iron surface

Only high-temperature reactions

Only radiation effects

to track

2026 Statistics

Key Facts: AMPP ICS Exam

Closed

New Candidates (2026)

AMPP ICS page

8 years

Historical Experience

AMPP ICS requirements

PE/BS

Historical Education

AMPP ICS requirements

0.05 psi

Sour Threshold (H2S)

NACE MR0175 / ISO 15156

22 HRC

Max Hardness (Sour)

NACE MR0175

100

Practice Questions

OpenExamPrep

AMPP Internal Corrosion Specialist (ICS) is a senior internal corrosion credential. IMPORTANT: per AMPP's 2026 website, ICS is currently NOT open to new candidates. This question bank remains valuable for internal corrosion study, Senior Internal Corrosion Technologist exam prep, Corrosion Specialist exam prep, and integrity management knowledge. Content covers CO2/H2S corrosion, MIC, inhibitors, monitoring (coupons, ER/LPR, UT, ILI), flow-induced corrosion, and core NACE/API standards (MR0175, SP0106, SP0208, API 570/510/653, API 579 FFS, API RP 580 RBI).

Sample AMPP ICS Practice Questions

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1CO2 (sweet) corrosion of carbon steel in produced water involves:

A.Direct reaction with dry CO2 gas

B.Dissolved CO2 forming carbonic acid (H2CO3) that reduces pH and attacks the iron surface

C.Only high-temperature reactions

D.Only radiation effects

Explanation: CO2 dissolves in water to form carbonic acid (H2CO3), which dissociates to H+ and HCO3-, lowering pH. The acidic conditions attack iron at the cathodic sites (H+ reduction to H2) and anodic sites (Fe oxidation to Fe2+). Produced water with dissolved CO2 is the primary cause of internal corrosion in oil/gas production and transmission pipelines. Dry CO2 alone does not cause significant corrosion.

2The de Waard-Milliams model predicts CO2 corrosion rates as a function of:

A.Only pH

B.CO2 partial pressure, temperature, and pH (with corrections for protective scale formation)

C.Only temperature

D.Flow rate only

Explanation: The de Waard-Milliams (1975) and de Waard-Lotz (1993) models correlate CO2 corrosion rate with CO2 partial pressure (ppCO2), temperature, and pH, with corrections for protective iron carbonate (FeCO3) scale. The models provide a screening-level prediction for sweet corrosion and are widely used in risk assessment. More recent models (NORSOK M-506, predict.com, Cassandra) refine with additional factors.

3Iron carbonate (FeCO3) scale forms on steel surfaces in CO2 environments and typically:

A.Accelerates corrosion

B.Provides protective barrier when it forms as a dense, adherent layer (protective scale)

C.Has no effect

D.Is unstable in all conditions

Explanation: When FeCO3 precipitates as a dense, adherent scale on the steel surface, it provides protective barrier properties and substantially reduces corrosion rate. Scale protectiveness depends on temperature (better above 60°C), pH (higher pH favors precipitation), supersaturation, and flow conditions. Flow can disrupt protective scale, exposing fresh steel. Localized FeCO3 scale is a mixed blessing — can cause under-deposit corrosion.

4'Top of Line Corrosion' (TLC) in wet gas pipelines occurs when:

A.Gas flows too slowly at the bottom

B.Condensation of water on the upper (top) pipe wall creates acidic droplets that corrode the top of the pipe

C.Only bottom of line is affected

D.Only external corrosion

Explanation: Top-of-Line Corrosion (TLC) in stratified-flow wet gas pipelines occurs when the gas cools below the dew point and water condenses on the cool upper pipe wall. The condensate is essentially distilled water with dissolved CO2 and organic acids, very acidic, and corrosive. Bottom-of-line corrosion is inhibited by corrosion inhibitor in the bulk water phase, but TLC at the top is not reached by bottom-phase inhibitors. Volatile inhibitors are needed.

5NACE SP0106 (now AMPP SP0106) addresses:

A.External pipeline coatings

B.Control of internal corrosion in steel pipelines and piping systems

C.Atmospheric corrosion

D.Welding procedures

Explanation: NACE SP0106 / AMPP SP0106 'Control of Internal Corrosion in Steel Pipelines and Piping Systems' is the foundational standard for internal corrosion management. It addresses design, monitoring, mitigation (inhibition, cleaning, cathodic protection), and integrity management for internal corrosion. Specifiers and corrosion engineers reference SP0106 for internal corrosion programs.

6The pH of a CO2-saturated water solution at 25°C and 1 atm CO2 partial pressure is approximately:

A.7

B.5

C.4

D.2

Explanation: CO2-saturated water at 25°C and 1 atm CO2 partial pressure has pH approximately 3.9-4.0 (carbonic acid is a weak acid). This is corrosive to carbon steel. Higher CO2 partial pressures (common in oil/gas production, up to hundreds of psi) produce even lower pH. In-situ pH in producing systems depends on CO2, bicarbonate buffering, and other ions.

7Mesa attack in CO2 corrosion is characterized by:

A.Uniform thinning

B.Localized attack with flat-bottomed pits resembling mesa landforms, typically on the floor of horizontal pipes

C.General corrosion only

D.Weight gain

Explanation: Mesa attack is a distinctive CO2 corrosion morphology where localized attack produces flat-bottomed pits or 'plateaus' resembling mesa landforms, often on the bottom of horizontal oil/gas pipelines. It combines general corrosion with localized pit formation driven by inconsistent protective scale. Mesa attack is particularly problematic because it penetrates faster than general corrosion.

8Increasing temperature in CO2 corrosion typically:

A.Always increases corrosion rate

B.Initially increases rate (due to kinetics) but can decrease rate above ~60-70°C due to protective FeCO3 scale formation

C.Has no effect

D.Only affects pH

Explanation: CO2 corrosion rate has a complex temperature dependence. Below ~60°C, higher temperature accelerates kinetics and increases corrosion. Between 60-90°C, protective FeCO3 scale forms more readily, potentially reducing corrosion rate. Above ~90°C, the balance depends on other factors. This non-monotonic behavior is modeled in de Waard-Milliams and related models.

9Organic acids (e.g., acetic acid) present in produced water can:

A.Reduce CO2 corrosion

B.Accelerate CO2 corrosion by providing additional H+ and destabilizing FeCO3 protective scale

C.Have no effect

D.Only cause SCC

Explanation: Organic acids like acetic, formic, and propionic acid (common in produced water) destabilize FeCO3 protective scale and provide additional H+ acidity. Their effect is often more aggressive than equivalent CO2-only conditions because they target the protective scale. Modern corrosion prediction models account for organic acid contribution.

10Dew point at the top of a wet gas pipeline is influenced by:

A.Only the gas temperature

B.Gas temperature, pipe wall temperature, pressure, gas composition, and ambient conditions

C.Only the pressure

D.Only ambient

Explanation: The dew point at the top of a wet gas pipeline — and thus condensation and TLC risk — depends on the gas temperature entering the pipe, pipe wall temperature (influenced by ambient conditions via heat transfer through wall and insulation), pipeline pressure, gas composition (water vapor content, hydrocarbon dew point), and ambient temperature/wind. Insulation can reduce cooling and TLC risk.

About the AMPP ICS Exam

The AMPP Internal Corrosion Specialist (ICS) is the senior credential for professionals who design, implement, evaluate, and manage internal corrosion integrity management programs for pipelines, pressure vessels, and piping — regardless of industry. NOTE: Per AMPP's 2026 certification site, the ICS certification is currently NOT accepting new candidates. Content remains valuable for practitioners studying internal corrosion fundamentals, preparing for related certifications (Senior Internal Corrosion Technologist, Corrosion Specialist), or supporting integrity management programs. The knowledge domain covers CO2 sweet corrosion (de Waard-Milliams model, iron carbonate scale, mesa attack, top-of-line corrosion), H2S sour corrosion per NACE MR0175/ISO 15156 (SSC, HIC, SOHIC, 22 HRC hardness limits, CRAs, TM0177, TM0284), microbiologically influenced corrosion (SRB, APB, biofilms, qPCR, biocides, NACE TM0194), corrosion inhibitors (film-formers, batch, continuous, squeeze, VCIs, RCE testing, residuals), monitoring methods (coupons per SP0775/TM0169, ER probes, LPR, FSM, UT, ILI smart pigs, hydrogen permeation), flow-induced corrosion (FAC, erosion-corrosion, API RP 14E, sand production, slug flow, cavitation), sampling and water chemistry analysis, and core standards including NACE SP0106, SP0208 ICDA, SP0607, SP0775, API 570/510/653, API 579 FFS, and API RP 580 RBI. Historical eligibility required Senior Internal Corrosion Technologist certification OR 8 years verifiable internal corrosion in pipeline environment work experience plus a PE/P.Eng/EIT equivalent or a bachelor's degree in an approved discipline.

Assessment

Written CBT exam (certification currently NOT accepting new candidates per AMPP 2026 — content remains valuable for internal corrosion study)

Time Limit

Not publicly disclosed

Passing Score

Not publicly disclosed

Exam Fee

Not publicly disclosed (AMPP (Association for Materials Protection and Performance))

AMPP ICS Exam Content Outline

15%

CO2 Sweet Corrosion

Carbonic acid mechanism, de Waard-Milliams model, iron carbonate (FeCO3) scale, mesa attack, top-of-line corrosion (TLC) in wet gas, NACE SP0106, organic acids (acetic), 13Cr CRA selection

15%

H2S Sour Corrosion

NACE MR0175 / ISO 15156 sour service definition (0.05 psi H2S threshold), Sulfide Stress Cracking (SSC), HIC, SOHIC, 22 HRC hardness limit, PWHT, TM0177 SSC testing, TM0284 HIC testing, duplex/Ni CRAs, hydrogen permeation

12%

MIC

Sulfate-Reducing Bacteria (SRB), Acid-Producing Bacteria (APB), biofilms, EPS, NACE TM0194 enumeration, qPCR molecular methods, biocide selection and rotation, tubercle pitting, dead-leg risks, stagnation prevention

12%

Corrosion Inhibitors

Film-forming chemistry, batch vs continuous injection, squeeze treatments, VCI for top-of-line, rotating cylinder electrode (RCE) screening, residual testing, compatibility with other chemicals, minimum effective concentration

15%

Monitoring Methods

Weight-loss coupons per TM0169, Electrical Resistance (ER) probes, Linear Polarization Resistance (LPR), Field Signature Method (FSM), UT thickness monitoring, ILI (smart pigs) per API 1163, hydrogen permeation, dead-leg monitoring, threshold setting

Flow-Induced Corrosion

Flow-Accelerated Corrosion (FAC, magnetite dissolution), erosion-corrosion (multiphase), API RP 14E erosion velocity (V_e = C/√ρ), sand production impingement, elbow erosion, slug flow, cavitation, erosion allowance

Sampling and Analysis

Water sampling preservation, field pH measurement, chloride analysis, iron/manganese as corrosion indicators, oxygen scavenging, H2S sampling (zinc acetate), TAN (Total Acid Number) for naphthenic acid, integrity database

15%

Standards and NACE

NACE MR0175/ISO 15156, SP0106 internal pipeline corrosion, SP0208 ICDA, SP0607 ECDA bare pipe, SP0775 coupon practice, TM0169/TM0194/TM0177/TM0284, API 570/510/653 inspection codes, API 579-1 FFS, API RP 580/581 RBI, API 571 damage mechanisms, API RP 584 IOWs

How to Pass the AMPP ICS Exam

What You Need to Know

Passing score: Not publicly disclosed
Assessment: Written CBT exam (certification currently NOT accepting new candidates per AMPP 2026 — content remains valuable for internal corrosion study)
Time limit: Not publicly disclosed
Exam fee: Not publicly disclosed

Keys to Passing

Complete 500+ practice questions
Score 80%+ consistently before scheduling
Focus on highest-weighted sections
Use our AI tutor for tough concepts

AMPP ICS Study Tips from Top Performers

1Master NACE MR0175 / ISO 15156 sour service requirements: 0.05 psi H2S partial pressure threshold, 22 HRC hardness limit for carbon/low-alloy steels, PWHT requirements for welds, and CRA selection for various H2S/Cl/CO2/temperature combinations

2Understand the four conditions required for Sulfide Stress Cracking (SSC): H2S, water (electrolyte), tensile stress (applied + residual), and susceptible material — removing any one prevents cracking

3Distinguish HIC (Hydrogen Induced Cracking — internal, parallel to rolling, from inclusions) from SOHIC (Stress-Oriented HIC — stress-oriented, often near welds) and SSC (stress corrosion cracking with H2S)

4Learn CO2 corrosion prediction (de Waard-Milliams) parameters: CO2 partial pressure, temperature, pH, and protective iron carbonate (FeCO3) scale behavior — especially the temperature dependence above/below ~60°C

5Study corrosion monitoring methods and their tradeoffs: coupons (average, time-lagged), ER probes (near real-time general corrosion), LPR (real-time but requires electrolyte), FSM (non-intrusive voltage matrix), UT thickness (direct), ILI (whole-line survey)

6Memorize key standards and their purposes: NACE MR0175 (sour service materials), SP0106 (internal pipeline corrosion), SP0208 (ICDA), SP0775 (coupon practice), TM0169 (coupon cleaning), TM0177 (SSC testing), TM0284 (HIC testing)

7Understand MIC mechanisms: SRB (sulfate to sulfide), APB (organic acids), biofilms creating localized anaerobic zones, and qPCR molecular methods replacing traditional culture-based enumeration (NACE TM0194)

8Know API inspection codes at functional level: API 570 (piping), API 510 (pressure vessels), API 653 (tanks), API 579-1 (Fitness-for-Service), API RP 580/581 (Risk-Based Inspection) — internal corrosion data feeds all of these

Frequently Asked Questions

Is the AMPP Internal Corrosion Specialist certification currently available?

Per AMPP's 2026 website (ampp.org/education/job-function/specialty-certifications/internal-corrosion-specialist), the Internal Corrosion Specialist certification is currently NOT open to new candidates. This question bank remains valuable for: (1) existing ICS holders preparing for renewal, (2) candidates preparing for related AMPP credentials such as Senior Internal Corrosion Technologist or Corrosion Specialist, (3) integrity management professionals studying internal corrosion fundamentals, and (4) corrosion engineers supporting RBI and IOW programs. Check ampp.org periodically for possible reopening.

What are the historical eligibility requirements for ICS?

The historical ICS eligibility required EITHER active Senior Internal Corrosion Technologist certification OR 8 years of verifiable internal corrosion work experience specifically in pipeline environments, PLUS a professional engineering credential (PE, P.Eng, or EIT equivalent) or a bachelor's degree in an approved discipline (chemistry, chemical engineering, materials, metallurgy, or similar). Candidates also had to complete the Ethics for the Corrosion Professional course or an AMPP-approved equivalent and submit an approved Internal Corrosion Specialist application.

What topics are covered in the ICS body of knowledge?

The ICS body of knowledge covers: CO2 sweet corrosion (de Waard-Milliams model, iron carbonate scale, mesa attack, top-of-line corrosion); H2S sour corrosion per NACE MR0175/ISO 15156 (SSC, HIC, SOHIC, hardness limits, PWHT, CRAs); microbiologically influenced corrosion (SRB, APB, biofilms, biocides, qPCR); corrosion inhibitors (film-formers, batch/continuous, squeeze, VCIs); monitoring methods (coupons, ER, LPR, FSM, UT, ILI, hydrogen permeation); flow-induced corrosion (FAC, erosion-corrosion, API RP 14E); water chemistry sampling and analysis; and industry standards including NACE SP0106, API 570/510/653 inspection codes, API 579-1 Fitness-for-Service, and API RP 580/581 Risk-Based Inspection.

Is the Senior Internal Corrosion Technologist certification still available as an alternative?

Yes, per AMPP's 2026 website, the Senior Internal Corrosion Technologist certification is still available and is delivered as the Internal Corrosion for Pipelines - Advanced course. It serves as a path for advanced internal corrosion knowledge without requiring ICS-level engineering credentials. The Senior Internal Corrosion Technologist includes an in-person course, theory exam, and active certification. Some professionals who would historically have pursued ICS are now pursuing Senior Internal Corrosion Technologist or the broader Corrosion Specialist credential.

How does ICS relate to API inspection codes?

Internal corrosion management integrates with API 570 (Piping Inspection), API 510 (Pressure Vessel Inspection), and API 653 (Tank Inspection) — the three primary inspection codes governing in-service integrity of refinery and petrochemical equipment. Internal corrosion specialists identify damage mechanisms per API 571, support Risk-Based Inspection per API RP 580/581, calculate corrosion rates and remaining life, contribute to Fitness-For-Service evaluations per API 579-1, and help define Integrity Operating Windows per API RP 584. The ICS content complements API code training for corrosion engineers.

Should I study this content for a different certification?

Yes — internal corrosion content is directly relevant to several AMPP and API credentials including the Senior Internal Corrosion Technologist (currently open), Corrosion Technologist and Senior Corrosion Technologist, Corrosion Specialist, Refining Corrosion Technologist, and the Pipeline Corrosion Assessment Field Techniques (PCAFT) and Pipeline Corrosion Integrity Management (PCIM) micro-credentials. API 570, 510, 653, and the SIFE (Source Inspector Fixed Equipment) credentials also overlap heavily. This ICS question bank serves as internal corrosion study material across this family of credentials.

What is the role of NACE MR0175/ISO 15156 for internal corrosion specialists?

NACE MR0175 / ISO 15156 'Petroleum and natural gas industries - Materials for use in H2S-containing environments in oil and gas production' is the single most important material selection standard for sour service. Internal corrosion specialists must know its sour service definition (H2S partial pressure threshold 0.05 psi / 0.3 kPa), hardness limits (22 HRC max for most carbon/low-alloy steels), PWHT requirements, and CRA (corrosion-resistant alloy) selection tables for 13Cr, duplex stainless, nickel alloys (825, 625, C276), and titanium. MR0175 is referenced in virtually every sour-service specification.