Managing Internal Corrosion of Subsea Pipelines and Risers20Managing%20Internal%20...2018/10/15  · Important to monitor Sessile Microorganisms (e.g., NACE TM0194) since Monitoring

DNV GL © 2016 SAFER, SMARTER, GREENERDNV GL © 2016

Managing Internal Corrosion of Subsea Pipelines and Risers

“Providing our clients with cost effective solutions to materials, corrosion and

integrity problems through innovative and fundamentally sound research

and engineering practices”

DNV GL Offshore Pipeline Day

Oct. 15, 2018

DNV GL © 2016

Outline

▪ Introduction to corrosion management

▪ Identification of internal corrosion threats

▪ Internal corrosion mitigation alternatives

▪ Monitoring effectiveness of chemical

treatment

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Corrosion Management System (CMS)

▪ “A CMS is the documented set of processes and procedures required for planning,

executing, and continually improving the ability of an organization to manage the

threat of corrosion for existing and future assets and asset systems.”

▪ Risk-based corrosion planning approach (based on ISO 31000)

– Requires an in-depth technical knowledge of the potential or existing corrosion

mechanisms and available options for mitigating credible corrosion threats at

each of the key stages of an assets’ life cycle.

– Includes a continuous improvement process.

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Source: NACE IMPACT Report. “International Measures of Prevention, Application, and Economics of Corrosion Technologies” March 2016

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Internal Corrosion Threat Assessment

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Internal Corrosion Threat Assessment

▪ It is a process to understand potential internal

corrosion threats and the factors that lead to

potential threats

▪ Utilizes an algorithm than weighs different factors

– Pipeline Construction

– Operation History

– Inspection and Maintenance History

– Water Analyses

– Gas or Crude Oil Composition

– Chemicals injected (e.g., biocide, corrosion

inhibitor, scale inhibitors)

▪ Allows defining maintenance and mitigation efforts

to be implemented and focusing the efforts on the

highest threat level pipeline segments.

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Common Internal Corrosion Threats in Oil and Gas Pipelines

▪ Corrosion only in presence of liquid water

▪ Metal Loss Corrosion

– Corrosion associated to dissolved gases

– Sweet (CO2) Corrosion

– Sour (H2S) Corrosion

– O2 Corrosion

– Elemental Sulfur Corrosion

– Corrosion associated with added chemicals

– Preferential Weld Corrosion

– Galvanic Corrosion

– Microbiologically Induced Corrosion

– Top of the Line Corrosion

– Corrosion under Deposits

– Flow Induced Corrosion and Erosion-Corrosion

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▪ Environmentally Assisted Cracking

– Sulfide Stress Cracking

– Hydrogen Induced Cracking

– Corrosion-Fatigue

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Internal Corrosion Failures in Oil and Gas Production

CO2 50%

WELD RELATED20%

H2S/MIC8%

GALVANIC6%

PITTING10%

CREVICE5%

OTHERS1%

CO228%

WELD18%

H2S18%

GALVANIC6%

PITTING12% CREVICE

3%

EROSION CORROSION

9%

INPINGEMENT3%

SCC3%

Company A

Company B

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Sweet (CO2) Corrosion

▪ Principal cause of damage in O&G assets

▪ Corrosion rates can be very high and tend to

increase with CO2 partial pressure, fluid velocity

and temperature (up to a maximum)

– General Corrosion

– Localized Corrosion (pitting, mesa)

▪ Water chemistry plays an important factor

▪ Under certain conditions of pH, CO2 partial

pressure, iron concentration and temperature,

protective FeCO3 scales form

▪ Small amounts of H2S tend to form a protective

FeS film, decreasing corrosion rates. However,

localized corrosion may occur

▪ Presence of O2 increases corrosion rate and tends

to reduce effectiveness of corrosion inhibitors

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Sour (H2S) Corrosion

▪ H2S naturally occurs in some gas and crude oil

reservoirs.

– Concentration may increase with time (reservoir

souring) due to the presence of sulfate-reducing

bacteria (SRB) in injection water.

▪ Corrosion leads to the formation of iron sulfides,

which tend to be protective if homogeneous

– Different types of iron sulfide surface layers

may form depending on temperature.

– Localized corrosion has been recently been

related to the presence of pyrite.

▪ Elemental sulfur increases dramatically corrosion

rates.

– precipitation from gases containing high H2S

concentrations

– oxidation of H2S by air or oxides

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NACE MR0175/ISO 15156 SSC zones for carbon steel

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Preferential Weld Corrosion (PWC)

▪ Selective corrosion around weld joints

– Weld Metal, Heat Affected Zone, or Base Metal

– Can be up to 12 mm/y

▪ Galvanic corrosion among different regions of a weld

due to differences in composition and microstructure

– WM and HAZ may be anodic to the BM

– Inhibitors may adsorb preferentially on WM or BM

▪ Galvanic corrosion is not the only consideration

– WM with 1% Ni (cathodic to BM) have been reported

to display PWC due to a high rate of self-corrosion

▪ Corrosion inhibitors need to be evaluated

– PWC promoted by under-dosing of inhibitor

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Effect of Sand on Corrosion

▪ Affect corrosion inhibitor efficiency by adsorption loss

▪ At low velocities, accumulates and induces under-deposit corrosion

▪ At high velocities, induces erosion or corrosion-erosion

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Source: DNV RP O501-2014. Managing Sand Production and Erosion

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Corrosion-Erosion

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▪ Process combining electrochemical and

mechanical removal of pipe metal by impinging

liquid or solid particles in a corrosive environment

▪ Often found in areas of flow disruption or

acceleration, i.e., elbows, fittings, diameter

changes, etc.

▪ These locations can create areas of increased

turbulence, flow velocity, and/or increased angle

of particle impingement

▪ May have a sandblasted appearance

▪ Synergistic effect where protective films are

removed

▪ Several models available to predict erosion (e.g.,

Tulsa SPPS, DNV RP-O501-2015 )

▪ NACE TG 245 is developing a Recommended

Practice for O&G production

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UDC Mechanism - Scenarios

▪ Corrosion under or around deposits may be significantly

higher than on bare steel

▪ Scenarios

– No local separation of anode and cathode

– Changes in the local chemistry under deposit induce

higher uniform corrosion rate, compared to the

uncovered metal

– Separation of anodes and cathodes beneath the deposit

only (no external cathode)

– Anode/cathode separation developing from small

differences in local chemistry under the deposit and

inducing localized corrosion

– Internal anode (beneath deposit) coupled to a dominant

external cathode (uncovered metal)

– Localized corrosion, starting in areas close to deposit

edges

– Requires ionic path between anode and cathode

24 October 2018

Source: J. Vera, D. Daniels, M. H. Achour. Under Deposit Corrosion (UDC) in the Oil and Gas Industry: A Review of Mechanisms, Testing and Mitigation. NACE International CORROSION/2012. Paper C2012-0001379. 2012

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Microbiologically Influenced corrosion (MIC)

▪ Localized corrosion or pitting occurring under biofilm.

▪ Important to monitor Sessile Microorganisms (e.g., NACE TM0194) since

Monitoring Planktonic Microorganisms alone may be misleading.

▪ Sulfate reducing bacteria (SRB) thrive in anaerobic conditions

– SRB biofilms generate H2S, which can precipitate as iron sulfide.

– Iron sulphides are cathodic to bare steel, increasing corrosion rate.

▪ Aerobic bacteria can also induce corrosion

▪ Highest corrosion rates

– Stagnant or low flow

– pH 5 – 9.5

– Temperature 40-113F

– 5-10 mm/y

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Top of the Line Corrosion (TOL)

▪ TOL refers to corrosion occurring when

water condenses in the upper part of

the pipe, not covered by liquids

▪ Condensing water is unbuffered and

may have much lower pH that the

brine, but often becomes saturated

with corrosion products.

▪ Corrosion rates depend on water

condensation rates, CO2 partial

pressure and presence of acetic acid in

the gas.

Stratified Liquid

(water, oil, inhibitor)

Water Saturated Gas

(CO2, H2S, HAc)

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Effect of Oxygen

▪ Hydrocarbon producing and processing facilities are

usually designed assuming no oxygen is present

▪ Oxygen ingress may change corrosion mechanism,

increase corrosion rates and decrease efficiency of

most oilfield corrosion inhibitors

– In sweet systems, induces localized corrosion

– In sour systems, produces elemental sulfur

▪ Oxygen ingress can be monitored on-line using

galvanic probes.

▪ Analyses of corrosion products (e.g., XRD) can be

used to confirmed oxygen corrosion, as Fe(III)

oxides are usually present

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Corrosion-Fatigue

▪ Combined action of an alternating or cycling stresses and a corrosive

environment

▪ Reduction in the fatigue limit (or fatigue life at a given stress), compared to air

▪ Increase in the Fatigue Crack Growth Rate (FCGR) compared to air

▪ Corrosion inhibitors are not necessarily beneficial

Reference: W. Yu, J. Bowman, A. Batra, R. Thodla, C. Holtam, B. Gerst. “Effect of Sour Acidizing Treatments on the Fatigue Crack Growth and Fracture Toughness Behavior of C-Mn Line Pipe Steels” Paper OMAE2016-54388. ASME 2016.

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Modeling Corrosion Threats

▪ NACE TG 076 report describes more than 20

models available to predict corrosion rates of

carbon steel (some also include CRAs) in

oilfield fluids.

▪ NACE TG 447 report describes steps to select

an appropriate model for ICDA.

▪ Some models are mechanistic and others are

based on empirical correlations

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Source: NACE Technical Report 21413 (TG 076) “Prediction of Environmental Aggressiveness in Oilfield Systems from System Conditions” (2016)NACE Technical Report 21410 (TG 447) “Selection of Pipeline Flow and Internal Corrosion Models” (2015)

▪ Most predictive models were developed to estimate CO2 corrosion rates but

caution is recommended mainly when H2S or crude oil is present or at conditions

where protective iron carbonate films form.

▪ Several models have been published in the last decade to quantify the likelihood

of MIC but only two predict corrosion rates.

▪ DNV GL utilizes an Bayesian network approach to combine results from different

models and threats to give a probability of internal corrosion along a pipeline.

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Modeling Corrosion Threats ExampleMechanistic CO2 Corrosion Model

▪ CO2 models can be broadly divided

into two classes

– semi-empirical and empirical

– electrochemical/mechanistic

models

▪ Electrochemical/mechanistic models

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Source: S. Hernandez, Z. Zhang, J.R. Vera, and R. Woollam. Development and Implementation of a new Mechanistic Corrosion Model for Oil and Gas Production. NACE International CORROSION/2010. Paper 10364. 2010

– Predict polarization curves

– Includes the following processes

– Heterogeneous chemical reactions, including precipitation of surface films

– Electrochemical reactions at the steel surface

– Transport of species to and from the bulk

– Provide a detailed understanding of the contributions of each step in the CO2

corrosion process to the overall corrosion rate

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Multiphysics Modeling of Corrosion Inhibitors

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Source: C.D. Taylor, A. Chandra, J. Vera, N. Sridhar. A Multiphysics Perspective on Mechanistic Models for Chemical Corrosion Inhibitor Performance. J. Electrochem. Soc. 2015 162(7): C369-C375

▪ Bayesian networks for integrating across

multiple cause/effect relations

▪ Integrate findings from laboratory, field and

fundamental multiphysics models: e.g.

– Fluoroescence, CMC

– Adsorption isotherms, QCMB

– Partition coefficients, Log P

– Electrochemical testing, Rp and EIS

– Acidity constants, pKa

▪ Mechanistic modeling of corrosion inhibition

▪ Multiphysics modeling by integrating:

– Environmental Effects

– Speciation and Micellization

– Interfacial Chemistry

– Material Microstructure

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Internal Corrosion Mitigation Options

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Internal corrosion mitigation alternatives

▪ Process control

– Flow rates

– Dead-leg management

– Dehydration

▪ Materials Selection

– Carbon Steel/Low Alloy + Corrosion Allowance

– Corrosion Resistant Alloys (full body or cladding)

– Non-metallic materials (FRP, Flexible Risers)

– Carbon Steel with Internal Coating

▪ Chemical Treatment

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24 October 2018

Materials Selection/Qualification

▪ Inhibited carbon steel or CRA?

– MSS, DSS, SS, Ni, Ti, Al

▪ Localized corrosion, corrosion

fatigue, SCC, SSC, HE

0.1 1 1010

100X60 Weld

X80 Weld

X70 Weld

X65 reeled

FC

GR

en

v/F

CG

Ra

ir

CH (ppm)

Equation y = a + b*x

Adj. R-Square 0.94134

Value Standard Error

Increase in FCGR Intercept 7.37171 7.87589

Increase in FCGR Slope 56.05479 6.94253

Equation used to estimate diffusible

H concentration

[H]ppm

= 3.1+0.56log(pH2S

) - 0.17pH

Based on Hara & Asahi, NACE99

All samples are weld centerline

X65 reeled

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Flexible Risers and Pipelines

▪ Main components are thermoplastic barriers and

steel armor wires

▪ Armor wires provide structural support required to

contain the fluid in the bore and support axial,

bending and torsion loads.

▪ Corrosion of the armor wires occurs due to the

presence of

– Corrosive gases (e.g., CO2, H2S) that permeate

from the bore through the polymer, and

– Seawater (from the exterior) or condensed water

(form vapor permeated from the bore)

▪ DNV GL launched a JIP to predict flexible Riser

annulus environment, needed to assess wires

susceptibility to stress corrosion cracking and

corrosion fatigue

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Carbon Steel + Chemical Treatment

▪ First choice for most applications

– Lowest cost

– Many projects are not economically feasible otherwise

– Readily available in most product forms and high strength grades

– Good weldability

▪ Chemical treatment, maintenance and inspection program usually required to

maintain integrity

▪ Corrosion Allowance (CA) can be calculated based on the design life and expected

corrosion rates considering

– Corrosion rates may change significantly with time

– Inhibitor efficiency and availability

– Other alternatives if calculated CA is too high (e.g., > 8 mm)

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InhibitorsFactors to consider

▪ Specificity

– Metal

– Environment

– Temperature

– Concentration range

▪ Possible localized corrosion

▪ Compatibility with other chemicals

▪ Selection

– Empirical

–Multiphysics modeling

▪ Evaluation and qualification

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Monitoring Effectiveness of Internal Corrosion Measures

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Monitoring Effectiveness of Chemical Treatment

▪ Monitoring Inhibitor Availability (for continuous injection)

– Actual inhibitor dosage vs. target

– Inhibitor injection downtime

▪ Corrosion monitoring techniques

– Direct: Measures a parameter directly changed by corrosion

– Intrusive

– Non-Intrusive

– Indirect: Measures a parameter that influences or is influenced by corrosion

– Online

– Offline

▪ Technique needs to be selected to measure changes in parameters

– related to the corrosion threats that are being mitigated

– to allow remedial actions to be taken before significant damage occurs

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Source: NACE Technical Report 3T199 (TG 390) “Techniques for Monitoring Corrosion and Related Parameters in Field Applications” 2012 Edition

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Corrosion monitoringDirect Techniques

Source: NACE Technical Report 3T199 (TG 390) “Techniques for Monitoring Corrosion and Related Parameters in Field Applications” 2012 Edition

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Corrosion monitoringIndirect Online Techniques

Source: NACE Technical Report 3T199 (TG 390) “Techniques for Monitoring Corrosion and Related Parameters in Field Applications” 2012 Edition

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Corrosion monitoringIndirect Offline Techniques

Source: NACE Technical Report 3T199 (TG 390) “Techniques for Monitoring Corrosion and Related Parameters in Field Applications” 2012 Edition

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Summary

▪ Internal corrosion is one of the main causes of incidents and loss of service life in

subsea pipelines and risers

▪ A CMS is required to manage the threat of corrosion in existing and future assets,

which includes

– Assessment of internal corrosion threats, due to presence of water and

– Corrosive gases (CO2, H2S, O2)

– Sand

– Bacteria

– Different materials in welds or joints

– Implementation of mitigation measures

– Process control

– Materials selection

– Chemical Treatment

– Monitoring and review program

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SAFER, SMARTER, GREENER

www.dnvgl.com

Thanks for Your Attention

Questions?

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Jose Rafael Vera

[email protected]

+ 1 281 396 1743