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Assessing and Predicting the Corrosive Impact of Opportunity Crudes 3rd Opportunity Crudes Conference in Houston, TX (USA) May 6-8, 2012 Brian Chambers1 Sridhar Srinivasan1 Russell Kane2 1Honeywell

Corrosion Solutions Houston, Texas USA 2iCorrosion, LLC Houston, Texas USA


Overview  Acknowledgement  Problem Statement - Corrosion of non-stainless alloys in low to moderate flow conditions - Influence of sulfidic and naphthenic acid species - Lack of accurate predictive tools  Testing Methodologies  Prediction Model and Software Tool  Summary

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Acknowledgment  The experimental methodology and prediction model described herein was primarily developed in a Joint Industry Program (JIP)  Honeywell recognizes those participants of the JIP  Baker Petrolite  BP  Chevron  ExxonMobil  Flint Hills Resources  Fluor  Idemitsu  IOCL  Lyondell

 Marathon  Nalco  Petrobras  Petronas  Reliance  Shell  Statoil  Syncrude  UOP 3


Introduction to Crude Corrosivity  Corrosion in hot oil distillation circuits and associated piping is a major safety and cost concern for modern refineries  Corrosion tendency increases with feedstock impurities - ‘Opportunity’ crude refining can lead to greater corrosion risk  Crude corrosivity refers to non-aqueous corrosion that occurs in and around crude oil distillation units and piping  Crude corrosivity primarily controlled by two mechanisms - Naphthenic acid corrosion - Sulfidic corrosion

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Introduction – Previously Available Predictions  Historically, only limited data has been available for making alloy selections and planning inspection schedules  Many refineries or refining companies have experience with predicting hot oil corrosion - Often experiential-based notions that may not transfer to different crude oil processing

 API RP 581 Base Resource Document for RBI provides guidelines for assessing corrosivity and operational risk - Substantial conservatism and in some cases apparent errors - Thus, not accurate for use in materials selection

Need better definition of boundaries between corrosive and non-corrosive service conditions over a broader range of refinery process conditions.

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Critical Parameters in Crude Corrosivity  To understand and predict hot oil corrosion, must understand the critical factors and their effects  Critical parameters in crude corrosivity include: - Process temperature  400 to 750 F range relevant for mechanisms  Corrosion rates tend to increase with higher temperature

- Vapor / Liquid Phase Behavior  Liquid full flow vs. condensing fluids  Side-cut piping typically liquid full flow

- Velocity (and Wall Shear Stress (WSS)) of flowing media  Fluid properties, pipe configuration and roughness, flow regime  Side-cut piping typically in range of 5 to 100 Pa WSS

- Naphthenic acid content and characteristics - Nature and concentration of sulfur compounds - Materials of construction 6


Critical Parameters – Naphthenic Acids  Naphthenic acid corrosion heavily dependent on both the contents and characteristics of the acids present  Naphthenic acids – organic acids - By chemical definition – limited to cycloaliphatic ring acids - By refining reference – all organic acids with relevant thermal stability at distillation temperatures and aggressivity leading to possible corrosion

 Characteristics of naphthenic acids important - Acids with lower molecular weight (MW) generally more corrosive - Acids with more simplistic ring structure generally more corrosive - Type ‘A’, or α, acid refers to MW in 125 to 425 atomic unit (au) range with boiling point less than 725 F (aggressive acids) - Type ‘B’, or β, acid refers to MW in 325 to 900 au range with boiling point exceeding 675 F (significantly less aggressive than Type ‘A’)

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Critical Parameters – Sulfur Compounds  Sulfidic corrosion also heavily dependent on both the contents and characteristics of the compounds present

ACTIVITY

 Sulfur compounds fall into different classes - Mercaptans - Sulfides - Thiophenes

ACTIVITY

RSH

RSR

THERMAL STABILITY

 Characteristics of sulfur compounds important - Simpler compound types (mercaptans) more prone to thermal

instability and reactivity (or corrosive activity) with alloys, but behavior is a function of process temperatures 8


Naphthenic Acid and Sulfidic Corrosion  Naphthenic acid corrosion generally considered more aggressive than sulfidic corrosion and less well understood - Naphthenic acids result in soluble corrosion products  Iron-naphthenates from alloy corrosion  Dissolution of sulfide scales  Very high corrosion rates

 Sulfidic corrosion well established issue in refineries - Sulfidic corrosion results in sulfide scales or sulfo-spinels  Slower corrosion over time significantly as scales act as barriers to corrosion  Scales can be prone to dissolution or cracking from acid attack and WSS

 Complex interaction between naphthenic acid and sulfidic - Sulfur-containing compounds can inhibit naphthenic acid corrosion - Not enough reactive sulfur to counteract naphthenic acid corrosion - Amplified corrosion from both mechanisms in certain cases  For example, cases with high WSS

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Materials of Construction  Materials selected based on refinery use - High velocity areas or areas with condensing corrosion  Austenitic stainless steels or Ni-based alloys

- Side-cut piping  Carbon steels, alloy steels, or austenitic stainless steels

 For JIP study, the following steels were primarily evaluated: - C1018 carbon steel (UNS G10180) - 5Cr / 0.5Mo low alloy steel (UNS K41545) - 9Cr / 1Mo alloy steel (UNS K90941) - 12Cr stainless steel (UNS S41000) - 18Cr stainless steel (UNS S30403)  Other stainless steels also assessed in limited conditions - 316L (UNS S31603), 317L (UNS S31703), and 904L (UNS N08904) 10


Prediction Model Development  A prediction model was developed based on laboratory evaluations of crude corrosivity under simulated service conditions - Empirical model based on laboratory corrosion data and trends - Experiments assessed corrosion rates of multiple alloys in:  ‘synthetic oil fractions’  Data benchmarked using sponsor-supplied oil fractions

- Critical factors were varied to create an extensive matrix of results

 An extensive test program developed the test methodology and conducted experiments evaluating hundreds of simulated process conditions 11


Test Methodology  Simulation of refinery variables relevant to side-cut piping - Acid type and concentration - Sulfur compound type and concentration - Applied wall shear stress (WSS) - Temperature  Simulations implemented by: - Synthetic oil fractions or provided refinery oil fractions - Synthetic oil fractions included addition of acids and sulfur - Equipment to contain and control the test parameters  Stirring to increase WSS on coupon surfaces  Heating to control temperature of the oil fractions

 Brief introduction to test procedures presented herein

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Synthetic Oil Fractions  Synthetic oil fractions were utilized primarily in the JIP  A ‘white oil’, Process 1200 was utilized as the base oil - Hydrotreated oil with low acid and low sulfur content - Typical analysis for acid and sulfur content Name

TAN (mg KOH/g)

Total Sulfur (wt%)

Mercaptans (ppm)

Process Oil 1200

0.14

0.12

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 Additions were made to synthetic oil fractions - Acids added to increase acid content for select acid types - Sulfur compounds were added to increase sulfur concentration - H2S gas introduced to increase ‘active’ sulfur concentration 13


Equipment Pop Valve

Magnedrive

Condenser

Outlet

Inlet

Splash Barrier

Temp Controller

Vortexless Stirrer 10 corrosion coupons

Outlet Sample container

To vacuum pump

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Equipment

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Naphthenic Acids for Synthetic Oil Fractions  For the bulk of the JIP testing, an aggressive acid relevant to typical refinery naphthenic acids was needed - Multiple commercial blends of naphthenic acids were evaluated  Chemical characteristics  Corrosivity

 Target aggressive acid (Type ‘A’) - Low molecular weight (MW) - High content of cyclic organic acid types - Thermal stability in the 450 to 700 F range  Low active sulfur content in that range

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Naphthenic Acids for Synthetic Oil Fractions Boiling Point Characteristics

Acid Name

TAN (mg KOH/g)

Total Sulfur (wt%)

Initial

50% Distilled

Final

Blend 1

253

0.047

447 F (231 C)

578 F (303 C)

826 F (441 C)

Blend 2

237

0.03

305 F (152 C)

559 F (293 C)

784 F (418 C)

Blend 3

252

0.026

305 F (152 C)

554 F (290 C)

792 F (422 C)

Blend 4

265

0.054

441 F (227 C)

580 F (304 C)

865 F (463 C)

Blend 5

210

0.167

403 F (206 C)

583 F (306 C)

831 F (444 C)

Blend 6

138

0.931

359 F (182 C)

1195 F (646 C)

Blend 7

83

1.61

622 F (328 C) Not determined

Acid Name

MW Range

MWn

StraightChain

Monocyclics

Dicyclics

Tricyclics

Tetracyclics

Pentacyclics

Other

Blend 1

110-365

221

29.46%

37.15%

23.25%

4.86%

2.39%

1.69%

1.20%

Blend 2

120-400

266

58.42%

21.34%

11.24%

2.76%

1.01%

0.50%

4.73%

Blend 3

134-406

272

67.29%

15.21%

7.24%

3.35%

1.17%

0.90%

4.85%

Blend 4

120-345

222

14.43%

42.35%

33.63%

5.82%

2.26%

1.05%

0.46%

Blend 5

119-392

228

28.40%

37.18%

23.07%

5.28%

2.63%

1.92%

1.51%

Blend 6

125-430

270

22.77%

25.69%

22.36%

13.28%

7.31%

4.66%

3.93%

Blend 7

119-459

291

19.45%

22.04%

22.31%

16.72%

9.20%

5.48%

4.48%

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Naphthenic Acids for Synthetic Oil Fractions

 Comparative corrosivity test at hightemperature conducted

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50 Blend 1

Corrosion Rate (mpy)

 Blends 1-4 selected for corrosivity test - High TAN - Low S

Comparison of Commercial Naphthenic Acids 24 Hour Test at 700 F, 1700 RPM

40 Blend 2

30

Blend 3

20

Blend 4

10

0 0

5

10

15

20

Alloy Content (% Cr)

 Blend 1 and Blend 4 acids were considered more desirable due to low straight-chain acid content (typical of oil fractions)  Blend 1 then selected for basis of predictive model due to higher corrosivity 18


Procedural Refinement - Crude Corrosivity Testing  Many oil-testing procedures were refined in the JIP  For naphthenic-acid dominated test types: - Minimum test duration of 48 hours was found to be needed  Transient effects in first 24 hours  lack of good reproducibility in results  Longer test durations tended to result in same corrosion rate findings

- Daily replenishment of test oil to avoid degradation of acids - Elevated pressure relief valve  Counteract acid degradation / distillation

 For sulfur-containing test types: - Daily replenishment of oil for acid content and active sulfur content - Longer test durations enhanced reproducibility of test results - Elevated pressure relief valve setting - Multistep purge and pressurization procedure when using H2S as active sulfur proxy

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Laboratory Experiments - Parameters  Over two hundred (200) total experiments conducted  Critical parameters were varied to develop a substantial matrix of results and data trends - Alloys (Carbon Steel, 5 Cr, 9 Cr, 12 Cr, 304L, 316L, 317L, 904L) - Temperature (450, 550, 600, 650, 700 F) - Wall shear stress (1 Pa up to 135 Pa) - Synthetic Corrosive Crude Oil Fractions:  Total Acid Number (TAN) manipulated using naphthenic acids and process

oil (TAN values of 1, 3, 5.5)  Naphthenic acid type manipulated using commercial naphthenic acid blends or reagent grade acids  Sulfur content simulated using hydrogen sulfide additions or mercaptan sulfur additions (primarily evaluating three (3) levels of active sulfur)

- Sponsor-supplied oil fractions  Verifying / adjusting results and data trends from ‘synthetic oil fraction’ tests 20


Prediction Model Development  Laboratory results were examined for data trends  Iso-corrosion curves developed from finalized data - Enable interpolation between empirical model data points  Iso-corrosion curves plotted on acid content vs. temperature - Several iso-corrosion curves for various active sulfur levels and different acids - Modified for effects of wall shear stress

 Example of the setup of iso-corrosion curve:

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Iso-corrosion Curve Example For a given acid type, active sulfur level: 6

Acid content (mg KOH / g)

5

4

3

2

1

0 450

500

550

600

650

700

Temperature (F) 22


Parameters Presently in API RP 581  Sulfur (wt%)  TAN (mg/g)  Temperature (F)  Velocity (ft/sec)  Alloy Grade

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Parameters Required for Predict-Crude User Input for Honeywell’s Predict-Crude:  Operating temperature

 Pipe ID  Pipe configuration

 Crude Fraction Type

- 3D – Bend - 90 deg. Elbow

 Naphthenic acid type

- Weld Protrusion (5 mm)

- Type A - Behenic acid

 Type of flow

- Horizontal or Vertical  Flow rate

 Active Sulfur Level

 Density  Viscosity

 Acid content (TAN / NAT) 24


Predict-Crude Software Input Screen

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Predict-Crude Software Output Screen

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Corrosion Predictions  For corrosivity assessment, whole crude assays cannot be used; not specific to hydrocarbon fractions where corrosives can concentrate.  Use crude assay information from ‘opportunity crudes’ to determine corrosivity of oil fractions in side-cut piping  Assess feasibility of processing crude or need for blending  Assist in updating inspection schedules and protocols

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Summary  Crude corrosivity from naphthenic acid corrosion and sulfidic corrosion continues to present problems in refinery operations  Processing of opportunity crudes may lead to breakdown of experiential rules of corrosivity for crude processing  Autoclave exposure testing was conducted to assess corrosion rates of several alloys exposed to crude fractions  Empirical prediction model and accompanying software (Predict-Crude) developed to assist refiners and engineers in planning for crude processing and corrosive impact

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3rd Opportunity Crudes Conference in Houston, TX (USA) May 6-8, 2012

Thank You

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Assessing and Predicting the Corrosive Impact of Opportunity Crudes