20100211 dettman napacid corrosivity

11

THE INFLUENCE OF NAPHTHENIC ACID AND SULFUR COMPOUND STRUCTURE ON GLOBAL

CRUDE CORROSIVITY UNDER VACUUM DISTILLATION CONDITIONS

Heather D. Dettman, N. Li and D. Wickramasinghe (NRCan)J. Luo (U. of Alberta)

Presented to: COQA/CCQTA Joint MeetingNew Orleans, LAFebruary 10 – 11, 2010

2

Mechanisms of Refinery Corrosion

Refinery corrosion occurs at temperatures between 220°C and 400°C Naphthenic (organic) acids (RCOOH) reach their

boiling points and condense on metal surfaces, removing iron [Fe] and eventually causing pits

Sulfur-containing compounds decompose to form hydrogen sulfide (H2S), where iron removal causes general corrosion but can form protective films

Acids and hydrogen sulfide work together:Fe + 2RCOOH → Fe(RCOO)2 (oil soluble) + H2

Fe + H2S → FeS (oil insoluble) + H2

Fe(RCOO)2 + H2S → FeS + 2RCOOH

3

Corrosivity, TAN, and Sulfur

Corrosivity does not always correlate with total acid number (TAN) (Derungs, 1956; Messer 2004) Are organic acid molecular species in some oils “less

active” that those in other oils? Does high sulfide content result in iron sulfide film that

protects the plant metallurgy? Another reason?

This project was conducted to improve the understanding of the contributions of specific structural features of organic acids and sulfur compounds to corrosivity at refinery temperatures

44

Corrosion Test Unit

Features:1. Volume: 250 mL2. Charge: Any crude or

refinery feed blend3. No. of coupons: 44. Operates under

vacuum throughout the temperature range

Simulates corrosion in vacuum distillation unit

Coupon location in liquid

Coupon locations in vapor phase where vapor condenses on metal surface

55

When Does TAN Correlate with Corrosivity?

TAN correlates with corrosivity when different concentrations of the same acids are tested. (Corrosion rates of carbon steel coupons for commercial naphthenic acids [CMNA] in white oil.)

0

1

2

3

4

5

6

7

8

9

10

0 1 2 3 4 5 6

TAN (mg KOH/g)

Cor

rosi

on R

ate

(mm

/y)

Liquid - 300 C Vapor -300 C Liquid - 330 C Vapor -330 CLiquid - 350 C Vapor -350 C

6

When comparing corrosion rates for different crude oils.......?

0.00.20.40.60.81.01.21.41.61.8

CMNA ATHB SA1 SA2 AB16 AB17 INT22 INT30

Oil

Cor

rosi

on R

ate

(mm

/y)

Liquid Phase Vapor Phase

TAN 3.00 3.39 0.60 3.22 1.36 1.31 2.33 4.15S (wt%) 0.00 4.77 0.94 3.76 3.85 2.51 0.78 0.10

As Produced Commercial Products

When Does TAN NOT Correlate with Corrosivity?

7

Corrosivity of Organic Acid Compounds

Liquid Phase Vapor PhaseLiquid Phase Vapor Phase

Corrosion rates of carbon steel coupons for organic acid compounds in white oil (TAN= 5.0mg KOH/g) at atmospheric equivalent temperature (AET) of 300°C (250°C actual)

88

Sulfur compounds R-S-R H2S + by-products

FeS

Model sulfur compounds were chosen to represent the different C-S bonds found in petroleum. For example:

Thermal decomposition studies of nine sulfur compounds dissolved in white oil (1 wt% sulfur) were performed

DibenzothiopheneS

Octyl sulfide

R C S C R

H

H

H

H

What about Sulfur?

Thermal CrackingSulfidic Corrosion

9

Thermolysis of Sulfur Compounds

At temperatures as low as 200°C (392°F), within 2 hours -CH2-S- bonds (sulfides) crack and form H2S

0

10

20

30

40

50

60

70

200 220 240 260 280 300 320 340 360 380 400

Temperature (℃)

H2S

Yie

ld (w

t% F

eed

Sulfu

r)

Dicyclohexyl disulfide Dibenzothiophene Sec-butyl disulfideBenzyl sulfide 1,3-Dithiane Diphenyl sulfideBenzyl phenyl sulfide Dodecyl sulfide Octyl sulfide

S

S

SS

S

S

s

s

400°C

0

10

20

30

40

50

60

70

200 220 240 260 280 300 320 340 360 380 400

Temperature (℃)

H2S

Yie

ld (w

t% F

eed

Sulfu

r)

Dicyclohexyl disulfide Dibenzothiophene Sec-butyl disulfideBenzyl sulfide 1,3-Dithiane Diphenyl sulfideBenzyl phenyl sulfide Dodecyl sulfide Octyl sulfide

S

S

SS

S

S

s

s

400°C

10H2S Effects on Corrosivity of Organic Acids under Refinery Conditions

Influence of presence (1wt% S) or absence of sulfur compounds on the corrosion rates of commercial naphthenic acids (CMNA) in white oil (Total acid number = 5.0mg KOH/g) for carbon steel coupons at atmospheric equivalent temperature of 300°C (250°C actual)

0123456789

Oct y l Sul f i de+CMNA Di phenyl Sul f i de+CMNA CMNA

Corro

sion

Rate

(mm

/y)

i n Li q i n CondLiquid Vapor Phase

Cor

rosi

on R

ate

(mm

/y)

CMNA in white oil + octyl sulfide CMNA in white oil + phenyl sulfide CMNA in white oil

Fe + H2S → FeS + H2High H2S generation

Inhibited corrosion in liquidphase due to significant

film formation

Fe(RCOO)2 + H2S → FeS + 2RCOOHLow H2S generation

Enhanced corrosion in vapor phasewith little film formation

Fe + 2RCOOH → Fe(RCOO)2 + H2No H2S present

11

Why Does TAN Not Correlate with Corrosivity?Model compound studies show that: Small organic acid molecules (boiling point <

300°C) are significantly more corrosive than larger molecules (boiling point > 300°C) In liquid phase, chain and 1-ring acids are the most

corrosive; in vapor phase, chain and 1-ring cycloalkane(naphthenic) acids are most corrosive

Vapor phase corrosion due to organic acids is greatest at temperatures above the boiling point of the acid

Sulfur compounds can decompose to form hydrogen sulfide at temperatures as low as 200°C; acid corrosion can be inhibited or enhanced depending on how much hydrogen sulfide is present

12

Crude Oil Analyses

C H N S OATHB 83.07 10.51 0.52 4.77 1.14 1.0100 3.39SA1 86.77 10.64 0.60 0.94 1.05 0.9934 0.60SA2 83.67 10.31 0.83 3.76 1.43 1.0090 3.22

AB16 81.89 12.66 0.44 3.85 1.16 0.9304 1.04AB17 84.75 11.70 0.25 2.51 0.79 0.9319 1.27INT22 86.34 11.77 0.34 0.78 0.76 0.9379 2.11INT30 86.10 12.29 0.32 0.10 1.19 0.9282 4.15

Density (g/mL)

TAN (mg KOH/g)

ElementalCrude Oil

As produced:ATHB Athabasca bitumenSA South AmericaCommercial products:AB Alberta heavy oil or bitumenINT Non-Canadian crude of non-disclosed

geographical location* Crudes were topped at 204°C for corrosion testing

***

(wt%)

13

HTSD of Crudes

High temperature simulated distillation (HTSD) of:A – Crudes, as producedB – Crudes, commercial products

-100

0

100

200

300

400

500

600

700

800

0 20 40 60 80 100

Weight % Off

Tem

pera

ture

(C)

ATHB SA1 SA2

A

-100

0

100

200

300

400

500

600

700

800

0 20 40 60 80 100

Weight % Off

Tem

pera

ture

(C)

AB16 AB17 INT22 INT30

B

14

Analyses of Extracted Organic Acids

C H N S OCMNA - 74.35 11.97 0.00 0.00 13.68ATHB-OA 2.68 78.06 10.29 0.37 3.75 7.54SA1-OA 0.99 81.18 9.97 0.44 0.99 7.42SA2-OA 2.22 78.14 10.48 0.82 3.54 7.02

AB16-OA 1.11 78.80 10.15 0.57 3.72 6.76AB17-OA 1.43 77.96 10.06 0.58 4.75 6.64INT22-OA 2.37 81.48 10.98 0.36 0.90 6.29INT30-OA 4.83 81.09 11.66 0.34 0.27 6.64

Organic Acids

Content in Crude (wt%)

Elemental

CMNA Commercial naphthenic acids

Organic Acids Extracted from Crude Oils (Mediaas et.al., 2003)As produced: Commercial products:ATHB Athabasca bitumen AB Alberta heavy oil or bitumenSA South America INT Non-Canadian crude of non-

disclosed geographical location

(wt%)

15

Crude Oil TAN versus Organic Acid Yield

0.00

1.00

2.00

3.00

4.00

5.00

6.00

0.00 1.00 2.00 3.00 4.00 5.00 6.00

Yield (wt% Crude)

TAN

(mg

KO

H/g

)

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Distillation of Organic Acids from Crudes

Organic acids from:A – CMNA and crudes, as producedB – Crudes, commercial products

-100

0

100

200

300

400

500

600

700

800

0 20 40 60 80 100

Weight % Off

Tem

pera

ture

(C)

CMNA ATHB-OA SA1-OA SA2-OA

A

0

100

200

300

400

500

600

700

800

0 20 40 60 80 100

Weight % Off

Tem

pera

ture

(C)

AB16-OA AB17-OA INT22-OA INT30-OA

B

bp<300°C“most corrosive”

17

Corrosivity Results – CMNA & Crude Oils

0.00.20.40.60.81.01.21.41.61.8


Oil

Cor

rosi

on R

ate

(mm

/y)


TAN 3.00 3.39 0.60 3.22 1.36 1.31 2.33 4.15S (wt%) 0.00 4.77 0.94 3.76 3.85 2.51 0.78 0.10


Corrosion rates of carbon steel coupons for CMNA in white oil and crude oils at AET of 300°C (250°C actual)

Corrosivity does not correlate with TAN

18


0.00.20.40.60.81.01.21.41.61.8


Oil

Cor

rosi

on R

ate

(mm

/y)


TAN 3.00 3.39 0.60 3.22 1.36 1.31 2.33 4.15S (wt%) 0.00 4.77 0.94 3.76 3.85 2.51 0.78 0.10



Higher corrosivity of CMNA is explained by its higher content of lower boiling acid components (i.e. 50wt% have bp<300°C)

19



0.00.20.40.60.81.01.21.41.61.8


Oil

Cor

rosi

on R

ate

(mm

/y)


TAN 3.00 3.39 0.60 3.22 1.36 1.31 2.33 4.15S (wt%) 0.00 4.77 0.94 3.76 3.85 2.51 0.78 0.10


Boiling point distributions of organic acids in these crudes do not explain why SA2 and INT30 have higher liquid phase corrosivity than the other crudes; higher contents of chain &/or 1-ring naphthenic acids in lowest boiling species are implicated

20


0.00.20.40.60.81.01.21.41.61.8


Oil

Cor

rosi

on R

ate

(mm

/y)


TAN 3.00 3.39 0.60 3.22 1.36 1.31 2.33 4.15S (wt%) 0.00 4.77 0.94 3.76 3.85 2.51 0.78 0.10



Boiling point distributions of organic acids in these crudes do not explain why AB16 has high vapor phase corrosivity

21Identification of Sulfidic Corrosion Influences in Crude Oils

Replace the oil matrix with a sulfur-free medium i.e. white oil Organic acids isolated from each of the Global

crudes were dissolved in white oil at TAN values similar or slightly lower than those of the original crude oils tested

If the oil matrix has no influence on corrosion, the corrosion rates of the white oil mixtures should be the same as that of the original oil

If the oil matrix influences corrosion, the corrosion rates of the white oil mixtures could be either greater or lesser than those of the original oil

22

0.00.20.40.60.81.01.21.41.61.8

CMNA ATHB-OA

SA1-OA

SA2-OA

AB16-OA

AB17-OA

INT22-OA

INT30-OA

Extracted Organic Acids in White Oil

Cor

rosi

on R

ate

(mm

/y)


Corrosivity Results – Extracted Acids

Corrosion rates of carbon steel coupons for CMNA and extracted organic acids in white oil at AET of 300°C (250°C actual)

23

-1.4-1.2-1.0-0.8-0.6-0.4-0.20.00.20.40.6


Difference (Organic Acids in White Oil - Oil)

Cor

rosi

on R

ate

(mm

/y)


TAN 3.00 3.39 0.60 3.22 1.36 1.31 2.33 4.15S (wt%) 0.00 4.77 0.94 3.76 3.85 2.51 0.78 0.10


Differences in Corrosivity Results

24

-1.4-1.2-1.0-0.8-0.6-0.4-0.20.00.20.40.6



Cor

rosi

on R

ate

(mm

/y)


TAN 3.00 3.39 0.60 3.22 1.36 1.31 2.33 4.15S (wt%) 0.00 4.77 0.94 3.76 3.85 2.51 0.78 0.10



Negative difference for AB16 vapor phase corrosion rate shows that sulfidic corrosion is the predominant corrosion mechanism

25

-1.4-1.2-1.0-0.8-0.6-0.4-0.20.00.20.40.6



Cor

rosi

on R

ate

(mm

/y)


TAN 3.00 3.39 0.60 3.22 1.36 1.31 2.33 4.15S (wt%) 0.00 4.77 0.94 3.76 3.85 2.51 0.78 0.10



Positive differences for corrosion rates suggest sulfidic film formation provides protection for original crudes; protection does not correlate with sulfur content.

26

-1.4-1.2-1.0-0.8-0.6-0.4-0.20.00.20.40.6



Cor

rosi

on R

ate

(mm

/y)


TAN 3.00 3.39 0.60 3.22 1.36 1.31 2.33 4.15S (wt%) 0.00 4.77 0.94 3.76 3.85 2.51 0.78 0.10



Positive differences for vapor phase corrosion rates for SA1, SA2 and INT30 also indicate higher contents of chain &/or 1-ring naphthenic acids in lowest boiling species of these crudes compared to those of Alberta and INT22 crudes

27

CONCLUSIONS

TAN values of crude oils are not reliable indicators of crude oil corrosivity

Crude corrosivity appears to be determined by: Low boiling acids (i.e. bp<350°C) where content of

chain and/or 1-ring naphthenic acids will be important

Content of thermally-labile sulfur species Hydrogen sulfide-generating ability of the crude

will be influenced by: Content of CH2-S bonds in sulfur species Thermal history of crude oil (field and plant)

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IMPLICATIONS OF RESULTS If TAN does not correlate with crude

corrosivity, why is it used for setting crude prices?

How does production method influence corrosivity (i.e. SAGD versus mined?) How does the content of low-boiling chain and 1-

ring naphthenic acids compared to the total organic acid content, and the contents of thermally-labile sulfur species work together to influence corrosivity

When can blending a high TAN crude with a low sulfur, low TAN crude (or diluent?) result in enhanced corrosion?

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Funding Acknowledgements

Alberta Science and Research Authority (COURSE/Alberta Energy Research Institute [AERI])

Canadian Association of Petroleum Producers (CAPP)

Natural Resources Canada through partial funding by the Canadian Program for Energy Research and Development, and the Technology and Innovation Program

20100211 dettman napacid corrosivity

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