Outline

• NACE Conferences

– Northern Area Eastern Conference 2012

• Crude Oil Corrosivity

– Pipeline Operating Conditions

• NACE Proceedings, “Corrosivity of Crude Oil Under Pipeline

Operating Conditions”

– Refinery (High Temperature) Operating Conditions

– Domestic Fuel Tanks

• Summary

Easter

n Area

Central

Area

Western

Area

European

Area

Latin

American

Area

West Asia

& Africa

Area

East Asia

& Pacific

Rim Area

NACE

Members

NACE International

Board of

Directors

Northern

Area

Sections

NACE International - Structure

• NACE International – Serves nearly 30,000 members in 116 countries

– Organises annual conference every year with over 5,000 participants, among several other activities

• NACE Northern Area – Includes 9 sections and 2 student sections

– Serves nearly 3,000 members

– Organises two regional conferences every year • Northern Area Eastern Conference

– Halifax, Montreal, Ottawa, and Toronto (2012)

• Northern Area Western Conference – Calgary, Edmonton, Alaska, and Victoria (2013)

NACE Northern Area Eastern Conference,

Toronto, Ontario, Canada, Oct. 28-31, 2012

• Crude Oil Corrosivity

– 2 Keynote lectures

– 18 Presentations

• Pipeline operating conditions

• Refinery (High-temperature)

• Domestic fuel tank

– Panel discussion

– All presentations are available for conference participants on NACE webpage

• Proceedings

– 16 Papers

• 10 papers from the NAEC 2012

• 6 classical papers

– All papers peer-reviewed

Corrosivity vs Corrosion Conditions: The dilemma in

transporting “clean” hydrocarbon products

Trevor Place, Enbridge (Keynote address)

Fuels, lubricants LPG and other gases Petrochemicals

Consumers

Asphalt Products

Alberta Pipeline Example

• In Alberta, the majority of incident data

is from smaller lines and lines carrying

products other than refinery ready

crude

• It is not reasonable to expect all the

lessons from the upstream industry to

apply to transmission pipe

“Transmission” pipelines account

for less than 7% of Alberta pipe

Typical Water Microemulsion

EXPOSURE

CORROSIVE

MTLS

SUSCEPTIBL

E METAL

Water normally exists as a dispersed water-in-oil microemulsion, which is not corrosive. Corrosion occurs only when corrosive water or sediment accumulates on the pipe floor and persists for extended time.

Corrosion will not occur without contact between a corrosive material and a susceptible metal. Rather than focusing on corrosivity, it may be better to take aim on the factors that affect exposure.

Section 1: Location of

Corrosion

Solid Deposition Modeling for Heavy Oil Transmission

Pipelines

A. Runstedtler, CanmetENERGY

• NACE SP 0208, “Internal Corrosion Direct

Assessment Methodology for Liquid Petroleum

Pipelines” presents models to predict locations for

water accumulation

• Runstedtler analysed the light oil vs. heavy oil

transportation

250 meters long

48 inch diameter

* *

Oil Velocity Distribution

Light oil

Heavy oil

The flow speed near the wall is slower in heavy oil than in light oil. This effect

is magnified downstream of pipe over-bends because the momentum of the

flow carries it away from the pipe floor.

Section 2: Corrosion

Mechanisms

Corrosion Conditions in the Path of Bitumen from Well to Wheel S.Papavinasam, CanmetMATERIALS; P.Rahimi, CanmetENERGY; and S. Williamson, Ammonite

Corrosion Engineering Inc

Refining Production

Mining

In situ

Bitumen Upgrading

Conventional Oil Oil

Transmis

sion

Pipelines

Storage

Tanks

Product

Storage

Tanks

Product

Pipelines

Extraction,

Froth

Treatment,

Diluent addition

Tailing

plants

Sep

arat

ors

Images are from CAPP and NEB reports

Summary • Between the wheel and

well, the crude oil is exposed to various operating conditions.

• Oil transmission pipelines • Probability of corrosion is

low

• Water content (less than 0.5%)

• Flow rate (less than 3 m/s),

• Temperature (less than 50oC)

• Localized corrosion may occur if water is allowed to collect and pool.

50

100

150

200

250

300

350

400

450

1998 1999 2000 2001 2002 2003 2004 2005 2006

Years

Le

ng

th o

f P

ipe

lin

es

(10

00

s o

f k

m)

2

2.5

3

3.5

4

4.5

5

5.5

Fa

ilu

re R

ati

o p

er

1,0

00

km

Corrosivity of Dilbit and Conventional Crude Oil in

Transmission Pipelines J. Been* and J. Zhou, AITF

*Currently with TransCanada

• Concerns from Some Stakeholders 1. Dilbit contains 15 - 20 times higher corrosive acid concentrations

2. Dilbit contains 5 - 10 times more sulfur

3. Dilbit has a high concentration of chloride salts

4. Dilbit contains more abrasive sand particles, which can erode the pipelines

5. Dilbit can be up to 70 times more viscous, leading to higher temperatures

6. The Alberta pipeline system has had ~16 times as many spills, due to

internal corrosion, as the U.S. system

7. Dilbit pipelines have an increased risk of internal corrosion due to dilbit

sediment composition and characteristics

8. Chemical corrosion combined with physical abrasion can increase the rate

of dilbit pipeline deterioration

9. Dilbit pipelines operate at higher temperatures, which would significantly

increase the corrosion rate

10.Dilbit pipelines can have a higher incidence of external stress corrosion

cracking

Analysis of Concerns

1. TAN in dilbit overlaps with that of conventional crude and it does not lead to corrosion

at transmission pipeline temperatures.

2. Dilbit sulfur content overlaps with conventional crude. Organically bound sulfur is too

stable to be corrosive at transmission pipeline temperatures.

3. Dilbit has some of the lowest chloride concentrations and Cl-SCC is not a problem for

carbon steel.

4. Dilbit is comparable to conventional crude in sediment content. No evidence of erosion

has been observed in dilbit pipelines.

5. The viscosity of dilbit is comparable to conventional heavy crudes and must meet

pipeline specifications to be accepted for transportation.

6. When corrected for spill volumes and pipeline types, the number of transmission

pipeline failures in Alberta is comparable to the US (FEIS, 2011).

7. While there is insufficient information on the sediment composition in conventional

crude and dilbit, there is no evidence to suggest that there is an increased risk of

corrosion in dilbit pipelines.

8. Erosion-corrosion combination is improbable in dilbit transmission pipelines.

9. Dilbit transport will be within pipeline operating temperatures. Temperature increase

does not necessarily lead to an increase in corrosion rate.

10. Current practice is to build pipelines with FBE coatings. Experience to date has shown

that SCC is not likely on FBE coated pipelines.

Section 3: Evaluation of Crude

Oil Corrosivity

ASTM G205-10 Crude Corrosivity Testing for Crude Transmission

Pipelines

F. Hornsby, Cormetrics and T. Place, Enbridge

•Presented an

Overview of ASTM

G205

•Evaluated 3

Parameters:

– Emulsion Inversion

Point: Change to a

water external

emulsion

– Wettability:

Preference for oil or

water wetting to steel

– Corrosivity: Impact of

crude on brine

corrosion rate

Emulsion

W/O

O/W

No Corrosion

Wettability

Oil-Wet

Mixed-Wet

Water-Wet

No Corrosion

Corrosivity of

Brine in the

Presence of

Hydrocarbon

Preventive

Hydrocarbon

Inhibitive

Hydrocarbon

Neutral

Hydrocarbon

Corrosive

Hydrocarbon)

Reduced

Corrosion

Aqueous

Corrosion

Accelerated

Corrosion

No Corrosion

Test Results

0

0.5

1

1.5

2

2.5

0

10

20

30

40

50

60

70

80

90

0 5 10 15

TAN

(mg

KOH

/g)

EIP,

Cor

r Rat

e, W

etta

bilit

y

Crude Sample

G205 Results Sorted By Crude TAN

# OF PINS (wettability) EIP (% Crude) Corr. Rate (mpy) TAN (mg KOH/g)

Laboratory Tests Comparing the Corrosivity of Dilbit and Synbit

with Conventional Crudes Under Pipeline Conditions

D.R. McIntyre, M. Archour, M.E. Scribner, and P.K. Zimmerman,

ConocoPhillips

• At pipeline temperatures and specified water contents, neither

conventional crude, dilbit nor synbit cause significant corrosion.

• Corrosion rates remain low in simulated produced water due to slight

alkalinity and significant buffering capacity.

• Under flowing conditions, there were no significant differences in

corrosion rate between conventional oil, dilbit and synbit.

• Synbit and dilbit are indistinguishable with regard to corrosion rate.

• Tests showed no evidence of abrasion or erosion-corrosion.

• Tests showed no evidence of hydrogen-induced cracking.

• Tests showed no evidence of pitting.

• Dilbit is no more likely to drop out water than synbit or conventional.

• Claims that dilbit is “highly corrosive” “liquid sandpaper” are not

supported.

Putting These Results in Perspective

1 mil = 1/1000th inch = 0.025 mm

0

2

4

6

8

10

12

14

16

18

20

co

rro

sio

n r

ate

, m

ils p

er

year

Conv. Oil Dilbit Synbit Tap H2O Soft drink

Oil

Water

H2O/CO2/H2S

Flow @ 1.4m/s

Low

Moderate

High

1 mil = 1/1000 inch

0

2

4

6

8

10

12

14

16

18

20

co

rro

sio

n r

ate

, m

ils p

er

year

Conv. Oil Dilbit Synbit Tap H2O Soft drink

Oil

Water

H2O/CO2/H2S

Flow @ 1.4m/s

Low

Moderate

High

1 mil = 1/1000 inch

Comparison of Corrosivity of Crude Oils Using Rotating

Cage Method J. Collier, S. Papavinasam, J. Li, C. Shi, P. Liu and M. Podlesny, CanmetMATERIALS

• Studied the effect of crude oils on the corrosivity of brine using the atmospheric rotating cage method (ASTM G202, ASTM G205)

• All tested conventional and bitumen-derived crude oils classified as inhibitive hydrocarbons (ASTM G205)

– No difference between conventional and bitumen-derived crude oils

– Based on average corrosion rate in aqueous water phase (brine) in presence of crude oil

• Average corrosion rates significantly lower than for brine alone

– Brine + crude oil: 0.057 ± 0.093 to 2.1 ± 1.9 mpy

– Study control brine: 19 ± 2.8 mpy

– ASTM bench mark for brine: 23 ± 2 mpy

• Surface analysis indicated general corrosion but no significant pitting

– SEM and EDS

Corrosivity of Brine in the Presence of Crude Oils

0

5

10

15

20

25

30

783

*

816

*

847

*

883

*

915 920 921 921 931

*

943 954 957

*

961

*

972

*

977

*

5%

NaCl

ASTM

RR

Density (kg/m3)

Co

rro

sio

n R

ate

(m

py

)

Conventional

Bitumen-Derived

Brine

* Stored samples

Development of Laboratory and Pilot Scale Facilities for the Evaluation of

Sludge Corrosivity in Crude Oil Pipelines,

M. Mosher, B. Crozier, W. Mosher, J. Been, and H. Tsaprailis, ATIF; T. Place,

Enbridge; and M. Holm, GE

Test Section - 4” diameter

Auxiliary Lines - 2” diameter

Pump - 10 HP Gear Pump

Piggable Test Section

Temperature Controlled 15 – 60 C

Flow Rates > 150 GPM

MEA Probe

EFM & UT

1. Negligible corrosion rates (0.04 +/- 0.01 µm/yr) were observed during

laboratory testing of carbon steel exposed to diluted bitumen (oil wet

condition), while corrosion rates were aggressive (>1000 µm/yr) when

carbon steel was exposed to brine (water wet conditions). Water wet

conditions are necessary for corrosion to occur at pipeline

temperatures.

2. Laboratory testing of carbon steel covered with sludge deposits

collected from crude oil transmission pipelines had low corrosion rates

(3.4 - 18.9 µm/yr) despite having high water contents (~ 20 wt.%).

3. Pilot Scale Flow Loop tests have shown that bacterial-enriched sludge

deposits were unable to produce a corrosive under-deposit

environment. The instantaneous maximum corrosion rate was at 17

µm/yr.

4. More work needs to be conducted to identify the appropriate

conditions for an aggressive water wet environment under sludge

deposits.

Summary

• The relative corrosivities of 42 fluids transported in an oil

transmission pipeline were measured:

– 9 were condensates and 33 were classified as light,

medium, heavy, sweet or sour oils, including several

synthetic crudes.

• Immersion Test (Static Corrosion Test)

– 200-mL volume of fluid for 13 days, after which a 10-mL

sample was analyzed for iron content by ICP

spectroscopy.

• Electrochemical Measurements

– Potentiodynamic polarization using commercial

potentiostat.

Relative Corrosivity of Crude Oils from Oil

Transmission Pipelines

W. Friesen, S. Petrovic, J.C. Donini*, CanmetENERGY

and R.W. Revie, CanmetMATERIALS

Properties of Crude Oils: Acid Number &

Corrosion Rate

0.0 0.2 0.4 0.6 0.8 1.0

0.0

0.5

1.0

1.5

2.0

2.5

Co

rro

sio

n r

ate

(1

0-2 m

py)

32

35

38

Acid No. (mg KOH/g)

14

• The four fluids identified as

being the “most” corrosive do

not have correspondingly high

acid number

Heavy Sour

Diluted Bitumen

Heavy Sour

Diluted Bitumen

Heavy Sour

Conventional

Medium Blend

M. De Romero, A. J. De Turris, U of Zulia, Venezuela and S.

Papavinasam, CanmetMATERIALS

Effect of a Venezuelan crude oil on the

corrosion of carbon steel in a produced water

with SRB and CO2 by ASTM G205.

Test E: Presence of crude oil decreased both general and localized pitting corrosion of carbon

steel. The presence of crude oil reduced total mass loss determined in SPW with SRB and

CO2 by 26%.

Other researchers working with Venezuelan crude oil have obtained inhibiting effects between

35-52% for different crude oil, but without considering the effect of SRB.

Test

ID Condition

Mass Loss

(mg)

Standard

Deviation PT

(pits/mm2)

General

Corrosion

Rate (mpy)

Effect

(c/w

control)

Observations

A

SPW

(control for

B,C,D)

5.35 0.7 0 0.7 control GC

B SPW + CO2 15.2 1.2 0.7 2.1 284% Greater tendency to

undergo GC than LC

C SPW + SRB 10.7 1.4 2.6 1.5 199% Greater tendency to

undergo LC than GC.

D

SPW + SRB + CO2

(control for E) 23.9 0.9 3.5 3.2 447%

GC rate was higher

and deep pits formed

(48 µm in 4 days

172 mpy)

E SPW + SRB +

CO2 + Crude oil 17.6 1.1 1.2 2.4

74%

(26%)

GC rate was lower

and less pits formed

by an inhibitive

effect of the crude

Oil

Managing Internal Corrosion and Public Perception of Oil

Transmission Pipelines

S. Papavinasam, CanmetMATERIALS

• Managing Internal

Corrosion – No crude oil can sustain

corrosion under pipeline

operating conditions

• Absence of

conductive

electrolyte phase

– In the presence of water

and oil phases three

properties should be

evaluated

• Emulsion

• Wettability

• Change in corrosivity

of aqueous phase by

oil phase

Emulsion

W/O

O/W

No Corrosion

Wettability

Oil-Wet

Mixed-Wet

Water-Wet

No Corrosion

Corrosivity of

Brine in the

Presence of

Hydrocarbon

Preventive

Hydrocarbon

Inhibitive

Hydrocarbon

Neutral

Hydrocarbon

Corrosive

Hydrocarbon)

Reduced

Corrosion

Aqueous

Corrosion

Accelerated

Corrosion

No Corrosion

Public Perception Issues

• Lack of publically available data on crude oil corrosivity

• Make the information and data publically available (ASTM G205) – Emulsion inversion point

– Wettability

– Corrosivity of aqueous phase in the presence of oil

• This data may be collected at the point of entry of crude oil into pipeline

Section 4: Classical Papers

Predicting the Conductivity of Water-in-Oil Solutions as

a Means to Estimate Corrosiveness,

B.D. Craig, MetCorr

Understanding the Inhibiting Properties of Venezuelan

Crude Oils

S. Hermandez, BP Alaska; C. Mendez, DNV; and J.R.

Vera, DNV

Effect of Water-Oil Ratio on the CO2 Corrosion of L-80 Steel

J.A. Carew, A.Al-Sayegh, and A.Al-Hashem

Kuwait Institute for Scientific Research

Crude Oil Corrosivity from European Experience

G. Schmitt and N.Stradman, M. Stoe, IFINKOR, Germany;

and

M. Bonis, N.P.Boulet, and B. Adams, Total, France

Oil °API TAN (mg

KOH/g)

Inhibitive

efficiency

(%)

1 23.68 1.4 15

2 22.20 2.0 75

3 28.64 0.4 91

4 30.49 0.3 94

The Effect of Crude Oil on the Corrosion of Steel

K.D. Efird, Efird International

Crude Oil Chemistry Effects on Inhibition of Corrosion and Phase

Wetting

S.Nesic, S. Richter, W. Robbins, F. Ayello, P. Ajmera, and S. Yang

Ohio University

0.0

0.2

0.4

0.6

0.8

1.0

1.2

0 5 10 15 20

Time (hr)

Co

rro

sio

n r

ate

(m

m/y

r)

Water

0.1% Asph +Hep

1% Asph +Hep

5% Asph +Hep

Arab Heavy

Other Presentations

(No papers)

Canadian Crudes Commodities…Blending and

Pooling Quality Considerations

Randy Segato, Suncor Energy (Keynote Address)

Naphthenic Acid Corrosion – Are all Naphthenic acids corrosive?

Separation of Corrosive Naphthenic Acids from Non-Corrosive

Naphthenic Acids

P. Rahimi, CanmetENERGY; T. Kayukawa, JGC; R. Rodgers,

Florida State University; and T. Alam, CanmetENERGY

• This study was carried out under refinery

operating conditions

– Not all naphthenic acids are corrosive

– Mechanism of naphthenic acid corrosion is

not well understood

• Correlation between crude corrosivity and TAN is

not well established

Domestic Fuel Tanks

• There’s Oil in There You Know by R. J. Twigg and D.M.M. Twigg, Glencor Engineering Limited – Domestic fuel system failures are generally attributed to either water in

the oil or something known as under-deposit corrosion.

– However, several different corrosion mechanisms are often involved, creating a mosaic of well-developed corrosion patterns that ultimately lead to failure.

– Therefore, attempts to prevent only one possible corrosion mechanism often results in an accelerated attack by another factor causing unanticipated domestic fuel system failures

• Interaction of Crude Oil Corrosivity, Sulphur Levels and Economics – How much Do we Know? by J. F. Clayton, FAMEX Engineering – The anomalous behavior of sulphur compounds in the MIC corrosion of

above-ground fuel tanks (AFTs) was thought to possibly be active in pipelines.

– Of particular interest was the difference in corrosion rates between synbit (synthetic bitumen) and dilbit (diluted bitumen), the latter having a very much greater sulphur content.

– Further investigation is recommended.

Overall Summary from the Conference

• Under pipeline operating conditions

– Crude oil is non-corrosive

• 23oC and 65oC

• Dilbit is no different than other crude oils

– Presence of crude oil

• Decreases the corrosivity of water phase

• Extent to which the corrosion rate decreases is specific to

each crude oil

• No trends are identified

– Standard tests are available to evaluate the effect of

crude oils on the corrosivity of aqueous phase

“In God we trust; all others bring data”

-motto of the Apollo Astronauts

(as presented by D. McIntyre)