237896271-Chemical-Control-of-Corrosion.pdf

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2. TERMINAL OBJECTIVE
Upon completion of this module, the
participant will be able to select the
proper treating chemicals and the
best treating methods, given
corrosion-related operating systems.

3. ENABLING OBJECTIVE
•Define chemical treating terms
and describe treating chemicals.
•Describe treatment methods.
•Describe bacteria monitoring
techniques in terms of purpose,
methods, and significance of
results.

4. Operating Problems and Treating
Chemicals
Operating Problem Treating Chemical
Equipment corrosion Corrosion inhibitor,
Oxygen scavenger
Microbiologically-influenced Biocide
Corrosion
Mineral scale deposits Scale inhibitor
Suspended solids Coagulant, flocculant
Water-in-oil emulsion Emulsion breaker
Oil-in-Water emulsion Reverse breaker
coagulant, flocculant

5. Chemical Treating Terminology
Typical Treating Chemical Composition
1/3 Active
Ingredients
2/3 Solvents
or additives
Treating Chemicals

6. •Additives: a treating chemical usually
contains an active compound and one or
more additives
•Solvents: are add to most treating chemicals
to keep them from separating also lower pour
point
•Solubility: is chemical’s ability to dissolve in
solution
•Dispersibility: is chemical’s ability to
transported by fluids or gases
Chemical Treating Terminology

7. •Emulsion tendency: a chemical’s ability to
disperse one liquid phase into another
liquid phase
•Oil Soluble-Water Dispersible Inhibitors :
are normally used in oil wells and gas
condensate wells
•Water Soluble Inhibitors : they are soluble
in fresh and brine water
Chemical Treating Terminology

8. Corrosion Inhibitors
•They adsorb on metal surfaces
•They combine with corrosion product film
•They form precipitates
Work by one or more of the following
mechanisms:

9. Inhibitor Classifications
Corrosion Inhibitors
Inorganic Organic
Anodic Cathodic Film Forming
Chromates
Nitrites
Molybdates
Phosphates
Zinc inhibitors
Polyphosphates &
Phosphonates
Amines
Amine salts
Imidazoilnes

10. Inorganic & Organic
inhibitors
•Inorganic inhibitors are used mainly in boilers,
cooling towers, and fractionation units.
•Organic inhibitors are used mainly in oil field
systems.
•Organic inhibitors are also used to prevent
overhead corrosion in some refinery crude
units

11. •Often used to reduce corrosion in open
(aerated) and closed cooling water systems.
•used alone or in combination with other
inhibitors.
•Not enough anodic inhibitor lead to severe
localized pitting.
Inorganic Anodic Inhibitors

12. Inorganic Inhibitors
Electrochemical Corrosion Reactions in
an Open (Aerated) Cooling Water System
Precipitation of Black
Oxide
Hydrolysis and
Oxidation
Hydrolysis of Dissolved
Iron Lowers pH
ACIDIC PIT SOLUTION
WITH LOWER OXYGEN
CONTENT
6
5
3
1
7
2
Precipitation of Red Oxide
Iron Dissolves (ANODE)ANODIC AREA
Reduction of Oxygen
(CATHODE)
CATHODIC AREA
4
Evolution
of Hydrogen
(CATHODE)
MAGNETITEMAGNETITE
Fe
2o
3
Fe
3o
4
RED OXIDE
BLACK OXIDE
H
2
O
2
OH
-
Fe
e
-
e
-
e
-
e
-
Fe
+2
H
+
+ FeOH
+
Fe(OH)
2+ FeOH
+2

13. Ferric Iron Deposits as a Gamma
Iron Oxide Film
Inorganic Anodic Inhibitors
4 Fe
0
+ 3 O
2= 2gFe
2O
3
Inorganic Inhibitors

14. Inorganic Anodic Inhibitors
Combined Iron Oxide and chromium oxide
film on a Metal Surface

15. Inorganic Anodic (Passivating) Inhibitors
ShiftinAnodePotentialCausedbyAnodicInhibitors
Before anodic inhibitors
After anodic inhibitors
Potential Difference
More
negative
More
positive
Anode Cathode
CathodeAnode
Inorganic Inhibitors

16. Inorganic Anodic Inhibitors
Estimate of Proper Concentration of
Sodium Nitrite
Weight NaNO
2(in mg/L)
Wt NaCl + Wt Na
2SO
4 (in mg/L)
= 1
Inorganic Inhibitors

17. •Not as effective as inorganic anodic inhibitors
but safer to use.
Inorganic Cathodic Inhibitors
O
2+ 4H
+
+ 4e
-
2H
2O
O
2+ 2H
2O+ 4e
-
4(OH
-
)
In acidic systems:
In neutral or alkaline systems:
Reduction Reactions

18. Shift in Cathode Potential Cause by
Cathodic Inhibitors
Inorganic Cathodic Inhibitors
Inorganic Inhibitors

19. Zinc Inhibitors
Inorganic Cathodic Inhibitors
Zn
+2
+ 2 OH  Zn (OH
2
)
Zinc IonHydroxide Ion Zinc Hydroxide

20. Inorganic Cathodic Inhibitors
Polyphosphate Structure
PNaO
O
P
O
O
ONa ONa
ONa
x
x = 0 Orthophosphate
x = 1 Pyrophosphate
x = 2 Tripolyphosphate
x = 12-14Polyphosphate
Inorganic Inhibitors

21. Polyphosphates Prevent Reduction Reactions
at Cathodic Areas
Inorganic Cathodic Inhibitors
Polyphosphate
inhibitor
molecules
H
+
O
2
Metal
Fe
2+
O
2H
+
e e
Polyphosphates reacts with Ca and other divalent
ions in water such colloids are attracted to +ve
cathode

22. Organic Inhibitors
•Electrical potential of metal
•Inhibitor molecule chemical
structure
•Size and shape of inhibitor
molecule
•Complex mixtures of many different
molecular compounds
•Affect both cathodic and anodic sites
Their effectiveness depends upon:

23. Representation of an Organic Inhibitor Molecule
Using an Aliphatic Amine
Organic Inhibitors
H
C
H
Electrons available for bonding to
metal (chemisorption bond)
Polar amine
nitrogen group
N
Hydrocarbon chain
Oil soluble and attract crude oil
molecules to form oily layer
barrier

24. Chemisorption & Physical
Adsorption
•Organic inhibitors molecules attach to metal
surfaces by chemisorption and physical
adsorption
•Physical adsorption is weaker than
chemisorption
•Physical adsorption does not involve sharing
of electrons
Organic Inhibitors

25. Organic Inhibitors
Mechanism for Organic Film Forming Inhibitors
Inhibitor molecule
dispersed in process
stream
Metal
Process Stream
H HC
N
HH HHHHHHHHHHHHHHC C C C C C C C
N N
N
NNNNNN
Chemisorption & physical
adsorption by polar
amine group
HydrocarbonOil molecule
Hydrocarbon
chain “R”
H HC

26. Organic Inhibitors
Molecular Structure of Common
Oil Field Inhibitors
Name
NH
2
RCONH
2
RC
CH
2N
CH
2N
R
1
RN
(CH
2CH
2O)yH
(CH
2CH
2O)xH
Primary Amine
Amine
Amine
Polyethoxylated Amines
Structure
R
Organic Inhibitors

27. •Laboratory Static Test
•Laboratory Wheel Test
•Laboratory Electrochemical Test
•Field Corrosion Test Coupons
•Field Corrosion Probes
Corrosion Inhibitor Testing

28. Corrosion Inhibitor Testing
Corrosion Rate
Where -
W=weight loss in grams
A=coupon surfaces area ( in
2
)
d=metal density (g/in
3
) = g/cm
3
x 16.387 cm
3
/in
3
t=time (days)
A x d x t
mpy=
= 3.9 mpy
Weight in grams x 365000
0.037 g x 365000
mpy =
3.875 in
2
x 7.85 g / cm
3
x 16.387 cm
3
/ in
3
x 7 days

29. Laboratory Electrochemical Tests
LPR Test Apparatus for Continuous
Inhibitor Evaluation
Corrosion Inhibitor Testing

30. Corrosion Coupons
Field Corrosion Test Coupons
0.5” or1”
3”
0.0625” or 0.125”
Strip coupon Rod coupon Flush-mounted disc
Corrosion Inhibitor Testing

31. Field Corrosion Test Coupons
Flush-Mounted Corrosion Coupon in an Access Fitting
Disc coupon
holder assembly
Flush disc
Retriever
Service
valve
1 2 3 4 5
Retrieval Procedure
1.Access fitting in service,
externals removed.
2.Service valve installed,
retriever goes in.
3.Retriever is attached to plug.
4.Retriever extended, plug pass
gate, valve closed.
5.Plug removed.
Corrosion Inhibitor Testing

32. Field Corrosion Test Coupons
Pitting Severity
Where -
Penetration Rate (mpy)
Pitting Severity=
Maximum Pit Rate (mpy)
Time (days)
Maximum Pitting Rate=
Maximum Pit Depth x 365
Corrosion Inhibitor Testing

33. Field Corrosion Test Coupons
Interpretation of Corrosion Rates and Pitting Rates
Corrosion Inhibitor Testing

34. Quality Control
of Corrosion
Inhibitors
Comparison of NMR*
Spectra for Two
Samples of a
Corrosion Inhibitor
*NMR = Nuclear Magnetic Resonance

35. Quality Control
of Corrosion
Inhibitors
FT-IR*Spectra of Two
Samples of a
Corrosion Inhibitor
*FT-IR = Fourier-Transform Infrared

36. Oxygen Depolarizes the Cathode
Oxygen accepts
electrons
at the cathode.
Electrolyte
Cathode
Cathode
Metal
Fe
2+
H
+
H
+
H
2 H
2
H
2
H
2
H
2
O
2
ee
Anode
Oxygen Scavengers

37. •O
2main cause of corrosion in many water systems
•As low as 0.05 ppm O
2 can cause corrosion in water
•Arabian seawater contains 5-7 ppm O
2
•Sources of O
2 in water systems (open vents, thief hatches on
water tanks, suction side of centrifugal pumps, etc)
Gas blankets
Gas stripping
towers
Vacuum deaeration
Oxygen Scavengers
Mechanical techniques:
Reduce O
2 to about 1 ppm

38. •High-temp scavengers are commonly used in
boiler feedwater treatment
•For boiler: O
2 recommendedconc.7 ppb
•Sulfite are commonly used in oil field systems
•In oil field systems: O
2 to be reduced to 50 ppb

39. High-Temperature Oxygen
Scavengers
Hydrazine
N
2
H
4
+ O
2
2H
2
O +N
2
Hydrazine Oxygen Water Nitrogen
6Fe
2
O
3
+ N
2
H
4
4Fe
3
O
4
+ 2H
2
O + N
2
Iron (III)Hydrazine Magnetite Water Nitrogen
Oxide
Hydrazine will react with iron oxide as follows:

40. Sulfite and Bisulfite Oxygen
Scavengers
Na
2
SO
3
+ 1/2 O
2
 Na
2
SO
4
Sodium SulfiteOxygen Sodium Sulfate
NH
4
HSO
3
+ 1/2 O
2
 NH
4
HSO
4
Ammonium Oxygen Ammonium
Bisulfite Bisulfate (Ammonium Acid
Sulfate)
Are used in most oil field systems

41. Biocides
Planktonic and Sessile Bacteria
Planktonic
Bacteria
Metal Surface
Sessile
Bacteria Biofilm
Cause two major operating problems in oil field water systems:
declining water quality
corrosion

42. Biocide Application
Bacteriostats or bactericides.
Bacteriostats do not kill bacteria.
Bactericides inhibit bacterial growth.
Chemicals that control bacteria growth are classified as:

43. Performance is based on success in
controlling sessile bacteria.
Planktonic counts are used first to screen
several biocides.
Further testing using sessile counting
techniques.
Biocide Performance

44. List of Biocides Frequently Used in
Oil Field Operations
Primary Cocoamine RC · NH
2
· HOOCH
Amine Salts acetate
Diamine Cocodiamine RC · N C C C NH
2· HOOCH
Salts acetate
Quarternary Dialkyl-benzyl
Ammonium ammonium chloride
Salts
Aldehydes Glutaraldehyde OCH(CH
2
)
3
CHO
Acrolein CH
2
= CHCHO
Oxidizing Chlorine CI
2
Agents
Chlorine dioxide CIO
2
R
C
R
C
N
HC
C
6
H
5
CH
2
CI
-
+
H H H H
H H H
Biocides

45. Biocide Effectiveness
((10,000 -100) / 10,000) x 100 = 99%
Biocides
Abiocideconc.isconsidereffectiveif
itkillsatleast99%ofthebacteria
comparedtoantreatedblanksample.

46. •Scale can inhibit or promote corrosion
•Prevent & Remove oil field scale whether or not it protects the metal.
•Scale can cause operation problems in addition to corrosion
•Scale deposits are mainly caused by supersaturation:
Temp. decrease
Temp. increase
Press. Decrease
Incompatible waters are mixed
Water evaporates
Saturated waters become stagnant
Scale Inhibition

47. Most Common Oil Field Scales
NAME FORMULA COLOR WHEN PURE
Barium sulfate BaSO
4
White
Calcium carbonate CaCO
3
Colorless to white
Calcium sulfate
Anhydrite CaSO
4
Colorless to white
Gypsum CaSO
4
.2H
2
O Colorless to white
Iron carbonate FeCO
3
Gray
Iron oxide Fe
2
O
3
Redish brown to
black
Iron sulfite FeS Brown to black
Strontium sulfate SrSO
4
Colorless to white
Scale Inhibition

48. Ca
+2
+2HCO
3
-

Ca
+2
+CO
3
-2
+CO
2
+H
2
O
CaCO
3
+CO
2
+H
2
O
Calcium Carbonate Formation
Scaling tendency ofCaCO
3
as temp
Scales
Normally produced waters contain Ca
+2
, HCO
3
-
, and CO
2

49. Colors of Pure Oil Field Scales
NAME FORMULA COLOR WHEN PURE
Barium sulfate BaSO
4
White
Calcium carbonate CaCO
3
Colorless to white
Calcium sulfate
Anhydrite CaSO
4
Colorless to white
Gypsum CaSO
4
.2H
2
O Colorless to white
Iron carbonate FeCO
3
Gray
Iron oxide Fe
2
O
3
Redish brown to
black
Iron sulfite FeS Brown to black
Strontium sulfate SrSO
4
Colorless to white
Identifying Scales

50. Composition of a Typical Scale Inhibitor
30% Active
Ingredients
70% Water
Scale Inhibitors

51. Scale Inhibitor
•Are water based products.
•Reduce rate of scale deposition.
•Distort scale micro crystals in solution.

52. Scale Inhibitors Used Most
Often in Oil Field Operations
NaO
O
PO
ONa
O
PO
ONa
O
PON
aONa
n
RNCCOPN
O
OHR
1
HOP
O
CH
2
OH
HOP
O
CH
2
OH
NCH
2
CH
2
N
HOPCH
2
OH
HOP
O
CH
2
OH
O
CH2CH
C=O
CH
+
,Na
+
n
CH
2
CH
C=O
NH
2
x
Inorganic
Polyphosphates
Organic Phosphates
Esters
Organic
Phosphonates
Organic Polymers
CLASS STRUCTURE

53. •overall effectiveness.
•Thermal stability
•Compatibility with water ands solubility in.
Scale Inhibitors Selection
Most important factors are:

54. Scale Inhibitors Selection
Inhibitor Type Solubility*Thermal Stability
Phosphate EstersMost solubleLeast stable
Phosphonates
Polymers Least solubleMost stable
*Solubility in high-calcium brines.
Organic Scale Inhibitor Properties

55. •Flocculation
process in which
water droplets
gather into groups
•Coalescence
process in which
surfactant film
breaks hence water
droplets become
larger
•Settlinglarger
droplets settle to the
bottom
Water
Oil
Flocculation
Coalescence
Settling
The Oil-Water
Separation Process
Emulsion Treatments

56. Continuous Chemical Injection
Chemical
reservoir
Injection
pump
Pipeline

57. Batch
Treatments
Batch and
Fall
Application
Method
Casing
Tubing
Gas
Inhibitor
mixture
falls down
tubing wall

58. Tubing
Displacement
Treating
Method
Displacing
fluid or
nitrogen
Inhibitor
mixture
Oil
Perforations

59. Champion
Tubing
saver
Connection for
weight bar
Gas
Wire line tie
Nylon brush
Knuckle joint
Nylon brush
Inhibitor
mixture

60. Corrosion
Inhibitor
Squeeze
Treatment
Casing
Displacing
Fluid
Tubing
Inhibitor
mixture
Parker
Perforations
Inhibitor

61. Serial Dilution Technique
GAB and SRB Broth Media Bottles
9 ml of
broth media
Nail
GAB 9 ml
dextrose broth
SRB 9 ml
lactate broth
9 ml of
broth media
28 days
incubation
period
5 days
incubation
period

62. Serial Dilution Technique
Dilution Ratio 1:10 1:100 1:1,000 1:10,000 1:100,000 1:1,000,000
Dilution Level 10
-1
10
-2
10
-3
10
-4
10
-5
10
-6
Syringe
with 1 ml of
water sample

63. Triplicate Test for Sulfate Reducing
Bacteria
Test 1
Test 2
Test 3
10
0
10
1
10
2
10
3
10
4
10
5
10
6
BACTERIA / ML