OIL FIELD CORROSION
DETECTION AND CONTROL
HANDBOOK
;
:nt
3.S-
OIL FIELD CORROSION
DETECTION AND CONTROL
By ' _
HOWARD J. ENDEAN
CONSULTANT
Published By
CHAMPION CHEMICALS, INC.
Houston, Texas
1989
m-
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of
:d.
ACKNOWLEDGEMENT
The writer appreciates the support and encouragement of the management
of Champion Chemicals, Inc. in the preparation of this manual. Also, myassociate Mr. Raymond Shelton for review and permission to include his compilation of Champion's Cortron Corrosion Inhibitors in Chapter V. The
cheerful cooperation of Ms. Debbie Burroughs in the frequent re-working of
the drafts required in the preparation of this manual is greatly appreciated.
i
TABLE OF CONTENTS
DESCRIPTION
ITEM
DESCRIPTION
ITEM
PAGE
CHAPTER II - OIL WELL CORROSION AND ITS PREVENTION
CHAPTER I - CAUSES OF CORROSION IN OIL FIELD EQUIPMENT
General
13
A.
Water Cut vs Water Wetting of Well Equipment
13
B.
Typical Causes of Sucker Rod Body Breaks
14
C.
Endurance Limit of Sucker Rods
15
D.
Typical Causes of Sucker Rod Pin Breaks
16
General
1
A.
Defmition of Corrosion
1
B.
Electrochemical Environment
1. Metallurgical Factors
2. Mill Fabricating Factors
3. Field Operating Factors
2
3
3
3
C.
Typical Idealized Electrochemical Reaction
4
E.
Typical Appearance of Sucker Rod Body Breaks
16
D.
Appearance of Metal Loss Corrosion
1. Hydrogen Sulfide - Pitting & General Attack
2. Carbon Dioxide - Pitting Attack
3. High Chloride Brines - pH 6.0 - 7.0
4. Acids - 15% HCI & Spent Acid
5. Bacteria - Sulfate Reducers
6. Corrosion/Erosion - Velocity Effect
4
4
5
5
5
6
6
F.
Typical Appearance of Sucker Rod Coupling Breaks
17
G.
Slag Inclusion Mill Defect
17
H.
E.
Corrosivity vs pH of Water
7
Rules of Thumb for Estimating Corrosion
1. Rule 1 - Corrosion Coupon Data - 30 Days
2. Rule 2 - Rpd String Stress Failures
3. Rule 3 - pH Measurements - Fresh Samples
4. Rule 4 - Water Cut & pH
18
18
18
18
18
F.
Corrosion vs Hydrogen Sulfide & Carbon Dioxide
1. Corrosivity of Hydrogen Sulfide
2. Corrosivity of Carbon Dioxide
7
8
8
I.
Field Program for Detecting Corrosion
19
J.
Decisions in the Design of an Inhibition Program
20
G.
Corrosion Rate vs Velosity & Temperature
9
K.
Treating Procedures for Pumping Oil Wells
21
H.
Accelerating Rate of Pit Development
10
L.
I.
Hydrogen Embrittlement
11
J.
Factors Controlling Hydrogen Embrittlement
1. Yield Strength
2. Hardness
3. Stress Level
4. Internal Stresses
5. Hydrogen Concentration
6. Temperature
11
11
Initial Filming Procedures
1. Running Tubing and/or Rods in Well
2. All Batch and Continuous Injection Treatments
3. Squeeze Treatments
21
21
22
22
M.
Periodic Batch Treating Procedure
1. Adequate Volume ofInhibitor
2. Gallons of Inhibitor Required per Week
3. Adequate Frequency of Treatment
4. Assuring Inhibitor Enters Tubing
22
22
23
23
23
K.
Hydrogen Blistering
12
N.
Periodic Batch with Inhibitor Emulsion Procedure
24
L.
Galvanic Corrosion
12
O.
Continuous Injection Procedure
24
..
II
'--
PAGE
-
- - -- - - -
11
11
11
11
11
iii
DESCRIPTION
ITEM
PAGE
Squeeze Treatment Procedure
24
Q.
Monitoring Oil Well Corrosion
1. Rod String Failure Analysis
2. Corrosion Coupon Data
3. Iron Count Data
25
25
25
Iron Loss Nomograph
27
R.
26
J.
General
28
A.
Theoretical Limiting Velocities for Well Tubing
28
B.
Calculation of Approximate Tubing Velocity
1. Approximate Bottom Hole Pressure of Gas
Wells
29
C.
Corrosivity vs Limiting Velocity & Density
30
D.
Phase Relations of Gas and Liquids in Tubing
1. Flow Patterns in Tubing
2. Slip and Holdup in Tubing
31
32
32
E.
Gas/Condensate Wells Water Production
1. Gas Expansion Reservoirs
2. Water Drive Reservoirs
3. Mobile Water Table Reservoirs
33
34
34
34
F.
Rules of Thumb for Estimating Corrosion
1. Rule 1- Predicting Corrosion in All Wells
2. Rule 2 - Predicting Corrosion - Sweet Gas Wells
3. Rule 3 - Predicting Corrosion - Sweet Gas Wells
4. Rule 4 - Predicting Corrosion - Coupon Data
34
35
35
35
36
G.
Decisions Required for Inhibiting Program
36
H.
Procedures for Inhibiting Gas Wells
37
1.
Treating Rates for Gas Condensate Wells
37
30
PAGE
37
38
1. Batch Treating per 5000' of 2"-3" Tubing
2. Continuous Injection Rates 2"-3" Tubing
3. Squeeze Treatment Volume
38
Corrosion Control in Wellheads and Downhole
Equipment
38
CHAPTER-IV OIL AND GAS PIPELINE CORROSION & PREVENTION
General
39
A.
Frequent Causes of Internal Corrosion in Pipelines
39
B.
Flow Patterns in Pipelines
1. Custody Transfer Oil Lines
2. Wet Gas Pipelines
40
40
41
c.
Approximate Velocities in Wet Gas Pipelines
1. Approximate OR for Buried or Submerged
Pipelines,
2. Approximate Pipe Areas in Square Feet
42
D.
Evaluation of Corrosion Possibilities in Pipelines
43
E.
General Types of Inhibiting Programs for Pipelines
1. Procedures for Cleaning Lines Prior to
Inhibiting
a. New Pipelines
b. Operating Oil Lines
c. Operating Wet Gas Pipelines
d. Operating Dehydrated Gas Pipelines
44
CHAPTER III - GAS/CONDENSATE WELL CORROSION & PREVENTION
iv
DESCRIPTION
ITEM
P.
43
43
44
44
45
45
45
2. Inhibiting Oil Pipelines by Continuous Injection 45
a. Inhibiting Field Transmission Lines
46
b. Inhibiting Custody Transfer Lines
46
3. Inhibiting Wet Gas Pipelines
a. Type 1 Treatment (Batching)
b. Type 2 Treatment (Continuous Injection)
c. Type 3 Treatment (Special Conditions Only)
d. Optimum Treatment
F.
Inhibitor Requirements Versus Wet Gas Velocity
v
47
48
49
50
50
51
DESCRIYfION
ITEM
PAGE
G.
51
Inhibiting Sales Gas Pipelines
1. Type 1 Treatment (See E,3,a Type 1 Treatment) 52
52
2. Type 2 Treatment (Continuous Injection)
H.
Monitoring Corrosion in Pipelines
1.Corrosion Coupons-Installation Requirements
a. Lease Flow Lines
b. Custody Transfer Lines
c. Wet Gas Pipelines
d. Sales Gas Line
e. Interpreting Corrosion Coupon Data
52
53
53
53
53
54
54
2. Water Analysis of Corrosion Potential
a. Lease Flowlines
b. Custody Transfer Lines
c. Wet Gas Pipelines
d. Water Samples-Corrosion Monitoring
e. Water Samples-Inhibitor Monitoring
54
55
55
55
56
56
I.
Monitoring Sales Gas Pipelines
56
CHAPTER V - OXYGEN CORROSION IN PRODUCTION & PIPELINES
General
57
A.
Air Entrainment in Oil Wells
58
B.
Air Entrainment in Tanks
58
C.
Air Entrainment in Transfer and Injection Pumps
58
D.
Air Entrainment in Injection Systems
59
E.
Potential Sources of Air Contamination
59
F.
Air Entrainmeni in Water Sources
60
G.
Solubility of Oxygen in Surface Waters
60
H.
Removal of Oxygen from Injection Waters
60
vi
ITEM
DESCRIYfION
1. Scavenging and Inhibiting of Oxygen
2. Gas Refluxing or Vacuum for Oxygen Removal
PAGE
61
61
CHAYfER VI - CHAMPION'S CORTRON INHIBITORS
FOR CORROSION CONTROL
A.
Sucker Rod Pumped Wells-High Fluid Level
62
B.
Sucker Rod Pumped Wells - Low Fluid Level
62/63
C.
Gas Lift Wells
63
D.
Hydraulic Pumped Wells
63
E.
Gas/Gas Condensate Wells
63/64
F.
Oil & Gas Pipelines
64/65
CHAYfER VII - MISCELLANEOUS TECHNICAL INFORMATION
General
66
A.
Failure Analysis Procedure
67
B.
Approximation of Tensile and Yield Strength of Steel
1. Brinell vs Rockwell Hardness
2. Brinell Hardness vs Tensile Strength
3. Tensile Strength vs Yield Strength Range
68
68
69
69
C.
Approximate Velocity Criteria for Liquid
1. Calculation of Approximate Velocity
2. Limiting Velocities for Water in Steel Pipe
3. Limiting Velocities for Oil in Steel Pipe
4. Design Criteria for Pump Suctions
5. Pipe Velocities vs Fluid Densities
70
70
70
70
70
71
D.
Design Velocities for Well Tubing
71
E.
Corrosion Resistant Materials
72
vii
ITEM
DESCRIPTION
1. Non-Metallic Materials
a. Extruded Plastic Pipe
b. Glass Filament Wound Epoxy Pipe
c. Plastic Liners in Steel Pipe
d. Baked on Coatings
e. Cement Linings
F.
G.
PAGE
72
72
73
73
73
74
2. Corrosion Resistant Alloys
a. Monels
b. Stainless Steels
(1) AISI 300 Series Stainless Steels
(2) AISI 400 Series Stainless Steels
74
3. Aluminum Bronze Alloys
75
4. Inconel, Hastelloy, Stellite and Colmonoy
76
API Specifications - Physical Properties
1. API/SPEC. llB Sucker Rods & Couplings
2. API/SPEC. SA, 5AC, SAX Tubing & Casing
3. API/SPEC. 5L Line Pipe
76
References Pertinent to Oil Field Corrosion
79
74
75
75
76/77
77
78
FOREWORD
Serious corrosion in production and pipelines began in the 30's with
widespread drilling of wells west of the Mississippi River. In many of the fields
the oil and gas contained significant amounts of the acidic gases, Hydrogen
Sulfide and Carbon Dioxide. In addition, some fields had active water drives
or mobile water tables and were completed in non-consolidated formations
that further intensified corrosion. While the 30's incidents of corrosion were
widespread the actual number of fields in which it was occurring was limited.
However, by the mid 40's corrosion failures had reached epidemic level.
Well and pipeline corrosion was classified as a field problem with the responsibility for its solution at the descretion of the field operators and their staffs.
In cooperations with production chemical companies widespread field testing began, mostly based on intuitive guesses at solutions. Also many ad-hoc,
off the record meetings were held for comparing of results. By the early 50's
the widespread testing and interchange of results had developed "Rules of
Thumb" for both detecting a corrosive condition and limiting the rate of metal
loss. Since the 50's, through continued testing and the formulation of superior chemicals, t'reatments have been further improved. Considerable of the
information in this manual is today's versions of these original programs.
While by technical definition they would still be classified as "Rules of
Thumb" based on years of successful application they can be applied with
confidence.
There is no way the many operating and production chemical company personnel that contributed to the developments can be acknowledged. In the
late 40's the NACE was still in the formative stages with the formal reporting and cataloging of field work in the beginning stage. The NGAA Corrosion
Research Project, one ad-hoc committee comparing and analyzing field
studies lists 22 production companies and service organizations a~tive in fi~ld
studies. The minutes of this committee refers to many of the studies bllt With
only limited reference to the personnel involved. However, this manual attests to the thoroughness of studies and the technical proficiency and objectivity of the personnel that undertook these investigations.
viii
ix
CHAPTER I
CAUSES OF CORROSION IN OIL FIELD EQUIPMENT
GENERAL
It has been estimated that 80% of failures occurring in production and
pipeline operations are caused by corrosion. This is either of the metal loss
type or of the stress types with corrosion developing the stress raisers or
atomic hydrogen associated with Hydrogen Embrittlement. The primary objective when failure occurs is to establish that if corrosion is the cause, what
are the specific reasons and how can it be prevented in the future.
Since corrosion is generally suspected as the cause, it is essential the operator
have a general understanding of the corrosion phenomena, its appearance
and operating conditions that can initiate the attack. Since most equipment
is manufactured from Ferrous metals the corrosion of steels etc., are of
primary concern. The two principal corrodents associated with oil and gas
are Hydrogen Sulfide and Carbon Dioxide. Oxygen is also of major concern
when produced or injection waters are in contact with air. While there are a
wide variety of operating conditions under which corrosion may occur, the
electrochemical reaction is always the underlying cause. Once these factors
controlling corrosion are understood and the types of failures recognized,
corrosion can be readily established as the probable cause. Usually a review
of operating conditions coupled with relatively simple tests will confirm the
condition.
The following reviews the basic concepts of oil field corrosion and other pertinent information to field failure analysis.
A. DEFINITION OF CORROSION
The "CORROSION HANDBOOK" by Herbert H. Uhlig states:
CORROSION:
Destruction of a metal by chemical or electrochemical reaction with its environment.
In routine production and pipeline operations only the electrochemical reaction applies. Depending on metallurgy, cor rodents and operating conditions
the appearance of the corrosion and failures can be quite differerent,
however the underlying cause is the electrochemical component of the definition.
-1-
While the chemical component of the definition is discounted for routine
operations it can be a factor in failures associated with acid jobs, packer fluids
and other operations where large volumes of treating chemicals have been
used in stimulation or completion operations. Where corrosion has occurred
without apparent cause, a review of the chemical possibilities is desirable.
LOCAL CELL ACTION
Fe+ +
Fe+ +
B. ELECTROCHEMICAL ENVIRONMENT
Fe++~iNtH:1w
(ELECTROLYTE)
The figure below is an idealized representation of the electrochemical environment with a clean, perfect steel surface without internal or external imperfections. Each grain is minutely different in structure and composition
and markedly different from the grain boundary alloys that precipitated as
the steel cooled from the molten to the solid state. When the surface is filmed
with an electrolyte, always water in routine field operations, there is a minute
current flow between the anodic and cathodic areas of the surface.
ELECTRO CHEMICAL ENVIRONMENT
~ WATER
~
G R A : : : : J GRAINBOUNDARIES
MAYBE
/~
H+
Surface deterioration of the metal surface would be slow and generally
uniform. Frequently corrosion products, such as rust, coat the surface, slowing the reaction rate. While this general corrosion is not usually a major concern from metal loss considerations, the atomic hydrogen can cause
Hydrogen Embrittlement in high strength, highly stressed steels.
The electrochemical pitting type attack is the major cause of stress corrosion
and metal loss failures. There are a number of factors in typical oil field steels
fabricating procedures and operliting conditions that form the areas of high
electrochemical potential where pining attack develops. The following is a
partial listing of the many conditions in field materials and equipment that
can initiate corrosion pitting.
1. METALLURGICAL FACTORS: Abnormal grain growth, improper
heat treatment, dirty steel (slag, slugs, scabs), improper stress relief, inadequate melting sequence.
ANODES OR CATHODES
SIMULATED STEEL MICROSTRUCTURE
X'S 1,OOO'S
The following figure is an idealized representation of the electrochemical
reactions at the anodic and cathodic surfaces. Iron ions enter the water from
the anode; hydrogen ions in the water move to the cathode, combine to form
molecule, rise as minute gas bubbles and leave the electrolyte.
-2-
2. MILL FABRICATING FACTORS: Inadequate heat treatment and/or
stress relief, folds, seams, upsetting heat runouts, inadequate heading
and scarfing, inadequate cleaning (mill scale), improper or inadequate
welding, excessive cold straightening, surface damage (knicks, gouges,
etc.).
3. FIELD OPERATING FACTORS: Surface damage (tool marks,
gouges, knicks, etc.), improper welding (seams, heat runouts, blow
throughs, slag, etc.) cold bending and straightening, acidic produced
water, water deposited scales, corrosion product scales, water legs,
high velocity (turbulence at flow discontinuities), dissimilar metals and
alloys.
-3-
C. 1YPICAL IDEALIZED ELECTROCHEMICAL REACTIONS
The following ferrous corrosion products shown would form with the H2S
and C02 in low solids water and from corrosion considerations they are the
only products of concern. However, analysis of typical field scales will contain other chemical elements associated with oil field brines and an organic
component from the oil, condensate or well treating chemicals.
H20
+
H2S ------------- FeS + H2
(sour corrosion)
Fe + H20 + C02 ------------- FeC03 + H2
(sweet corrosion)
4 Fe + 302 -------------- 2 Fe203
(oxygen corrosion)
Fe
D. APPEARANCE OF METAL LOSS CORROSION
The following are typical textbook examples of metal loss corrosion. The
samples were thoroughly cleaned to illustrate the type of metal loss. When
field samples are to be inspected a sample of the corrosion product should
first be removed and placed in an air tight container in case an analysis is required. A section of the sample should then be thoroughly cleaned, with an
acid wash if necessary, so the surface condition can be inspected.
2. CARBON DIOXIDE - PITTING ATTACK
The corrosion product can vary from dark brown to black. Generally it
is loosely adhering. Initially the pits are small as at the left center of the
illustration, sides are vertical and the bottoms rounded. Originally the
attack was called ring worm corrosion due to its appearance in a circumferential ring at the heat runout zone of upset tubing. Frequently
they also appear in extended lines of pits as illustrated. Frequently the
balance of the metal surface is either free of corrosion or only very
lightly attacked.
3. HIGH CHLORIDE BRINES - pH 6.0 - 7.0
In produced water, with no or only minute traces of acid gases, the pH
will approach 7.0. This will often result in a general attack with shallow
round bottom pitting, the rounded bottom shape markedly decreases
in stress raiser affect. The rate of metal loss is usually low.
1. HYDROGEN SULFIDE - PITTING & GENERAL ATTACK
With both types of attack the corrosion product will be black. In the
case of the pitting type attack it will generally be tightly adhering. In appearance it can vary from a smooth, shiny surface to a rough, dull
black, noduler. With the general type attack the corrosion product is
usually thin, relatively soft and dull black.
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4. ACIDS - 15% HCI & SPENT ACID
With fresh, non-inhibited acid the attack is severe and rapid. The surface is deeply etched with sharp needle like protrusions. With spent
acid, the attack, while rapid, is a less surface damaging type.
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5. BACTERIA - SULFATE REDUCERS
The attacked area is covered with a black, impenetrable adhering corrosion product film. In the initial phase of the infestation the steel surface has the mottled surface illustrated below. As the attack progresses
a more conventional type pitting can develop as shown in the upper illustration. However, the outer edge of the pit still exhibits the mottled
appearance establishing that the initiating cause was the bacteria
development.
E. CORROSM1Yvs pH OF WATER
With water wetting of field equipment being a primary requirement for corrosion, its acidity - pH, is a readily made measurement for determining the
significance of the attack. For solids free water of velocities of 3 FPS or less
the following "Rules of Thumb" are applicable.
pH 7.0 or higher
pH 7.0 to 6.5
pH 6.5 to 6.0
pH 6.0 or less
- Significant corrosion unlikely
- Minor corrosion possible
- Moderate corrosion with possible pitting
- Significant corrosion with probable pitting
The figure indicates the effect of increasing velocity on the corrosion rate.
From approximately 3 to 7 FPS, water is in a transition range between laminar
and total turbulent flow and the relative corrosion rate will be between the
Dormant Water and the Corrosion/Erosion Condition. The upper curve will
be the limiting condition up to velocities where erosion of the metal will begin.
RELATIVE CORROSION VS pH & VELOCITY
8
>-
I-
7
:;:
6. CORROSION/EROSION - HIGH VELOCI1Y EFFECT
With high fluids velocity the type corrosion can be masked by erosion.
The corrosion product formed is continuously eroded away, generating
a smooth surface. This continuously presents clean metal to the corrodent with a high rate of metal loss.
Ui
o
a:
gj
6
5
U
~
4
i=
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DORMANT WATER
(No Flow)
a:
2
12
10
8
7
ALKALINE - p H -
6
4
2
ACIDIC
F. CORROSION vs HYDROGEN SULFIDE & CARBON DIOXIDE
Hydrogen Sulfide and Carbon Dioxide are the only acidic components contained in any significant amount in oil and gas reservoirs. The amounts normally vary from minute traces to 5%. The corrosivity (pH) of produced water
is a function of the amounts of these two gases in solution. However, the rate
of metal loss, type, and locations are controlled by other factors, such as,
temperature, pressure, susceptibility of the metal and pitting initiating conditions as noted in Item B.
-6-
-7-
The examples below are from laboratory tests performed at low pressures
and room temperature. As such, specific values would have no relation with
field operating conditions. However, the rate of change shown can be considered reasonable approximations of the change of the corrosion rate that
could be anticipated for similar changes in the variables in operations.
6
w 5
le(
a:
z
0
1. CORROSMTY OF HYDROGEN SULFIDE
In considering the figure most sour corrosion will have less than 2000
ppm ofH2S and will be in the (5.0 - 6.5) pH range. Assuming an
average pH of 6.25, an increase from a trace of H2S to 2000 ppm would
increase the corrosion rate by a factor of 4. The curve indicates that for
a H2S content of over 100 ppm the corrosion would be significant. It
would probably be a pitting attack.
4
(j)
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a:
a: 3
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w
> 2
i=
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W
a:
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w
-
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a:
z
pH 4.5
pH 5.0
4
3
0
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w
i=
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5
10
15
20
25
CARBON DIOXIDE - PPM
G. CORROSION VERSUS VELOCITY AND TEMPERATURE
0
iii
0
a:
a:
o
pH 6.25
2
....I
W
a:
The following figure illustrates the effect of both velocity and temperature
increases on the rate of metal loss. The tests on sea water in a closed system
would be for a pH in the 7.0 - 8.0 range, without oxygen present. The type attack for flow rates below 3 FPS would be similar to that illustrated in 4,C. The
temperature rate increases would be of the same order of magnitude for all
corrosive conditions. However, the effect of velocity could be markedly increased for more corrosive conditions due to the corrosion/erosion phenomna.
e::-:::
-
pH 9.0
0
500
1000
1500
2000
SULFIDES AS H2 S, ppm
5
2500
2. CORROSMTY OF CARBON DIOXIDE
w
Ie(
With the amount of Carbon Dioxide in solution being a function of the
pressure and temperature in the system, the pH measurement on a
water sample is misleading and should be discounted. When other than
minute traces of C02 are present, the pH's of the water in either wells
or pipelines will be markedly lower than measurements on even fresh
water samples. The figure illustrates the rate of increase in corrosion
that occurs with increasing C02 content in the water and also how the
oxygen entering the water, by contact with air, further increases the
rate of metal loss. The curve of 10 ppm 02 is for the maximum
solubility that would be expected in routine field operations.
/
4
a:
z
0
(j)
0
3
./
V
0
0
w 2
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i=
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a:
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V
V
V
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co
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V V
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a:
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4
6
VELOCITY IN FT.!SEC.
-9-
8
10
H. ACCELERATING RATE OF PIT DEVELOPMENT
I. HYDROGEN EMBRITTLEMENT
The principal cause of all corrosion failures in oilfield operations is the pitting type attack. In operations where the equipment is under continuous or
repeated strains, due to pressure or mechanical action, pitting can be the
principal cause of premature failure. Pits under these conditions develop the
stress raiser affect which markedly reduces the theoretical, calculated failure
stress of an item. This stress raiser type failure is widely recognized and where
it can occur every effort is made to minimize corrosion.
Wide spread, spontaneous brittle failures were first encounte~ed in t.he
production industry in the late 30's. These were generally aSSOCiated WIth
high strength steels producing sour oil and gas (H?S). Initially, these were
not identified as hydrogen embrittlement and a vanety of names were used
to identify the failures such as: sulfide stress cracking, sulfide corrosion cracking, sulfide cracking, and sulfide stress corrosion cracking. While .this type
failure is now generally recognized as a form of hydrogen embnttlement
several of the field names are still in general use.
However, it is frequently overlooked that in non-stressed equipment pitting
can also cause premature equipment failures. This reflects a lack of understanding of the increasing rate of pit penetration of steel as corrosion progresses. As noted in Item D, APPEARANCE OF METAL LOSS
CORROSION, Page 4, H2S, C02 and Sulfate Reducers, the principal oilfield corrodents, generally develop a pitting type attack. As illustrated below,
as the pit deepens, the rate of ferrous ions entering the water remains constant. However, the surface area of the anode supplying the ferrous ions continuously decreases. This increased the rate of pit penetration and can result
in rapid, premature failure of equipment. This can occur even though the
overall corrosion rate in a system remains low.
INCREASING RATE OF
PENETRATION WITH PIT DEVELOPMENT
There are several hypothesis for hydrogen embrittlement and all are in agreement that the phenomena is initiated by hydrogen di~fus~on into .the st~e.l.
While the hydrogen can be from a number of sources, l~ OIlfield faIlures It ~s
normally associated with water wet ferrous metals. While the electrochemical reaction is also the cause of metal loss corrosion, where steel are susceptible to hydrogen embrittlement and under sufficient tensile stress, failures
are quite rapid and before any significant metal loss has occurred. Rese~ch
and field testing has established rigorous specifications for preventmg
hydrogen embrittlement. Details of the phenomena are. beyond the scope .of
this presentation. The following lists the factors controlhng hydrogen ~mbnt­
tlement and Chapter VI lists the of API grades of sucker rods and tubmg and
their susceptibility to this type failure.
J.
+-+--
--+-+
Large anodic area, rate of metal
loss and pit penetration slow.
~
+--
--+-
-+-
-+-+
Anodic
area
decreases,
cathodic area extends down
~ide of pit. Rate of penetration
mcreases.
~
Anodic area confined to bottorn of pit. Rapid rate of metal
loss and wall penetration.
FACTORS CONTROLLING HYDROGEN EMBRITTLEMENT
1. Yield Strength - Steels with yield strengths of 90,000 psi or lower are
generally not susceptible to hydrogen embrittlement.
2. Hardness - Maximum hardness should be Rc-22 or less.
3. Stress Level - With failure susceptible steels there is a stress level
below which failures will not occur. This is a function of the yield
strength of the steel and decreases as the yield strength increases.
4. Internal Stresses - Stress susceptible steels can fail due to internal tensile stresses caused by welding, cold working, bending or surface
.
damage by tools or handling.
5. Hydrogen Concentration - Time to fa~lure is a fun.ction o.f ~ydr?gen
concentration. However, with susceptIble steel, faIlure WIll meVitably
occur if hydrogen is present and the allowable stress is exceeded.
6. Temperature - Research and field experience indicates that failures
will not occur above 150 F.
0
NOTE: Corrosion product normally coating or filling pits not shown.
-10-
-11-
K. HYDROGEN BLISTERING
CHAPTER II
While low strength, ductile steels are not susceptible to hydrogen embrittlement occasionally hydrogen blistering can occur. Normally the atomic
hydrogen entering the steel along the grain boundaries will defuse through
the metal. Occasionally, an inclusion or other anomoly in the grain structure
will stop the diffusion of the hydrogen with the combining of atoms to form
the much larger molecules of hydrogen. This will cause internal cracking that
with continuing molecule formation develops blisters. Generally this occurs
in low pressure equipment and few failures have been reported from the
cause. When the conditions develops to where blisters are noted the equipment should be replaced.
L. GALVANIC CORROSION
One source of failures frequently overlooked in field equipment where water
is involved is that associated with the coupling of dissimilar metals. Failures
from galvanic attack are usually associated with small piping and control
items and not of serious consequence. However, this corrosion can easily be
avoided. The following table lists the Galvanic Series for the metals normally used in oil field equipment. Every effort should be made to select metals
in close proximity in this series. Where metals are widely separated it is mandatory, an insulating arrangement is to be used between the metals.
GALVANIC SERIES IN FIELD OPERATIONS
Magnesium and Alloys
Zinc or Galvanized Metals
Aluminum (soft alloys)
Cadmium or Cadmium Plating
Aluminum (hard alloys)
Steel, Cast Iron, Wrought Iron
Solder (50% lead, 50% tin)
Stainless Steel (AISI Series 300, active)
Lead
Tin
Naval Brass, Maganese Bronze, Yellow Brass
Admiralty Brass, Aluminum Bronze, Red Brass
Copper, Silicon Bronze
Inconel
Monel
Stainless Steel (AISI Series 300, passive)
-12-
OIL WELL CORROSION AND ITS PREVENTION
GENERAL
With adequately designed well bore equipment, during the flush and low
water producing periods and with an average fluid velocity of 3 FPS and
above, the flow string surfaces will be oil wetted and no significant corrosion
will occur. With velocities below 3 FPS, water legs can build-up in the lower
sections of the well. This can result in casing, tubing and pumping equipmept
being water wetted and corrosion is possible. Without the water leg development the equipment will normally remain oil wetted up to water cuts of about
25%. Between 25% and 45% water cut, equipment may be either oil or water
wetted, depending on the crude oil characteristics. Generally as the API
gravity of the oil decreases the cut level at which water wetting begins increases. At a water cut of 45% and above the equipment will always be water
wetted. In gas drive reservoirs with stable water tables, wells will experience
no significant corrosion during the primary producing phases. (With the exception of water leg corrosion). In reservoirs with water drives, mobile water
tables or water injection projects the rate of water intrusion and oil characteristics will determine when corrosion will be occurring. In many fields
where wells are essentially corrosion free during primary production, serious
corrosion may develop during secondary recovery operations. The early
detection of corrosion and beginning of corrosion control programs are essential for controlling well equipment replacement costs. When corrosion inhibition is deferred until equipment failures begin, corrosion is probably
serious in many wells. This can result in widespread premature equipment
failures, requiring replacement, before the corrosion control program can
effectively protect equipment.
The following summarizes information and "Rules of Thumb" that can be
used to evaluate corrosion in oilwell operations. Various types of corrosion
inhibiting programs are detailed along with the other pertinent information.
Specific Champion Cortron inhibitors for the programs are listed in Chapter VI.
A. WATER CUT VS WATER WETTING OF WELL EQUIPMENT
Water Cut
0-25%
25 - 45%
45%& Up
Wetting Film On Eguipment
Oil (possible water leg)
Can be oil or water
Water
-13-
B. 1YPICAL CAUSES OF SUCKER ROD BODY BREAKS
With the exception of mill and metallurgical defects practically all breaks in
the body of sucker rods will be caused by conditions illustrated. The Bend
Damage will normally be at beginning of pin upset with break at a slight angle
with rod axis. Endurance Limit - See Item C.
STRESS CORROSION FAILURES
Corrosion Pits (many)
Fatigue Cracks
MECHANICAL DAMAGE TYPE
STRESS FAILURES
c. ENDURANCE LIMIT OF SUCKER RODS
A factor frequently overlooked in sucker rod failure analysis is the possibility
of the Endurance Limit having been exceeded. When a rod has a multiple
crack appearance as in Item B an Endurance Limit failure has occurred. All
steel items that undergo repeated stress reversals will eventually fail by exceeding the Endurance Limit. The curves illustrate the Endurance Limit for
a steel immersed in air and in water. Steel specimens for these tests have a
smooth surface without any apparent stress raisers. When immersed in water
the electrochemical reaction will develop minute pits that serve as stress
raisers to reduce the Endurance Limit.
Sucker rod design is based on the water condition with a stress reversal range
beyond the knee of the curve. With this stress range and a good corrosion
control program, at least 108 cycles should be possible before the Endurance
Limit is reached. When wells are pumping from gas drive reservoirs with less
than 25% water, the rods will be oil wetted and the curve for air will control
the Endurance Limit. With this condition, sucker rods will last for many years.
The picture is a typical example of an Endurance Limit failure.
Nicks, Dents, Scratches
Hammer Blows, Gouges
100
i
I
Fatigue Cracks
xr---
t;'
c
)
:e
Fatigue Cracks (many)
0
0
0
....
V
r-....
!!
x 1'10
60
\l~ l-
40
'"
Air
en
en
~en
iii
c
i!
f'.. "
....... 80
STRESS OR ENDURANCE
LIMIT FAILURES
""r--"
,"
);
r-\r--.
II
Water- V
20
10'
10'
I
~
I I
10'
I
II
!
10'
10'
10'
Rod Bend
..!
'~~I_~fJ&oo
~"
~.
~
0
0
.
.- . -"
~
, ..... , ~~.~ '.'..~
..... ,;
~
.
,
0,
",.
",
ENDURANCE OR FATIGUE LIMIT FAILURE
-14-
-15-
I
~
Number of cycles (log scale)
Stress Raising Crack
After Straightening
i
I
~
0
z
x
I-x
Ir
Of
BEND DAMAGE TYPE STRESS
RAISER FAILURES
:I
x
.
D. lYPICAL CAUSES OF SUCKER ROD PIN BREAKS
F. lYPICAL APPEARANCE OF SUCKER ROD COUPLING BREAKS
While corrosion as a cause of failure is extremely rare in sucker rod pins,
failures are frequent when the pin and coupling are not properly mated. The
principal cause of this is inadequate torque. This causes slight separation at
coupling and pin bearing surfaces with a slight bending. Under these conditions the threads act as stress raisers with failure occurring within the
threaded section of the pin. The following lists the various conditions for pin
failures. Failures in the undercut area are unusual except in thin wall couplings. When failures occur frequently in the pin threads, API RP llBR, Section 4 on Sucker Rod Joint Makeup gives the proper procedure to assure
adquate joint torquing.
With standard couplings the metal cross-sectional area is large compared to
other cross-sections of rod string components and corrosion failures are infrequent.
BREAK BEGINNING AT INTERNAL LOCATION
Tensile Break
(distorted cup-cone)
Rough Granular
(area of rapid separation)
CAUSE
Smooth Surface
(area of slow separation)
corrosion, wear,
Origin of Break
LOCATION
OF BREAK
handling damage,
manufaduri n9
defect
BREAK BEGINNING AT EXTERNAL LOCATION
Tensile Break
(distorted cup-cone)
Sucker Rod Pin
Rough Granular
(area of rapid separation)
Smooth Surface
(area of slow separation)
E. lYPICAL APPEARANCE OF SUCKER ROD BODY BREAKS
Except for case hardened rods, body breaks, including those at the beginning
of rod to pin taper, will invariably have the illustrated appearance. The size
of the smooth surface area reflects that until the area is reduced to where the
yield strength of the rod is reached the crack continually opens and closes
peaning the surface. Once the yield strength is exceeded only a few pump
strokes are required for complete failure and generation of the modified typical tensile cup/cone failure appearance.
Origin of Break
G. SLAG INCLUSION MILL DEFECT
Most mill and metallurgical defects require laboratory investigations for
?ete<:tion. Howev~r, slag ~clusion type defects as illustrated can usually be
Identified by field mspectIon. These occur when a surfaced slag inclusion is
brok~n an~ extended and pressed into the rod surface in the forming process.
The mcluslOns are generally spaced at approximately equal intervals either
'
in a straight line or a long radius helix.
Tensile Break
(modified cup or cone)
Rou h Gran ular
(area of rapid separation)
Smooth Surface
(area of slow separation)
Origin of Break
-16-
-17-
H. RULES OF THUMB FOR ESTIMATING CORROSION
I.
In most fields the initial water rate is low and corrosion protection is not required. However, in many fields it is obvious corrosion will eventually develop
and it is desirable to detect and inhibit as soon as possible. The following are
"Rules of Thumb" that have been used for early detection and beginning treating programs.
In fields where corrosion is anticipated it will begin when equipment is first
water wetted in the 25 - 45% range. With the use of a key well type monitoring program, using pH and corrosion coupon data, the critical water cut level
can be approximated. Depending on the size of the field select as key wells
(3-10) those with the highest water cut. These will generally be those with the
highest producing rate. With monthly measurements of pH's, coupon rate
and water cuts follow the block diagram procedure to determine when well
inhibition programs should begin.
1. RULE 1 - CORROSION COUPON DATA - 30 DAYS
FIELD PROGRAM FOR DETECTING CORROSION
Coupons Pitted - Corrosion Always Serious
COUPONS - GENERAL CORROSION
0-2MPY
2-5MPY
5&UpMPY
Mild Corrosion, Not Serious
Moderate Corrosion, Watch
Significant Corrosion, Treat
1- 2/YR
2& Up/YR
Mild Corrosion, Not Serious
Moderate Corrosion - Treat
Significant Corrosion, Treat
3. RULE 3 - pH MEASUREMENTS - FRESH SAMPLES
6.0 - 6.5
6.0 & Less
I
No Corrosion, Scale Possible
Mild Corrosion
Moderate Corrosion - Treat
Significant Corrosion - Treat
I
pH
6.0 TO 65
I
NOTE: With new strings, failures in first 3 months are probably mill defects
and should not be considered.
7.0& Up
6.5 -7.0
CORROSION POSSIBLE
I
pH LESS
THAN 6.0
2. RULE 2 - ROD STRING STRESS FAILURES
o-1/YR
WATER CUT
25% OR OVER
pH
OVER 7.0
I
I
CORROSION
PROBABLE
I
pH
65 TO 7.0
CORROSION
UKELY
I
CORROSION
CORROSION
UNUKELY
I~'~ALLOOAAO"ON OO~";
COUPON
DATA
I
COUPON
DATA
I
I
I
MORE'THAN
5MPY
LES,S THAN LESS THAN MORE THAN
5MPY
5MPY
5MPY
NO PITS
,ITS (3)
CORROSION ISOLATED CORROSION
UNUKELY CORROSION OCCURRING
(2)
CORROSION ISOLATED CORROSION
UNLIKELY CORROSION OCCURRING
LESS THAN
5MPY
NO PITS
I
LESS THAN
5MPY
PITS (3)
I
COlOSIO~
INHIBLON
PROGRAM DESIRABLE
I
(2)
I
I
I
CORROSION INHIBmON
PROGRAM PROBABLY DESIRABLE
4. RULE 4 - WATER CUT & pH
STEEL
WATER WET
WATER CUT
No
0 -25%
Possible
25% -45%
Possible
25% -45%*
Yes
45%- Up
Yes
45% - Up*
*- Possibility of Scale Formation
pH
pH
.!l:.1
1.:..!1.
X
X
X
X
-18-
CORROSION
No
Uncertain
Doubtful
Yes
Possible
1. Corrosion occasionally occurs above a pH of 7.0. Where field experience indicates possibility of corrosion.
2. When equipment becomes water-wet, corrosion will occur. Maintain a
planned monitoring program.
3. Check systems for air entrainment. If air entrainment is found,
eliminate and re-test.
-19-
J.
DECISIONS IN THE DESIGN OF AN INHIBITION PROGRAM
Once the start of significant corrosion has been detected the object is to
quickly control the attack with a cost eff~ctive inhibitin~ program. I~iti<l:lly
many programs are ineffective due to faIlure to recognize how filmmg mhibitors function and the required solubility characteristics in the well fluids
being produced. Another factor overlooked in older fields is the necessity of
a special treatment to quickly establish an initial film of inhibitor. Occasion:uly effective treatments are also discredited by faill!re to r~cognize ~hat e9Ulp ment corroded prior to the start of a program will contmue to fail. Failures
that occur during the first three months after beginning a program should be
discounted. These generally reflect either equipment that is already corroded
or with new equipment, damaging mill defects, not rejected in mill inspections.
1. Does well need to be cleaned? (NOTE 1)
2. What treating procedure should be used? (NOTE 2)
K TREATING PROCEDURES FOR PUMPING OIL WELLS
The following treating methods are only for rod pumped oil wells. When wells
are flowing, on gas lift or centrifugally pumped, other treating methods are
required.
Type of Treatment
Periodic Batch
Yes
Possible
Note 1
Periodic Batch With
Inhibitor Emulsion
Yes
Yes
Note 1
Continuous Injection
Yes
Yes
Note 2
Squeeze Treatment
Note 3
Note 3
Yes
Note 1:
3. What inhibitor should be used? (NOTE 2)
4. In batch and squeeze treatments what frequency is needed? (NOTE 3)
Note 2:
5. In batch and squeeze treatments what volume is required? (NOTE 3)
6. In continuous injection what rate is required?
7. What monitoring procedure is desirable or required? (NOTE 4)
NOTE 1: The metal must be reasonable clean to effectively film.
NOTE 2: Items 2 & 3 are interchangeable and the treatment will generally
dictate the type inhibitor or vice versa.
NOTE 3: Squeeze treatments may cause skin damage and are not recommended if other treating methods are possible.
NOTE 4: Monitoring should be for meaningful results and not require extensive field and laboratory time.
-20-
1YPE COMPLETION
Open
Tubing On
Annulus
Packer
Iii&!! Fluid Level Low Fluid Level
Note 3:
If operator is willing to unseat pump, either treating procedure
can be used down tubing. Also, if the water oil ratio is not excessive, weighted inhibitors QIay be possible.
Continuous injection is possible with a capillary tubing type completion. Downhole injection valves are also possible but field experience with these has been poor due to plugging of the valve.
Squeeze treatments should be recommended only as a last resort.
L. INITIAL FILMING PROCEDURES
When running new rods and/or tubing it is desirable to quickly establish an
inhibitor film. This will protect the tubing until the on-going treating program
films the equipment.
1. Running Tubing and/or Rods in Well
The objective is to place a batch of inhibitor at the top of liquids in well
so as to film rods and/or tubing as it is run. Use Cortrons in Chapter
VI, Standard Inhibitors-Semi-Weekly Batch.
a)
Running both tubing and rods.
Pump into casing: 2 gallons of inhibitor/1,OOO' of
tubing
b) Running rods only.
Pump into tubing: 1 gallon of inhibitor/1,OOO' of
tubing.
-21-
2. All Batch and Continuous In·ection Treatments
not required when Item 1 has been used)
The objective is to quickly film inside of tubing and rods to provide
protection until the batched or continuously injected inhibitor can circulate.
Wells that can be circulated.
Pump into annulus: 2 gallons of inhibitor/l,OOO' of
tubing.
Circulate once or twice.
Park inhibitor in annulus.
b) Wells that cannot be circulated.
Pump into annulus 2 gallons of weighted mhibitor/l,OOO' of tubing.
a)
2) Gallons of Inhibitor Required per Week
(BOD
+ BWD) x 7 days x 42 galslbbl x ppm Treating rate
1,000,000
Example: (30 BOD + 160 BWD)
@ 25 ppm = 190 x 7 x 42 x
~25~~ = 1.3 gallons/week
1,000,000
@ 35 ppm = 190 x 7 x 42 x ~3~5~ = 1.8 gallons/week
1,000,000
@ 50 ppm = 190 x 7 x 42 x _;;.;50;....._
1,000,000
= 2.6 gallons/week
3) Adequate Frequency of Treatment
3. Squeeze Treatments
Treatment down tubing.
Apply Item 1, b) to treat rods.
b) Treatment down annulus.
Apply Item 2, a) or b) at the rate of 1 gallon of inhibitor
per 1,000' of tubing.
a)
Period of treatments can very widely depending on corrosivity, water
oil ratio, tubing size and well deviation. Unless field experience has established the required treating period the following is recommended
as the initial program.
Producing Rate
Treating Period
Up to 150 BFPD
150 to 300 BFPD
300 to 800 BFPD
Every Two Weeks
Weekly
Twice Weekly
M.PERIODIC BATCH TREATING PROCEDURE
The theory of batch treating is that O?ce the ~ell equip~ent has bee~ filmed,
inhibitor batched into the annulus will feed mto the tubmg and contmuously
maintain the film on rods and tubing. The three requirements for an effective program are; A) Adequate Volume ofInhibitor, B) l\dequate Frequ~n­
cy of Treatment, and C) Assuring Inhibitor Enters Tubmg. The followmg
reviews each requirement.
=
(Barrels Oil
+ Barrels Water) per Day
4) Assuring Inhibitor Enters Tubing
Low Fluid Level Wells (1,000' or less)
1) Adequate Volume ofInhibitor
a) Pump one barrel of produced water down annulus.
Treating Rates
25 ppm for mild field corrosion
35 ppm standard Permian Basin Recommendation
50 ppm for severe field corrosion
ppm
BFPD
Gallons of Inhibitor
= 1,000,000 Gallons of Production
b) Pump required inhibitor volume.
c) Pump 1/2 to 1 barrel of produced water flush per 1,000' of depth.
High Fluid Level Wells (1,000' or over)
a) Pump required volume of inhibitor.
b) Circulate well at least once returning inhibitor to annulus.
c) If wells cannot be circulated, flush with one barrel of produced
water per 1,000' of depth. Depth measured to pump inlet.
l
-22-
-23-
N. PERIODIC BATCH WITH INHIBITOR EMULSION PROCEDURE
The theory in M and requireme.n~s for volut.ne .a~d fr~quency. of 1), 2), and
3) remains the same. The combmmg of t~e 1~~lbltor. m a semi-stable emulsion with the injection water assures the mhlbItor will fall.t~ the bot~om of
the tubing so that no overflush 4) is required. However, It ..S essential the
emulsion break by the time it reaches the bottom of the tubmg. Test as follows:
1. Combine inhibitor on a 1:1 basis with water used in injection.
(Use 4 oz. sample bottle)
2. Hand mix 50 times, a uniform emulsion should form.
3. Emulsion should break slowly with essentially complete separation in 4 hours.
o. CONTINUOUS INJECTION PROCEDURE
The theory of continuous injection is that inhibitor injected in~o the a?Du~us
will fall through the annulus oil and cont.in~lOusly enter ~he tubmg, mamt~n­
ing a film on the equipment. However It IS a!",:ays. deslra~le ~o. hav~ a Side
stream flush with continuous injection. Also mJectmg the mhlbltor mto the
flush piping is preferred.
Q. MONITORING OIL WELL CORROSION
The best way of determining the effectiveness of a corrosion control program
is the rate of stress corrosion failures occurring in a sucker rod string. A
properly designed string should operate for at least 108 cycles before Endurance Limit failures begin. Failures occurring before reaching this number of strokes are invariably due to the development of stress raisers. The
principal causes are mill and handling defects, rod bending, corrosion pits or
improper makeup. With careful inspection those due to corrosion pits can
readily be isolated.
1. Rod String Failure Analysis
In inhibited wells, with new strings, where rod failures due specifically
to stress corrosion have been isolated, the effectiveness of a corrosion
control program can be judged as follows:
FIRST YEAR
Corrosion
Control
Failures
1 Well
Failures
+S Wells
SECOND YEAR
Failures
1 Well
Base daily injection rate on oil + water per day.
1) Typical Field Corrosion = 25 ppm.
2) Permian Basin Corrosion = 35 ppm.
3) Severe Field Corrosion = 50 ppm.
P.SQUEEZETREATMENTPROCEDURE
This is the least desirable procedure and should be used only as a last res?r!.
In low permeability sand formations producti~n rates are often redu~d mltially and there are instances of permanent skm damage. In unconsohdated
sands producing through gravel packs, squeezes have destroyed the gravel
pack. 'The treatments are not effective in vugular porosity and have a poor
performance record in fractured formations.
Failures
+SWells
Very
Effective
0
0.5-1 Avg.
1
1-2 Avg.
Partially
Effective
1
1-2 Avg.
2
2-3 Avg.
Not
Effective
3-4
3-4 Avg.
Failure rates increase
and string replaced.
NOTE: New rod strings typically contain 3% to 8% rods containing potentially damaging defects. Generally rod failures occurring in the first 60 days
will be caused by mill or handling defects.
The following is one method for estimating squeeze treatments.
Q
=T
(.!'..-
Q =
T =
F =
G =
l
1,000
2. Corrosion Coupon Data
+
...Q...8)
Inhibitor in Gallons at 25 ppm Rate.
Life of Squeeze in Days
Total Fluid Production in BFPD.
Gas Production in MMCF/D
-24-
a) Installation and testing requirements.
Coupons must be where wetted by typical produced water.
Velocity should not be over 5 fps.
Minimum exposure period = 10 days.
Desirable exposure period = 30 days or more.
Preferred steel = 10/20 sandblasted, hot rolled.
-25-
b) Significance of Results
Corrosion
Control
30 Days
MPY
Very
Effective
0-2
Partially
Effective
2 - 5 To be considered effec-
IRON LOSS NOMOGRAPH
tive,coupons must be
free of pits.
Not
Effective
5&Up
3000
500
500
400
300
200
300
100
~
00
3. Iron Count Data
a) Significance of results with water cuts less than 25%.
Iron
Count
Corrosion
Control
2000
- - - - -_ _ _-1_30
20
100
EXAMPLE:
300 barrels
Iron Count
Iron Loss
10
Pipeline carries
of water daily.
= 200 ppm
= 21.0 Ibs/day
5
3
2
Very
Effective
Oto 50
50
40
0.5
Partially
Effective
50 to 150
30
0.3
0.2
0.1
150& Up
b) Significance of results with water cuts over 25%.
Iron counts must be interpreted on the basis of the attached
NOMOGRAPH. Any iron loss of over 5 lbs/day should be considered significant.
0.05
0.03
0.02
10
5
0.01
0.005
5
0.003
0.002
4
NOTE: The use of iron counts in oil production requires careful
sampling and analysis, particularly with sour production.
3
3
2
0.001
pounds of iron
removed daily
ppm-iron
R. IRON LOSS NOMOGRAPH
With the Iron Loss Nomograph it is assumed all of the Ferrous Ions dissolved
from the metal remain in solution and will reflect the actual weight of iron
removed from the well bore equipment. Providing there is no iron contained
in the formation waters and scaling of corrosion products is not significant,
the chart can be considered a reasonable approximation. Also when used as
a periodic measurement for estimating the effectiveness of the fIlming efficiency of the inhibitor, it is a good monitoring tool. However, it indicates
only total iron removed and cannot be related to a pitting attack. Single reading can be misleading and duplicate or triplicate samples are recommended
and the results from a series of periodic tests reviewed to establish a basis of
the significance of the readings.
-26-
30
20
20
Not
Effective
50
-27-
barrels
water per
day
LIMITING VELOCITIES
CHAPTER III
GAS/CONDENSATE WELL CORROSION AND PREVENTION
GENERAL
The flow stream of gas, condensate, and water from the reservoir through the
tubing to the surface separating equipment is a continually changing process
stream. The pressure, temperature, ratios of gas, condensate, water, and
velocity continuously changes. Furthermore, the composition of the water
changes as the formation water entrained in the gas is diluted by condensate
water separated from the gas, with reduction in temperature, as it flows up
the tubing. All of these factors can affect the type and location of corrosion
and should be considered in a corrosion control program. As previously
noted the basic cause of the metal loss is the electrochemical reaction. With
at least trace amounts of formation water always initially entrained in the gas,
another corrosivity factor frequently overlooked is the flow patterns for the
two phase flow variations with velocity changes. The velocity controls the slip
and holdup of the liquid in the gas stream and the degree of turbulence, all
of which affect the corrosivity. The following reviews the effect of these factors and corrosion inhibiting procedures for gas/condensate production.
Specific Champion Cortron corrosion inhibitors for the programs are listed
in Chapter VI.
WELL STREAM
CONDITION
TUBING PRESSURE
1,000 psi
5,000 psi
Wet
Non-Corrosive
Wet
Corrosive
Wet Corrosive
& Abrasive
-28-
50fps
40fps
30 fps
25 fps
B. CALCULATION OF APPROXIMATE TUBING VELOCI1Y
With single sized tubing strings the maximum velocity will be at the top of the
string and calculations for well head conditions will indicate maximum
velocity. However, with tapered strings the maximum velocity can occur down
hole. If down hole pressure conditions are unknown the curve below can be
used for an approximation of down hole pressures. The following will provide
"ball park" approximations suitable' for field evaluations of well operating
conditions.
TUBING VELOCI1Y IN FEET/SECOND
CFS GAS
The effectiveness of inhibition programs in high velocity gas wells is limited
by the erosive action of the flow stream. Continuous injection programs thru
capillary tubing or macaroni string are the most effective. Frequent batch
treatments with high surface tension, heavy film forming inhibitors may be
partially effective.
75 fps
NOTE: See Item C for effect of temperature and gas density.
A. THEORETICAL LIMITING VELOCITIES FOR TUBING
The following is for well streams entraining only minor amounts of formation
water and condensate water, liberated from the saturated gas with temperature reduction, total water not to exceed 5 bbls/MMCF. At the listed
velocities all corrosion product will erode and the attack will be general. For
the corrosive conditions failures due to metal loss will eventually occur, even
with inhibiting, due to the corrosion/erosion phenomenon.
85 fps
MSCFD
OR
=
= MSCFD x OR x Z =
Px3600
Cu. Ft./Sec.
Gas in Thousands of Cubic Feet per Day
= OF + 460° = Absolute Temperature
Z
=
Compressibility Factor
P
= Operating Pressure in psi
NOTE: Disregard Z for pressures of 1,000 psi or less. When Z is unknown,
for pressures over 1,000 psi, use 0.9.
Gas Velocity in Feet/Second
=
CFS
Tubing Area in Square Feet
-29-
1. APPROXIMATE BOTTOM HOLE PRESSURE OF GAS WELLS
.10
:I:
~
Q.
w
Q
C)
.09
.08
PRESSURE
PSI
150°F
1,000
2.97
2,000
5.93
DENSITIES @
200°F
250°F
300°F
2.74
2.55
2.38
5.48
5.10
4.76
3,000
8.90
8.22
7.65
7.15
4,000
11.87
10.96
10.19
9.53
5,000
14.84
13.70
12.75
11.91
iii .07
6,000
17.80
16.45
15.29
14.29
u. .06
7,000
20.76
19.19
17.84
16.67
z
~
~
0
~ .05
'wCo
~
.04
w .03
en
c(
w
a: .02
0
~
.01
EXAMPLE
T.H.P. 3000 psi - Depth 9000'
Factor 3000 psi
.07 psi/ft.
C.I.S.H.P.
3000+(.07X9000)
C.I.S.H.P. = 3630 psi
=
=
0
12345
CLOSED IN TUSING HEAD PRESSURE - psi X 1000
DENSITY· POUNDS PER CUBIC FOOT
C. CORROSM1Y VS LIMITING VELOCI1Y & DENSI1Y
D. PHASE RELATIONS OF GAS AND LIQUIDS IN TUBING
The limiting velocity in a gas/condensate well defines the fluid flow rate above
which the rate of metal loss by abrasion will result in a markedly premature
failure. In wells where the water is non-corrosive all metal loss will be due to
abrasion of the steel by the entrained water droplets. When the water is corrosive the limiting velocity is lower due to rapid erosion of the corrosion
product, exposing clean steel with its higher susceptability to corrosion attack. This rate is further reduced when the flow stream entrains formation
fmes which are frequently hard sand particles.
The relative volumes of gas, condensate and water vary from the formation
face to the well head. Also as the gas expands with reduction of pressure the
velocity is continually increasing. The velocity will determine the flow patterns and in combination with the volume of liquids establishes the extent of
liquid holdup. The slip and holdup dictate that the tubing wall will be wetted
over the entire length of the tubing and at lower velocities result in a water
leg buildup, with gas flowing as bubbles or small slugs through the buildup.
At higher velocities, usually over 10-15 fps, all water and gas remain
entrained. Within the gas stream the liquids will be in the spray form and
there will be a film of liquid on the tubing wall. The thickness of the film will
be a function of the velocity and rate of liquids being produced. From corrosion consideration, with the continuous water wetting of the tubing, C02
and/or H2S present in the gas and the limiting velocity are the items of concern. The following is an overview of Flow Patterns and Slip and Holdup factors for consideration in designing a corrosion control program.
The table lists approximate densities at various temperatures for a typical gas
entraining only traces of water (± 5 bblsIMMCF). The curves give maximum
allowable velocities for three conditions. For the corrosive/abrasive condition the limiting Velocity can be increased with a good corrosion control
program. However, the corrosive limit of velocity would be considered maximum for maintaining an inhibitor film for any batch treating type program.
-30-
-31-
1. FLOW PATTERNS IN TUBING
The flow pattern illustration is for ambient temperature and low pressure.
While the flow patterns are considered typical, the velocities at which they
occur would vary somewhat with the density of the gas. The range of flow patterns for typical gas wells are indicated. With flows in the Slug Flow regime
down hole water legs would be anticipated. As noted the Annular Mist Flow
develops in the 40 to 50 fps range, where as noted in Item C, the Limiting
Velocities are predicted. The term superficial velocity is defined as the
velocity of a phase in a multi-phase flow stream calculated as though it were
the only phase present.
From corrosion considerations, the presence of water not its volume, is the
critical factor. As noted in Item 1 - Flow Patterns, water will be continuously
present. At low velocities the Holdup will dictate the length of the water leg,
in gas well depletion periods or with low formation pressures, the buildup may
result in killing of the well. A major consideration in inhibiting treatments for
wells with water legs is designing a treatment that assures displacing of the leg
and filming of the tubing covered by the water leg. The following curve illustrates the typical holdup conditions for ambient temperatures and low
pressure. While the range for typical tubing is indicated literal interpretation
would not be representative of gas wells.
500.-----..----,------.--,-----.--",
SLUG
~
FROTH
c
FLOW PATTERNS
Superficial Water Ve
VSL • ftlsec
IIIIIIIIIIIIIIIIIII
c
A
D
n
li [J
>
......
u
V\
....a.
W
....
ex:
0
......
Q)
r
01
w
to
~
a::
:=I
V)
0.1
.. ,-.
)?:~
-
;.~
........
x:
";j:'jf,::'-
L
\'F;,
10.
c
c
ex:
HOLDUP
RATIO:
~
.
~
/
~
tt:
0.
"'0I"
10~--~~~~-~-~~-T_~-~~
.~
/ /
tI
10.0.
When phases differ in density and/or viscosity the lighter
phase tends to flow at a higher in-situ average velocity.
The in-situ volume fraction ratio of the heavier phase to the
lighter phase in the flow stream.
/
'l/ /' / .....
. ~. :-..~
Range in Typical Tubing
SUPERFICIAL GAS VELOCITY - ft./sec.
-32 -
/
c5
/
Ii:
:n
;::
:/:J;-/
2. SLIP AND HOLDUP IN TUBING
The Slip and Holdup phenomena that is inherent in any multi-phase flow in
vertical pipe is frequently overlooked in evaluating gas well corrosion. These
factors can be defined as follows:
SLIP:
I
.\~:~
::J
I I I
10.
G
'
to
V)
/
/
.. '"!'!r.'~~'
[J A
.
a:: c
3
0
V\
01 ,
::J
3
F
....
lJ...
a:: 0
0.01/
100
lJ...
0
-
W
E
"'0:
3
0
...J L.n
:>
0
ity
~ ..:.;;;;:.-_
0
' .'
-
'f..--
10
10 Tubing
Range of Typical
Superficial Gas Velocity, VSG+O.1,fVsec
E.
GAS/CONDENSATE WELLS WATER PRODUCTION
The geologic processes that resulted in the forming of gas reservoirs dictates
that all produced gas will entrain water. The water will be of two types. Formation water stripped from the water wetted reservoir rock and condensate
water that evolves from the water saturated gas. The formation water composition can vary widely dependi?g upon ~hether the w~ter.in the ori~nal
sedimentary basin was fresh or sahne but wdl always contam d1ssolved sohds.
Condensate water is always solids free. The composition of the produce?
water will be a function of the ratio of the two types of water. The compOS1tion of the water may vary widely over the producing life of a we~l depend~ng
on the type of reservoir. The corrosivity of the produced water 1S a functlon
of the acidic components (H2S and/or CO2) contained in the gas stream. The
following reviews the water production sequence in typi~al gas depletions.
These are based on the initial production from completlons above the gas
water interface zone in the reservoir.
-33-
1. GAS EXPANSION RESERVOIRS
Depending on depth, pressure and temperature of the reservoir the water
production will be in the range of 1 to 3 bbls/MMCF throughout the life of
the well. Initially the water will be principally condensate type with a low
salinity. As the well depletes the amount evolved from the gas decreases and
the amount of formation water stripped from the reservoir increases. In the
later stages of depletion the composition will approximate that of formation
water. As pressure and gas flow decrease, water legs develop, eventually killing the well.
2. WATER DRIVE RESERVOIRS
Depending on permeability, the well pressure may remain relatively high, and
until water enters the well bore the rate and composition will be identical to
that in a gas expansion reservoir. With a water drive intrusion the water rate
will markedly increase and the composition approximate that of formation
water. If the water intrusion is due to permeability stratification, gas production may continue at a reduced but economic rate for a considerable period.
When the producing interval is thin or of relatively uniform permeability, the
well may water out quickly.
3. MOBILE WATER TABLE RESERVOIRS
Production history is similar to a gas depletion reservoir until the pressure
drops and allows water entrainment from the water table. Rate of water increase is frequently slow and can occasionally be stopped and reversed by
reducing the gas producing rate. Water composition will approximate that of
formation water. The well will water out, the time being a function of formation characteristics.
F. RULES OF THUMB FOR ESTIMATING CORROSION
1. RULE 1 - PREDICTING CORROSION - ALL WELLS
SOUR GAS
H2S - 250 ppm & Up
pH - 6.5 & Less
COUPONS
COUPONS
SAND,ETC
WATER
VELOCITY
SWEET GAS
C02 - 7.0 PSI P.P. & Up
pH - 7.0 & Less
Fe - 100 ppm & Up
Pitted
5MPY&Up
Any
2BBLS/MMCF & Up
25FPS& Up
NOTE: Wells showing any two potentially corrosive.
2. RULE 2 - PREDICTING CORROSION - SWEET GAS WELLS
(With C02 Partial Pressure over 7 psi)
WATER
PRODUCTION
BBLS/MCCF
CHLORIDE
CONTENT
PPM
IRON
COUNT
PPM
POSSIBILITY
OF SERIOUS
CORROSION
NO
±2
0-250
± 50
±2
0-250
50 -150
POSSIBLE
±2
0-250
150& UP
PROBABLE
2-5
250 - 500
2-5
250 - 500
50 -150
PROBABLE
2-5
250 - 500
150& UP
YES
5&UP
500& UP
150& UP
YES
±50
POSSIBLE
3. RULE 3 - PREDICTING CORROSION - SWEET GAS WELLS
Serious down hole corrosion and failures were first encountered in domestic gas production in the late 30's and early 40's. By the mild 40's failures were
wide spread, occurring in both sweet and sour gas producing areas. Field
conducted studies to determine the cause of the failures were wide spread.
Many of these were trial and error type studies based on relating field failures
with well operating conditions. The following are different "Rules of Thumb"
that evolved from this empirical data. Years of experience have established
these are all valid procedures and are still widely used.
-34-
a. A part~al pressure of C02 above 30 psi usually indicates
corrosIOn.
b. A part~al pressure of C02 between 7 and 30 psi may indicate
corrosIOn.
c. A partial p~essure of C02 below 7 psi is considered
non-corrOSlve.
-35-
4. RULE 4 - PREDICTING CORROSION - COUPON DATA
COUPON
REPORT
MPY
EXPOSURE
PERIOD
DAYS
TYPE
ATTACK
POSSIBILITY
OF SERIOUS
CORROSION
0-5
30 Min.
General
No
0-5
30 Min.
Pitting
Yes
5 -lO
30 Min.
General
Possible
5 -lO
30 Min.
Pitting
Yes
lO&Up
30 Min.
Any
Yes
H. PROCEDURES FOR INHIBITING GAS WELLS
The following six procedures have all been successfully used with the (1)
Batch method (where applicable) being the most cost effective. The (2) Batch
with a Wireline Brush assures uniform filming and is particularly advantageous in deviated wells. The (4) Tubing Displacement is an excellent
procedure where wells have a large ~ater leg t~at must be ~ispla~ed to totally film the tubing string. The (5) CapIllary Tub10g and (6) Kill Stnng are both
excellent methods but require large well bore equipment investment. The (3)
Batch Squeeze and (7) Injector Valves are the least desirable. Squeezing can
cause skin damage with a period of decreased productivity and in gravel pack
completions, can disturb or de~troy the pack. Inj~ctor y alves f~e9uentl~ plug
due to mud solids or other solIds or scales entramed 10 the dnll10g flUids.
1. Batch
2.
3.
4.
5.
6.
7.
G. DECISIONS REQUIRED FOR INHIBITING PROGRAM
1. What inhibitor should be used? (Note 1)
2. What treating procedure should be used? (Note 1)
3. In periodic treatments what volume is required?
4. In periodic treatments what frequency is required?
5. In continuous injection what rate is required?
6. What monitoring method should be used? (Note 2)
I.
Batch with wireline brush.
Batch Squeeze - liquid or nitrogen.
Tubing Displacement.
Capillary tubing - batch or continuous
Kill string - batch or continuous
Injector valves - batch or continuous
TREATING RATES FOR GAS/CONDENSATE WELLS
The following batch treating rates are based on field experience in typical corrosive wells where the rates do not exceed the limiting curve (in Item C).
Where these velocities are exceeded a continuous injection procedure will
provide partial inhibition.
1. BATCH TREATING PER 5000 FEET OF 2" - 3" TUBING
NOTE 1: Items 1 & 2 are interchangeable. The inhibitor will usually dictate
the treatment or vice versa.
NOTE 2: Monitoring should be for meaningful results and not require extensive field and laboratory time.
RATEMMCF/D
0-2
2 -5
5 -10
10&Up
INHIBITOR GALS.
25
25
25
25
INTERVAL MONTHS
3
2
1
1/2
NOTE 3: Squeeze treatments may cause skin damage and should not be
recommended if other treating methods are possible.
OPTIMUM RUN DOWN TIME - 1 HOUR/lOoo FEET.
MINIMUM RUN DOWN TIME - 1 HOUR/15oo FEET.
DILUENT WHEN REQUIRED - 1;1 TO 1:4 INH. TO DILUENT.
PRE OR OVERFLUSH WHERE REQUIRED - 2 TO 10 BBLS.
-36-
-37~
'I'I
2. CONTINUOUS INJECTION RATES - 2" - 3" TUBING
(capillary tubing, kill string and injector valves)
LOW GAS AND WATER RATES -1/4 TO 1 PINT/MMCF.
CHAPTER-IV
PIPELINE CORROSION AND PREVENTION
LOW GAS & HIGH WATER RATES - 50 TO 100 PPM
INHIBITOR IN PRODUCED WATER.
HIGH GAS & LOW WATER RATES - 1 PINT TO 1
QUART/MMCF.
HIGH GAS & HIGH WATER RATES - 50 TO 100 PPM INHIBITOR IN PRODUCED WATER OR 1 QUART/MMCF.
3. SQUEEZETREATMENTVOLUME
Q=T
_F
(1,000
+~ -
G)
8
WHERE: Q = INHIBITOR IN GALLONS/25 PPM RATE
T = LIFE OF SQUEEZE IN DAYS
F = TOTAL LIQUID PRODUCTION IN BBLS/DAY
G = GAS PRODUCTION IN MMCF/D
J.CORROSION CONTROL IN WELLHEADS AND DOWNHOLE
EQUIPMENT
The corrosion inhibiting treatments are designed for tubing strings with only
minor diameter changes. Wellheads, storm chokes and seating nipples have
locations of marked diameter changes or changes in direction of flow. These
non-conformities create zones of high turbulence where inhibitor films will
be quickly eroded, causing locations where corrosion/erosion occurs. The
rate of metal loss under these conditions can be severe resulting in rapid
failure.
The velocity creating a level of turbulence for the corrosion/erosion
phenomenon is uncertain, being a function of the configuration of the discontinuity. Field failures indicate it will generally be in the 15-20 fps range.
When velocity at the top of the tubing is within this range the use of stainless
steel or equipment components with stainless type overlays are recommended. All wellhead manufacturers can supply corrosion resistant equipment.
The corrosion/erosion problem is also frequently encountered down hole on
both sides of storm chokes and seating nipples. When velocities at down hole
locations across non-conformities are in the 15-20 fps range, stainless steel
subs at least 3 feet in length should be installed on both sides of the location
of high turbulence. The alloy usually recommended is 410 stainless steel.
-38-
GENERAL
As with all metal loss corrosion the occurrence in pipelines is controlled by
the electrochemical reaction. This dictates the presence of water and the
water wetting of the pipe wall. With this condition satisfied the electrochemical reaction will occur. However, the rate of metal loss and type is controlled by other factors. A pitting type attack can be caused by mill scale, slag
inclusions or slugs, improper heat treatment, heat run out zone effects or use
of unsuitable welding rod. The corrosion/erosion effect can be caused by too
high fluid velocity. Water and sludge buildups will develop with too Iowa
flUld velocity that may cause pitting and bacteria infestations. With low
velocity water, sludge segregatIon invariably occurs and scheduled pigging
programs are desirable. The rate and type of attack is also a function of the
corrodents present. When corrosion is not controlled, depending on wall
thickness and operating conditions, time to first corrosion type failure will be
from three to twelve years. However, with a well desigIled corrosion inhibition program placed 10 operation"at the same time the line is commissioned,
corrosion failures can be prevented indefinitely.
The following reviews the effect of these factors and inhibiting procedures
for pipelines. Specific Champion Cortron corrosion inhibitors for the
programs'are listed in Chapter VI.
A. FREQUENT CAUSES OF INTERNAL CORROSION IN PIPELINES
NOTE: Welds and heat affected zones are areas of high electrochemical
potential and subject to an accelerated pitting type attaCk. Inhibiting with a
heavy film forming inhibitor is desirable.
I{
COLD - COLD PASS
HOT - COLD PASS
HEAT RUN OUT
WRONG ROD
IMPROPER
WELDING
TOO HIGH
TOO LOW
VELOCIlY
INADEQUATE _ __
PIGGING
{
SCALE BUILDUP
LIQUID BUILDUP
BACTERIA GROWTH
INHIBITOR
{
WRONGlYPE
LOW VOLUME
-39-
,It
B. FLOW PATIERNS IN PIPELINES
With all oil, gas and refinery pr<?ducts, uJ:.ltil de.hy<!rated to b.elow the de~­
point temperature encountered In operations, lIqUId water will evolve. This
evolves as a minute droplet dispersion that on contact coalesces into larger
droplets. Except for crude oils of 10 API gravity or lower the water will tend
to gravity segregate to the bottom of the pipeline. In pipelines the velocity is
the controllIng factor, since in combination with the fluid being tra!lsported
it determines the degree of turbulence that controls the extent to whlcli water
segregation will occur.
Once the pipe wall is water wetted, the electrochemical reactio.~l i.e. corrosion, begins. Generally, when segregation occurs, corrosion will be most
severe along the bottom of the pipe. In some systems the metal loss is further
intensified on the up-dip side of low spots where the fluxing of the water can
develop the corrosIOn/erosion condition.
7 FPS& Up
All water remains suspended as droplets in oil stream.
NOTE: Tendency of water entrained in oil stream to water wet pipe is a function of oil gravity and surface tension. Assume that with oil gravity under 40°
API, pipe IS oil wet; and over 40° API, pipe is water wet.
The following are conservative "Rules of Thumb" that can be used to approximate Flow Patterns and degree of water segregation.
2. WET GAS LINES - (WATER: TRACE T05 BBLS/MMCF)
1. CUSTODY TRANSFER OIL LINES - (WATER: TRACE TO 2%)
0-31/2 FPS
All water drops from oil and flows to low spots building up pools. As area
over pool is reduced, water becomes turbulent and is displaced up dip. Eventually a slug is stripped from pool and flows with oil. Pool flows back to bottom of dip and repeats build-up.
:;::E'" ';:::. ___~O
Em NO
0-71/2 FPS
All water quickly drops from gas stream flows to low spots and builds up
pools. As area over 1'001 is reduced, water becomes turbulent and is displaceo
up dil'. Eventually slug is ~tripped fr.om t?P of pool and flows with gas. Pool
flows back to bottom of dip and agambUlIOs up.
E DRY :::;7~
';::_---0
/
DORMANT POOLS
/
DORMANT WATER POOLS
71/2 -15 FPS
31/2 -7 FPS
A velocity range of uncertainty. The extent to which water remains suspended
as droplets depends on oil gravity, viscosity and droplet size. The higher the
gravity, the greater the tendency of water segregation.
Most water drops from gas stream and collects in turbulent pools on up hill
side of dips. Slugs are stripped from tops of pool and flow with gas. Minor
spray flow persists with droplets continuously wetting pipe waIl and entering
pools and being stripped from pipe walls ana pools and entering spray.
SP.ZtZ,;:;:,,<
7112 -15 f .p.s.
{IMiNOR
AGITATED POOLS
AGITATED WATER POOLS
-40-
-41·
~~_ _-:--~
0
""
1.
15 - 25 FPS
APPROXIMATE ° R FOR BURIED OR SUBMERGED PIPELINES
Water dropping out forms a continuous flowing stream along bottom of pipe.
Minor} turbulent pools build up on up hill side of dips with frequent small
slu,g displacement. Continuous spray with water alternately depositing and
belOg stripped from pipe walls and stream.
15 -
-e;SPRAY; :'~'''
'
-:. .
.- > .'
.-
South of Denver, Colorado ° R = 520°
Denver to Canadian Border ° R = 510°
North of Canadian Border
° R = 500°
25 f.p.s .
~···:'··:~· <:'hn
. :':: ':~
:. ~
••
' _.,fir
..............
SMALL
AGITATED
POOLS
~.
CONTINUOUS
STREAM
NOTE: With only trace amounts of water, above 15 FPS velocity all water
remains in spray regime.
25 FPS& UP
All liquids remain in spray regime, continuously wetting and being stripped
from pipe wall.
2.
APPROXIMATE PIPE AREAS IN SQUARE FEET
(Based on nominal diameters)
Diameter
Ins.
Area
Sq.Ft.
Diameter
Ins.
Area
Sq.Ft.
2
.0218
12
.7853
3
.0490
16
1.3963
4
.0872
20
2.1817
6
.1963
24
3.1416
8
.3491
30
4.9087
10
.5454
36
7.0685
NOTE: Calculations give order of magnitude velocities suitable for use with
FLOW PATTERNS 10 pipelines illustrated in Item B. With two phase lines
always include gas volumes, however when CFS (liquid) is less than 5% of
total fluid volume, it can be deleted from gas velocity calculations.
c. APPROXIMATE VELOCITIES IN WET GAS PIPELINES
Liquids in cubic feet/second
=
BWPD
+ BOPD
=
CFS
Gas in cubic feet/second
MSCFDXOR
PX3060
Velocity in feet/second
CFS (Iiq.) + CFS (gas)
Pipe Area in Sq. Ft.
=
BWPD = Barrels of water per day
BOPD = Barrels of oil per day
MSCFD = Gas in 1,OOO's feet/day
OR
=oF+460°
P
CFS
=
=
D. EVALUATION OF CORROSION POSSIBILITIES IN PIPELINES
15400
CFS
As noted in GENERAL: with water present in the fluids in a pipeline, the
electrochemical action will occur if the 'pipe wall is water wetted. The extent
to which this may cause serious corrOSIOn, will be a function of the electropotential and the corrosivity of the fluids. With water wetting in the weld area
some corrosion should always be anticipated. In any major or critical
pipeline, if water is known to be present, initial inhibiting of the weld areas
IS aesirable.
In new lines where corrosion is anticipated, inhibition should begin when the
line is placed in operation. Generally new lines will operate a minimum of
three years before the first corrosion failure. However when corrosion of the
pitting type has occurred and corrosion products are of the scaling, encapsulating type, controlling corrosion with an inhibitor program may not be possible, unless the line is thoroughly cleaned.
psi operating pressure
Cubic feet/second
-42-
-43-
Flow patterns in Pipelines, Item B, are "Rules of Thumb" for water wetting
in pipelines. In operating lines where corrosion is known to be occurring, the
fonowing listing indicates factors for review prior to determining the
desirability of an inhibition program.
b. OPERATING OIL PIPELINES
Pig line with batching pig to remove any water or sludge build-ups,
then clean line with a cleaning type pig.
A. An estimate of present condition of line with regard to internal
corrosion.
B. Required operating life of system.
Option 1:
If sludge in receiving trap shows large amounts of corrosion product, repeat cleaning run with pig.
Option 2:
Displace 50 to 100 foot slug of alcohol between two batching pigs to dry line.
C. An estimate of cost of line repairs or replacement.
D. Practicality of various type treatments.
c. OPERATING WET GAS PIPELINES
E. Importance of maintaining uninterrupted operation.
Pig line with batching pig to remove any water build-up, then clean line
with cleaning pig.
E. GENERAL ITPES OF INHIBITING PROGRAMS FOR PIPELINES
The following treatments can be applied in many systems. However where
the thru-I?ut IS large and variable, With multiple laterals either delivering to
or supplymg line, or where the line is looped, a design study is desirable. In
large complex systems the specifics of operations may dictate multiple treating procedures. Also in complex system a design study invariably results in a
more cost effective program.
Item 1. outlines pipeline cleaning procedures. The importance of adequate
cleaning cannot be over emphaSized. Filming inhibitors function by establishing a film of an electrical insulating matenal between the water and the
steel, stopping the electrochemical reaction. This requires intimate contact
between the inhibitor and steel and filming the steel surface is mandatory to
assure corrosion control.
1.
PROCEDURES FOR CLEANING LINES PRIOR TO INHIBITING
If sludge in receiving trap shows large amount of corrosion
product - repeat run with pig.
Option 2:
Using cleaning pig, displace cleaning solution thru line.
Use surfactant mixed with fresh water at a 1: 10-20 dilution ratio. Size miXture for a 50 - 100 feet slug in line.
Option 3:
Displace alcohol slug between batch pigs to remove film
of cleaning solution. Size slug for 50 - 100 feet of line.
d. OPERATING DEHYDRATED GAS PIPELINES
NOTE: Lines that have not been frequently pigged may have build-ups of
spent glycol or dessicant dust.
Using bat ching pig, disl?lace surfactant cleaning solution through line. Mix
with fresh water at dilution rate 1: 10-20. Size mIXture for 50 - 100 foot slug.
a. NEW PIPELINES:
After displacing of test water, blow line down to remove any by-passed
water. Then pig line with cleaning type scrapper.
Option 1:
Option 1:
After scraping, using a bat ching type pig displace alcohol
slug through line to remove water film and that trapped in
weld blowouts and crevices. Size slug for 50 to 100 feet of
line.
-44-
Option 1:
2.
If history indicates any water drop out or that corrosion
has occurred, clean line with cleaning pig run.
INHIBITING OIL PIPELINES BY CONTINUOUS INJECTION
Oil pipelines are of two types. Field lines between the wells and tank batteries' ,generally flowing oil, gas and water. This flow will be turbulent at
velocities of 3 1/2 fps and over. ~en water c}lts are 25% or less, C?il. or gas
will be the external phase and senous corrosion would not be antiCipated.
However, when water cuts are over 25%1 the piping will probably be water
wetted, and regardless of velocity, corrosion may occur.
-45-
The objective in the tank battery processing is to p!~duce Custody Tr~sfer
oil. The usual specification for Custody Transfer oil IS BS&W content m the
1 to 2 percent range. Water and oil distribution in these lines is ~hown in Item
B, 1. All lines having velocities ofless than 7 fps should be considered potentially corrosive.
Fluid phases and flow characteristics in these field and transmission lines are
significantly different, requiring different type inhibition programs. These
programs are described below.
a. INHIBITING FIELD TRANSMISSION LINES
OBJECTIVE: To combine water soluble inhibitor with produced water
and film all surfaces of system contacted by water.
PROCEDURE: Continuously inject inhibitor at beginning of line at a
rate to establish a 50 to 100 ppm residual in water at terminal of line.
After inhibitor residual has stabilized the injection rate can be reduced
until a residual in the 25 to 50 ppm range has been established.
TREATING RATES FOR 50 PPM INHIBITOR RESIDUAL
Water Rate - BID
100
200
300
400
500
Inhibitor Rate-ptslD
1.4
2.8
4.2
5.6
7.0
h. INHIBITING CUSTODY TRANSFER LINES
OBJECTIVE: To combine water soluble inhibitor with BS&W so that water
that collects along the bottom of the pipe will contain a sufficient concenration of inhibitor to continuously film water wetted pipe.
PROCEDURE: Continuously inject inhibitor at beginning ofline at a rate to
establish a 250 ppm residual at the terminal of the line. When monitoring
proves corrosion is controlled injection rate can be reduced.
TREATING RATE FOR 250 PPM INHIBITOR RESIDUAL,
BASED ON 2% BS&W
Oil Rate - BID x 1000
20
40
60
80
100
Inhibitor Rate - galslD
1.4
2.8
4.2
5.6
7.0
3. INHIBITING WET GAS PIPELINES
Gas pipelines are of two types. Wet gas field gathering and transmission systems and transmission lines for dehydrated sales gas.
The field systems in large operations can be quite complex with many
laterals of different sizes with large differences in producing rates. The
lines can also vary widely in the rates of water production and occasionally in composition of the gas. Generally these operations require a design study to determine the best inhibition program both
from corrosion protection considerations and cost effectiveness.
The following describes three types of corrosion inhibition programs
that have been extensively applied in wet gas pipelines, and an optimum program where a maximum corrosion inhibition control is
desirable. The decision as to the type program will generally be dictated by the condition of the line, logistics with regard to line servicing,
pigging program, velocity of the gas and corrosivity of the fluids.
Of primary importance in inhibiting wet gas lines with velocities of less
than 15 fps is maintaining an inhibitor film on the bottom of the pipe.
The Type 1 program with a diligently applied maintenance program is
desirable for this condition. The inhibitor used for this type treatment
form heavy, tenacious films that are very durable. With new lines an initial filming treatment is always desirable to inhibit the weld areas.
In lines with velocities of 15 fps and over there will always be a spray
regime, with little or no build-up of water in the lower sector of the
line. Also as velocities increase erosion of the film applied in the Type
1 treatment increases and the continuous injection type program becomes more cost effective. The Type 2 program is frequently recommended for new lines.
Experience has established that for maximum inhibiting effectiveness
the corrosion inhibitors should be formulated for the specific treatment type. Also since the corrosion protection is based on a continuous film of inhibitor, the concentration of the inhibitor component
in the formula is critical. The programs reviewed in this chapter are
based on inhibitors specifically formulated for pipeline operations.
NOTE: With lines with low thru-puts batch treating can be used. Inject at
rate of 1.0 gallon per 10,000 barrels of oil transported between treatments.
-46-
-47-
I'
b. 1YPE 2 TREATMENT (CONTINUOUS INJECTION PROGRAM)
a. 1YPE 1 TREATMENT (BATCHING PROGRAM)
OBJECTIVE: To film the entire internal surface of the pipe with a corrosion inhibitor insoluble in the gas, condensate and water carried in
the system.
PROCEDURE: Mix the inhibitor with a carrier at a 1:1 to 1:4 basis and
displace through the line between two batching pigs. Recommended
carriers - diesel, #2 fuel oil, water free crude oil (± 30 API). Rate of
pig displacement not to exceed 5 mph.
MAINTENANCE PROCEDURE: (For repair of mm on lower segment
of line. Use 1/4 of initial treatment, push treatment through line with
one batching pig. Frequency of treatment is a function of fluids carried
and velocity.
"RULE OF THUMB" - INHIBITOR VOLUME CALCULATION
± 2 MIL FILM
OBJECTIVE: To combine water soluble inhibitor with entrained water
and coat all surfaces of pipe contacted by water. Also to establish and
maintain a sufficient concentration of inhibitor in water in pools or
flowing along bottom of pipe to assure all pipe surfaces are continuously inhibited.
PROCEDURE: Continuously inject corrosion inhibitor at beginning of
line. In low velocity lines used fogging type injecting jet.
NOTE: Where the volume of water transported in the gas in known or
can be reasonable estimated use injection rate shown below.
Where the volume of water transported with the gas is unknown, inject
inhibitor at 1 to 2 pints per MMCF of gas. When inhibitor residuals at
line terminal stabilize, adjust injection rate for recommended residual
in system.
INHIBITOR REQUIREMENTS FOR WET GAS PIPELINES
(For maintaing 100 ppm in water phase)
Gallons of Inhibitor = 3 X D X L
D = Nominal Pipe Diameter in Inches
L = Length of Pipeline in Miles
DAIL Y INJECTION RATE IN PINTS 1 bAY FOR 100 PPM CONCENTRATION
2
INHIBITOR REQUIREMENTS FOR INTERNALLY COATING PIPE
J
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GAS RATE - MMSCF 1 DAY
PIPE DIAMETER - INCHES
(Based on 1/2" wall thickness)
-48-
,-
\\ \ \ \\1'\' ,,~,
5 10
12
6
1
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en
<l:
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-49-
80
"
I",
90
100
c. ITPE 3 TREATMENT (SPECIAL CONDITIONS ONLy)
NOTE: This treatment is suggested only for low velocity lines where
neither Type 1 or 2 treatments can be applied. In line known to be
badly corroded or with sludge build-ups in low sections it may not be
effective. It has been successful in relatively clean wet gas systems.
OBJECTIVE: To establish and maintain a level of inhibitor concentration in water trapped in low spot of the system to assure all water
wetted surfaces are adequately ftlmed.
INITIAL PROCEDURE: Estimate the volume of water continuously
trapped in low spots in the system. In pipelines traversing a typical terrain the amount of water continuously entrained in the system for
velocities of 7 FPS or less would probably be 10 to 20 percent of the
line volume. Based on the estimated volume an initial batch of inhibitor
to establish a SOO ppm residual is injected into the line.
1,000 Barrels of water
=
± 17 1/2 Gallons of Inhibitor
PERIODIC BATCH PROCEDURE: At a 1 to 3 months interval batch
into the line a volume of inhibitor based on 1 pint of inhibitor per
MMCF of gas delivered during the time since previous batch. When inhibitor residuals in monitoring program stabilize, adjust volume of inhibitor batches for a 250 ppm residual.
d. OPTIMUM TREATMENT
In critical systems where maintaining delivery is mandatory or major
systems where serious corrosion and failures may have occurred, an optimum corrosion inhibition program may be required. This consists of a
thorough cleaning of the system as detailed in E, 1. A Type 1 treatment
is then applied followed by a Type 2 program. It is further recommended that the Maintenance Procedure detailed for the Type 1 treatment also be followed.
The Optimum Treatment has been used successfully in badly corroded
lines that have experienced corrosion failures, maintaining the lines in
continuous operations for extended periods.
F. INHIBITOR REQUIREMENTS VERSUS WET GAS VELOCIlY
The water s?luble inhibitors required for inhibiting wet gas lines function by
the abs.orp~lOn, de-absorption phenomenon. This requires a level of concentratIon m the water phase to assure frequent contact of the pipe wall by
the inhibitor molecules.
In low velocity lines, with water segregated in low spots, the movement in the
water will be principally by convection currents and the inhibitor concentration must be .hi~ to assure frequent contact of molecules with the pipe wall.
~s .th.e ve"ocI~ mcreas~s through laminar to the turbulent range the rate of
~hibltor Impmgement mcreases decreasing the amount of inhibitor required
m the water phase.
The f<.>llo~n~ ~i~ts the desired inhibitor residual in the water phase to assure
effectIve mhlbltIon for normal gas velocity ranges. The level of inhibitor is
determined by inhibitor residual tests conducted on water samples collected
at the terminal of the line.
INHIBITOR
RESIDUAL RANGE
GAS VELOCIlY
oto 7 FPS
2S0 - SOO ppm
ISO - 2S0 ppm
50 -ISO ppm
7to ISFPS
IS& UPFPS
G. INHIBITING SALES GAS PIPELINES
Sales gas is always dehydrated and will generally be stripped of most of the
LPG components a~d the Sales Gas is highly undersaturated with regard to
?ot~ :-vater and th~ hght~r hydrocarbon components. This dictates a special
mhlbltor formulatIon usmg a carrier that will not flash, i.e. dissolve, into the
~a~ stream. Attempting to apply typical inhibitor formulas will not only result
m madequate filmIng but also cause the heavy viscous inhibitor to gunk out
in the line.
'
~he pri~cipal objectives for inhibiting Sales Gas Pipelines is to assure protec-
tI.on In Instances of plant upsets and to assure government regulatory agenCI~S that all possible safety precautions are being taken to prevent pipeline
failures.
Sales Gas lines can be effectively protected with either a periodic Type 1
Treatment or a Type 2 Treatment.
-50-
-51-
1. lYPE 1 TREATMENT (SEE E, 3, A lYPE 1 TREATMENT)
NOTE: The film life of a Type 1 Treatment in a dehydrated system will
be long. With gas velocities of 25 FPS and less a minimum of three
years effective inhibition would be expected.
2. lYPE 2 TREATMENT (CONTINUOUS INJECTION PROGRAM)
OBJECTIVE; To entrain special inhibitor in gas, condensate or anyextraneous water that may enter the system.
PROCEDURE; Inject the special inhibitor through a fogging type jet
into the inlet of the pipeline.
1. CORROSION COUPONS - INSTALLATION REQUIREMENTS
NOTE: Unless located where coupons or probes are continuously water
wetted and maintained free of any scaling materials entrained in the pipeline
fluids, the results will be meaningless. Pipeline failures have occurred where
coupons and probes improperly located have indicated no corrosion was occurring.
The following lists operating conditions and locations where representative
measurements can be expected.
a. LEASE FLOW LINES
TREATING RATE: 1/4 to 1/2 pint per MMSCF
WATER CUT
NOTE: During periods of extended plant upsets or plant by-passing increase injection rate to 1 to 2 pints per MMSCF.
COUPON DATA MEANINGFUL
GAS >25 CU.FTJBBL
GAS <25 CU.FTJBBL
I
>25%
NO
YES
<25%
YES-?
YES
H. MONITORING CORROSION IN PIPELINES
YES - ? Dependenton water being external phase.
With all oil, gas and product lines, until the fluid is dehydrated to a dew point
temperature below the lowest temperature that will be encountered in the
pipeline, at least traces of water will be present. If the flow patterns indicate
the pipe walls will be water wetted, corrosion is possible and monitoring is
desirable. If corrosion is anticipated and an inhibition program started,
monitoring is necessary to assure the effectiveness of the treament.
It is particularly desirable in designing a monitoring program to recognize
and design for the type of isolated metal loss attack that may occur. Corrosion
coupons and the various probe type instruments indicate metal loss only at
the point of their location. Unless wetted by the entrained water the monitoring data obtained will be meaningless and misleading.
The two principal monitoring procedures used in pipelines are corrosion
coupons and water analysis. These are discussed below. The various probe
type instruments i.e. electrical resistance, linear polarization, galvanic and
hydrogen, subject to the same limitations as corrosion coupons, would be
equally effective.
b. CUSTODY TRANSFER LINES
NOTE: Dependent on sample pot mounted to bottom sector of line.
OIL
VELOCITY
0-31/2FPS
31/2-5FPS
5& UpFPS
COUPON MOUNTING LOCATION
IN LINE
IN SAMPLE POT
NO
?
NO
YES
YES
NO- ?
? - Depends on whether oil or water preferentially wets coupon.
c. WET GAS PIPELINES
NOTE: Coupons in wet gas pipelines must be located either in a spray
flow regime or where water collects. Where a sampling pot is required
it must be attached to the bottom sector ofthellne.
-52-
-53-
GAS
VELOCI'IY
COUPON MOUNTING LOCATION
IN LINE
IN SAMPLE POT
0-71/2FPS
71/2 -15 FPS
15& UPFPS
YES
YES
NO
NO
YES
YES
8.
LEASE FLOW LINES
NOTE: It is assumed in Lease Flow Lines that Flow Regime will be
either turbulent or pUlsating, and segregated flow will not occur.
Since iron count and CI- or salt reflect well conditions, only the pH
reading is considered significant.
Coupons mounted in the line at 15 & up FPS must be located to
prevent the corrosion/erosion effect.
d. INTERPRETING CORROSION COUPON DATA
NOTE: Minimum time requirement for coupon period is 30 days. Preferred
material 10-20 C, hot rolled steel, with light sand blast to clean and remove
all mill scale.
!!!!!.t.
0-5
0-5
5 -10
5 -10
10&Up
Pitting
COUPON RESULTS
Comment
Corrosion Level Not Serious
Corrosion Level Serious
Corrosion of Concern - Watch
Corrosion Serious - Inhibit
Corrosion Serious - Inhibit
NO
YES
NO
YES
Yes or NO
e. SALES GAS LINES
Corrosion Coupons Not Applicable.
2.
WATER ANALYSES FOR CORROSION POTENTIAL
NOTE: The measurements required for a corrosivity evaluation are pH, iron
count and CC or salt content. While water samples at both ends of a pipeline
are desirable, generally samples are obtained only at the terminal of a system
and the following is based on terminal samples.
For accuracy the pH measurements should be made on fresh samples at the
sampling site. When samples are transported to the laboratory for testing,
some of the acid gases evolve and reading will be higher. Laboratory pH
values should be reduced by 0.5 to 1..0 for more realistic values.
The water in either a Custody Transfer Crude or Wet Gas Pipeline should
be principally of the condensate type that evolves from the fluids with
temperature reduction. The salt content in the water should be > 500 ppm;
salt content over this amount indicates a carryover of produced water and
the iron count should be discounted since it reflects carryover of dissolved
iron from the production equipment.
-54-
pH versus Serious Corrosion
pH
0-25%
0-6.0
6.0 -7.0
7.0 -14
possible·
unlikely
unlikely
!Yi!l~r ~Yl
25%-45%
45&UP
possible •
possible *
unlikely
probable·
probable *
unlikely
*Where wells are inhibited, feed back of well treatments may protect
flowlines.
b. CUSTODY TRANSFER LINES
NOTE: Water content will normally pe under 2%. Unless velocity is
under 3 fps, most water will remain entrained. If water samples can be
obtained from the pig traps after pig runs, they can be used for pH
determinations and iron counts. The pH conditions noted in item (a)
are applicable. If iron counts exceed 100 ppm it indicates that isolated
corrosion is possibly occurring in the bottom of the line and corrosion
inhibition may be required.
c. WET GAS PIPELINES
NOTE: As indicated in "H, 1, c Corrosion Coupons - Wet Gas
Pipelines", provided coupons are properly located, corrosion can be
successfully monitored. However, water samples can always be obtained from sampling pots or separating equipment prior to the
processing plant and is the preferred monitoring method. Water
sample analysis in addition to evaluating corrosion can be used to
monitor the inhibiting program and the effectiveness of field separating
operations.
-55-
The following are data normally reviewed in water sample studies and
the significance of the numerical results.
d. WATER SAMPLES - CORROSION MONITORING
OXYGEN CORROSION IN PRODUCTION AND PIPELINES
GENERAL
NOTE: For 5 bbls/MMCF or less.
pH
0-7.0
7.0
7.0 -14.0
Water Corrosive
Water Neutral
Water Non-Corrosive
(scaling possible)
Iron
Count
ppm
0-50
50 -100
100 - Up
Minor Corrosion
Moderate Corrosion
Significant Corrosion
Chlorides
mgll
>1,000
1,000 - 5,000
<5,000
Low Carryover
Average Carryover
High Carryover
Daily
Water
Bbls/MMCF
>.50
.50 - 2.5
<2.5
Mostly Condensate Water
Condensate + Produced
Mostly Produced Water
e. WATER SAMPLES - INHIBITOR MONITORING
GAS
VELOCIIT
FPS
INHIBITOR
RESIDUAL
PPM
COMMENT
0-71/2
71/2 - 15
15- Up
250 - 500
150 - 250
50 -150
250 Minimum
200 Preferred
100 Preferred
f. MONITORING SALES GAS PIPELINES
There are no simple procedures for monitoring corrosion in Sales Gas
Lines. Calipering, Radiography, Sonies, Internal Inspection and Test
Spools have been successfully used.
-56-
CHAPTER V
Of all the corrodents that can be encountered in production and pipeline
operations oxygen is the most serious. Not only is the rate of general metal
loss and pitting type attack drastic, with either C02 and/or H2S also present
the rate of attack is further intensified. Fortunately neither formation waters
or condensate water contain oxygen. With well designed and carefully
operated production and in pipelines, air the source of oxygen, can be excluded and this type corrosion will not be a problem. However there are many
locations where air can enter the flow stream. When these are overlooked in
the design and operating procedures; oxygen corrosion is frequently encountered.
Water floods or produced water disposal systems are major problem areas
with regard to oxygen type attack. At all ambient temperatures, water contacted by air quickly dissolves oxygen to the level dictated by the temperature and pressure. All surface water for flood projects, whether fresh or sea
water, will be saturated with oxygen. The initial procedure in the use of these
waters is to remove the oxygen. In well designed and operated production
systems the production water separated for disposal will be oxygen free on
leaving the separator. If this water can be maintained oxygen free from
separation to the injection well head or point of disposal, corrosion can be
low and readily controlled. However, unless the possibility of air entrainment
is considered in design and operation, there are a number of locations where
air can enter the system and increase corrosion.
In designing water handling systems where oxygen or other corrosion is of
concern, the use of corrosion resistant materials and coatings should always
be considered. Corrosion resistant metals are avilable for valves, pumps and
most control equipment. Tanks, piping and fittings can be obtained in plastics or with coatings that are resistant to corrosion. While designs will be more
costly, when the time of anticipated operation is considered, the systems will
generally be more cost effective.
The following reviews typical locations of air entrainment in field operations
and procedures for control. Where control is impractical, oxygen scavenging
procedures are noted. There are also specific corrosion inhibitors available
for the control of 0 gen corrosion; however where possible the scavenging
methods are prefer ble.
-57-
A. AIR ENTRAINMENT IN OIL WELLS
When wells are producing with the annulus closed or high fluid levels, air
entrainment is improbable in the well bore. However, when wells are in the
stripper phase, operating conditions change; generally the annulus is open
and the fluid level is insignificant. Under these conditions the annulus fills with
air and defuses through the short oil blanket in the annulus. The oxygen then
enters any produced water at the bottom of the well bore and oxygen corrosion
can occur in all portions of the tubing string contacted by produced water.
This possibility can be prevented by closing the annulus. In cases where the
well produces traces of gas up the annulus, using a low pressure relief valve
or "U" tube arrangement on the annulus will essentially establish the same condition as to back pressure on the formation as achieved when producing with
the annulus open.
A more frequent source of air entrainment in wells that are operated in the
pumped off condition is the polish rod stuffing box. In this operating condition pump efficiency is low and a slight vacuum will occur at the wellhead
with each pump stroke. Typical polish rod seals are designed for internal
pressure on the seals. Unless the stuffing box seal is tight and will hold a
vacuum, air will intermittantly enter the well fluids. This type of leakage can
also occur in other packing type seals between the wellhead and flowline
check valve. It is important in stripper production that all wellhead connections and packing gland items be able to hold a vacuum.
B. AIR ENTRAINMENT IN TANKS
The produced water tank in the battery, unless protected with a gas blanket,
is the most frequent source of air contamination. While these tanks will
generally develop a thin oil blanket, this quickly oxidizes after which the
oxygen passes through the film and enters the water. A thick oil blanket, frequently replaced, is reasonably effective. However, the oil entrained in the
water is generally inadequate for effective blanketing. Gas blanketing the
tanks is the recommended procedure. This should be maintained at a pressure of several inches of water. The gas supply line must be large enough to
maintain the blanket pressure when the water is discharged from the tank.
Many lease vessels develop bottom layers of water and sludge. While this
water may be oxygen free, this is an ideal zone for sulfate reducer bacteria
incubation and growth. When bacteria are detected, periodic slug treatments
with a biocide will prevent bacterial corrosion.
C. AIR ENTRAINMENT IN TRANSFER AND INJECTION PUMPS
Pump installations are frequent sources of air contamination. This is generally caused by failure to recognize that for a given set of pumping conditions,
a pump will endeavor to deliver a specific volume of liquid. When the liquid
is not available at the pump suction in an adequate volume and pressure,
cavitation with accompaning partial vacuum occurs within the pump. Unless
packing glands on pump and adjacent valving are vacuum tight, air is drawn
-58-
into the system and the oxygen dissolves into the water. This source of air is
easily prevented when the following specific installation specifications are
followed.
a. Suction piping one size larger than size of inlet to pump
b. Valves to be through ported and full opening.
c. Changes in flow direction minimized.
d. Flow direction changes with 45° ells or long radius fittings.
e. Suction system as short as possible.
f. Maintain 6 to 10 feet of head on suction.
g. Apply surge suppressors on suction side of high speed piston pumps.
4. AIR ENTRAINMENT IN INJECTION SYSTEM
If ~ate~ is kept air-free through the injection pump and a positive pressure
mamtalOed to the formation face, air contamination will not occur in a pressure tight system.
The corros~on problem ~ost frequently encountered on the injection side of
the system IS ca1!sed by faIlure to seal mating components. The slightest seep
~roV1des a CO?tlOU~>US water phase between the atmosphere and the injechon. water which wIll quickly corrode·a joint. This is because oxygen dissolves lOtO the w~ter at the se~p ~nd diffuses·into the wetted joint section. While
t~e amount will not be a slgruficant quantity in the total injection stream, it
will create an extremely C?rro~i~e fluid in the: joint which quickly deVelops a
l~ak. Absolute pr~ssure-tIght jomts and seahng surfaces through the injection system are prlIDary requirements for trouble free operations.
E. POTENTIAL SOURCES OF AIR CONTAMINATION
PRODUCING
WELLS
PRODUCTION
FACILITIES
INJECTION
FACILITIES
Well Annulus
Polish Rod
Stuffmg Box
Wellhead Valves
Produced Water Tank
Inadequate Gas
Blanket
Inadequate Oil
Blanket
Transfer Pump
Piping
Transfer Pump
Shaft Seal
Water Well Annulus
Supply Water Tanks
Inadequate Gas
Blanket
Injection Pump
Manifold
Injection Pump Seals
Piping Joints & Seals
Water Meters
(Vacuum Only)
Wellhead Valves
(Vacuum Only)
-59-
F. AIR ENTRAINMENT IN WATER SOURCES
Injection waters are generally from wells, streams, lakes or oceans. Water
wells completed in deeper aquifers, far removed from their surface outcrops
are oxygen free. When completed to assure no entrainment of air in producing or through the injection system, oxygen corrosion will not be a problem.
In shallow wells where water is from aquifers closely associated with surface
sources, air entrainment may occur either intermittantly or eventually continuously and a monitoring program should be planned for early detection.
Regardless of the source all surface waters should be considered saturated
wit~ oxygen, and treatment or removal is required for preventing oxygen corroslOn. The oxygen content and control procedures are discussed in the following.
l.SCAVENGING AND INHIBITING OF OXYGEN
Both scavenging and inhibiting require a continuous injection of chemical into the water stream with the amount dictated by the ppm content
of oxygen. In water disposal systems where the volumes are low or
oxygen is present in only trace levels, the chemical control will usually
be the most cost effective. The chemicals should be injected either
upstream or as close to the source of air contamination as practical.
Providing the injection system is pressure and vacuum tight, injection is
required only during periods of flow. Where only traces of oxygen are
present, the scavenging procedure will generally be the most effective.
The inhibiting chemicals will usually be the most cost effective when
the level of oxygen is above the trace level.
G. SOLUBILIlY OF OXYGEN IN SURFACE WATERS
Theoretically the solubility of oxygen is controlled by temperature of the
water at point of contact with the air and to a minor degree by composition
of the water. With water entraining large amounts of organic matter some of
the oxygen will be consumed by oxidation of the entrained contaminents. In
general, providing the water inlet for the project is a reasonable distance
above the bottom, in oceans or lakes, the quality of the water both from
oxygen in solution and entrained solids is improved.
2.GAS REFLUXING OR VACUUM FOR OXYGEN REMOVAL
In large water volume injection projects or where a long life is anticipated for a project, a plant for the physical removal of oxygen is invariably most cost effective. From capital expense considerations the
plant requirements for the two methods are comparable and, with an
adequate design, properly operated, the efficiencies are equivalent. In
offshore operations where g(is volumes will not support a pipeline, gas
is frequently preferred. With either method it is frequently desirable to
inject a scavenger immediately down stream of the treating tower to
remove any minute traces of oxygen remaining in the stream. The
design of these units are beyond the scope of this handbook. However,
the following schematic of a system installed in the Gulf of Mexico indicates features to be considered in the design. The reference D is a publication ofthe International Nickel Company.
The approximate solubility range for oxygen in water is from 10 ppm at 32°F
(freezing), to 0 ppm at 212°F (boiling). Where the specific oxygen content
has not been measured, the following can be used for conservatively estimating the oxygen content.
ppm oxygen
= 10
- .0555 (T OF - 3Q°F)
(D)
T OF
=
r-_(A_)O_R-,-(B-,-)_ _ ~
Temperature of water at system inlet
(A)OR(B)
H. REMOVAL OF OXYGEN FROM INJECTION WATERS
Four methods are in general use for control of oxygen corrosion in water in~
jection processes. With either gas or vacuum deaerator towers the oxygen is
physically removed from the water. With chemical scavenging the oxygen is
combined to form a non-corrosive molecule. Oxygen inhibitors are also available that in combination with the oxygen will form a protective fUm on the
exposed steel. The most cost effective method will generally be dictated by
volume of water, ppm of oxygen, and logistics of the operation. The following discusses the methods and there limitations.
(GASOUT)
(GAS IN)
(C)
..
::.'~ '
(A)
(D)
(A)
(A)
(A)
-=--- -~
-
SCREEN~
(MONEL)
(D)
SUGGESTED MATERIALS
(A)-FIBER GLASS EPOXY PIPE
(B)-LINED WITH BAKED ON COATINGS
(C)-COAL TAR EPOXY COATING
(D)-METALLURGY AS INDICATED IN
"GUIDELINES FOR SELECTION OF
MARINE MATERIALS"
70 '
--t10 '
~
-60-
SCHEMATIC OF MAJOR COMPONENTS
IN OFFSHORE INJECTION PLANT
-61-
CHAPTER VI
B. SUCKER ROD PUMPED WELLS-LOW FLUID LEVEL (continued)
CHAMPION'S CORTRON INHIBITORS FOR
CORROSION CONTROL
Production Chemical Company inhibitor formulations are proprietary. The treating procedures
detailed in previous chapters have been successfully applied for the past 20 years using
Champion's Cortron Inhibitors. Other chemicals with the same generic inhibitor and additives
would be equally effective. However, since these formulations cannot be identified, only
Champion's Cortrons are included in the listing.
A. SUCKER ROD PUMPED WELLS - HIGH FLUID LEVEL
TREATING
MEI1IOD
INHIBITORS
NOH2S
~
Continuous
Injection
R-2263
RN-63
RU-19
R-2263
RN-63
RU-19
Flush 25-50 ppm down annulus by continuous slipstream.
350-500 BFPD
Semi-Weekly
Batch
RH-147
RD-46
RH-147
Weighted Inhibitors. Prewet annulus with 1-2 bbls
fluid. Batch 25-50 ppm
down annulus. Neat with no
flush or circulate.
350-500 BFPD
Semi-Weekly
Batch
R-2375
R-129
R-2314
R-129
R-2375
Standard inhibitors. Disperse 25-50 ppm in 1 bbl
brine per 1000 ft. of tubing
and/or circulate annular
fluid up tubing and back
into annulus.
PRODUCTION
RATE
>5OOBFPD
50BFPD
Monthly
Batch
Weekly
Batch
RH-147
RD-46
Weighted Inhibitor. Same
as above for 350-500 BFPD
with Semi-Weekly treatments.
150-350 BFPD
Weekly
Batch
R-2375
R-129
R-2314
R-129
R-2375
Standard Inhibitors. Same
as above for 350-500 BFPD
with Semi-Weekly treatments.
< 50-150 BFPD
Weekly
Batch
Bi-Weekly
Batch
R-2375
R-2255
R-2314
R-129
R-2255
R-2300
R-129
R-2239
Disperse 25-50 ppm in 1 bbl
brine. Flush down annulus
with 1/2-1 bbl brine per
1000 ft. of tubing. Circulate
as needed.
R-2375
R-2255
R-2314
R-129
R-2255
R-2300
R-129
R-2239
Same as above for 150-350
BFPD with weekly treatments.
-62-
Same as above for 150-350
BFPD with weekly treatments OR batch neat and
circulate down-hole to
pump.
All
Continuous
Injection
RU-161
R-2255
R-2314
R-129
RU-161
R-2300
R-129
R-2239
Inject 25-100 ppm into lift
gas at wellhead.
All
Tubing
Displacement
1 t03 Month
R-66
R-66
R-68
R-2255
R-2258
R-2345
R-2300
Dosage 1 gal/1oo sq.ft. of
metal surface to be filmed.
Mix 1:1 to 1:4 with crude or
diesel. Displace to bottom
of tubing with crude or
diesel. Or atomize mixture
into nitrogen and displace
tubing volume.
R-68
R-2255
R-2258
R-2345
D. HYDRAULICALLY PUMPED WELLS
Continuous
Injection
R-2314 ~. R-129
Batch
R-129
R-68
R-2258
R-129
R-68
R-2258
Disperse 25-50 ppm in
power oil. Maintain level by
monitoring.
Power Water
Systems
Continuous
Injection
R-2263
RN-63
RN-82
R-2263
RN-63
RN-82
Inject 25-50 ppm.
Water Supply
Systems
Continuous
Injection
R-2263
RN-63
RU-19
R-2263
RN-63
RU-19
Inject 10-50 ppm.
Power Oil
Systems
B. SUCKER ROD PUMPED WELLS - LOW FLUID LEVEL
< 150-350 BFPD
R-2255
R-2300
R-2300
R-2239
C. GAS LIFT WELLS
DOSAGE & PROCEDURE
150-350 BFPD
R-2375
R-2255
R-2314
R-129
Inject 25-50 ppm.
E. GAS/GAS CONDENSATE WELLS
lOMMCF/D
or
VaNe = 0.7
Continuous
Injection
Ru-156
RU-161
RU-163A
R-2302
RU-156
RU-161
RU-163A
R-2302
Inject 100-200 ppm via
capillary tubing, macaroni
string or bottom hole injectionvalve.
5 -lOMMCF/D
or
VaNe = 0.7-0.9
Batch
3-6 Weeks
R-66
R-2258
R-2345
R-66
Treat at rate of 1
drum/lO,ooo ft. for up to 3"
tubing. Dilute 1:1 to 1:4
with diesel or equivalent.
-63-
R-2258
R-2345
F. OIL & GAS PIPELINES (continued)
E. GAS/GAS CONDENSATE WELLS (continued)
5 - 10 MMCF/D
or
VaNe = 0.7-0.9
2-5 MMCF/D
or
VaNE = 0.5-0.7
0-2MMCF/D
or
VaNe = 0.2-0.5
Tubing
Displacement
3-6 Weeks
R-2255
R-2258
R-2255
R-2258
Treat at rate of 1
drum/lO,OOO ft. Dilute 1:1 to
1:10
with
diesel
or
equivalent. Displace to bottom of tubing with diesel or
atomize
mixture
into
nitrogen and displace to
bottom of tubing.
Batch
6-8 Weeks
R-66
R-2258
R-2345
R-66
R-2258
R-2345
Same as above for batch
treatments.
Tubing
Displacement
6-8 Weeks
R-2255
R-2258
R-2255
R-2258
Same as above for tubing
displacement.
Batch
8-12 Weeks
R-66
R-2258
R-2345
R-66
R-2258
R-2345
Same as above for batch
treatments.
Tubing
Displacement
8--12 Weeks
R-2255
R-2258
R-2255
R-2245
Same as above for tubing
displacements.
Wet Gas Lines
Velocity > 15 fps
Continuous
Injection
RN-63
RN-82
RU-19
RN-63
RN-82
RN-97
RU-19
Inject inhibitor at a rate that
maintains at least 250 ppm
residual in water samples at
end of line
Wet Gas Lines
Velocity < 15 fps
Continuous
Injection
RN-63
RN-82
RU-19
RN-63
RN-82
RN-97
RU-19
Inject at 1/2 - 1 pint/MMCF.
Dehydrated
Gas Pipelines
Velocity-All
Continuous
Injection
RN-177
RN-I77
Inject 1/4 - 1/2 pint/MMCF.
NOTE: Inhibitor type is critical, must be generically similar to RN-177.
NOTE: Va=Actual Velocity, Ve=Erosional Velocity. Calculate using
methods in API RP-14E.
F. OIL & GAS PIPELINES
All
Pipelines
Batch
As Required
R-129
R-2255
R-2239
R-2231
R-129
R-2255
R-2239
R-2300
R-2231
Vol.lnhibitor = 2-3 gals per
inch diameter per mile of
line. Dilute 1:1 to 1:4 with
diesel, batch between
squeege pigs.
Wet Oil Lines
Water> 25%
Velocity 5fps
Continuous
Injection
RN-63
RN-82
RU-19
RN-63
RN-82
RN-97
RU-19
Inject inhibitor at rate that
maintains at least 250 ppm
residual in water samples at
end of line.
Wet Oil Lines
Water < 25%
Velocity-All
Continuous
Injection
RN-63
RN-82
RU-19
RN-63
RN-82
RN-97
RU-19
Inject inhibitor at a rate that
maintains 50-100 ppm
residual in water samples at
end of line.
Custody
Transfer Oil
Pipelines
Velocity> 3 fps
Continuous
Injection
RN-63
RN-82
RU-19
RN-63
RN-82
RN-97
RU-19
Same as for Wet Oil Lines.
> 25%
-64-
-65-
CHAPTER VII
MISCELLANEOUS TECHNICAL INFORMATION
A. FAILURE ANALYSIS PROCEDURE
FAILURE ANALYStS
INSPECTION OF FAILURE
SERVICE HISTORY
(Decision)
GENERAL
The following information while not directly related to corrosion is frequent1y desirable in studying a failure or reporting on the problem. The primary
objective in most studies is to isolate the reasons and if possible modify
producing operations to prevent their reoccurence. Statistics indicate that 80
to 90 percent of the failures in production and pipeline equipment are due
to metal loss corrosion. When corrosion has been isolated as the cause, it is
frequently probable that the condition causing the attack is present
throughout the operation. Research and field studies have identified most of
the reasons for corrosion and the most likely location of corrosive zones. With
this information a corrosion engineer or experienced field operator can frequently, quickly solve a corrosion problem.
The 10 to 20 percent not readily identified as corrosion may require an indepth laboratory study to determine the cause. Such studies are generally
time consuming and frequently quite expensive. This requires a decision on
the operator's part as to whether a further investigation is warranted. Where
the failure is defmitely not due to corrosion but probably reflects a material
or operating anomaly, neither of which will reoccur, studies are probably unwarranted. Failures that cause either a catastrophic or hazardous operating
condition should always be studied.
A reoccurring inquiry on non-identifiable failures is "...not to specification".
Most wellbore equipment and piping is made to API specifications. These
are always precise as to dimensions. However, the API composition
specifications for steels are quite broad and generally limited to carbon, manganese, sulfur and phosphorous. Invariably the steels will be within specification. The physical strength specifications, except for materials designated for
sour service are also broad. Failure to meet API specifications within the
designated grade are rare. While failure to meet specifications are unusual,
there are occasional instances of heat treating, major surface imperfections
or API grade substitution or mistake causing failure. These conditions will
generally require laboratory tests to establish lack of specification as the
cause of failures. In addition to the following a number of references are listed
at the close of this chapter as further sources of information frequently pertinent to corrosion studies.
-66-
--------------------------- --------------------------------TESTING
METALLOGRAPHIC STUDY
ANALYSIS OF RESULTS
CAUSE NOT OBVIOUS
CAUSE OBVIOUS
The block diagram lists steps in a ~yPical failure analysis. In field operati?ns
the steps above the first decision line would n~rmally be per.forme~ at SIte.
If corrosion is recognized as the cause, an expenenced corrOSIon ~n~eer or
field operator can generally locate the reaso~ for the attack. ThIS Will complete the investigation and other than prepanng necessary reports no other
action is required.
If the first three items have not isolated the cause, the opera~ions betwee~ the
decision lines are the next considerations. Generally the testI?-~ branch w.Ill be
first considered. In view of API limited and broad compOSItIonal. specIfi~a­
tions Chemical Analysis is not usually considered as desirable. Ph~slcal. testmg
will determine if rods and tubular goods are within grade speclfica~lOn: As
noted in Item B, non-destructive testing based on hardness determmatI~ns
will determine if laboratory tensile testing is warranted. T~e non-destruct~ve
hardness testing can generally be made in field labor atones and determme
whether destructive type tensile testing is warranted.
If testing is not definitive, a Metallographic Study m~y be ~esirable. If a
failure is of a metallurgical nature, it is frequently assocIated.WIth an anoI?oly in the metal at or close to the point ~f initi~ting ?f the ~ai1ure. ~etectIon
usually requires multiple metallographlc sectIons tmmedlately adjacent to
the failure location.
-67-
If the Testing or Metallographic Study indicates cause of failure the Final
Report can be made. However, if, "Cause Not Obvious", is the result a
decision is required as to further investigation. The indicated Laboratory Experiments will be time consuming and always expensive. Unless required by
legal considerations, the indicated Preliminary Report including a summary
of probable causes will usually complete the study.
2. BRINELL HARDNESS vs TENSILE STRENGTH
With the Brinell Hardness the range of probable Tensile Strength can be obtained from the curve. If the steel specification is outside these limits, standard tensile tests should be made on samples from the failure.
180,000 r - - - - - - - - - - - - - - - ,.....
B. APPROXIMATION OF TENSILE & YIELD STRENGTH OF STEEL
160,000
iii
As noted in Item A, with either Rockwell or Brinell hardness tests that can
usually be made in Field area locations, tensile and yield strengths can be estimated. Three to five hardness measurements, as close to the failure as
practical, should be averaged to assure to reasonably accurate result. This
hardness can then be used in conjunction with the following curves to estimate
the range of tensile and yield strengths of a steel.
140,000
Q.
i= 120,000
t!)
Z
~ 100,000
l-
f/)
~ 80,000
iii
ffi
1. BRINELL vs ROCKWELL HARDNESS
I-
60,000
40,000
Item 2 & 3 relate Tensile and Yield Strengths to Brinell Hardness. The curve
below converts Rockwell "e" to Brinell.
20,000
100
40
200
300
BRINEll HARDNESS
3. TENSILE STRENGTH vs YIELD STRENGTH RANGE
35
w
Using median tensile strength from Item 2 determine Yield Strength range.
""
If steel specifications range is outside these values, make standard tensile yield
-I
0
til
30
tests.
0
til
til
25
w
90
Z
W
..J
Q
a:: 20
iii
z
w
""
-I
-I
l-
w 15
3:
0
#
J:
u.
~
0
0
a::
/'
0
l-
t!)
zw
/
II:
l-
5
/
/'
::r::
10
/'
/'
/
f/)
0
..J
W
0
>=
200
230
260
290
BRINELL HARDNESS
320
350
50
75,000
100,000
125,000
150,000
TENSILE STRENGTH - PSI
-68-
-69-
175,000
C. APPROXIMATE VELOCI1Y CRITERIA FOR LIQUIDS
Velocity limitations are frequently overlooked in the design of production
and pipelining of liquids. One factor of particular importance is the much
lower velocities required where corrosive and/or abrasive liquids are being
transported. The following "Rules of Thumb" based on field experience have
been successfully used for years.
1. CALCULATION OF APPROXIMATE VELOCI1Y
CPS (cubic feet per second)
= .;;Ba.;.;.IT;.;.e.;.;.l_so_f_L_iq....u_id...pe_r_D....
ay
5. PIPE VELOCITIES vs FLUID DENSI1Y
V (fps)
=#
C
P
=
=
Operating Constant
Density in pounds per cubic feet
To keep pipe clean
C = 15 to 24
For long life projects
C = 100 to 125
For short life projects
C = 160
Swing Check Valves
C = 35 to 50
Piston Check Valves
C = 40 to 140
Tilting Disk Check Valves
C = 30 to 80
Check Valves "Cs" function of design.
15,400
CFS
Pipe Area in Square Feet
fps (feet per second)
D. DESIGN VELO~ITIES FOR WELL TUBING
Analyis of tubing failures has indicated that this empirically derived curve establishes suitable design velocities for tubing in reasonably vertical wells.
2. LIMITING VELOCITIES FOR WATER IN STEEL PIPE
100r--,--,----'-.---r--r---r---r----.
= 12 to 20 fps
Water (non-corrosive)
Water
(corrosive)
= 6 to 12 fps
Water
(corrosive + abrasive) = 4 to 6 fps
NOTE: Higher values fresh water, lower values brine.
CLEAN-SINGLE PHASE FLUIDS
oIII
3. LIMITING VELOCITIES FOR OIL IN STEEL PIPE
Crude Oil (dry)
= 30 to 35 fps
Crude Oil (wet)
= 20 to 25 fps
NOTE: Minimum velocity to entrain emulsion
Vel. = 31/2 to 5 fps
~
~
go
70
60
50
III
>
~ 40
ffl
c
30
4. DESIGN CRITERIA FOR PUMP SUCTIONS
Optimum Velocity
= ±
20
10
1 fps
Piping one size larger than pump inlet.
Pressure Head of 8 to 10 feet.
Pump as close to liquid storage as possible.
-70-
10
20
30
40
50
60
POUNDS PER CUBIC FOOT OF LIQUIDS
GAS-CONDENSATE
LIQUIDS RANGE
RANGE
-71-
70
80
FLUID DENSI1Y CALCULATIONS
BOPD X SG X 14.6
BWPD X SG X 14.6
MSCFD X SG X 3.17
=
=
=
pounds per hour
TOTAL
BOPDXO.234
BWPDX0.234
MSCFD X 1.18 X oR X Z
=
cubic feet per hour
cubic feet per hour
cubic feet per hour
=
=
=
cubic feet per hour
TOTAL
SG
pounds per hour
pounds per hour
pounds per hour
h. GLASS FILAMENT WOUND EPOXY PIPE
The performance of this pipe has been excellent. It is recommended in applications where it meets pressure and temperature requirements and cost
considerations.
c. PLASTIC LINERS IN STEEL PIPE
A number of plastic pipe liners are available for use in steel pipe. In one type,
the inserted plastic tubing is molded directly to the next tubing section,
eliminating the problem of sealing and protection at the pipe coupling. With
other systems, joint inserts and sealing combinations are used. Field experience with the liner type of systems has been inconsistent, instances of frequent joint failures or collapse of the plastic liner have occurred. From
engineering considerations, the insert liner type of system is good but requires careful control of application for a trouble-free installation.
Specific Gravity
d. BAKED ON COATINGS
·
Total Pounds per Hour
.
D enslty =
Total CubIc Feet per hour
E. CORROSION RESISTANT MATERIALS
There are a variety ofcorrosion resistant non-metallic mate~ials and metal alloys used in production and pipeline oper~tions. Where s~ltable and cost .effective, they can provide excellent protection from cor~os~o~. T~e followmg
is a brief overview of these materials and some of theIr IlDlltatIons. Where
apparently applicable and cost effective, a detailed review of types, manufacturers and availability is desirable.
1. NON-METALLIC MATERIALS
With the exception of cement linings most of the non-metallic. ~aterials ~e
tradename plastics or synthetic organic coatings ~he c<.>mp~sltIon o~ which
are considered proprietary. Where a tradename Ite~ IS ~emg co~sldered,
technical data should be reviewed to assure to matenal will be satisfactory
for the operating environment.
EXTRUDED PLASTIC PIPE
Although extruded plastic pipe is freque~tly used; the limitations of t~s pipe
must be carefully considered and the pipe applIed <.>nly where .a~plIcable.
Specifications are usually based on the American SanltaIJ: ASSOCiation ~tan­
dards. The temperature base in this standard is 73.4°F. With f~w exceptI~)lls,
the extruded plastic pipe is also fatigue-sensiti~e under surgmg operations
and must be down-rated where pressure fluctuatIOns occur. A general recommendation would be to use extruded plastic pipe only in open-end systems,
free of surging and down-rated for temperature.
3.
-72-
In smaller pipe and injection lines, the baked-on coating is the most widely
used procedure for corrosion protection. Laboratory tests have established
that if properly applied, all of the baked-on coatings, whether they are of the
thin or thick film types, will give good protection in oil and water handling
operations. In practically all instances where failures occur these are due to
either improper cleaning, coating'application, baking of the coatings or fieldinduced failures resulting from improper transporting or laying procedures.
Where the baked-on coatings are properly applied and handled, good service can be expected in oil and water piping.
In many instances baked on coatings have been unsatisfactory in high pressure gas piping. Service has been particularly poor in lines subject to frequent
pressure fluctuations. The failures are due to blistering and the coating flaking off the steel. The failures are attributed to the coating being permeable
to gas, which diffus through the coating. With pressure reduction the gas
expands, forming bl sters, which spall from the pipe wall. Baked on coatings
are not recommended for high pressure gas service.
e. CEMENT LININGS
In large diameter piping (6" plus) cement is a widely used lining system for
handling water. With present laboratory proved specifications excellent performance can be anticipated from cement type linings. The major problem
area is in the joints. However, such failures are usually due to improper welding or chalking practices. When the laying of the cement lined pipe is supervised to assure proper welding and sealing of the joints excellent service can
be expected. There are a number of special joint systems that can also be
used to assure line integrity.
-73-
2. CORROSION RESISTANT ALLOYS
Although it is impractical to use corrosion-resistant alloys for such items as
pipe or lease vessels, it is possible to use such metals where the major cost of
equipment is fabrication. Generally such equipment is connected to a carbon steel item. Chapter I, Item L, Page 12, discusses Galvanic Corrosion that
is occasionally overlooked in such installations.
All of the alloys discussed below are available in a variety of grade designations. While each designation will include the same major elements for corrosion resistance, other elements are added to improve some specific factor,
such as machine ability, weldability, ductility, pit resistance, etc. When the environment is unusual, these factors should be reviewed in designating the
specific alloy.
3. MONELS
In highly corrosive environments, where failures will be of serious consequence, Monels are the preferred materials. The Monels have a distinct advantage over most of the other corrosion-resistant metals in that their
corrosion rate is not markedly increased by aeration. Also, since Monels are
resistant to sulfide stress corrosion cracking, the material can be used at high
stress levels. While Monels would be preferred for many items, the cost and
lack of availability will often preclude its use.
b. STAINLESS STEELS
The term stainless steel used with many tradenames is a misnomer. These alloys may resist corrosion for some specific operating condition but unless the
chromium content is above 9% - 10% they do not meet the AISI designation
for stainless steel. The following figure is the designation of the alloys as based
on the chromium content.
45
I
40 ~Steel
35
.l:
.ll'
30
~
~
..
.!: 25
E
.,
~
u
~
20
15
l~
.
-'",
Stainless steels
"""""-
"
D..
10
5
00
8
12
16
CAUTION: These alloys have a tendency to gall in running fits such as
threads, pistons, valve stems, etc. Mating surfaces can be coated to prevent
galling. On surfaces not subject to frequent movement or disassembly the
coatings are satisfactory.
(2) AISI 400 Series Stainless Steels
Equipment fabricated from the AISI 400 stainless steel series is most readily available. In sour water, the 400 series will be subject to a pitting type attack, with the susceptibility to attack and the rate of attack increasing as the
hardness, tensile and yield strengths of the metal increases.
CAU ION: While the 400 Series alloys are widely used and frequently the
only stainless steel available in "off the shelf' items, they should not be used in
non-oxidizing or saline water. As noted above, once the chromium oxide film
is destroyed and not replaced, the steel is active and corrodes; frequently a
rapid, isolated, pitting type attack develops under these conditions.
C~rome_
Iron
I'
4
(1) AISI 300 Series Stainless Steels
This is the 18% Cr, 8% Ni stainless steel group. These alloys are mostly of
the non-hardenable type and have generally given good corrosion-resistance
in sour field waters. The yield and tensile strengths are less than most steels
normally used in oil field equipment and this must be considered in designing parts subject to high stresses. The alloys also have a tendency to gall in
running fits and this factor should be taken into consideration in threads, pistons, valve stems, etc.
(3) ALUMINUM BRONZE ALLOYS
Aluminum Bronze and other bronze alloys are used extensively for water handling, particularly in piston-type injection pumps, and have generally given
good service. The two principal uncertainties are the endurance limits for
various operating conditions and internal stresses in cast and machined parts.
Research studies have established that heat-treating and stress-relieving are
required for development of ultimate performance of the material.
Chromium steels
~
Chromium is the principal alloying element for increasing the corrosion resistance of steel. The resistance of the steel to attack is developed by a very thin
fIlm of chromium oxide that forms on the surface. Even though this film can
be ruptured or destroyed, in the atmosphere or in a highly oxidizing environment, it is self healing and the stainless condition is maintained. However, in
the presence of certain acids, chlorides, etc. the film may be destroyed and
not reestablish. The condition of the alloy is then designated as active and
the metal corrodes like plain carbon steels.
20
24
33.5
....,.
28
32
Chromium (per cent)
-74-
-75-
(4) INCONEL, HASTELLOY, STELLITE AND COLMONOY
These are the specialty alloys most commonly found in oil field. <:quipment.
Inconel has excellent corrosion-resistance and very good physlclal characteristics. Although this metal is not generally used in stock items, it has found
wide-spread use in springs for corrosive service, particul~ly where such
springs may also be subject to a hydrogen sulfide type of envrronment.
Hastelloy, Stellite and Colmonoy all have excellen~ corrosi?n~resistant
properties in sour waters and are primarily used as facmgs or tnm m valves,
etc.
F.
The primary objective of API Specifications is to assure equipment f~om
various suppliers will be dimensionally interchangeable. A secondary obJective is that equipment will have the physical strength to wit~stand the str.ess
caused by field operating conditions. There have been ongomg efforts t? Improve specifications to include damaging mill defects and in some specifications these are broadly defined. With the exception of hydrogen
embrittlement corrosion resistance, corrosion is not considered in specifications. The API and NACE have various Recommended Practice publications
detailing procedures for corrosion control in field operations.
With premature or unusual failures it is possible the API physical prope.rties
have been exceeded. These specifications along with API reference are listed
below.
1. API/SPEC. llB: SUCKER RODS & COUPLING
The fotIowing table lists the only composition and ~ech~ni~al properties for
sucker rods and couplings. The Grade D rod operatmg wlthm ~he API recommended stress range is not susceptible to sulfide stress crackmg.
API SUCKER ROD SPECIFICATIONS
K
C
D
CHEMICAL
COMPOSITION
AISI46XX
AISI1536*
CARBON/ALLOY**
TENSILE STRENGTH
MIN.PSI
MAX.PSI
85,000
90,000
115,000
115,000
115,000
140,000
* Generally manufactured from but not restricted to AI~I ~536.
.
* * Any alloy that can be effectively heat treated to the mlmmum ultimate
tensile strength.
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CLASS
HARDNESS
ROCKWELL-C
T
16 Min. - 23 Max.
CHEMICAL REQUIREMENTS: The maximum sulphur content of
couplings and subcouplings is limited to 0.05%.
2. API/ SPEC SA, SAC, SAX TUBING & CASING
API SPECIFICATIONS· PHYSICAL PROPERTIES
GRADE
API COUPLING SPECIFICATION
The following specifications cover the various grades of tubing and casing
with industry specifications, also including information on drill pipe. As
noted in Item A, Failure Analysis Procedure, specifications for composition
are quite broad and seldom considered in failure studies. The following lists
the Physical Specifications, the first consideration, when failures not attributable to corrosion are investigated. In the H2S column, "YES" indicates
the Grade is suitable for sour service.
GRADE
STRENGTH
YIELD
TENSILE
MIN.
MAX.
MIN.
~
SPEC.
60,000
YES
5A
H-4O
40,000
J-55
55,000
80,000
75,000
YES
5A
K-55
55,000
80,000
95,000
YES
5A
N-8O
80,000
110,000
100,000
?
5A
C-75
75,000
90,000
95,000
YES
5AC
L-80
80,000
95,000
95,000
YES
5AC
C-95
95,000
110,000
105,000
?
5AC
P-105
105,000
135,000
120,000
NO
5AX
P-ll0
110,000
140,000
125,000
NO
5AX
? - Where maximum stress does not exceed 90,000 psi or downhole temperature is in excess of 1500 F, sulfide stress cracking would not be expected.
-77)
3. API SPEC. SL LINE PIPE
The composition specifications in 5L are broad and with only minimum requirements for yield and tensile strengths. These physical requirements are
listed below for the various Grades of pipe. Failures are invariably associated
with either external or internal corrosion. External failures are beyond the
scope of this presentation but are frequently associated with the weld area
and either holidays in the pipe coating, malfunction in the cathodic protection system or both.
Internal failures are principally due to corrosion with occasional stress
fa!lures in old lines, subject to pulsating pressure. Most lines are designed
With a large safety factor and with the broad specifications noted above physicalor chemical tests are generally unwarranted.
GRADE
API LINE PIPE TENSILE SPECS.
STRENGTH
YIELD MIN. PSI
TENSILE MIN. PSI
A
30,000
48,000
B
35,000
60,000
X42
42,000
60,000
X46
46,000
63,000
X52
52,000
66,000*
72,000**
X56
56,000
71,000*
75,000**
X60
60,000
75,000*
78,000**
X65
65,000
77,000*
80,000**
X70
70,000
80,000*
82,000**
G. REFERENCES PERTINENT TO OIL FIELD CORROSION
While there are many references to corrosion few specifically relate to
production and pipeline operation. Furthermore, there are not many giving
extensive illustrations and specifics on the environment where the failure occurred. Another factor frequently overlooked in failure analysis is the extent
to which complex flow patterns in multi-component, two phase, can induce
failures. The following is a list of references particularly suited to failure
analysis where the cause cannot be easily identified.
1.
Corrosion Control in Petroleum Production
NACE, TPC Publication No.5.
2.
Forms of Corrosion, Recognition and Prevention
c.P. Dillon - Editor, NACE Publication
3.
Metals Handbook, Volume 10, Failuare Analysis and Prevention
8th Edition - American Society for Metals, Metals Park, Ohio 44073
4.
The Flow of Complex Mixtures in Pipes
Govier/Aziz, Van Nostrand-Reinhold co.
5.
Physical metallurgy for Engineers
Clark and Varney, Van Nostrand-Reinhold Co.
6.
Production Operations, Vol. 1 & 2
Allen and Roberts, Oil and Gas Consultants International, Inc.
Tulsa, Oklahoma
* For pipe less than 20" O.D. with any wall thickness and for pipe 20"
O.D. and larger with wall thickness greater than 0.375".
** For pipe 20" O .D. and larger with wall thickness 0.375" and less.
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