Paper No.
11296
Bing Q. Han
Schlumberger
200 Gillingham Lane
Sugar Land, TX 77478
ABSTRACT
The electrical submersible pump (ESP) is one of the most efficient artificial lift technologies enabling oil
production. Depending on the operating conditions and corrosivity of downhole well fluids, ESP
components are built from various materials with suitable corrosion resistance. This article briefly reviews
the corrosion of ESPs in oil production from downhole well fluids of corrosive species such as dissolved
carbon dioxide, hydrogen sulfide and chloride ions. Materials and their performance in major ESP
components, including pump stages, heads and bases, housings, and shafts, in the environment of oil
production are also discussed. Finally, the proper selection of ESP materials in different applications is
examined.
Key words: Corrosion, produced water, materials, ESP.
INTRODUCTION
In a naturally flowing well without artifical lift equipment, the primary method to recover oil from a reservior
is to connect the wellhead to a pipeline network for storage and processing at the surface at the natural
flow rate. Typically this method can recover 5% to 15% of the oil reservior. When a reservoir no longer
has sufficient energy to naturally produce the oil, operators can increase the flow rate by deploying
artifical lift equipment and enhanced oil-recovery methods. Among artificial lift technologies, the electrical
submersible pump is one of the most powerful and versatile, enabling high production rates from 200 to
60,000 bbl/d at depths of up to 15,000 ft. In addition, it minimizes the lifting cost for high fluid volumes.
An ESP system is composed of several major components: multistage centrifugal pumps consisting of
rotating impellers and stationary diffusers within a protective housing; high-speed, three-phase electric
motors filled with dielectric oil deployed at the bottom of the pumps; a seal section (protector) that isolates
well fluids from the motor and carries the thrust load; a downhole sensor that records temperature and
pressure data; and an armored power cable that runs from the surface down to the motor-lead extension
of the electric motor. Produced well liquids, after being subjected to great centrifugal forces caused by
the high rotational speed of the impeller, convert their kinetic energy to pressure in the diffuser, enabling
the fluids to reach the surface.
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
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Corrosion and Materials Challenges of Electrical Submersible Pumps in Oil Production
Table 1
A sample of chemical parameters of produced water
Oil-in-water
Typical range
Maximum (Upset Conditions)
Total Suspended Solids
(Excluding oil)
Bottomhole Temperature
Specific Gravity at 15 oC
Salinity
pH (at Surface)
Dissolved CO2
Sulfide as H2S
100 – 500 mg/L (free oil)
Up to 3,000 mg/L (free oil)
2 mg/L normal
3,000 mg/L extreme maximum
50 – 90 oC
1.03 – 1.15
2.4 – 20 wt%
5.1 to 7.0
50 – 2,000 mg/L
0 – 1,000 mg/L
The successful operation and runlife of ESPs depend on the application of suitable materials for the
expected reservoir conditions. In this article, the corrosivity of well fluids is reviewed and the performance
of typical materials in ESPs is discussed.
CORROSIVE SPECIES IN WELL FLUIDS DURING OIL PRODUCTION
The selection of ESP metallurgy is essentially based on the corrosiveness of well fluids in the service
environment. To better understand the corrosivity of well fluids, the following parameters are usually
analyzed:
- pH value, specific gravity (g/cm3), total dissolved solids (TDS) or electrical conductivity (EC),
alkalinity (mg/L of CaCO3), total hardness, and calcium hardness;
- Concentration of, dissolved carbon dioxide (CO2), dissolved hydrogen sulfide (H2S), and
dissolved oxygen (DO) when oxygen ingress is suspected;
- Anions: chloride (Cl-), bicarbonates (HCO3-), carbonates (CO3-), sulfate (SO42-);
- Cations: sodium (Na+), calcium (Ca+), magnesium (Mg+), iron (Fe+), barium (Ba+), strontium
(Sr+), etc.;
- Total suspended solids (TSS), the quantity and dimension of suspended solids, and residual oil
and grease in water (in ppm).
The concentration of chemical constituents may be reported as parts per million (ppm) or milligrams per
liter (mg/L). The general corrosiveness of well fluids can be evaluated by pH, which is the negative of the
concentration of hydrogen ions (H+) expressed as a power of 10. In acidic solutions (a low value of pH),
there are more H+ ions than OH- ions. Corrosion of materials occurs more severely at lower pH, since
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
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During oil production, the mixture of three phases—i.e., oil (hydrocarbon compounds), free gas
(hydrocarbon and non-hydrocarbon compounds), and aqueous solutions (non-hydrocarbon
compounds)—is pumped from downhole up to the surface. Carbon dioxide and hydrogen sulfide
(corrosive species) may be present in all phases of the mixture. They cause more corrosion of ESP
metallurgy when in aqueous solutions (produced water) than in oil and gas. Produced water is the water
trapped in underground formations that is brought to the surface as a byproduct along with hydrocarbons
during oil and gas exploration and production. Produced water is undesirable water, often generated in
large volumes. Oil companies produce an average of 3 bbl of produced water for every 1 bbl of produced
oil,1 and water production increases significantly over time in many wells with high water cut. An example
of the chemical parameters of produced water is summarized in Table 1. This water may include water
from the reservoir, water injected into the formation, and chemicals added during the drilling, production,
and treatment processes. Because some of this the water has been in contact with the hydrocarbonbearing formation for centuries, it has some of the chemical characteristics of the formation and the
hydrocarbon itself.
there are more H+ ions available for cathodic reactions (by releasing H2 gas), resulting in more electrons
from materials dissolving into aqueous solutions.
In ESP applications, the major corrosion process takes place due to the presence of carbon dioxide,
hydrogen sulfide, chloride ions, etc., in produced fluids.2 Therefore, a general overview of the corrosion
mechanisms of steels by these several species will be discussed here.
CO2 (gas)  CO2 (aq);
CO2 (aq) + H2O  H2CO3.
Corrosion process occurs through the following reactions:
H2CO3 + e-  H+ + HCO3-;
HCO3-  H+ + CO32-;
+
2H + 2e-  H2 (cathodic reaction)
Fe  Fe2+ + 2e- (anodic reaction)
Fe + CO2 + H2O  H2 + FeCO3 (overall reaction).
The corrosion rate of metals is directly related to the concentration of carbonic acid. As partial pressure
of CO2 gas increases, the corrosion rate will normally increase. CO2 corrosion products include iron
carbonate (siderite - FeCO3) and iron oxides (magnetite - Fe3O4) with colors of green, tan, or brown to
black. CO2 corrosion is enhanced in the presence of both oxygen and organic acids, which can dissolve
iron carbonate scale and prevent the formation of protective scaling.
Hydrogen sulfide (sour) corrosion is another common form of corrosion in oil production. Hydrogen sulfide
(H2S) is a weak acid when it is dissolved in water and can act as a catalyst in the absorption by steel of
atomic hydrogen formed by the cathodic reduction of hydrogen ions, through the following reactions.
H2S (gas)  H2S (aq)  H+ + HS-;
HS- (aq)  H+ + S2- (cathodic reaction)
Fe + H2S + H2O  FeSH- + H3O+;
FeSH-  Fe(SH) + e-;
Fe(SH)  FeSH+ + e-;
FeSH+  FeS(1-x) + xSH- + (1-x)H+ (anodic reaction).
In environments with hydrogen sulfide (H2S) corrosion, the most common type of corrosion includes
uniform corrosion, pitting corrosion, corrosion fatigue, sulfide stress cracking, hydrogen blistering,
hydrogen embrittlement, and stepwise cracking. Black iron sulfides (FeS) are formed from corrosion
reactions of hydrogen sulfide and can be important in limiting further corrosion, especially at lower
temperatures and low H2S partial pressures. However, this protective film forms only when oxygen and
chloride salts are absent. Hydrogen sulfide can promote sulfide stress corrosion cracking in high-strength
steels, stainless steels, or nickel-based alloys.
Because CO2 and H2S acid gases usually coexist in oil production, the corrosion effect of CO2 and H2S
on ESP equipment must be considered simultaneously. In certain cases CO2 corrosion dominates where
FeCO3 corrosion product is usually formed and in other cases H2S corrosion dominates where FeS scale
usually forms. In the absence of stable FeCO3 corrosion product CO2 corrosion rates are higher than H2S
corrosion.3
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
3
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Carbon dioxide (sweet) corrosion is one of the common corrosion forms in oil production, especially in
wells with high water cuts. Carbon dioxide gas dissolves into water to form a weak acid known as carbonic
acid (H2CO3) in a relatively slow reaction, through hydration by water:
Chloride ions in produced waters can cause pitting corrosion or chloride stress corrosion cracking of
steels in pumps as well. Chloride ions easily penetrate films of FeS or FeCO3, forming pits under corrosion
product scales of carbon or low-alloyed steels. It can also break down the protective passive film (CrO2)
of stainless steels, forming pits on stainless steels. The anodic dissolution of the steel leads to the
introduction of positive metal (iron or chromium) ions (M+) in the solution, which causes migration of Clions. In turn, metal chloride reacts with water:
M+Cl- + H2O  MOH + H+Cl- .
This causes the pH in the pits to decrease, further accelerating the local corrosion.
Figure 1:
Effect of salt concentration on CO2 corrosion rate of X65 carbon steel at a
temperature of 80oC, CO2 partial pressure of 0.53 bar, and pH of 6.6 in aqueous solutions6
Dissolved oxygen (DO) in aqueous solutions has a substantial effect on the corrosion behavior of steels.
When DO is present, the common types of corrosion include pitting corrosion and uniform corrosion of
steels. Oxygen easily combines with hydrogen atoms at the cathode and allows the corrosion reaction to
occur at the anode area. O2 corrosion products are iron oxides, including goethite (FeO(OH)), hematite
(Fe2O3, magnetite), Fe3O4, and ferrous hydroxide (Fe(OH)2). DO can also cause severe corrosion of
steels at concentrations as low as 50 ppb. Additionally it promotes pitting corrosion, especially in the
presence of hydrogen sulfide, carbon dioxide and chloride ions in aqueous solutions. To effectively
control the corrosion damage, DO must be limited to levels lower than 10 ppb for many applications.8,9
Fortunately, DO is not commonly present in the production formation, and therefore it is usually not
involved in the corrosion of ESP in oil production. On the other hand, DO does exist in the water injection
system and can result in the severe corrosion of water injection pumps.
Temperature also has a significant effect on the corrosion rate of steels. The corrosion rate of carbon
steels increases with an increase of temperature in CO2-saturated solution at low pH 4. For example, the
corrosion rate of X65 carbon steel increases with the increase of temperature from 50oC to 90oC at pH
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
4
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The effect of salt concentration on CO2 corrosion rate of carbon or low-alloy steels was studied recently.
It was found that CO2 corrosion rate of 1018 carbon steel decreased with increasing sodium chloride
concentration from 3% to 25% in deaerated solution at temperatures of 5°C and 20°C.4, 5 The similar effect
of salt concentration from 1% to 15% on CO2 corrosion rate of X65 carbon steel was reported at a
temperature of 80°C and with a CO2 partial pressure of 0.53 bar in the total pressure of 1 bar and a pH
of 6.6 in deoxygenated aqueous solutions, as shown in Figure 1.6 Even with the presence of H2S in
solution, the CO2 corrosion rate of X65 carbon steel decreased with the increase of salt concentration at
a temperature of 60oC in aqueous solutions with H2S partial pressure of 50 psi and CO2 partial pressure
of 50 psi.7
Figure 2:
Effect of temperature on corrosion rate of carbon steel in deoxygenated aqueous
solutions 10, 11
As temperature, pH, or both increase in CO2-contained produced water, the tendency of calcium
carbonate scale formation increases. It is possible to predict the tendency of scale forming with
parameters from chemical analysis of produced water using one of the myriad scaling indices, such as
Langelier saturation index (LSI), Stiff-Davis index, Oddo-Tomson index, etc.13,14 Because of its simplicity,
the LSI is often used to estimate the potential of scale formation based on the calculated pH of saturation
of calcium carbonate (pHs) using the following expression:
LSI = pH – pHs
Where pHs = (9.3 + A + B) – (C + D)
A = (log(TDS) – 1)/10
B = (-13.12 x log(T + 273)) + 34.55
C = (log(Calcium hardness)) – 0.4
D = log(Alkalinity)
TDS in ppm
Temperature in oC
Ca hardness in ppm (as CaCO3)
Alkalinity in ppm (as CaCO3)
The factors that influence scale formation are calcium hardness, total alkalinity, pH level, water
temperature, and total dissolved solids. Calcium hardness is a key parameter in evaluating scale
formation. It generally constitutes 70% or more of the total hardness in water. In the absence of sufficient
information, calcium hardness can be considered equal to total hardness. If the value of calcium ions is
available from water chemistry analysis, calcium hardness (as CaCO3) can be estimated by multiplying
the value of the calcium ions by 2.5. The tendency of corrosion increases as the LSI value becomes
negative down to –1 or lower, indicating noticeable corrosion. On the other hand, the tendency of scale
forming increases as LSI value becomes positive up to 1 or greater, indicating scale forming but not
corrosion. Calcium carbonate scale forms more easily in heavy water with high pH, high temperature,
and high calcium hardness.
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
5
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4.2 – 4.5, as reported in both theoretical modeling and experimental data in Figure 2.10, 11 The
temperature effect on corrosion rate changes when iron carbonate (FeCO3) is formed. In another report
where iron carbonate is formed in 3.5% NaCl solution saturated with CO2, it was found that corrosion rate
increased due to the continuous formation of Fe2+ in the low-temperature range. As temperature
increased to approximately 60oC, the formed FeCO3 film became more adherent to the metal surface
and protective in nature; thereafter the corrosion rate started to decrease as temperature increased.12 In
CO2 solutions with a higher pH, the kinetics of precipitation and the formation of adherent iron carbonate
film are accelerated as temperature increases, leading to the corrosion rate decreasing with increase of
temperature after reaching to the peak of corrosion rate at temperature of 60 – 80oC.
CORROSION OF ESP METALLURGY IN CORROSIVE WELL FLUIDS
Table 2
Composition (wt% max) of a few Major Components in ESP
Materials
C
Ni-resist 1
3.0
Ni-resist 4
2.6
1026 Steel 0.11-0.28
8620 Steel 0.18-0.23
4130 Steel 0.28-0.33
9Cr1Mo steel 0.15
13Cr steel
~ 0.15
316SS
0.08
2205Duplex 0.03
Mn
0.5-1.5
0.5-1.5
0.6-1.6
0.7-0.9
0.4-0.6
0.3-0.6
1.25
2.0
2.0
Si
1.0-2.8
5.0-6.0
0.35
0.15-0.35
0.15-0.30
0.25-1.0
1.0
1.0
1.0
Cr
1.5-2.5
4.5-5.5
0.15
0.4-0.6
0.80-1.10
8.0-10.0
11.5-14.0
16.0-18.0
21.0-23.0
Ni
13.5-17.5
29.0-32.0
0.15
0.4-0.7
0.5
10.0-14.0
4.5-6.5
Mo
Cu
5.5-7.5
0.5
0.1
0.2
0.15-0.25
0.15-0.25
0.9-1.1 0.6
2.0-3.0 2.5-3.5 -
Fe
Bal.
Bal.
Bal.
Bal.
Bal.
Bal.
Bal.
Bal.
Bal.
9Cr1Mo alloy steel offers greater corrosion resistance at similar strength level compared to carbon or
low-alloy steels because it contains higher alloying elements of chromium and molybdenum. 9Cr1Mo
steel tubulars are commonly available as ESP housings. 13Cr stainless steel bar stock or tubulars have
been successfully applied as ESP components because of the good corrosion resistance in CO2containing oil production. High-alloyed stainless steels also have many applications in ESP
manufacturing. As more and more high-strength alloys are applied in ESPs, manufacturers must follow
the NACE MR0175 / ISO 15156 standard for materials for use in H2S-containing environments in oil and
gas production to avoid sulfide stress cracking (SSC) or stress corrosion cracking (SCC). Because highstrength alloys and hard weld zones are prone to SSC, special care must be taken to verify the maximum
allowed hardness in selected alloys, as well as to cracking from welding processes. The requirements of
NACE MR0175 for use in sour solutions have been defined in most specifications of ESP alloys,
minimizing the risk of SCC in ESP metallurgy.
As the most common oilfield corrosive species are carbon dioxide, hydrogen sulfide and chloride ions, it
is worthwhile to review the corrosion rates of these pump materials in the corrosive environment of oil
production. Stages (impellers and diffusers), housings, heads and bases, and shaft are the major
components in ESP pumps, as shown in Figure 3. During production, the impellers—which are keyed
into the shaft—rotate at a typical speed of 3600 rpm and push the well fluid upward in the stationary
diffusers. Corrosion of the shaft in produced water is not common as it is typically made of nickel-based
or other highly alloyed corrosion-resistant alloys. Other major components such as housings, heads and
bases, impellers, and diffusers may suffer from corrosion-related damage in corrosive well fluids during
the operation. ESP equipment is usually designed to continuously operate for 2 to 3 years in the
environment of oil production. For successful operation of ESPs through their entire design life,
understanding corrosion behavior of components is critical to properly select materials that suit the
corrosive well fluid.
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
6
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Ni-resist cast iron, carbon steel (1026) or low-alloy steels (8620, 4130, 4140, etc.), 13Cr (416, 410 or
420) martensitic stainless steel, 316 austenitic stainless steel, and 2205 duplex stainless steel are the
commonly used materials in ESP equipment for oil production, as listed in Table 2. High-nickel (15% to
30% Ni) cast irons, called Ni-resist irons, have good corrosion and erosion resistance in produced water
and are a primary material in stages (impellers and diffusers) of ESP pumps. Because of their austenitic
matrix with flake graphite, high-nickel cast irons from Type 1 to Type 4 have both good foundry property
and excellent machinability. REDA 5530 Austenitic Ductile Iron (a Schlumberger propriotary material)
has similar composition as that of Ni-resist Type 4 but with a small addition of magnesium, which turns
flake graphite into spheroidal graphite, called ductile Type 4. Compared to the low tensile strength (24 to
30 ksi) and hardness (120 to 215 HB) of Ni-resist Type 1, there is a significant improvement of tensile
strength (56 to 71 ksi) and hardness (170 to 250 HB) of REDA 5530 Ni-resist ductile Type 4.
Illustration of impeller, diffuser, housing, base & head and shaft in ESP pumps
The most comprehensive corrosion data on Ni-resist cast irons were published by Nickel Development
Institute.15 The corrosion rate of Ni-resist iron Type 1 in various corrosion media related to CO2, H2S, or
chloride-containing environments is very low, usually a few mils per year (mpy), as shown in Table 3.
The corrosion rate of Ni-resist irons from Type 1 to Type 4 (15% to 35% Ni) in chloride-containing
solutions can also be found in the Corrosion Survey Database, NACE International and their corrosion
rate is reported to be less than 20 mpy in solutions of 5% to 35% NaCl at temperatures of 25 – 225oF.16
Table 3
Corrosion rate of Ni-resist iron Type 1 in chloride-containing solution 15
Aqueous Corrosive Medium
CO2, saturated aqueous solution
NaCl, natural brine feed
Water, salt, from oil wells
Water, sea
Water, sea
T (oF) /Aeration / Velocity
~90 / Some / 80 / Moderate / Some
60 / Slight / By flow
86 / Considerable / 27f/s
158—176 / - / By flow
Corrosion rate, mpy
1
1
1
8
10
Carbon steels have been used intensively as the housing alloys of ESP system, as well as the casing of
downhole wells. Table 4 lists corrosion rates of carbon steel in several chloride-containing solutions.
Inspection of the corrosion rates indicates that many solutions of chloride ions promote severe corrosion
of carbon steel. The corrosion rate of 12Cr stainless steel (similar to the 13Cr (410, 420, and 416)
stainless steels in ESP specifications) is slower than that of carbon steel in chloride-containing solutions.
If the average corrosion rate of carbon steels is less than 2 mpy (0.05 mm/y), corrosion of steels is
considered to be mild. The corrosion rate of 20 mpy (0.508 mm/y) is considered to be the maximum
economic corrosion rate of steels in oil production.8 In practice, when corrosion rate is estimated to be
10 to 20 mpy for carbon steel in well fluids, remedial approaches of either using corrosion resistant alloys
in ESP, applying effective coatings on components or employing corrosion inhibitor programs in
downhole should be considered.
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
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Figure 3:
Table 4
Corrosion rate of carbon steel and 12Cr stainless steel in salt solutions 16
Temperature, oF
25 - 75
125 - 175
175 - 225
25 - 225
Corrosion rate,
mils/year
> 50
20 - 50
> 50
< 20
PERFORMANCE OF ESP METALLURGY IN OIL PRODUCTION
After the corrosivity of well fluids is understood from the fluid analysis and the application conditions,
proper metallurgy can be selected to build an ESP. Several examples of the application of ESP metallurgy
in different fluid conditions are described in this section.
In an ESP application for dewatering a gas well, the composition of produced water was analyzed, and
the results are shown in Table 5. There was a high concentration of chloride ions (172,896 mg/L and a
low pH (5.43) in the water measured at wellhead). There were 1.015 mol% CO2 and a very low H2S
concentration in the gas. The well temperature was 250 oF.
Because the corrosion rate of carbon steel is usually high in an acidic heavy brine produced water, carbon
steel is ruled out for the head and base alloy and, instead, stainless steels are considered. A 9Cr1Mo
steel has good resistance to CO2 corrosion and may be considered as the housing alloy in this application.
In addition, the corrosion rate of Ni-resist Type 1 under this condition is low, making it acceptable in
stages.
Table 5
Chemical analysis of produced water in a dewatering application
Cations
mg/L
meq/L
Sodium
76,000
3,306
Calcium
22,409
1,118
Magnesium
2,918
240
Iron
16.2
0.9
Potassium
5,660
145
Barium
7.6
0.1
Specific Gravity at 770F
Resistivity at 770F, ohm-meters
Total Dissolved Solids (Calc.) mg/L
Anions
Chloride
Carbonate
Bicarbonate
Sulfate
Nitrate
mg/L
172,896
0
159
150
0
meq/L
4,877
0
2.6
3.1
0
1.190
0.051
280,216
pH
NaCl (Calc.)
H2S
5.43
205,105
NEG
In another ESP application for oil production, the composition of gas and oil was analyzed and the main
components of the primary stage separator gas, the primary stage separator fluid, and the reservoir fluid
are shown in Table 6-1. Hydrogen sulfide (H2S) and carbon dioxide (CO2) were dissolved in the reservoir
fluid and the primary stage separator liquid in this well. The average reservoir pressure was 2,200 psi
and the average reservoir temperature 152 oF (66.7 oC). The chemical composition of produced water
was also analyzed, and the results are shown in Table 6-2. Based on the water analysis, LSI is estimated
to be ~ 1.6 at a temperature of 66.7 oC, which indicates that the well is mildly corrosive, but with a high
tendency of scale formation. Because the H2S content is higher than CO2 content, the corrosion process
should be dominated by H2S corrosion. A housing of carbon steel, head and base of low-alloy steel, and
Ni-resist stages are recommended for this application.
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
8
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Carbon steel
Carbon steel
Carbon steel
12Cr
Aqueous Corrosive
Medium
NaCl, 5 – 15%
NaCl, 5 – 15%
NaCl, 5 – 15%
NaCl, 5 - 15%
Table 6-1
Composition of gas and liquid in a well
Component
Mol % in primary
stage separator fluid
0.85
0.39
0.07
2.65
1.02
2.11
1.08
3.25
2.34
Mol % in primary
stage separator gas
3.32
4.14
3.59
75.67
5.27
3.54
0.91
1.82
0.53
Table 6-2
Composition of produced water in oil production
Constituents
Total Hardness (CaCO3)
Total Alkalinity (CaCO3)
Total Dissolved Solids (TDS), dried at 180oC
Calcium (Ca)
Magnesium (Mg)
Sodium (Na)
Potassium (K)
Carbonate (CO3)
Bicarbonate (HCO3)
Sulphate (SO4)
Chloride (Cl)
pH value at 25oC
Electrical Conductivity at 25oC (Micro Mohr/Cm)
Concentration, mg/L
56,250
95
222,110
17,836
2,856
83,250
3,916
Absent
116
711
156,336
6.46
287,200
The proper selection of ESP metallurgy based on the corrosivity of produced water is critical for the
successful operation of ESP. For instance, an ESP system was installed in a CO2-flooded well and
unexpectedly failed after running in the well fluid for 290 days. The failed ESP pump showed severe
corrosion at the low-alloy steel head and base and carbon steel housing, as shown in Figure 4. The flowassisted corrosion was noticed in both head and base, where the fluid changed direction and formed
turbulent areas. In this application, the setting depth of the ESP in a 5.5-in. casing was 4,878 ft (total well
depth 5,400 ft) and temperature at the time of failure was approximately 60 oC/140 oF. Reportedly, the
operator continuously injected corrosion and asphaltene inhibitors downhole via capillary tube. However,
the corrosivity of the produced water was not evaluated after the chemical treatment. The pump intake
pressure was approximately 1,500 psi and the pump discharge pressure approximately 4,000 psi. Based
on the well fluid data provided by the operator, an ESP system with standard metallurgy was supplied.
After the ESP failure, the chemical composition of the produced water was analyzed, and the results are
shown in Table 7. The produced water remained corrosive after chemical treatment. To verify the
corrosion of ESP components, coupons of 1026 carbon steel and 4140 low-alloy steel were tested using
the produced water with flowing gases of 5% carbon dioxide (CO2) and 5% hydrogen (H2) in nitrogen (N2)
at a temperature of 60oC (140 oF) for 28 days in a lab. From the calculation of material loss, the corrosion
rates of 1026 steel and 4140 steel coupons were estimated to be 13.3 mpy and 11.0 mpy, respectively.
Based on the results of water analysis and the lab test of steel coupons, it was finally realized that 13Cr
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
9
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Hydrogen sulfide
Carbon dioxide
Nitrogen
Methane
Ethane
Propane
Iso-Butane
n-Butane
Iso-Pentane
Mol % in
reservoir fluid
0.89
0.69
0.32
8.84
1.30
2.08
0.98
2.86
1.91
stainless steels as head and base and 9Cr1Mo steel as housing should be applied to achieve an expected
runlife of more than one year in this application.
Pump head
Split
pump
base
(a)
Corrosion of pump head (full);
(b) Corrosion of pump base (split);
Split pump
head
Pump housing
(c)
Corrosion of pump head (split);
Figure 4:
(d) Corrosion of internal surface of pump housing.
Corrosion of ESP pump after application in an unexpectedly corrosive well fluid
(corroded areas denoted with red arrows)
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
10
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Many wells fluids contain sand or abrasive particles that can result in erosion corrosion and accelerate
radial wear of pump components. To improve the runlife of an ESP, it is often necessary to enhance the
surface hardness of impellers and diffusers because ESP stages are primarily manufactured from soft
Ni-resist cast irons with a hardness of 131 - 183 HB for Type 1, 240 to 280 HB for Type 4 or REDA 5530
Ductile Type 4. Several surface-hardening technologies have been applied in ESPs, such as electroless
nickel plating, thermochemical processes (including nitriding, nitrocarburizing or carbonitriding,
chromium-diffusion process, boron-diffusion process), and thermal spray.
Table 7
Chemical analysis of a produced water
Sample pH
Conductivity
10360
1622
6.38
714
61071
256
4.56
52
0.00
0.00
0.00
1.26
0.082
0.00
5.40
318469
ANIONS (ppm)
Chloride (Cl)
Sulfate (SO4)
Bromine (Br)
Dissolved CO2 (CO2)
Bicarbonate (HCO3)
Carbonate (CO3)
Silica (SiO2)
Phosphate (PO4)
H2S (H2S)
Fluoride (F)
Nitrate (NO3)
Boron (B)
131000
50
600
73
0.00
0.00
0.00
0.00
0.00
0.00
0.00
4.49
PARAMETERS
Temperature (oF)
TDS
Resistivity
120
197390
3.14
Electroless nickel plating (ENP) is a chemical reduction process that depends upon the catalytic reduction
process of nickel ions in an aqueous solution and the subsequent deposition of a nickel layer on parts
without the use of electrical energy.17 Because of its low process temperature, exceptional corrosion
resistance, and high hardness, the process can be used to enhance the life of components exposed to
sandy fluids. Electroless nickel/Teflon composite coating consists of microscopic beads of Teflon codeposited up to 20% with the electroless nickel, yielding a very low-friction surface. This finish can be the
solution to sticking, galling, or drag problems with moving parts, or heated seal surfaces. In some cases,
liquid lubricants can be eliminated with the use of nickel/Teflon plating.
Nitriding or nitrocarburizing is a thermochemical process which involves the introduction of atomic
nitrogen (N) into the surface of components to form nitrides at a temperature of usually higher than 550
o
C. It has developed into a process that can enhance the surface hardness and wear resistance of cast
irons and steels.18 The most important nitriding technologies today are salt bath nitriding, gas nitriding,
and DC plasma nitriding (DCPN). Each of these processes has strengths and weaknesses. An example
of Nitrided surface of a low alloy steel is shown in Figure 5 (a). Surface hardening is achieved by the
formation of nitrides and diffusion zone.
Methods of chromium diffusion process (CDP) and boron diffusion process (BDP) have been applied to
form thin wear-resistant chromium-carbide or boron-carbide layers on ESP components by the pack
cementation method. Pack diffusion employs the chemical vapor deposition of a metal which is
subsequently diffused into the surface of a substrate at a high temperature. The chromium-rich surface
enhances both corrosion and wear-resistant properties. Boronizing is similar to the chromium diffusion
process, in which boron atoms diffuse into the metal substrate and form the boron carbide in the surface
at the temperature between 700-1000oC in 1-10 hour.19 An example of boronized surface of 8620 low
alloy steel is shown in Figure 5 (b).
Tungsten carbide hard material with an alloyed nickel-chrome binder has been applied to stage vane tips
and diffuser breakwater areas using a high-velocity oxy-fuel (HVOF) process. However, it is difficult to
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
11
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CATIONS (ppm)
Calcium (Ca)
Magnesium (Mg)
Barium (Ba)
Strontium (Sr)
Sodium (Na)
Potassium (K)
Lithium (Li)
Iron (Fe)
Field Iron (Fe)
Ammonia (NH3)
Aluminum (Al)
Manganese (Mn)
Zinc (Zn)
Lead (Pb)
apply the coating on the entire flow passage surfaces because of the line-of-sight process. Unlike
tungsten carbide in other applications, a thin coating (0.003 in.) is generally applied for ESP applications.
Diffusion zone
Nitrided surface of a low-alloy steel (original magnification X500).
Boronized zone
Matrix
b)
Figure 5:
Boronized surface of 8620 steel (original magnification X100).
Examples of surface hardening processes of low-alloy steels
The benefit of hard coating on Ni-resist stages to improve the runlife of ESP pumps in sandy fluids has
been demonstrated in a recent SPE paper.20 In tests described in that paper, Ni-resist stages (impellers
and diffusers) were coated with DURAD (a GE Oil & Gas propriotary coating), CDP, or BDP and then
assemblied in ESP pumps for comparitive tests in a sand loop. It was reported that the special DURAD
coating on Ni-resist stages had a surface hardening of 65 – 68 HRC for a thickness of 10 mils after
treating at a temperature of 550 – 580 oC. According to the results of lab tests, the specially hardened
stages, similar to BDP stages, had much less material loss than untreated Ni-resists Type 1 or Type 4
stages in the sand loop test. The dimensional change of skirt diameter of surface hardened impellers was
much smaller than that of untreated Ni-resist impellers, similar to CDP impellers, as shown in Figure 6
(a). The specially hardened stages were assembled in ESP pumps that were tested in different fields.
The field tests indicated pump run life improved significantly with the surface-hardened stages—3 to 5
times longer than the runlife of pumps with standard Ni-resist stages, as shown in Figure 6 (b).
Matrix
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
12
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a)
(b)
Dimensional change of skirt diameter of impellers with various coatings;
Run life of pumps in sandy fluids. Blue bars – stages without coating; Red bars – stages with
the DURAD hardening.
Figure 6:
Change of skirt diameter of several types of impellers and performance of pumps
in sandy fluids 20
CONCLUSIONS
The corrosivity of well fluids in oil production, the corrosion mechanisms of CO2 corrosion and H2S
corrosion, and the effect of chloride concentration and temperature on corrosion rate of steels in oil
production were discussed in detail. As partial pressure of CO2 gas in well fluids increases, the corrosion
rate of steels increases. CO2 and H2S corrosion may interact together on ESP equipment. CO2 corrosion
rate of carbon steel decreases with increasing sodium chloride concentration in downhole well fluids.
Temperature has a complicated effect on the corrosion rate of steels. The corrosion rate of carbon steel
increases with the increase of temperature in acidic well fluids. In CO2 solutions with a higher pH, the
corrosion rate decreasing with increase of temperature after reaching the peak of corrosion rate. As
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
13
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(a)
temperature, pH, or both increase in CO2-contained produced fluids, the tendency of iron carbonate
corrosion product formation increases.
To maximize runlife at a reasonably low manufacturing cost, electrical submersible pump (ESP)
components are built from various materials with different corrosion resistance. Ni-resist cast iron, carbon
steel or low-alloy steels, 13Cr stainless steel, austenitic stainless steel, and duplex stainless steel have
all been used in ESP equipment for oil production.
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D. Brondel, R. Edwards, A. Hayman, D. Hill, S. Mehta, and T. Semerad, “Corrosion in Oil Industry”,
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B. Kermani, J. Martin, and K. Esaklul, “Materials Design Strategy: Effect of H2S/CO2 Corrosion on
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©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
14
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Materials and the performance of pump components in the corrosive environment of oil production were
discussed. The proper selection of ESP metallurgy based on the corrosivity of produced fluids is critical
for the successful operation of ESP. To improve the runlife of an ESP in well fluids containing abrasives,
several surface-hardening technologies, including electroless nickel plating, nitriding, chromium-diffusion
process, boron-diffusion process, and thermal spray, have been applied in ESPs.
Corrosion Survey Database (COR*SUR), NACE Publication (2002).
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R. Parkinson, “Properties and Applications of Electroless Nickel”, Nickel Development Institute,
publication No. 10081.
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E.J. Mittemeijei, “Fundamentals of Nitriding and Nitrocarburizing”, Steel Heat Treating and
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R. Bianco, M.A. Harper, R.A. Rapp, “Codepositing Elements by Halide-activated Pack
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20.
H. Munoz, R. Mazzola, M. Bruni, R. Teves and R. Oyarzun, “Experiences of DURAD Pumps, a
special hardened stage for sandy wells”, SPE ESP Workshop (2015).
©2018 by NACE International.
Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to
NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.
The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.
15
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16.