Seawater Material c2012-0001632

Material Selection and Corrosion Control for Topside Process and Utility Piping and Equipment

R.T. Hill, F.A. Ramirez, and A.L. Perez UniversalPegasus International

777 North Eldridge Parkway, Suite 700 Houston, Texas, 77079

B.A. Monty

Modec International, Inc. 14741 Yorktown Plaza Drive

Houston, Texas, 77040

ABSTRACT

This paper gives guidelines for the material selection and corrosion control philosophies for topside process (multiphase/crude, gas, and produced water) and utility (raw seawater, de-aerated seawater, chemical injection, etc) piping and equipment. For process piping and equipment, the paper discusses CO2 internal corrosion predictions on carbon steel, as well as pitting and chloride stress cracking of corrosion resistant alloys due to high chloride contents in the produced water. For the utility systems, the paper discusses the corrosivity of the internal fluids and establishes suitable materials. The paper also addresses external corrosion control strategies based on using high durability painting systems supported by adequate surface preparation requirements. Key words: Corrosion, Process Facilities, Oil and Gas

INTRODUCTION

Due to the large demand for hydrocarbons, operators are now developing deep water, high pressure, high temperature, high CO2, high H2S, and high chloride fields. This trend results in numerous challenges to the capital cost (CAPEX) and operating cost (OPEX) of projects. Due to the complexity of the topsides processes, the piping and equipment selection represents an important part of the overall project costs (CAPEX/OPEX). The material selection can be optimized based on a good understanding of the corrosion mechanisms and the fluid partitioning through the topsides production systems.

The inlet wellstream into the facility is separated into three basic product streams from the facility: Crude which is stabilized (degassed) to meet crude product vapor pressure specifications,

dehydrated, and desalted.

2012 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, 1440 South Creek Drive, 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.

C2012-0001632

Gas which is compressed and dehydrated to be exported, to be injected into the field for maintaining the reservoir pressure, or to be used as fuel gas in the facility.

Produced water which is treated to remove oil to meet overboard water disposal specifications. At reservoir conditions, the crude exists as a single phase. As the reservoir fluid is produced through the wellbore, flowlines, and risers to arrive at the inlet conditions of the facility, associated gas begins to form as a separate phase due to the reduction in pressure relative to reservoir conditions. The CO2 becomes concentrated in the gas phase by the time it reaches the first stage separator of the topsides processing facility. The separation of the three phases primarily occurs in the crude separation and stabilization process. Bulk separation occurs in the high pressure (HP) separator. The application of heat allows for more refined separation in subsequent stages. Special coalescence technologies are applied in the final stages to remove additional waters not able to be removed by gravity separation techniques alone. The gas leaving the latter stages of crude separation and stabilization process contains large quantities of H2O as vapor. When the gas is cooled prior to entering the flash gas compression, the concentration of CO2 increases in the gas phase due to H2O vapor condensing out of the liquid/water phase. The produced water that leaves the oil and gas separation system is treated in the produced water treatment system to degas the water and remove the oil. Over time, the amount of water produced with the crude will increase. The composition of the water is essentially the same throughout this system as through the crude separation and stabilization process. However, dissolved gases may have flashed out of solution. This is attributed to lower operating pressures of the vessels in the produced water system relative to the operating pressure of the HP separator (where bulk water phase removal takes place) and other separators in the crude separation-stabilization system. The utility systems also play a paramount role in the facilities. For instance, raw seawater is used to cool-down the cooling medium which is used to cool-down the crude before being stored, the gas after each compression stage, and the produced water before been sent overboard. After proper treatment of the seawater (de-aeration and sulfate removal), the treated water may be injected to the reservoir as an enhanced oil recovery method. Treated seawater is also used as fresh water after going thru a reverse osmosis process where salts/ chlorides are removed. In some instances, treated seawater (de-salted, inhibited, and in some cases de-aerated) may be used as cooling and heating media; in other cases, evaporator quality water may be used for these services.

CORROSION MECHANISMS Various corrosion mechanisms may be relevant to the production and processing of hydrocarbons. This section briefly reviews and discusses the most prevalent of these mechanisms. Internal Corrosion Table 1 shows the typical internal corrosion threats for topsides process facilities.

CO2 and H2S Corrosion. CO2 corrosion, or sweet corrosion, is one of the most common corrosion mechanisms that affect carbon steel and low alloy steel piping and equipment. CO2 is a highly soluble gas that dissolves in water to form carbonic acid. Carbonic acid causes a reduction in the pH of water and results in corrosion when it comes in contact with carbon steel. When carbon steel corrodes in water containing



CO2, the hydrogen ions remove electrons from the metal surface while the carbonic anions may take part in the formation of an iron carbonate (FeCO3) film. Under certain conditions, this film may help to reduce the corrosion rate. The iron carbonate film is deposited when the temperature exceeds a limit that corresponds to a specific CO2 partial pressure. This temperature is referred as the scaling temperature.

Table 1 Internal Corrosion Mechanisms

Corrosion Mechanism Carbon and Low

Alloy Steels (NOTE 1)

CRA (NOTE 1)

CO2 and H2S corrosion (General mass loss BLC and TLC)

Yes No

H2S cracking corrosion (SSC, HIC) Yes Yes

(SSC)

Chloride induced pitting / chloride contribution to pitting Yes Yes

Chloride SCC No Yes

Corrosion from dissolved oxygen Yes Yes

(Pitting and cracking in the presence of chlorides and high temperatures)

MIC Yes Yes

Notes: 1) Galvanic corrosion due to dissimilar material connections is also a corrosion threat.

When acetic acid, an organic acid, is present, it dissolves in the aqueous solution. In addition to the potential for reducing the pH, acetic acid may prevent the formation of the iron carbonate film and attack the existing scale. On the other hand, the presence of bicarbonates (HCO3-) in the produced water increases the pH and reduces the corrosion rates. The most important parameters for CO2 corrosion are temperature, partial pressure of CO2, produced water composition, and flow conditions. The presence of H2S in combination with CO2 influences the corrosion of carbon steel. The corrosion product (iron sulfide or mackinawite) formed by the combination of H2S and water on carbon steel is a tenacious scale that helps reducing the general CO2 corrosion rate. General mass-loss corrosion caused by H2S-dominated corrosion conditions is rarely a problem. However, if the iron sulfide scale is damaged, localized pitting corrosion can occur.

H2S Cracking Corrosion. The presence of H2S, referred to as sour environment, can lead to localized attack in the form of sulfide stress cracking (SSC) and hydrogen induced cracking (HIC) These forms of corrosion are brittle mechanical fractures caused by diffusion and penetration of atomic hydrogen into the crystal structure of steel. The H+ ions present in the acidic solution combine at the cathode with electrons, released by the steel, to form atomic hydrogen on the steel surface. Normally, the adsorbed hydrogen at the surface of the steel will recombine to form hydrogen gas (H2). However, the sulfide ions will poison the recombination of hydrogen atoms thus promoting hydrogen atoms diffusion into the steel. Diffused hydrogen atoms are trapped at sensitive microstructural locations.



For carbon steel, low alloys steels, and martensitic stainless steels, the maximum susceptibility to hydrogen embrittlement is at ambient temperatures. As the temperature increases, the hydrogen diffusion increases and, therefore, the possibility for hydrogen entrapment/embrittlement decreases. NACE MR0175/ISO 15156-21 has established 4 SSC severity regions for carbon steel and low alloy steels exposed to H2S (see Figure 1 of the subject standard) Region - 0: This region was regarded as Non-Sour in previous editions of the subject standard.

The discontinuity shown in Figure 1 of the subject standard below 0.003 bar_a H2S partial pressure and low pH reflects uncertainty in the steel performance.

Regions 1-3: The severity of the region will depend on the environment pH and H2S partial pressure.

For SSC, many of the NACE MR0175/ISO 15156-2 requirements are related to hardness restrictions. Materials that exceed the specified hardness limits may be utilized after appropriate testing.

On the other hand, the HIC process does not require the presence of stress. HIC occurs when atomic hydrogen generated by the corrosion reaction diffuses through the steel and then accumulates as gaseous hydrogen at voids, segregation bands, and other anomalous structures that provide enough intergranular space. As more hydrogen accumulates, the pressure increases deforming the surrounding steel. The probability of HIC occurrence in carbon steel is influenced by steel chemistry and manufacturing route. HIC leading to loss of containment has occurred rarely in seamless pipe and other products that are not flat-rolled. The resistance of flat-rolled products to HIC can be improved by reducing the amount of inclusions (thru restrictions on sulfur content), controlling the shape of inclusions (thru calcium or rare earth metal treatments), minimizing microstructural banding from chemical segregation and associated temperature transformation products (thru proper balance of carbon, manganese, and phosphorous).

For corrosion resistant alloy (CRA) materials, NACE MR0175/ISO 15156-3 and NORSOK M-0012 have established different limiting operating and environmental parameters (temperature, partial pressure of H2S, chloride content, and pH) (See Table 2) to avoid SSC. For duplex and 316/316L stainless steels (common material for process piping), the subject standards give a small combination of operating/environmental parameters which does not suffice the industry requirements. Therefore, significant testing has been performed by the industry to validate the use of duplex and 316/316L under a wider range of environments. Table 3 shows some of the operating/environmental combinations where these materials have been successfully tested.

Chloride Induced Pitting and Stress Corrosion Cracking. Although for carbon steel the majority of corrosion takes place as general corrosion, the presence of chlorides produces conditions favorable for localized corrosion. While stainless steels such as duplex (UNS S32205/S31803), super duplex (UNS S32750/S32760), 316/316L austenitic (UNS S31600/S31603) and 904L super austenitic (UNS N08904) are resistant to CO2 corrosion, they are susceptible to pitting and chloride stress corrosion cracking (CSCC). Pitting corrosion is defined as the localized attack on a metal surface in locations where the overall metal surface is relatively un-corroded and is often covered with passive films or scales. Unlike general attack, pitting corrosion may start and propagate quickly leading to significant damage. Chloride stress corrosion cracking is defined as the brittle failure of an otherwise ductile material due to the presence of tensile stresses and chlorides. CSCC initiation sites include pits, metallurgical defects, surface discontinuities, intergranular corrosion, and other stress raisers. Stainless steel corrosion can be defined as a two step process; initiation and propagation. The initiation, or breakdown of the passive film, depends mainly on the chromium and molybdenum contents. The propagation depends mainly on optimum nickel content9. The chloride salts impair the passive state of the iron-chromium alloys and the addition of molybdenum increases the resistance in such environments. The susceptibility to CSCC in stainless steels is a function of the composition of the



microstructural phases and the presence of chromium depleted zones around precipitates. These forms of corrosion depend on the chloride concentrations, oxygen concentrations, and temperatures, (as well as the stress levels for CSCC). Figures 1 and 2 show the resistance of different stainless steels to chloride stress corrosion cracking (CSCC) and crevice corrosion, respectively, in oxygen bearing environment with respect to temperature and chloride level. Note that the chloride level in seawater is approximately 20,000 ppm (2%). The effect of oxygen is crucial; for instance, the resistance of 316/316L to cracking is significantly higher in oxygen free environments than in oxygen bearing environments (i.e. for comparison, refer to Tables 2 and 3, oxygen free environment, and Figure 1, oxygen bearing environment). The material resistance to localized corrosion is generally related to the pitting resistance equivalent number (PRE) which is a function of the chromium (Cr), molybdenum (Mo), and nitrogen (N) content, the critical pitting temperature (CPT), and the critical crevice temperature (CCT). Typical PRE, CPT, CCT numbers are shown in Table 4. The CPT and CCT numbers should only be used for comparison purposes between the different steels since they are obtained using a ferric-chloride environment in accordance with ASTM G48 which does not reflect the actual operating conditions.

Table 2 NACE MR0175 / ISO 15156 and NORSOK M-001 Operating/Environmental Limitations for CRA

Materials

Material

Temperature (C)

Partial Pressure of H2S (bar)

Chlorides (ppm)

pH Reference

1

316 or 316L

60 1.0 any any

NACE MR0175/ ISO 15156-3

2 any any 50 any

3 93 (Note 1) 0.1 5,000 >5.0

4 149 (Note 2) 0.1 1,000 >4.0

5 120 1.0 1,000 3.5

ISO 15156 Ballot (awaiting acceptance) 3

6 90 10.0 1,000 3.5

7 90 0.01 50,000 4.5

8 60 10 50,000 4.5

9 120 0.1 10,000 3.5

NORSOK M-001 (Note 1) 10 120 0.01 50,000 3.5

11 120 0.1 50,000 5.0

12

Duplex (30 < PRE < 40)

232 0.1 any any NACE MR0175/ ISO 15156-3 13 Any Any 50 any

14 150 0.02 30,000 3.5 NORSOK M-001

15 150 0.1 10,000 3.5

16

Super Duplex (PRE>40)

232 0.2 any any NACE MR0175/ ISO 15156-3

17 any any 50 any

18 150 0.1 50,000 3.5 NORSOK M-001

19 150 0.4 50,000 4.5 Notes:

1) Limits are given for 316 SS 2) Limits are given for 316L SS 3) The limits given assume oxygen free environments.



Table 3

Additional Operating/Environmental Combinations in which CRA Materials Have Been Successfully Tested

Material

Temperature (C)

Partial Pressure of H2S (bar)

Chlorides (ppm)

pH Reference

1

316L

79 0.034 50,000 3.5 [4]

2 107 0.034 10,000 3.5 [4]

3 178 0.0 150,000 3.5 [5]

4

Duplex (Notes 1 and 2)

90 0.1 130,000 4.5 [6]

5 150 0.1 130,000 4.5 [6]

6 80 0.1 100,000 4.5 [7]

7 90 0.1 130,000 4.0 [6]

8 150 0.1 130,000 4.0 [6]

9 150 0.1 130,000 3.5 [6]

10 80 0.04 90,000 4.5 [8]

11 80 0.03 150,000 4.5 [8]

12 80 0.05 60,000 3.2 [8]

13 80 0.02 90,000 3.2 [8]

14 80 0.01 125,000 3.2 [8]

15 80 0.005 150,000 3.2 [8]

16 80 0.34 100,000 4.5 [7]

17 80 0.30 60,000 4.5 [8] Notes: 1) Duplex stainless steels are most susceptible to SSC between 80 to 110 C. At higher temperatures, the hydrogen

diffusion rate is high enough to prevent hydrogen entrapment. 2) Duplex tested have a pitting resistance equivalent number (PRE) of approximately 35. 3) The limits given assume oxygen free environments.

Table 4

Typical PRE, CPT, and CCT Numbers for Stainless Steels

Materials Typical PRE CPT (C) CCT (C)

304L 19 2.5-4 - 316L 24-26 5-15

greater than 40 are required for adequate crevice corrosion resistance to ambient-temperature seawater service.

Figure 1: Resistance of Different Stainless

Steels to CSCC.11

Figure 2: Resistance of Different Stainless Steels to Crevice Corrosion.11

Under normal seawater service, the stainless steels can be subjected to under deposit corrosion, an accelerated form of pitting corrosion. If part of the stainless steel surface is covered with deposit, or if there is a mechanical crevice such as a gasket, the localized environment will naturally tend to become oxygen depleted and anodic to the aerated exposed surface. The occluded site will then develop a corrosion potential substantially more active than the surrounding passivated surface. The corrosion current density within the pit is very high and this attracts chloride ions into the pit by electro-migration to maintain charge neutrality. Even if the bulk solution is at neutral pH (7.0), the pH in the pit can have much lower pH values (acidic). With a small anode (pit) and a large cathode (surrounding area), high corrosion rates are encountered. Pitting of stainless steels can produce a through wall-penetration with nearly negligible weight loss to the piping/tubing. Chloride pitting usually results in undercutting and produces large subsurface cavities.

Microbiologically Induced Corrosion. Microbiologically induced corrosion (MIC) from sulfate-reducing bacteria or other bacteria such as acid-producing bacteria and nitrate-reducing bacteria, can lead to high local corrosion rates. Low flow velocities increase the likelihood of MIC. Microbial activity is likely to occur in dead legs and bypasses where water can sit stagnant and be cooler than the bulk water temperature. Service temperature is a critical consideration with regard to microbial activity. Mesophiles are the most common group associated with corrosion problems in the oil and gas industry. Given the high operating temperature, Mesophiles will not pose a risk to the sections of plant operating continuously at a temperature above 75C. Infection of the system (via seawater) with bacteria that can survive and proliferate at the planned operating temperatures remains possible. If the line were to become infected with a species of bacteria that proliferates at the service temperature, MIC corrosion rates can be extreme and active. Pitting corrosion in excess of 10 mm/yr is common in systems affected by active MIC.

Galvanic Corrosion. Galvanic corrosion can result from electrical contact between two different metals. In order for galvanic corrosion to occur, the anode and cathode must be in electrical contact and exposed to a continuous electrolyte environment. The potential difference between the two metals can cause significant increase in corrosion rate of the less noble material (i.e. anode). The extent of galvanic corrosion is strongly



influenced by the area ratio of the two metals, the conductivity of the electrolyte, oxygen content, and temperature. For hydrocarbon production and process systems which involve anaerobic corrosive fluids in which the cathodic process is not driven by dissolved oxygen, internal galvanic corrosion is not generally a concern.12 External Corrosion The external marine atmospheric environment contains water and chloride salts. The marine environment can affect both carbon steels and CRA materials. CRAs are particularly vulnerable to stress corrosion cracking, especially at the welds due to residual stresses and geometric stress concentrations. Corrosion under insulation (CUI) and fireproofing is another external corrosion integrity threat for both carbon steel and CRA materials.

CORROSION ASSESSMENT

The corrosion assessment for topside piping and equipment considers both internal and external corrosion threats. Internal Corrosion A corrosion evaluation is performed to determine the general corrosivity of the fluids for the materials under consideration. For wet hydrocarbon processing piping and equipment, carbon steel is considered the base case material option. When carbon steel, even with the use of corrosion allowance and corrosion inhibition, cant guarantee the integrity of the equipment, CRA materials are considered. When CRA materials are used, other corrosion risks/threats are identified. In general, the environment aggressiveness for CRA materials is determined based on temperature, chloride content, H2S partial pressure, and pH. For hydrocarbon fluids, the ASPEN HYSYS(1) simulation model is used to predict the fluid partitioning thru the topside process equipment. The outputs of the simulation model are referred to as heat and mass balance (HMB). The corrosion assessment methodologies and criteria are listed in Table 5. A maximum use of previous field experience is used when assessing the corrosion likelihood. The assessment also account for the poss1ible change of produced fluid composition due to reservoir souring.

Table 5 Criteria for Corrosion Assessment

Item Corrosion

Phenomenon Parameters Studied Remarks

1 CO2 corrosion and CO2 + H2S corrosion

Pressure: normal service pressure from (HMB) Temperature: normal service temperature from HMB Flow velocities: flow rates from HMB in conjunction with line sizing criteria (see item 8) Water content: water content from HMB Produced fluid composition: predicted CO2 and H2S partitioning throughout the process facility from HMB Water composition: representative water analysis, including organic compounds. The partitioning of

The evaluation criterion is based on corrosion risks and calculated corrosion rates using public domain software. The normal service operating parameters for each of the streams evaluated are obtained from the HMB. The different modeling scenarios/cases evaluated are considered. For piping transporting all-liquid dual phase hydrocarbons (oil, condensate, produced water), the CO2 (and H2S) partial pressure for the last separation stage is used to estimate the corrosion rate to account for CO2 and (H2S) dissolved in the water phase. The corrosion assessment is based on oxygen free environments.

(1) ASPEN HYSYS software from AspenTech



Item Corrosion Phenomenon

Parameters Studied Remarks

the produced water constituents thru the facility is not well established. For produced/process liquids: the water chemistry is taken into account for streams containing produced water. For produced/process gas: condensed water with organic acids is conservatively assumed (i.e. the pH buffering effect of the bicarbonate content is neglected). Chlorides are assumed to be present. However, downstream of the gas scrubbers, field experience has shown that the chloride content is typically below 50 ppm.

Reference is made to previous field experience, in-house documentation, and open literature. When H2S is present, the following approaches are taken: a. When H2S composition is certain / confirmed: when the H2S composition is clear, the beneficial effects of the iron sulfide scale product are taken into account. However, caution is taken since if the scale is damaged, localized pitting corrosion can occur. b. When H2S composition is uncertain: if the H2S composition is uncertain or if H2S is expected in the future due to reservoir souring, the beneficial effects of the iron sulfide scale product are not taken into account. However, the localized corrosion effects (i.e. HIC and SSC) of H2S are taken into account (See Item 3)

2 Environmental induced cracking (H2S SSC and chlorides effects)

Carbon Steel: Pressure: maximum expected pressure in the process stream. Temperature: temperature range from ambient to operating temperature from HMB pH: minimum calculated in-situ pH. CRA: Pressure: maximum expected pressure in the process stream. Temperature: normal service temperature from HMB and critical temperature for CRA (see remarks). pH: minimum calculated in-situ pH. Chlorides: (see chloride content discussion on Items 1 and 2)

The evaluation criterion is based on NACE MR0175 / ISO 15156, supported by field experience, and published literature. For piping transporting all-liquid dual phase hydrocarbons (oil, condensate, and produced water), the H2S partial pressure for the last separation stage is used to estimate the corrosion rate to account for H2S dissolved in the water phase. The corrosion assessment is based on oxygen free environments. Carbon, low alloy, and martensitic steels are most susceptible to SSC at ambient temperature. As the temperature increases, the hydrogen diffusion rate increases and the probability of hydrogen entrapment decreases. Other CRAs, such as duplex stainless steels are most susceptible to SSC between 80 to 110 C. At higher temperatures, the hydrogen diffusion rate increases and there is low possibility of hydrogen entrapment.

3 H2S cracking (HIC) See remarks The probability of HIC is influenced by steel chemistry and manufacturing route. When evaluated flat rolling carbon steel, HIC should be considered even when there is small trace amounts of H2S.

4 Chloride induced pitting and stress corrosion cracking of CRA materials (utility and other services)

Chloride content: maximum chloride content expected Temperature: normal service temperature from HMB pH: minimum calculated in-situ pH. Oxygen: maximum oxygen content expected

--

5 Corrosion from dissolved oxygen (hydrocarbons)

See remarks The ingress of oxygen into process systems is an operationally avoidable upset condition and therefore is not considered for internal corrosion assessment.

6 Corrosion from dissolved oxygen (injection water)

Oxygen content: see remarks

A maximum oxygen content of 10 ppb, (with excursion up to 30 ppb) is accepted in injected water.

7 Microbiological Induced Corrosion

Flow rates: minimum flow rates Water content: maximum water content Temperature: Range of operating temperatures.

MIC is to be considered as a major issue in liquid flow conditions with no or limited gas production (oil, water injection, produced water, potable water, cooling/heating media, etc). MIC is particularly present at low velocities (below 1.5 m/s).

8 Liquid Erosion Corrosion

Pressure: service pressure from HMB Temperature: service temperature from HMB Overall parameters: overall mass flow, and overall mass density from HMB Gas parameters: standard gas flow, mass density, molecular weight, gas compressibility, and gas viscosity from HMB Oil parameters: actual liquid volumetric flow, liquid mass density, and liquid viscosity from HMB

The operating parameters for each of the streams evaluated are obtained from the HMB. The worst case from the different modeling scenarios/cases evaluated is considered. Maximum expected flow rate characteristics are used for the analysis. The evaluation criterion is based on in-house line sizing practice for liquids, gas, and two-phase streams. The criterion depends on material, piping size, pump suction and discharge sections, compressor suction and discharge sections, etc.

9 Galvanic corrosion Electrolyte effectiveness Connection between dissimilar metals: --



External Corrosion The degree of external corrosion depends on atmospheric conditions such as temperature, wind speed, humidity, UV radiation, environmental salinity, and the corrosive pollutant gasses that may be present in the area. The external corrosion rate relating to marine environments is mostly caused by extended periods of wetness as well as high concentrations of chlorides. Atmospheric conditions such as wind speed, temperature, atmospheric pressure, and relative humidity over the course of a year have a significant impact. For carbon steel, ISO 12944-212 provides levels of expected corrosion in terms of material loss. ISO 12944-2 has classified offshore platforms as structures subjected to high atmospheric corrosion, C5-M. Marine corrosion of unprotected steel is typically in the range of 80 - 200 m per year. For CRA materials, ISO 2145713 defines maximum operating temperature limits to prevent CSCC. For uncoated type 316 SS austenitic steels, the standard limits the maximum operating temperature to 50 - 60 C. For uncoated duplex stainless steels, the standard limits the temperature to 80 100 C. The lower temperature limits represent cracking in the worst case situation, at high tensile stresses and high chloride concentrations. These lower temperature limits are based mostly on laboratory experiments.

Pitting and crevice corrosion may occur at temperatures lower than those given above.

CORROSION MITIGATION METHODS Internal Corrosion Mitigation Methodology The selection of the internal corrosion mitigation method is based on the results of the corrosion assessment. The following corrosion mitigation methods are considered: For produced/process fluids piping and equipment:

- The use of carbon steel (CS) with corrosion allowances (CA) (i.e. 1.5 mm, 3.0 mm, or 6.0 mm).

- The use of carbon steel with corrosion allowance and chemical injection (CI) (corrosion inhibition, pH control, etc). When corrosion inhibition programs are used, the following considerations are taken:

a. Process vessels that treat systems with a gas phase should not rely on chemical inhibition as an effective mean of corrosion protection due to lack of proper inhibition distribution.

b. In general, topside gas systems should not rely on corrosion inhibitors as a barrier for corrosion due injection complexity and difficulty in maintaining proper inhibition coverage.

- The use of carbon steel vessels with organic coating and cathodic protection. The use of coatings and cathodic protection should be avoided when the coating integrity cant be guaranteed (e.g. high service pressures or temperatures, presence of solids in the fluid, etc).

- The use of corrosion resistant materials (e.g. solid CRAs, CRA cladding or overlay). - Proper design (velocities, prevention oxygen contamination, avoidance of dead legs to prevent

stagnate water accumulation, etc). - The use of physical treatments for removal of main corrosive species (gas dehydration, oil

stabilization and dehydration, CO2 removal, etc)

For utilities and other services piping and equipment: - The use of carbon steel with corrosion allowances (i.e. 1.5 mm, 3.0 mm, or 6.0 mm). - The use of carbon steel with corrosion allowance and chemical injection (corrosion inhibition, pH

control, biocides, oxygen scavenger, etc). - The use of carbon steel vessels with organic coating and cathodic protection.



- The use of corrosion resistant materials (e.g. fiber reinforced polymers, solid CRAs, CRA cladding or overlay).

- Proper design (velocities, prevention oxygen contamination, avoidance of dead legs to prevent stagnate water accumulation, etc.

- The use of physical treatments for removal of main corrosive species (seawater de-aeration, filtration, salts removal by reverse osmosis, etc)

Table 6 shows common mitigation methods for most facilities. The subsequent sections show mitigation methods for specific systems; for instance, Table 7 addresses Oil Separation and Stabilization Systems, Table 8 addresses Gas Compression and Dehydration Systems, Table 9 addresses Produced Water Treatment Systems, Table 10 addresses Seawater Systems, and Table 11 addresses other systems.

Table 6 General Corrosion Mitigation Methods

System Main Threats Mitigation Methods

General Liquid erosion corrosion and/or solid erosion corrosion

Proper design to account for velocity limitations.

Oxygen ingress in process streams

Oxygen ingress should be avoided at all times. Oxygen in chemicals to be injected should be controlled. Oxygen ingress at pumps or other equipment should be controlled.

MIC Chemical/biocide injection Velocities should be maintained above 1.5 m/s whenever possible. Water accumulation and trapping should be avoided.

Oil General

Generally, the oil is to be stabilized and dehydrated to produce a low salt content and a maximum BS&W of 0.5% vol.

Gas General Generally, the gas is to be dehydrated to be used as fuel gas, gas lift, gas injection, and export gas.

pH (TEG- glycol regeneration)

When glycol dehydration is used, the glycol pH is to be controlled using chemical injection.

Produced water General

The produced water removed from the process is treated. Skimmed hydrocarbons are removed and directed to the off-spec tank in the hull.

Seawater General Seawater for injection purposes is to be de-aerated (vacuum de-aeration followed by oxygen scavenger) to target values of 10 ppb of oxygen. Typically, the vacuum de-aeration will achieve oxygen levels of 50 ppb and the oxygen scavenger will further reduce the oxygen levels to 10 ppb. The water treatment also includes multi-media filters and sulfate removal units.

Cooling / Heating Media

General The cooling/heating media are closed loop type. Chloride content and oxygen content are kept to a minimum. The cooling/heating media is to be inhibited.

Table 7

Oil Separation and Stabilization System Equipment Main Threats Mitigation Methods

General CO2 and CO2 + H2S corrosion Material selection and/or chemical injection: see specific cases below.

H2S cracking Materials should be qualified to NACE MR0175 / ISO 15156, as applicable. When carbon steel is used, the material chemistry should be controlled to avoid HIC (i.e. especially, sulfur and phosphorous content).

Galvanic corrosion at CS/CRA connections

For dissimilar metal flange connections of piping carrying fluids with high water cuts (upstream of dehydrated oil), the carbon steel flange face and ring groove should be CRA overlaid.

Separators and Vessels

CO2 and CO2 + H2S corrosion (* Chloride, temperature, pH and H2S partial pressure for CRAs)

Base Case: CS + CA Option 1: CS + cladding. Typical cladding material for separators containing

liquids with high chloride content is 904L. However, The CRA* material should be selected based on the Corrosion Assessment.

Option 2: CS + coating and anodes. Coating is not recommended for high pressure separators and vessels that may be subjected to the following: a) possible solid-erosion corrosion from inlet fluids. b) coating integrity may not be guaranteed due to high service pressures and/or temperatures. c) the fluid may be very corrosive and coating breakdown can promote severe pitting (to be confirmed based on Corrosion Assessment). If Option 2 is selected, the anode design life should be 5 years. The CP design should take into consideration the



Equipment Main Threats Mitigation Methods

characteristics of the produced water and operating conditions (temperature). Other Remarks: CS + CA + CI: this option should not be considered for

multiphase (with gas phase) separators or vessels. Three-phase process vessels should not rely on chemical inhibition as an effective mean of corrosion protection due to lack of proper corrosion inhibitor distribution.

Heat Exchangers CO2 and CO2 + H2S corrosion (* Chloride, temperature, pH and H2S partial pressure for CRAs)

Corrosion allowances are not generally available for carbon steel tubes, and thus, it may be necessary to consider CRA materials for the tubes (or plates). Typical tube and plate materials for streams containing high chlorides are duplex and titanium, respectively. However, The CRA* material should be selected based on the Corrosion Assessment.

The heating/cooling media also posses other threats that need to be mitigated (Table 6).

Piping CO2 and CO2 + H2S corrosion (* Chloride, temperature, pH and H2S partial pressure for CRAs)

Base Case: CS + CA Option 1: CRA. Typical CRA material used for piping containing liquids with

high chloride content is duplex. However, The CRA* material should be selected based on the Corrosion Assessment.

Option 2: CS + cladding. Typical piping cladding CRA material is 316L, 904L, 625 or 825. However, The CRA* material should be selected based on the Corrosion Assessment.

Option 3: CS + CA + CI. The use of corrosion inhibition program may be considered. The corrosion inhibition program represents higher risk and may be reflected in higher life cycle cost.

Valves CO2 and CO2 + H2S corrosion (* Chloride, temperature, pH and H2S partial pressure for CRAs)

The valve body material should be compatible with the piping material. Valve internals should have better corrosion resistance than the body. The CRA* material should be selected based on the Corrosion Assessment.

Materials for valve internals should have wear and abrasion resistance for use in fluid services containing suspended solids.

If carbon steel valves are used in streams containing liquids with high water cuts (upstream of dehydrated oil), the seat pockets and sealing areas should be overlaid with Alloy 625.

Pumps CO2 and CO2 + H2S corrosion (* Chloride, temperature, pH and H2S partial pressure for CRAs)

The pump casing material should be compatible with the piping material. Pump internals should have better corrosion resistance than the body. The CRA* material should be selected based on the Corrosion Assessment.

Table 8

Gas Compression and Dehydration System Equipment Main Threats Mitigation Methods

General CO2 and CO2 + H2S corrosion (TLC)

Material selection: see specific cases below Chemical injection: In general, gas systems should not rely on corrosion

inhibitors as barrier for corrosion. H2S cracking Materials should be qualified to NACE MR0175 / ISO 15156, as applicable. When carbon steel is used, the material chemistry should be controlled to avoid

HIC (i.e. especially, sulfur and phosphorous content). Scrubbers CO2 and CO2 + H2S corrosion

(* Chloride, temperature, pH and H2S partial pressure for CRAs)

Base Case: CS + CA Option 1: CS + cladding. Typical cladding material for scrubbers is 316L.

However, The CRA* material should be selected based on the Corrosion Assessment.

Other Remarks: CS + coating and anodes. Coating is not recommended for scrubbers due to the following reasons: a) coating integrity may not be guaranteed due to high service pressures and/or temperatures, b) the fluid may be very corrosive and coating breakdown can promote severe pitting (to be confirmed based on Corrosion Assessment), and c) coating may be damaged by compressor suction.


Corrosion allowances are not generally available for carbon steel tubes, and thus, it may be necessary to consider CRA materials for the tubes. Typical tube materials for gas streams are 316L and duplex. However, The CRA* material should be selected based on the Corrosion Assessment.

The heating/cooling media also posses other threats that need to be mitigated (Table 6)

Piping CO2 and CO2 + H2S corrosion (* Chloride, temperature, pH and

Base Case: CS + CA Option 1: CRA. Typical CRA material used for gas streams are 316/316L dual

grade1 and duplex. However, The CRA* material should be selected based on




H2S partial pressure for CRAs)

the Corrosion Assessment. Option 2: CS + cladding. Typical piping cladding CRA material is 316L or 825.


Compressors CO2 and CO2 + H2S corrosion (* Chloride, temperature, pH and H2S partial pressure for CRAs)

Base Case: CS + CA casing and CRA* impeller. Option 1: CRA casing and impeller. Typical CRA material used for impeller is

13% Cr. Typical CRA material used for casing is 13% Cr or 316L. Overlay can be also considered. However, The CRA* material should be selected based on the Corrosion Assessment.


The valve body material should be compatible with the piping material. Valve internals should have better corrosion resistance than the body. The CRA* material should be selected based on the Corrosion Assessment.



Piping Downstream of Gas Treatment Unit

-- Material: CS + 1.5 mm

Note:

1) The 316/316L SS dual grade means that the material should have the mechanical properties of 316 SS while having a maximum carbon content of 0.030% to avoid sensitization in the heat affected zone.

Table 9

Produced Water Treatment System Equipment Main Threats Mitigation Methods

General CO2 and CO2 + H2S corrosion (TLC)

Material selection: see specific cases below

H2S cracking Materials should be qualified to NACE MR0175 / ISO 15156, as applicable. When carbon steel is used, the material chemistry should be controlled to avoid HIC (i.e. especially, sulfur and phosphorous content).

Galvanic corrosion at CS/CRA connections

For dissimilar metal flange connections, the carbon steel flange face and ring groove should be overlaid with alloy 625.

Water Collection / Skim Vessel and Floatation Cell

CO2 and CO2 + H2S corrosion (* Chloride, temperature, pH and H2S partial pressure for CRAs)

Base Case: CS + CA. Option 1: CS + CA + coating and anodes. The anode design life should be 5

years. The CP design should take into consideration the characteristics of the produced water and operating conditions (temperature).

Option 2: CS + cladding. Typical cladding material is 904L. However, The CRA* material should be selected based on the Corrosion Assessment.

Other remarks: CS + CA + CI: this option should not be considered for three-phase separators or vessels. Three-phase process vessels should not rely on chemical inhibition as an effective mean of corrosion protection due to lack of proper corrosion inhibitor distribution.

Hydrocyclone CO2 and CO2 + H2S corrosion (* Chloride, temperature, pH and H2S partial pressure for CRAs) Erosion Corrosion

Duplex*. Tungsten carbide hard facing may be required to ensure abrasive resistance.


Corrosion allowances are not generally available for carbon steel tubes, and thus, it is necessary to consider CRA materials for the tubes (or plates). Typical tube and plate materials for produced water are duplex and titanium, respectively. However, The CRA* material should be selected based on the Corrosion Assessment.

The heating/cooling media also posses other threats that need to be mitigated (see Table 6).

Piping CO2 and CO2 + H2S corrosion

Base Case: CS + CA Option 1: CRA. Typical CRA material used is duplex. However, The CRA*




(* Chloride, temperature, pH and H2S partial pressure for CRAs)

material should be selected based on the Corrosion Assessment. Option 2: CS + cladding. Typical piping cladding CRA material is 316L or 825.


Option 4: CS + CA + CI. The use of corrosion inhibition program may be considered. The corrosion inhibition program represents higher risk and may be reflected in higher life cycle cost.


The valve body material should be compatible with the piping material. Valve internals should have better corrosion resistance than the body. The CRA* material should be selected based on the Corrosion Assessment. Materials for valve internals should have wear and abrasion resistance for use in fluid services containing suspended solids. If carbon steel valves are used in, the seat pockets should be overlaid with Alloy 625.



Table 10

Seawater System Equipment Material Selection

Seawater Lift Pump Super duplex

Process Cooling Media / Seawater Heat Exchangers Titanium plates

Piping (raw seawater) FRP piping

Piping (de-oxygenated seawater) FRP CS + 3mm-CA 316/316L SS

Hypochlorite Piping FRP (vynylester based) C-PVC Valves (raw seawater) Super duplex (temperature below 30 C) Aluminum bronze Valves (de-oxygenated seawater) Aluminum bronze (for FRP piping system) Carbon steel (for CS piping system)

Table 11 General Services

Equipment Material Selection

Fire Water FRP and 90-10 Cu-Ni Piping: CS + 3mm-CA (GALV) (for dry systems)

Fresh Water Piping: CS + 3mm-CA (GALV) Tanks: CS + 3mm-CA + coating + anodes

Dry Fuel Gas Piping CS + 1.5mm-CA and 316/316L dual grade when cleanliness is required/downstream filters Diesel Piping: CS +1.5mm-CA and 316/316L dual grade when cleanliness is required/downstream

filter Tanks: 316L or CS + 3mm-CA + coating

Jet Fuel, Lube Oil, Seal Oil Piping: 316/316L dual grade Receiver: 316L or CS + 3mm-CA + coating

Instrument Air Piping: 316/316L dual grade Receiver: 316L or CS + 3mm-CA + coating

Utility Air Piping: CS + 3mm-CA (GALV) Receiver: CS + 3mm-CA + coating

Nitrogen Piping: CS + 3mm-CA Receiver: CS + 3mm-CA + coating

General Chemicals (Corrosion Inhibitor, Demulsifier, Anti-foam, etc)

Piping: 316/316L dual grade (for BDNPA biocide, titanium is used) Tanks: 316L (for BDNPA biocide, FRP is used)



Equipment Material Selection

Flare System Piping 316/316L dual grade and/or LTCS + 3mm-CA (material to be confirmed based on Corrosion Assessment)

Flare tip: 310 SS General Instrument Tubing 316L w/ min 2.5% Mo or 904L

External Corrosion Mitigation Methodology Mitigation and control of external corrosion for topsides piping, equipment, and structures presents special challenges for the oil and gas industries. Guidelines to determine specific corrosion threats as well as effective barriers have been developed by industry standards13,14,15 , however, particular challenges are still in need to be addressed. External corrosion mitigation should be based on a combination of material selection and coating system. As a minimum, the following methodology should be followed. All carbon steel piping and equipment should be coated. 304 or 304L piping and tubing should not be used. 316/316L process piping and equipment exposed to marine environments and operating at

temperature above 60 C should be coated. Duplex and piping and equipment exposed to marine environments and operating at temperature

above 100 C should be coated. All piping under insulation should be coated.

The following items are not to be painted: Concrete structures Galvanized steel gratings Machined surfaces Fiber reinforced plastics provided they are UV resistant. No ferrous materials such as 90-10 and 70-30 copper nickel alloys, monel, aluminium bronze, and

nickel alloys when not thermally insulated

For un-manned topside facilities, where maintenance is to be kept to a minimum (e.g. wellhead platforms), higher integrity coatings such as thermal sprayed aluminium (TSA) should be considered.

CONCLUSIONS

The large demand for hydrocarbons has led to the exploration of new offshore oil and gas sources in stringent environments (deep water, high pressure, high temperature, high CO2, high H2S, and high chloride fields). This trend is resulting in numerous challenges for topside material selection, and therefore, project cost (CAPEX/OPEX). At topsides, the inlet wellstream into the facility is separated into three basic product streams: Crude which is stabilized (degassed) to meet crude product vapor pressure specifications,

dehydrated, and desalted. Gas which is compressed and dehydrated for use as fuel gas and injected or exported. Produced water which is treated to remove oil to meet overboard water disposal specifications. The internal corrosion evaluation for these streams is prepared based on a good understanding of the fluid partitioning thru the topside process equipment. The integrity of the utility systems is also an important factor in material selection since these systems play a paramount role in the facility operation.



The material selection for utilities systems as well as the external coating requirements for the topside piping and equipment are mainly based on field experience.

REFERENCES

1. NACE MR0175 / ISO 15156, Petroleum and Natural Gas Industries Materials for use in H2S

Containing Environments in Oil and Gas Production. 2. NORSOK Standard M-001, Material Selection. 3. B.K. Holmes, S. Bond, Sour Service Limits of Dual Certified 316/316L Austenitic Steel and

Weldments, NACE 2010, Paper 10308. 4. TG. Chitwood, L. Skogsberg, The SCC Resistance of 316L Expandable Pipe in Production

Environments Containing H2S Chloride, NACE 2004, Paper 04138. 5. T. Cassagne, G. Moulie, C. Duret, Limits of Use of Low Alloy and Stainless Steels in Upstream

Sour Environments, NACE 2009, Paper 09079. 6. C.J.B.M, Joia, A.L.L.T, Small, and J.A.C. Ponciano, Rapid Screening of Stainless Steels for

Environmentally Assisted Cracking in H2S/CO2/Cl Environments Using the Slow Strain Rate Test, NACE 1997, Paper 48.

7. J.G., Maldonado, J.W., Skogsberg, Cracking Susceptibility of Duplex Stainless Steels at an Intermediate Temperature in the Presence of H2S Containing Environments, NACE 2004, Paper 04134.

8. L. Scoppio, M. Barteri, and C. Leali, Sulphide Stress Cracking Resistance of Super Duplex Stainless Steels in Oil and Gas Field Simulated Environments, NACE 1998, Paper 95.

9. R. Winston Revie, Uhligs Corrosion Handbook, Second Edition (New Jersey, Wiley-Interscience, 2006), 601-667.

10. P.I. Nice, O. Strandmyr, Material and Corrosion Control Experience within the Statfjord Field Seawater Injection Systems, NACE 1993, Paper 64.

11. F. Estberger, Sandvik: Duplex Stainless Steel Development and Properties. 12. ISO 12944-2, Paints and Varnishes Corrosion Protection of Steel Structures by Protective

Paint Systems Part 2: Classification of Environments. 13. ISO 21457, Petroleum, Petrochemical and Natural Gas Materials Selection and Corrosion

Control for Oil and Gas Production Systems. 14. Guidance For Corrosion Management In Oil And Gas Production And Processing, Energy

Institute, May 2008, ISBN 978 0 85293 497 5. 15. DNV-RP-G101 Risk Based Inspection of Offshore Topsides Static Mechanical Equipment.



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