1.dr.ir.slameto-material selection for co2 and h2s environme

PEMILIHANMATERIAL

TEKNIK UNTUK APLIKASI DI

INDUSTRI

Dr.Ir. Slameto Wiryolukito Program Studi Teknik Material

Institut Teknologi Bandung [email protected]

mailto:[email protected]



022-250-2457; 022-250-8144; 0815-7055525

Material Eng. Dept. of ITB 1

JENIS MATERIAL TEKNIK LOGAM

Berbasis Besi: Steel, Cast Iron, Stainless Steel, Iron Base Super

Alloy (70% kebutuhan) Berbasis Tembaga: Cu (cp) Brass, Bronze Berbasis Aluminium: Seri 2xxx s/d 7xxx Berbasis Titanium: Ti-Al-V; Ti (cp) Berbasis Nikel: Ni (cp), Ni-Base Super Alloy

POLIMER: PE; PP; PTFA; KERAMIK:

Berbasis Oksida, Karbida, Nitrida KOMPOSIT:

Polimer berpenguat Keramik: GFRP; CFRP Polimer berpenguat Logam: ban mobil Logam berpenguat Keramik: CerMet


Contoh Aplikasi

a. Oil & Gas Industries: Pipeline, Piping, HE,Vessel, Column, Tanks

b. Power Generation: PLTU; PLTG; PLTP; PLTA

c. Automotive & Transport Vehicles: Cars,Motorcycles, Trains, Buses,

Airplanes,

Ships,Tankers, Bridges,

Harbord. Medical Purposes

e. Housing & Building

f. House wares


Material Eng. Dept. of ITB

Contoh Aplikasi

4

PERTIMBANGAN UMUM

Sasaran dari Pemilihan Material: Menyediakan material yang memenuhi

persyaratan kerja suatu komponen dengan memerhatikan

Fabrikasi menjadi komponen tidak sulit (welding, forming, casting, dst) Harga memadai Waktu pengadaan tidak lama (ketersediaan, lokasi asal, embargo)

Keperluan: Produksi komponen baru (saat FEED: Front End Engineering Design) Modifikasi peralatan

Perawatan dan Perbaikan

Beban saat Kondisi Kerja Komponen Beban Mekanik:

Gaya, Momen Bending, Momen Torsi bersifat Statik, Dinamik (putaran), Kejut

Beban Termal: Tmaks, Tmin bersifat Isotermal, Siklus, Kejut

Beban Listrik Beban Lingkungan Kerja:

Temperatur sekitar, Korosivitas (Oksidasi, Karburasi, Posfidasi, Nitridasi, Asam, Basa, CO2, H2S, Cl-, dst)

Beban Saat Fabrikasi, Transportasi & Penyimpanan Akibat metal forming: rolling, forging, coiling, packaging Akibat pemanasan: welding, heat treatment Lingkungan saat transport & penyimpanan


Dasar Acuan Pemilihan Material Bagi Pengguna: SANGAT BANYAK PILIHAN: Jenis dan Tipe Material Di Pasaran SANGAT LUAS PENAWARAN: Sifat Mekanik, Sifat Teknologi, dan Ketahanan

Lingkungan

Be Smart “I Know What I Want” – “Ku Tahu Yang Ku Mau”

PILIHAN: PROVEN TRACK RECORDS: Jenis Material, Keandalan Produsen STANDARD & Spesifikasi Material

International: SNI, ASTM, JIS, DIN, BS, AFNOR, AS Perusahaan: EXXON, SANDVICK, NORSOK, DNV Profesi: Militer, NACE; API, ASME

MATERIAL BARU Seringkali Belum Distandarkan Tingkat Resiko Tinggi

Perlu dilakukan Trial


STANDAR NORSOK (M-001)OIL AND GAS PRODUCTION AND PROCESSING

Equipment

Material

Wellhead equipment/X-mast trees 13Cr4Ni, Low Alloy Steel with alloy625 weld overlay

Piping and vessels 22Cr Duplex, 25Cr Duplex, 6Mo, 316

Thick wall vessel Carbon steel with 316, Alloy 625, Alloy

825 or 904 clad or weld overlay

Piping and Vessels in low corrosivitysystem

Carbon steel

Inlet side of compressor Carbon steel, Carbon steel with CRAweld overlay or solid CRA if require, based upon corrosivity evaluation

Piping, vessels for produced water 316, 22Cr duplex, 25Cr duplex, 6Mo, Titanium or GRP.


APA YANG TERCANTUM DALAM STANDAR MATERIAL? Tipikal Aplikasi: untuk Pressure Vessel, Boiler, Piping di Temp

Rendah, dst Korelasi dengan Standard Material Lainnya Persyaratan Kualitas dikaitkan dengan Proses Produksinya Komposisi Kimia Proses Perlakuan Panas (Heat Treatment) Maksimum Pengotor yang dibolehkan

Sifat Mekanik (Tensile Strength, Yield Strength, Elongtion, Hardness, Impact Value)

“PERLU PENGETAHUAN DASAR MATERIAL TEKNIK”


STUDIKASUS


Material SelectionsFor Oil and

GasProduction Facilities(Case: Internal Corrosion)

Dr.Ir. Slameto Wiryolukito Material Engineering Department Bandung

Institute of Technology

INTRODUCTION

The recent Oil and Gas explorations turn to fields having more aggressive fluids

Typical corrosive agents in Oil & Gas production facilities: CO2, H2S, Cl-, O2. Typical Fluid Conditions:

CO2 up to 5% mole H2S up to 500 ppm Cl- up to 25,000 ppm

Other contributing factors to corrosion: Water Cut, High T, High P, Low pH, Flow Rate, Erosion

CO2Corrosion(“Sweet” Corrosion) It applies to any production fluid containing CO2 Gas

together w/ Water Potential to corrode facilities upstream of the dehydration units

CO2 + H2O —> H2CO3

Fe + H2CO3 —> FeCO3 + H2

It address to Top Of Line (TOL) or Dew Point Corrosion & Bottom Of Line (BOL) or Bulk Water Corrosion

CO2 in Gas and Oil Productions Any water in contact w/ gas will dissolve CO2 Oil production containing water will readily dissolve CO2 Corrosivity is proportional to partial pressure of, pCO2

pCO2 = mol% CO2 x Total Gas-Pressure

pCO2 < 7 psia ; no corrosive

7 psia < pCO2 <30 psia ; mild corrosion pCO2 > 30 psia ; severe corrosion

14

Contributing Factorsto CO2

Corrosion Temperature & Scales (FeCO3 and F3O4 ):

CO2 corrosion susceptible at T below saturated steam temp(T<85oC); Maximum CR occurs at T ≅

60oC FeCO3 and F3O4 scales formation suppress the CR

expressed as Scale Factor; common practice Scale Factor= 0.85 At pH > 6; Higher Temp increases possibility of Scale Formation

Pressure: higher P will be more aggressive Flow Regime: controlled by flow rates of Gas, HC-

Liquid, Produced & Formation Water, Eroding Particles, Acetic Acid

Dissolved O2: Aerated or De-aerated conditions Passive Inhibitions: presence of Bicarbonate,

Crude/Condensate, Scales of FeCO3, F3O4, FeS Inhibitors: Type, Efficiency, Availability, Effectivity


FormulationsP = Total Pr essure x

⎛ % mole CO2 ⎞ CO2 Partial Pressure

Water Cut

CO 2

⎛⎜⎝

Pr oducedWater

⎟100 ⎠⎞

Water − cut (%) = ⎜ ⎟ x 100%⎝ Pr oducedWater + Condensate ⎠ Scale Factor, fscale

log(f ) = ⎜ 2400 ⎟ − 0.6. log(p ) − 6.7scale

⎛ ⎞⎝ T ⎠ CO 2

H2S Partial Pressure

pCO 2

H 2 S

bara ;

T (K )

⎜ ⎟100

P = Total Pr essure x ⎛ % mole H 2 S ⎞⎝ ⎠

Inhibitor Effect

Inhibitor shall suppress the CR Huge variation; track records is important Inhibitor Effectivity = Efficiency x Availability

= 0.90

x 0.90= 0.9

5x 0.9

0= 0.90

x 0.95= 0.9

5x 0.9

5 Inhibitor Efficiency Inhibitor Efficiency = UCR – I CR x 100 %

UCR

Inhibitor Effect (cont’d)

INHIBITOR AVAILABILITY 80% availability = 73 days annual downtime

90% availability = 36 days annual downtime

95% availability = 18 days annual downtime

High availability implies: dedicated attention to corrosion inhibition

Immediate repair/refit of injection equipment

use of correct injection equipment

correct dosage rate related to flow rate


CO2CorrosionAssessments

CR prediction by: NORSOK; Cassandra (bp- property right); ECE (Liane Smith)

Reynolds number: indication Laminar orTurbulent Flows

Shear Stress Critical Gas Velocity Fugacity

Inhibitor Effectivity

CO2CRPrediction [5] CO2 Corrosion in C/S causes a General Corrosion Mode; CR prediction:

De Waard/Milliam’s & SHELL, firstly published in 1975 CORROSION-91: predictive model for CO2 CORROSION-93: predictive of CO2 Cor. of C/S CORROSION-95: considers Fluid Flow Velocity

Flowline7

NORSOK (IFE Norway)

BP-Cassandra

Hydrocorr99

ECE= Electronic Corrosion Engineer (SHELL-Cees de Waard of CorCon, Liane Smith-Intetech Ltd)

General Overviewon CR

Predictions Software[5]

NORSOK BP-Cassandra ECEIFE-Shear StressModelNorwegian Oil Co.Considers:

CO2; pH; Flow Regime; Fugacity; Glycol effect; Inhibitor

SHELL Model &Field Experiences

Emphasize on Water Chem; pH & Acetate with respect to ScalingConsiders: CO2;

Flow Regime; Inhibitor; TOLC; H2S

SHELL Model w/Correction Factors

Considers:

CO2; Flow Regime; TOLC; HCO3&Fe+

saturation; H2S; pH; Liq hold-up; HC-liquid


H2SCorrosion(“Sour-Corrosion”)

Susceptible to production fluid containing H2S Fe + H2S —> FeS + H2 (overall reaction) 2H+ + 2e- —> 2H (atom) —> H2 (molecule)

FeS is protective film, but breakdown of FeS causes

pitting oreven cracking in most iron base alloys

Hydrogen atoms diffuses to steel to cause cracking SSCC

HIC HIC-SOHIC

NACE MR-0175 for environment w/ pH2S > 0.05 psia considers

“Sour Service”

NACE MR 01-75Nomogram

SSCC & HIC Testsat Mat’l Eng. Dept.of

ITB

Materal Eng. Dept. of ITB

HIC Testing ssembly

i 25

CO2-H2S Corrosion

Existence of CO2 together with H2S will enhance corrosion aggressivity of the fluids

Dominant Corrosion mechanism depends on

PCO2 /PH2S [*]: PCO2 /PH2S < 20 : H2S corrosion is dominant

20 < PCO2 /PH2S < 500 : mixed corrosion

PCO2 /PH2S > 500 : CO2 corrosion is dominant

Material Cl- (ppm) pH2S (psia) T ( C )

316 < 10,000, pH > 3.5 < 0.74 < 60

< 50,000, pH > 3.5 < 1.74 < 60

S31254 < 50,000, pH > 3.5 < 14.7 < 150

< 50,000, pH > 5 < 29.4 < 150

22 Cr < 30,000, pH > 3.5 < 0.294 < 150

< 10,000, pH > 3.5 < 1.47 < 150

25 Cr < 50,000, pH > 3.5 < 1.47 < 150

< 50,000, pH > 4.5 < 5.88 < 150

Cl- Effect

Existence of Cl- in production fluid will

Promote general type corrosion in C/S

ClSCC in high grade material (S/S)

Threshold ClSCC susceptibility for S/S [* API 581; Norsok, NACE MR 01-75]:

Cl- > 10,000 ppm; T>60oC; pH < 4.5

Cl- together w/ H2S [Norsok]

MIC (Microbially Induced)Corrosion Risk Prediction of CR or knowing when pitting starts due to

MIC is unreliable, instead current practice considers only the susceptibility of equipment/piping

Information required to Evaluate MIC Risk

Water wetting, water cut pH = 5 to 9.5 TDS > 60 g/l, SRB grows T= 10 to 45oC; T>45oC SRB grows Total Carbon from fatty acid > 20

mg/l N > 5 mg/l C/N ratio < 10

Flow Velocity: 1 to 3 m/s Existence debris on pipe bottom Pigging Frequency Prolonged O2 Ingress > 50 ppb Biocide Equipment Age

Corrosion Mitigation


Corrosion Mitigation

1. Materials Selection (Presented in this Paper)

2. Isolation from the Environment

3. Modification of the Environment

4. Electrical Modification

5. Design


MATERIALSELECTIONS


MATERIAL PROPERTIES

Material Properties: Mechanical, Chemical (corr.

Resistance), Physical, Technological

Dependable on: Base metals Alloying Elements: type, amount Manufacturing Treatments Microstructures

Base Metals

Manufacturing

&

Treatment

s

Microstructure

Material

Properties

Alloying Elements

- Type, Amount

Considerations in MaterialSelections

CAPEX versus OPEX

Reduction of hidden costs

Life cycle costs

Overcoming operational restraints

Fit and forget

Environmental aspects

Safety


Life Cycle Costs

CAPEX


Corrosion

Considerations

UponMaterial

Selections(w/o Residual

Stress)


RationalizationinMaterial Selections Us

eC/S Uninhibited, UCR

Use

C/S + Inhibition program,

ICR Use C/S + CP Program (SA; ICCP) Use CRA (Huge variations of CRA)

Solid CRA Clad CRA (Metallurgical Bonding or Mechanical Lining)

Use CRA + CP Program (SA; ICCP) forExternal Corrosion Case

Use Titanium Base Clad

Non Metallic Material (Base or Coating)Material Eng. Dept. of ITB 37

UninhibitedC/S

Operating conditions (T, P, Flow Rate, pH) & Fluid composition (CO2, H2S, Cl-, Acetic Acid, Water Cut, DO, TDS)

Candidate Material of C/S

Grade, Strength, Hardness,Thickness Prediction

UCR

Prediction Un-inhibited Corrosion Allowance,

UCA,max = 8 mm

Economics Considerations: Seamless, Long-seam, Spiral-seam, UOE

ERW, SAW Availability, Delivery Time


C/S + Inhibition Program Operating Conditions & Fluid Compositions Candidate Material C/S

Grade, Strength, Hardness, Thickness

Inhibitor Effectivity Inhibitor Efficiency x Inhibitor Availability

Prediction Inhibited CR, ICR Prediction Inhibited, CA

Max ICA = 8 mm

Economics Considerations: Seamless, Long-seam, Spiral-seam, UOE ERW, SAW Availability, Delivery Time

CRA(Solid or

Clad) Operating Conditions & Fluid Compositions Candidate Material of CRA

Chem Composition, Grade, Strength, Hardness Solid CRA or, Clad System (Metallurgical Bonding or Mechanical Lining)

Potential Corrosion Atack General Corrosion: Prediction CR and CA Pitting Cracking: SSCC; HIC, ClSCC; SCC; Hydrogen

Crack; Sodium Crack

Economics Considerations;

HUGE VARIATIONS, Length & OD, Availability, Delivery

Time


Clad CRA [6]


Cracking Mechanisms

Active-Passive transformations

Pitting

Stress Corrosion Cracking

Hydrogen Embrittlement

Corrosion Fatigue


Passivation

ETrans- passive zone

Passivezone

Active-passivephenomena

Active Corrosion Zone

Log i

Corrosion Awareness Course 55


Pitting Resistance Number

PREN = Cr% + 3.3Mo% + 14N

Material PREN

13 Chrome steel 13

316 Stainless steel 25

317 Stainless steel 31

2205 Duplex stainless steel 34

A219 Super Duplex stainless steel

42

Alloy 825 32

Alloy 625 51



STRESS

ENVIRONMENT

SUSCEPTIBLEMATERIAL Stress

CorrosionCracking



Stainless steels + stress + chloride +temperature

Carbon steels + stress + sulphide

Copper alloys + stress + ammonium compounds

Carbon steels + stress + strong alkali


Rat

e o

f cr

ack

gro

wth

Sulphide Stress Cracking

Initiationperiod

Propagation phase Mechanicalfailure

Time


Pre

ssu

reRisk of as Systems

Risk of Cracking

No riskof cracking

Hydrogen sulphide concentration


Avoiding Sulphide Stress Cracking

• Limitation on strength of material<120,000 psi

• Hardness restrictionRC < 22 or VHN10<248

• Suitable welding procedure• Avoidance of cold work• No arc strikes• Adequate difference between yield

and ultimate strength


MATERIAL SELECTIONS(Case Study)


Considerations

CO2Effect

H2SEffect;

Susceptibility

to SSC

Cl- Effect; Susceptibility to ClSC

Combination Effects of CO2; H2S; Cl-

Inhibitor

Effectivity ====

CO2Effect

CR prediction by: NORSOK; Cassandra (bp-property

right); ECE (Liane Smith) Reynolds number:

indicationLaminar or TurbulentFlows

Shear Stress Critical Gas Velocity Fugacity

Efficiency x Availability0.90 x 0.900.95 x 0.900.90 x 0.95

Materia=l En0g..9De5pt.xof 0IT.B95 52

CO2Effect (cont’d)

INHIBITOR EFFICIENCY Inhibitor Efficiency = UCR – ICR x 100 %

UCR

INHIBITOR AVAILABILITY 80% availability = 73 days annual downtime 90% availability = 36 days annual downtime 95% availability = 18 days annual downtime

High availability implies: dedicated attention to corrosion inhibition Immediate repair/refit of injection equipment use of correct injection equipment correct dosage rate related to flow rate


Susceptibility to SSC

NACE MR 01-75

NKKNomogram

SUMITOMONomogram

Membrane Stress Analysis


NACE MR 01-75

Consider Multiphase Systems

Consider H2S only (ignores pCO2, T, Cl-)

Comment NACE MR 01-75 considers the environment is still

within non-SSC region but close to border of SSC Region

Mat’l Hardness shall be confirmed to have HRC< 22

NACE MR 01-75Nomogram

NKKNomogram [2]

Consider p CO2

incorporated with p

H2S

ConsiderCl-

incorporated with


Temp

7

NKKNomogram (cont’d)


SumitomoNomogram [3]

Consider ppH2S incorporated with pp CO2

Consider

Mat’l


strength, T

0

Membrane StressAnalysis

Flowline; Pipeline; Piping ANSI B 31.3

Pressurized Equipment ASME Sect. VIII, Div.1

API 579

SUMMARY Technically, one selects material shall

understand the needs

Motto: “Ku Tahu yang Ku Mau” “I Know What I Want”

Should always be

aware: “Material Properties dependon

Chemicalcompositions, Manufacturing, andTreatment

” Ignorance to manufacturing, treatment, and workmanship certainly will ruin an excellent-design

Commercial approach shall no t sacrificed the technical considerations for high safety and reliability guarantee of the production facilities

THANK YOU


Literature

1. NACEMR01752. NKKOCTGJournal

3. SUMITOMO Journal

4. Roger A. King, “Corrosion

Awareness”

5. AKER KVAERNER presentation6. JSW “Clad Pipe Production

Journal”

1.dr.ir.slameto-material selection for co2 and h2s environme

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