Sour Gas Corrosion of API 5L X42 PSL1 and PSL2 Pipeline Carbon Steels

Tammy Tancharoensuksavai Materials Science & Engineering 4100

Advisor Dr. Rick Reidy - UNT MTSE Sponsor Cory Weinbel - Denbury Resources Manager Jim Bieda - Denbury Resources

OBJECTIVE

Experiment was designed to identify and understand the behaviors of API PSL1 and PSL2 line pipe material in true severe environments in order to:

Identify microstructural behavioral differences

Contribute towards design of operational limits

Design of improved safety procedures

PSL 2

PSL 1

GANTTFall 2014 Oct Nov Dec Spring 2015 Lead TimeStart End Feb W3 Feb W4 Mar W1 Mar W2 Mar W3 Mar W4 Apr W1 Apr W2 Apr W3 Apr W4

Project Definition Autoclave/Reactor 2 weeks 2/16 3/2 received

Lit Research Gases & Regulators 4-5 weeks 2/16 3/9regulator received received exchange

gas mixture received

Coupon Research Metallic Specimens <2 weeks 2/16 3/2 received

Gas Research Presentations 2/13 3/6 3/27 4/17 4/24 5/1

Reactor Research Before exp Characterization 4 pc cutting polishing etching repeat

Budget Planning ESEM 3/27 4/2

Finalize Planning XRD 3/27 4/2

Draft Report OM 3/20 3/26

Poster Aqueous Test I 4/1 4/8 setup

Presentation After exp Characterization 4 pc

ESEM 3/6 3/27

XRD 3/6 3/27

OM 3/6 3/27

Draft Report 4/6 4/11

Final Report 4/12 4/16

Poster 4/16 4/21

Final Presentation 4/22 4/23

PERT

1. Shipments received 2. Sample preparation 3. Before test characterization 4. Experiment 5. After test characterization 6. Analysis & comparison

1.

2.

4.

3. 6.

7.

5.

timeline Feb-March April

CO2 ENHANCED OIL RECOVERY (EOR)

Tertiary method of oil recovery using supercritical carbon dioxide to attach to hydrocarbons inside of reservoirs

Sour Gas - any amount of H2S carried in CO2

Sweet Gas - H2S-free CO2

Hydrogen sulfide (H2S) attaches to CO2 in formations

Difficult and costly to separate

Material integrity-small amounts create protective layer that retards CO2 corrosion 10-100x lower than pure CO2 corrosion-once mackinawite layer is broken, corrosion rates corrosion rates greatly increase.

SAMPLE PREPARATION

PSL 2PSL 1

72 x 8.5 x 5 mm coupons cut with diamond metal bonded wafering blade

PSL1 = 25.0382g; PSL2 = 24.3238g

Polished from 80 to 800 grit then 1µm fine polish with diamond suspension

Ultrasonically cleaned/degreased in methanol bath

Etched with Nital for 11s

Immediately cleaned with Methanol and dried with compressed air before pre-

experimental analysis

STANDARDSLongitudinally welded API 5L X42 cut from 10 ¾” O.D. pipePSL1 - no further processing techniques PSL2 - requires smaller range of elemental composition, Charpy testing, higher tensile strength, higher yield strength, extra certifications & traceability. PSL2 also has variety of processing conditions: as rolled, normalizing rolled, normalized & tempered/annealed, quenched & tempered, thermomechanically formed, thermomechanically rolled

PSL 1 Element C O Si P Nb S Ti V Mn Fe Total

StandardWeight %

0.26 - - 0.03 sum < 0.15 0.03 sum < 0.15 sum < 0.15 1.30 98.23 100

As Received 5.47 0.13 0.42 0.21 0.42 0.14 0.05 0.16 1.06 91.94 100

PSL 2 Element C O Si P Nb S Ti V Mn Fe Total

StandardWeight %

0.26 - 0.45 0.025 0.05 0.015 0.04 0.05 1.30 97.81 100

As Received 4.20 0.08 0.60 0.35 0.73 0.30 0.09 0.10 1.00 92.57 100

Observance of several different production conditions were considered.Test conditions were chosen based on the average IP gathering lines for monitored fields.

DESIGN OF CORROSION TEST

Pressure Temp Time H2S in CO2 DI water

480 psi 45°C / 318K / 113°F 193 h 102 ppm 6mL

PROCEDURE• PSL1 & PSL2 coupons simultaneously placed inside 600ML vessel in upright position with 1% DI water added• Co-mingled CO2/H2S gas mixture was used to deoxygenate vessel for 1h• Vessel was placed inside distilled water bath that was heated to 45°C • Vessel was pressurized to cylinder’s allowed max of 480 psi• Conditions monitored daily and maintained for 193h• Immediately following end of experiment, coupons were characterized using SEM, EDX, and XRD.

SEM to view surface topography, scale, and/or grains. EDX was used as semi-quantitative method to determine elemental compositionXRD was used to confirm phases from elements spotted using EDS

DESIGN OF CORROSION TEST continued

Carbon Dioxide: Temperature - Pressure Diagram

Saturation Line

Sublimation Line

Melting Line

0.1

1.0

10.0

100.0

1000.0

10000.0

-100 -90 -80 -70 -60 -50 -40 -30 -20 -10 0 10 20 30 40 50Temperature, °C

Pres

sure

, bar

Drawn with CO2Tab V1.0

Copyright © 1999 ChemicaLogic Corporation

Triple Point

Critical Point

Solid Liquid

Vapor

33.09 bar / 480 psi @ 45°C

BSE 20 µm

A.

PSL 1 Before Experiment

A & B. Micrographs of PSL 1 prior to experiment - 2000x images taken with FEI Quanta ESEM using backscattered electrons. A.) Grains visible within matrix with the inclusion of dark spots possibly from etchant. B.) Inclusion protruding through grains C.) Image taken with Zeiss Optical Microscope at 10x magnification.

20 µmBSE

OM 10x

C.

B.

500 µm 40 µm

100 µm

D. E.

F.PSL 1 After Experiment

FEI Quanta ESEM Secondary Electrons D.) 80x image of scale build-up. E.)1000x magnified image of surface scale build-up. F.) 250x image of possible exclusion of material.

Material completely covered with sludge-like coating. Grains not viewable. No cracking found. Total weight lost = 0.10 g PSL 1 Corrosion Rate = 0.14108 µm/year

SE SE

SE

100 µm 40 µm

PSL 2 Before ExperimentFEI Quanta ESEM - backscattered electrons. Images G. H. and I. display grains at 250x, 1000x, and 2000x respectively. All images display smooth, more even grains than PSL 1 Before Experiment. This proves that material has been through heat treatments and quenching. No grain alignment proves no rolling was done. Nital did not affect material as greatly as PSL1 20 µm

G. H.

I.BSE

BSE

BSE

PSL 2 After ExperimentFEI Quanta ESEM - Secondary Electrons J.) Microcracks developed on surface of material under scale build-up at 500x magnification. K.) Large intragranular crack ~200µm in length. L.) Side-view of surface of coupon. Observable rough surface of metal lost and scale gained.

50 µm50 µm

50 µm

J. K.

L.

SE

SE

SE

Completely different corrosion growth mechanism than PSL1. Cracks on surface of scale build-up Total weight lost = 0.05 g PSL 2 Corrosion Rate = 0.01675 µm/year

flower-like FeS growth

BCC Ferrite

•Sideright Fe(CO3) •Iron Sulfate FeSO3 •minimal Triolite FeS •minimal Iron Sulfite FeS

1. before

2. after

BCC Ferrite

•Sideright Fe(CO3) •Iron Fe •minimal Iron Carbide Fe7C3 •minimal Iron Sulfide FeS

4. after

3. before

XRD PSL 2Rigaku Ultima III DiffractometerXRD PSL 1

RESULTS continued

EDX PSL 1 (Full Frame)

Before Experiment

• EDX is semi quantitative way to determine elemental composition • beam penetration depth is larger than nanoscale • viewable for Be-Am but far from precise for light elements or <1% • more qualitative understanding than quantitative • better techniques: XRD, WDS, TEM, ion-beam techniques

RESULTS continued

EDX PSL 2 (Full Frame)

Before Experiment

EDX PSL 2 (Full Frame)

After Experiment

A. Fe-H2S-H2O Pourbaix diagram. From XRD results, FeS was generated more prominently for PSL1 than 2. B. Fe-CO2-H2O Pourbaix diagram. FeCO2 was primarily generated based on XRD results.

ANALYSISPSL 2 steel to have noticeable cracking on scale surface leaving metal underneath crack susceptible to corrosion initiation during 193h test. Growth of corrosive product is scattered and spotty with some flower-like FeS patterns beginning. Sideright, iron, iron carbide, iron sulfide observed. PSL 1 steel developed sludge scale coating and resulted in an overall weight loss 2x that of PSL 2 during identical 193 hour run. Grains not viewable; no cracking observed. Sideright, iron sulfate, triolite, iron sulfite observed.

Based on conclusions within this experiment, PSL 2 exceeded results from PSL 1.

B.A.H2S CO2 SiderightFe SulfideFe Sulfite

Triolite

ANALYSISCES EduPack graph of high yield strength, low density ferrous alloys. Highest performing carbon steel alloy displayed on right, ANSI 1340 tempered at 205°C and oil quenched. Highest performing ferrous alloy is a wrought martensitic stainless steel tempered at 316°C, AISI 440C.

CES EduPack graph of highest yield

strength carbon steel alloys.

Slight range of tempering proves to

better enhance the material.

CONCLUSIONCost analysis of PSL1 and PSL2 ERW pipe

With a corrosion rate nearly nine times slower at 0.0167 vs. 0.1411µm/yr,

PSL2 proves to greatly outperform PSL1. At a cost difference of $0.05/lb, it

should replace the reliance of PSL1 pipes for use in aqueous sour gas

environments in pressures near 480 psi at 45°C. If internally coated

pipeline is likely to erode from sand or strip away from a chemical reaction,

PSL 2 should be chosen as a safety measure for pipe integrity and

environmental safety.

PSL1 $900/net ton $0.45/lb

PSL2 $1,000/net ton $0.50/lb

REFERENCES[1] API 5L 45th Ed, PSL 1 Seamless and Welded; API 5L 45th Ed PSL 2 Seamless & Welded; and API 5L 45th Ed PSL2 Welded only[2] Arzola, S., and J. Genescá. "The Effect of H2S Concentration on the Corrosion Behavior of API 5L X-70 Steel." Journal of Solid State Electrochemistry 9.4 (2005): 197-200. Web.[3] Choi, Y. and Nesic, S. (2011). Effect of Water Content on the Corrosion Behavior of Carbon Steel in Supercritical CO2 Phase with Impurities. Corrosion/2011, paper (11377).[4] Choi, Y., Nesic, S. and others, (2010). Effect of Impurities on the Corrosion Behavior of Carbon Steel in Supercritical CO2-Water Environments. CORROSION 2010.[5] Farelas, F., Choi, Y. and Nevsic, S. (2012). Corrosion Behavior of API 5L X65 Carbon Steel Under Supercritical and Liquid Carbon Dioxide Phases in the Presence of

Water and Sulfur Dioxide. Corrosion, 69(3), pp.243–250.[6] Forero, A. B., Milagros.m.g. Núñez, and I. S. Bott. "Analysis of the Corrosion Scales Formed on API 5L X70 and X80 Steel Pipe in the Presence of CO2." Materials

Research Ahead (2013): n. Web.[4] He, W., Knudsen, O. and Diplas, S. (2009). Corrosion of stainless steel 316L in simulated formation water environment with CO2--H2S--Cl-. Corrosion Science, 51(12), pp.2811–2819.

[7] He, W., Knudsen, O. and Diplas, S. (2009). Corrosion of stainless steel 316L in simulated formation water environment with CO2-H2S-Cl-. Corrosion Science, 51(12), pp.2811-2819.[8] Henriquez, M., N. Pébère, N. Ochoa, and A. Viloria. "Electrochemical Investigation of the Corrosion Behavior of API 5L-X65 Carbon Steel in Carbon Dioxide Medium." Corrosion 69.12 (2013): 1171-179. Web.[9] Liu, M., Wang, J., Ke, W. and Han, E. (2014). Corrosion Behavior or X52 Anti-H2S Pipeline Steel Exposed to High H2S Concentration Solutions at 90C. Journal of Material Science Technology, 30(5), pp.504-510.[10] Liu, Z., Dong, C., Li, X., Zhi, Q. and Cheng, Y. (2009). Stress corrosion cracking of 2205 duplex stainless steel in H2S--CO2 environment. Journal of materials

science, 44(16), pp.4228–4234.[11] MUKHOPADHYAY, S. (2003, January 1). SAMPLE PREPARATION FOR MICROSCOPIC AND SPECTROSCOPIC CHARACTERIZATION OF SOLID SURFACES

AND FILMS. Retrieved March 27, 2015, from http://www.spectroscopynow.com/userfiles/sepspec/file/specNOW/Tutorials/sample_prep_mitra_377-412.pdf[12] NACE MR0175/ISO15156 Petroleum and natural gas industries. Materials for use in H2S-containing environments in oil and gas production - Part 2: Cracking-resistant CRAs (corrosion resistant alloys) and other alloys[13] Nesic, S., Li, H., Huang, J., Sormaz, D. and others, (2009). An Open Source Mechanistic Model for CO2/H2S Corrosion of Carbon Steel. Corrosion/2009, Paper,

(572).[14] Ning, J., Zheng, Y., Young, D., Brown, B. and Nesic, S. (2013). Thermodynamic Study of Hydrogen Sulfide Corrosion of Mild Steel. Corrosion, 70(4), pp.375--389.[15] Zhang, Y., Gao, K., Schmitt, G. and others, (2011). Water effect on steel under supercritical CO2 condition. CORROSION 2011.[16] Zhichao, Q., XIONG, C., CHANG, Z., Zhihong, Z., Chun, Z. and Zhengrong, Y. (2012). Major corrosion factors in the CO2 and H2S coexistent environment and the

relative anti-corrosion method: Taking Tazhong I gas field, Tarim Basin, as an example. Petroleum Exploration and Development Online, 39(2), pp.256–260.[17] Zipperian, Ph.D., D. (n.d.). Metallographic Specimen Preparation Basics. Retrieved March 27, 2015, from http://www.metallographic.com/Technical/Basics.pdf

I would like to thank Cory Weinbel and Denbury Resources for funding and support throughout my project.

Other acknowledgements include Jim Bieda at Denbury, Tommy Moore at Texas Pipe, David Garrett, Alyn Gray and David Brice in Dr. Pete Collins’ group, and CART for their resources and assistance.

Thank you to my teacher and advisor, Rick Reidy.