CO2 pipeline tra nsport issues

Kuma r Pa tchigolla , J ohn O a key

School of W a ter, Energy a nd Environment

Ema il: k.pa tchigolla @cra nfield.a c.uk

MATTRAN: UK based project (2010-2014)

Overall Aim to resolve the principal material issues required to allow the near term

implementation of CO2 transport, and thereby of CCS itself.

Sub-aims to define and predict the conditions under which corrosion, degradation

and internal cracking will occur;

to validate the predictions with experimentation and modelling; and

to specify the material properties and/or CO2 stream composition required to prevent or control corrosion, degradation, cracking and fracture propagation.

Materials for Next Generation CO2 Tra nsport Systems (MATTRAN)

WP3: Pipeline Specification

WP4: Internal Corrosion & Degradation Investigation

WP1: CO2 Stream Specification

WP2: Phase & Dew Point Determination

WP6: Fracture Control

WP5: Internal Stress Corrosion Cracking

Investigation

WP7: Synthesis & Dissemination

GHGT Papers

Presentation Outline

PACT CO2 transport facility Rig characteristics Corrosion data for CO2 with impurities Metallic materials

Technical and material challenges Future plans/applications

PACT: Pilot-scale Advanced Capture Technology

PACT facilities - CO2 transport flow rig

Dynamic flow loop facility: This facility can characterise the effects of contaminants-dense fluid and materials interaction that impact pipeline materials issues Operates up to 225 bar, 40 deg (capable for up to 700

bar & -50 to 150oC) in flow mode (fluid flow rates up to 5l/min)

High pressure observation window-provide detailed information on phase separation, hydrodynamic flows, contamination etc.

Runs continuously for several hundred hours to study the effects of material corrosion and chemical environment environment

Continuous corrosion monitoring by electro chemical noise & linear polarization resistance

Offline/online gas composition measurement (infrared, mass spec)

Measurement and monitoring of physical properties- density, pH, temp, pressure

Impurities– H2O, H2, H2S, NOx, SO2and O2 etc..; dedicated MFCs to maintain gas compositions over extended periods

Factors influencing CO2 corrosion--pipelines

Parameter Effect on CO2 pipeline

Temperature The corrosion rate increases with increasing temperature. FeCO3 corrosion product film forms when the solubility is exceeded and the product film may fail leading to a high localised corrosion rate. This behaviour is very similar to what has been observed in oil and gas pipelines (Dugstad et al., 2011)

Pressure Increased CO2 pressure yields a lower pH in the fluid. This leads to a higher solubility of corrosion products and more H+ ions that corrode the steel

Presence of SO2 The presence of SO2 leads to a reduction in pH and increased H+ amounts, thus an increased corrosion rate

Flow regime The desired properties of the fluid (CO2) should be adequately monitored to avoid phase changes and ensure the maintenance of a single phase flow throughout the pipeline

Flow velocity An increase in flow leads to an increase in corrosion rate in the CO2 pipelines. Due to the higher flowrate removing the corrosion products formed and leaving the new material/surfaces to the corrosion process. (Dugstad et al., 2011)

Water content When water combines with CO2, it forms carbonic acidic; this is very corrosive to carbon steel. Therefore, CO2 should always be dehydrated prior to transportation to a water level of less than or equal to 500 ppm (Serpa et al., 2011 )

EPSRC – MATTRAN Project (2010-2014)

(generated 5000 h of engineering data)

National Grid-Corrosion studies (2014-2015)

(another 5000h test data generated)

PACT facilities - CO2 transport flow rig

Tested for 225 bar

Exposed coupons for each environment, in total 60+ metallic coupons and 60+ non-metallic seals

Pres

sure

Temperature

Compressor

Heater

Liquid CO2

4 Column reactor

Coupons

Controlled Decompression Up to 3 bar per min

Aged coupons

Sampling- infrared sensors

Supercritical region

Critical point

Contaminants addition

Pump 90 bar 5 deg Up to 5 bar per min

90 bar 40 deg

Condenser 57 bar 5 deg

Process flow diagram-current mode of operation

Applied the Code of Practice: SMT3-CT95-2001

Dense phase CO2 fa cility: P & I dia gra m

57 bar

57 bar 5 deg

90 bar -~5 deg

90 bar 40deg

Feed pump

Water heater

Coupon holder + corrosion sensor

Impurities

Analyzer

Circ. pump

Inhibitor addition

Mounting mechanism for coupons Stack of coupons mounted in the 1” tubular reactor

Spring Tube

Plates Non-metallic materials

Charpy coupon

Coupons made from 18” pipe section

Charpy, Tensile

• ~20 coupons of materials per probes • Each probe contains same material with

different geometry • Four probes in series-1” reactors

Timeline plan-coupon exposure

Approximately 2 months intensive programme for each environment

Coupons were taken for varying time periods during the course of the 1100h test period

Transport rig characteristics-cha rging procedure

Accumulator in circuit

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117

Pres

sure

, bar

Tem

pera

ture

, oC

Time, mins

TempA1

TempA2

TempA4

Pressure

Fluid circulation started

Filled with bottled cylinder

Compressor to increase the system pressure

Transport rig characteristics-impurity dosing for SO 2

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0 5 10 16 21 26 31 36 41 47 52 57 62 67 72 78 83 88 93 98 103

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Tem

pera

ture

oC;

Pre

ssur

e, b

ar

SO2

Conc

entr

atio

n

Time, mins

SO2ppm

Temp Out

Temp In

Pressure

SO2 dosing

CO2 charging

Another SO2 reading; Need some time for mixing

SO2 analyser reading

Dense Phase CO2- O bserva tion window

Dense phase CO2 ~ 90 bar ~40 deg

Dense Phase CO2- O bserva tion window

Decompression from ~ 90 bar ~40 deg

Rapid filling the system with H2O at ~ 90 bar ~40 deg

Reservoir of H2O in the system to maintain CO2 saturation

Post exposure metrology

Along with corrosion sensors, the exposed coupons analysed by imaging and weight loss methods

Exposed coupons are mounted, cross-sectioned and polished

Corrosion damage measured around edge

1.5 µg/cm2/h.

15 µg/cm2/h.

Polished cross-section with

calibrated X-Y stage

Resin

Coupon

Measurements of corrosion thickness damage taken at >24 positions around mounted cross-section

Corrosion rate (mm/y) = (8.76E4 x weight loss, g)/(area, cm2 X density, g/cm3 X time, hours)

e) origina l sa mple sha pe

c) microscope sta ge

sa mple

Dimensional Metrology: Technique

(Correction for systematic errors also required) Range of shapes can be studied

b) d) ima ge

interna l da ma ge

rad

ius

f) m

eta

l lo

ss

loca tion

sam

ple

8x

dia meter a )

g)

cumula tive proba bility

met

al l

oss

corroded sa mple sha pe

CO2 sa tura ted by H2O

XRD analysis of the surface (1100 h sa mple)

Corrosion product – Iron oxide (Fe2O3)

SEM-EDS a na lysis of the surfa ce (1100 h sa mple)

C O F Al Si S Mn Fe Total

Spectrum 1 2 3 1.9 0.21 1.5 92 100 Spectrum 2 24 0.33 0.25 1.4 74 100 Spectrum 3 10 5 8.6 0.11 0.31 0.11 1.2 75 100

Corrosion data-C O 2 environment

-0.50

0.00

0.50

1.00

1.50

2.00

2.50

0 100 200 300 400 500 600 700 800 900 1000 1100 1200

Met

al lo

ss, m

icro

ns

Time, h

X70 Tube X100 Tube X60 Plate

X70 Plate X100 Plate

Corrosion data-C O 2 environment meta l loss distributions

-20

0

20

0 10 20 30 40 50 60 70 80 90 100

Cha

nge

in s

ound

met

al (µ

m)

Cumulative probability (%)

Ground reference sample, 0 hours MATTRAN-CO2, 1100 hours

Change in sound metal for the bare alloy as a function of the probability damage

Exhibit a normal (Gaussian) distribution of damage

CO2 sa tura ted by H2O +SO 2 (500ppm)

Chemical composition & after exposure Element

(%) X60 X70 X100

C 0.04 0.05 0.07

Si 0.19 0.26 0.30

Mn 1.04 1.89 1.83

S 0.008 0.010 0.009

P 0.013 0.010 0.012

Ni 0.03 0.44 0.28

Cr 0.03 0.41 0.17

Mo <0.01 0.40 0.16

Cu 0.02 0.45 0.15

V 0.04 0.07 0.01

Nb 0.06 0.05 0.04

Ti 0.01 0.01 0.02

Al 0.03 0.01 0.04

Co <0.01 <0.01 <0.01

Fe Balance Balance Balance

X70 Tubes

Specimens were blackish after exposure; Surface was covered with thin corrosion film

Corrosion data-SO2 environment SEM - EDX ANALYSIS

API X100- 1100h

O Si S Mn Fe

Spectrum 6 45.07 0.15 22.99 0.68 31.11

Spectrum 7 27.63 0.34 6.62 1.37 64.04

Sample free surface without mounting

XRD ANALYSIS

API X100- 1100h

X100-SO2-1100hrs

01-1262 (D) - Iron - Fe - Y: 50.00 % - d x by: 1. - WL: 1.5406 - Cubic - 22-1017 (I) - Iron Sulfite Hydrate - FeSO3·3H2O - Y: 50.00 % - d x by: 1. - WL: 1.5406 - Monoclinic - Operations: Y Scale Mul 1.042 | Y Scale Mul 0.958 | Y Scale Mul 0.750 | ImportX100-SO2-1100hrs - File: X100-SO2-1100hrs.raw - Type: 2Th/Th locked - Start: 10.000 ° - End: 90.000 ° - Step: 0.020 ° - Step time: 1. s - Temp.: 27 °C - Time Started: 15 s - 2-Theta: 10.000 ° - Theta: 5.000 ° -

Lin (C

ounts

)

0

100

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700

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900

1000

2-Theta - Scale10 20 30 40 50 60 70 80

Identified the material deposited on the surface- Iron Sulphite Tri-hydrate FeSO3 3H2O

Corrosion data-SO2 environment

Corrosion data-C O 2+SO 2 environment

0

2

4

6

8

10

12

0 100 200 300 400 500 600 700 800 900 1000 1100 1200

Met

al lo

ss, m

icro

n

Time, h

X70 Tube X100 Tube X60 Plate

X70 Plate X100 Plate

Corrosion data-C O 2+SO 2 environment meta l loss distributions

-100

-80

-60

-40

-20

0

20

0 20 40 60 80 100

Cha

nge

in s

ound

met

al (µ

m)

Cumulative probability (%)

MATTRAN X60 plate-SO2 500ppm, 1100 hours MATTRAN X100 plate-SO2 500ppm, 1100 hours

Giving uniform metal loss of about 10µm (average), but with no extreme damage as the line is slightly different in gradient to unexposed material.

CO2 sa tura ted by H2O +H2S (500ppm)

SEM - EDX ANALYSIS API X100- 1100h

O Si S Mn Fe

Spectrum 8 18.05 0.28 10.12 1.48 70.07

Spectrum 9 41.24 0.37 11.53 0.99 45.87

Sample free surface without mounting

XRD ANALYSIS API X100- 1100h

Identified the material deposited on the surface- FeS0.9

24-0073 (D) - Mackinawite, syn - FeS0.9 - Y: 50.00 % - d x by: 1. - WL: 1.5406 - Tetragonal - 01-1262 (D) - Iron - Fe - Y: 42.47 % - d x by: 1. - WL: 1.5406 - Cubic - Operations: ImportX100-H2S-1100hrs - File: X100-H2S-1100hrs.raw - Type: 2Th/Th locked - Start: 10.000 ° - End: 90.000 ° - Step: 0.020 ° - Step time: 1. s - Temp.: 27 °C - Time Started: 7 s - 2-Theta: 10.000 ° - Theta: 5.000 ° - Operations: Y Scale Mul 0.750 | ImportX100-H2S-700hrs - File: X100-H2S-700hrs.raw - Type: 2Th/Th locked - Start: 10.000 ° - End: 90.000 ° - Step: 0.020 ° - Step time: 1. s - Temp.: 27 °C - Time Started: 16 s - 2-Theta: 10.000 ° - Theta: 5.000 ° - C

Lin (C

ounts

)

0

100

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2100

2-Theta - Scale10 20 30 40 50 60 70 80

17.54

9 °-d=

5.049

51

40.24

0 °-d=

2.239

33

44.70

1 °-d=

2.025

67

64.91

3 °-d=

1.435

37

82.29

0 °-d=

1.170

72

Corrosion data-C O 2+H2S environment

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0 100 200 300 400 500 600 700 800 900 1000 1100 1200

Met

al lo

ss, m

icro

ns

Time, h

X70 TubeX100 TubeX60 PlateX70 PlateX100 Plate

Specimens were golden yellowish after exposure; Surface was covered with very thin corrosion film

Technical challenges

Water accumulation with in the system Material failures Hydrates formed when compressed CO2 flow

with water; f(Tsys, Psys, Ccont, Cwater); hydrates dissolved when increasing the temperature

Material failures-Explosive decompression

Problem: Structural failure of the pressure relief value seals under dry dense phase CO2. Explanation: when the system pressure decays quickly (part of safety), the dense phase CO2 expands quickly into gas- rupturing the O-ring

• Gas escaping from a rubber O-ring • Internal failure is observed-internal

cracking, splitting

Fluorocarbon

Original Internal failure

Material failures-Polymer hose

Problem: Another structural failure of smooth bore PTFE hose. Explanation: when charging the system from bottled pressure (~57bar), the flexi host pipe failed- bulging, diffusion of dense phase CO2

******Gas diffusion through PTFE and silicone cover******

Before exposure: Smooth bore PTFE hose; 304SS and fiber braids; Silicone cover

After several hours of exposure

Acknowledgments

E.ON-EPSRC strategic partnership (EP/G061955/1)

W hat do you think about this sa mple?

Key gaps/questions

• Transportation has not received the same degree of attention as other parts of the CCS chain.

• Until now CO2 pipelines running exclusively overland through relatively sparsely populated regions. Are we ready for developing ISO standard?

• What about densely populated regions to storage sites?- which may include subsea option?

• Is there any technical constraints with the operation/maintenance of off-shore pipelines? • What about well bore materials in the presence of brine, dense-phase CO2 and trace

contaminants?