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
0
20
40
60
80
100
120
0
5
10
15
20
25
30
35
0 3 5 8 10 13 15 18 20 23 25 28 30 33 35 38 41 43 46 48 51 53 56 58 61 63 66 68 71 73 76 79 81 84 86 89 91 94 96 99 101
104
106
109
111
114
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
0
20
40
60
80
100
120
0
100
200
300
400
500
600
0 5 10 16 21 26 31 36 41 47 52 57 62 67 72 78 83 88 93 98 103
109
114
119
124
129
134
140
145
150
155
160
165
171
176
181
186
191
196
202
207
212
217
222
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
200
300
400
500
600
700
800
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
200
300
400
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1600
1700
1800
1900
2000
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?