Corrosion Predictions and Risk Assessment in
Oilfield Production Systems Steve Turgoose Intertek CAPCIS, Manchester UK
Outline
Corrosion Prediction Models
Accuracy
Limitations
Application of Models to Risk Assessments
Materials Selection
Inhibition System Design
Effects of Process Changes
Predictions of Current Condition
Emphasis on carbon steel in production environments
Predictive Models for CO2 corrosion
Freely available
Norsok M506 (Norwegian Standard)
Cassandra (BPs implementation of DeWaard et al. equations)
Commercial
ECE (allows for H2S, based on DeWaard equations)
In house many
e.g. Hydrocorr (Shell)
Inputs
Temperature
Partial pressure CO2 (system pressure + mole % CO2)
pH (water chemistry -TDS and bicarbonate)
Flow parameters (Oil, water, gas flow rates, pipe diameter)
Outputs
Predicted general sweet corrosion rate of pipeline steel due to CO2
Many models (including Norsok and Cassandra) do not include effects of:
Oil wetting
Top of Line corrosion
Organic acids
Sour corrosion rates
H2S pitting
Effect of inhibition
Accuracy of models
How accurate are the predicted uninhibited rates?
NACE Symposium 2005 Predicting Corrosion in Oil and Gas Environments
Hedges et al paper 05552
Cassandra +- 25% of calculated rate
Smith & DeWaard
ECE 25 % standard deviation
Norsok (Olsen et al NACE 05551)
Hydrocorr (Pots, NACE paper 05550)
Standard test procedures
Allow similar variations in corrosion rates under identical contions
E.g. Shell protocols for one particular test
Baseline corrosion rate should be between 4 and 7 mm/y
i.e. +- 25%
Oil wetting
At moderate velocity and low water cut surfaces may be oil wet
Consequent reduction in corrosion rate
But can we be sure that water drop out will not occur?
No concensus among operators on this effect.
Does not apply to light condensates
Top of Line Corrosion
At high condensation rates (>0.25 g/m2/s) may be high corrosion rates in condensing water at the top of the line.
At lower condensation rates water saturates with iron carbonate and corrosion rate generally taken to be ~ 10 % of bottom of the line
corrosion rate
A possible problem with stratified flow.
Organic acids
Recent work has started to quantify this.
Corrosion rate increases by an amount proportional to undissociated acid concentration (usually mostly acetic acid).
Not usually a major effect but may be significant in condensing conditions.
Sour corrosion
H2S reduces general corrosion rate
ECE applies a multiplying function no rigorous basis but seems to reflect what is seen
H2S may give pitting
Sweet rate multiplied by a pitting factor often close to 1 but higher at high chloride or if oxygen present
Does the accuracy of the uninhibited rate
matter?
What are we going to use the results for?
Can we use C steel without CI? uninhibited rate important
Can we use C steel with CI? feasibility of inhibition matters
Carbon steel without inhibitor?
At low corrosion rates (maybe < 0.3 mm/y) corrosion inhibitor may not be required.
Allowable corrosion rate depends on design life and corrosion allowance.
Inspection can indicate if later inhibition is required.
Risks associated with use of carbon steel
with corrosion inhibitors
What can we achieve in practice?
How do we determine and mitigate risks?
Availability Approach (conventional)
Assume a certain corrosion rate when inhibitor added (e.g. 0.1 mm/y).
The inhibitor concentration for this is determined by testing.
Assume uninhibited rate when inhibitor not added at or above the required concentration.
What is Availability?
It is a measure of the time that the chemical is present in the pipe at the required concentration
We measure inhibitor availability by:
Concentration
Pump operation time
Time
Below target dosage
Me
asu
red
Con
ce
ntr
atio
n
Target dosage level
%100
T
TTA
Contributions to lack of availability
Two types of contribution
Downtime of inhibitor dosing system (times with no inhibitor dosed)
Variations in inhibitor dosing with times below target
Common Design Assumptions
0.1 mm/y inhibited corrosion rate
95 % availability can be increased is appropriate measures taken
6 mm corrosion allowance up to 8 or 10 mm possible on large (>18 inch) pipes
Leads to decision on whether carbon steel is technically possible for design life
Economic factors must be considered
What can be achieved with inhibitors
when present?
CAPCIS recently reviewed a large set of test data over many years
And obtained chemical suppliers inputs
Under what conditions can a rate of < 0.1 mm/y be achieved ?
Results published in NACE 2011 (Hedges et al, paper 11062)
What can be achieved with inhibitors?
Very limited data
T > 120 C
Shear stress > 320 Pa
Difficult to achieve < 0.1 mm/y if the uninhibited rate is > 35 mm/y
Also difficult if TDS > 250,000 mg/l
To inhibit these systems may not be possible or may require very high concentrations of inhibitor.
What availability is achievable
Has to be operator defined
is largely a corrosion management issue
System specific e.g. multiple wells vs one trunkline
For a single pipeline downtime can be reduced to close to zero with sufficient care / expenditure, but there will be times under target.
For treatment of multiple wells some downtime must be expected and 95 % availability may be difficult.
Factors limiting availability?
Dosing pump failure / injection point blockage
duplication of equipment and injection points
Empty dosing tanks
ensure sufficient stocks
Leaks, so that inhibitor not going into line
measurement of inhibitor residuals in the pipeline
Uses of predictions
Design
Materials selection can we use C steel
CI regime requirements concentration and availability required
This should be reviewed in the light of monitoring and inspection data
System modifications
Can assess effect of changes in operation
May lead to further consideration of CI treatment
Base on present condition from inspection
Condition assessment
Failure investigation (root cause)
Assessment of present condition -
example
An operator had a subsea leak
Reasons unknown at present
Review of all other subsea lines in same field
Without confidence in present condition all lines will be shut in until they can be inspected.
Data available?
No In Line Inspection carried out after 12 years
No monitoring of corrosion inhibitor levels in the line
Corrosion coupons and probes show low corrosion rate, but not relied on since the coupons and probes in the failed line also showed low
corrosion rate
Only data available is laboratory test data for corrosion inhibitor and inhibitor volumes pumped (+ production data)
One year inhibitor records
0
50
100
150
200
250
300
14/11/2007 03/01/2008 22/02/2008 12/04/2008 01/06/2008 21/07/2008 09/09/2008 29/10/2008 18/12/2008 06/02/2009
Date
Co
rro
sio
n I
nh
ibit
or
pp
m
Target
Actual
If uninhibited when CI below target -
conventional definition of availability
Uninhibited rate = 5 mm/y (test data) model said 4.5 mm/y
Inhibited rate = 0.1 mm/y at 100 ppm
In one year
217 days above target
75 days below target
~ 70 days shut down (ignore corrosion in this period low T & P)
Loss in the year
= 217 days at 0.1 mm/y + 75 days at 5 mm/y
= 1.1 mm loss in one year
If uninhibited when CI below target -
conventional definition of availability
For all twelve years (from similar calculations)
Loss = 16.5 mm from 18.6 mm nominal wall thickness (MAWT ~ 4mm)
PIPELINE ALREADY FAILED
But it has not
Look at data again?
One month data
0.00
20.00
40.00
60.00
80.00
100.00
120.00
140.00
160.00
16/06/2008 21/06/2008 26/06/2008 01/07/2008 06/07/2008 11/07/2008 16/07/2008 21/07/2008 26/07/2008
date
Inh
ibit
or
Co
nc
en
tra
tio
n (
pp
m)
inhibitor
Target
Look at specimen one month data
30 days
Average daily concentration 105 ppm
14 days < 100 ppm
BUT
Only 1 day < 90 ppm (due to spike in production)
What is the effect of small variations around the target?
Effect of concentration on corrosion rate
0
0.05
0.1
0.15
0.2
0.25
50 60 70 80 90 100 110 120 130 140 150
concentration ppm
Co
rro
sio
n r
ate
mm
/y
0.122
0.082
50% time at 80 ppm, 50 % at 120 ppm
Average rate = 0.102 mm/y
Compared to 0.098 mm/y at 100
ppm
Consider unavailability only due to
downtime (no dosing)
Assume that system still inhibited when just below target (other days are better inhibited)
Days with no dosing = 15 days
Days with dosing = 277 days
Total loss in year = 0.28 mm
Total loss to date in 12 years ~ 4 mm
OK at present?
Look at downtime data
In one year 15 days with no inhibitor (but with production)
1 period of 5 days
1 period of 2 days
8 individual days
If inhibitor persistent (maintains protection) for one day with no dosing
Total loss in one year = 0.15 mm
Total loss to date ~ 2.5 mm
Condition
May have lost
16 mm
4 mm or
2.5 mm
Depending on assumptions (somewhere between the latter two is likely to be correct)
There is significant uncertainty, and consequent high risk, due to absence of
inspection,
monitoring of inhibitor residuals and corrosion rate
Conclusions
Corrosion predictions can enable assessment of
whether carbon steel with corrosion inhibition can be used, and
requirements for control of corrosion inhibition programs.
Users of the models should be aware of the limitations and accuracy of the models
A more realistic (less conservative approach to the definition of inhibition availability is required to address risks associated with
inhibition.
These risks will never be reduced to low levels unless appropriate inspection and monitoring is carried out.
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