Corrosion Predictions and Risk Assessment in

Oilfield Production Systems Steve Turgoose Intertek CAPCIS, Manchester UK

stephen.turgoose@intertek.com

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.