Export Pipeline CO2 Modelling 1

[Cor123]

Dear All
I am planning of modelling CO2 general corrosion on an export Condensate Pipeline(Cassandra) My understanding is that both CO2 content and Pressure input data should be from the last stage separator (where the gas is in equilibrium). I have seen a number of reports (from consultancies) which use the condensate export pipeline operating pressure (which is substantially higher than last stage separator Pressure)
I assume both cannot be right and would appreciate your input.
Many thanks

 

[georgeverghese]

Would imagine the composition should be taken from the condensate phase of the separator feeding the condensate pumps,assuming any free water has been decanted off. Once pumped up, the equilibrium phase compositions in the export pipeline would depend on the actual operating pressure and temperature of the pipeline and not on the pressure of the feed separator.

 

[SJones]

Read the software manual and get some competent instruction. If you don't have the manual, you shouldn't be using the model.

Cassandra is the historical BP take on the de Waard - Milliams, de Waard - Lotz work. Thus, it is likely to work with fugacity of CO[sub]2[/sub]. The model generally derives this as a function of the gas phase partial pressure. This implies that you are going to have to come up with a gas phase composition. If your condensate line is single phase, how will you work out the gas phase composition? Has pumping the condensate pressure up increased or decreased the fugacity of the CO[sub]2[/sub] compared to the separator?

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[Cor123]

Hi Steve,
The manual categorically states to use the last stage separator data for liquids.What confused me is to see so many reports using the pipeline Pressure when using Cassandra!
Wouldn't the partial Pressure remain same as it's linked to Henry Constant? Wouldnt any dissolved gases in the condensate be much lower than the last stage CO2 mol% used as an input hence the fugacity would remain constant?
Many thanks for your input.

 

[AndySimm]

Most (all?) corrosion models require a partial pressure of gas that is in equilibrium with the liquid stream of interest as the input to the model. For a liquid full line it is common practice to look upstream to find the last location that a gas stream was in equilibrium with the liquid, this is usually a separator and the gas composition and operating pressure is taken from there and input to the model. This methodology is also described in NACE/ISO 15156-2 Annex C2 for calculating H2S partial pressure in gas-free liquid systems.

If it is close by this is quite accurate, problems may occur however if any degassing then occurs or if the liquid is subsequently pumped.

If the line pressure is greater than the separator operating pressure then it suggests that the condensate passes through a pump before it enters the pipeline, hydraulic pressure does not increase the concentration of dissolved acid gases in the liquid and therefore it is not correct to use the line pressure to calculate partial pressure of the gas to enter into the model.

A common problem in this type of example is to be provided only with dissolved liquid measurements of acid gas concentrations with no upstream equilibrium gas phase data available. In equilibrium with a gas phase the equivalent liquid concentration is much lower than the gas concentration and entering this data combined with the line operating pressure into a corrosion model is a frequent mistake that will result in the underestimation partial pressure and therefore corrosion rates.

In this case if upstream data is not available a “hypothetical equilibrium gas phase” must be calculated using henrys law and correcting for fugacity if needed to calculate an accurate rate.

 

[SJones]

Shell's Hydrocor can work with dissolved CO[sub]2[/sub] concentration and reverse engineer. If you don't have Hydrocor, you are at the mercy of the process engineer with UniSim, OLI Studio, etc to come up with the data. A significant number of "consultancies" don't think about this because they don't receive the requisite training in the model. I'm wondering how many CRA pipelines have been built based on deliverables of these "consultancies" showing huge corrosion rates for carbon steel.

Anyway - you have your answer: do what the manual says.

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[Cor123]

Hi Andy & Steve
Many thanks. That's why I love this website. Such an immense knowledge sharing!
This is an eye opener for me to see these countless reports from "consultancies " with this issue not being highlighted by the end users!
Many thanks all.

 

[SJones]

Partially sighted leading the blind.

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[Cor123]

On the same topic, the export pipeline received two stream of condensate, each with its own last stage separator. For the gas composition, i will be using the flow average of the streams. Just curios to know what about the Pressure? Would taking the highest Pressure of the two last stage separator be reasonable?
Thanks

 

[SJones]

For pipeline design purposes, in the absence of any more detailed data, it's a reasonable selection to get you started on the first iteration (case). Bear in mind, that as design gets more detailed, the number of cases that you will have to run will really mount up to cover the hypothetical operating scenarios and production profiles that will get dreamed up. One scenario could be that the high pressure train is shut down for a while. The number of cases that you could end up with might get a bit overwhelming.

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[Cor123]

Thanks Steve.

 

[georgeverghese]

Note CO2 dissolved in a pure hydrocarbon stream with no free water cannot ionise and hence there is theoretically no acidic corrosion due to CO2. Partial pressure of CO2 only has meaning when there is a 2phase stream with free water, which can be free water in the liquid side of the unit or condensed water on the vapor side.

CO2 corrosion can only occur in an all liquid condensate stream when there is a pH value (or some other parameter which correlates with pH) for the free water phase of the condensate stream.

 

[SJones]

Some models will still give a prediction of a corrosion rate even if zero water content is input into the starting parameters, and users need to be able to interpret this as outlined by georgeverghese above. I cannot say whether Cassandra will do so because I have never actually used it. A review of the construction and operation of Cassandra is given in NACE Corrosion 2005, Paper 05552. It should be noted that BP have now discarded Cassandra and replaced it with a mechanistic model that used to go by the monicker 'Concordia.'

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[AndySimm]

The oil/water/gas flow rate inputs to the Cassandra model are only used by the model to determine flow regime, they are not considered in any way to determine if conditions for liquid water are feasible and hence corrosion is possible.

Cassandra predicts the corrosion rate at water wetted locations only (The data the model is built upon is taken from flow loop tests in water) and the output is not corrected for any oil wetting effect.

If the condensate is a completely dry hydrocarbon then the corrosion rate would be zero yes, however the ability of condensate to entrain water is very limited and typically no oil wetting effect is considered for condensate. So if there was any water drop out in the pipeline there could be corrosion.

ECE includes an oil wetting correction factor.

 

[SJones]

If my memory is correct, ECE is one of those models that will still spit out a corrosion rate even if you tell it that there is no water.

NACE has been trying to publish a couple of reports on corrosion modelling. Having just checked the NACE website, they don't appear to be having much success with the membership. One document is called "Prediction of Environmental Aggressiveness in Oilfield Systems from System Conditions," and the other is "Selection of Pipeline Flow and Internal Corrosion Models." Unfortunately, the drafts have been copyright marked so they cannot be attached.

That really only leaves the 2009 IFE Report as being of any use: IFE/KR/E - 2009/003

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[AndySimm]

There was a comparison paper draft a couple of years ago, I dont know if it is out yet.

Actually you cannot enter zero water to ECE.

 

[SJones]

Thanks for the correction on ECE

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[georgeverghese]

Another complicating factor is the effect of pipeline corrosion inhibitors ( which are injected into production fluids before entry into a pipeline or piping) on the water - condensate separation that is expected at the upstream separator. These corrosion inhibitors form water condensate emulsions that remain stable even after 1year in a beaker with no turbulence - I have seen a photo of this beaker at a process engineer's desk in Aberdeen on an inhouse discussion forum.

So you can imagine what doesnt happen in these separators. These also wreak havoc on condensate-water separators when in MEG/water - hydrocarbon service where CI and MEG injection occurs far upstream of gathering pipelines at subsea wells.

 

[SJones]

Corrosion models aren't usually working down at that sort of flow assurance detail. The impact of inhibition should have been assessed by a rigorous chemical testing and selection process.

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[Chumpes]

Hi
Nesic team from Ohio university developed modelling of CO2 corrosion (free dl)
Nowadays DeWaard&Milliams is more or less obsolete (always gives very high corrosion rates whatever the operating parameters)
API RP941 for HT H2 service (annex, latest edition) provides several methods for evaluating equivalent partial pressures pp for full liquid streams while knowing conditions in previous separator, this includes change in total pressure :