Corrosion and Scale Control in Subsea Production Systems

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Corrosion and Scale Control in Subsea Production
Systems

• Marion Seiersten
• Institute for Energy Technology

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Hydrate control Monoethylene glycol
(MEG) Corrosion controlpH stabilisation
?Conventional inhibition ?Combination?
Project background Multiphase gas-condensate
pipelines as for example the one that will be
built between the Snøhvit field and Kvaløya
Gas/condensate pipelineLength 161.5 kmID
30Inlet 80-90 C / 110 barOutlet -5/5 C /
70/35 barCO2 pressure 10 bar (inlet)Carbon
steel
? Water production RequiresPrecipitation /
scaling control downstream MEG injection point
System for salt removal
Other considerations Organic acids (not
Snøhvit)O2 contamination (not Snøhvit)H2S (not
Snøhvit)Deposition/scaling due to corrosion
products and accumulated salts in the process
system onshore
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• All this requires that the chemistry of MEG-water
  systems is known
• Solubility of salts and gases as function of
  temperature, pressure and solvent composition
• Precipitation / scaling rates
• Corrosion rates
• Corrosion / scale interaction
• That is what our project has been about

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Project summary

• Partners
• NFR
• Statoil (Huldra pipeline, O2 effects)
• Statoil (Snøhvit development)
• Norsk Hydro (Ormen Lange development)
• Hydro Formates
• Economy (kNOK)

2000 2001 2002 Total Oil companies 1200 1500 15
00 4200 NFR 800 1000 1000 2800 Total 2000 2500
2500 7000
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Objectives

• To generate data that make it possible to predict
  the risk of precipitation and scaling in
  gas-condensate pipelines
• To develop a model for MEG water solutions that
  is able to
• evaluate the pH stabilisation technique
  conditions for the formation of a stable FeCO3
  film
• predict precipitation and dissolution of
  particles and scale that may result from mixing
  formation water and MEG with increased alkalinity
  (pH adjusted or stabilised)
• determine acetic acid / acetate build up in
  regenerated MEG
• determine O2 solubility in MEG water
• look into the effect that O2 has on precipitation
  and dissolution of corrosion products and scales

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State of the art at the start of the project

• Data on the solubility of gases and salts in
  mixed solvents (MEG-water) were sparse and
  scattered. A large part of the data that existed
  had been generated by IFE. Existing data at the
  start of the project
• CO2 solubility IFE had covered whole temperature
  and composition range, literature data at 20-30
  C.
• Dissociation constants for H2CO3 Only part of
  the temperature and composition range was covered
• Solubility of FeCO3 Inaccurate data and only
  part of the ranges covered
• There was no model that could be used to predict
  the solubilities
• Need for data in the temperature range 25
  140C and 0-90 wt MEG
• H2CO3 dissociation constants, FeCO3, CaCO3, NaCl,
  NaHCO3, Na2CO3, HAc, H2S, and others.

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Working method

• Solubility model
• At least 20-30 experiments are needed to cover
  the whole temperature and composition range. More
  experiments are needed if ionic strength
  variations shall be covered.
• Model Based on regression of stoichiometric
  solubility functions to measured data
  equilibrium constants that are functions of
  temperature, pressure, solvent composition and
  ionic strength.
• By running the model development in parallel with
  experiments, the amount of experiments could be
  kept at a minimum.
• Corrosion experiments
• Experiments to evaluate the effect of trace
  amounts of oxygen on pipeline corrosion

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Solubility experiments

• Simple experimental set-up
• Extensive analysis of dissolved ions
• Solubility of the following compounds have been
  measured in water - MEG
• CaCO3 and MgCO3
• NaCl
• NaHCO3
• Na2CO3
• Acetic acid
• CO2 (formate solutions) and H2S (partly)

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Calculation example Scale prediction in a pH
stabilised pipeline

• The pHm is chosen so that the CO32- concentration
  is high enough to ensure FeCO3 precipitation even
  at low corrosion rates
• Aiming for a pHm between 6.5 and 7 at the outlet
• Example
• Wet gas pipeline
• Total pressure 100 bar
• CO2 content 2 mol

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MEG and H concentration along pipeline
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Formation of FeCO3 and CaCO3
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Pipeline inlet
CnHnx, CO2, H2S, R-COOH
Condensed, formation water with salts
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MEG injection
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Corrosion
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Glycol regeneration
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Precipitation in injection line
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Exploitation of the results

• In-house model at IFE for equilibrium chemistry
  calculations in MEG / water
• A simplified model for pH calculations delivered
  to Statoil
• Data delivered to Hydro for implementation in
  their own simulation tool
• Co-operation with Statoil, Hydro, NTNU and IFE to
  develop MEGScale a commercial equilibrium model
  for MEG solutions, first version planned by the
  end of 2004
• The IFE in-house model has been used for the
  evaluation of pH stabilisation or MEG
  regeneration/reclaiming units all over the World
  (Åsgard (Statoil), Snøhvit (Statoil), Brodgar
  (Conoco Phillips), South Pars (Several), Shah
  Deniz (BP), Nnwara Doro (AKT))

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Conclusions

• A successful project because it has
• Met the objectives (revised objectives) and
  enhanced a good relationship between the project
  partners
• Upgraded the partners competence and contributed
  to
• Optimised developments (increased robustness,
  better safety, reduced environmental impact, new
  solutions)
• Increased amount of projects within the field at
  IFE
• Formed a fundament for further model development
  through better understanding of MEG - water
  systems
• MEGScale to develop software which implements
  the results (started)
• Glycol loops integrated calculation tools that
  combine thermodynamic models for MEG and
  chemicals with a multiphase flow pipeline model
  and process models for the MEG regeneration
  system (co-operation with Aker Kværner, not
  started)