Corrosion Control on Amine Plants: New Compact Unit Design for High Loadings Michel BONIS, Total Jean KITTEL, IFP Gauthier PERDU, Prosernat Good afternoon Corrosion has always been a matter of concern for the operation of gas sweetening plant with amine solvent. But the corrosion experience can open the way to optimized designs, to reduced operating costs and to debottlenecking perspectives when attached to higher loadings of solvent. I first thank my co-authors : Michel Bonis from Total for his feed back of amine plants and Jean Kittel from IFP for his skilled analysis of recent issues; special thanks to Jean for his contribution to the preparation of the paper. I will develop the Total experience in this field. This Company has decades of back ground in management of gas plants, in optimized maintenance, as well as in construction of grass root projects. It brought strong innovations and benefits into plants mainly built in CS. As CRA also gives way to improved design, new analysis made at IFP secure the use of CRA as a solution to high intensity operation of gas sweetening units, especially in the perspective of high chloride content in the solvent. Hand over of presentation: The factor and the location of corrosion in an amine gas plant The risks The reiterated use of CS as basic construction material, the drawbacks, how it can bring us to high loadings. With the help of CRA at the good place. CRA : is there any drawbacks, the NACE. Conclusion. OAPEC IFP joint Seminar – 17th 19th June 2008

Outlook Introduction Overview of corrosion likelihood in amine units Key factors of corrosion in amine plants An illustrative case Study From operating old CS units to handling high amine loadings More than 50 years REX The present operating basis High loadings - Lessons learnt from experience The use of stainless steels in amine sour units – the question raised by NACE MR0175 / ISO 15156-3 Main conclusions – a path to compacted designs Lets start with the presentation After a exposure of the places where we can face corrosion in gas sweetening units with amine, we will see what are the factors and catalysts. Secondly I will present you the TOTAL experience on corrosion, the feedback and the benefits Thirdly I will question the use of CRA with the requirement of NACE in sour environment We will finish with the overview a the solution proposed by the technology.

Outlook Introduction Overview of corrosion likelihood in amine units Key factors of corrosion in amine plants An illustrative case Study From operating old CS units to handling high amine loadings More than 50 years REX The present operating basis High Loadings - Lessons learnt from experience The use of stainless steels in amine sour units – the question raised by NACE MR0175 / ISO 15156-3 Main conclusions – a path to compacted designs Quick passing by

Five Decades of Operations Experience Total has operated and licensed amine units for more than 50 years: The 1st units : DEA units, sour gas, 16% H2S & 10% CO2, started in 1957 Now : 141 units licensed on 42 different locations over the world, 75 DEA units, 66 Selective or energized MDEA units, 25 units operated by Total Many of them have been debottlenecked for higher intensity operation Most are used for H2S removal, from 30 ppm to 50% H2S in, i.e. up to very high amine loads! CO2 removal units mostly licensed during the last 10 years, Extensive use of CS with monitoring and aggregated feed back Prosernat - an IFP subsidiary is now the licensor That is the story of the Lacq plant in South part of France in production since mid 50’s. As far as our experience is concerned, various solvent, various processes including elaborated schemes with integrated reflux of double split flows. Canada Russia More recent businesses linked to the LNG plants. Mid 1990 The story written by new hands

A Typical Scheme of an Amine Unit Wet sweet gas Sour Gas Absorber Tank Acid gas Demin water Exchanger Regenerator Flash drum Flash gas LP steam Reboiler Absorber The solvent route : the rich amine The solvent route the lean amine The gas route (HP) The wet acid gas route (BP) The stripping effort The reflux system

Amine Unit Corrosion: Key Factors Temperature Thermal activation Amine loading pH Oxygen entry HSS type of amine & concentration MEA > DEA ≥ MDEA pH - Conductivity Velocity Turbulences Inadequate design Too high flow rates Intrinsic corrosivity of amine solution Protectivity of sulfide / carbonate layer On one side we have got the corrosivity of the solution, on the second side we a have the protection of material by a protective layer . This is the fondamental : we can afford high coorisivity of the solution if we are sure that the layer will protect the CS material that equipment are made of. How can we say that an amine solution can be corrosive ? A Lean solvent solution is not corrosive and it is a well known passivator of CS. Some elements drive it to corrosive substance to its environnement: Type of solvent : from MEA to MDEA on the route to high corrosivity High loadings of solvent : from MEA to MDEA on the route to high corrisivity High temperature on the route to high corrosivity But even with a corrosive solution, the metal wall can be protected. How loose the protection of material? The oxygen : high Hss to high corrosion rate desctruction of layer Inadequate velocities : destruction of layer… If the corrosivity / protection balance is not reached, it results in the 3 forms of corrosion : weight loss, erosion corrosion, amine stress Uniform weight loss corrosion Erosion – corrosion Amine stress corrosion cracking

Wet Acid Gas Corrosion: Key Factors - Amine wall wetting - Condensation - Water accumulation Inadequate design Inadequate metallurgy (PWHT, sour grades...) Too low gas flow rates Flue gas composition Inadequate scrubbing - H2S / CO2 ratio - Condensation CO2 content in treated gas Condensation in the treated gas lines Again the balance between the intrinsic corrosivity vs the protection of iron walls. Corrosivity : high H2S content , high CO2 content with presence of liquid water. Protection layer: Iron Sulfide protection always better than iron carbonate. High H2S content is better. A good policy is not too have too low velocity of wet gas, in presence of CO2 especially. Promoters: Early degradation of sulfide carbonate layer, slow regeneration of it and presence of water traps, stagnant water. Results: Sour service with effects of hydrogen : in reference to NACE HIC SSC SOHIC corrosion , As a results it has been found Hydrogen cracking corrossion and weight loss corrosion. Intrinsic corrosivity of condensed acid water Protectivity of sulfide / carbonate layer Hydrogen cracking (HIC, SSC...) Weight loss corrosion

Wet Acid gas corrosion condensed water Corrosion of CS reboiler coils Main Corrosion Areas Wet Acid gas corrosion condensed water Wet sweet gas Acid gas Erosion – Corrosion Sour Gas Demin water So where did we find the corroded places: And what kind of corrosion? At the bottom of the absorber with spot all around the outlet rich amine nozzle. On high velocity spots such as valves manifold. At the top of the absorber with top of line corrosion (low velocity piping and water pockets). At the top of the regenerator on the wet acid gas line (low velocities / pockets). It shall be underlined that even in very corrosive environment, piping with high velocity have not been deffective. Provided that plant trend was about 100%. Coil of reboilers : CS tubes has never been the solution with high temp solvent. Cone found ok. Corrosion of CS reboiler coils LP steam

Illustrative Case Study: Sweet Gas Unit Wet sweet gas Acid gas AISI 410 (13% Cr) Trays, valves & down-comers Flash gas Sour Gas CS shell Demin water The Horror picture show…. LP steam

Outlook Introduction Overview of corrosion likelihood in amine units Key factors of corrosion in amine plants An illustrative case Study From operating old CS units to handling high amine loadings More than 50 years REX with CS The present operating basis High loadings - Lessons learnt from experience The of use stainless steels in amine sour units – the question raised by NACE MR0175 / ISO 15156-3 Main conclusions – a path to compacted designs Il y a quatre points, voici comment je vais vous les présenter. Et dans quel ordre. From operation with CS to operation with high loadings. Rex from CS is wide. High loadings has been introduced in design along with the wish to reduce the operatings cost and boost energy savings.

Experience from Initial CS Units More than 40 years after start-up some of the initial CS units are still in operation today Most encountered type of corrosion Erosion - corrosion in the rich amine route Most susceptible areas Bottom of absorber (unappropriate design – Impingement...) Rich amine lines (too high velocities, degassing effects...) Top of the regenerator (unappropriate protection of walls) Analysis got from inspection reports Maintenance frequency and overhaul : 3 to 5 years Problems were faced: Bottom of absorber (unappropriate design – Impingement...) Rich amine lines especially in valves manifold with line reduction and in elbows. Top of the regenerator (splashing on walls)

CS Units: Lessons learnt to updated design A combination of GOOD PRACTICE & selective replacement with CRA Efficient policy to minimize amine degradation prevent oxygen entry strict blanketing of amine tank deaeration of make-up water avoid high reboiler temperature control HSS concentration < 5000 mg/L Moderate velocities / reduced turbulences rich amine piping in CS: a < 0.35  flow < 2 m/s // a < 0.9  flow < 1.4 m/s bottom of Absorber / top of Regenerator Avoid jetting with CRA deflectors The good practise: Maintain the solvent as nice as possible;: Upto 8 years operations without complete solvent overhaul. O2, Reboiler, HSS monitoring Check your profile : reduce fatigues, check that moderate velocities in pipe does not mean moderate velocity everywhere: elbows, manifold. Check your internals. Check wall are wetted with lean solvent. Practise UT test some times.

Updated design to High Solvent Loadings A combination of good practise & SELECTIVE REPLACEMENT WITH CRA’s. Allows high intensity operation and debottlenecks Upgrade Bottom of Absorber & Top of Regenerator CRA cladding where appropriate or CRA weld overlay or CRA lining Select rich amine piping in CRA from Absorber to Regenerator allows Solvent Loadings a > 0.9 & velocities > 2 m/s The response to local troubles The response to already-in-trouble areas. Simplify your routine procedure of control and do not pressure your piping engineers too much! Go to CRA on critical service! CRA gets your rid of local trouble and difficult valves and isometrics arragement. Reduced diameters of CRA piping.

High Amine Loadings : the Experience More than 50 years of experience on various fields... Amine Type H2S (% v) CO2 (%v) Loading Start-up year DEA 15.8 9.8 0.85 1957 (first unit) 34.6 6.1 0.90 1972 8.5 9.5 0.77 1980 21.5 14.7 0.82 1987 (first train) DEAMDEA 4.2 6.0 0.64 1984 Formulated MDEA Traces 9.2 0.72 1996 MDEA 4.0 5.6 0.71 2001 The experience is spread between fields in France(Lacq), Canada, AbuDhabi, Russia and Norway. ... Mostly with CS, to extended lifecycle, with reduced investments and energy costs … without major corrosion problems…

High Amine Loadings – Corrosion Impact High Loadings Enhanced corrosivity to CS Enhanced flashing Unit design Too high velocities Turbulences Impingement From Highloadings : low pH and local vapor locks. Avoid local problems. The story of high average velocities. Often means local troubles. Turbulences Impingement And the results are…. Stable protective layer No Corrosion Unstable or mechanically damaged layer  Severe erosion - corrosion

High Amine Loadings : Lessons Learned High Loadings Enhanced corrosivity to CS Enhanced flashing Unit design Too high flow rates Turbulences Impingement Good design & good practises: No degradation, Flow < 1.4 m/s CRA: - Rich Amine Lines - Bottom Abs. + Top Reg. The way to being safe CRA where protective layer is not always maintained The good point should be to maintain velocity below 1.4 m/s. This reduces the erosion of layer, locally or generally.  No Corrosion Loading up to a > 0.9 High velocities (> 2 m/s) Compact designs Reduced maintenance Stable protective layer Unstable or mechanically damaged layer  Severe erosion - corrosion

Outlook Introduction Overview of corrosion likelihood in amine units Key factors of corrosion in amine plants An illustrative case Study From operating old CS units to handling high amine loadings More than 50 years REX with CS The present operating basis High Loadings Lessons learnt from experience The use of stainless steels in amine sour units – the question raised by NACE MR0175 / ISO 15156-3 Main conclusions – a path to compacted designs Chlorides and austenistic CRA : is it only a sour service question?

Use of CRA's in sour amine units: the NACE NACE MR 0175/ISO 15156-3 "Petroleum & natural gas industries –Materials for use in H2S containing environments in oil & gas production – Part 3: Cracking-resistant CRAs and other alloys" (2003) The facts Recommended limits of use of austenitic grades (304, 316, 321) 60°C, pH2S > 15 psi 60°C, 15 psi > pH2S > 50 psi, Chlorides (Cl-) must be < 50 mg/L  Strict application of standard would drastically restrict the use of austenitic CRA’s in amine units

CRA's in Sour Amine Units : the Experience  A specificity of many sour amine environments 304L and 316L have been used in sour amine units for several decades A practical experience of austenitic CRA in operation with chlorides up to 2000 mg / litre in highly sour service Should-be-sensitive material are commonly present: Lean / Rich cross heat exchanger plates, 0.6-0.7 mm thick / SS316L No internal failure Additional laboratory tests have been performed at IFP over a long period: Amine Solvent load T° Cl- Steel type Result DEA 4N 10 bar H2S 7 bar CO2 110°C 6 g/L AISI 321 No cracking-No pitting MDEA 40% 4.7 bar H2S 1.8 bar CO2 AISI 304L AISI 316L No cracking- No pitting The story in amine service and the set of tests. Especial mateiral : the case of plate and frame heat exchanger. Usually problems of gaskets! Satus of platesis then easily checked!

NACE and Sour Amine Service The U-bend test : A detailed view : no cracking – no pitting Strict application of NACE MR0175/ISO 15156 is questioned from Lab Tests and Long Term Monitoring of amine gas plants with Cl- NACE MR0175/ISO 15156 is based on acidic systems data which does not fit the alkaline pH of liquid amine solvents The results of test. The piece The views The advanced conclusion; Sour service does not mean amine service since pH is 8 to 10!

Outlook Introduction Overview of corrosion likelihood in amine units Key factors of corrosion in amine plants An illustrative case Study From operating old CS units to handling high amine loadings More than 50 years REX with CS The present operating basis High loadings - Lessons learnt from experience The of stainless steels in amine sour units – the question raised by NACE MR0175 / ISO 15156-3 Main conclusions – a path to compacted designs

Main Conclusions – 1 Corrosion control in DEA and MDEA amine units is a simple combination of: A few key operating practices Avoid amine degradation careful blanketing + deO2 of Make-up Water and Nitrogen + controlling heat flux to reboiler Avoid high velocities with CS A consistent design Carefully manage turbulences & impingement areas with dedicated arrangements Use CRA at selected locations (Bottom of absorber, top of regenerator, rich amine lines)  Successful results with high amine concentrations and high amine loading (a > 0.9 mol/mol) Read Be aware the areas are weaker than others! Use CRA with confidence. Take your advantages! Go to high acid gas content of raw gas!

An Up-Dated Design of High Loadings Sour Units Wet sweet gas Acid gas Prevent oxygen entries Blanketting  > 300 k.cm Controlled chloride Flash gas Demin water An overwiew of the updated design for relaible and quiet operation. Reduced Project engineering mangement for rich amien piping Quiet long term operation ,with no need for solvent overhauls. LP steam Fluid monitoring HSS < 5000 mg/l Cl- < 500 mg/l Use of 316L stainless steel

Main Conclusions – 2 Present design and operating practice are based on more than 50 years of positive experience Rely on extended use of the 316L SS on corroded sensitive areas No cracking in sour media, documented by Feed Back & Lab Tests Keep all flexibility to any future process change or solvent swap Keep the possibility for upgrading during scheduled maintenance phases to allow operation with higher loadings Use specific design rules for sweet service units Keep quiet with SS316L CRA in amine service. Do not forget to investigate the upgrade before your maintenance period. Prepare you upgrade as a revamp project. If you use CS lines : check them; Go to the weak points if your are in the red zone. Keep a look upon service without H2S, with increased consideration for need of CRA.

Thank you very much for your attention OAPEC IFP joint Seminar – 17th 19th June 2008