AMINE SYSTEM FAILURES IN SOUR SERVICE

MESPON 2016

o Amine Treating is widely used in Gas Processing to meet H2S & CO2 specifications

o Maximizing amine unit on-stream time and minimizing process upsets is challenging

o A large body of industry knowledge exists, BUT knowing how to apply this at a plant can be daunting (60+ potential root causes of failures)

INTRODUCTION

SYSTEM FAILURE

o 320 incidents of major system failure were analyzed; 225 with >1000ppm H2S in their feed

o Failure had costs ranging between $100,000 and $250,000,000 and typically required external assistance to solve/diagnose

o 246 cases from Amine Experts site consulting and 74 from literature; most incidents post 1999

SOUR GAS SYSTEM FAILURES

Corrosion 54

Flooding 18

Foaming 65

Product Quality

77

Amine Loss

11

MEETING SPECIFICATION

0 5 10 15 20 25 30

High lean loading

Understrength

Overcirculating

Undercirculating

Insufficient heating/ cooling

Mechanical Damage

Salt out (BTEX or CO2)

Phase envelope

High degradation or HSAS

Incorrect formulation

Insufficient Contact

Recorded Cases

~ 50wt% MDEA Jou et al. 1982 – ACS I&E Chemistry Vol 21, No 4.

~ 50wt% MDEA Jou et al. 1982 – ACS I&E Chemistry Vol 21, No 4.

4ppm H2S in 50 bar gas

CASE STUDY - TREATED GAS H2S VS. TEMPERATURE (MDEA)

Lean Molar 110°F 120°F 130°F Loading 43°C 49°C 55°C 0.002 M/M 1.7 ppm 2.0 ppm 2.3 ppm 0.003 M/M 2.5 ppm 3.0 ppm 3.7 ppm 0.004 M/M 3.4 ppm 4.1 ppm 5.2 ppm 0.005 M/M 4.3 ppm 5.3 ppm 6.7 ppm

MEETING SPECIFICATION

FOAMING

0 5 10 15 20 25 30 35 40

Feed Contamination

BTEX

Solvent contamination

Approach Temperatures

Ineffective flash drum & carbon bed

Incompatable chemical/material

Poor particle filtration

Spray flow regime

Phase envelope

High HSAS

Design fault

No regenerator purge

Recorded Cases

CONTAMINANTS IN GAS STREAMS

Liquids • Compressor lube oils • Hydrocarbon condensates • Organic acids • Pipeline Chemicals • Completion fluids • Well brines

Solids • Iron sulphides • Iron oxides • Corrosion products • Scale • Dirt (silica, etc.) • Desiccant fines • Coker fines • Catalyst fines

FOAMING PLANT

INLET SEPARATION

• Knock-Out Drum / 3-phase separator • Coalescer • Tie-Ins for: - Water Washes - Silica Gel Beds - Mechanical Filter

PREVENTION OR CURE? o Use of an appropriate anti-foam normally

dramatically reduces the foaming in a system.

o Continuous anti-foam dosing is normally not good practice and allows contaminants to accumulate to high levels.

o Antifoams may degrade with time; antifoam injection equipment should be cleaned annually.

o Overdosing of antifoam has been reported to lead to foaming.

ANTI-FOAM ADDITION

CORROSION

0 5 10 15 20 25 30 35

High CO2:H2S ratioHigh HSAS (>3%)

High SolidsHigh Bicine

High degradation productsPoor operating conditions

High lean loadingHigh reflux NH3/HCNHigh amine strength

Poor CO2 slipHigh temperature bulge

Cold spotsImpaction / vibration

High rich loadingPressure drop

Wrong MetallurgyPoor design

Recorded Cases

CORROSION

0 5 10 15 20 25 30 35

High CO2:H2S ratioHigh HSAS (>3%)

High SolidsHigh Bicine

High degradation productsPoor operating conditions

High lean loadingHigh reflux NH3/HCNHigh amine strength

Poor CO2 slipHigh temperature bulge

Cold spotsImpaction / vibration

High rich loadingPressure drop

Wrong MetallurgyPoor design

Recorded Cases

Hygiene

Design

Operation

CORROSION - LOCATIONS

REBOILER & LOWER REGENERATOR CORROSION

o Improper regeneration of the rich amine in the stripping column results in excess CO2 in hot, wet stagnant reboiler

o Poorly regenerated solutions are caused by: • insufficient steam traffic up the column • cold rich amine feed • high column back-pressure

REBOILER HOUSING CORROSION

AMINE HYGIENE GUIDELINES

Degradation Products o Corrosion typically occurs above 5 wt% of

degradation products in the Amine Solution

Heat Stable Amine Salts o Corrosion typically occurs above 3 wt% HSAS o Exception: In conjunction with other corrosive

factors corrosion in the 1.5 to 3 wt% HSAS range has been observed on some MDEA plants

Based on Database

LOADINGS & PRESSURE DROP

Carbon Steel o Rich Amine Less than 0.45 → 0.55 mol/mol o Lean Amine less than 0.04 mol/mol o Velocity less than 3 m/s

Stainless Steel o Rich Amine loading maximum undetermined. o Velocity less than 6 m/s

Based on Industry Guidelines

POST WELD HEAT TREATMENT • Molecular H2 diffusion into steel can induce cracking • Traditionally extremely prevalent in gas treating • Carbon steel in amine service MUST be heat treated

KEY FOCUS AREAS

1. Low lean loadings 2. Inlet separation 3. Do not under-strip the amine 4. Good Amine System hygiene FOCUS ON THESE AREAS WILL HALVE THE

LIKELIHOOD OF A MAJOR SYSTEM FAILURE ON YOUR PLANT!

AMINE OPERATORS MOTTO

“HEAT IN, SEPERATORS ON,

SALTS OUT”

THANK YOU MESPON

Philip le Grange, Michael Sheilan, Ben Spooner