Predicting internal corrosion in oil and gas exploration and production operations 9782759827961

Table of contents :
Contents
Contributions
List of figures and tables
Introduction
1 Scope and Objectives
2 Definitions, Acronyms and References
3 Description of Damage Mechanisms
4 Corrosion Prediction

Citation preview

Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations Scientific and Technical Guide

CEFRACOR Workgroup “Corrosion interne Oil & Gas” Commission “Corrosion in Energy and Process Industries”

17, avenue du Hoggar Parc d’activités de Courtaboeuf, BP 112 91944 Les Ulis Cedex A, France

Printed in France ISBN(print): 978-2-7598-2795-4 – ISBN(ebook): 978-2-7598-2796-1 All rights relative to translation, adaptation and reproduction by any means whatsoever are reserved, worldwide. In accordance with the terms of paragraphs 2 and 3 of Article 41 of the French Act dated March 11, 1957, “copies or reproductions reserved strictly for private use and not intended for collective use” and, on the other hand, analyses and short quotations for example or illustrative purposes, are allowed. Otherwise, “any representation or reproduction – whether in full or in part – without the consent of the author or of his successors or assigns, is unlawful” (Article 40, paragraph 1). Any representation or reproduction, by any means whatsoever, will therefore be deemed an infringement of copyright punishable under Articles 425 and following of the French Penal Code. © EDP Sciences, 2023

Contents

Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

III

List of figures and tables. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .



V

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .



1

1.



3

1.1. Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2. Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3 4

2.

Scope and Objectives . . . . . . . . . . . . . . . . . . . . . . . .

Definitions, Acronyms and References . . .



5

2.1. Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 2.2. Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 2.3. Standards and other references . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

3.

Description of Damage Mechanisms. . . . . .

11

3.1. Assessment of damage mechanisms applicable to E & P . . . . . . . . . 11 3.2. Damage mechanisms amended from API RP 571 . . . . . . . . . . . . . . 15 3.3. Specific damage mechanisms in E & P activities . . . . . . . . . . . . . . . 30

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Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

4. 4.1. 4.2. 4.3. 4.4.

Corrosion Prediction. . . . . . . . . . . . . . . . . . . . . . . . . .

111

Evaluation of the sensitivity to the different damage mechanisms . . 114 Use of simplified process diagrams . . . . . . . . . . . . . . . . . . . . . . . . . 115 Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117 Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221

Contributions

Authors Michel BONIS, TOTAL S.A. Benoit DUCIEL, Doris Engineering Amélie FEREY, TECHNIP France Marc KAMIONKA, TECHNIP France Anass LAGRINI, SAIPEM S.A. Antoine SURBLED, A.S. Corr. Consult Delphine ZUILI, TECHNIP France and Emilie BIXQUERT, GENESIS Oil and Gas Consultants Jérémy BOISSELIER, SAIPEM S.A. Thierry BRAISAZ, TECHNIP France Cindy CECILLON-FROSSARD, TECHNIP France Alexandre DIDOT, TECHNIP France Quentin GAUSSERES, TECHNIP France Jean KITTEL, IFP ENERGIES NOUVELLES Militza LOBATON, Institut de Soudure Industries Jean-Marc MARTINEZ, SUBSEA7 Frédéric WACOGNE, Compagnie Française de Géothermie

IV Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Reviewers Claude DURET-THUAL Grégory MOULIE, TotalEnergies Steve PATERSON, Shell Felipe RAMIREZ, Modec International Inc.

List of figures and tables

Figures Figure 1.  –  Corrosion management process diagram. . . . . . . . . . . . . . . . . . . . . .3 Figure 2.  –  SSC domains as a function of pH and H2S partial pressure, as defined in NACE MR0175/ISO 15156. . . . . . . . . . . . . . . . . . . . .16 Figure 3.  –  Illustrations of a coarse-grained carbon steel HAZ reheated to close-to-critical temperatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . .22 Figure 4.  –  Reheat Cracking Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23 Figure 5.  –  The main factors of CO2 corrosion. . . . . . . . . . . . . . . . . . . . . . . . . .31 Figure 6. – CO2 corrosion of production tubing, with coalescence of craters. .32 Figure 7. – CO2 corrosion at the gas cooler outlet, ~ 3% CO2, 40 °C, ~ 7.0 MPa. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .32 Figure 8.  –  Preferential corrosion of a weld – a particular and highly localized form of CO2 corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . .33 Figure 9.  –  Localized CO2 corrosion with protruding corrosion deposit in a gas well. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .33 Figure 10.  –  Sweet vs. Sour Corrosion Domains, adapted from B. Pots & al. [1]. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36 Figure 11.  –  Severe localized corrosion of produced water pipes contaminated by oxygen ingress. . . . . . . . . . . . . . . . . . . . . . . . . . .39 Figure 12.  –  Corrosion associated with a thick iron sulfide deposit at the bottom of a gas well [5]. . . . . . . . . . . . . . . . . . . . . . . . . . . . .39 Figure 13.  –  Case of sweet TLC combining localized corrosion at the top and uniform on the sides [1]. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .44 Figure 14.  –  Tubercles removed from carbon steel surfaces in power plants (source: page 188 of Manual of microbial corrosion [9]). . . . . . . .51

VI Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 15.  –  Microbiologically Induced Corrosion of a mine water raising column (courtesy of: Compagnie Française de Géothermie). . . . .51 Figure 16.  –  Hemispheric crater morphology caused by severe Microbiologically Induced Corrosion (5 to 15 mm/year) [17]. . . .51 Figure 17.  –  Erosion - corrosion pattern. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .58 Figure 18.  –  Erosion patterns. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .58 Figure 19.  –  Preventive solutions for erosion-corrosion. . . . . . . . . . . . . . . . . . .59 Figure 20.  –  Preventive solutions for mechanical erosion. . . . . . . . . . . . . . . . . .59 Figure 21.  –  Structure of the rust layer in aerated water (adapted from H.M. Herro, Paper No. 84, Corrosion ’91). . . . . . .67 Figure 22.  –  Corrosion concentration cell, developing tubercles, chemical equilibria, pH and oxygen concentration gradients in the tubercle vs. location (adapted from HM Herro, Paper No. 84, Corrosion ’91). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 Figure 23.  –  Tubular corrosion mechanism: the mechanism is close to that leading to the development of tubercles – the tubular form is due to a combination of forces exerted during the corrosion process [9]. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .68 Figure 24.  –  Water-steam circuit; (a) oxygen induced corrosion of the upper part of a thermosiphon vaporizer; (b) detail of pit. . . . . . . . . . . . .72 Figure 25.  –  Severe pitting corrosion due to sulfur deposition. . . . . . . . . . . . . .78 Figure 26.  –  Pitting corrosion mechanism diagram in aerated chloride environment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .83 Figure 27.  –  Classification of pits according to their shape. . . . . . . . . . . . . . . . .87 Figure 28.  –  Crevice corrosion of austenitic stainless steel under gasket. . . . . .92 Figure 29.  –  Corrosion Mechanisms of Aluminum Alloys in presence of mercury. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .98 Figure 30.  –  Separation of the plates in a cryogenic exchanger core due to the formation of an amalgam. . . . . . . . . . . . . . . . . . . . . . . . . .100 Figure 31.  –  Hydrated alumina resulting from corrosion of an aluminum alloy by an amalgam. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .101 Figure 32.  –  LME cracking of an Al-Mg alloy, attack at grain boundaries (cross section, optical microscopy). . . . . . . . . . . . . . . . . . . . . . . .101 Figure 33.  –  LME cracking of a weld on a cryogenic aluminum heat exchanger. This crack caused the failure of the heat exchanger. . 101 Figure 34.  –  Cracks due to stress corrosion in H2S environments [5]. . . . . . . .107

List of figures and table

VII

Figure 35.  –  Oil and Gas Separation, Produced Water Block Flow Diagram.. . 112 Figure 36.  –  Condensate and Gas Separation Block Flow Diagram. . . . . . . . . .113 Figure 37.  –  Gas Treatment Block Flow Diagram. . . . . . . . . . . . . . . . . . . . . . .113 Figure 38.  –  Simplified Corrosion Location Diagram & Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .116 Figure 39.  –  Oil Receiving and Separation Unit (CO2 only), P01a – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . .123 Figure 40.  –  Oil Receiving and Separation Unit (CO2 only), P01a – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . .124 Figure 41.  –  Gas Receiving and Separation Unit (CO2 only), P02a – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . .125 Figure 42.  –  Gas Receiving and Separation Unit (CO2 only), P02a – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . .126 Figure 43.  –  Oil Receiving and Separation Unit (CO2 + H2S), P01b – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . .133 Figure 44.  –  Oil Receiving and Separation Unit (CO2 + H2S), P01b – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . .134 Figure 45.  –  Gas Receiving and Separation Unit (CO2 + H2S), P02b – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . .135 Figure 46.  –  Gas Receiving and Separation Unit (CO2 + H2S), P02b – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . .136 Figure 47. – CO2 corrosion caused by condensation water leaving wet gas coolers: overview and close-up. . . . . . . . . . . . . . . . . . . . . . . . . . .139 Figure 48.  –  Wet Gas Compression Unit (Sweet), P03a – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .146 Figure 49.  –  Wet Gas Compression Unit (Sweet), P03a – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .147 Figure 50.  –  Wet Gas Compression Unit (CO2 + H2S), P03b – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .148 Figure 51.  –  Wet Gas Compression Unit (CO2 + H2S), P03b – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .149 Figure 52.  –  AGRU, CO2 dominant, P04a – Corrosion Location Diagram. . . .158 Figure 53.  –  AGRU, CO2 dominant, P04a – Material Selection Diagram. . . . .159 Figure 54.  –  AGRU, H2S dominant, P04b – Corrosion Location Diagram. . . .160 Figure 55.  –  AGRU, H2S dominant, P04b – Material Selection Diagram. . . . .161

VIII Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 56.  –  Sweet Gas Dehydration Unit based on TEG, P05a – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .166 Figure 57.  –  Sweet Gas Dehydration Unit based on TEG, P05a – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .167 Figure 58.  –  Sour Gas Dehydration Unit based on TEG, P05b – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .168 Figure 59.  –  Sour Gas Dehydration Unit based on TEG, P05b – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .169 Figure 60.  –  Gas Dryers Unit, P06 – Corrosion Location Diagram. . . . . . . . . .174 Figure 61.  –  Gas Dryers Unit, P06 – Material Selection Diagram. . . . . . . . . . .175 Figure 62.  –  Examples of corrosion in SRU: (a) Weld cracking; (b) Sulfuric acid corrosion of condenser; (c) Sulfuric acid corrosion of an heater head; (d) Sulfuric acid corrosion on a burner quill. 186 Figure 63.  –  Sulfuric acid corrosion of air injection quills for degassing, installed in a sulfur pit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .186 Figure 64.  –  Sulfur Recovery Unit, P07 – Corrosion Location Diagram. . . . . .187 Figure 65.  –  Sulfur Recovery Unit, P07 – Material Selection Diagram. . . . . . .188 Figure 66.  –  Tail Gas Treatment Unit, P08 – Corrosion Location Diagram. . .198 Figure 67.  –  Tail Gas Treatment Unit, P08 – Material Selection Diagram. . . . .199 Figure 68.  –  Sweet Oil – Condensate Stabilization Unit, P09a – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .205 Figure 69.  –  Sweet Oil – Condensate Stabilization Unit, P09a – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .206 Figure 70.  –  Sour Oil – Condensate Stabilization Unit (CO2 + H2S), P09b – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . .207 Figure 71.  –  Sour Oil – Condensate Stabilization Unit (CO2 + H2S), P09b – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . .208 Figure 72. – CO2 Capture, Compression and Dehydration Unit, P10 – Corrosion Location Diagram (1). . . . . . . . . . . . . . . . . . . . .218 Figure 73. – CO2 Capture, Compression and Dehydration Unit, P10 – Corrosion Location Diagram (2). . . . . . . . . . . . . . . . . . . . .219 Figure 74. – CO2 Capture, Compression and Dehydration Unit, P10 – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . .220 Figure 75.  –  Water Treatment Unit, U01 – Corrosion Location Diagram. . . . .227 Figure 76.  –  Water Treatment Unit, U01 – Material Selection Diagram. . . . . .228

List of figures and table

IX

Figure 77.  –  Functional description of a seawater injection and cooling network. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .229 Figure 78.  –  Grooving corrosion morphology on a seawater injection pipeline. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .232 Figure 79.  –  Seawater Injection and Cooling Unit, U02 – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .240 Figure 80.  –  Seawater Injection and Cooling Unit, U02 – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .241 Figure 81.  –  Semi-Open Type Cooling Water Unit, U03a – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 252 Figure 82.  –  Semi-Open Type Cooling Water Unit, U03a – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .253 Figure 83.  –  Closed Type Cooling Water Unit, U03b – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .259 Figure 84.  –  Closed Type Cooling Water Unit, U03b – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .260 Figure 85.  –  Hot Water Production and Distribution Unit, U04 – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .266 Figure 86.  –  Hot Water Production and Distribution Unit, U04 – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .267 Figure 87.  –  Steam Generators, Steam and Condensate Circuits, U05 – Corrosion Location Diagram (1). . . . . . . . . . . . . . . . . . . . .276 Figure 88.  –  Steam Generators, Steam and Condensate Circuits, U05 – Corrosion Location Diagram (2). . . . . . . . . . . . . . . . . . . . .277 Figure 89.  –  Steam Generators, Steam and Condensate Circuits, U05 – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . .278 Figure 90.  –  Pretreatment and desalination of seawater workflow. . . . . . . . . .279 Figure 91.  –  MED – TVC Seawater Desalting Unit, U06 – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .288 Figure 92.  –  MED – TVC Seawater Desalting Unit, U06 – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .289 Figure 93.  –  RO Seawater Desalting Unit, U06– Corrosion Location Diagram. 290 Figure 94.  –  RO Seawater Desalting Unit, U06– Material Selection Diagram. . 291 Figure 95.  –  Air Compression and Distribution Unit, U07 – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .298 Figure 96.  –  Air Compression and Distribution Unit, U07 – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .299

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Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 97.  –  Profile of internal combustion in a flare tip, under the effect of wind. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .305 Figure 98.  –  HP and LP Flare Unit (Sweet), U08a – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .311 Figure 99.  –  HP and LP Flare Unit (Sweet), U08a – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .312 Figure 100.  –  HP and LP Flare Unit (Sour), U08b – Corrosion Location Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .313 Figure 101.  –  HP and LP Flare Unit (Sour), U08b – Material Selection Diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .314 Figure 102.  –  Closed Drain Network, U09 – Corrosion Location Diagram. . . .319 Figure 103.  –  Closed Drain Network, U09 – Material Selection Diagram. . . . .320 Figure 104.  –  Open Drain Network, U10 – Corrosion Location Diagram. . . . .322 Figure 105.  –  Open Drain Network, U10 – Material Selection Diagram. . . . . .323

Tables Table 1.  –  Relevance in E & P of damage mechanisms listed in API RP 571. . .12 Table 2.  –  API RP 571 vs. E & P; correspondence between damage mechanisms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12 Table 3.  –  Damage mechanisms specific to E & P. . . . . . . . . . . . . . . . . . . . . . . .15 Table 4.  –  Susceptibility of CRAs to different SCC mechanisms in H2S environments [2]. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .105 Table 5.  –  List of oil and gas production units and associated utilities. . . . . . .111 Table 6.  –  Symbolization of the sensitivity to the damage. . . . . . . . . . . . . . . . .115 Table 7.  –  Common CRA selections for applications in sweet environment. . . 121 Table 8.  –  Common CRA choices for applications in sour environment.. . . . .132 Table 9.  –  Compressed air purity classes for particles, moisture, liquid water, and oil. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .292

Introduction

The need for a guide dealing with corrosion mechanisms and prevention solutions applicable in the oil and gas upstream and midstream has become important for many players of the sector, in particular operators, maintenance specialists, inspectors, inspection managers, and engineering. This guide was written by a group of materials and corrosion specialists from oil and gas production, liquefied natural gas, and engineering. It is intended primarily for use by operators, inspectors, technologists, engineering companies, suppliers of equipment and anticorrosion solutions and those responsible for corrosion and erosion control in the sectors of exploration production (upstream) of mineral oils and natural gas and Liquefied Natural Gas (installations on or near production sites). An inventory of the documents concerning corrosion upstream of the oil and gas industries did not make it possible to find books summarizing the relevant information to characterize the specific corrosion mechanisms. API RP 571 deals with damage encountered in downstream (refining), some of these damages are common to upstream and midstream, while some others are never or very rarely encountered. A review of the API RP 571 damage mechanisms was done for possible application in exploration-production facilities. The description of some of them has been adapted to upstream. Description of damage mechanisms, specific to exploration & production, has been introduced in this guide. This guide, which covers the prediction of different corrosion mechanisms and their prevention in typical units found in oil and gas production facilities, is subdivided into four chapters: • • • •

Scope and objectives; Definitions, acronyms, and references; Description of damage mechanisms; Corrosion prediction in upstream process and utilities units.

Chapter 3 describes the degradation mechanisms encountered in the upstream and midstream while in Chapter 4, the possible damage mechanisms, their

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Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

severity, and location are described for ten process units and ten utility units. The descriptions are illustrated in typical process diagrams. Typical material selection and prevention solutions are provided. They are also reported and described on these same diagrams. These proposals are essentially generic and should be considered as a guideline and have to be confirmed or infirmed during engineering studies. It covers onshore surface installations and topsides of upstream offshore installations with the exception of structures. Production facilities such as production wells, reinjection wells, hoses, etc., are not covered in this guide.

1

1

Scope and Objectives

1.1. Scope The guide concerns oil and gas production units, excluding refining and chemical units, throughout their life cycle. Its scope covers: • All internal damage mechanisms applicable to these units and indicated in chapter 3; • The production, injection and utility units listed in chapter 4. The guide discusses all corrosion prediction, prevention, and control phases in the corrosion management process, as illustrated in figure 1.

Figure 1. – Corrosion management process diagram.

It is designed as a practical guide, divided according to functional process units: • Regarding corrosion prediction: the objective is not to describe in detail the corrosion mechanisms, criteria, or tools for predicting corrosion, even though these topics are introduced. Rather, it is to indicate the location, the conditions and the severity of the damage mechanisms involved;

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Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

• Regarding corrosion mitigation: the aim is to present the main selection of materials and prevention solutions most commonly applied, in the form of Material Selection Diagrams supported by additional explanations. This document purposely uses the same approach as the one used in API RP 571. From the list of damage mechanisms covered in API RP 571, only the damage mechanisms applicable to the oil production facilities are retained and adapted, where relevant. Additional damage mechanisms specific to oil and gas production facilities are also described in a similar format. The prediction and corrosion mitigation information provided in this document can be used as input when setting up corrosion management and monitoring for an oil or gas production facility. The procedures for designing, installing, commissioning, and performing corrosion monitoring are described in the CEFRACOR’s Scientific and Technical Guide: “Monitoring Internal Corrosion in the Oil and Gas Industries”.

1.2. Objectives The main objectives are: – to promote awareness of the damage mechanisms that are commonly occurring oil and gas production facilities for all persons involved; – to indicate their potential severity, according to the operating conditions; – to help locate these mechanisms in the facilities, in order to anticipate them, avoid them or monitor their evolution; – to help with materials selection and corrosion prevention solutions in the design phase; – to provide schematics and diagrams that can be used in documents, guides, specifications, etc.; – to provide up-to-date feedback from operated facilities.

2 Definitions, Acronyms and References 2

2.1. Definitions Austenitic: A term that refers to a type of metallurgical structure (austenite) normally found in 300 Series stainless steels and nickel base alloys. Block Flow Diagram: A drawing of a process used to simplify and understand the basic structure of a system. Carbon steel: Steels without intentionally added alloying elements. However, specifications, such as SA516-70 (P355NH) and SA106 Gr B (W. Nr. 1.0405), permit the occurrence of small amounts quantities of elements such as Cr, Ni, Mo, Cu, -S, Si, P, Al, V and B, which can affect corrosion resistance, hardness after welding, and toughness. Corrosion: According to ISO 8044, corrosion is a physico-chemical interaction between a metal and its environment leading to changes in the properties of the metal and which may lead to a significant degradation of the function of the metal, of the surrounding environment or of the technical system of which they are a part of. Corrosion loop (or corrosion circuit, according to API RP 970): A set of pipes and equipment of equivalent material exposed to a process environment of equivalent corrosiveness, leading to damage mechanisms and degradation rates that can be expected to be reasonably similar. Corrosion monitoring: Monitoring of corrosion and/or erosion. Damage: The effect of corrosion or erosion detrimental to the function of the material, its environment, or the technical system of which it forms part. Damage mechanism: For any type of damage, the mechanism includes the physicochemical processes associated with a material and its environment. Duplex (stainless steel): A family of stainless steels that contain a mixed austenitic-ferritic structure, including lean duplex e.g.: (S32101, EN 1.4162), duplex e.g.: (S32205, EN 1.4462), super duplex e.g.: (S32750, EN 1.4410). Erosion-corrosion: The joint action involving erosion and corrosion in the presence of a moving corrosive fluid or material carried by the fluid, leading to accelerated loss of metal.

6

Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Erosion: The progressive loss of material from a solid surface resulting from mechanical interaction between that surface and a fluid, a multicomponent fluid, or solid particles carried out with the fluid. Ferritic: A term that refers to a type of metallurgical structure (ferrite) normally found in carbon and low-alloy steels and many 400 series stainless steels. Heat Affected Zone (HAZ): The portion of the base metal in contact with a weld and which has not melted, in which the metallurgical microstructure and mechanical properties have been changed by the welding heat, sometimes with undesirable effects. Integrity Operating Window: Established limits for process variables (parameters) that can affect the integrity of the equipment if the process operation deviates from the established limits for a predetermined amount of time (includes Critical, Standard and Informational IOW’s). Martensitic: A term that refers to a type of metallurgical structure (martensite) normally found in some 400-series stainless steels. Heat treatment and/or welding followed by rapid cooling can produce such a structure in carbon and low-alloy steels. Material Selection Diagram: An engineering drawing which shows material selection information and specification of the piping and equipment in a process unit/ facility, the material selection diagrams are based on process flow diagrams. Process Flow Diagram: A simplified diagram of a process unit showing the main equipment parts and piping, with limited details of process design and operating parameters. Stainless steel: Four categories of stainless steel are characterized by their metallurgical structure at room temperature: austenitic, ferritic, martensitic, and duplex. These alloys contain varying amounts of chromium and other alloying elements that make them variably resistant to corrosion.

2.2. Acronyms AGRU AHPH AIRC AMP API ATB AWS BAHX BEU BFD BFW

Acid Gas Recovery Unit 2-amino 2-hydroxymethyl 1,3-propanediol Adsorption Induced Reduction in Cohesion 2-Amino-2-methyl-1-propanol American Petroleum Institute Amine Total Base American Welding Society Brazed Aluminum Heat Exchanger Exchanger type per TEMA code Block Flow Diagram Boiler Feed Water

2 – Definitions, Acronyms and Reference

Bis-HEP BKU BSW CAPEX CCS CCT CEFRACOR CFD CMIC CPT CRA CUI DADS DEA DEDA DEG DEM DIPA DM DMDS DMW DNBPA DNS DPM DSS E & P ED EDTA EFC EFW ENCAP EMIC EPDM EPRI ER ERW FEPM

7

Bis-Hydroxy ethyl piperazine Exchanger type per TEMA code Basic Sediments & Water Capital Expenditure Carbon Capture and Storage Critical Crevice Temperature French Anti-Corrosion Center (Centre Français de l’Anti-Corrosion) Computational Fluid Dynamics Chemical Microbially Influenced Corrosion Critical Pitting Temperature Corrosion Resistant Alloy Corrosion Under Insulation Diaryl Disulfide Diethanolamine Di-ethylene diamine (Piperazine) Diethylene glycol Discrete Element Model Diisopropanolamine Damage Mechanism Dimethyl Disulfide Dissimilar Metal Weld 2,2-dibromo-3-nitrilopropionamide (biocide) Direct Numerical Simulation Discrete Particles Model Duplex Stainless Steels Exploration & Production Electro dialyse Ethylene Diamine tetra acetic acid European Federation of Corrosion Electric Flash Welding, Electric Fusion Welding Enhanced Capture of CO2 (EU Project 2004–2009) Electrical Microbially Influenced Corrosion Ethylene-propylene-diene monomer Electric Power Research Institute Electrical Resistance (Probes) Electric Resistance Welding Fluorinated Ethylene Propylene Monomer

8

Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

FFKM FKM FRP HAZ HDPE HFW HIC HMPO HP HPHT HSC HSS HT HVOF IGC IGSCC IPIECA

Perfluoroelastomer Fluoroelastomer Fiber Reinforced Plastic Heat Affected Zone High Density Polyethylene High Frequency Welding Hydrogen Induced Cracking Hydroxymethyl propyl oxazolidone High Pressure High Pressure, High Temperature Hydrogen Stress Cracking Heat Stable Salts High Temperature High Velocity Oxy-Fuel Intergranular Corrosion Intergranular Stress Corrosion Cracking International Petroleum Industry Environmental Conservation Association ISO International Organization for Standardization ISOCORRAG Atmospheric corrosion test program organized by ISO between 1986 and 1998 IOW Integrity Operating Window LES Large Eddy Simulation LME Liquid Metal Embrittlement (also LM induced Embrittlement, LMIE and LM Induced Cracking, LMIC) LNG Liquefied Natural Gas LPR Linear Polarization Resistance LR-ERW Low Frequency Electric Resistance Welding LTCS Low Temperature Carbon Steel MD Membrane Distillation MDEA Methyl diethanolamine MDT Minimum Design Temperature MEA Monoethanolamine MED Multi Effect Distillation MED-MVC Multi Effect Distillation - Mechanical Vapor Compression MEG Mono Ethylene Glycol (1,2-Ethanediol) ME-TVC Multi Effect Thermal Vapor Compression

2 – Definitions, Acronyms and Reference

MICAT MPT MRU MSD MSF NAB NACE NETL O&G OPEX PE PEC PFD PPR PRE PREN PREW PTFE PWC RANS RBI RFB RO RP SCC SCOT SME SMIE SOHIC SRB SRU SSC SSCC TAC TDS TEG

9

Ibero-American Map of Atmospheric Corrosiveness Minimum Pressurization Temperature Mercury Removal Unit Material Selection Diagram Multi-Stage Flash Nickel Aluminum Bronze NACE International National Energy Technology Laboratory Oil and Gas Operational Expenditure Polyethylene Pulsed Eddy Current Process Flow Diagram Pitting Propency Rating Pitting Resistance Equivalent (Number) Pitting Resistance Equivalent of Ni-Stainless steels (Number) Pitting Resistance Equivalent of W-Stainless steels (Number) Polytetrafluoroethylene Preferential Weld Corrosion Reynolds-Averaged Navier-Stokes Risk Based Inspection Regenerable Free Base Reverse Osmosis Recommended Practice Stress Corrosion Cracking Shell Claus Off gas Treating Solid Metal Embrittlement Solid Metal Induced Embrittlement Stress Oriented Hydrogen Induced Cracking Sulfate-Reducing Bacteria Sulfur Recovery Unit Sulfide Stress Cracking Sulfide Stress Corrosion Cracking Total Alkalinity, or methyl orange alkalinity (includes OH– + CO3–– + HCO3–) Total Dissolved Salts Triethyleneglycol

10 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

TEMA TGTU THEED TLC TRB UDC UV VRU WHB

Tubular Exchanger Manufacturers Association Tail Gas Treatment Unit Tri-hydroxyethyl ethylenediamine Top of Line Corrosion Thiosulfate-Reducing Bacteria Under Deposit Corrosion Ultra Violet Vapor Recovery Unit Waste Heat Boiler

2.3. Standards and other references This section lists only the main references. Most of the bibliography is included in those sections dedicated to the units or damage mechanisms. API Recommended Practice 571, Damage Mechanisms Affecting Fixed Equipment in the Refining Industry, 3rd edition, American Petroleum Institute, Washington, D.C., March 2020. API Recommended Practice 584, Integrity Operating Windows, 2nd edition, American Petroleum Institute, Washington, D.C., December 2021. API Recommended Practice 970, Corrosion Control Documents, 1st edition, American Petroleum Institute, Washington, D.C., December 2017. ISO 8044, Corrosion of metals and alloys – Basic Terms and definitions, International Standard, February 2020. NACE MR0175/ISO 15156, Petroleum and natural gas industries – Materials for use in H2S-containing environments in oil and gas production, part 1, part 2 and part 3, International Standard, 2015. CEFRACOR, “Monitoring de la Corrosion Interne dans les Industries Pétrolières et Gazières”, EDP Sciences, Paris, France, Copyright © 2016, ISBN: 978-2-7598-1746-7.

3

3

Description of Damage Mechanisms

At the time of writing this document, there was no reference document describing damage mechanisms specific to E & P activities. Therefore, it was decided to make an inventory of the mechanisms described in API RP 571 and to check their applicability.

3.1. Assessment of damage mechanisms applicable to E & P The classification in API RP 571 is based on a pragmatic rationale developed by players in the oil refining industry. Damage mechanisms can be categorized as follow: • • • • •

Mechanical and metallurgical damage; Generalized or localized loss of thickness; High-temperature corrosion (> 200 °C); Environmentally assisted cracking; Other mechanisms.

The names of damage mechanisms are relevant for the material and corrosion in oil and gas downstream profession but not necessarily for the scientific community or for other industries. Some damage mechanisms encountered in refining are not applicable to E & P, and are not covered in this document. Some damage mechanisms are common to those potentially encountered in E & P, and so their description is retained or slightly modified. Other damage mechanisms, such as those due to CO2, to stress and corrosion in the presence of H2S, to erosion-corrosion, and due to microbiological environments, require a description specific to the E & P sector. Finally, some damage mechanisms encountered in E & P are not mentioned in API RP 571, either because they are not encountered in refining, or because they are known by another name. In such cases, these are discussed under a specific description.

12 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

The criteria for ranking the relevance of damage mechanisms descriptions in API RP 571 with respect to E & P are given in table 1. The damage mechanisms names indicated in API RP 571, in some cases modified to fit the E & P context, are listed in table 2. The damage mechanisms are annotated according to their relevance in E & P. The changes to API RP 571 are described in the “Action” column in table 1 and the “Damage mechanism name” column in table 2. Table 3 introduces the damages mechanisms developed in this document. Table 1.  –  Relevance in E & P of damage mechanisms listed in API RP 571. Relevance

Meaning of the ranking

Action

Unlikely

With current technologies it is unlikely to experience this type of damage mechanism in E & P.

No amendment of API RP 571 (See table 2)

Marginal

This damage mechanism may occur in specific units or utilities, but it is not a major industry concern.

Low

This damage mechanism is sometimes occurring.

Moderate

This damage mechanism is regularly occurring.

Amendment of API RP 571 (See table 2 and section 1.1)

High

This damage mechanism is frequently occurring and is a major concern.

Table 2.  –  API RP 571 vs. E & P; correspondence between damage mechanisms. DM#

API RP 571 Damage Mechanism Name

Application E & P Relevance

Reference

DM#

1

Sulfidation

Marginal

API RP 571

1

2

Wet H2S Damage - Note 1 Sulfide Stress Cracking (SSC)

High

API RP 571 & § 3.2.1

2

Blistering / HIC

Moderate

API RP 571 & § 3.2.1

2

SOHIC

Marginal

API RP 571 & § 3.2.1

2

3

Creep / Stress Rupture

Marginal

API RP 571

3

4

High temperature H2/H2S Corrosion Unlikely

API RP 571

4

5

Polythionic Acid Cracking

Marginal

API RP 571

5

6

Naphthenic Acid Corrosion

Unlikely

API RP 571

6

7

Ammonium Bisulfide Corrosion (alkaline sour water)

Unlikely

API RP 571

7

8

Ammonium Chloride Corrosion

Marginal

API RP 571

8

9

Hydrochloric Acid Corrosion

Moderate

API RP 571 & § 3.2.2

9

10

High-Temperature Hydrogen Attack

Unlikely

API TR 941 API RP 571

10

3 – Description of Damage Mechanisms

DM#

13

API RP 571 Damage Mechanism Name

Application E & P Relevance

Reference

DM#

11

Oxidation

Marginal

API RP 571

11

12

Thermal Fatigue

Marginal

API RP 571

12

13

Sour Water Corrosion (acidic) – Note 2

Low

API RP 571

13

14

Refractory Degradation

Marginal

API RP 571

14

15

Graphitization

Unlikely

API RP 571

15

16

Temper Embrittlement

Unlikely

API RP 571

16

17

Decarburization

Unlikely

API RP 571

17

18

Caustic Stress Corrosion Cracking

Low

API RP 571 & § 3.2.3

18

19

Caustic Corrosion

Low

API RP 571 & § 3.2.3

18

20

Erosion / Erosion-corrosion

High

Replaced

P5

21

Carbonate Stress Cracking Corrosion

Marginal

API RP 571

21

22

Amine Stress Corrosion Cracking

Moderate

API RP 571 & § 3.2.4

22

23

Chloride Stress Corrosion Cracking

High

API RP 571 & § 3.2.5

23

24

Carburization

Unlikely

API RP 571

24

25

Hydrogen Embrittlement

High

API RP 571 & § 3.2.6

25

27

Thermal Shock

Unlikely

API RP 571

27

28

Cavitation

High

API RP 571 & § 3.2.7

28

29

Graphitic Corrosion (see Dealloying) Marginal

API RP 571 & § 3.2.8

41

30

Short Term Overheating – Stress Marginal Rupture (including steam blanketing)

API RP 571

30

31

Brittle Fracture

High

API RP 571 & § 3.2.9

31

32

Sigma Phase / Chi Embrittlement

Moderate

API RP 551

32

33

885 F (475 °C) Embrittlement

Moderate

API RP 571 & § 3.2.10

33

34

Softening (Spheroidization)

Unlikely

API RP 571

34

35

Stress Relaxation Cracking (Reheat Cracking)

Moderate

API RP 571 & § 3.2.11

35

36

Sulfuric Acid Corrosion

Low

API RP 571

36

37

Hydrofluoric Acid Corrosion

Unlikely

API RP 571

37

38

Flue-Gas Dew-Point Corrosion – Note 3

Marginal

API RP 571 & § 3.2.12

38

39

Dissimilar Metal Weld (DMW) Cracking

Marginal

API RP 571

39

40

Hydrogen Stress Cracking in HF

Unlikely

API RP 571

40

41

Dealloying (Dezincification / Denickelification)

Moderate

API RP 571 & § 3.2.8

41

42

CO2 Corrosion – Note 4

Low

API RP 571

42

14 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

DM#

API RP 571 Damage Mechanism Name

Application E & P Relevance

Reference

DM#

43

Corrosion-Fatigue

High

API RP 571

43

44

Fuel Ash Corrosion

Unlikely

API RP 571

44

45

Amine Corrosion

Moderate

API RP 571 & § 3.2.13

45

46

Corrosion Under Insulation (CUI)

High

EFC 55

46

47

Atmospheric Corrosion

High

API RP 571 & § 3.2.14

47

48

Ammonia Stress Corrosion Cracking

Marginal

API RP 571 & § 3.2.16

48

49

Cooling Water Corrosion

High

API RP 571 & § 3.2.16

49

50

Boiler Water / Condensate Corrosion High

API RP 571 & § 3.2.17

49

51

Microbiologically Induced Corrosion (MIC)

High

Replaced

P4

52

Liquid Metal Embrittlement

Moderate

Replaced

P11

53

Galvanic Corrosion

High

API RP 571 & § 3.2.18

53

54

Mechanical Fatigue (includes Vibration Fatigue)

High

API RP 571

54

55

Nitriding

Unlikely

API RP 571

55

57

Titanium Hydriding

Moderate

API RP 571 & § 3.2.19

57

58

Soil Corrosion

High

API RP 571 & § 3.2.20

58

59

Metal Dusting

Unlikely

API RP 571

59

60

Strain Aging

Marginal

API RP 571

60

62

Phosphoric Acid Corrosion

Unlikely

API RP 571

62

63

Phenol (carbolic acid) Corrosion

Unlikely

API RP 571

63

64

Ethanol Stress Corrosion Cracking

Marginal

API RP 571

64

65

Gaseous Oxygen-Enhanced Ignition and Combustion

Marginal

API RP 571 & § 3.2.21

65

66

Organic Acid Corrosion

Unlikely

API RP 571

66

67

Brine Corrosion

Moderate

API RP 571

66

68

Concentration Cell Corrosion

Moderate

API RP 571

68

69

Hydrofluoric Acid Stress Corrosion Cracking of Nickel Alloys

Unlikely

API RP 571

69

70

Oxygenated Water Corrosion (Non-Boiler)

Moderate

Replaced

P7

Note 1

In API RP 571, Wet H2S Damages (Sulfide Stress Cracking (SSC), Blistering, HIC, SOHIC) descriptions are differing from NACE MR0175 / ISO 15156.

Note 2

DM#13: Process specific, See DM#P2 for usual E & P process.

Note 3

DM#38: More generally, Acid Gases Dew Point Corrosion.

Note 4

DM#42: Process specific, See DM#P1 for usual E & P.

3 – Description of Damage Mechanisms

15

Table 3.  –  Damage mechanisms specific to E & P. DM#

Damage Mechanism Name

E & P application Relevance

Comments

P1

CO2 Corrosion

High

Replace DM#42 for E & P-specific processes

P2

H2S + CO2 Corrosion (weight loss corrosion) (not including cracking)

High

Replace DM#13 for E & P-specific processes

P3

Top of Line Corrosion

High

P4

Microbiologically Induced Corrosion

High

Replace DM#51

P5

Erosion-Corrosion/ Erosion

High

Replace DM#20

P6

Under Deposit Corrosion

High

Not specific to E & P

P7

Oxygen Induced Corrosion

High

Not specific to E & P

P8

Low Temperature Sulfur Corrosion

High

Not specific to E & P

P9

Pitting Corrosion

High

Not specific to E & P

P10

Crevice Corrosion

High

Not specific to E & P

P11

Mercury Induced Cracking of Aluminum Alloys

Moderate

Important in gas liquefaction processes.

P12

Aluminum Alloys Amalgamation and Amalgam Corrosion

Moderate

Important in gas liquefaction processes.

P13

SCC of Corrosion Resistant Alloys

High

Note

Pitting Corrosion and Crevice Corrosion are not strictly corrosion mechanisms but manifestation of corrosion mechanism.

3.2. Damage mechanisms amended from API RP 571 Some descriptions in API RP 571 are perfectly applicable to refining, but cannot be fully applied to E & P. Others need to be revised because of the different environmental conditions occurring in the E & P sector. The purpose of this section is to highlight the specific characteristics of these damages mechanisms in the E & P sector.

3.2.1.

Wet H2S Induced Cracking (Blistering / HIC / SCC / SOHIC) (DM#2)

The damage mechanisms SSC, blistering (internal decohesion)/HIC and SOHIC are considered separately in the E & P sector. Even if they have become relatively rare, their consequences are immediate and often dramatic.

16 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

SSC type of damage is one of the worst types of damage in E & P. It requires a combination of i) hydrogen entry into the steel, which is highly promoted in corrosive solutions with dissolved H2S; ii) a susceptible steel – high strength low alloy steel grades are generally more prone to SSC than medium and low strength grades; and iii) either residual or applied stresses/strains, e.g. resulting from internal pressure, weight of tubes in the well, bending, end effect for surface facilities… SSC cracks are generated at the surface of the steel, perpendicular to the applied stress. The cracking process does not require incubation time, so that it may appear after as low as a few hours or a few days of exposure if the material is not properly selected with respect of environmental conditions. Owing to the extreme dangerousness of SSC, a considerable amount of work has been carried out by E & P operators together with the steel industry since the 1970’s (first editions of NACE recommendation MR0175 for the selection of steels for use in H2S containing environments, and NACE TM 0177, [20], for laboratory testing of the resistance of metals to SSC). The accumulation of laboratory test data shared by all the industrial actors then led to the publication by the European Federation of Corrosion of a guideline on materials requirements for low alloy steels for H2S containing environments in oil and gas production (EFC 16 publication). At the beginning of the 2000’s, NACE MR0175 and EFC16 documents merged into the ISO standard NACE MR0175/ISO 15156 [1] that helps: in evaluating the susceptibility of materials to such damage, depending on the environment, and in selection of the materials that can be used with respect to the environment. SSC severity domains as a function of in situ pH and H2S partial pressure, first developed in EFC16 document, [19], have been introduced in the NACE MR0175/ ISO 15156 document (figure 2).

6

region 0

SSC region 1

5

pH

C SS

2 ion g e r

4

SSC region 3

3 1

10

100

pH2S (mbar)

1000

Figure 2. – SSC domains as a function of pH and H2S partial pressure, as defined in NACE MR0175/ISO 15156.

3 – Description of Damage Mechanisms

17

Blistering and HIC result from a mechanism different from SSC, though they have in common the penetration into the steel of ”atomic” hydrogen from corrosion reactions and from the promoting contribution of H2S / HS– to this penetration. Such damage is seen in steel plate with low yield strength and can occur in the absence of applied stress. The presence of sulfur inclusions increases the sensitivity of the material to these mechanisms. Blistering and hydrogen induced cracking are less common than SSC in the E & P sector since the 80–90’s, because the necessary metallurgical precautions have progressively been implemented, however they can occur in gas treatment units and water stripping units for removing sour contents. These damage mechanisms mostly concern rolled steel plate. Document NACE TM0284 [2] defines the test method used. The acceptance criteria for the defects are usually provided by dedicated specifications. Reference values are given in NACE MR0175/ISO 15156 [1]. Stress Oriented Hydrogen Induced Cracking (SOHIC) occurs under the effect of stresses, possibly internal only, usually on welded joints or in the weld transition zone (HAZ). This type of damage mechanism has been occurred on pipeline steels in E & P, because of the precautions currently implemented to prevent both HIC and SSC. It has been observed in gas processing units, in plate of relatively low yield strength whose cleanliness falls out of the E & P criteria applicable since 1990 - 2000. The critical factors for the E & P sector are described in NACE MR0175/ISO 15156 [1] parts 1 & 2. H2S related cracking can occur within a few hours or days, in any wet H2S containing environment. Qualification of steel used in H2S containing environments

3.2.2.

HCl Corrosion (DM#9)

Most metallic materials used in E & P may be affected by this type of corrosion. Aqueous solutions of hydrochloric acid can also degrade plastics or composite materials. Hydrochloric acid is used in E & P for water treatment, for chemical cleaning of facilities and for well stimulation. The contact with production facilities is temporary, mostly for several hours/ days only (with the exception of the piping used to deliver the acid until its injection point). Corrosion damage by hydrochloric acid can be encountered in these applications. A corrosion inhibitor is usually applied for downhole well stimulations to provide short term protection.

3.2.3.

Stress Corrosion in Alkaline Environments Caustic Soda (Caustic Cracking) (DM#18) & Caustic Corrosion (DM#19)

The damage mechanisms in caustic environments are stress corrosion cracking and/or caustic corrosion in a high-pH environment containing alkali metal hydroxides.

18 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

When steel comes in contact with caustic soda, such damage generally occurs at very specific pH and electrochemical potential conditions, corresponding to dihypoferrite formation. In E & P, carbon steel and stainless steels may be subjected to caustic corrosion. This type of corrosion also affects many other metals and metal alloys, especially aluminum alloys. The units that are affected are essentially water treatment deionization sections and boilers, as well as mercaptan processing units.

3.2.4.

Amine Cracking (DM#22)

In addition to the information given in documents [3] and [4], recent solvent formulations (Piperazine and MDEA for example) used both in gas treatment units and in CO2 capture units have to be taken into consideration. When used in CO2 capture plants, the main issue for the amine employed is the permanent exposure to the residual oxygen contained in most flue gases.

3.2.5.

Chloride Stress Corrosion Cracking (DM#23)

In addition to the mechanism described in DM#P13, Chloride stress corrosion cracking can affect equipment and pipe made of austenitic or duplex stainless steels that are in contact with a medium containing chloride (seawater, condensates...) and dissolved oxygen.

3.2.6.

Hydrogen Embrittlement (DM#25)

In E&P, hydrogen embrittlement may result from exposure any corrosion reaction where hydrogen is generated, if reactant is H2S, then it is likely associated with SSC. Hydrogen produced by corrosion reaction penetrates the material (as a proton in the steel matrix) and diffuses into the metal. Another source of hydrogen is cathodic protection, in which the hydrogen that develops at the cathode penetrates and diffuses into the material. Hydrogen can also be generated by surface treatment operations (zinc coating for example). In this case the hydrogen remains in the material and embrittles it. Several significant incidents have occurred due to the embrittlement of threaded rods following a surface treatment. In E&P, carbon steel (API 5L X60 and higher grades), 400 series stainless steels, duplex stainless steels, precipitation hardened stainless steels, and certain nickel or Ni-Fe-Cr alloys (in particular precipitation hardened Ni based alloys), are potentially sensitive to hydrogen embrittlement. HISC of duplex stainless steels and Hydrogen Stress Cracking (HSC) of precipitation hardened Nickel alloys are forms of hydrogen embrittlement.

3 – Description of Damage Mechanisms

3.2.7.

19

Cavitation (DM#28)

The cavitation phenomenon is the rupture of a continuum of a liquid caused by a decrease in pressure at roughly constant liquid temperature [5], it can appear under the following circumstances: • High velocity flows around geometries causing areas of depression; • Flows causing high shear stresses, for example, dragging obstacles or flow control devices; • Transient flows, such as water hammers. When the pressure is sufficiently low, it may become lower than the saturated vapor pressure, and a vapor bubble is formed. It is possible to define the cavitation according to their origin and form, however, there is no established consensus on a single classification: • Attached cavitation: Attached cavitation develops in hydraulic systems, it is characterized by a pocket of vapor attached to the leading edge, resulting in the erosion of surfaces where it develops. Vapor cavities are entrained by the flow and implode in compression zone. This is the typical case of ship propellers; • Convected cavitation: Occurs when the incidence of flow at the leading edges is low. The separated vapor bubbles form in the zones of depression, their volume increases, then these bubbles implode in the zones where the pressure becomes greater than that of the saturating vapor. This form of cavitation is encountered in the pumps near their optimum operating point. They are the source of hydraulic noise; • Vortex cavitation: Can be attached or convected. It occurs under the effect of the depression in the center of a vortex, which causes a local vaporization of the liquid. The energy and stress induced by cavitation cause damage that is generally demonstrated by the tearing of metal. Resistance to cavitation can be improved by design (e.g., material change, conception) or improved fluid flow (e.g., use of additives) and increased pressures. The occurrence of cavitation phenomena can be detected using ultrasonic sensors and vibration analysis techniques. The effects of cavitation can be modeled by numerical methods.

3.2.8.

Dealloying (Selective Corrosion, Dezincification, Denickelification …) (DM#41)

Selective corrosion is characterized by the preferential dissolution of one or more components or specific phases of the alloy in the presence of an electrolyte. It often results from galvanic effects at grain boundaries level. In some cases, the alloy becomes porous, and its mechanical properties are often altered.

20 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

The most common forms of selective corrosion are: • • • • • • •

Graphitic Corrosion of cast iron (DM#29 API RP 571); Dezincification of certain brasses; Denickelification of copper-nickel alloys or monels; Decobaltification of Co-Cr-W alloys; Dealumination of aluminum bronzes; Selective corrosion of duplex stainless steels; In general, selective corrosion of phases or precipitates at grain boundaries.

Graphitic corrosion mainly affects gray cast iron. Cast iron has been rarely used in E & P for many years now. Graphitic corrosion takes the form of selective dissolution of the alpha phase while the graphite remains intact. This type of corrosion is less sensitive with ductile cast iron in which the graphite is spheroidal. Graphitic corrosion does not occur in white cast iron (cementite – ferrite alloys). Dezincification affects single-phase brass with a high zinc content and alpha + beta two-phase alloys; the presence of iron and/or manganese in the alloy accelerates the process. Dezincification of admiralty brasses (C44300, C44400) is restrained or prevented by the use of suitable alloying elements such as arsenic, antimony, tin, or phosphorus. Brasses are seldom used in E & P, [6]. Denickelization is the selective corrosion of nickel in nickel or copper-nickel alloys, especially 70Cu-30Ni alloys [6]. It is infrequent and may occur after prolonged use in freshwater or is the result of thermo-galvanic effects resulting from hot spots above 150 °C. Decobaltification is the selective corrosion of cobalt or cemented carbides in cobalt alloys, such as Stellite. Dealumination of two-phase aluminum bronze (Al ≥ 9.1%) is prevented by heat treatments, which eliminate the γ2 phase while preserving the α and β structures. Single-phase aluminum bronzes (Al 40). In freshwater closed loops systems, carbon steel is most often used. Corrosiveness is mitigated by suitable compositions and physicochemical characteristics of the medium: salinity, pH, suspended solids, organic matter, concentration of calcium and magnesium, concentration of anions (chlorides, sulfates, carbonates, bicarbonates and oxygen) and by chemical and bacteriological treatments. Monitoring essentially involves determining chemical parameters such as pH, and conductivity. In the case of freshwater cooling, Ryznar or Langelier indexes, cation (Ca, Mg, Fe, Cu) and anion (HCO3–, CO32–, Cl–, SO42–...) concentrations are also used to anticipate and follow the water corrosiveness. Inspections must be suited to the expected damage mechanisms.

3.2.17. Boiler Water / Condensate Corrosion (DM#50) Mechanism DM#50 is actually a combination of several mechanisms, [13, 14]. As mentioned above, it is best to define the applicable mechanisms in a corrosion study. It is useful to distinguish potential damage due to boiler feed water from that due to steam condensate. The following types of damage should be considered in a boiler-feed water context: • • • • • •

Erosion - Corrosion (DM#P5); Oxygen Induced Corrosion (DM#P7); Galvanic Corrosion (if the conductivity is high) (DM#53); Acidic Corrosion, [14]; Corrosion by complexing agents, [14]; Cavitation (DM#28).

In a steam condensate context, the most significant types of damage are: • Erosion - Corrosion (DM#P5); • CO2 Corrosion (DM#42);

3 – Description of Damage Mechanisms

27

• Oxygen Induced Corrosion (DM#P7); • Dealloying (DM#41); • Acid Dew Point (CO2) Corrosion.

3.2.18. Galvanic Corrosion (DM#53) Galvanic corrosion is form of corrosion that occurs at the interface of different conductive materials in the presence of an electrolyte. It can potentially affect all conductive materials. Graphite, some composites, and carbon-charged polymers are conductive and cause galvanic corrosion. Galvanic corrosion is not specific to E & P. In practice it is not frequently experienced in oil and gas production because the produced fluids usually prevent continuity of the water over the interface of two materials. Stratified flow is potentially the most detrimental flow condition. However, galvanic corrosion does occur in seawater injection systems, and external environments such as steel bolts in stainless steel equipment.

3.2.19. Titanium Hydriding/Hydride Cracking (DM#57) Hydriding is a mechanism often related to the galvanic effect between a sensitive titanium alloy and another alloy in contact, with the titanium being the cathode. It is found in water systems, especially in seawater. Hydrogen formed on titanium surface acting as a cathode reacts with the metal, thereby forming hydrides. Embrittlement is delayed with respect to the absorption of hydrogen. The metal is increasingly attacked over time. Due to the lower solubility of hydrogen in pure titanium and in alloys with an α-β structure, hydriding is encountered mostly in these alloys. β-structure alloys are less sensitive. The critical factors are the chemical composition of the environment, the alloy composition, and the alloy temperature. Hydriding occurs within pH ranges below 3.0 or above 8.0 or at neutral pH in the presence of H2S. Equipment made of a titanium alloy subjected to a cathodic protection at a potential ≤ 0.9 Volt/SCE is at high risk from hydriding. The galvanic contact between the titanium alloy and more active metals such as carbon steel exacerbates the damage. However, galvanic contact is not necessary, hydride cracking can occur if the surface of the titanium alloy is in contact with the corrosion products of steel or of a more reactive metal (iron oxides, sulfides, etc.). Damage can appear on tubular plates of carbon steel heat exchangers clad with a titanium alloy or another vulnerable metal.

28 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.2.20. Soil Corrosion (DM#58) The corrosion of buried structures is a significant problem encountered in E & P buried pipeline system. Soil properties (e.g., wetness and conductivity) often change over the length of a pipeline, consequently affecting the corrosion behavior. It is preferable to define the primary damage mechanisms encountered such as differential aeration corrosion (oxygen concentration), Microbiologically Induced Corrosion (MIC), etc.

3.2.21. Oxygen-Enhanced Ignition and Combustion (DM#65) The ignition of materials in an oxygen-enriched atmosphere is not a specific damage mechanism. However, the conditions of degradation are different from those encountered in a conventional atmosphere. When the oxygen concentration in a mixture rises above 23.5% by volume, oxygen reactivity is greatly increased, thereby increasing the risk of ignition and fire. Materials that do not burn in ordinary air can burn energetically in an oxygen-rich environment even at low pressure, as is the case with most metallic materials [3]. The auto-ignition temperature and heat of combustion criteria are considered for material selection in an oxygen-rich environment. Factors affecting materials in oxygen-rich media: • The nature of oxides presents on the metal surface; • The source(s) of ignition: the contaminant itself can ignite under the effect of many factors such as particle impact, mechanical impact, pneumatic impact, ignition sources, seizure, friction, resonance, electric arc; • Operating conditions (temperature, pressure, gas velocity, purity, geometry of the equipment); • The ignition temperature thresholds values.

3.2.22. References 1

ANSI/NACE MR0175/ISO 15156, Petroleum and natural gas industries – Materials for use in H2S-containing environments in oil and gas production, part 1, part 2 and part 3, International Standard, 2015.

2

ANSI/NACE Test Method 0284, Standard Test Method, Evaluation of Pipeline and Pressure Vessel Steels for Resistance to Hydrogen-Induced Cracking, NACE International, HOUSTON, TX, March 2016.

3

API Recommended Practice 571, Damage Mechanisms Affecting Fixed Equipment in the Refining Industry, 3rd edition, American Petroleum Institute, Washington, D.C., March 2020.

4

API Recommended Practice 945, Avoiding Environmental Cracking in Amine Units, American Petroleum Institute, Washington, D.C., June 2003 reaffirmed June 2020.

3 – Description of Damage Mechanisms

29

5

C.E. Brennen, “Cavitation and Bubble Dynamics”, Oxford University Press, NY, 1995, ISBN: 0-19-509409-3.

6

R. Francis, “The Corrosion of Copper and its Alloys: A practical Guide for Engineers”, NACE International, Houston, TX, Copyright © 2010, ISBN: 978-1-57590-225-8.

7

Perry’s Chemical Engineers’ Handbook, Eighth Edition, Don W. Green, Mc Graw-Hill, NY. ISBN-13: 978-0071422949 and ISBN-10: 0071422943.

8

F. Gabrielli, S. Goodstine, T. Mastronarde, Alstom Cold-end Corrosion in HRSG’S, Power Inc. Alstom Power Inc. 2000 Day Hill Road Windsor CT, PowerPlant Chemistry; 4, 3; 148 – 153, 2002, ISSN 1438 – 5325.

9

ISO 9223, Corrosion of metals and alloys -- Corrosiveness of atmospheres -- Classification, determination and estimation, International Standard, ICS 77.060 – 2012, reaffirmed 2017.

10

ISO 9224, Corrosion of metals and alloys -- Corrosiveness of atmospheres -- Guiding values for the corrosiveness categories, International Standard, ICS 77.060 – 2012, reaffirmed 2017.

11

ASM Metals Handbook, Volume 13, “Corrosion”, ASM International, Materials Park, OH, 1600-1602, ISBN 0-87170-007-7.

12

R.D. Port and H.M. Herro, “The Nalco Guide to Cooling Water System Failure Analysis”, Nalco Chemical Company, McGraw-Hill, NY, 1993, ISBN: 0-07-028400-8.

13

Handbook of Industrial Water Treatment, http://www.gewater.com/handbook/index.jsp.

14

J.C. Dillon, P.B. Desch, T.S. Lai, “The Nalco Guide to Boiler Failure Analysis”, Nalco Chemical Company 2nd edition, McGraw-Hill, NY, 2011, ISBN: 9780071743006.

15

ASTM G63, Evaluating Nonmetallic Materials for Oxygen Service, American Society for Testing and Materials, West Conshohocken, PA, October 2015.

16

ASTM G94, Evaluating Metals for Oxygen Service, American Society for Testing and Materials, May 1, 2022.

17

F. Dabosi, G. Beranger, B. Baroux «Corrosion Localisée», Editeurs Scientifiques, Les éditions de physique, 1994. ISBN: 2-86883-240-7.

18

Dimosthenis Manitsas, Joel Andersson, Hot Cracking Mechanisms in Welding Metallurgy: A Review of Theoretical Approaches, MATEC Web of Conferences 188, 03018 (2018, ICEAF-V 2018), https://doi.org/10.1051/ matecconf/201818803018.

19

EFC 16: Guidelines On Materials Requirements For Carbon and Low Alloy Steels For H2S-Containing Environments in Oil and Gas Production.

20

NACE TM0177-2016: Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking and Stress Corrosion Cracking in H2S Environments.

30 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3. Specific damage mechanisms in E & P activities 3.3.1.

CO2 Corrosion (DM#P1)

3.3.1.1. Description of the damage “CO2 (or sweet) corrosion” of oil production equipment can be a localized or general corrosion damage. It can affect all production equipment made of carbon steel (excluding stainless steels and alloyed materials) in contact with water containing dissolved CO2 [1 to 4]. Depending on water composition and various environmental parameters such as temperature and pressure, average CO2 corrosion rates can reach up to 5 to 10 mm/year, but they may also remain quite negligible ( 1.0 MPa); however, the simultaneous presence of alkaline anions such as bicarbonates can maintain the pH at higher levels, up to 6 to 6.5 [3, 4]. It is particularly within this high pH range that CO2 corrosion can be negligible even though the gas may contain several percent CO2 and total pressures of at least 5.0 to 10.0 MPa; • The organic acid content (mainly acetic acid) is also an important factor [4], given that it is indeed the acetic acid content at the pH of the in-situ

3 – Description of Damage Mechanisms

31

water, and not the total acetates content measured in the water in analytical conditions (most of the acetates are dissociated into anions when the pH of the water is higher than about 4.7). These organic acids influence CO2 corrosion through two complementary effects: ○ They directly contribute to the corrosion cathodic reaction, by “providing” additional protons to the surface through a buffer effect, ○ They affect the precipitation of a corrosion deposit on the surface, in that while iron carbonate (i.e., the product of the corrosion reaction with CO2) is not very soluble, iron acetate is fully soluble. For this reason, the presence of an organic acid is considered to be one of the triggering factors of a rapid localized corrosion, • Finally, CO2 partial pressure is a less significant factor, because even though it may reduce the pH and contribute the cathodic current supply, its effect is also counteracted by the water composition itself. So, in practice, the amount of corrosion observed can be major or minor, for the same amount of CO2; • The effect of the temperature is also a sensitive, but not decisive factor insofar as it has a dual role: ○ On one hand, it increases the thermally activated kinetics in corrosion reactions, ○ On the other hand, it reduces the solubility of iron carbonate, thereby allowing the saturation at the contact to be reached more quickly, • Flow rate has a varied role which is therefore not necessarily essential: ○ Agitation related to a rapid flow rate promotes mass transfers at the metal surface. This may enhance corrosion reactions affected by diffusion and hinder corrosion deposits that form on the surface through evacuation (Fe++, HCO3–), ○ Conversely, rapid flow rate can reduce water wetting when the water-cut is low (several % for example). It can also reduce the contact with water to that of a thin film (low Volume / Surface ratio), which would be less corrosive than full immersion.

Figure 5. – The main factors of CO2 corrosion.

32 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.1.4. Impacted units or equipment The equipment in producer wells and transport pipelines is especially affected by CO2 corrosion. In particular, the low flow velocities in the transport lines favor water separation, thus systematic water wetting even at low water content, whereas a vertical well would be slightly less “water wet”. Gas-cooled heat exchangers, in which an acidic corrosive water condensation occurs, are also particularly affected by CO2 corrosion: the coldest zones, on which most of the condensation takes place, are therefore the best candidates for corrosion. Finally, any production facility in contact with CO2-containing water is potentially sensitive to this type of corrosion since such water is fairly acidic and corrosive. On the other hand, installations in contact with dry or nearly dry gases, i.e., not likely to induce significant water condensation on the wall or an accumulation of water at any retention point, are not affected by this type of corrosion.

3.3.1.5. Aspect or morphology of the damage CO2 corrosion has widely varying aspects depending on environmental conditions, from nearly generalized corrosion with a smooth base (figure 6), to very localized corrosion (figure 9). A so-called “mesa-type corrosion” morphology with a straight edge and a flat bottom is common (somewhat like moon craters). Gradual coalescence of the craters is sometimes observed, resulting in a quasigeneralized corrosion aspect rather than the localized corrosion aspect it had at the start (figure 7). “Preferential corrosion of welds” (figure 8) is also a special form of CO2 corrosion, for which the weld area is the most active area of localized corrosion.

Figure 6. – CO2 corrosion of production tubing, with coalescence of craters.

Figure 7. – CO2 corrosion at the gas cooler outlet, ~ 3% CO2, 40 °C, ~ 7.0 MPa.

3 – Description of Damage Mechanisms

33

 

Figure 8. – Preferential corrosion of a weld – a particular and highly localized form of CO2 corrosion.

Figure 9. – Localized CO2 corrosion with protruding corrosion deposit in a gas well.

3.3.1.6. Prevention / Protection There are basically 4 modes of prevention: 1. Gas or oil dehydration gives highly satisfactory results whatever the CO2 content and partial pressure, provided there is no accumulation point (low points, dead legs, cold condensation zones); 2. Injection of film-forming corrosion inhibitors, most often continuously, or occasionally by “batch” treatment; 3. Use of a pH stabilizer – a chemical that increases the pH of the produced water to about pH 6.2 - 6.5. Whatever product is used (MDEA, NaOH, KOH, Na2CO3, etc.) this treatment finally consists in increasing the bicarbonate concentration in the water, which favors the precipitation of a protective iron carbonate corrosion layer. Provided the water does not contain any Ca++ or Mg++ precipitating cations, this solution has largely proven its effectiveness in operation; 4. The use of organic or metallic materials resistant to CO2 corrosion. Regarding non-corrodible metallic materials, even martensitic stainless steels with minor amounts of alloying elements such as 9Cr-1Mo or 13Cr (X20C13) already offer satisfactory resistance to CO2 corrosion, at least up to 150 °C and several MPa of CO2 partial pressure, and at water salinity values of more than 100 g/L. Because of their strong mechanical characteristics and their low weldability, these materials are used essentially in wells, and assembled by screwing. For weldable equipment (surface pipes, vessels) stainless steels with higher concentrations of alloying elements are used, and these offer a wider operating range in term of CO2 corrosiveness. Although the design service limits of 9Cr-1Mo and 13Cr martensitic stainless steels are currently determined in the laboratory on the basis of the limits given above, their actual service limits are still poorly known, because the actual service conditions involve multiphasic mixtures (oil + gas + water) and flow conditions that

34 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

generally extend the limits of use beyond those measured in the laboratory, under exclusive exposure to water under stagnant conditions. The 3 factors most likely to affect the usability of 13Cr martensitic stainless are: 1. The simultaneous presence of H2S in the fluid, even a few tens of ppm mol: the presence of H2S can induce both SSC (DM#2), i.e., very rapid sulfide stress cracking of these steels, and affect the passive layer of these stainless steels having a low chromium content; 2. Very high CO2 partial pressures corresponding to processing of gases containing more than 20-30% CO2, or to CO2 injection at high pressures (> 3.0 - 5.0 MPa) with the simultaneous presence of water; 3. Simultaneous presence (even temporary and accidental) of dissolved oxygen: these stainless steels are extremely sensitive to minor traces of dissolved oxygen, especially if the production water contains several tens of g/L of chloride ions.

3.3.1.7. Inspection and monitoring • Corrosion monitoring: coupons, corrosion probes, regular thickness measurements on selected areas; • Periodic monitoring of preventive chemical treatments: regular thickness measurements on selected areas associated with the monitoring of chemical injections and of residual concentrations in the treated water (e.g., pH measurements or residual corrosion inhibitor concentrations); • Dehydration monitoring: residual water content on liquid hydrocarbons, periodic measurement of gas dew point; • Detection and monitoring by inspection: ○ Vessels, tanks: Visual inspections and thickness measurements, ○ Process lines: visual inspection when disassembling, and periodic thickness measurements, ○ Pipelines: in-line inspections by Intelligent Pigging.

3.3.1.8. Associated mechanisms “Preferential Welding Corrosion” (PWC), “Under Deposit Corrosion” (UDC), DM#P6, Top of Line Corrosion (DM#P3) are special types and locations of CO2 Corrosion, or of H2S + CO2 Corrosion (weight loss corrosion), if H2S is also present in enough quantities.

3.3.1.9. References 1

Burke P.A., Asphahani AI., Wright BS., “Advances in CO2 corrosion” vol. 2, ISBN: 0915567156, NACE, Houston, Tx, 1985.

2

Simon-Thomas MJJ., Loyless JC., “CO2 Corrosion of Gas-Lifted oil production. Correlation of prediction & field experience”, paper n° 79, CORROSION/1993 Conference, NACE International.

3 – Description of Damage Mechanisms

35

3

MR Bonis, JL Crolet, “Basics of the prediction of the risks of CO2 corrosion in oil and gas wells”, paper n° 466, CORROSION/1989 Conference, NACE International.

4

JL Crolet, MR Bonis, “The very nature of the CO2 corrosion of steels in oil and gas wells, and the corresponding mechanisms”, Oil & Gas European Magazine (1984) 10, n° 2, pp. 68-76.

5

Greenwell, H.E., “Studies on Water Dependent Corrosion in Sweet Oil Wells”, Corrosion, Vol 9, n° 9, Sept 1953, pp. 307 - 312.

3.3.2.

H2S+CO2 Corrosion (weight loss corrosion) (DM#P2)

This chapter replaces damage mechanism DM#13 in oil production facilities: “Sour water corrosion (acidic)” covered in document API RP 571. This section in the API document only covers the contribution of H2S to corrosion in water systems downstream of the refining processes, at relatively low pressures and temperatures, but including possible acidic or basic contaminants, oxygen ingress, etc. Production facilities are quite varied (wells and pipelines) and are exposed to mixtures of CO2 and H2S, to pressures of up to several tens of MPa, temperatures of more than 200 °C, and highly diverse gas-oil-water mixtures. The type of damage covered in this chapter is always designated as “H2S + CO2 Corrosion (weight loss corrosion)”. Comment: This form of corrosion is sometimes referred to simply as “H2S Corrosion”. We chose to avoid this term for 2 main reasons: • The term is also commonly used to refer to Sulfide Stress Cracking (SSC) (DM#02); • In oil production fluids, H2S is almost never found without CO2: this type of corrosion is therefore not specific to the sole presence of H2S, but to the simultaneous presence of both acid gases.

3.3.2.1. Description of the damage The H2S + CO2 Corrosion (weight loss corrosion) mechanism covered here concerns only damage mechanisms caused by generalized or localized corrosion by craters, therefore involving significant weight loss. It does not cover: • All forms of corrosion cracking induced by the presence of H2S (DM#02); • H2 / H2S corrosion at high temperature (DM#04). H2S + CO2 Corrosion (weight loss corrosion) potentially affects the same oil production equipment as “CO2 Corrosion” (DM#P1) when the H2S in the produced fluid is in high enough concentrations so that CO2 corrosion mechanisms no longer apply. Concerning the expression “high enough concentrations”, B. Pots [1] defined a PH2S vs PCO2 diagram with 3 domains (sweet CO2, mixed CO2 – H2S and H2S sour corrosion regimes), that are illustrated in an equivalent way in figure 10   versus

36 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

either the H2S/CO2 or the CO2/H2S ratio measured in the associated gas. The limits between these 3 domains are defined respectively for H2S/CO2 ratios of 0.002 and 0.05, or CO2/H2S ratio of 500 and 20. Between these two boundaries, the authors consider that the so-called “mixed domain” is poorly defined.

Sweet CO2 Corrosion %CO2/ %H2S

1000

Mixed H2S – CO2 Corrosion

Sour H2S + CO2 Corrosion

500

100

20

10

1

0.001 0.002

0.01

0.05

0.1

1

%H2S/ %CO2

Figure 10.  –  Sweet vs. Sour Corrosion Domains, adapted from B. Pots & al. [1].

Comment: the so-called “H2S sour domain” by B. Pots [1] is the one corresponding to “H2S + CO2 Corrosion (weight loss corrosion)” discussed in this section. A more recent publication [2] uses a similar approach based on the following terms: • The specific H2S + CO2 Corrosion (weight loss corrosion) mechanisms and prediction criteria are understood for an H2S/CO2 concentration ratio of ≥ 0.05: this is equivalent to the previous PCO2/ PH2S ≤ 20 criterion; • The CO2 mechanisms and criteria formally apply whenever the 1st corrosion product likely to precipitate is iron carbonate. Knowing that the solubility of iron sulfide is much lower than that of iron carbonate, the transition occurs when the H2S / CO2 ratio is about 10–3 to 10–4 (this ratio varies depending on the temperature and type of iron sulfide forming), i.e., PCO2/ PH2S ratio ≥ 1000 to 10000. Rather than a set value of 500, this publication uses a ratio calculated from solubility equilibria; • Between these 2 values, in the so-called “Mixed H2S + CO2 regime” in figure 10, it is considered that even if the corrosion mechanism is no longer CO2 corrosion (DM#P1) as there is a likely precipitation of iron sulfide, the most realistic prediction criteria are those that are relevant to the CO2 corrosion mechanism. This is therefore a “default choice” because there is no specific explanatory and predictive model for this intermediate domain. Even though the 2 publications agree on an H2S / CO2 concentration ratio of ≥ 0.05 (or CO2/H2S ≤ 20) to define the domain of H2S + CO2 Corrosion (weight loss corrosion), this concentration ratio is currently only a rule of thumb, in the form of a simple, but yet approximate and not definitive, criterion.

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The main characteristics of H2S + CO2 Corrosion (weight loss corrosion) are as follows [2]: • H2S dissolved in water is an acid, like CO2. Under comparable partial pressures their acidifying power is very close; • As for CO2 corrosion, H2S +CO2 corrosion in production facilities occurs within a pH range of about 3 to 7, and between pH 4 and pH 5.5 for most cases; • H2S + CO2 Corrosion (weight loss corrosion) is often significantly lower than CO2 corrosion alone, at a ratio of at least 1/10th in comparable pressure, temperature, pH, flow rate, etc. conditions; • However, there are cases in which such corrosion is significant (0.5 to 3 mm/ year) and, especially, some extreme cases of highly localized corrosion propagating at more than 10 mm/year; • Due to the very low solubility of iron sulfides involved in corrosion, iron sulfide precipitation almost always occurs on the surface of the metal in contact with the H2S containing water; • It is the nature of the iron sulfide deposit (protective or non-protective) which is the most determining factor of the different severities of this abovementioned corrosion. Practical experience shows that in the presence of H2S, generalized corrosion is very rare, except erosion-corrosion under high flow velocities (DM#P5). The special conditions giving rise to localized corrosion are those being problematical for oil production facilities: these conditions are detailed in a next section. When there are no localized corrosion, oil or gas-oil production facilities have lasted several decades without showing any signs of significant problems, despite high concentrations of CO2 and H2S (> 5 - 10% of both acid gases).

3.3.2.2. Impacted materials Weight loss corrosion is a gradual process that concerns carbon steel and low-alloy steels. H2S dissolved in water may also corrode certain stainless steels, but the mechanisms involved are of a different type and therefore are not covered in this section.

3.3.2.3. Critical factors The critical factors define the potential occurrence of localized corrosion introduced above. No fully descriptive mechanism reaches a consensus among the corrosion community. On the other hand, there is a rather general consensus concerning several critical factors [2]: • Deposition of liquid or solid sulfur, known to induce rapid localized corrosion (Low-temperature sulfur corrosion, DM#P8); • Oxygen ingress, regular or even accidental: preventing such entries is essential for installations that treat H2S-containing fluids;

38 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

• The deposition of iron sulfide particles: this is an important factor in the initiation and stabilization of localized corrosion. This situation is encountered particularly in pipelines in which fluids are conveyed at low flow rates, or even more so in dead legs and low points in the process piping; • The possibility of microbiologically induced corrosion due to significant water contamination: such corrosion can contribute to initiating the damage, whose propagation is then favored by the presence of H2S - CO2 and iron sulfide on the metal surface; • There are cases where insufficient inhibition may have caused corrosion to initiate in conditions that favored its propagation, owing to the presence of H2S and iron sulfide. In general, operating with sufficiently high flow velocities is one of the best ways of controlling H2S + CO2 Corrosion (weight loss corrosion). The flow rates should typically be within the following limits: • 1.5 to 5 m/s for a liquid fluid; • 5 to 15 m/s for a wet gas at a pressure of 5 to 15 MPa. Conversely, irregular operations with periodic shutdowns, low points and dead legs, and low flow rates are unfavorable factors, as is the ingress of “parasitic fluids”, particularly those that are oxidizing. In gas production fields, or in gas treatment processes, H2S + CO2 Corrosion (weight loss corrosion) is often minor in the sole presence of water condensation (i.e. low water volumes and salinity), provided the critical conditions listed above are not present. On the other hand, such corrosion has often been observed to be more serious (involving localized corrosion) in the event of produced reservoir water, which is often significantly salty. Although the primary cause of this aggravated corrosion has sometimes been ascribed to salinity, or to chloride ions alone, it is now considered to be a more complex, multi-factorial effect, whereas no direct chloriderelated effect has been demonstrated: 1. Modification of flow conditions due to produced reservoir water; 2. Modification of the pH, which induces a modification in the resulting iron sulfides; 3. Greater galvanic contribution of the iron sulfides, due to the increased salinity; 4. Contribution of divalent cations (particularly calcium) to the iron sulfide deposited on the surface, etc. Finally, whatever the exact causes, the incipient occurrence of reservoir water in any equipment is an alarm signal which must be factored into a corrosion prevention and monitoring program.

3.3.2.4. Impacted units or equipment All production equipment in contact with wet CO2+ H2S containing fluids may be potentially impacted (producing wells, pipelines, and fluid treatment facilities).

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This most seriously concerns equipment in contact with reservoir water. Conversely, H2S + CO2 Corrosion (weight loss corrosion) is generally very minor in gas production plants (wells, pipelines, and pipes) where the flow rates are high enough to induce an annular-mist flow. Conversely, rapid failures are observed in the low points of pipelines that convey slow fluids, in zones where water and solid particles can accumulate [4]. Therefore, many gas wells that produce only condensate water and subjected to annular flow have average lifetimes of 15 to 25 years [4]. On the other hand, more severe corrosion is generally observed in the lower part of the well, when the flow velocity is too low to be able to transport the interstitial water produced from the pores of the reservoir, and which is not yet diluted by the water condensing in the upper part of the well. Abundant iron sulfide deposits can then clog the inner diameter of the production tubing [5, 6]. Finally, the greatest risk concerns facilities in which solid sulfur precipitation is likely to occur, especially in the presence of water: localized corrosion rates > 10 mm/year may then occur [3] see DM#P8.

3.3.2.5. Aspect or morphology of the damage Figures 11 and 12 below illustrate some aspects of H2S + CO2 Corrosion (weight loss corrosion).

Figure 11.  –  Severe localized corrosion of produced water pipes contaminated by oxygen ingress.

Figure 12.  –  Corrosion associated with a thick iron sulfide deposit at the bottom of a gas well [5].

40 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.2.6. Prevention / Protection As with CO2 corrosion, corrosion inhibitors are the most commonly used solution for preventing H2S + CO2 Corrosion (weight loss corrosion) on steel equipment. They are used particularly to protect pipelines and separation facilities. On the other hand, they are seldom used to protect production wells (requires downhole injection) or to protect gas compression units. In some cases, corrosion can also be prevented by eliminating enough quantity of water, to avoid condensation (in the gas phase) or separation (in the liquid phase) of free water in contact with metal surfaces. As indicated in section 3.3.2.3, maintaining the flow velocity at enough level is another means of limiting corrosion, provided the flow rate can be controlled. The specific aim is to avoid stagnant water and the accumulation of solid particles through a sufficiently turbulent flow regime. Finally, the use of stainless-steel materials is the most effective preventive measure, provided the selected material is well suited to all internal and external environment conditions. The main limitation to this choice is that, compared to stainless steel materials used in the sole presence of CO2, materials resistant to different forms of Sulfide stress cracking (SSC) are richer in alloying elements, and therefore much more expensive. The operating limitations of H2S-resistant metallic materials are essentially defined in document NACE MR0175/ISO 15156-3 [7] and can be briefly summarized as follows: • Martensitic stainless steels are highly sensitive to Sulfide Stress Cracking (DM#02), and therefore can only be used in well equipment at H2S concentrations not exceeding several tens to several hundred ppm in the gas, depending on the maximum operating pressure. This operating range decreases with increasing chloride content in the water, because of the negative impact of chlorides on the resistance of the passive layer; • The usual austenitic steels (300 series) also have a narrow operating range in the presence of chlorides, even though the range is much broader in fresh water; • Duplex stainless steels also offer some resistance to H2S (typically at partial pressures of 10 to 50 kPa) in chloride-based environments, however for cold-worked materials requiring superior mechanical properties the limits of use are much more stringent than for annealed materials; • As a result, resistance to high H2S contents, high pressures, and high temperatures require highly alloyed stainless steels or nickel alloys, therefore very noble, expensive materials. In addition to metallic materials, various composite materials are gradually finding a niche in the market, particularly in the areas of pressure, temperature, and corrosive fluids. Finally, the high cost of non-corrodible metal solutions is leaving enough room for the use of low-alloy steels, combined with the injection of corrosion inhibitors.

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3.3.2.7. Inspection and monitoring Monitoring H2S + CO2 Corrosion (weight loss corrosion) uses methods that are quite comparable to those of CO2 corrosion monitoring, namely a combination of corrosion coupons and corrosion probes, chemical analyses, periodic thickness measurements and, especially, the monitoring of corrosion inhibitor treatments, where necessary. The only tools specific to H2S monitoring are sensors for measuring hydrogen output on the external surfaces of pipes or equipment: considering that H2S promotes the penetration of hydrogen related to corrosion of the inner surface and that part of this hydrogen appears on the outer surface after penetrating through the metal wall, a relationship related to corrosion can be drawn between the output flow rate, measured by specific sensors, and the input flow rate. As regards inspection, acoustic emission is an effective means of monitoring the propagation of cracks as soon as they are observed. This inspection means is particularly suitable for progressive cracking (HIC, SWC) but much less for SSC cracking, in which the crack is likely to emerge before monitoring is implemented.

3.3.2.8. Associated mechanisms Sour Water Corrosion (acidic) (DM#13) Top of Line Corrosion (DM#P3): There is a form of “Top of line corrosion” specific to H2S containing gases, which differs from the Top of line corrosion that occurs in absence of H2S.

3.3.2.9. References 1

B. Pots, et al “Improvements on the de Waard – Milliams Corrosion Prediction and Applications to Corrosion management”, paper n° 02235, Corrosion/2002 Conference, NACE International.

2

M. Bonis, M Girgis, K. Goerz, R MacDonald, “Weight Loss Corrosion with H2S: Using Past Operations for Designing future Facilities”, paper n° 06122, Corrosion/2006 Conference, NACE International.

3

M. Bonis, R. MacDonald, “H2S+CO2 corrosion: Additional learnings from field experience”, paper n° 5718, Corrosion/2015 Conference, NACE International.

4

N.N. Bich, K. Goerz, “Caroline Pipeline Failure: Findings on Corrosion Mechanisms in Wet Sour Gas Systems Containing Significant CO2”, paper n° 26, Corrosion/1996 Conference, NACE International.

5

J.  I.  Al-Tammar et al, “Saudi Aramco Downhole Corrosion/ Scaling Operational Experience and Challenges in HP/HT Gas Condensate Producers”, paper n° 169618, SPE Conference, Aberdeen, 12-13/05/2014.

42 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

6

S.N. Smith, R.S. Palakapati, “Thirty years of Downhole Corrosion Experience at Big Escambia Creek: Corrosion Mechanisms and Inhibition”, paper n° 5718, Corrosion/2015 Conference, NACE International.

7

NACE MR0175/ISO 15156-3, Petroleum and natural gas industries — Materials for use in H2S-containing environments in oil and gas production — Part 3: Cracking-resistant CRAs (corrosion-resistant alloys) and other alloys, International Standard, 2015.

3.3.3.

Top of Line Corrosion (DM#P3)

3.3.3.1. Description of the damage Top of line corrosion (TLC) is a particular form of CO2 or H2S + CO2 corrosion that affects the upper area of wet gas pipelines where water condensation can occur without contacting the produced water in the lower part of the pipeline. Depending on the case, this type of corrosion may be limited to just the top part of the pipeline (in a location of about 10:00 to 2:00), whereas in other cases it may extend over almost the entire area in contact with the gas, i.e., from about 8:00 to 4:00.

3.3.3.2. Impacted materials Only carbon and low alloyed steels are sensitive to this form of corrosion.

3.3.3.3. Critical factors In practice there are two forms of TLC that do not develop through the same mechanisms and therefore are not affected by the same critical factors: TLC CO2 (Sweet TLC): This form occurs in conditions where H2S is absent, or its concentration is low enough that the developing corrosion deposit is essentially iron carbonate. Such conditions are defined as “sweet” and “mixed” in figure 10, section 3.3.1.3. The critical factors are: 1. The Water Condensation Rate (WCR) on the metal wall, usually expressed in g/m2.s. Sweet TLC corrosion is commonly observed to occur over a “critical condensation rate”; it is quite negligible below this rate of condensation. Values in the range of 0.05 to 0.2 g/m2.s are usually indicated [1,2]. The WCR depends on: a. The temperature of the gas in the pipeline, b. The temperature and thermal conductivity of the external medium (water, soil, air), c. Any thermal insulation applied to the outer surface of the pipeline to reduce the rate of condensation, 2. The corrosive nature of condensing water, which is essentially determined by: a. The temperature of the gas,

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b. The CO2 partial pressure, c. The concentration of acetic acid in the gas and in the condensing water [3], 3. The flow regime: TLC occurs only when the condensing water is not significantly affected by any component in the produced fluid itself (which is often less acidic and treated with a corrosion inhibitor). In this respect, TLC is observed only in stratified flow regimes. The basic “sweet TLC” mechanism is that of characteristic CO2 corrosion, which occurs when acidic water (due to the presence of CO2 and potentially of acetic acid) condenses but is not inhibited. Whether or not “sweet TLC” develops ultimately depends on who wins the competition between: – The supply of acidic and naturally corrosive condensing water; – The partial neutralization, the iron carbonate saturation and the formation of a protective corrosion deposit that reduces corrosion. Corrosion wins at high water condensation rates, as the concentration of the corrosion product is never high enough to provide satisfactory protection. Conversely, at low condensation rates, corrosion product saturation is rapidly reached and quickly provides efficient protection. TLC H2S (Sour TLC): This form of TLC is seldom encountered [4, 5, 6], in conditions where the H2S concentration is high enough (“Sour’’ domain in figure 10, section 3.3.2.1) that iron sulfide forms rapidly and is the only corrosion deposit. This form of TLC develops through mechanisms that are totally different from those responsible for “sweet TLC”. The notion of critical water condensation rate does not exist in sour TLC: this type of TLC is observed even at very low water condensation rates, even lower than 0.001 g/m2.s [6], where Sweet TLC would be negligible in the absence of H2S. The difference between “Sweet TLC” and “Sour TLC” lies in the fact that iron sulfide always reaches its saturation level very quickly (owing to the very low solubility of iron sulfide) whereas iron carbonate is more soluble, so it reaches its saturation level more slowly. On the other hand, iron sulfide tends to be porous and does not adhere very easily at moderate temperatures, whereby the greater possibility of corrosion, whereas it is dense and forms a protective layer at higher temperatures (> 40–50 °C), resulting in minor sour TLC. Presumably, regular injection of methanol into the gas promotes “sour TLC”, even though the related mechanism is not clearly established [4]. The main critical factors in this case are: • Low temperatures – lower than 40–50 °C, favorable to the formation of an iron sulfide deposit that offers little protection; • Low flow velocity: < 2–4 m/s, minimizing any transport of liquid droplets to the upper part [5, 7]; • The adverse effect of methanol [4, 5].

44 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.3.4. Impacted units or equipment Top of the Line Corrosion concerns mainly wet-gas pipelines that operate in stratified flow regime. Even though it may not be designated as TLC, it can be also encountered in the upper parts of separators and tanks subjected to water condensation, in the tubes of coolers/condensers and on tank ceilings. Cold spots such as taps, dead legs, anodes, apparent areas of buried pipelines... are singular areas where “sweet TLC” can occur.

3.3.3.5. Aspect or morphology of the damage The following morphologies are usually encountered: – Crater corrosion, usually with rather close craters (10 to 20mm in diameter) in the upper parts where the flow velocity of the condensate water is low or even nil; – Nearly generalized, uniform corrosion on the sides, where the condensate water trickles down (see figure 13 below).

Figure 13.  –  Case of sweet TLC combining localized corrosion at the top and uniform on the sides [1].

Sweet TLC usually develops at rates of 0.5 to 2 - 3 mm/year depending on the internal temperature, the condensation rate, and the corrosiveness of the condensate water. A corrosion rate of about 10 to 20% of the “potential corrosiveness” of the produced water transported (i.e., the instantaneous corrosion rate before the formation of any corrosion deposit) represents a realistic order of magnitude for the rate of “Sweet TLC” development [8].

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3.3.3.6. Prevention / Protection Several measures can be applied to combat TLC; they differ according to operating conditions, cost, and acceptable operating constraints. In some cases, a preventive strategy can combine several modes: 1. Use a high corrosion allowance (6 to 10 mm), good for the entire expected lifetime: this amount to accepting the occurrence of TLC, provided it is moderate or not permanent; 2. Keep the condensation rate below critical, using external heat insulation, burying, gas cooling before entering pipeline, etc.: this solution is suitable only for “Sweet TLC” as “Sour TLC” preferentially occurs at moderate temperatures, so even at very low condensation rates. When implementing such solutions, avoid any cold spot (dead legs, anodes, valves, upheaval buckling, thermal bridges, etc.); 3. Use non-corrodible materials, at least in the high-condensation part. This non-corrodible section will then provide a cooling function, beyond which TLC will be low; 4. Inhibit TLC using suitable chemicals (periodic batch treatment using concentrated inhibitor, using “Spray Pigs” [9], volatile inhibitors [10]); 5. Make sure the gas flow rate is high enough so that the produced fluid in the lower part can modify the condensing water on top (inhibitor supply, pH increase), either by operating in an annular or slug flow regime, or by sufficient transport of droplets to the upper wall.

3.3.3.7. Inspection and monitoring TLC monitoring in pipelines essentially involves periodic inspections by intelligent pigging. There is a specific TLC sensor: the “TLC cooled probe” [10], which is simply an ER resistance probe. It works by deliberate cooling using a flow of air or an external liquid, to promote TLC on the probe surface. Since TLC is intentionally forced to develop on this sensor, it cannot be used to detect the occurrence of this corrosion in the monitored pipeline. It can, on the other hand, make it possible to monitor the effectiveness of a treatment applied upstream, for example when applying a volatile inhibitor.

3.3.3.8. Associated mechanisms CO2 Corrosion (DM#P1), for Sweet TLC H2S + CO2 Corrosion (weight loss corrosion) (DM#P2), for Sour TLC.

46 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.3.9. References 1

Y.M. Gunaltun, D. Supriyatman, A. Jamaludin, “Top of line corrosion in multiphase gas lines- A case history”, paper n° 36, Corrosion /1999 Conference, NACE International.

2

F. Vitse, Khairul Alam, Y.M. Gunaltun, D. Larrey, P. Duchet Suchaux, “Semiempirical model for prediction of the top-of-the-line corrosion risk”, paper n° 02245, Corrosion/2002 Conference, NACE International.

3

C. Mendez, M. Singer, S. Nešić, Y. Gunaltun, M. Joosten, Y. Sun, P. Gabetta, “Effect of acetic acid, pH and MEG on the CO2 Top of line corrosion”, paper n° 05278, CORROSION/2005 Conference, NACE International.

4

NN. Bich, KE Szklarz, “Crossfield Corrosion experience”, paper n° 196, CORROSION/1988 Conference, NACE International.

5

R. Paillassa, M. Dieumegard, M. Estavoyer, “Corrosion control in the Gas gathering system at Lacq sour gas field”, 2nd International Congress on Metallic Corrosion, NACE, New York, 1963, pp. 410-417.

6

DV Pugh, et al. “Top of line corrosion Mechanism for Sour Wet Gas Pipelines”, paper n° 09285, CORROSION/2009 Conference, NACE International.

7

M. Bonis, R. MacDonald, “H2S+CO2 corrosion: Additional Learnings from Field Experience”, paper n° 5718, CORROSION/2015 Conference, NACE International.

8

C. de Waard, U. Lotz, “Prediction of CO2 Corrosion of Carbon Steel”, paper n° 69, CORROSION/1993 Conference, NACE International.

9

Y. Gunaltun, L. Payne, “A new technique for the control of top of line corrosion: TLCC-PIG”, paper n° 03344, Corrosion /2003 Conference, NACE International.

10

S. Punpruk, M. Thammachart, Y. Gunaltun, “Field testing of volatile corrosion inhibitors and evaluation of batch treatment efficiency by cooled probe”, paper n° 10096, Corrosion /2010 Conference, NACE International.

11

DF Ho-Chung-Qui, AI Williamson, “Corrosion experiences and inhibition practices in wet sour gas gathering systems”, paper n° 46, CORROSION/1987 Conference, NACE International.

3.3.4.

Microbiologically Induced Corrosion or MIC (DM#P4)

3.3.4.1. Description of the damage Microbiologically Induced Corrosion, commonly referred to as MIC, is the accelerated deterioration of a material due to the presence of a biofilm on its surface. Any surface in a non-sterile environment can be colonized by microorganisms that

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can develop such a biofilm. The biofilm generally consists of several species of bacteria but can also include fungi, algae, and especially various products of their metabolism (proteins, lipids, polysaccharides). Microbiologically Induced Corrosion involves varied mechanisms, reflecting the diversity of microorganisms (and sometimes involves cooperation between several species), of environments and of materials. It is important to understand that Microbiologically Induced Corrosion cannot exist without microorganisms, but also that the presence of microorganisms does not necessarily lead to Microbiologically Induced Corrosion. The combined action of the generated biofilm, the fluid and the environmental conditions must be favorable to the development of this type of corrosion. Despite the diversity of the bacteria and the environments in which they live, all bacteria need water, a source of energy and nutrients to construct and maintain their cellular material (carbon, nitrogen, phosphorus, trace elements etc.) [1]. Bacteria can derive their energy from sunlight or from certain chemical reactions. In the absence of light, microbial metabolism is powered by oxidation and-reduction reactions involving oxygen in an aerobic environment, or other electron acceptors in anaerobic environments. Of all the types of bacteria likely to cause specific corrosion or accelerate the corrosive nature of the environment (for example: acetogenic bacteria, methanogens, reducing nitrogen or thiosulfates), Sulfato-Reducing Bacteria (SRB) have received utmost attention from the oil industry. SRB, which include a wide variety of bacterial families, develop in anaerobic environments, as are almost all oil production environments. They can significantly amplify the corrosiveness of an environment. Various models have been put forward to explain the detrimental effect of SRB on metal. Although the “cathodic depolarization” model has long been cited in microbiological literature, it is sufficiently controversial not to deserve being covered in detail here. The most recent models suggest two mechanisms that may explain the effect of SRBs on metal corrosion. It should be noted that these two mechanisms are not contradictory and can be combined: • The first is a purely chemical mechanism CMIC (Chemical Microbially Influenced Corrosion). It is because the bacterial activity in the biofilm on the metal surface locally produces abundant reducible species (H2S, CO2, other acids), thereby accelerating the corrosion caused by these bacteria [2, 3, 4]. There are many suggestions as to the species generated and the reactions actually involved, but finally, the common notion is this that the bacteria in the biofilm produce a local physical & chemical environment [3, 4] different from that of the mass of volume, which promotes corrosion according to the usual electrochemical mechanisms between the metal and its local environment: the “bacteria generate the environment and the environment generates corrosion!”. Moreover, because of the ferrous ions generated by the corrosion and the simultaneous formation of

48 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

sulfides by sulfate reduction, an iron sulfide deposit is often observed above the MIC craters. When the iron sulfide is deposited on the metal it may produce an additional cathodic surface (because FeS is conductive and nobler than Fe) that promotes corrosion even more. If we include this effect, cathodic reactions ultimately occur both on the surface and on the iron sulfide; • Whereas the first mechanism can be caused by all types of SRB, a second mechanism EMIC (Electrical Microbially Influenced Corrosion) apparently consists in the electronic transport from the metal surface to the bacterial nucleus. Reduction reactions can then occur not only on the metal wall but also in biofilm layers not directly in contact [5]. The steps involved in this electron transfer are still unknown, but this more recently discovered phenomenon is probably relatively widespread. Unlike CMIC, EMIC supposedly generates a depositional layer consisting not only of iron sulfides but also of other chemical species such as iron carbonate. Therefore, the presence of SRB apparently greatly accelerates the degradation of iron in an anaerobic environment. The introduction of oxygen (for example during a production shutdown) in an environment contaminated by bacterial byproducts (H2S, FeS) might further promote corrosion phenomena. An even less expected consequence of bacterial contamination of a metal surface is the phenomenon of “ennoblement” [5]. Ennoblement has been observed on various metallic materials, such as copper alloys, mild steel, or stainless steels. In the presence of bacteria, the corrosion-free potentials of these materials increase, and their rate of corrosion either accelerates or decelerates. Experiments with the Discophora Lepthotrix manganese oxidizing bacteria [6, 7] demonstrate the formation of mineralized manganese compounds deposited on the metal. Among them, MnO2 apparently increases the potential of stainless steel through electrical contact, especially through the reduction of MnO2 to Mn2+. A more generally applied hypothesis is that cathodic reactions are enhanced/ catalyzed by the biofilm or by species deposited on the metal surface, thereby substantially increasing the corrosion potential. Contrary what the term “ennoblement” suggests – an improvement in the corrosion resistance of the material itself – the main outcome, for passive materials, is that the corrosion potential of the material tends to converge with its “pitting potential”. This is due to the increase in corrosiveness of the environment, with the added increased risk of pitting corrosion. The widely used term “ennoblement” is therefore misleading and should therefore be banned. The hypothesis that bacteria produce corrosion-inhibiting substances has also been mentioned [5]. Given the diversity of potential environments, materials, and microbial consortia, it would be very surprising that no protective effect could be found for even one situation. Nevertheless, such a protective effect is rather circumstantial as long as it is neither predictable nor observable in a wide range of conditions: generally speaking, it is safe to consider that microbial contamination has at best a negligible effect, if not a harmful effect on corrosion.

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Finally, Microbiologically Induced Corrosion: • • • •

Absolutely requires the presence of water in contact with the metal; Usually exhibits localized corrosion with hemispherical craters; Is caused by microorganisms developing in a biofilm on the metal surface; Rarely depends only on the bacterial environment: the natural corrosiveness of the fluid (excluding any contamination) has a very significant effect on the importance of the corrosion; • Is considerably related to environmental factors, especially temperature, flow velocity and flow regime, accumulation of deposits...; • Is not currently predicted by any reliable predictive model in oil and gas production. Reference document EFC No. 66 [8] offers a particularly useful synopsis of topics underlying Microbiologically Induced Corrosion, microbial environments, and their characterization by recent methods in genomic molecular microbiology and metabolic measurements.

3.3.4.2. Impacted materials Owing to the predominant use of carbon steel and low alloy steels in oil production, this material is the most widely exposed to the effects of Microbiologically Induced Corrosion. Nevertheless, MIC affects most metallic materials such as stainless steel (300 and 400 series), aluminum alloys, copper alloys and certain nickelbased alloys. Only titanium appears to be immune to the risk of Microbiologically Induced Corrosion in anaerobic or marine environments, but it is subject to biologically induced fouling [9]. In practice, however, the literature reports few cases of significant Microbiologically Induced Corrosion of internal origin on stainless steels, whereas the effect is more frequently reported in immersion in seawater environments due to the serious increase in the corrosion potential, as mentioned in a foregoing chapter.

3.3.4.3. Critical factors Factors such as the condition of the material, the composition of the environment (the chemical composition of the water, the temperature, and the pH) and the types of microorganisms present, have an influence on Microbiologically Induced Corrosion. In addition, the simultaneous presence of different populations can greatly accelerate the corrosion process. Thus, studies of the 1990s demonstrated the harmful effects of thio-sulfate-reducing bacteria [10]. Low flow rates and long residence times in contact with contaminated water (e.g., systems that operate intermittently) also promote considerable microbial growth and an accumulation of sediments that protect the microorganisms from disinfection. The adaptability of the microorganisms that form the biofilm is remarkable, thereby limiting the effectiveness of the corrosion prevention scheme. Thus, some

50 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

SRB strains capable of surviving at temperatures of 104 °C at 100 MPa (in subsurface petroleum geological formations) were isolated, and it was shown that bacterial life occurred in pH ranges from very acidic to very basic [1].

3.3.4.4. Impacted units or equipment For the upstream oil industry, the microorganisms responsible for corrosion may originate in the oil reservoirs themselves, if their temperatures are moderate (less than 80–100 °C). However, they often come from surface waters or sediments, especially industrial water or seawater used in testing, washing... The facilities most affected by corrosion itself are those with the most favorable environmental conditions for microbial activity, i.e., the water injection networks, the oil production networks and produced water treatment networks, and finally cooling water circuits [17]. Oil or water storage tanks are particularly favorable for the development of microorganisms, as they combine all the favorable factors (stagnant water, frequent accumulation of deposits, moderate temperatures...) whereas the treatment possibilities are, on the contrary, difficult, and ineffective (almost impossible to disperse a biocide, shield effect produced by deposits, impossibility of cleaning surfaces outside prolonged shutdowns). Conversely, corrosion is much rarer in gas production plants, except for water treatment units downstream of separation processes. Corrosion is also rarely observed in oil production well tubing’s, even with significant proportions of water: this is certainly due to slug flow regimes that are not conducive to the development of a biofilm.

3.3.4.5. Aspect or morphology of the damage Tubercle formation (figure 14) has been mentioned several times in the literature and is generally considered to be characteristic of underlying localized corrosion, often of bacterial origin. However, such protuberances are not seen in pipes regularly scraped by cleaning tools: the absence of tubercles cannot be considered as a decisive sign. Hemispherical craters a few cm in diameter are often seen on carbon steel or low alloyed steel (figure 15). The craters are sometimes embedded in other craters (figure 16); this is certainly a sign of repeated episodes of development and interruption. It is especially important to note that it is difficult to systematically and unquestionably associate damage morphology and microbial origin: some corrosion morphologies in sterile environments are very similar to those caused by Microbiologically Induced Corrosion. Stainless steels are susceptible to pitting and crevice corrosion in the presence of bacteria, whereas copper alloys can also suffer from localized corrosion with coupled effects (due to the toxicity of their corrosion products, some surface parts are covered by a separate deposit and acquire cathodic behavior). Cases of microbially-induced stress corrosion cracking have also been found in alloyed steels [1]. The presence of bacteria may be responsible for the formation of hydrogen sulfide

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or hydrogen, thereby promoting the penetration of hydrogen into the metal and sulfide stress cracking (DM#02).

Figure 14. – Tubercles removed from carbon steel surfaces in power plants (source: page 188 of Manual of microbial corrosion [9]).

Figure 15. – Microbiologically Induced Corrosion of a mine water raising column (courtesy of: Compagnie Française de Géothermie).

Figure 16.  –  Hemispheric crater morphology caused by severe Microbiologically Induced Corrosion (5 to 15 mm/year) [17].

52 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.4.6. Prevention / Protection Preventive measures against Microbiologically Induced Corrosion include mainly: • Cathodic protection, often combined with cladding, for pressure vessels, tanks, as well as for the external pipeline surfaces; • Non-oxidizing biocides, preferably in combination with periodic pigging to destroy the biofilm and to scrape off any solids accumulating in the pipelines; • Organic oxidizing biocides, such as chlorine bleach, for cooling circuits; • Filtration systems or ultraviolet radiation, in water treatment circuits, for example. As for chemical treatments, the best strategies aim to prevent the formation of the biofilm by means of dispersant chemical formulations (which prevent the adhesion of the biofilm), and where necessary, the use of biocides. There are four main types of products or processes known as “biocides”: • Oxidizing biocides: chlorine, chlorine dioxide, bromine, iodine, ozone, hydrogen peroxide, etc.; • Non-oxidizing biocides: quaternary ammonium, isothiazolinones, glutaraldehyde, etc.; • Biodispersants: acrylate, methacrylate, polycarboxylic acid, etc.; • Physical biocides: UV, electrolytic ionization (Cu, Ag), etc. Although low biocide concentrations are sufficient to significantly reduce the bacterial count in suspension in the water (e.g., 10 to 30 ppm vol commercial glutaraldehyde products for sulfate-reducing bacteria), much higher concentrations are required to eliminate microorganisms present in the biofilm and sediments (200 to 500 ppm of the same products). Therefore, it is usually necessary to combine biocide injection with physical surface treatment (by pigging of pipelines, periodic tank washing, etc.) of the surfaces requiring protection. The flow velocity must also be kept as high as possible to minimize adhering and growth of any developing biofilm. The elimination of dead legs from a network and rapid drying of tested hydro parts also contributes MIC corrosion prevention. Attempted water treatment, based on filtration, focuses on removing organic carbon to obtain biologically stable water, i.e., treated water that does not promote the growth of microorganisms during circulation. The use of treatments such as sludge-blanket digestion or fixed biomass biodegradation (biological filtration), adsorption, membrane ultrafiltration with addition of powdered activated carbon, nanofiltration or reverse osmosis can help reduce dissolved biodegradable organic carbon.

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3.3.4.7. Inspection and monitoring Monitoring the effectiveness of a biocide treatment is usually obtained through biological assays of microorganisms that are both fixed on a surface or in suspension in the liquid. Monitoring microorganisms on the surface is obviously more useful as they are the ones that are responsible for corrosion. However, this is more complex and so usually seldom used. Microbiologically Induced Corrosion probes have also been developed [11]. They help foresee the appearance of localized corrosion. More complex assays involving measurements on genes specific to microbial activity, or even the determination of all in-situ microbial species (by genomic measurements) have been developed in recent years, owing to the significant reduction in the costs of such analyses. However, straightforward, general criteria for evaluating the results are yet to be found. Other indicators such as the reduced efficiency in an exchanger or odors or hydrogen sulfide concentrations are warning signs of the risk of fouling and development of microorganisms.

3.3.4.8. Associated mechanisms Although it is often tempting to ascribe corrosion-related degradation to a single mechanism, Microbiologically Induced Corrosion in oil production facilities is often associated with CO2 corrosion (DM#P1). The two share the oxidative nature of CO2-induced acidity, as well as favorable or unfavorable effects of corrosion deposits that develop on a surface. Experience often shows strong Microbiologically Induced Corrosion when the conditions favorable to CO2 corrosion are met, and vice versa. Microbiologically Induced Corrosion can also be associated with the following mechanisms: • Sulfide Stress Cracking (DM#02), if the material concerned is unsuitable for the service, owing to the H2S formation induced by Microbiologically Induced Corrosion; • Corrosion-Fatigue (DM#43); • Pitting Corrosion of stainless steels (DM#P9); • Crevice Corrosion (DM#P10).

3.3.4.9. References 1

T. R. Jack, Biological corrosion failures, ASM Handbook volume 11: failure analysis and prevention, pp. 1869-1915.

2

D. Enning, J. Garrelfs, Corrosion of iron by sulfate-reducing bacteria: new views of an old problem, Applied and environmental microbiology, p1226 – 1236, February 2014.

54 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3

Crolet JL, From biology and corrosion to microbial corrosion, Oceanologica Acta (1992) 15, n° 1, p. 87-94.

4

Crolet JL, Daumas S., Magot M., Microbial corrosion : régulation du pH par les bactéries sulfato-réductrices, Mat. et Tech. (1992) 80, n° 9-10, p. 71-77.

5

F. Mansfield, C. H. Hsu, Z. Sun, D. Örnek, T. K. Wood, Technical note: ennoblement – a common phenomenon? Corrosion – Vol. 58, n° 3, 2002.

6

X. Shi, R. Avci, Z. Lewandowski, Microbially deposited manganese and iron oxides on passive metals – their chemistry and consequences for materials performance. Corrosion, September 2002.

7

S. Campbell, G. Geesey, Z. Lewandowski, G. Jackson, Influence of the distribution of the manganese-oxidizing bacterium, Lepthoptrix discophora, on ennoblement of 316L stainless Steel, Paper No. 03566, Corrosion 2003 Conference, NACE International.

8

L. Lingen, D. Feron …, “Understanding Microbial corrosion: Fundamentals & Applications”, EFC publication n° 66, Woodhead Publishing, (2014), ISSN 1354-5116.

9

H. A. Videla, Manual of microbial corrosion, CRC Press, 1996, 179-204.

10

X. Campaignolle, X. Caumette, …, “The role of thiosulfate on the microbially induced pitting of carbon steel”, paper n° 273, CORROSION/2016 Conference, NACE International.

11

CEFRACOR, “Monitoring de la Corrosion Interne dans les Industries Pétrolières et Gazières“, EDP Sciences, Paris, France, Copyright © 2016, ISBN: 978-2-7598-1746-7.

12

F. Ropital - Corrosion et dégradation des matériaux métalliques – IFP Publications- 2009.

13

S. Pineau – « Interactions entre les communautés bactériennes et les processus de corrosion accélérée des structures métalliques en environnement marin » - Thèse 2006.

14

A. Franks, S. Egan, C. Holmström, S. James, H. Lappin-Scott, S. Kjelleberg. Inhibition of Fungal Colonization by Pseudoalteromonas tunicate provides a Competitive Advantage during Surface Colonization. 2006. Appl. Environ. Microbiol. 72, 6079–6087.

15

M. Mehanna, R. Basseguy, M.L. Delia, A. Bergel, Role of direct microbial electron transfer in corrosion of steels. 2009. Electrochemistry Communications. 11, Issue 3, 568–571.

16

D. Féron. Comportement des aciers en environnement naturel: cas des aciers inoxydables en eau de mer. 2005. Matériaux & Techniques 93, 43-58.

17

B. Kermani, D. Harrop, “Corrosion & Materials in hydrocarbon Production: A compendium of Operational and Engineering Aspects”, chapter 11, Wiley, ISBN9781119515722, 2019.

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3.3.5.

55

Erosion – Corrosion / Erosion (DM#P5)

3.3.5.1. Description of the damage This damage mechanism description replaces the description of DM#20 in API RP 571. This is because DM#20 includes, under the term “erosion”, a number of mechanisms that are in fact “Erosion-corrosion”, i.e., for which the final damage results in dissolution of the metal by corrosion. This chapter is devoted essentially to erosion-corrosion, which requires the presence of a corrosive fluid, whereas this is not the case for pure erosion, which is only a mechanical effect of the fluid on the metal surface. In oil production, it is considered that there are many more problems related to erosion-corrosion, in the presence of corrosive water, than solely to mechanical “erosion”. Erosion-corrosion is therefore produced by the relative movement on a surface, of a corrosive fluid with or without solid particles. It is promoted by a fluid circulating at a high flow velocity against the metal wall; this reduces the possible protective nature of a corrosion deposit or a corrosion inhibitor, thereby subjecting the metal to the full effect of the natural corrosiveness of the fluid. The presence of suspended solids in the flowing fluid may be a source of erosion corrosion. When solids settle out of the flowing fluid, their harmfulness is altered but not necessarily neutralized. Although the presence of solid particles considerably enhances Erosion-corrosion, it is not essential. If present, the solid particles may be sand from the reservoir, or corrosion products. Conversely, the mechanical erosion of a metal (or abrasion) results from the mechanical action of a fluid, very generally charged with solid particles, whose impact energy allows the progressive removal of this metal, without the need for any corrosive fluid. Thus, a dry gas or a liquid hydrocarbon charged with solid particles and touching a metal under high flow velocities can induce erosion, but not an Erosion-corrosion phenomenon. Finally, in the presence of a corrosive fluid, there is synergy between mechanical erosion and corrosion, their respective rates are added.

3.3.5.2. Impacted materials All so-called “active” materials are susceptible to erosion-corrosion, especially carbon steel and low-alloy steels, metals protected by a thick protective deposit (such as copper alloys). Conversely, materials protected by a “passive layer” such as stainless steels, nickel alloys) show little sensitivity to erosion-corrosion. However, these passive materials are sensitive to purely mechanical erosion by solid particles.

56 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.5.3. Critical factors Several factors play a role in erosion-corrosion, by decreasing order of impact: • The fluid flow rate and velocity of any entrained particles; this determines the mechanical and chemical impact of the fluid on the metal wall. The velocity also favors diffusion of corrosive species from the fluid towards the surface and corrosion products from the surface to the fluid; • The fluid composition, which determines its corrosive nature (presence of water, pH, CO2 partial pressure, etc.), [1, 2, 6, 7, 9, 10]; • The temperature, which affects the corrosiveness of the fluid; • The concentration of solids, if any, as well as their particle size and shape; • The nature of the impacted material; • The fluid density; • The fluid viscosity; • The angle of impact; • The geometry of the impacted component; • The hardness of the impacted material (for a same family of material). The factors of mechanical erosion are essentially the same, apart from those relating to the corrosiveness of the fluid (presence of water, pH, temperature, etc.). For both mechanical erosion and Erosion-corrosion, the mechanical aspect of the movement is important. Friction and wear can also occur as surface mechanical damage (case of pumps). For fluids without solid particles: At current flow velocities used in oil production facilities (generally less than 20 m/s and very rarely above 50 m/s), mechanical erosion does not occur if there are no solid particles. As stated above, this is not the case for erosion-corrosion. If inhibition is the main corrosion prevention measure, the critical flow velocity (with respect to erosion-corrosion) of fluids without particles, is the flow velocity beyond which the effectiveness of the corrosion inhibitor is strongly reduced. It is generally assumed that all inhibitors can accept fluid flow velocities of 15-20 m/s, at least when the fluid phase is predominantly gas. This is because the energy that binds the inhibitor to the metal surface is strong enough to remain much higher than the energy delivered by the fluid flow velocity of 20m/s, thereby inducing protection the metal surface. Some inhibitors have recently been tested at flow velocities of up to 50 m/s and have provided suitable protection. However, for situations where the inhibitor will be exposed to gas flow velocities greater than 15-20 m/s and for liquid flow velocities greater than 5 m/s, representative tests have to be conducted to select and confirm the effectiveness of the inhibitor. The mechanisms by which an inhibitor loses its protective function at high flow velocities remain unclear. The usual claim that the shear stress of the fluid is greater than the adsorption capacity of the inhibitor is increasingly rejected, following results of measurements carried out in 2013 - 2015, [13] at least for cases where solid particles are not present.

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If protection is provided by pH stabilization, the critical Erosion-corrosion velocity is that at which the protective films formed by corrosion products may be damaged. Laboratory tests were carried out on pipelines conveying fluids at water flow velocities up to 5m/s; no damage to the protective films was observed, provided no solid sandy particles are present. Conversely, solid particles are very damaging to corrosion deposits. For corrosion-resistant alloys, where a passive film on the metal surface (e.g., stainless steels) provides protection against corrosion, the fluid flow velocity is not a major factor unless the repassivation has been compromised by the fluid corrosiveness (e.g., at low pH and high chloride content). If the fluid contains low salinity water (e.g., condensed water), the protective film usually forms again during service. For fluids with solid particles: Little work has been done to quantify the effects of erosion-corrosion in systems containing solids, where the system is corrosive, and protection is provided by inhibition. If erosive conditions are quite severe, solid particles can “rip” the inhibitor off the metal surface, even though their energy is not sufficient to erode the surface of the metal itself (mechanical erosion). Although few studies exist that can establish the limiting flow velocities of fluids containing solid particles, oil production operators still indicate this as one of the most critical factors when considering inhibition in high flow velocity conditions. Inhibition cannot be recommended for mean fluid flow velocities greater than 8 - 10 m/s for a wet gas and 3 m/s for a liquid effluent containing solid particles. Solid particles could constitute another adsorption site for the inhibitor, proportionally to their “active surface area”, which could reduce the amount of inhibitor available for covering the metal surfaces. However, there is little support for this explanation, as the particles with a “high active surface area” are clays (10 to 100 m2/g), which are usually fine, softer particles in comparison to very erosive large sand particles, whose “active surface area” is much more moderate (> 100 m/s).

3.3.5.5. Aspect or morphology of the damage Erosion-corrosion causes the appearance of grooves, valleys, undulating surfaces and holes with a characteristic directional aspect. The “horseshoe” shape shown in figure 17, is common in erosion-corrosion. Erosion also has a directional aspect especially related to the fluid flow, very often with a smooth, highly polished surface: see figure 18.

Figure 17.  –  Erosion - corrosion pattern.

Figure 18. – Erosion patterns.

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3.3.5.6. Prevention / Protection Solutions for preventing Erosion-corrosion are summarized in figure 19.

Figure 19.  –  Preventive solutions for erosion-corrosion.

Measures for preventing physical erosion are summarized in figure 20 below. They are quite like those used to prevent Erosion-corrosion, with two exceptions: • The preferred solution consists in selecting hard materials (e.g., tungsten carbide); • Inhibitor treatments are ineffective.

Figure 20.  –  Preventive solutions for mechanical erosion.

60 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Preventive models have been developed to predict Erosion-corrosion rate with and without the presence of solid particles. They may be common CO2 corrosion models that include the effects of flow velocities. The simple model described in API RP 14E [11], formally developed for erosion, can be applied to erosion-corrosion. Predictive models also exist for mechanical erosion (SPPS, University of Tulsa, DNV RP O501 [12]). These models apply to pipes and related accessories (elbows, tees, reductions). On the other hand, modeling areas with strong turbulence (impacts, sharp angles, sizeable reductions, etc.) or very high velocities (chokes) is difficult and not the objective of common models. CFD-type modeling is implemented as an option.

3.3.5.7. Inspection and monitoring Inspection and monitoring of erosion-corrosion and its inhibition are based essentially on the same methods as for CO2 Corrosion (DM#P1) or H2S+CO2 (DM#P2) but include regular thickness measurements in sensitive areas or in those already affected by erosion-corrosion. The second major difference involves sand detection using acoustic sensors; the method is based on detecting the sound emitted when sand particles impact the metal walls. As for other forms of internal corrosion due to thickness loss, visual inspections and thickness measurements are also commonly used.

3.3.5.8. Associated mechanisms Flash Erosion (a form of erosion-corrosion) (DM#20), Cavitation (DM#28).

3.3.5.9. References 1

M. Rudman and H.M. Blackburn, “The Effect of shear thinning behaviour on turbulent pipe flow”, Third International Conference on CFD in the Minerals and Process Industries CSIRO, Melbourne, Australia 10-12 December 2003.

2

Y. M. Ferng, Y. P. Ma, and N. M. Chung (2000) “Application of Local Flow Models in Predicting Distributions of Erosion corrosion Locations”. Corrosion: February 2000, Vol. 56, No. 2, pp. 116-126.

3

S. E. Hernández, S. Hernández, H. Rincón, and J. R. Vera (2002) “FlowInduced Carbon Dioxide and Hydrogen Sulfide Corrosion Studies Using the Dynamic Field Tester in Crude Oil Wells”. Corrosion, October 2002, Vol. 58, No. 10, pp. 881-890.

4

J. R. Shadley, S. A. Shirazi, E. Dayalan, M. Ismail, and E. F. Rybicki (1996) “Erosion-corrosion of a Carbon Steel Elbow in a Carbon Dioxide Environment”. Corrosion: September 1996, Vol. 52, No. 9, pp. 714-723.

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5

G. Liu, D. A. Tree, and M. S. High (1994) “Relationships between Rotating Disk Corrosion Measurements and Corrosion in Pipe Flow”. Corrosion: August 1994, Vol. 50, No. 8, pp. 584-593.

6

B F.M. Pots, E.L.J.A. Hendriksen, J.F. Hollenberg, “What are the Real Influences of Flow on Corrosion?”, NACE-06591, CORROSION 2006, 12-16 March, San Diego, California.

7

John R. Thome, Engineering Data Book III, Wolverine Tube Inc., 2004. Chapter 12, Two-Phase Flow Patterns.

8

D. C. Silverman, “The Rotating Cylinder Electrode for Examining VelocitySensitive Corrosion—A Review”. Corrosion: November 2004, Vol. 60, No. 11, pp. 1003-1023.

9

J. Postlethwaite and S. Nešić. Erosion–Corrosion in Single- and Multiphase Flow. In Uhlig’s Corrosion Handbook, Third Edition, 2011, ISBN: 9780470080320.

10

K.D. Efird. Controlling Flow Effects on Corrosion. In Uhlig’s Corrosion Handbook, Third Edition, 2011, ISBN: 9780470080320.

11

API RP 14E “Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems”, 5th Edition, June 2000.

12

DNV RP O501, Managing sand production and erosion, August 2015 Amended 2021-09.

13

Chapter Author’s Private communication.

3.3.6.

Under Deposit Corrosion (DM#P6)

3.3.6.1. Description of the damage Under deposit corrosion describes localized forms of corrosion that develop beneath or around deposits on the metal’s surface. The following main types of deposits are encountered in the oil industry: • Solid organic products resulting from precipitation reactions in the crude (asphaltenes, paraffins) or from microbiological activity (biofilms); • Inorganic solids originating from the geological formation (sand), or from corrosion reactions (sulfides, oxides, or iron carbonates), or from precipitation reactions in the transported fluid (barium or strontium sulfates, calcium carbonate, etc.); • Or a combination of both. Under deposit corrosion is sometimes associated with MIC (see section 3.3.4), either because the biofilm can constitute a deposit in itself, or because the deposit can play host to a biofilm. Precipitation of solids can be caused by changes in solubility, e.g., degassing which causes an increase in the pH, the presence of cold spots, corrosion products, and

62 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

the formation of colloids by flocculation/coagulation, etc.) and their accumulation due to low flow rates, bends, dead-legs, etc. Deposits may hinder the access of a corrosion inhibitor on the surface requiring protection; they can reduce its adsorption capacity by rapidly corroding the metal underneath [2], or even partly or completely absorb the inhibitor [1], thereby limiting its effectiveness. No single mechanism can sufficiently explain under deposit corrosion. The mechanism(s) involved depend on the conditions to which the facilities are exposed: the type of metal (passivable or not passivable), the type of deposit (inert or reactive), the corrosive promoters present (O2, CO2, H2S, H+, bacteria, etc.). Owing to the high variability of facilities, the mechanisms involved are both highly diverse and very specific: caustic corrosion, acid corrosion involving hydrogen formation or acid phosphates corrosion, in boilers [3,4], corrosion under bitumen deposits in pipes transporting crude oil [1], etc. Under deposit corrosion is sometimes related to crevice corrosion, where the deposit is a barrier to the diffusion of oxygen creating anodic conditions in the zone under the deposit. It can also be simply related to general corrosion, such as when a hygroscopic salt locally produces an aggressive electrolyte attacking the metal precisely under the deposit. The deposit itself can accelerate corrosion, for example by forming a galvanic cell as encountered between iron sulfide deposits and a carbon steel pipe. Finally, the mechanism may seem to follow an initiation period prior to the corrosion propagation stage: a minimum amount of deposits is required to initiate the corrosion processes. In short, under deposit corrosion is not a corrosion mechanism truly speaking, but rather the manifestation of damage caused by a variety of mechanisms – the presence of deposits being the decisive factor. As such it is not necessarily different from the basic mechanisms that trigger corrosion, such as those involved in CO2 Corrosion (DM#P1), H2S + CO2 Corrosion (weight loss corrosion) (DM#P2), Microbiologically Induced Corrosion (DM#P4), Oxygen Induced Corrosion (DM#P7), LowTemperature Sulfur Corrosion (DM#P8), Caustic Corrosion (DM#19), etc.

3.3.6.2. Impacted materials The impacted materials are essentially carbon steels and low-alloy steels but also any metal exposed to more aggressive conditions caused by a confined environment under the deposit, is likely to suffer from accelerated corrosion.

3.3.6.3. Critical factors Design: Any geometry that slows down the fluid and contributes to build-up of deposits in low points is likely to cause under deposit corrosion. So, geometries with sudden changes of direction (baffles, tees, etc.), or geometries that catch particles, such as salient welds, have to be monitored.

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Flow rate: High flow rates usually make it more difficult for suspended deposits to settle, but it may not be the case for products formed by change of chemistry (carbonates). Chemistry of the environment: The ability of the environment to form deposits is of course a decisive factor. Even though the extent of possible deposits has been highlighted above, not all fluids are likely to induce them. The presence of sand, the paraffinic or asphaltenic nature of crude oils and the over-saturated status of the water with respect to carbonates or sulfates are among the most struggling indicators. The environment’s chemistry should be stabilized to reduce corrosion of the structure and consequently, the formation of corrosion products that can build up. Cleaning program: Most installations can become encrusted by a layer of deposits. The maintenance plan often stipulates cleaning to maintain an optimal heat exchange capacity or a reasonable internal diameter. If the deposit is non-protective, then infrequent cleaning increases the time the material is exposed to conditions of under deposit corrosion. Temperature: Excessively high temperatures can accelerate evaporation and contribute to concentrating aggressive species, or even to precipitation, acting as precursors of under deposit corrosion. Shutdowns: These are a good opportunity for suspended particles to decant, and for external agents (mainly oxygen) to contaminate the facilities and promote the precipitation of certain species (in particular, the formation and accumulation of corrosion products). “An ounce of prevention is worth a pound of cure”: An installed deposit can lead to a self-sustaining corrosion cycle, causing even more deposition on the surfaces. Maintaining good operating conditions (high flow rates, regular cleaning, and suitable inhibition) can delay the development of this cycle.

3.3.6.4. Impacted units or equipment Insofar as under deposit corrosion is similar to the basic corrosion mechanisms encountered in E & P, as described in section 3.3.6.1, almost all units are potentially subject to under deposit corrosion, as are cooling water, hot water, and steam production units. It must be noted, however, that under deposit corrosion is seldom explicitly mentioned as the cause of corrosion, given that the contribution of deposits is often intrinsic to most of the basic mechanisms in section 3.3.6.1.

3.3.6.5. Aspect or morphology of the damage For the same reasons as those mentioned above, there are no actual morphologies characteristic of under deposit corrosion, which can be explicitly differentiated from the morphologies of the basic mechanisms mentioned in section 3.3.6.1.

64 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.6.6. Prevention / Protection The following methods are recommended to limit the occurrence of deposits, [2]: • A design that minimizes the areas where solids are likely to accumulate dead legs, no-flow pipes, ducts; • When the local layout of the installation sets limits on the design, the use of internal coating or corrosion-resistant alloys can help prevent such corrosion in areas where deposits are unavoidable (vessels or storage tanks, for example); • Regular cleaning, especially with pigs; • The highest possible flow rate (this solution is rarely possible in oil facilities); • The use of chemical dispersants (scale inhibitors): these chemicals should be used with caution because they can inhibit the formation of a protective film on low-alloy steels.

3.3.6.7. Inspection and monitoring A maintenance plan must be set up. It should indicate the inspection frequency of those parts of the facility where debris is most likely to accumulate (low points, dead legs, etc.), and the points to be monitored which have to be taken into consideration. The maintenance plan can include the following points: • • • • •

Radiographic testing; Visual inspection; Monitoring pressure in the pipes; Monitoring heat transfer; Particulate load (sampling for particulate or bacterial counts, the latter indicating the formation of a biofilm).

3.3.6.8. Associated mechanisms As indicated in section 3.3.6.1 under deposit corrosion groups a large number of corrosion mechanisms: • • • • • •

CO2 Corrosion (DM#P1); H2S + CO2 Corrosion (weight loss corrosion) (DM#P2); MIC (DM#P4); Oxygen Induced Corrosion (DM#P7); Low-Temperature Sulfur Corrosion (DM#P8); Caustic Corrosion (DM#19), etc.

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3.3.6.9. References 1

J. R. Vera, D. Daniels, M. H. Achour, “Under deposit corrosion (UDC) in the oil and gas industry: a review of mechanisms, testing and mitigation”, Corrosion /2012 - paper n° 1379, NACE International.

2

Power Plant Chemistry 2009, 11(12), Under deposit corrosion – a general introduction, pages 760-763.

3

R. B. Dooley, A. Bursik, Hydrogen damage, Power Plant Chemistry 2010, 12(2), pages 122-127.

4

J. M. Jevec, “Fossil Boiler Water Chemistry, Experiences and Challenges”, IAPWS Symposium 2010.

3.3.7.

Oxygen Induced Corrosion (DM#P7)

3.3.7.1. Description of the damage Oxygen dissolved in an electrolyte in general has a negative impact on the corrosion resistance of materials. Oxygen accelerates the corrosion process on carbon steel and low-alloy steels. In water containing 2 mg/L dissolved oxygen at neutral or close to neutral pH and at 20 °C, the corrosion rate of steels is less than 0.5 mm/year, whereas in water containing 9 mg/L of oxygen, it is approximately 4 times higher [18]. The corrosion rate is almost proportional to the concentration of dissolved oxygen. In a closed or confined circuit, corrosion no longer occurs when all the oxygen is consumed. Major cathodic and anodic reactions at close to neutral pHs: • Anode: Fe  Fe2   2e  ; 1 • Cathode: H 2 O  O2  2e   2OH  (predominant in neutral or aerated al2 kaline solutions); 1 • H   e   H 2 , (predominant in deaerated acidic solutions). 2 The corrosion rate is essentially controlled by the rate of the cathodic reaction (slower than the anodic reaction). The corrosion products formed during oxygen induced corrosion can form complex structural layers when they precipitate. However, the initial corrosion product is ferrous hydroxide, which is fairly soluble in acidic solutions but precipitates quite easily in neutral or alkaline solutions. Fe   2H 2 O  Fe OH2   2H 

66 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Ferrous hydroxide is rapidly oxidized into ferric hydroxide in water saturated with oxygen. This hydroxide is highly insoluble. Fe OH2 

1 1 H O  O2  Fe OH3 2 2 4

Ferrous and ferric hydroxides are usually hydrated. A layer of hydrated magnetite, rust, sometimes forms between the ferrous and ferric hydroxide layers. In an aerated medium, most of the rust is composed of ferric hydroxides; however, when tuberculation corrosion develops, the major compound near the wall is composed of ferrous hydroxide owing to the local oxygen deficit (figures 21 and 22). In boiler feed water systems, in boilers and in steam systems, the steel is usually covered by magnetite which forms a protective layer: if the magnetite layer is damaged or if hematite forms, then oxygen induced corrosion can be significant, even though it is generally localized. Magnetite is formed by the Schikorr reaction which involves the anaerobic oxidation of Fe2+ to Fe3+ and the dehydration of ferrous and ferric hydroxides. The resulting reaction is: 3Fe OH2  Fe3 O4  2H 2 O  H 2 In the presence of excess oxygen, magnetite oxidizes to Fe2O3 4 Fe3 O4  O2  6 Fe2 O3 All of these reactions concern partially or fully aerated water circuits that are permanently in contact with the atmosphere. Since oil production fluids are absolutely deaerated in the reservoirs, this situation is quite rare in oil production facilities, except for accidentally aerated systems. Rather, residual oxygen levels are encountered, often with less than 1 mg/L of dissolved oxygen. The oxidation of iron up to ferric stage, Fe+++, is no longer common, nor the precipitation of ferric hydroxide. As for the ferrous hydroxide, the acidity of the medium often renders it too soluble to be a major precipitate. Nevertheless, oxygen can always have severe consequences: • It always provides a cathodic reaction capacity that is proportional to its residual concentration or its ingress, if it enters the system at singular points (see discussion below); • It can generate stable oxidative degradation products with subsequent corrosive effects by accumulation: these concerns, in particular, the formation of sulfur by reaction between H2S and oxygen, or the formation of Heat Stable Salts (HSS) in amine units, due to unexpected oxygen ingress; • It hinders the effectiveness of most corrosion inhibitors, which are designed for reducing environments; • It can modify the nature and the protectiveness of corrosion deposits that normally form in a reducing environment (carbonate or iron sulfide), even if it is not enough to generate the hydroxide deposits mentioned above.

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Consequently, the careful prevention of the accidental oxygen ingress in oil production facilities must always remain a fundamental concern which should never be disregarded.

Figure 21. – Structure of the rust layer in aerated water (adapted from H.M. Herro, Paper No. 84, Corrosion ’91).

Figure 22.  –  Corrosion concentration cell, developing tubercles, chemical equilibria, pH and oxygen concentration gradients in the tubercle vs. location (adapted from HM Herro, Paper No. 84, Corrosion ’91).

68 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 23.  –  Tubular corrosion mechanism: the mechanism is close to that leading to the development of tubercles – the tubular form is due to a combination of forces exerted during the corrosion process [9].

3.3.7.2. Impacted materials Carbon steel and Low Alloy Steels: the corrosion mechanisms are described in the previous section. Galvanized steels: zinc deposits act as an anode and protect the steel; however, if the deposit is deteriorated or of poor quality, the steel may become corroded. Copper alloys: oxygen has two roles in the corrosion of copper alloys. On the one hand, it stimulates the attack by interacting at the cathode, and on the other hand it delays corrosion by producing a protective layer. CRA: the combination of dissolved oxygen and chlorides or other anions in solution is often dramatically harmful to most stainless steels, especially the lower grades alloys (martensitic, 300 series austenitic, duplex). They are subject to fast pitting (DM#09), crevice corrosion (DM#10) and to stress corrosion cracking (SCC). In glycols, oxygen corrosion can occur as pits on stainless steels including duplex ones, [16].

3.3.7.3. Critical factors Oxygen concentration: For water in equilibrium with the atmosphere or an oxygenbearing gas, the dissolved oxygen concentration depends on the temperature, the

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partial pressure of oxygen in the gas phase, the ionic strength of the electrolyte and the nature of the dissolved ions. The oxygen concentration can be estimated using Henry’s Law or through simplified relationships [6, 10, 14, 15]. Temperature: At a constant oxygen concentration, the corrosion rate of steels approximately doubles for every 20 °C, from ambient temperature to approximately 80 °C. For water at equilibrium with the atmosphere, the corrosion rate of the steel decreases from 80 °C due to the sharp drop in the dissolved oxygen content. Composition of carbon steel: In neutral environments, the nature of the steel has only a very limited impact. The steel composition has an impact in acidic environments (e.g., potential difference on different components of steel for example ferrite, cementite…) Presence of other ions: The other ions present usually affect the composition of the deposit. Halides, in particular, promote pitting corrosion. Fluid flow rate: As long as the mechanism is controlled by mass transfer (the most common situation) the fluid flow rate is a significant negative factor (especially in a neutral medium). When corrosion is controlled by charge transfer, it is less critical. Influence of dissolved gases: The amount of dissolved CO2 is an important factor as it affects the pH of the fluid. When the concentration of CO2 increases, the corrosion rate also increases. There is a synergy between the gases contained in the system and the presence of oxygen. In the O2-H2S-coexisting environment the corrosion rate is higher than the sum of corrosion rates of the O2-containing environment and the H2S-containing environment, regardless of the gas phase and the liquid phase. In boiler systems, three critical factors are considered: the presence of moisture, the presence of dissolved oxygen and an unprotected metal surface. In aerated systems, one or more of the situations below can result in lack of protection: • Absence of magnetite due to chemical cleaning; • Surface covered with hematite Fe2O3, (red) instead of magnetite; • Degraded layer of Fe3O4 magnetite (black).

3.3.7.4. Impacted units or equipment All units and equipment in contact with ionic solvents containing or potentially containing oxygen may be affected by oxygen induced corrosion. In practice, as most oil production facilities are normally strictly deaerated (except for aerated seawater systems), two basic situations are encountered: 1. Oxygen is normally removed, albeit insufficiently, either by lack of treatment or by a process upset. This concerns for example seawater injection systems, boiler, or cooling water systems, amine, or glycol systems;

70 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

2. Oxygen ingress into systems that are normally deaerated, either accidentally or not regulated by specific process equipment: in particular, this has to do with the absence of, or defects in the vessel blanketing design or maintenance, the regular or occasional reinjection of external aerated water in the production circuits, the use of large quantities of aerated chemicals (methanol, glycol, kinetic hydrate inhibitors), defects in the pumps’ stuffing boxes, damage to gaskets in low-pressure facilities... Closed cooling water systems, boiler feed water, boilers, and steam systems: Oxygen attacks are sometimes encountered in these circuits and equipment when they are contaminated by oxygen: e.g., by defective or absence of blanketing as indicated above, or lack of oxygen scavenger treatment. The most sensitive areas are superheater tubes, heating tubes, economizers, feed water heaters [3, 4, 8]. In cases of severe contamination by oxygen, attacks have been reported at the water line in the vaporization tubes as well as in the steam drum. Oxygen contamination of feed water or condensates has been shown to promote corrosion-fatigue in thermal degassers that do not meet the NACE SP0590 criteria [17]. Aerated Cooling Water Circuits: The attack concerns metal surfaces exposed to oxygen-containing water. Often oxygen induced corrosion is the precursor to the development of tubers. Exchanger tubes and their headers, and the pipes are potentially affected [3, 5]. In systems made of galvanized steel, oxygen must be maintained in the water during an initial passivation phase, in order to avoid the formation of white rust. Amine circuits and glycol (contamination by oxygen, often by lack of blanketing, the make-up water, or storage tank): The presence of oxygen accelerates the corrosion rate: firstly, oxygen contributes to the formation of amine degradation products, some of them are corrosive; secondly, it directly contributes to corrosion [11]. Water re-injection (oxygen contamination or insufficient deaeration of seawater): In oxygen-containing injected waters, severe corrosion is observed when the residual concentration is higher than 0.1 to 0.2 mg/L in areas subjected to high flow rates. The current specification for fully deaerated water is to achieve a maximum oxygen content of 20 to 30 ppb of oxygen. Hydrocarbon systems (oxygen contamination): oxygen is generally not naturally present in hydrocarbons, but accidental ingress of air is frequent, and can lead to corrosion in wet environments [7, 12]. Wet gas systems subjected to preventive treatment against hydrate formation by injection of methanol or glycol: Oxygen is about 10 times more soluble in methanol than in water. In systems containing H2S, methanol is often injected in large quantities and can potentially dissolve a lot of oxygen. The oxygen reacts rapidly with H2S to form sulfur and oxidized forms of sulfur. The effect is less serious in sweet systems, even though part of the oxygen spreads towards the surface of the metal and can contribute to accelerating the corrosion rate [13]. 

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Glycol injection usually reduces the corrosion rate, except when dissolved oxygen is present, and especially if there is little H2S. It has been shown that carbon steel corrodes by pitting when temperature rise above 80 °C and that above a dissolved oxygen concentration greater than a few hundred ppb, the 22 Cr duplex stainless steels whose passivation layer has been altered could undergo selective dissolution of ferrite and/or stress corrosion cracking [16].

3.3.7.5. Aspect or morphology of the damage The morphology of the damage can be differentiated according to the medium. Corrosion can be generalized and relatively homogeneous in aerated water systems, or localized: • In the form of cavities covered with tubercles in slightly carbonated, stagnant water; • Relatively localized in case of differential aeration; • In the form of grooves in boiler evaporation tubes; • In the form of very localized pits in economizer and superheater tubes and in the steam networks. Aerated water circuits: As the oxygen-containing water is in contact with the entire surface, corrosion will occur all over. Tubers may form in stagnant areas. Tuberculation corrosion occurs in aerated flowing water containing bicarbonates, and/or sulfates. The tubers appear as clusters of corrosion products and deposits on corroded areas; they can impede fluid flow. Tubers are structured; there is a relationship between their structure and their development mechanism [3]. Stratified oxide layers may form in areas subjected to mists. Corrosion product layering is often encountered under alternating dry-wet conditions (e.g., corrosion under thermal insulation in cyclic temperature conditions). The degradations are generally uniform when the oxygen concentration remains close to saturation and at ambient temperature. Pits can occur when the corrosion products are destroyed locally. Corrosion products can also take on tubular shapes when they develop. It has been shown that this results from a difference in the oxygen concentration at the anodic and cathodic surfaces (figure 23). The tubular shape can be explained by considering the various factors that contribute to corrosion [9]. Feed water from boilers, boilers, steam, and condensate systems: The amount of dissolved oxygen is very low. Theoretically, it should be less than 20 ppb in the downstream degasser circuits, (7 ppb in the case of high-pressure boiler feed, 5 ppb according to the EPRI). Nevertheless, some oxygen may accidentally enter (process drift, misfunction during startup, accumulation at high points, etc.). Unlike in open-circuit cooling water systems, where the relatively high concentration of oxygen contributes to generalized corrosion, oxygen induced corrosion in feed and steam water systems usually occurs as very localized attacks (pitting, grooves at liquid-vapor interfaces, etc.) (figures 24 and 25).

72 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Hydrocarbons: As previously indicated, oxygen induced corrosion is accidental. Corrosion usually occurs through pits or grooves at the liquid gas interface.

Figure 24.  –  Water-steam circuit; (a) oxygen induced corrosion of the upper part of a thermosiphon vaporizer; (b) detail of pit.

3.3.7.6. Prevention / Protection The concentration of dissolved oxygen is reduced using physical methods (vacuum degassing) or chemical methods (oxygen reduction using a reducing compound: sulfite, organic reducing agent, corrosion inhibitors), or by the successive action of the two solutions, in particular in water injection systems. Physical oxygen-resistant barriers can also be implemented: • • • •

Metallic or organic coatings; Galvanized steel, acting as a coating and a cathodic protection; Selection of seals, gaskets and stuffing limiting air intake; Use of materials insensitive to the action of dissolved oxygen (some metal alloys, non-metallic materials, composite materials); • Commissioning and operating procedures must also limit the probability of periodic or accidental oxygen contamination of the systems; • Storage tanks used for additives or solvents should be maintained under inert atmosphere; • Oxygen scavenging treatment should be done on aerated fluids introduced into the production systems.

3.3.7.7. Inspection and monitoring Monitoring methods: Online analyzers: • Oxygen analyzers placed on circuits that may contain oxygen; • Measurement of the redox potential of water; • Measuring the iron concentration in solution.

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Periodic analyses using colorimetric kits in absence of on-line measuring devices, Pressure and degassing temperature checks, Analysis of the amount of residual inhibitor in the circuits and determination of the distribution of the inhibitor in the different phases, Corrosion Coupons, Electrical Resistive Probes, Linear Polarization, etc. Inspection methods: Oxygen induced corrosion is evaluated by thickness measurements using methods suitable for the morphology and distribution of the corrosion: (Ultrasonic thickness control, Pulsed Eddy Current, X-ray techniques, Magnetic Flux Leakage, etc.). The inspection methods are selected on the basis of the morphology of the foreseen damage. There is no method that is specific to this mechanism.

3.3.7.8. Associated mechanisms Oxygen induced corrosion is associated with many damage mechanisms, and vice versa: • Concentration cell corrosion, tubular corrosion, filiform corrosion, [2]; • Boiler Water / Condensate Corrosion (DM#50); • Cooling Water Corrosion (in general, also includes seawater corrosion) (DM#49), ferruginous tuberculosis, [3]; • Atmospheric Corrosion (DM#47) and Corrosion Under Insulation, DM#46; • Oxidation at ambient temperature, [1].

3.3.7.9. References 1

Traité des matériaux, Corrosion et chimie de surfaces des métaux, Dieter Landolt, Presses Polytechniques et universitaires romandes, © 1993, ISBN 2-88074-245-5.

2

Corrosion Engineering, Mars G. Fontana and Norbert D. Greene, McGrawHill Book Company, Copyright © 1978, 1967 by the McGraw-Hill, Inc., ISBN 0-07-021461-1.

3

R.D. Port and H.M. Herro, “The NALCO Guide to Cooling Water System Failure Analysis”, Nalco Chemical Company, McGraw-Hill, NY, 1993, ISBN: 0-07-028400-8.

4

The Nalco Guide to Boiler Failure Analysis, Nalco Chemical Company, Authored by Robert D. Port and Harvey M. Hero, McGraw-Hill, Inc, Copyright © 1991 by the McGraw-Hill Companies, ISBN 0-07-045873-1.

5

Sea Water Corrosion Handbook, edited by M. Schumacher, Noyes Data Corporation, Park Ridge, New Jersey, U.S.A, 1979, Copyright © 1979 by Noyes Data Corporation, ISBN 0-8155-0736-4.

74 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

6

Modeling Oxygen Solubility in Water and Electrolytes Solutions, Desmond Tromans, Ind. Eng. Chem. Res., 2000, 39, 805 – 812, © 2000 American Chemical Society.

7

NACE Paper 612, Effect of Oxygen on the Internal Corrosion of Natural Gas Pipelines, C.L. Durr and J.A. Beavers (1996).

8

NACE Paper 00649, A Non-Chemical Approach to Oxygen Corrosion Control in Closed Loop Systems, Edward S. Beardwood, (2000).

9

Theoretical Elucidation on the Corrosion Tube Growth Mechanism of Mild Steel in the Effect of pH on Oxygen Corrosion at Elevated Pressures, Ming-Te Liang, Journal of Marine Science and Technology, Vol16, No. 4, pp. 265 – 270 (2008).

10

USG Oregon Water Services, Office of Water Quality, Technical Memorandum 2011.03, July 13, 2011, Change to Solubility Equations for Oxygen in Water.

11

Texas gas plant face ongoing battle with oxygen contamination, Andy Sargent and Mike Howard, Oil&Gas Journal, July 23, 2001, pages 52 – 58, Copyright© by PennWell Corp, Tulsa, Oklahoma.

12

Effect of Water and Gas Compositions on the Internal Corrosion of Gas Pipelines – Modeling and Experimental Studies, N. Sridhar, D.S Dunn, A.M. Anderko, M.M. Lencka, and H.U. Schutt, Corrosion, Vol. 57, No 3, NACE International.

13

Review: The Effect of Methanol on the Corrosion of Carbon Steel in Sweet or Sour Environments, Lara Morello and Neil Park, NACE Northern Area Western Conference, February 15-18, 2010, Calgary, ©NACE, 2010.

14

Unesco technical papers in marine science, No 36, 1981 & No 44, 1983.

15

Effect of Oxygen, Temperature and Salinity on Carbon Steel Corrosion in Aqueous Solutions; Model Predictions Versus Laboratory Results, S. L. Grise, B.J. Saldanha, Paper 08271, Nace Corrosion Conference 2008.

16

Paper 07116, Materials Consideration for MEG (Mono Ethylene Glycol) Reclamation Systems, M. W. Joosten, B. Tier, M. Seiersten, C. Wintermark, Nace Corrosion Conference 2007.

17

NACE SP P0590, Standard Practice: Prevention, Detection, and Correction of Deaerator Cracking, NACE International, 7th Edition, February 24, 2015.

18

Effect of Dissolved Oxygen (DO) on Internal Corrosion of Water Pipes, Haeryong Jung, Unji Kim, Gyutae Seo, Hyundong Lee, and Chunsik Lee, Environ. Eng. Res. Vol. 14, No. 3, pp. 195 – 199, 2009, Korean Society of Environmental Engineers.

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3.3.8.

75

Low-Temperature Sulfur Corrosion (DM#P8)

3.3.8.1. Description of the damage The term “sulfur corrosion” is a common term that should be referred more specifically to as “Corrosion induced by sulfur-deposits”; the sulfur deposit may be liquid or solid. Most of the severe forms of corrosion attributed to sulfur are believed to be caused by solid sulfur, at temperatures below 110–120 °C. Moreover, the term “low temperature” corresponds to a temperature range between ambient temperature and 140–150 °C, i.e., the domain in which sulfur is in the solid or liquid phase. Currently there is no evidence of a corrosion effect due to gaseous sulfur (as sulfur or polysulfides) in the maximum temperature range commonly encountered in the oil industry (< 200 °C). The corrosion rate is often very high (even more than 50 mm/year), in the form of very deep pits or cavities. The detailed mechanisms of sulfur-induced corrosion are not yet indisputably established. However, the main characteristics can be defined: • In the past, one of the proposed mechanisms that can explain sulfur-induced corrosion has been the hydrolysis of sulfur, which theoretically generates acidity [1]: S8 + 8 H2O  2 H+ + SO4–– + 6 H2S. Measurements of pH and of sulfate and H2S generation have finally refuted this as a dominant or even secondary mechanism. These measurements effectively showed that the acidity generated by hydrolysis is sensitive at temperatures only above 100–120 °C whereas considerable corrosion is observed at much lower temperatures. In addition, these tests show that the pH induced by such hydrolysis remained in the range of pH 4 to 5 up to temperatures of approximately 100–120 °C, an order of magnitude comparable to that of waters saturated in H2S and CO2 at few bars of partial pressure of these 2 gases [2,3]; • Whatever the mechanism finally put forward, it is accepted that: 1. The oxidizing nature of sulfur (which can be reduced from S0 to S2–) contributes to localized corrosion: ○ However, wet acidic hydrocarbon fluids with high H2S + CO2 contents have corrosive capacities that can easily reach 10 to 20 mm/year on bare steel, ○ This implies that there is no need for the additional oxidizing power provided by the sulfur itself to produce strong corrosion, ○ Rather, it is considered that sulfur preferentially helps initiation and enhances the development of localized corrosion, (in particular, pyrite deposition is enhanced by the presence of sulfur [4], which is an “insoluble anionic” non-protective deposit [5]), 2. There must be “immediate proximity” at minimum, or “direct contact” between the sulfur deposit and the metal wall:  ○ According to G. Schmitt[2], the reason for this is that accelerated corrosion is due to a galvanic coupling between steel and the sulfur deposit,

76 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

and that the iron sulfide deposit that forms gradually is the intermediary through which electrons are transferred between the steel and the solid sulfur, ○ Another corrosion mechanism controlled by the kinetics of sulfur dissolution in water and its reduction on an adjacent surface has also been given, but not published (Crolet [6]). According to this mechanism, when the partial pressure of H2S is high, sulfur is somewhat soluble in water. When the distance between sulfur and metallic surface is small enough to allow a significant diffusion through the water layer, this mechanism assumes that the consumption of dissolved sulfur is ensured by its reduction on the surface, thereby sustaining the dissolution kinetics of the immediately adjacent sulfur. This sulfur on the metal surface can be reduced to adsorbed HS– anions or on an iron sulfide deposit, ○ This assumption does not involve a real galvanic effect as in the 1st hypothesis. It also does not require an absolute contact between the sulfur and the metal surface, but only their close proximity which eases the transport of the dissolved sulfur despite its low solubility, 3. High water salinity promotes significant corrosion: theoretically, such sensitivity would be compatible with a galvanic corrosion effect. It is also possible that the increasing chloride content enhances the solubility of sulfur by solvation of the sulfur with the chlorides in the medium. Whatever the exact mechanisms of this type of corrosion, the sulfur in an H2S environment definitely promotes a very rapid localized corrosion, often leading to perforation. Such severe corrosion does not occur in the absence of sulfur. The role of sulfur is not limited to providing only further corrosiveness. It must also stimulate the initiation and development of an active, rapidly corroding surface, different from the surrounding average surface, whose corrosion remains weaker. Although the exact origin of this differentiation and the mechanism that develops localized corrosion are not fully explainable, this adverse effect of sulfur is well established.

3.3.8.2. Impacted materials Only carbon steels and low-alloy steels are susceptible to this form of corrosion. The sensitivity of virtually all stainless steels and even nickel alloys to stress corrosion cracking in H2S rich environments is also greatly increased by the presence of sulfur in a solid or liquid state. However, that is a different damage mechanism which is not dealt with here.

3.3.8.3. Critical factors In a situation where sulfur deposits may occur (see standard conditions in 3.3.8.4), the four most critical factors are: 1. The presence of water, which is a necessary condition for this type of corrosion;

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2. The salinity of this water, insofar as ionic transfer effects are necessary between the sulfur, which is oxidizing but non-conducting, and the corroding metal; 3. The temperature; 4. The concentration of H2S and CO2 of the associated gas. Finally, for the “sulfur-induced corrosion” to occur, a direct or close contact is required between the sulfur and the metal, possibly through an intermediate ironsulfide deposit.

3.3.8.4. Impacted units or equipment The 1st condition required for such corrosion to occur is the possibility of sulfur deposition, so the main units and equipment potentially impacted are: • Gas field wells and pipelines containing high concentrations of H2S (> 10 - 15%), elemental sulfur, possibly polysulfides, and low concentrations of hydrocarbon condensates: liquid condensates are quite good sulfur solvents, so saturation is rarely achieved for gases rich in liquid condensates; • Pipelines and process gas equipment containing H2S in which oxygen ingress occurs: this entry is generally accidental, therefore unknown. Hot-oxidation Sulfur Recovery Units (SRU) are little impacted by this type of corrosion because they operate under temperature and water content conditions that prevent the presence of liquid water, except in accidental situations, in particular cold points. Low-temperature sulfur corrosion is sometimes encountered in the cold, wet piping, and equipment in SRU tail gas treatment units (SCOT or Clauspol), as well as in VRUs and low-pressure flare lines. It is well known that strong sulfur-induced corrosion can occur even in the absence of H2S: such corrosion can develop even if solid sulfur is in contact with metal and water. However, in oil-production environments, which are reductive, the actual presence of sulfur is strictly related to the presence of H2S, either in high concentrations or associated with oxygen or another oxidant. In this guide we only deal with sulfur-induced corrosion in H2S environments.

3.3.8.5. Aspect or morphology of the damage The most common morphology observed is localized corrosion [7], which can occur very rapidly and deeply, as shown in figure 25. It is worth reminding that this morphology is not highly specific to sulfur deposition + H2S, so it cannot be strictly attributed to this mechanism, e.g., when compared to the detrimental effect of oxygen entries in a sour fluid. Abundant iron sulfide deposits are frequently reported around the corrosion zone but as stated above this is not so specific to the sulfur effect.

78 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 25.  –  Severe pitting corrosion due to sulfur deposition.

On the other hand, local corrosion rates higher than 30 to 50 mm/year have been reported for this type of corrosion and are more specific to the sulfur effect. It is one of the fastest mass-loss corrosion mechanisms encountered in oil production, which is why it should be prevented in any condition where liquid or solid sulfur is likely to accumulate.

3.3.8.6. Prevention / Protection In conventional cases where sulfur is deposited from gas heavily loaded with H2S and sulfur, whether in the production tubing or in pipelines, the 1st preventive measure is to prevent sulfur precipitation. This preventive measure must be applied as soon as the precipitating quantities are significant, not only to control sulfur-induced corrosion but also to avoid the gradual obstruction in the zone of deposition. Three solvent families are used or have been used in the past: • Liquid hydrocarbons (gas condensates, “Spindle oil”); • Products based on amines; • Sulfuric solvents (diaryl disulfide DADS, dimethyl disulfide DMDS). The treatment methods can be: • Continuous preventive, to prevent any precipitation; • Discontinuous curative, (usually weekly to monthly, depending on the quantities that are likely to precipitate). These treatments are designed to periodically dissolve sulfur deposits before they can induce operating problems, clogging or corrosion. Finally, treatments can be done with a “lost solvent”, especially for periodic batch treatments (which preferentially use solvents with a high dissolution capacity, such as the sulfur solvents mentioned above). A regenerated solvent can also be reused in a solvent recirculation loop: this process is particularly suited to hydrocarbon or amine solvents.

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These 3 types of solvents have specific advantages and disadvantages, which determine their scope of use: 1. Hydrocarbon solvents have relatively low sulfur dissolution capabilities. They are therefore particularly suitable for continuous treatments with regeneration and recirculation. Conversely, their low dissolution capacity makes them less attractive for curative treatments, because of the high volumes required if an abundant amount of sulfur is to be dissolved. On the other hand, as these solvents are hydrocarbon compounds, they are a common product of the oil industry, and therefore easily available and manageable in operations. 2. Amine products are also used in processes with regeneration, therefore in preventive treatment with recirculation. They are rarely used and are suitable only for treatments in processing facilities downstream of reservoir brine separation. In the presence of reservoir water, salty and rich in calcium ions, amines would stimulate the mass precipitation of calcium carbonate, so they cannot be used. This is the main reason why this treatment is rather inapplicable in the oil production industry, for the treatment of wells or downstream pipelines. 3. Sulfur based solvents (in particular DADS and DMDS) have a major advantage: that of high solvent power, making them preferential candidates for discontinuous curative treatment. Their main drawbacks are that they are difficult to use because of their highly unpleasant smell, their toxicity, and their flammability, thereby imposing strong safety and environmental constraints when they are used. For these reasons, these products are used preferentially for discontinuous curative treatments. Preventing sulfur deposition cannot be the only solution implemented to prevent corrosion. The following issues must still be addressed: • The certainty that sulfur deposits will still occur in a program with curative dissolution-based treatments; • The risk of deposits if the preventive treatment is incomplete, ineffective, or only partly effective, or if it is occasionally interrupted. Prevention of sulfur-induced corrosion is therefore achieved either through the choice of materials resistant to this type of corrosion and to stress corrosion cracking in the presence of sulfur, or by using inhibiting treatments on standard steel: 1. Materials resistant to sulfur induced corrosion: • Nickel alloys: they must be resistant to both the H2S-bearing fluid, which is acid and detrimental for passive film stability owing to the effect of the chlorides and H2S in the fluid, and the oxidative nature of the sulfur deposit; • Because of this dual constraint, resistant materials are more alloyed, and therefore more expensive than materials that must only be H2S-resistant; • NACE MR0175/ISO 15156-3 [8] gives recommendations for materials that are specifically adapted to the presence of sulfur, depending on the temperature, on the amount of H2S present and on the chloride content present in the water.

80 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

2. Carbon Steels and corrosion inhibitors • There are positive cases of corrosion control by inhibiting treatments, according to several treatment methods; • In the curative treatment of wells and pipelines using sulfur solvents (hydrocarbon or sulfur solvents), the solvent contains an additive with a high concentration of a film-forming inhibitor that is preferentially oil-soluble. The inhibitor is deposited on the metal surface during the dissolution treatment. This is therefore a periodic treatment by “batch”, using a product selected for its persistence on the metal surface. Certain products specific for these applications can be found among the main suppliers of inhibitor products; • In preventive sulfur-deposit treatments based on permanent recirculation of a regenerated hydrocarbon solvent, the solvent can serve as a “carrier fluid” for a corrosion inhibitor; the latter is therefore chosen to be preferentially “oil-soluble”. The treatment is then continuous from the solvent injection points (in the wells or at the start of the pipelines, depending on the predicted zone of precipitation); • Finally, in the absence of preventive treatments and in situations of rare curative treatments (low risk of sulfur deposition), continuous treatments of corrosion inhibitors are also applicable to the concerned facilities; • In any case, the inhibitor must be specifically designed for sulfur deposits and be selected by tests involving such deposits. Such environments are a major challenge for most of the standard inhibitors used in oil production. Suppliers must be informed of this situation in order to put forward suitable products.

3.3.8.7. Inspection and monitoring In situations likely to induce the formation of sulfur deposits, the exact areas of deposition and the importance of the latter are difficult to predict at the onset of production. The first and most important monitoring measure is therefore: • To identify the potential zones of deposition and their amounts, in the hypothesis that no preventive treatment was to be implemented; • To ascertain the non-deposition and to monitor the effectiveness of the preventive treatment if such treatment is implemented. This actually concerns monitoring of potential deposits in a production facility, which is not directly related to corrosion monitoring (verification of flow rates and pressure drops, regular pigging, etc.). There is no truly specific corrosion monitoring solution for this corrosion mechanism, which is different from what happens in a facility with fluids laden with H2S. Likewise, there are no specific inspection methods. However, it is necessary to reinforce inspection in the areas of presumed or known sulfur deposition, because of the much higher risk of corrosion.

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3.3.8.8. Associated mechanisms H2S + CO2 Corrosion (weight loss corrosion) (DM#P2).

3.3.8.9. References 1

PJ Boden, S.B. Maldonado-Zagal, “Hydrolysis of elemental Sulfur in Water and its Effect on the Corrosion of Mild Steel”, British Corrosion Jal, vol 17, n° 3, (1982), 116 – 120.

2

G Schmitt, “Present Day Knowledge of the Effect of Elemental Sulfur on Corrosion in Sour Gas Systems, Paper n° 39, CORROSION/1990 Conference, NACE International.

3

H. Fang, B. Brown, D. Young, S. Nešić, “Investigations of Elemental Sulfur Corrosion Mechanisms”, Paper n° 398, CORROSION/2011 Conference, NACE International.

4

SN Smith, MW Joosten, Corrosion/2006, paper n°  06115, CORROSION/2006 Conference, NACE International.

5

JL Crolet, M. Bonis, “Algorithm of the Protectiveness of Corrosion Layers: Protectiveness Mechanisms and H2S Corrosion Prediction”, Paper n° 10365, CORROSION/2010 Conference, NACE International.

6

JL Crolet, private communication, not published (2010).

7

M. Bonis, R MacDonald,” H2S + CO2 Corrosion: Additional Learnings from Field Experience”, paper 5718, CORROSION/2015 Conference, NACE International.

8

NACE MR0175/ISO 15156-3, Petroleum and natural gas industries — Materials for use in H2S containing environments in oil and gas production — Part 3: Cracking-resistant CRAs (corrosion-resistant alloys) and other alloys, International Standard, 2015.

3.3.9.

Pitting Corrosion (DM#P9)

3.3.9.1. Description of the damage The term “pitting corrosion” is often used to designate any form of localized deep corrosion, for example on steel in CO2-rich acidic environments. In this section, we consider that the term “pitting corrosion” applies only to materials in the passive state and caused by the mechanisms described below, whereas the generic term “localized corrosion” would be more appropriate for all other situations. According to the definition given in ISO 8044 [1], pitting corrosion is localized corrosion resulting in pits, i.e., cavities that develop in the metal starting from the surface.

82 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

These narrow cavities can progress rapidly in depth while the rest of the surface remains unscathed. An equipment wall can be perforated in just a few days without any appreciable loss of the structure’s weight. This form of corrosion is related to the presence of a “passive” or “pseudo-passive” film on the surface of the metal. The corrosion develops when the metal is in the presence of an aggressive anion, for example a halide, in combination with an oxidant. The corrosion initiates preferentially in opportune locations, for example at surface discontinuities or where inclusions are found. However, it would be ineffectual to consider that the removal of any discontinuity would avoid pitting corrosion: the existence of slightly more severe conditions would suffice for such corrosion to emerge and develop. It is accepted that pitting corrosion of stainless steels and nickel alloys develops in two stages: A phase of incipient pitting, or nucleation: Corresponding to the local failure (depassivation) of the passivation layer. Several models, described in various works [3, 4, 5], have been put forward to describe this phase. Stable pit propagation phase: In the absence of rapid repassivation, coupling occurs between the bare metal and the passive metal. The pit propagates by anodic dissolution of the metal in the single pit, coupled with the reduction of oxygen (or any other oxidant) on the passive surface in the vicinity (electrochemical process). When the pit development is stable, this step is self-perpetuating by the acidification at the base of the pit, which prevents its repassivation. M  M n   ne  , anodic reaction. O2  2 H 2 O  4 e   4 OH , cathodic reaction in the presence of oxygen. The hydrolysis of the metal ions leads to the formation of H+ ions which acidify the medium inside the pit, thereby stabilizing it because the small pit diameter reduces the possibility of dilution of the acid confined to the pit. This therefore perpetuates the coupling between the passive surface exposed to oxygen (or other oxidant) and the active pit stabilized by its acidity (figure 26), M n   n H 2 O  M OH n  n H  , inducing an acidification process. The transition from metastable propagation to stable propagation is characterized by the pitting initiation potential, Ep. The potential below which the system must drop to repassivate a formed pit is called the repassivation potential, Erp; it also depends on the propagation stage of the pit. It should be noted that the anodic current density in the pit can be very high because the ratio of the cathode/anode surfaces is very high: this is well known to be very unfavorable in situations of galvanic corrosion. Unlike crevice corrosion, the distribution of pits may not be just local. Admittedly, the intrinsic flaws at the metal-solution interface often constitute localized spots of dissolution nuclei, but not all the nuclei concerned are attacked. The initiation and development of these nuclei is always somewhat random [4, 6].

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Figure 26. – Pitting corrosion mechanism diagram in aerated chloride environment.

3.3.9.2. Impacted materials All so-called passivable metallic materials are potentially subject to pitting corrosion, according to the mechanism described above: • • • •

Stainless steels and nickel alloys; Copper and copper alloys; Aluminum and aluminum alloys; Titanium and titanium alloys.

3.3.9.3. Critical factors General case Pitting corrosion occurs when the corrosion potential exceeds the pitting initiation potential, Ep, according to the definition of ISO 8044: the pitting initiation potential is the lowest value of the corrosion potential at which pit initiation is possible on a passive surface in a given corrosive environment. This notion of an initiation potential applies to all metals and metal alloys. It is not an absolute value, depending on several parameters as shown below. The repassivation potential evaluated by the hysteresis of the polarization curve (electrochemical method) helps evaluate the ability of the material to repassivate in a given environment.

84 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Factors affecting the probability of pitting corrosion, relevant to the environment The 2 main environmental factors that decrease the pitting potential of passive materials are: 1. The halide content (F–, Cl–, Br–, I–), usually that of chlorides; 2. The temperature. Conversely, the 2 main factors that increase the corrosion potential are: 1. The dissolved oxygen content in the water, potentially combined with HClO– ions, which are also oxidizing; 2. Bacterial contamination that generates a biofilm on the surface (this effect is especially observed in aerated environment) which commonly increases the corrosion potential of stainless steels from 200 to 300 mV. These 4 factors are those that determine how close the corrosion potential and pitting potential of a given material can be, either by an increase in one (corrosion potential) or a decrease in the other (pitting potential). To a lesser extent, the presence of sulfides and / or H2S also exacerbates the sensitivity to pitting corrosion by lowering the pitting corrosion potential. The presence of an oxidizing cation (Fe3+, Cu2+, Hg2+, etc.) can also contribute to the formation of pits even in the absence of oxygen, through a comparable increase in the corrosion potential. Conversely, the NO3– and to a lesser extent SO42– ions have some inhibiting capacity on pitting corrosion of austenitic stainless steels in a chloride-rich environment [3]. As for the effect of temperature, the Critical Pitting Temperature (or CPT; NACE / ASTM G193 [2]), is, for stainless steels and nickel alloys, the temperature at which the pits start to appear in a given corrosive environment. In general, the CPT values in literature relate to the results of one of the ASTM G48 tests, in a reference medium [12]. These values are rarely representative of those obtained in the actual environments to which the material is subjected. However, they allow a relative classification of materials and may be used for quality control. It is possible to correlate the Pitting Resistance Equivalent (PRE) Number discussed below and the critical pitting temperature, the relation is practically linear. To illustrate the effect of oxygen, 13Cr stainless steel, although it contains only very little of the alloy element, is very resistant to highly deaerated produced water despite salinities of more than 100 g/L of sodium chloride above 100 °C, whereas it does not resist aerated seawater at room temperature for more than a few days. The role of oxygen is therefore decisive on the corrosion potential and ultimately on the pitting sensitivity of the material.

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Factors affecting the probability of pitting corrosion, relevant to the material Chemical nature of the metal: In a given medium, the critical pitting potential is different for different metal alloys. In seawater, titanium CP (Commercially Pure) and titanium alloys have a much higher pitting potential than most stainless steels, hence their very good resistance in this environment. In the case of stainless steels and nickel alloys, resistance to pitting corrosion increases with increasing Cr, Mo, W, N concentration, and also with certain austenite-soluble elements such as Si, V, Ti, Ce, Nb, Ta, Zr, and Re [7, 17]. Sulfur reduces this resistance. The Pitting Resistance Equivalent (PRE) Number is an indication of the resistance of stainless steels and nickel alloys to pitting. The PRE is usually calculated according to the formula: PRE = % Cr + 3.3 x [(% Mo) + 0.5 x (% W)] + 16 x (% N) (weight %) The PRE is sometimes noted PREN and PREW depending on whether the alloy contains nitrogen and/or tungsten. According to some authors, [8, 9], this formula is valid only for austenitic stainless steels and the austenitic phase of duplex steels. In the case of duplex steels, the distribution of the alloying elements in the two phases has to be considered; so, for nitrogen whose solubility is very low in the ferrite phase, and which modifies the distribution coefficients for Cr and Mo, the coefficient assigned to the nitrogen concentration can take on the three values: 16, 20 and 30. 16 is the most widely used value. Other formulas have been put forward to calculate the PRE [10], so for the alloys Ni-Cr-Mo (Alloy 625, Hastelloy, ...), the following expression can be used: PRE  %Cr  1.5  %Mo  %W   %Nb  30  %N  , Stainless steels and low-PRE nickel alloys are the most sensitive to pitting corrosion in the presence of chlorides. Surface condition, inclusions: The time for pitting initiation is usually delayed when the surface condition has no asperities, and its roughness is low. The presence of non-metallic inclusions, for example sulfides, lowers the pitting potential of an alloy. Inert inclusions have the lowest effect, while inclusions favoring anodic or cathodic reactions create a galvanic effect. The absence of non-metallic inclusions reduces or delays the occurrence of pitting corrosion. According to some studies, cold working increases the sensitivity to pitting of certain austenitic stainless steels [11].

86 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Pitting corrosion of copper alloys Commercially pure copper and some of its alloys are sensitive to pitting corrosion under specific environmental conditions. Three types of pitting corrosion (Type I, Type II, Type III) have been described [13], type I is most common. Pitting corrosion similar to type I has been observed on aluminum brasses. Copper-nickel alloys are not sensitive to pitting corrosion in chloride-bearing environments, however they can become so if the environment contains sulfides. In this last case, sulfide concentration is a critical factor for pitting corrosion of copper-nickel alloys. Aluminum-Nickel Bronzes (NAB) are generally not affected by pitting corrosion, depending however on their structure and the heat treatment process they received, [14]. Pitting corrosion of aluminum alloys It is characterized by the random formation of pits, usually caused by the presence of halides in an aerated environment. The resistance to pitting corrosion depends on the alloy, its microstructure, and the heat treatment [20]. Aluminum alloys generally do not develop pitting corrosion in environments containing other ions than halides because the critical pitting potential is greater than in chloride-bearing environments. Pitting corrosion of titanium and titanium alloys Titanium and titanium alloys are extremely resistant to pitting corrosion, so this damage is seldom encountered. Nevertheless, according to practical experience some grades of titanium alloys in salty waters can be sensitive to it when the temperature exceeds 110°C.

3.3.9.4. Impacted units or equipment All units and equipment may be subjected to forms of pitting corrosion.

3.3.9.5. Aspect or morphology of the damage The pits are characterized by their maximum depth, the pitting factor, the ratio of the surface area of the pits to the total area, and their shape: The pitting factor is the ratio of the depth of the deepest pit resulting from the corrosion, divided by the average corrosion depth calculated from the weight loss. The pits can be relatively isolated, scattered or grouped [6].

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The surface ratio and the shape of the pits are defined in API 579 / ASME FFS-1, chapter 6 [15]. • The surface area ratio is defined by eight levels (grades 1-8), • The shapes of the pits are defined according to the criteria illustrated in figure 27.

Figure 27.  –  Classification of pits according to their shape.

The combination of all these factors makes it possible to quantitatively evaluate the severity of the pits.

3.3.9.6. Prevention / Protection The choice of material must be adapted to the environment and consider the transient, shutdown and extreme conditions. In the event of stainless steels and nickel alloys, the alloying elements of PRE, namely chromium, molybdenum, tungsten, and nitrogen, are those increasing the resistance to this damage. The chemical cleanliness and surface condition of the alloy are also influential factors: • The presence of sulfur in the alloy decreases the corrosion resistance; • Annealed stainless steels, which therefore do not have precipitated carbides, are more resistant to pitting corrosion; • A specific surface preparation by mechanical cleaning, or preferably chemical, and passivation can improve the resistance to pitting corrosion. Regarding the environment itself, it is essential to ensure the permanence of deaeration, if stainless steels are used in production environments, generally deaerated but chloride-rich: the accidental entries of oxygen are therefore a major subject of Warning.

88 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Similarly, if pit resistance is controlled by a low chloride content (for example in water cooling circuits), this is the content that should be monitored and controlled.

3.3.9.7. Inspection and monitoring Acoustic emission and certain intrusive electrochemical techniques (e.g., electrochemical noise) can be used to monitor pitting corrosion. Visual inspection and X-ray allow to detect macroscopic pits.

3.3.9.8. Associated mechanisms • Chloride Stress Corrosion Cracking (DM#23) (see also [16]); • Crevice Corrosion (DM#P10).

3.3.9.9. References 1

ISO 8044: 2020 Corrosion of metals and alloys — Vocabulary, ICS: 01.040.77; 77.060.

2

NACE/ASTM G193, Standard Terminology and Acronyms Relating to Corrosion, 2021 Edition, December 15, 2021.

3

Corrosion Localisée, F. Dabosi, G. Béranger, B. Baroux, Les éditions de physique, ISBN: 2-86883-240-7, © Les Editions de Physique, 1994.

4

Traité des matériaux, Volume 12, Corrosion et chimie de surface des métaux, Dieter Landolt, © 1993, Presses Polytechniques et universitaires romandes, ISBN 2-88074-245-5.

5

Corrosion Mechanisms in Theory and Practice, Third Edition, Edited by Philippe Marcus, CRC Press., International Standard Book Number 13: 9781-4200-9463-3 (eBook – PDF), Copyright © 2012 by Taylor & Francis Group, LLC.

6

Uligh corrosion handbook – Second edition – Part 22 – Corrosion Probability and Statistical Evaluation of Corrosion Data, by T.SHIBATA.

7

Effect of Supplementary Alloying Elements on Pitting Corrosion Susceptibility Of 18Cr-14Ni Stainless Steel, N.D Tomashov, G.P. Chernova, O.N. Marcova, CORROSION. 1964, 20, 5 166t-173t.

8

The corrosion resistance of stainless of steels. S. Bernhardson. In Duplex stainless steels, Beaune, 1991.

9

Corrosion resistance of super duplex stainless steels in chloride ion containing environments: investigations by means of a new microelectrochemical method. i. precipitation-free states, P.J. Uggowitzer, L. Weber, R. Magdowski, H. Böhni, R.A. Perren, T.A. Suter and M.O. Spiedel. Corrosion Science, 43(4): 707, -726, 2001.

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89

10

Corrosion Performance and Fabricability of the New Generation of Highly Corrosion-Resistant Nickel-Chromium-Molybdenum Alloys, Stephen A. McCoy, Lewis S. Shoemaker & James R. Crum, Special Metals Corporation.

11

Pitting susceptibility of AISI 304 stainless steel after cold rolling, Olandir V. Correa, Mara C.L. de Oliveira, Renato A. Antunes, INTERCORR2014_065, INTERCORR ABRACO maio 2014, © ABRACO.

12

ASTM G48-11(2020): Standard Test Methods for Pitting and Crevice Corrosion Resistance of Stainless Steels and Related Alloys by Use of Ferric Chloride Solution.

13

The corrosion of Copper and Its Alloys: A Practical Guide for Engineers, Roger Francis, © 2010, NACE International, ISBN 978-1-57590-225-8.

14

H. T. Michels, R. M. Kain, Effect of Composition and Microstructure on the Seawater Corrosion Resistance of Nickel Aluminum Bronze, paper n° 3262, Corrosion/2003 Conference, NACE International.

15

API 579-1/ASME FFS-1; Fitness for service, ASME, The American Society of Mechanical Engineers and API, 1220 L Street, NW, Washington, DC 20005-4070.

16

R. Parrott BSc PhD MIMMMM CEng, H Pitts Meng PhD - RR902 prepared by the Health and Safety Laboratory for the Health and Safety Executive 2011 – Chloride stress corrosion cracking in austenitic stainless steel.

17

Influences of niobium and solution treatment temperature on pitting corrosion behavior of stabilized austenitic stainless steels, Guanshun Bai, Shanping Lu, Dianzhong Li, Yiyi Li, Corrosion Science Volume 108, July 2016, Pages 111-124.

18

Livre Multimédia de la Corrosion, INSA de Lyon, Laboratoire MATEIS CorrIS, http://www.cdcorrosion.com/corrosion_version_web.html.

19

Métallurgie générale, 2ème édition, J. Bénard, A. Michel, J. Philibert, J. Talbot, Masson éditeur (1969).

20

Christian Vargel, Corrosion of Aluminium, 2nd edition, Elsevier Science, 6th May 2020, Hardcover ISBN: 9780080999258, eBook ISBN: 9780080999272.

3.3.10. Crevice Corrosion (DM#P10) 3.3.10.1. Description of the damage According to the definition of ISO 8044, crevice (or cavernous) corrosion is a form of localized corrosion associated with and taking place in a narrow interstice or clearance formed between the metal surface and another surface (metallic or non-metallic); corrosion develops in this area or in its immediate vicinity [1]. A crevice is a confined area in which a stagnant aqueous solution is in contact with the metal surface. This confinement limits the exchanges (diffusion, convection) with the outside of the zone. This results in a local evolution of the solution in the

90 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

crevice, whose composition becomes different from that of the external environment, as detailed below. Crevice corrosion is somewhat comparative to pitting corrosion, with local acidification in the crevice, as in the pits: the chloride ion concentration, the temperature and the aeration of the water environment are critical factors. Several factors, however, differentiate crevice corrosion from pitting corrosion: • It particularly occurs in halide-containing environments though also possible in others; • Crevice corrosion is enhanced in stagnant environments; • Crevice corrosion is limited to confined areas; • Crevice corrosion occurs at lower potentials than pitting corrosion. The initiation time can be lower and depend on interstice geometrical parameters; • Crevice corrosion can occur in less severe conditions (with respect to the chloride content, the temperature, etc.) than pitting corrosion, due to the more favorable initiation process. As with pitting corrosion, the crevice corrosion process can be divided into an initiation phase and a propagation phase. Several models have been put forward to describe the initiation of crevice corrosion; they are covered in various works, [3, 4, 6, 14]. The material, the environment and the geometric shape are common parameters for all the models proposed. According to the most common passive dissolution models, passive dissolution of metals in an aerated crevice area, even if very weak, suffices to accumulate metallic cations, due to the confinement of the interstices. Hydrolysis of these cations, and more particularly of chromium, according to the reaction already indicated in 3.3.9.1, induces acidification inside the crevice, which is sustained because of the confinement. M n   n H 2 O  M OH n  n H  Once the local pH drops below the material’s “pH of depassivation”, the metal becomes active in this crevice, and its potential decreases very significantly. The oxygen consumption inside the crevice also contributes to lowering the potential. This marks the end of the initiation process, giving rise to an acidic and active crevice with a lower potential than the outer surface, due to local chemical and electrochemical reactions within the crevice and the ohmic drop. The propagation phase then follows the same galvanic mechanisms described in section 3.3.9.1 for pitting corrosion: • Galvanic coupling between the active and acidic crevice and the aerated external surface; • Accumulation of chlorides inside the crevice, to ensure the charge balance. This accumulation also contributes to the stability of the activity of the surface. M  Mn  n e

1 O  H 2 O  2 e   2 OH  M n   n H 2 O  M OH n  n H  2 2

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The accumulation of corrosion products in confined crevices can cause stresses and pillowing.

3.3.10.2. Impacted materials Stainless steels, nickel alloys, aluminum alloys, and under certain conditions, copper alloys are sensitive to crevice corrosion. Reference is also made to confined corrosion of carbon steel or low-alloy steels, but the mechanisms involved in the acidic environments of oil production are necessarily different from those mentioned in section 3.3.10.1 because of the absence of external passivity. Therefore, it has been decided not to include these materials in this section, referring to passive materials. Among the stainless steels used in oil production, martensitic, 300 series austenitic and duplex are the most widely concerned. Among nickel alloys, alloy 825 is particularly concerned because of its low Cr and Mo concentration. As for copper alloys, [5, 8], the mechanisms are very different from those of stainless steels. There is a concentration cell effect in the crevice where the cuprous ions are not removed and as a result the crevice potential in the crevice becomes higher than that of the outer surface which behaves like an anode. In these conditions, superficial corrosion occurs outside and not inside [13]. In the case of nickel-aluminum bronzes, (NAB), crevice corrosion takes the form of a selective attack. Crevice corrosion of Titanium CP (commercially pure) and titanium alloys is similar to that encountered on stainless steels – an oxygen-poor reductive zone develops in isolated crevices. This type of crevice corrosion can occur in hot environments containing halides or sulfates. It occurs at both metal-seal contacts and on tubes-tube/sheets connections or from seals, welds, or surface deposits.

3.3.10.3. Critical factors The critical environmental and material factors are comparable to those of pitting corrosion (see section 3.3.9.3). It is also important to include the factors relating to the interstices which are the sources of crevice corrosion. Design and workmanship: The nature of “contact”, (metal / metal, metal / nonmetal, metal / marine fouling), galvanic protection, height and depth of the space, the crevice interior / crevice exterior surface ratio and the number of crevices is essential factors. The design of the equipment and packages, and how they are assembled and operated are critical. From an operational perspective, simply greasing the interstices may be enough to delay initiation of crevice, but it is not a guaranteed solution that can be used to avoid employing more alloyed materials. It remains a possible precaution to be taken for a sensitive material, “for lack of anything better”.

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Critical Crevice Temperature (CCT[2]) is an indication of the temperature from which crevice corrosion can occur in a defined environment: however, determination methods (e.g., ASTM G48, [9]) are rarely representative of the actual environment to which the material is subjected, because measured in a standard solution, which can be far from the one really presents in any application. The Critical Crevice Temperature is below the Critical Pitting Temperature, because of the detrimental effect of the interstice during the initiation phase.

3.3.10.4. Impacted units or equipment Confined areas such as areas under seals or under deposits are the most impacted, as well as confined areas of expanded tube-to-tube/sheet faces, mechanical equipment, areas with many gaskets, valves, etc. Capillary tubing’s in stainless steels are also known to experience crevice corrosion around the clamps on offshore facilities. On the other hand, internal crevice corrosion is quite rare inside production facilities provided no accidental oxygen ingress occurs.

3.3.10.5. Aspect or morphology of the damage

Figure 28. – Crevice corrosion of austenitic stainless steel under gasket.

3.3.10.6. Prevention / Protection Prevention requires both optimized design and appropriate operating practices: Design: • Use suitably alloyed materials for the expected service conditions; take into consideration the most severe, even exceptional conditions;

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• Avoid narrow areas as much as possible (avoid connections with sharp bends, properly position and tighten joints between flange seats, prefer welded joints, reduce the number of flanged joints as much as possible, avoid riveted joints, etc.); • Paint, or apply a coating to surfaces exposed to seawater or to a marine atmosphere; • Cathodic protection is an excellent solution for preventing crevice corrosion of stainless steels, including with steel equipment in close proximity. Manufacturing: The welding practices as well the weld shape can promote crevice corrosion; welds must be fully penetrated, without gutters nor insufficient or excess penetration. Operations: • Control chlorine levels or dissolved oxygen levels in circuits for which corrosion control depends on one or another of these factors; • Avoid the accumulation of deposits, or the growth of algae or shells on the surface: include cleaning in routine maintenance programs; • Reduce the amount of debris that can settle on the metal surface leading to interstices that are prone to crevice and under deposit corrosion (filters, slopes on pipes, pressure rinsing); • Consider the use of sealants to seal interstices or threading (grease, glue). These products must be compatible with the process, their use must be submitted to a change management review; • Consider the encapsulation of flanges and use of corrosion inhibitors for their protection.

3.3.10.7. Inspection and monitoring Visual inspection when crevice is accessible. Ultrasonic testing methods: Techniques based on phased array emitters have been developed to inspect joints and bolts. Radiography and eddy currents can be used as inspection techniques for specific configurations; the results may not always be reproducible.

3.3.10.8. Associated mechanisms • Pitting Corrosion (DM#P9); • Certain forms of MIC (DM#P4); • Under Deposit Corrosion (DM#P6) and corrosion in the presence of living organisms (barnacles), etc.

94 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.10.9. References 1

ISO 8044:2020 Corrosion des métaux et alliages – Termes principaux et définitions, ICS: 01.040.77; 77.060.

2

NACE/ASTM G193, Standard Terminology and Acronyms Relating to Corrosion, 2021 Edition, December 15, 2021.

3

Corrosion Mechanisms in Theory and Practice, Third Edition, Edited by Philippe Marcus, CRC Press., International Standard Book Number 13: 978-1-4200-9463-3 (eBook – PDF), Copyright © 2012 by Taylor & Francis Group, LLC.

4

Traité des matériaux, Volume 12, Corrosion et chimie de surface des métaux, Dieter Landolt, © 1993, Presses Polytechniques et universitaires romandes, ISBN 2-88074-245-5.

5

Carol Powell and Peter Webster, Copper Alloys for Marine Environments, Copper Development Association, CDA Publication No 206, May 2011, Revised December 2012.

6

Oldfield, J. W. and Sutton, W. H., “Crevice Corrosion of. Stainless Steels A. Mathematical Model,” British Corrosion. Journal, Vol. 13, No. 1, 1978, pp. 13-22.

7

Mechanism for Barnacle-Induced Crevice Corrosion in Stainless Steel, M. Eashwar, G. Subramanian, P. Chandrasekaran, K. Balakrishnan, Corrosion, Volume 48, issue 7, July 1992.

8

The corrosion of Copper and Its Alloys: A Practical Guide for Engineers, Roger Francis, © 2010, NACE International, ISBN 978-1-57590-225-8.

9

ASTM G48-11(2020): Standard Test Methods for Pitting and Crevice Corrosion Resistance of Stainless Steels and Related Alloys by Use of Ferric Chloride Solution.

10

Principles of Metallic Corrosion, 2nd edition, 1973, J.P. Chilton, Publisher London Chemical Society (Royal Institute of Chemistry Monographs for Teacher) (1973), ISBN-13: 978-0854040278.

11

The Fundamentals of Corrosion, 3rd edition, 1990, J.C Scully, Pergamon Press, ISBN-13: 978-008378749.

12

Corrosion Engineering, 2nd Edition, Mars G. Fontana, Norbert D. Greene, McGraw-Hill Series in Materials Science and Engineering, Copyright © 1978, 1967, ISBN 0-07-021461-1.

13

Livre Multimédia de la Corrosion, INSA de Lyon, Laboratoire MATEIS CorrIS, http://www.cdcorrosion.com/corrosion_version_web.html.

14

Philibert, Vignes, Bréchet, Combrade, Métallurgie du minerai au matériau, 2nd edition, 2013, Dunod, ISBN 10 : 210059754x, ISBN 13 : 9782100597543.

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3.3.11. Mercury Induced Cracking of Aluminum Alloys (DM#P11) & Aluminum Alloys Amalgamation and Amalgam Corrosion (DM#P12) Mercury (in its native state or in the form of organic mercury compounds) can cause damage to certain aluminum alloys when in contact with them. The sources of mercury are identified for the E & P domain in [1]. The harmful effects of mercury on aluminum alloys have been known in the aviation industry since the 1940s. In 1973, they were highlighted on cryogenic heat exchanger tubes from the LNG plant at Skikda (Algeria) [12, 13, 18]. Following the failure, ensuing studies showed that corrosion also occurred on manifolds of Groningen field, in the Netherlands, where the mercury concentration varied between 0.001 and 180 µg/Nm3 [13]. Mercury is deposited in equipment (usually the exchangers) by condensation of vapors or precipitation of mercury dissolved in liquid hydrocarbons. The phase transition can be caused by cooling in an exchanger or Joule-Thomson effect through a valve. Mercury can accumulate in equipment as liquid or solid deposits. In cold fluids, solid mercury particles can be transported over long distances; as a result, the deposits are often present in areas where the circulation of the fluid is weak and far enough from the point of initial condensation or precipitation.

3.3.11.1. Description of the damage Damage caused or accelerated by the presence of mercury, or its salts essentially include: • The formation of amalgams of aluminum or its alloys. Amalgams have a low mechanical strength; • Corrosion of the aluminum alloy by amalgams in wet environments; • Embrittlement under the action of liquid mercury (LME, LMIE, LMIC) of certain aluminum alloys. In the presence of an electrolyte, the galvanic aspect must also be considered; it is related to the potential difference between the mercury and the different phases of the aluminum alloy. Also, it is important to mention the loss of thermal efficiency related to the formation of deposits. Some aluminum alloys are also sensitive to intergranular corrosion, IGC and/or SCC, in a wet environment containing mercury. Damage to aluminum alloys due to mercury is influenced by: • The physical state of mercury: it must be in the liquid state to produce the damage; • The presence and the nature of the surface layer of alumina: if the metal surface is covered with a rather hard protective layer of alumina, this layer

96 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

curbs the access of mercury to the surface of the metal, even though it is not a reliable barrier. Alumina is not homogeneous and has many flaws such as cracks. Usually, the mercury cannot reach the underlying metal surface by capillarity through the defects of the alumina layer because its surface tension is too high; • The low solubility of aluminum in mercury (0.002%). However, the solubility of other elements in common aluminum alloys is higher [5]; • Strong dependence on the metallurgical structure, the microstructure, and the presence of phases at the grain boundaries.

1. Amalgamation and corrosion of aluminum alloys by their amalgam An amalgam is an alloy of mercury and another metal. Almost all metals can form amalgams. For the metals commonly used in the EP sector, the exceptions are mainly iron, tungsten, and tantalum [4]. Amalgamation is the process by which mercury forms liquid solutions with different metals, including aluminum, zinc, and magnesium. Water is not required for the development of the process. The amalgamation reaction with aluminum is: x Hg  y Al  Hg x . Al y The formation rate of an amalgam depends essentially on the solubility of the metal phases forming the amalgam, the metallurgical structure, and the microstructure of the aluminum alloy. Amalgams form preferentially on the heat-affected zones of welds, and they form more rapidly with certain alloys. The foremost sign of amalgam formation is the loss of mechanical strength of welded joints. If the continuity in the alumina layer is flawed, then the mercury can come into contact with the metal surface, thereby resulting in amalgamation. It is limited by the rate of diffusion of the alloying elements in the mercury. In this case, the corrosion is manifested by pitting. Immediately after contact with an aqueous phase, the alumina film undergoes a dynamic process of cracking and reforming at film defects (often at grain boundaries). The film reforming process, if it occurs, depends on the composition of the environment. In the specific case where mercury is present, the Hg2+ ions can be reduced directly on the aluminum surface, resulting in a metal-to-metal contact, initiating surface diffusion. This results in the formation of an amalgam. Aluminum atoms diffuse through liquid mercury and are oxidized at the amalgam / electrolyte interface. The aluminum amalgam is oxidized by water, the aluminum metal is converted to hydrated alumina and mercury is released (see figure 31). Corrosion by the aluminum amalgam becomes auto catalytic: 2 Al  3 Hg 2   6 H 2 O  Al2 O3 , 3 H 2 O  6 H   3 Hg, reduction of the Hg2+ ions

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This is a typically redox process, related to the potential difference of the redox couples in the water. x Hg  y Al  Hg x . Al y , formation of an amalgam 2 Hg x . Al y  6 y H 2 O  y Al2 O3 , 3 y H 2 O  2 x Hg  3 y H 2 , regeneration of mercury Aluminum amalgam-induced corrosion does not consume mercury. Consequently, it continues to propagate as long as the mercury remains in contact with the metal surface of the aluminum alloy and provided water is available. The corrosion rate can be rapid, it is limited by the mass transfer and the thickness of hydrated alumina produced by corrosion. The hydrated alumina is very bulky, therefore the access of water to the metal surface and that of the amalgam is limited. Amalgam-induced corrosion is accelerated in the presence of O2. The difference between amalgamation and corrosion due to the amalgam is that the latter requires water to propagate, and only very small amounts of Hg. This condition is particularly satisfied during equipment maintenance and inspections. Amalgam-induced corrosion is not a mechanism that develops in cryogenic heat exchangers in operation. If the humidity is high and there is enough mercury, the process can accelerate significantly, although not as much as for the LME. This process leads to the detachment of the alumina layer by cleavage; the morphology of the attack resembles large cavities. If only pure water is present, and the atmosphere is inert, the base metal in the amalgam is corroded gradually by reaction with water. The presence of aggressive ions is not required for the inception of the mechanism.

2. Mercury Induced Cracking of Aluminum Alloys Known as Liquid Metal Embrittlement (LME) or Liquid Metal Induced Cracking (LMIC), or Liquid Metal-Induced Embrittlement (LMIE), this is a phenomenon whereby the tensile strength characteristics and the resilience of the alloy drop in environments containing mercury. This mechanism develops under the effect of stress, regardless of whether it is internal or external. According to the classification reported by the ASM, [19], the embrittlement mechanism could be type 1 (leading to instant fracture), or of type 2 (leading to delayed fracture). Note: According to some authors, corrosion mechanisms controlled by the intergranular diffusion of a liquid metal atoms in a solid metal that occur under zero stress or independently of stress (case of intergranular corrosion of aluminum by liquid gallium), are considered to be induced by liquid metals and do not strictly refer to the LME, however, they appear to meet the definition of LME type 3 reported by ASM. All the models that have attempted to explain the LME mechanism consider that the lowering of surface energy of the solid metal induced by adsorption is the essential cause of LME [3]. The AIRC (Adsorption Induced Reduction in Cohesion) is the most widely accepted current model, but it does not explain all the experimental results.

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The prerequisites are: • The presence of external stress; • The presence of pre-existing cracks or limited plasticity and the presence of obstacles to dislocation movements, for example grain boundaries, precipitates; • Adsorption of an active species on the obstacles at the top of active cracks. From an empirical perspective, LME susceptibility is a function of the mutual solubility limit of the metals present. Excessive solubility makes it difficult to propagate fine cracks, but the lack of solubility prevents wetting of the solid surface by the liquid metal and prevents LME. The difference in surface energy between liquid and solid metals and the energy at the grain boundary of the solid metal strongly affects LME. The energies depend on the chemical composition of the alloy. LME kinetics are very difficult to predict quantitatively, the rate of crack propagation varies from a few centimeters to several meters per second, an incubation period precedes cracking. The various damage mechanisms induced by the presence of mercury are shown in a diagram in figure 29.

Figure 29. – Corrosion Mechanisms of Aluminum Alloys in presence of mercury.

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99

In wet environments, electrochemical corrosion mechanisms such as intergranular corrosion (IGSC), or stress corrosion cracking (SCC), can also develop on aluminum alloys of the 2000, 5000, and 7000 series, especially those in the T6 state (tempered, tempered, over-annealed), in competition with the LME.

3.3.11.2. Impacted materials All aluminum alloys are potentially affected by the formation of amalgam, and corrosion by aluminum amalgam. However, the rate of amalgam formation is lower with alloys that do not contain magnesium. Magnesium and cadmium can increase the severity of the attack, whereas others such as Zn decrease it. Mg forms with Al a phase which precipitates at the grain boundaries in the solid metal and makes the grain boundaries more susceptible. Maximum LME is observed when additions of alloying elements segregate at the grain boundaries of the solid metal. The hardness and deformation properties of the solid metal affect its susceptibility to LME. Hard metals are usually more severely embrittled. Grain size affects LME; coarse grains suffer. Aluminum alloys in the 2000, 5000 and 6000 series are the most sensitive to LME and stress cracking in mercurial environments: they contain from 0.2% to 6% magnesium, which gives them greater mechanical resistance in annealed conditions. Welding or soldering products also contain magnesium. Alloys containing more than 2 - 3% magnesium tend to become more sensitive due to the precipitation of an intermetallic compound, Al3Mg2 (β phase). This compound segregate at the grain boundaries during welding, thereby rendering the microstructure more sensitive to damage. The mercury reacts by forming an Hg-Mg intermetallic compound that is insoluble in the mercury contained in the cracks. Hg  Al3 Mg 2



Hg 2 Mg + 3Al

Because mercury attacks Al3Mg2 at the grain boundaries, the damage mechanism associated with Al-Mg alloys is specifically intergranular.

3.3.11.3. Critical factors The basic elements required to degrade aluminum alloys in mercurial conditions are: • The presence of liquid mercury: mercury is in a liquid state from –38.9 °C to +357 °C, at atmospheric pressure; amalgamation can only occur within this temperature range; • Cracks or porosities in the alumina layer: this condition is necessary because the oxide on the surface must be degraded for a physical contact to occur between the mercury and the aluminum; • Presence of liquid water: at atmospheric pressure, the water is liquid at 0 °C (case of amalgamation corrosion); • For LME development: residual or applied stress.

100 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

The grade and microstructure of the metal in contact must be sensitive to attacks; this is necessary for the initiation and the propagation of the damage. If the mercury concentration in the natural gas is higher than 0.1µg/Nm3, then the use of a Mercury Removal Unit (MRU) is recommended. IPIECA recommends limiting the mercury concentration to an average of 10 μg/kg in liquid feeds for refining [2].

3.3.11.4. Impacted units or equipment The damage to aluminum alloys under the effect of mercury concerns essentially the following: • Diverging pipes and expansion turbines [12]; • Cryogenic heat exchangers made of aluminum alloys, located in gas liquefaction units [16]; • Pumps; • Pipe systems [17]; • Cryogenic exchangers in gas purification units used in ethylene manufacturing [15].

3.3.11.5. Aspect or morphology of the damage If the mercury deposits are isolated and liquid water is present, then the corrosion by amalgamation is characterized by pitting. The pit spreads when the equipment is hot, and water is collected in areas covered with mercury.

Figure 30.  –  Separation of the plates in a cryogenic exchanger core due to the formation of an amalgam.

3 – Description of Damage Mechanisms

101

Figure 31.  –  Hydrated alumina resulting from corrosion of an aluminum alloy by an amalgam.

LME is characterized by intergranular or transgranular cracks: figure 32 shows an intergranular attack by LME of a component of an A5083 alloy in a cryogenic heat exchanger.

Figure 32.  –  LME cracking of an Al-Mg alloy, attack at grain boundaries (cross section, optical microscopy).

Figure 33.  –  LME cracking of a weld on a cryogenic aluminum heat exchanger. This crack caused the failure of the heat exchanger.

102 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.11.6. Prevention / Protection The prevention of amalgamation corrosion of aluminum alloys and their protection can be achieved by: • Action on the process; • Action on the equipment; • Appropriate outage managing procedures. Action on the process: mercury is removed from hydrocarbons in Mercury Removal Units (MRU); various technologies are available from different vendors [14]. MRUs comprize beds filled with an adsorbent, which achieves both adsorption and chemical reactions. The adsorbent is designed first to extract elemental mercury in the vapor state. Methods for removing the mercury from the gas are based on the principles of adsorption and chemical sorption, in which a microporous adsorbent is impregnated with elemental sulfur. The reaction forms stable mercury sulfide. Action on equipment: • Surface treatment of equipment: some surface treatments of aluminum alloys, such as fine ceramic coating or anodization are sometimes used to protect metal surfaces; • Selection of alloys: some manufacturers of BAHX cryogenic heat exchangers offer mercury-tolerant designs [11] based on the use of aluminum alloys that are not sensitive to LMIC; • Equipment design: a design that avoids the formation of dead legs in which mercury might accumulate [11]. Equipment shutdown: The preparation of equipment for handover to maintenance must consider decontamination (hot-gas flushing, drainage, inerting).

3.3.11.7. Inspection and monitoring Inspection methods: Owing to their design, it is extremely difficult to inspect those areas of BAHX heat exchangers that may be subject to mercury deposition. In some cases, liquid mercury deposits can be detected by X-ray, provided they are sufficiently large and accessible. They can also be detected by assisted visual inspection. In some cases, pits and a white color can be observed by assisted visual inspection. Areas corroded by amalgam formation can be detected by radiography in certain configurations or by assisted visual inspection. Pipes, expansion valves, diverters, and expansion turbines can be easily inspected by X-ray.

3 – Description of Damage Mechanisms

103

Monitoring methods: Monitoring consists primarily of measuring mercury in the gas or liquid streams, upstream and downstream of MRUs, and during decontamination of the systems. Some analytical methods for measuring mercury in gases are described in documents [6, 7, 8]. Few methods exist for monitoring mercury in liquids; the most frequently used are described in documents [9, 10]. Many online analyzers, essentially based on the principle of atomic fluorescence spectroscopy are available on the market.

3.3.11.8. Associated mechanisms All mechanisms of amalgam formation and corrosion by amalgams of other metals. All mechanisms causing the embrittlement of metal alloys by solid metals (SME / SMIE).

3.3.11.9. References 1

Mercury in Petroleum and Natural Gas: Estimation of Emission from Production, Processing, and Combustion, Prepared by National Risk Management Research Laboratory, September 2001, EPA/600/R-0-066, United States Environmental Protection Agency.

2

Mercury Management in Petroleum Refining, an IPIECA Good Practice Guide, 2014.

3

Technical report No 1, DA-ARO-D-31-214-71-G124, Embrittlement by Liquid Metals, April 1972, H. Kamdar.

4

E.I. Troyansky, M Baker, Aluminum Amalgam, Encyclopedia of Reagents for Organic Synthesis, John Wiley & Sons, April 2001, ISBN: 9780471936237.

5

Mercury Handbook Chemistry, Applications and Environmental Impact, ©Leonid F Kozin and Steve C Hansen, 2013, ISBN: 978-1-84973-409-7, RCS Publishing.

6

ASTM D6350-14: Standard Test Method for Mercury Sampling and Analysis in Natural Gas by Atomic Fluorescence Spectroscopy.

7

ISO 6978-1:2003 reviewed 2020 Natural Gas – Determination of mercury – Part 1: Sampling of mercury by chemisorptions on iodine.

8

ISO 6978-2:2003 reviewed 2020 Natural Gas – Determination of mercury – Part 2: Sampling of mercury by amalgamation on gold/platinum alloy.

9

UOP 938-10: Total Mercury and Mercury Species in Liquid Hydrocarbons.

10

ASTM 7623-10: Standard Test Method for Total Mercury in Crude Oil Using Combustion-Gold Amalgamation and Cold Vapor Atomic Absorption Method.

104 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

11

Brazed aluminum plate fin heat-exchangers – construction, uses, and advantages in cryogenic refrigeration systems, Dan Markussen, Larry Lewis, April 10 - 14, 2005; Spring meeting of the American Institute of Chemical Engineers, Atlanta.

12

Liquid metal embrittlement (LME) of the 6061 Al-alloy by mercury, Behzad Bavarian, Corrosion 2004, Paper No 04558, NACE.

13

Innovative approach to the mercury control during natural gas processing, Zdravko Spiric, INA-Naftaplin, Zagreb, Croatia, ETCE2001-17085, February 5-7, 2001, Houston, TX.

14

Mercury removal from natural gas and liquid streams, John Markovs & Jack Corvini, UOP, Des Plaines Illinois & UOP Houston, Texas.

15

Risk Analysis for Operation of Aluminum Heat Exchangers Contaminated by Mercury, S. Mark Wilhem, Mercury Technology Services, Tomball, TX 77377.

16

Corrosion failures in plate heat exchangers, R.L. Turissini; T.V. Bruno, E.P. Dahlberg, R.B. Setterlund; Paper No 522; Corrosion97, NACE.

17

Mercury Liquid Embrittlement Failure of 5083-O Aluminum Alloy Piping, Jerome J. English, Handbook of Case Histories in Failure Analysis, Vol 2, K.A. Esakul, Ed, ASM International, 1992.

18

Electrochemical Study of Aluminum Alloy AA5083 Corrosion Induced by Elementary Mercury in LNG Industries, D. Zeroualy, Z. Derriche, M.Y. Azri, Journal of Applied Sciences, 6 (11) 2491-2495, (2006), ISSN 1812-5604.

19

Liquid Metal and Solid Metal Induced Embrittlement, William R. Warke, ASM Handbook, Volume 11: Failure Analysis and Prevention, W.T. Becker, R.J. Shipley, editors, p861-867, DOI: 10.13-1/asmhba0003554, Copyright© 2002 ASM International.

3.3.12. Stress Corrosion in the presence of H2S for CRAs (DM#P13) 3.3.12.1. Description of the damage In H2S environments, corrosion-resistant alloys can be affected by several cracking corrosion mechanisms: • Sulfide Stress Cracking (SSC): is a phenomenon of “hydrogen embrittlement” in which H2S favors the charging of hydrogen in the metal. This damage corresponds to DM#2, which concerns carbon and low-alloy steels, as well as some stainless steels, as indicated below; • Stress Corrosion Cracking (SCC): this is a classical corrosion phenomenon that occurs when stress is applied to so-called “passive” materials, such as stainless steels or nickel alloys [1]. It results from local depassivation induced

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by the applied stress. In addition to the usual environmental factors of stress corrosion without H2S (oxidizing environment, chloride content and temperature), H2S also acts as an additional depassivation factor. Table 1 is based on the international standard NACE MR0175 / ISO 15156 [2]. It defines the degree of susceptibility of corrosion-resistant alloys to various cracking corrosion mechanisms in H2S environments. GHSC refers to Galvanic Hydrogen Stress Cracking, which is a hydrogen assisted cracking mechanism Hydrogen Stress Cracking HSC), since in this case, the material is the cathode of the galvanic couple with carbon or low alloyed steel. Table 4.  –  Susceptibility of CRAs to different SCC mechanisms in H2S environments [2]. Cracking corrosion mechanisms in H2S environments

Materials

SSC

CSC

GHSC

Austenitic stainless steels

S

P

S

High-alloy austenitic stainless steels

-

P

-

Solid solution nickel alloys

S

P

S

Ferritic stainless steels

P

-

P

Martensitic stainless steels

P

S

P

Austeno-ferritic stainless steels (Duplex)

S

P

S

Stainless steels obtained by precipitation (or age) hardening

P

P

P

Nickel alloys obtained by precipitation (age) hardening

S

P

P

Cobalt alloys

S

P

P

Titanium and tantalum

depend on the type of the alloy

Copper and aluminum

not affected by such damage

P indicates that the cracking mechanism is primary S indicates that a secondary cracking mechanism is possible

Of the three mechanisms listed above, this chapter deals only with the Stress Corrosion Cracking (SCC) mechanism in the presence of H2S. This mechanism can affect corrosion-resistant alloys (CRAs) when they are in contact with water containing chlorides and dissolved H2S. The mechanism does not concern carbon steels or low-alloy steels in the acidic environments encountered in oil production. However, it is important to note that although embrittlement and stress corrosion phenomena result from distinct mechanisms and factors, they are not exclusive of each other. Thus, most CRAs may be susceptible to hydrogen embrittlement (SSC) at moderate temperature, HSC at different temperatures depending on the grade/family and to stress corrosion cracking (SCC) at higher temperatures (Refer to NACE MR0175/ISO 15156-3).

106 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.12.2. Impacted materials All so-called passive metal materials are potentially sensitive to stress corrosion cracking in H2S environments, according to the sensitivity indications in table 1: • Stainless steels; • Nickel alloys; • Titanium and its alloys, Tantalum. Copper and aluminum alloys are not known to be affected by stress corrosion damage in H2S environments, but in practice they are rarely used in such environments. On the other hand, they can undergo mass loss corrosion because the same parameters cause this damage.

3.3.12.3. Critical factors Stress corrosion cracking in H2S environments depends on the main parameters below, which are classified into three categories. The parameters in each category are ranked by order of decreasing influence: • Environmental factors: ○ Temperature is the decisive environmental factor of sensitivity. Depending on the materials and environment, the “critical temperature” can vary from 50–60 °C to over 150 °C, ○ The level of stress/strain experienced is also a decisive factor for resistance to SCC, ○ Pressure can have an indirect effect on both the H2S partial pressure and on levels of stress suffered by the equipment. It does not have a significant direct effect. The presence of CO2 affects the pH, • Factors related to the fluid (supposedly hydrated): ○ The concentration of chlorides or other halides, ○ The presence of liquid or solid sulfur, in combination with the presence of water, ○ The partial pressure of H2S or an equivalent concentration of H2S dissolved in water, ○ The pH of the aqueous phase: while this factor is essential for sulfide stress cracking, its effect is moderate with respect to SCC, at least within the pH range of 4 to 7. It is sensitive only in environments with very low pH values (pH 7-8) in which the sensitivity is usually lower, • Factors relevant to the material: ○ The yield strength, resulting either from a heat treatment (quenchingtempering, structural hardening) or thermomechanical processes (cold working, forging...): materials with high mechanical properties are usually the most sensitive, ○ The chemical composition, more particularly the resistance-enhancing composition of the passivation layer. The Pitting Resistance Equivalent Number (PREN) provides a ranking of the alloying element effect,

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107

○ The microstructure (grain size and orientation, presence of precipitates and/or unwanted phases) related to the material quality and especially to the manufacturing and assembly method, ○ The finishing condition of the material.

3.3.12.4. Impacted units or equipment All production equipment made of corrosion-resistant alloys (CRA) and in contact with a wet fluid containing H2S is potentially concerned by H2S induced stress corrosion (producing wells, pipelines, and fluid treatment facilities). As the chloride concentration plays a dominant role in triggering this type of damage, it is rarely observed in gas compression units where chloride concentrations are negligible. However, care must be taken to avoid areas where chloride accumulation might occur and poorly designed equipment and pipe systems in which salty produced water can circulate in the system. Conversely, such damage is likely if inappropriate materials are chosen for hightemperature production wells (HT or HPHT wells), process units in contact with salty produced water at temperatures above 50–80 °C, produced water treatment units, etc.

3.3.12.5. Aspect or morphology of the damage The material usually does not show any visible signs of corrosion. Metallographic examination of cracked specimens generally reveals transgranular cracks. Cracks are sometimes initiated from pitting. Cracks initiated in the inner wall may be open or non-open.

Figure 34.  –  Cracks due to stress corrosion in H2S environments [5].

108 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

3.3.12.6. Prevention / Protection Prevention requires an optimized choice of materials: corrosion-resistant alloys (CRA) must be selected for the most severe environmental conditions. International standard NACE MR0175/ISO 15156 [2] sets limits of use for all CRAs commonly used in the petroleum industry. These limits can also be corrected, under the responsibility of the user, based on documented experience in comparable or more severe environments, or from Fit for Purpose tests in conditions representative of the intended use. In addition to the choice of material, additional prevention relates to the design of the facilities, for example the avoidance of excessively severe environmental conditions by monitoring the maximum temperatures, a facility design supporting maximum elimination of chlorides, prevention of any oxygen entry... Finally, in addition to selecting the appropriate CRA material, manufacturing and welding inspections must never be neglected, to avoid inappropriate microstructures, large grains, unwanted precipitates, and intermetallic phases (e.g., the sigma phase of duplex stainless steels): no material is good without a good quality control of the manufacturing and assembly.

3.3.12.7. Inspection and monitoring As SCC is a fast-developing corrosion process which can be controlled by the choice of fully resistant material, no systematic method exists to monitor the occurrence of such cracking (unlikely occurrence, due only to an error in design, manufacturing, or assembly). On the other hand, there are tools that monitor the occurrence or progression of SCC cracks, if their occurrence is suspected or known: • Dye Penetrant testing (or Dye penetrant inspection) is one of the most widely used methods, but it is effective only for emergent cracking; • Eddy current and X-ray testing are also used; • Acoustic emission is used to monitor the initiation and development of cracks; • Finally, the operating conditions must be reviewed on a regular basis to ensure that they remain within the permissible operating range, to avoid jeopardizing the resistance of the selected materials. The most important factors to check for are the chloride contents, maximum temperatures and any presence of oxygen or sulfur deposits; these should serve as a signal to reassess the resistance of the potentially impacted materials.

3.3.12.8. Associated mechanisms • Sulfide Stress Corrosion Cracking (SCC) (DM#2); • Chloride Stress Corrosion Cracking (DM#23);

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• Hydrogen Stress Cracking (HSC): This is a “hydrogen embrittlement” phenomenon similar to the SSC induced by H2S, but in which the cathodic protection or a significant corrosion, including a galvanic corrosion where the CRA is the cathode, cause hydrogen to enter the metal instead of being induced by H2S [6].

3.3.12.9. References 1

P. Lacombe, B. Baroux, G. Beranger, “Stainless Steels”, Les Editions de physique, ISBN n° 978-2868831897, 1993.

2

ANSI/NACE MR0175/ISO 15156, Petroleum, and natural gas industries – Materials for use in H2S-containing environments in oil and gas production, part 1, part 2 and part 3, International Standard, 2015.

3

NACE TM0177, Laboratory testing of metals for resistance to sulfide stress cracking and stress corrosion cracking in H2S environments, International Standard, 2016.

4

EFC 17, Corrosion resistant alloys for oil and gas production: guidelines on general requirements and test methods for H2S service, Maney Publishing, May 2002, ISBN 978 1 902653 556.

5

D. Zuili, A. Didot, S. Chapuis (TechnipFMC), Journée Technique de la Corrosion – Institut de Soudure, Case of cracking due to chloride stress corrosion cracking in a gas treatment unit, Sept 2012.

6

M. Sofia Hazarabedian, Andreas Viereckl, Zakaria Quadir, Garry Leadbeater, Vladimir Golovanevskiy, Skjalg Erdal, Paul Georgeson, and Mariano Iannuzzi, Hydrogen Induced Stress Cracking of Swaged Super Duplex Stainless Steel Subsea Component, Corrosion Journal, July 2019, Vol. 75, Issue 7.

4

Corrosion Prediction

4

This chapter relates to the prediction of corrosion in the main oil and gas production units and utilities focused on the most usual configurations and processes. It concerns the production units and utilities listed in table 5 and presented on Block Flow Diagrams P0a to P0c. Table 5.  –  List of oil and gas production units and associated utilities. PFD Reference

Unit name

Section

PROCESS P01a

Oil receiving and separation unit (CO2 only)

4.3.1

P01b

Oil receiving and separation unit (CO2 + H2S)

4.3.2

P02a

Gas/condensate receiving and separation unit (CO2 only)

4.3.1

P02b

Gas/condensate receiving and separation unit (CO2 + H2S)

4.3.2

P03a

Wet gas compression unit (CO2 only)

4.3.3

P03b

Wet gas compression unit (CO2 + H2S)

4.3.3

P04a

Acid gas removal unit (CO2 only)

4.3.4

P04b

Acid gas removal unit (CO2 + H2S)

4.3.4

P05a

Gas dehydration unit - triethylene glycol – TEG (CO2 only)

4.3.5

P05b

Gas dehydration unit - triethylene glycol – TEG (CO2 + H2S)

4.3.5

P06

Gas dehydration – molecular sieve

4.3.6

P07

Sulfur removal unit (SRU)

4.3.7

P08

Tail gas treatment unit (TGTU)

4.3.8

P09a

Condensate stabilization (CO2 only)

4.3.9

P09b

Condensate stabilization (CO2 + H2S)

4.3.9

P10

CO2 recovery unit

4.3.10

112 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

PFD Reference

Unit name

Section

UTILITIES U01

Produced water treatment unit

4.4.1

U02

Sea water injection & cooling

4.4.2

U03a

Cooling water network (semi-open loop)

4.4.3

U03b

Cooling water network (closed loop)

4.4.4

U04

Hot water network

4.4.5

U05

Steam generators & steam network

4.4.6

U06a

Sea water desalting unit by reverse osmosis

4.4.7

U06b

Sea water desalting unit by ejecto-compression

4.4.7

U07

Air unit

4.4.8

U08

HP/LP flare network

4.4.9

U09

Closed drain network

4.4.10

U10

Open drain network

4.4.11

P0a: Oil and Gas Separation and Produced Water Treatment

Figure 35. – Oil and Gas Separation, Produced Water Block Flow Diagram.

4 – Corrosion Prediction

P0b, Condensate and Gas Separation

Figure 36. – Condensate and Gas Separation Block Flow Diagram.

P0c: Gas Treatment

Figure 37. – Gas Treatment Block Flow Diagram.

113

114 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

The processes that can be implemented in each production unit and utility are covered in the general presentation at the beginning of the sections. Potential damage mechanisms are established for the most widely used processes in the E & P sector. The sensitivity of the various pieces of equipment to the damage mechanisms is based on the methodology described in section 4.1.

4.1. Evaluation of the sensitivity to the different damage mechanisms Damage mechanisms such as corrosion (mass loss), creep and fatigue can lead to loss of equipment integrity through a continuous time-dependent process. Stress corrosion mechanisms lead to the loss of integrity by a discontinuous process whose dependence on time is not necessarily so continuous. The sensitivity to the damage mechanisms is defined on the basis of the characteristics below: • Materials: except in explicitly mentioned cases, standard carbon steel (C ≤ 0.25% weight, carbon equivalent ≤ 0.45% by weight) is considered. It is assumed to have not undergone any additional heat treatment other than those required by manufacturing specifications; • Equipment and pipes are built with a corrosion allowance of 3mm over the minimum design thickness; • The damage mechanisms in the simplified process diagrams are defined with respect to standard operation of the unit in consideration. The damage mechanisms given in the text may relate to transient or abnormal operating conditions sometimes encountered; • Sensitivity to the expected damage: the expected damage can lead to loss of equipment integrity in the short - to long term: ○ For damage leading to a continuous decrease in thickness and/or resistance, the sensitivity is expressed as loss of mass (e.g., uniform corrosion) or loss of integrity (e.g., fatigue). Four sensitivity classes are defined: negligible, low, medium, and strong − their definitions are given in table 6, ○ For damage whose development is not or only weakly time-dependent (e.g., cracking), the sensitivity is qualitatively defined by four classes: negligible, low, moderate, and high, given in table 6. Some approaches (such as the one developed in API RP 581 [1]) can be used to link this indication to a failure probability function.

4 – Corrosion Prediction

115

Table 6.  –  Symbolization of the sensitivity to the damage. Symbol

Damage class

DM

Discontinuous damage process

High

The rate of degradation The sensitivity to the type of can be fast and can alter the degradation is high, strength (by loss of thickness or otherwise), and potentially the integrity, over a period of ten years or less.

Moderate

The rate of damage is mod- The sensitivity to the type of erate, and alters the resist- damage is moderate, ance (by loss of thickness or other), and potentially the integrity, after a service life of ten to twenty years

Low

The rate of damage is low; it is The sensitivity to the type of not presumed to alter the re- damage is low, sistance (by loss of thickness or other), and potentially the integrity before a service life of twenty years

Negligible

The rate of damage is practi- The sensitivity to the type of cally zero, no loss of thickness damage is negligible. or resistance is expected

DM

DM

Continuous damage process

There is no simple correlation between continuous damage processes and discontinuous damage processes.

4.2. Use of simplified process diagrams Each simplified process diagram is shown on two sheets. • The first sheet is annotated with the damage mechanisms that can be encountered (see chapter 3). The number corresponds to the expected damage mechanism and is contained within a symbol indicating the potential sensitivity of the degradation as defined in section 4.1. The meaning of the symbol is given again in table 6. Degradations affecting the piping system are shown in the diagram, whereas those affecting the equipment are indicated in a “notes” column. The damage mechanisms relating to the units described in this document and their influencing parameters are given in the table linked to the diagram; • The second sheet gives a selection of materials that should constitute an optimal barrier in terms of cost and efficiency, with respect to the relevant damage mechanisms.

116 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 38. – Simplified Corrosion Location Diagram & Material Selection Diagram.

4 – Corrosion Prediction

117

4.3. Process 4.3.1.

Receiving and Separation Unit (CO2 only) – P01a and P02a

This chapter deals simultaneously with receiving and separating units for multiphase fluids (gas, oil, and water) mainly processing oil (P01a units) or gas (P02a units). Even though two different process schemes are implemented, the common points between these units do not justify covering them separately.

4.3.1.1. Main damage mechanisms CO2 Corrosion (DM#P1) • It is the most common mode of corrosion in units receiving raw fluids, therefore often containing water; • This type of corrosion is much more severe in cases where H2S is absent (containing only CO2) than where both CO2 + H2S are present (section 4.3.2); • Separators and slug catchers: the risk of CO2 is particularly serious in the lower part of the separators and slug catchers, as the system is almost certainly wet from produced water, as it is for downstream produced water lines. Moreover, these low parts are likely to accumulate solids and bacteria, which often contribute to corrosion, and which lessen the effectiveness of the inhibitor treatments; • Inlet piping in 1st-stage separator (P01) units or slug catcher (P02) units: generally subjected to three-phase flow so the consequences of potential leakage can be serious and increase of the risk can be high. This being said: ○ P01 units (essentially oil production): these upstream multiphase lines may be temporarily preserved from water contact provided the BSW (Basic Sediment and Water) or water cut remain moderate (within a few %). On the other hand, the produced water pipes leaving these units generally undergo this type of corrosion first due to water wetting from the immediate start of production, so they may leak sooner, ○ P02 Units (gas and condensates): the corrosion likelihood is high on upstream three-phase lines as well as on water outlet lines, as light condensates rarely preserve the piping from water wetting despite the high flow rates, • Oil lines leaving separators and slug-catchers: corrosion may be variable depending on the water cut, BSW, the emulsion and the flow rate: ○ P01 units: the water is often emulsified in the oil at the separator outlets, so it is not necessarily permanently in contact with the wall. Corrosion is therefore moderate if the water cut remains moderate ( 150 °C and high salinities (> 200250 g/L), or in presence of H2S (proprietary limits)

AISI 304L and 316L SS

Austenitic (annealed)

Internal cladding, LP/MP Low yield strength. AISI piping, instrumentation 304L SS (or AISI 321 SS) devices, pumps frequently discarded vs AISI 316L SS because of its external susceptibility to marine atmosphere, though sufficient for CO2 corrosion

22 Cr Duplex SS Austenoferritic, annealed

HP piping, vessels, pumps… where its higher YS than AISI 316L SS is a decisive advantage.

No known limit with CO2 only

25 Cr Duplex SS Austenoferritic, annealed

Same as above.

The only reason for selecting 25% Cr instead of 22% Cr is to secure a higher YS.

Note

Limits could be variables according to standards, technical publications, and operational experience.

122 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Preventive solutions for carbon and low alloyed steel If the treated fluid is corrosive, an inhibitor treatment is presumably applied upstream. A biocide treatment can also be applied if potential MIC corrosion is suspected. However, these treatments are at best only for inlet piping, separators, and downstream piping for liquids. The following preventive solutions can be applied to other equipment, in combination with the inhibitor treatment if it touches the relevant equipment: • Internal organic coating preferably combined with cathodic protection: oil separators and low-pressure gas separators. This solution is essential for oil separators, which are very prone to MIC in the lower part, especially if accumulated solids are present. It also provides good protection for the upper part of the vessels subjected to water condensation; • Thermal insulation (and/or heat tracing): for gas separators operating under high temperatures, therefore exposed to TLC-type corrosion, and for gas piping leaving the separator, if there is a possibility of significant condensation and accumulation of condensed water; • Sand jetting device in the lower part of oil separators, to flush out any sand accumulation; • Local use of non-corrodible materials: flow diverters, baffles, elbows, internals not connected to the cathodic protection; • Prevention of oxygen ingress: oxygen ingress in production facilities (regular external water supply, low-pressure vessel leaks, defective blanketing or blanketing with technical nitrogen containing a few % oxygen) should be avoided whenever possible, or otherwise treated with anti-oxygen products, in the case of liquids. This is an essential precaution in operations, especially on P01 units.

4.3.1.3. References 1

Bruce D. Craig and Liane Smith, Corrosion Resistant Alloys (CRAs) in the oil and gas industry – selection guidelines update, 3rd edition, 2011, Nickel Institute Technical Series No 10 073.

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Figure 39.  –  Oil Receiving and Separation Unit (CO2 only), P01a – Corrosion Location Diagram.

124 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 40.  –  Oil Receiving and Separation Unit (CO2 only), P01a – Material Selection Diagram.

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Figure 41. – Gas Receiving and Separation Unit (CO2 only), P02a – Corrosion Location Diagram.

126 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 42.  –  Gas Receiving and Separation Unit (CO2 only), P02a – Material Selection Diagram.

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4.3.2.

127

Receiving and Separation Unit (H2 S + CO2 ) – P01b and P02b

As in section 4.3.1, this chapter deals simultaneously with receiving and separation units of multiphase fluids (gas, oil, and water) mainly processing oil (unit P01b) or gas (unit P02b). A fluid containing H2S in addition to CO2 shall be considered here. It is important to note that the H2S concentration limits are not the same for stress corrosion cracking mechanisms (DM#2) and for mass loss corrosion mechanisms (DM#P2): • Corrosion cracking limits: depending on H2S severity criteria, a few kPa to several tens of kPa of H2S, per NACE MR0175/ISO 15156 sour limits; • Corrosion limits between CO2 corrosion and H2S + CO2 are defined in section 3.0. For intermediate cases, the reader should consider the actual mechanisms that apply, and refer to the appropriate parts of this chapter and the previous one.

4.3.2.1. Main damage mechanisms Wet H2S Induced Cracking (Blistering/HIC/SOHIC/SSC) (DM#2) This term summarizes all the forms of cracking resulting from a combination of H2S dissolved in water with an acidic pH, induced by hydrogen adsorption on the metal surface caused by the corrosion cathodic reaction and adsorption of H2S on the metal surface and subsequent hydrogen permeation in the metal: • Sulfide Stress Cracking - SSC, which is the fastest form of cracking (a few hours in extreme cases), concerns essentially materials with strong mechanical properties and of significant hardness, or with locally very hard areas, such as poorly welded zones. SSC is managed by controlling the mechanical characteristics and welding conditions. In terms of the environment, the severity is divided into 4 categories on the pH – PH2S diagram given in document NACE MR0175/ISO 15156; • Hydrogen Induced Cracking – HIC which particularly concerns laminated and rolled products, i.e., metal sheets used for large pressure vessels and pipes. It is usually not relevant to seamless pipes and tubes, to forged components, etc.; • Stress Oriented Hydrogen Induced Cracking – SOHIC is an uncommon phenomenon when standard-quality materials are used. It mainly concerns welded zones. Materials designed for “H2S service” must be used when H2S severity conditions are met (as per the NACE MR0175/ISO 15156 severity diagram).

128 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

If minimum precautions are applied when selecting and specifying the materials and their assembly and by assuring a minimum manufacturing supervision as per NACE MR0175/ISO 15156, the different forms of corrosion cracking can be avoided. It is not necessary to use corrosion-resistant alloys (CRA) to avoid the types of corrosion cracking mentioned above. Moreover, even if such CRA materials are selected to avoid other types of corrosion given below, they may be susceptible to some types of corrosion cracking as well as to stress corrosion cracking (SCC, DM#13). H2S + CO2 Corrosion (weight loss corrosion) (DM#P2) This is a type of progressive corrosion caused by dissolution of the metal and loss of thickness, usually in localized areas. This type of corrosion is generally less severe than CO2 corrosion alone. It can even be negligible in many cases, except in special conditions and locations: • Low points in which produced water and solid particles (iron sulfides and/or sand) can accumulate, i.e., dead legs, produced water pipes, bottom of vessels or tanks, etc.; • Possible precipitation and deposition of elemental sulfur, potentially leading to very severe corrosion which can exceed rates of 10 mm/year (DM#P8); • Possible oxygen ingress, potentially leading to very severe corrosion. Accidental or regular oxygen ingress in a fluid containing H2S is a major cause of rapid corrosion: particular attention must be paid to this point. The two main factors leading to severe H2S + CO2 Corrosion (weight loss corrosion) are: • A low flow rate favoring the accumulation of water and solid particles, particularly iron sulfides formed upstream; • The presence or ingress of oxidizing contaminants, especially aerated water, or sulfur formation. Conversely, H2S + CO2 Corrosion (weight loss corrosion) is usually hindered by sufficiently high flow rates and by avoiding, wherever possible, unnecessary low points and dead legs. Wet gas lines: little corrosion if the flow rate is sufficient to ensure at least regular evacuation of produced water and solid particles without appreciable accumulation. Ideally, the flow rate should ensure annular flow (liquid film on the wall) or mist flow (> 5 to 8 m/s depending on the system profile, pressure, and fluid composition). Oil or water pipes: same objectives as for gas lines. Flow rates higher than 2 m/s are most adequate.

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Separators and slug catchers: the risk of H2S + CO2 Corrosion (weight loss corrosion) is particularly serious in the lower part because wetting by produced water is practically unavoidable and because of potential accumulation of solid particles (in particular iron sulfides) formed in the upstream lines and pipelines. Inlets of 1st stages of separators (P01 units) or slug catchers (P02 units): corrosion is depending on CO2, H2S, and Liquid – Gas ratio. Oil lines at separator and slug-catcher outlets: corrosion is usually moderate, except in conditions that promote the accumulation of salty produced water and solids (low points and low flow rates and dead legs). Produced water lines at separator outlets: these lines are usually the most subject to the likelihood of perforation by localized corrosion because: • They are systematically water wet; • They are generally thinner than the upstream separator or multiphase lines. Exchanger tubes: these are particularly susceptible to perforation because of their thickness (usually 2 to 3 mm); they are found in: • P01b Units: hydrated oil heaters because reheating promotes separation, and therefore water wetting; • P01b and P02b units: gas coolers because cooling promotes condensation of highly acidic water. In practice, corrosion is an issue where the flow rate is low ( 80–90% of the total condensed volume), the average contact time with water is low; 5. For impellers (with the possible exception of inlet nozzle, 1st impeller when liquid is carried over) and for compressor bodies. Caution should be taken for preservation of standby compressor and settle out conditions; 6. For coolers in which water condensation is negligible, owing to the respective inlet and outlet temperatures. Section 4.3.3.2 also states that sufficiently high flow rates (> 6–8 m/s) help reducing corrosion in cooling tubes. Given the variability of flow over time and the theoretical difficulty of mastering the flow rates, this favorable effect is difficult to factor in when designing a cooler. However, this effect may explain why some coolers resist corrosion over a long period whereas others suffer corrosion in just a few years. Points requiring special attention • In cold or very cold climates, it is recommended installing thermal insulation around water-saturated gas pipes and scrubbers to avoid potential TLC. Usually, the risk of frost alone requires the application of thermal insulation; • Make sure gas pipes without circulation (check valve lines, flare lines, side branches) are inclined and self-draining. If not, water accumulation points are to be periodically inspected; • Make sure the stainless-steel piping of liquid return is homogeneous along their entire length, in particular if it ends in a carbon steel receiving piping: a carbon steel termination has often been used for the end piece (usually a “T”), resulting in severe corrosion. Special attention must be paid to this contact point, to prevent the corrosive fluid coming from the scrubbers from touching any carbon steel point of the receiving equipment. Compression units with H2S 1st priority: use of SSC - HIC-resistant materials Given the risks of H2S-induced cracking, the 1st preventive measure is to always use materials resistant to this form of corrosion and to use appropriate-welding methods which do not lead to a structural and stress conditions favorable to the development of stress corrosion cracking, whether they are carbon steels, stainless steels, or any other metal. Steels or materials resistant against weight loss corrosion? In large facilities with high production rates, corrosion-resistant alloys can be systematically selected for units with H2S service, to reduce risks and inspection

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requirements. This is particularly relevant for equipment classified in the “Usually selected” category in the section above, § 4.3.3.2. However, experience has shown that the use of H2S cracking-resistant carbon steel can provide a service life more than 20 years without any major damage, to wet gas piping, or exchanger tubes provided the bulk gas flow velocity can be maintained above 6 to 8 m/s. This choice can reduce CAPEX, provided the OPEX factors are well managed in the relevant monitoring, inspection, and maintenance requirements. The use of corrosion resistant alloys (CRAs) shall comply with the limits given in standard NACE MR0175/ISO 15156-3, or according to user-specific limits that are documented through experience or specific tests. The choice may strongly depend on the presumed maximum chloride levels from the potential water carry-over from the upstream separators. The scope of use for 300 series austenitic steels and duplex stainless steels is limited to moderate H2S partial pressures which vary with the maximum chloride content. The most common materials for partial pressures exceeding 10 to 100 kPa are nickel alloys (825, 625, ...) or super-austenitic alloys: see table 8 in section 4.3.2.2 concerning separation units. For centrifugal compressor impellers, martensitic stainless steels (17-4 PH, X4CrNi16-4, F6NM...) are commonly used even when the H2S partial pressure exceeds 100 kPa, thus far beyond the limits of such materials for other applications (e.g., production tubing). This is partly due to better stress management for such equipment and to usual absence of chlorides in the water associated with the compressed gas. However, carry-over and regular ingress of chlorinated water in these compressors can rapidly impact the behavior of such materials. Finally, the most critical situation for martensitic materials is encountered for the impeller tightening bolts, when prolonged stoppage under high pressure: these are conditions of maximum stress, while the sensitivity to SSC is also maximum because of the low temperature. When martensitic stainless steels are no longer acceptable, structurally hardened nickel alloys are commonly selected. Points requiring special attention • Same precautions as for units without H2S service; • Pay attention to carry-over of salty produced waters if stainless steel materials are selected for compressor impellers despite high H2S partial pressures: this choice is based on the consideration that the water present will be only slightly chloride contaminated (typically 0.02 – 0.05 mol/mol for the transition from CO2 dominant to H2S + CO2 (depending on the type of amine).

4.3.4.1. Process description An Acid Gas Removal Unit (AGRU), designed for amine-based solvents, comprises two stages: absorption and regeneration, as per simplified flow diagram. Basically, the acid gases (CO2, H2S, and in some cases other sulfur compounds) are absorbed in the solvent absorber at relatively high pressure (0.4 to 17.5 MPa (g)) and low temperature and then released in the regenerator at lower pressure (10 to 100 kPa (g)) and higher temperature. The gaseous feed is contacted by counter-current flow with lean solvent entering the top of the absorber. The absorber consists of a column with trays (or packing). The treated gas leaves the absorber at the top. Upstream and downstream the absorber, knock-out vessels are installed to respectively remove any entrained liquid hydrocarbons from the feed and solvent solution from the treated gas. The temperature of the lean amine supplied to the top of the absorber is kept sufficiently high to avoid condensation of hydrocarbons, which, if it occurred, would promote foaming. The rich solvent leaves the absorber bottom and is heated to 90–100 °C by hot lean solvent from the regenerator in lean/rich solvent heat exchanger(s). After pressure let-down, the rich solvent enters the top section of the regenerator. The regenerator is a column with trays or packing. In most cases, the rich solvent passes through a flash vessel downstream of the absorber to reduce the entrained and dissolved gas. In the regenerator, the rich solvent is heated and stripped of acid gases by a counter-current flow of steam. The steam is generated in a reboiler by boiling the lean solvent taken from the bottom of the regenerator. The reboiler is generally heated by LP steam. The water-saturated overhead vapor from the regenerator, consisting of acid gases, steam, and residual hydrocarbons, goes through an air or water-cooled condenser, a knock-out drum allows the separation of water from the acid gases, the water is

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pumped back to the top of the regenerator, where it can serve as a water wash to reduce solvent entrainment. The acid gases then leave the accumulator for further treatment (e.g., a sulfur unit) or disposal. The hot regenerated lean solvent is pumped from the bottom of the regenerator, which serves as a buffer vessel, via the lean/rich solvent exchanger(s) to the lean solvent air or water cooler, from where it flows to the absorber. Lean and rich solvent (side-stream) filtration, and/or a (lean) solvent reclaimer, may also be installed to maintain solvent purity. The lean solvent is generally stored in a tank; it should be protected from air ingress by blanketing with inert gas to avoid the oxidation of amine. Chemicals packages, such antifoam packages and inhibitor packages, are generally provided; antifoam is injected in case of foaming, generally resulting from entry of liquid hydrocarbons.

4.3.4.2. Main damage mechanisms Wet H2S Induced Cracking (Blistering/HIC/SOHIC/SSC) (DM#2) • Occurs basically in absorbers and in solvent regenerators, both in circuits containing wet stripped H2S and in the return steam zone from the reboiler to the regenerator. Damage also occurs in the acid gas circuit at the top of the regenerator and in the acid gas circuit of the flash drum. Cases of damage (mainly due to SOHIC) have been encountered in the lean amine zone of the absorber and overhead circuit (not designed for H2S service). Erosion-Corrosion (DM#P5) • Erosion-corrosion can occur in areas where fluid flow rate becomes significant, leading to a high shear stress, and downstream of the pressure relief valves or rich/lean solvent exchanger and on the bubble impact zones: when the pressure decreases sharply or the temperature increases, the pressure drops below the vapor pressure of the liquid, large bubbles form and carry the liquid over. The stresses exerted on the wall remove the surface layers, sometimes even the metal itself. Amine Cracking (DM#22) • The probability of occurrence depends on the type of amine, the amount of H2S/CO2 in the solvent, the service temperature, the residual stresses in the metal. Amine cracking occurs more particularly in lean amine circuits. It mainly affects those areas subjected to mechanical stress (welds, areas opposite the pipe or platform supports). The probability of occurrence is very high in units based on MEA or DIPA, whereas it is lesser in units using based on activated MDEA.

152 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Cavitation (DM#28) • Cavitation can occur in valve bodies when conditions promote bubble formation and bottleneck flow, and when the actual differential pressure is slightly greater than the critical differential pressure (specific to each valve). When the bubbles collapse, they create shock waves that can damage the valve. Cavitation damage is manifested by the rough appearance of the surfaces. CO2 Corrosion (DM#42) or H2S + CO2 Corrosion (weight loss corrosion) (DM#P2) (depending on whether or not H2S is present) • This type of corrosion occurs in the presence of condensed water, essentially in the regenerator overhead section, including upstream of the overhead cooler, in the regenerator reflux tank condensate circuit, and to a lesser degree in the head circuit of the regenerator reflux drum; • This type of corrosion is much more severe in the absence of H2S (CO2 alone) than when CO2 and H2S are both present (chapter 4.3.2). Amine Corrosion (rich and lean solvent) (DM#45) • Essentially in the hot zones of the solvent solution circuits where the molar ratio of absorbed acid gas, Xs (molar fraction of H2S/free amine), Xc (molar fraction of CO2/free amine), and Xs + n Xc is greater than the specific threshold for each solvent (ranging from 0.3 for MEA to 0.8 for activated MDEA) and where the temperature is above about 80 °C. The corrosion rate depends essentially on the amine concentration in the solvent, the impurities present in the solvent, and its pH.

4.3.4.3. Corrosion prevention solutions Prevention of generalized and localized amine corrosion If the solvent remains clean and if its composition is acceptable (see Integrity Operating Windows), the corrosion rate is negligible up to about 80 °C, and low up to about 115 °C in the semi-rich amine (it is already partly leaned at such temperatures). The corrosiveness of the lean amine is also low up to the rebuilder’s temperature, particularly if a residual amount of dissolved H2S of 400–500 mg/L of H2S remains in the lean amine (H2S dominant conditions). The same applies with a minimal residual CO2 of a similar order of magnitude in CO2 dominant units. In both cases the objective is to help forming a protective layer, either of iron sulfide (preferred solution, if some H2S is present) or iron carbonate on steels. The tubes or plates of rich solvent/lean solvent exchangers are usually manufactured from CRA. Carbon steel can be used for the tubular exchangers up to 80 °C, provided that the solvent circulation rate is maintained at less than 2 m/s. A limit of 3 m/s is acceptable for CRA. Solid degradation products form at the bottom of the reboiler, especially in CO2dominant service, so CRA-cladded carbon steel should be used for parts that are

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in contact with the solvent. It is recommended to use plain CRA for the reboiler tubes. The solvent return lines from the reboiler to the regenerator and to Closed Drain Drum should be fabricated from CRA (owing to the degradation products). The steam lines from the reboiler to the regenerator should be manufactured from CRA (in CO2-dominant service). They can be made of carbon steel in an H2S dominant service – this depends on the anticipated project life. Finally, as long as carbon steel is used for most rich and lean amine sections, the two most essential actions consist in: 1. Remaining below the “critical velocity for erosion-corrosion” or use stainless steels (currently AISI 316L SS) if such velocities cannot be respected. Properly designing vessels and piping to minimize severe local flow turbulences; 2. Preventing as much as possible the formation of acid Heat Stable Salts (HSS) degradation products, by avoiding both the oxygen entries and the over-heating at reboilers. As far as the limiting flow velocities are concerned, current values are in the range of 2 m/s under usual acid loadings (below 0.5 M/M). Some publications give more conservative values, down to 1.4 m/s when higher acid loadings are faced [9]. Prevention of generalized and localized CO2 and H2S corrosion The corrosiveness due to CO2 on carbon steel surfaces subjected to the condensing water formed inside the regenerator increases strongly if the H2S-content is low in the acid gas. The corrosion problem is generally faced in the regenerator overhead circuit, in the liquid reflux circuit of the reflux vessel, and in the reboiler vapor circuit, as well as in the flash drum overhead circuit. It is an accepted fact that iron sulfides, which offer some protection for the steel, can form as long as the H2S concentration in the lean solvent remains above 500 ppm. If CO2 is present in excess, the CO2/H2S balance shifts and the protective layer is less efficient. Carbonates provide less protection than sulfides. In CO2-dominant service, the regenerator overhead circuit (regenerator head, lines, reflux circuit), and the overhead circuit of the flash drum (vessel head, acid gas line) are built in CRA materials (in practice AISI 316L SS). The selection of carbon steel or CRA for the absorber overhead circuit (absorber head, pipes, coolants, wash tanks, condensate lines from the wash-tank) depends on the CO2 concentration specified for the gas and the project lifetime. The Pressure Control Valves located on the rich amine circuits and condensates from the treated gas scrubber should be designed to avoid cavitation and erosioncorrosion. The differential pressure depends mainly on the service pressure in the absorber. It usually lies between 2.0 and 7.5 MPa. The pipe just downstream of the pressure control valves should be manufactured of CRA.

154 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

This is less critical for the control valve located downstream of the rich solvent exchangers (subject to pressure drops varying from 0.1 to 0.5 MPa). In H2S-dominant environments, those areas of the overhead circuit that are less subjected to acid condensation (treated gas, acid gas) may be made from carbon steel, provided the necessary precautions are taken to avoid condensed and/or stagnant water (using self-drained lines, heat tracing, etc.). Prevention of stress corrosion cracking The likelihood of stress corrosion cracking depends on the type of amine, the temperature and the presence of wet H2S. Application of stress relief heat treatment of carbon steel is required in some cases to release the stresses. The carbon steel should be compliant with NACE MR0175/ISO 15156 and NACE SP0472. The stress relief heat treatment should be done in compliance with API RP 945 rules. However, it is always advised to maintain the stress relieving temperature within the 620–650 °C range (even though it may need exception to meet certain construction codes rules). The application of an internal metal lining (rolled or explosion cladding, or hard overlay welding) is a good barrier against wet H2S-induced corrosion cracking and IGSCC – which is alkaline in low-pressure circuits (H2S partial pressure < 100 kPa). Not all the sour resistant requirements need be followed as regards the base metal and the stress relief treatment if a complete lining is done. On the other hand, lining of only local areas does not prevent assuring a complete cracking resistance of the supporting carbon steel material. Vibration prevention in reboilers Pipe failure caused by vibrations has been observed on BKU/BEU reboilers. Firstly, it is necessary to maintain a sufficient liquid level above the tubes in the reboilers, secondly, it is important to check the design of the tubes and baffles to make sure they can suitably withstand vibrations. Corrosion prevention solutions for standard steel As already indicated previously, the two essential prevention solutions to be applied on units built in standard steels consist in controlling the amine flow rate and the formation of degradation products. Complementary control measures may also be added as listed below, at least within realistic margins: • Internal metal lining (rolled/explosion cladding, weld overlay): these methods provide a good primary barrier to amine corrosion and amine stress corrosion mechanisms. In the case of wet H2S-induced cracking, the effectiveness of the barrier might be limited by the H2S partial pressure. In CO2rich gas treatment or in erosion-corrosion situations, AISI 316L stainless steel should be used. Flash zones are not fully protected, the corrosion is limited to localized areas;

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•

•

• • •

•

•

155

HVOF (High Velocity Oxy Fuel) internal metalizing or similar process does not constitute a fully efficient barrier, (as the sprayed deposit may show some porosity). This solution may however show significant progresses in the near future, so this position is mostly based on few experiences: it cannot be ruled out that this technique may prove showing much better performance than now; Internal organic coating: Internal organic coatings are used only during maintenance operations, when it is necessary to temporarily stop the effects of corrosion. They can be considered as a secondary barrier against corrosion, but their effectiveness is limited in time. In the state of development, they are not very reliable in terms of mitigating the likelihood of stress corrosion cracking. Few organic coatings can withstand MEA (which forms by degradation of secondary or tertiary amines). Over 0.2% weight MEA, there is a high probability of rapid damage of organic coatings; Stress relieving treatment: this may be considered as primary barrier against stress corrosion cracking. See previous chapter about this solution made by a dedicated heat treatment. Alternative to stress relaxation treatments such as surface compression by local hammering should be avoided; Thermal insulation, heat tracing, and self-drainage: for the overhead circuit of the amine reflux vessel and of the flash drum; Local use of non-corrodible materials: pressure letdown valve, jet breakers, distributors, separator trays and screens; Prevention of cavitation and erosion-corrosion in and downstream pressure control valves: a suitable design for all valve components (multiple depressurization stages, seat valve materials and hard flap valves) helps to prevent or limit the effects of cavitation and erosion- corrosion; Prevention of the effects of vaporization downstream or in depressurized areas: design of the piping system (limited circulation rate, use of long-radius bends). Downstream of the pressure letdown valves it is sometimes advised to upgrade the material (instead of carbon steel, use CRA on a straight pipe length that is at least 10 D, where D is the pipe diameter); Corrosion inhibitors: Corrosion inhibitors are sometimes used to inhibit the corrosion of the regenerator overhead circuits. They are usually not used in the amine network itself.

Designs with plate exchangers: plate exchangers have a thermal efficiency which is superior to that of tubular exchangers. In the case of conventional plate exchangers, the weak points are areas subjected to stress (gaskets); austenitic stainless-steel plates may be prone to chloride stress corrosion cracking, particularly from the outside if plates are regularly sprayed by fire water. Use of non-ferrous alloys Copper, nickel, and aluminum alloys should not be used in amine service as they corrode under the action of the amine and may be subject to LME in AGRU units. However, good results have been obtained with grades of aluminum brass (UNS C68700) and aluminum bronze (UNS C63000). CP titanium or titanium alloys can be used in some cases: they should not be put in contact with steel (galvanic couple and hydride formation).

156 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Seals and Gaskets Austenitic stainless steel spiral gaskets as well as graphite flexible gaskets, PTFE gaskets are acceptable in amine service. Flexible graphite fittings are usually also acceptable. EDPM type gaskets provide satisfactory resistance in amine service at temperatures of 130–135 °C. However, their use is limited at higher temperatures as well as in case of accidental ingress of liquid hydrocarbons. Nevertheless, as long as the risk of entry of liquid hydrocarbons is well controlled and the temperature and duty applied to the reboiler remain within reasonable limits, the EPDM material behaves satisfactorily. Several Perfluoro Elastomers (FFKM) can also be used, provided they are amine-compatible at 150 °C. This should be verified. Halides in elastomer should be limited to 200 ppm weight when in contact with austenitic stainless steels. Viton A® (or equivalent) can be used in valves installed at the overhead acid gas lines of the regenerators. Gaskets must be intrinsically resistant to bursting, they should not be glued. Solvent solution chemistry This is the most important point in corrosion management. • Preventing oxygen ingress: the points of potential oxygen ingress in solvent (amines) are the freshwater make-up, fresh amine solution make-up, exchanger tube leaks in contact with other fluids, insufficient valve sealing, blanketing failures, tail gas treatment in SRU gas oxidation units. Oxygen promotes the formation of amine degradation products and increases the corrosion rate. Oxygen ingress must be avoided; storage tanks should be kept under inert atmosphere; • Controlling the pH of solvent solutions: at 25 °C the pH should be maintained above 10.5 if conventional (primary, secondary or tertiary) amines are used. If the solvents contain sterically hindered amines, the pKa of the activating molecule must be considered before setting the pH limit; it is strongly advised not to raise the pH using a caustic soda treatment; • Preventing the formation of soluble salts: soluble salts (HSS) are organic ions (formate, acetate, oxalate, etc.) or inorganic ions (chlorides, sulfates, thiosulfates, etc.), that form by the decomposition and reaction of the amine; their formation can be limited by reducing oxygen ingress and by reboiling at the lowest possible temperature. A total threshold content of 5000 mg is recommended in a publication dealing with amine units for gas production plants [9]. Such limit is considered being quite easily achievable on such units always processing the same gas, though higher values are sometimes experienced in amine units of refineries, because of the much wider variety of gases treated in these units; • Preventing the formation of oxazolidones and polymers: oxazolidones mainly form in CO2-treatment units, with some solvents. They are not corrosive but greatly reduce the strength of the solvent; • Other degradation compounds: the following compounds form in solvents, some are potentially corrosive, THEED, Bicine, whereas others are not: formamides, Bis-HEP, polymers, HMPO (an oxazolidone);

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• Integrity operating windows: the following parameters are critical, and some thresholds depend on the type of solvent: ○ Minimum water concentration of the solvent solution, ○ Amine concentration in the solvent solution, depending on the type of amine, ○ Acid loading of the rich amine, characterized by the ratio of the molar fractions ([H2S]+n[CO2])/[Amine]; depending on the type of amine (for DEA and MDEA, the acceptable acid-loading ratio can be increased with suitable material selection), ○ In H2S dominant environments, the minimum residual H2S concentration in the lean solvent should be 500 ppm (a generally accepted value). In CO2-rich, H2S-deficient environments, the carbon steel use should be reconsidered when primary or secondary amines are used. If carbon steel is used, a minimal residual CO2 content in the 200 – 300 mg/L range should also be assured in order to promote the formation of some iron carbonate, ○ The total suspended solids in the lean solvent: maximum threshold of 50 ppm, optimum operation at 10 ppm, ○ Soluble salts or ATB – RFB (ATB: Amine Total Base; RFB: Regenerable Free Base) – depends on the type of amine; soluble salts (HSS), ○ pH: it is an indication of the quantity of salts of organic acids formed and of the active amine content. A minimum threshold of 10.5 at 25 °C is usually acceptable for conventional amines. This threshold may be different when using sterically hindered amines (can vary from 0.5% to 2.5% weight, depending on the type of amine), ○ Chlorides: no consensus on a lower threshold; a value of 1000 ppm is not a problem.

4.3.4.4. References 1 2 3 4

5 6

7

API RP 945, “Avoiding Environmental Cracking in Amine Units”, API Publishing Services. AWS D10.10, “Recommended Practices for Local Heating of Welds in Piping and Tubing” – 3rd edition, American Welding Society. NACE MT0103, “Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environment”. NACE SP0472, “Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environment”. NACE 8x194 publication, “Material and Fabrication Practices for New Pressure Vessels Use in Wet H2S Refineries Services”. NACE MR0175/ISO 15156, Petroleum and natural gas industries – Materials for use in H2S-containing environments in oil and gas production, part 1, part 2 and part 3, International Standard, 2015. Johan van Roij, Corrosion in Amine Treating Units, second edition, EFC publication No 46. On behalf on WP 15 and 13 on Corrosion in the Refinery and Petrochemical Industry, Woodhead Publishing, ISBN: 978-0-323-99724-9 (print); ISBN: 978-0-91550-2 (online), © 2022.

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8

M. Bonis, JP Ballaguet, C. Rigaill, “A critical look at amines: A practical review of corrosion experience over four decades”, Gas Processor Association (GPA), New Orleans, 15‑17 March, 2004.

9

J. Kittel, M. Bonis, G. Perdu, “Corrosion control on amine plants: new compact unit design for high acid gas loadings”, SOGAT seminar, Abu Dhabi, 2008.

Figure 52. – AGRU, CO2 dominant, P04a – Corrosion Location Diagram.

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Figure 53. – AGRU, CO2 dominant, P04a – Material Selection Diagram.

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160 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 54. – AGRU, H2S dominant, P04b – Corrosion Location Diagram.

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Figure 55. – AGRU, H2S dominant, P04b – Material Selection Diagram.

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162 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

4.3.5.

Gas Dehydration Unit based on Tri-Ethylene Glycol – TEG – P05a and P05b

Absorption drying consists in passing the wet gas through glycols (TEG, MEG, licensed processes) or through methanol. Glycols or methanol absorb the water, thereby decreasing the dew point by as much as –90 °C (–40 °C in average) and preventing the formation of hydrates. This process is used to dry natural gas that is sent to a liquefaction or export site. This chapter concerns TEG units, primarily CO2-dominant (P05a unit) and then those with H2S + CO2 service (P05b unit). The DEG and the Drizo processes are also covered.

4.3.5.1. Description of the process Gas dehydration using glycol (usually triethylene glycol, but diethylene glycol + the Drizo process can also be used) consists in “backwashing” the wet gas with highly dehydrated glycol (lean glycol containing less than 0.5% residual water) in the dehydration column, or in a contactor (a). The dew point of the gas at the column outlet depends on the residual water content of the glycol at the inlet, the number of trays in the column and the respective gas and glycol flow rates. This type of dehydration is commonly conducted at pressures of 6.0 to 10.0 MPa, depending on the requirements of the downstream processes. The rich glycol contains 3 to 5% water at the column outlet. It is then regenerated in the reboiler (k), by heating at low pressure up to a temperature of 200 °C (for TEG) or 150 °C (for DEG and a Drizo-type process). At such temperature and pressure, most of the water dissolved in the glycol re-evaporates. The glycol dehydration is less complete in the Drizo process, owing to reboiling at a lower temperature. The dehydration is therefore supplemented by “washing” with a volatile hydrocarbon solvent in the “stripping column” (L). Before entering the reboiler, the rich glycol is depressurized in the flash drum (c) and then again in the reboiler itself and reheated through a series of glycol-glycol exchangers (b and f). This process also cools the lean glycol leaving the reboiler. The cooled lean glycol is then further cooled by air or by water in a final step (exchanger o), before returning to the top of the dehydration column. One of the operating key points in this system is that the feed gas contains no hydrocarbons in the liquid phase, usually in the form of fine droplets. Liquid hydrocarbons, even in small quantities, can cause foaming problems that seriously affect the efficiency of the process. Scrubbers and coalescer filters are usually installed immediately upstream of the dehydration column to avoid transporting the droplets and any subsequent re-condensation before entering the column.

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4.3.5.2. Main damage mechanisms  Dehydration units without H2S Preliminary comment: in this document, “units without H2S” means those not potentially subjected to H2S-induced cracking corrosion. This refers to the H2S severity domains described in document NACE MR0175/ISO 15156. The most critical point in terms of H2S severity is, theoretically, the dehydration column, as this is the point subjected to the highest pressure in the entire circuit. However, when evaluating the severity, it should be noted that although the gas entering the dehydration column is saturated with water, it contains little or no free water. In addition, the glycol used can be treated with a pH stabilizer. Therefore, it would be very conservative to take into consideration the severity of native condensation water, which would correspond to a situation with considerable condensation. The most representative pH would be that of condensation water saturated with corrosion products. CO2 Corrosion (DM#P1) In a 1st approach, the corrosiveness of the CO2-saturated glycol is related to the corrosiveness of the water, proportionally corrected for the water content in the glycol. In a 1991 Shell publication [1] C. de Waard, U. Lotz gave the following equation, determined for water contents of 10 to 100%, with a corrosion correction factor, the glycol factor (Fglyc), that is a function of the water content W (%) in a glycol: log Fglyc = A logW(%) -2A where A ~ 1.6 This equation is equivalent to Fglyc = (W/100)A, W% is the weight of water in % Although this equation was determined only for MEG and DEG, with more than 10% water, it simply expresses that corrosion is directly related to the concentration of the reaction intermediate in the electrochemical exchanges at the surface, i.e., water. It can therefore reasonably be extended to TEG, and even to lower water concentrations, at least up to a few percent of rich TEG. Thus, a rich glycol containing 5% water is about 100 times less corrosive than water itself in the same conditions. Furthermore, the glycol is less acidic than would be pure condensation water, especially if a pH stabilizer has been added. Its actual corrosiveness is even lower, even in CO2-saturated glycol (leaving the dehydration tower). However, severe CO2 corrosion can occur at the top of the reboiler distillation column (column g), in the condenser (h) and in the condenser receiver vessel (i). There is no glycol but significant condensation due to cooling. Moreover, although the total column head pressure is low (slightly above atmospheric pressure), the CO2 content in the outgoing steam is much higher than in the feed gas, owing to the high solubility of the CO2 in glycol, usually 3 to 5 times higher than the solubility of methane. CO2 corrosion can also occur in the gas part of the flash vessel (c), in condensation zones or piping elements without circulation (valve, discharge to flare...).

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Glycol-specific corrosion The question of glycol-specific corrosion itself comes up regularly. In this document, it is considered that normally there is no glycol-specific corrosion, except in the case of operation outside normal operating limits, resulting in the formation of acids. In fact, as long as the glycol’s acidity is only related to the CO2 content (or to a combination of H2S + CO2, as in the following case), the resulting corrosion is actually CO2 corrosion (DM#P1), discussed above. What could be termed “glycol corrosion” would be corrosion gradually induced by degraded glycol and acidified by regular oxygen ingress or by overheating to above 200–210 °C, e.g., on heating tubes that are not fully immersed in the reboiler: this is resulting from upset, and therefore a specific corrosion phenomenon. In this case, the induced corrosion is also influenced by the additional presence of CO2 and H2S. Dehydration units with H2S Except for the usual issue of potential cracking corrosion (see preliminary comment for “units without H2S”), the other problems are equivalent and quite minor, considering that “H2S + CO2 Corrosion (weight loss corrosion)” replaces CO2 corrosion, which is the same type of corrosion mechanism, of comparable or even lesser severity, because of a more protective iron sulfide corrosion layer being formed on carbon steels when H2S is present.

4.3.5.3. Corrosion prevention solutions Dehydration units without H2S Main solution: standard steel Owing to the moderate corrosiveness of the lean glycol, the selection of carbon steel is the basic solution for the main equipment in contact with the glycol, with dry gas at the dehydration column outlet or with nearly dry gas at the column inlet. The inlet piping of the dehydration column is often thermally insulated from the last scrubber or coalescer, to avoid condensation of liquid hydrocarbons, which is critical for the column’s operation. This also has the advantage of minimizing the likelihood of significant water condensation. Due to the low service pressure, austenitic stainless steel (generally AISI 316L SS) – a material with low mechanical characteristics) – can be used for the following equipment: • • • • • • • •

The internals of the dehydration column (trays or packing); The glycol-glycol plate exchanger; The tubes of the glycol-glycol tubular exchanger; The internals of the stripper (I); The distillation column (g) and all its internals; The tube exchangers and the condenser downstream of the still column; The reboiler heater tubes; The gas piping downstream the still column and the gas piping downstream the flash vessel.

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In addition, the pH of the glycol should be maintained above 6.5 by a pH stabilizer, e.g., MDEA. While contributing to the precipitation of a protective iron carbonate deposit in the rich glycol, this treatment also reduces the likelihood of the solution becoming more acidic due to overheating or regular oxygen ingress. Vigilance points The 1st vigilance point concerns oxygen ingress (e.g., during the addition of glycol or by any other accidental source). Oxygen ingress can: 1. Promote the degradation of TEG, and thereby gradually increasing the acidity; 2. Enhance the precipitation of ferrous species from the dissolved iron in the glycol; 3. In the presence of H2S, induce the precipitation of sulfur, thereby increasing the probability of developing corrosion. The presence of chlorides and their evolution in time must also be monitored, as an increase in their concentration may indicate carry-over from the feed gas, i.e., an unwanted, potentially problematic anomaly. The appearance of foaming must also be carefully monitored. The origin of any foaming must be found and eliminated. Above all and as previously mentioned, the unexpected ingress of suspended liquid hydrocarbon droplets in the dehydration column must be considered and settled. Dehydration units with H2S Preventive solutions are usually similar, predominantly involving the selection of steel (for H2S service). Non-corrodible materials are essentially reserved for the same equipment or equipment parts with thin walls – a few millimeters thick (exchanger tubes, vessel internals, etc.) or to those parts particularly susceptible to corrosion. It is important to note that AISI 316L SS can be used even at high concentrations of H2S because of the low water and the low chloride contents. If there is a significant risk of accidental chloride ingress (e.g., in exchangers with direct cooling by seawater) it may be useful to select a nickel alloy for the elements exposed to high temperatures. Vigilance points The precautions to take are the same as for units without H2S but must also include unexpected oxygen ingress, as its consequences are much more severe in the presence of H2S than in its absence (formation of sulfur and degradation products).

4.3.5.4. References 1

C. de Waard, U. Lotz, DE Milliams, “Predictive model for CO2 Corrosion Engineering in Wet Natural Gas”, paper n° 577, Corrosion/1991 conference, NACE International, Houston, Texas.

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Figure 56. – Sweet Gas Dehydration Unit based on TEG, P05a – Corrosion Location Diagram.

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Figure 57. – Sweet Gas Dehydration Unit based on TEG, P05a – Material Selection Diagram.

168 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 58. – Sour Gas Dehydration Unit based on TEG, P05b – Corrosion Location Diagram.

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Figure 59. – Sour Gas Dehydration Unit based on TEG, P05b – Material Selection Diagram.

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4.3.6.

Gas Dryers – Molecular Sieves – P06

Processes with desiccants are used to obtain gas with a very low dew point. Several types of desiccants are used: • Silica gel or silica and alumina gel made of SiO2 or SiO2 + Al2O3, they can dehydrate gas to a residual water content of 10 ppm. They adsorb heavy hydrocarbons and are easily regenerated. They are H2S- tolerant up to about 5-6% weight (sulfur can be deposited on their surface). They cannot process NH3-bearing gases; • Alumina (Al2O3): the gas is dehydrated by a hydration reaction with the alumina. The latter is then regenerated by heating. The dew point of the dried gas is about –75 °C. Acid gases cannot be treated because of the alkaline nature of the adsorbent. Alumina tends to adsorb hydrocarbons, so it cannot regenerate, and it is easily disintegrated; • Molecular sieves: they are crystalline forms of calcium or sodium aluminosilicates. They are very porous, with very small pore diameters, and they can efficiently adsorb water and H2S owing to the polar charge at their surface. Because of the very small pore diameter, they do not adsorb the heavy hydrocarbon molecules. The molecular sieves are used to obtain a gas whose dew point meets the conditions necessary for its liquefaction (1 ppm residual water). The regeneration temperature is high.

4.3.6.1. Description of the process The treated gas from the AGRU absorber section is then sent towards the dehydration section. In normal service, this gas contains only very small amounts of H2S and CO2 (usually less than 50 ppmv) except if the absorber is malfunctioning. This type of situation usually persists only a few hours per year (as a non-compliant treated gas cannot be liquefied so it is normally recycled). Thermal exchangers maintain the gas at the optimum feed temperature for the molecular sieves; a part of the water in the gas condenses. Condensates, which may contain a small amount of entrained amines, are separated from the gas phase in a separator, while the liquid phase (essentially water) is sent back to the AGRU section. The molecular sieves follow an adsorption – desorption cycle that lasts from 16 and 24 hours. The process combines 3 or 4 drying vessels in parallel, that are alternatively used in the adsorption and regeneration phases. The adsorption service lasts about 3 times longer than the regeneration service, given a temperature difference of about 250 °C between adsorption and regeneration. Because of the repetitive and large temperature cycling, the thermal gradient needs to be followed. The wet gas enters the upper part of a dryer in adsorption mode, and the water is adsorbed by the molecular sieve. The dry gas exits at room temperature and contains less than 1 ppm water volume (depending on the dry gas specification). The gas passes through cartridges designed to filter the fines from the molecular sieves. Most of the gas is then directed to the downstream section. The remainder is heated to 300 °C by high-pressure steam or hot oil, in regeneration gas heaters.

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The dry and hot gas is sent through a system of manifolds to the bottom of the dryer to be regenerated, that contains a molecular sieve saturated with water. It carries the desorbed water from the bottom to the top of the dryer. In regeneration mode the dryer operates at a temperature of about 300 °C and at high pressure (4.5 to 8.0 MPa (g)). The gas leaving the dryer in regeneration mode is saturated with water. It is cooled from about 300 °C to about 40–50 °C in a cooler. The condensed water phase is retrieved in a separator vessel and is disposed of. The wet gas phase is compressed in a centrifugal or volumetric compressor and is recycled upstream of the exchanger located at the inlet of the section. In the event of severe depressurization, the temperature may drop to below the ductile-fragile transition temperature of carbon steel. It is important to note that the regeneration gas contains more H2S than the gas to be dried, owing to a concentration effect in the desorption phase.

4.3.6.2. Main damage mechanisms Wet H2S Induced Cracking (Blistering/HIC/SOHIC/SSC) (DM#2) • If the H2S partial pressure is greater than 0.03 kPa, the damage should be considered for the entire section of the circuit containing wet gas or an aqueous phase. In that case it is necessary to select materials that comply with NACE MR0175/ISO 15156 criteria. When the partial pressure is less than 0.03 kPa, the damage may be neglected; • Given that the H2S concentration in the regeneration gas separator may be higher than in the inlet separator, sometimes the selection of steels compliant with NACE MR0175/ISO 15156 criteria may be required. Thermal Fatigue (DM#12) • Considering the cyclicity of the process (approximately 300 to 600 thermal cycles of about 250 °C, per year), thermal fatigue on dryer inlet and outlet nozzles and on shell to skirt junctions must be taken into consideration when designing. Thermal fatigue cracks were found on equipment designed in the 1970s, after 20–25 years of service. Note: for processes that are based on hydrated alumina or silica gels, the regeneration temperature is lower, and therefore thermal fatigue is not taken into consideration. Erosion (DM#P5) • This damage mechanism must be taken into consideration for the dryer outlet piping, up to the filter: fragments from ceramic balls may be entrained if the grates break apart due to thermal stress. Severe cases have been observed with molecular sieves being entrained up to the cold boxes in a cryogenics section.

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Amine Cracking (DM#22) • Theoretically, damage may result in case of massive amine carry over from AGRU. In practice, the temperature of the gas is relatively low: ○ If secondary, tertiary or sterically hindered amines are accidentally entrained, the probability of damage is almost nil, ○ If MEA is entrained, damage should be possible on the gas cooler upstream of the inlet separator. The probability of damage is very low on the bottom of the inlet separator and the lines returning to the AGRU section. Brittle Fracture (DM#31) • The probability of occurrence of this type of damage must be fully eliminated at the design stage of the materials selection. Amine Corrosion (DM#45) • This type of mechanism could be considered if amines come from the absorber head. In practice, the gas temperature entering the unit is less than 80 °C, and the rate of corrosion associated with the presence of amines in areas where liquid may stagnate (upstream of the dryers), will be virtually nil. This damage could therefore be neglected. Corrosion Under Insulation (CUI) (DM#46) • Due to the cyclic temperature of the dryers, the sensitivity of this type of equipment to CUI is considerable. This is the most critical damage mechanism on this type of unit. Mechanical Fatigue (DM#54) • Considering the cyclicity of the process (approx. 300 to 600 opening-closing cycles per year), mechanical fatigue must be considered for the design of interlock valves that allow for operation of the dryers. H2S + CO2 Corrosion (weight loss corrosion) (DM#P2) • In the wet gas-phase circuits the corrosion rate will be very low, except possibly where condensation or liquid retention can occur. This damage can be neglected; • In the liquid condensate circuits, especially those in the dryer regeneration circuit, corrosion should be considered even though the corrosion rate might not be significant (depending on the residual CO2 concentration).

4.3.6.3. Corrosion prevention solutions Prevention of brittle fracture Use the appropriate steels and check their resilience properties during manufacturing down to the lowest predicted temperature.

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Prevention of thermal fatigue and mechanical fatigue In the design stage, choose solutions that limit the effects of temperature fluctuations on dryers and circuits (jacketing or any other design of dryer inlet manifolds, shell-skirt junctions of dryers without angle welds, etc.), fatigue resistance must be demonstrated by compliance with codes of design. Prevention of cracking by wet H2S Generally, the gas to be dried contains less than 50 ppmv H2S, and more for regeneration, so cracking induced by wet H2S is often not a real issue. The selection of steels that meet NACE MR0175/ISO 15156 criteria is sometimes required. In this case, the chemical composition and mechanical characteristics of the materials used must be able to meet H2S service requirements; the hardness and resilience of the materials, including welded joints, must be checked. Prevention of wet corrosion Avoid points where liquids could stagnate in potentially wet areas. If there is a possibility that the treated gas contains large amounts of CO2, the bottom of the inlet separator may be cladded with austenitic stainless steel and the condensates return line to the AGRU section could be made of austenitic stainless steel as well. In general, use of carbon steel with a corrosion allowance is often enough. Prevention of erosion due to ceramic balls Verify the design of the grate system and control of the assembly of the grates in operation. Measure the pressure drop in the filter located downstream of the dryers. Operating parameters to be monitored: in addition to Integrity Operating Window thresholds: • Water content of the dry gas; • Assembly of the grates and disposition of ceramic balls supporting the molecular sieve; • Free expansion of the gas heater. Standard Steel: which preventive solutions should be implemented? Carbon steel (with chemical composition and resilience compliant to service) or low-temperature carbon steels are commonly used. Given the regeneration-gas reheating temperature, the heater tubes can be made of low alloy steel 1.25Cr-0.5Mo, 2.25Cr-1Mo or austenitic stainless steels (AISI 304/304H SS, AISI 316 SS, AISI 321 SS). Integrity Operating Windows, in-service monitoring: • Monitor the number of adsorption-regeneration cycles: to assess potential fatigue;

174 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

• Check the temperature of the regeneration gas: to monitor the cyclic thermal amplitude; • Check the pressure drop in the filter downstream of the dryers: check for the absence of fines or alumina balls that could cause erosion upstream.

Figure 60.  –  Gas Dryers Unit, P06 – Corrosion Location Diagram.

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Figure 61.  –  Gas Dryers Unit, P06 – Material Selection Diagram.

4.3.7.

Sulfur Recovery Units (SRU) – P07

Sulfur recovery units convert 95 to 99% of the H2S contained in a sour gas (AGRU, off-gas, flue gas, etc.) into sulfur. When associated with a Tail-Gas Treatment Unit (TGTU), the conversion rate can increase to 99.5 – 99.9%. There are many sulfur recovery processes, each of which can be incorporated into several types of units, [9].

176 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Processes can be categorized according to the types of reactions & catalysts involved: • Hot oxidation mainly based on the high-temperature Claus reaction: H2S is converted to Sn by sub-stoichiometric combustion in a thermal reactor. As the conversion is incomplete, the residual H2S is then converted in several (usually 2 to 3) low-temperature catalytic stages [7, 8]; • Low-temperature gas-phase oxidation, complementary to hot oxidation. These processes use different catalysts [11]; • Oxidation in liquid phase (aqueous and non-aqueous): about 25 processes have been developed, more or less successfully [10, 11, 13]; • Biological oxidation: this is a chemical oxidation catalyzed by bacteria in an alkaline aqueous environment. The selection of the process is based on the molar % H2S in the gas to be treated, the amount of gas to be treated, and the possibility of evacuating the sulfur. A unit based on a Claus process implementing hot oxidation and low-temperature oxidation (2 reactors containing a classical Claus catalyst) is considered in this section. It allows to treat gas from an AGRU containing more than 40% of H2S, and no or little NH3. An option is considered for enriching the fuel with oxygen. The air is not preheated.

4.3.7.1. Description of the process A Claus unit includes the feed gas system, the Claus furnace, converters and their associated reheaters, and sulfur condensers. The simplified process flow diagrams show a post 1990’s typical design. In Oil and Gas Production, Claus feed consists of rich H2S gas along with other auxiliary feeds such as fuel gas, air, and/or oxygen to assist burning [12]. CO2 is also present in large amounts (several % to tens %), that are also extracted from the treated gas by the AGRU. The rich H2S gas comes from AGRU regenerator overhead. It enters the SRU at 25–50 °C and 0.07–0.14 MPa (g) where it mixes with the recycled acid gas from the TGTU unit. The mixed gases enter the acid gas KO drum where any entrained water and/or hydrocarbon is removed. Combustion air is supplied by blowers and is fed to the combustion chamber. Some units also use oxygen either, to enrich the air. All the combustion air / oxygen is supplied to the combustion chamber of the thermal reactor with a restricted portion of the rich H2S gas to ensure high enough temperature. The remainder of rich H2S gas is fed to the reaction chamber for the H2S to consume any residual O2 and to react with SO2. The split of rich H2S gas to the combustion chamber and the reaction chamber depends on the observed furnace temperatures. Thermal reactors designed to proceed only H2S need to be operated at least at 871 °C to ensure flame stability and to prevent

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oxygen slip from the burner flame. Ideally, the temperature in the combustion chamber should be maintained between 1316–1427 °C. The maximum temperature in the combustion chamber is typically limited to 1550 °C to avoid refractory damage. The combustion gases from the burner and combustion chamber flow into the reaction chamber where adequate residence time is provided for the sulfur reactions and reaction with any residual oxygen. The internal of the thermal reactor is refractory-lined to protect the metal shell from the high temperatures. Many thermal reactors have louvers and rain shroud which can be adjusted to maintain the metal temperature between 220 and 350 °C. Steam Generator The hot process gases flow from the Claus furnace into the thermal reactor steam generator. In the steam generator, the process gas is typically cooled in a Waste Heat Boiler (WHB), where the hot gas is on the tube side and Boiler Feed Water (BFW) is on the shell side. Steam at pressure of 1.4 – 4.5 MPa is produced in the WHB. The cooled process gas then goes through a multi-stage conversion section to complete the catalytic conversion reactions and to condense and remove elemental sulfur. Sulfur condensers and sulfur converters The process gas from the steam generator flows to sulfur condenser No. 1 where it is further cooled to 160–180 °C by BFW, generating low-pressure steam. Sulfur vapor is condensed into liquid state, which flows through the sulfur seal pot and into the sulfur pit or tank. After the sulfur drops out, the remaining gas is heated back up to about 232 °C in Reheater No. 1 via steam reheater. This is to ensure that the sulfur produced during the conversion stays above its dew point throughout the catalyst bed. The hot gas then enters the converter No.1 where it contacts a bed of alumina-based catalyst. Here the conversion reaction between H2S and SO2 occurs, yielding additional sulfur. Leaving converter No. 1, the gas goes to sulfur condenser No. 2 where sulfur is again condensed and drawn off. Generally, condensers 1 and 2 share a common shell. The remaining gas then goes through a second or in some cases a third stage conversion reaction. The converter’s operating temperature must be maintained above the sulfur dew point. Otherwise, sulfur will condense inside the catalyst pores and deactivate the catalyst. Following converter No. 2, the gas enters condenser No. 3, where sulfur is again condensed, separated, and sent to a seal pot and then to the sulfur pit.

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All non-condensable from this condenser go to the TGTU unit as Claus tail gas. When the TGTU unit is offline, the tail gas may be diverted to the incinerator and then released to the atmosphere via the stack, or the unit is stopped. The sulfur condensers typically generate LP steam while condensing elemental sulfur. Sulfur Handling System The molten sulfur from the condensers flows by gravity to the sulfur storage pit in steam-jacketed rundown lines via individual seal pots. All liquid sulfur lines are steam-jacketed to prevent freezing of sulfur and plugging of the lines. The sulfur pit is designed to store large quantities of molten sulfur. Heating coils are provided in the pit to maintain the sulfur at approximately 135 °C. This temperature corresponds to the lowest sulfur viscosity. Sulfur from the pit can be transferred by pumps to other sulfur storage tanks. Sulfur flowing to the sulfur pit contains H2S gas and dissolved hydrogen polysulfides. The H2S will evolve in the pit and may cause numerous of operating (explosive H2S/air mixture) and corrosion concerns (4.3.7.2). To minimize these potential problems, a steam jet eductor is used to sweep air from the pit. The swept air, now containing the evolved hydrogen sulfide, and eductor steam are routed to the incinerator. The air sweep lines, and eductor are also steam-jacketed to avoid plugging with sulfur.

4.3.7.2. Main damage mechanisms Before entering into the various potential damage mechanisms, it is worth noting that, under normal operating conditions, most of the SRU process is operated far above the water dew point, hence with minimal aqueous corrosion problems. As a consequence, potential corrosion issues are mostly related to: • High temperature corrosion, in furnaces; • Local wet areas, due to local or accidental cooling (e.g., dead ends); • Start-up or shut-down operations, if not properly managed (with not water but other strong acids being formed). Sulfidation (DM#1) H2S corrosion at temperatures above 240 °C can potentially occur: • In case of degradation of the refractory, the walls of combustion chamber, the thermal reactor, the line to the first exchanger may be in contact with hot gas and then attacked by H2S; • Also, for the recovery boiler pipes and the catalytic conversion circuit.

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Wet H2S Induced Cracking (Blistering/HIC/SSC/SOHIC) (DM#2) Acid gases from the AGRU contain H2S. The circuit between the battery limits of the AGRU unit and the H2S burner inlet is exposed to damage by wet H2S. Fuel gas and tail-gas circuits may be exposed to these mechanisms to a lesser degree. This is however limited in practice to the wet locations where some free water can be present, either permanently or during transient periods, as highlighted above. Oxidation (DM#11) • High-temperature oxidation can occur in the combustion chamber and the thermal reactor if the refractories are deteriorated and, to a lesser degree, in the recovery boiler tubes (process side). Sour Water Corrosion (acidic) (DM#13) • Gases from the AGRU contain H2S and CO2 which are weak acids. In aqueous solutions, they participate to the corrosion of carbon steel essentially in the acid feed gas circuit entering the AGRU. The corrosion rate is usually negligible, particularly due to the usually dry service; this also applies to fuel gas that contains CO2 and water. Refractory Degradation (DM#14) • The combustion chamber, the thermal reactor, the tube plates of the recovery boiler, and the supply line of the catalytic conversion circuit are protected by refractory, whereas the catalytic conversion reactors are partially protected. Degradation of the refractories is inherent to the process, so the choice of the refractories and their application are fundamental. Caustic Cracking (DM#18) • This can affect the HP steam drum and the outside of the recovery boiler tubes. Caustic Corrosion (DM#19) • This can affect the HP steam drum and the outside of the recovery boiler tubes. Erosion - Corrosion (DM#P5) • Specifically, on the boiler water circuit during high – low pressure flash; this can be considered as flash-erosion.

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Carbonate Stress Corrosion Cracking (DM#21) • As a reminder, this form of corrosion was encountered in refineries units that processed sour gases rich in CO2 and ammonia (NH3) [5]; the pH of the condensates is greater than 8.0. This type of damage should not be encountered in sulfur recovery units provided the pH of the sour gas condensates is lower than 7.6 or 8.0. However, if there is substantial amine entrainment, the condensates may be alkaline, in which case carbonate stress corrosion cracking can be considered. This form of corrosion is unlikely in normal service and in E & P conditions. Amine Cracking (DM#22) • Amine can be entrained by the sour gas. The dead legs, the sour gas separator vessel, and the condensate vessel are potentially exposed to amine cracking, but this is a marginal cause of damage. Short Term Overheating (DM#30) • Damage to the refractory can occur in the combustion chamber and in the thermal reactor, as well as on recovery boiler tubes if they are not covered by water (see DM#30 in API RP 571). Sulfuric Acid Corrosion (DM#36) • Sulfuric acid can form by reaction of SOx with water, mainly on the gas vent of sulfur pits and in sulfur storage tanks. CO2 and SOx Corrosion (DM#38) (Flue Gas Dew Point Corrosion) • This type of corrosion can occur wherever the temperature drops below the dew point; the respective partial pressures of CO2, SO2, SO3 and H2O in the circuits must be taken into consideration to assess the likelihood of condensation. It can be encountered on the outer walls of the combustion chamber and the thermal reactor if the refractory is damaged. Boiler Water / Condensate Corrosion (DM#50) • Occurs specifically in the boiler water circuit if the boiler water quality is unsuitable. This damage mechanism includes oxygen induced corrosion that can develop following degassing or insufficient chemical treatment of the feed water. The probability is low in recovery boilers, but can occur at the water line, in the upper part of the steam drum, and potentially at the tubes – plates interstices.

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Mechanical Fatigue (DM#54) • The outlet nozzles of the conversion reactors can be subjected to considerable temperature fluctuations that lead to localized mechanical stress; cases of fatigue failure (due to thermal and mechanical effects) have been observed. Oxygen Enhanced Ignition and Combustion (DM#65) • In units operating with oxygen-enriched combustion air (O2 > 40% volume), ignition can occur in the combustion chamber and the thermal reactor, the tubes of the recovery boiler, and in the oxygen inlet circuit. The circuits must be kept clean, free of hydrocarbons or combustible products. Low-Temperature Sulfur Corrosion / blockage (DM#P8) • As a reminder, wet sulfur in the SRU units leads to the formation of elemental sulfur. Such damage may occur in the downstream circuit of the sulfur condensers. Sulfur Ignition • As a reminder, sulfur ignition occurs when oxygen remains in the “anoxic zone” of the thermal reactor, usually when passing over natural or combustible gas or when the flame temperature is below 982 °C.

4.3.7.3. Corrosion prevention solutions Materials used Carbon steel: Used for fuel gas circuits, thermal reactions, catalytic conversion, liquid sulfur, tail gas, feed water and steam. Lined equipment and pipes: made of carbon steel, used mainly for liquid sulfur circuits; these assemblies should be heat-treated to reduce stresses. Carbon steel for Wet H2S service: can potentially be used for gas circuits from the AGRU and acid gas condensate circuits. Low-alloy steels: used in the manufacturing of tail gas pipes to the flue. 0.5 Mo, corten steel (ASME SA606-4, SA588, SA847) or equivalent alloys; alternatively, C-Mn, 1.25Cr-0.5Mo. Hot piping lines to the flue can be partially lined with refractory materials. Austenitic stainless steels: they can be used for constructing the connecting pipes between the recovery boiler and the sulfur condensers. They are also used to manufacture heating coils for the sulfur pit, splash lines and vent lines, which are subjected to atmospheres containing sulfur and sulfuric acid; the corrosion rate is significant. Austenitic stainless steels generally last twice as long as carbon steel.

182 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Refractory steels and alloys: these are used in the manufacture of heating elements, fasteners for ceramic materials and sometimes in the manufacture of ferrules. Ceramic materials: refractory concretes and cements (preferably silica-free) and ceramic fibers are used. Corrosion prevention solutions Prevention of sulfidation The combustion chamber, thermal reactor, recovery boiler inlet and outlet and the line to the first sulfur condenser are insulated by refractory materials. The proper refractory design and application rules are absolutely essential to long service lives of a SRU. The corrosion rate is relatively low on equipment and lines not requiring to be protected by a refractory. A corrosion allowance for the carbon steel is sufficient for the lifetime of the facility. The skin temperature of the equipment and piping should not exceed 343 °C to limit corrosion of carbon steel by sulfidation. Prevention of generalized and localized CO2 + H2S Corrosion The generalized corrosion rate is low, the corrosion allowance is enough to compensate for the loss of carbon steel thickness over the lifetime of the facility. Water condensation is limited by the heat tracing system and by the high operating temperature of most parts of the process. The design rules require gradients for the piping and absence of low points. Prevention of generalized and localized CO2 + SOx Corrosion This type of corrosion is prevented essentially by design and construction rules that require maintaining the skin temperature under the refractory, in the range of 20–30 °C above the SO3 dew point; unit shutdown rules that allow SOx removal from the circuits or preventing the formation of condensation; heat tracing of tail gas lines. It is finally worth noting that shut-down operations are among the most critical phases for corrosion due to sulfuric acid condensation, if all SO2 is not completely flushed out during a sufficient period (e.g., by processing fuel gas free of H2S during a sufficient time before starting cooling). Robust and well applied shut-down procedures are a decisive key of success. The situation is quite similar also for start-up procedures: the unit must be temperature stabilized before sending the H2S containing gas. Prevention of high temperature oxidation Operating rules that include air monitoring according to the type of sour gas burnt; rules for designing and installing refractories; protecting the ends of the recovery boiler tubes using inserts.

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Prevention of oxygen induced ignition Operating rules that involve monitoring the oxygen concentration and the absence of liquid hydrocarbons in the sour gas. Prevention of stress cracking Stress cracking is usually due to the presence of wet H2S. The use of NACE MR0175/ISO 15156 compliant carbon steel for sour gas circuits and condensate circuits [6]. If amine-induced stress corrosion cracking is a possibility, then API RP 945 thermal treatment criteria should apply [1, 2, 3, 4]. If carbonate stress corrosion cracking is a possibility, then stress-relieving heat treatment should be applied at 650 °C [5]. Prevention of fouling The recovery boiler tubes may lose their heat-exchange efficiency due to deposits from different potential sources: • Presence of condensates or amines entrained with the gas: deposits can reduce the efficiency of the exchange; these deposits can also form in the catalytic reactors; • Unsuitable specification of refractory materials: silica contained in the refractories can migrate due to excessive temperatures and then be deposited in recovery boiler tubes, thereby greatly reducing the exchange capacity. These deposits are very difficult to remove, and in most cases retubing is required; • Sulfur deposits can clog condenser tubes, lines, and sulfur pots. The sulfur condenser outlets should be maintained at a high enough temperature to prevent solidification of sulfur in the lines; • Sulfate formation in the catalytic reactors can clog the pores of the catalyst medium. Integrity operating windows • Check the liquid level in the gas separator vessel to avoid liquid entrainment; • Maintain the skin temperature of the acid gas piping above 82 °C to limit condensation; • Maintain the skin temperature of the outer walls of the combustion chamber and the thermal reactor between 204 °C and 343 °C. Avoid dew-point corrosion. Limit sulfidation; • Maintain the combustion chamber temperature < 1538 °C in general. Avoid the degradation of ceramics. If the refractories contain silica, make sure the temperature is compatible with that type of refractory; • Maintain the sulfur temperature in the heaters upstream of the catalytic conversion > 149 °C in the first heaters and > 135 °C in the last heater. Avoid sulfur condensation;

184 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

• Maintain the temperature of the feed water at the condenser inlets at > 107 °C. Avoid water condensation; • Maintain steam condensates at pH > 7.5. Avoid CO2 corrosion; • Boiler feed water: Check the level in the recovery boiler and sulfur condensers. Measure the conductivity. Corrosion prevention solutions for standard steel The use of carbon steel is standard in sulfur recovery units. Corrosion can be limited by implementing the following measures. • Protection of walls by refractories: the combustion chamber, the thermal reactor, the tube plates of the recovery boiler, and the outlet line to the first sulfur condenser are covered with a refractory material; • Tube end ferrules: to avoid the rapid sulfidation of the recovery boiler tube ends, usually made of carbon steel, ferrules are made of stainless steel, refractory alloy, or ceramic. The design (length, shape) and installation technique are fundamental to their effectiveness; • Thermal insulation, heat tracing, and self-drainage: all carbon steel lines conveying acid gas should have enough slope for self-drainage. They should comprize no dead legs, and their skin temperature should be maintained above the dew point of the water; • Double wall pipe: essentially for liquid sulfur service. The piping must be easy to clean by a mechanical passage of rod or a high-pressure cleaning system. Mechanical stresses on welds close to cleaning apertures may lead to possible stress-corrosion cracking. Water must be driven out from the outer wall before shutdowns, and heating devices must be decommissioned. When recommissioning, make sure that no liquid water is present in the sulfur side, to avoid water hammer; • Commissioning, shutdown, and standby procedures: when commissioning, it is important to respect the refractory drying times (difference between newly commissioned refractory and the subsequent service), and to maintain the temperature of the combustion chamber and the thermal reactor below the refractory temperature stability threshold (order of magnitude of 1540 °C). Maintain the temperature of the sulfur pit and the pouring lines and pots above 135 °C to prevent solidification of the sulfur. During shutdowns drive the gas out of the system by sweeping it with hot nitrogen to prevent sulfur ignition and dew-point corrosion. When decommissioning, maintain the condenser outlet temperature above 120 °C to avoid dew-point corrosion. When shutting down without opening the equipment, keep the temperature at the outlets of the sulfur condensers above 135 °C to keep the sulfur from solidifying; maintain the vapor pressure in the double wall pipes above 0.345 MPa (g).

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Prevent any water or steam from entering the sulfur pit to avoid explosions and corrosion by sulfur. Sweep dry air or nitrogen continually through the space between the liquid sulfur level and the top of the sulfur pit to avoid accumulation of H2S.

4.3.7.4. References 1

API RP 945, “Avoiding Environmental Cracking in Amine Units”.

2

AWS D10.10, “Recommended Practices for Local Heating of Welds in Piping and Tubing” - 3rd Edition.

3

NACE SP0472, “Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments”.

4

NACE 8x194, publication, “Material and Fabrication Practices for New Pressure Vessels Used in Wet H2S Refinery Services”.

5

NACE Pub 34108, “Review and Survey of Alkaline Carbonate Stress Corrosion Cracking in Refinery Sour Water”.

6

NACE MR0175/ISO 15156-2:2015, Petroleum and natural gas industries — Materials for use in H2S-containing environments in oil and gas production — Part 2: Cracking-resistant carbon and low alloy steels, and the use of cast irons.

7

P.D. Clark, “Fundamental and Practical aspect of the Claus Sulfur Recovery Process”, Topsøe Catalyst forum 2007.

8

F. Scheel, Jacobs-Comprimo, “Innovative approach to sulphur recovery unit emission production”, RTM Conference paper.

9

A.E Cover & al, “Review of Selected Sulfur Recovery Processes for SNG production”, Kellog Rust Synfuels, 1985.

10

A better solution for difficult to treat gas streams, The URS CrystaSulf® Process, Mid-Range H2S Removal and Sulfur Recovery.

11

Denis A. Dalrymple and David W. DeBarry, Girish Srinivas, Emerging Technologies for small-and medium-scale sulfur recovery – CrystasulfSM and TDA.

12

Reed J. Hendershot, Timoty D. Lebrecht, Nancy C. Easterbrook, Use of Oxygen to improve combustion and oxidation, CEP, July 2010.

13

P.Y. Le Strat, M. Cot, J.P. Ballaguet, J.L. Ambrosino, C. Streicher, J.P. Cousin, “Natural Gas Desulfidation with High Pressure Redox Process Sulfint”, Hydrocarbon Processing®, Gas Processes Handbook 2012.

186 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Examples of corrosion in an SRU unit (dry oxidation)

Figure 62.  –  Examples of corrosion in SRU: (a) Weld cracking; (b) Sulfuric acid corrosion of condenser; (c) Sulfuric acid corrosion of an heater head; (d) Sulfuric acid corrosion on a burner quill.

Figure 63. – Sulfuric acid corrosion of air injection quills for degassing, installed in a sulfur pit.

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Figure 64.  –  Sulfur Recovery Unit, P07 – Corrosion Location Diagram.

187

188 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 65.  –  Sulfur Recovery Unit, P07 – Material Selection Diagram.

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4.3.8.

189

SRU Tail Gas Treatment Units (TGTU) – P08

Many processes are available for treating tail gas from sulfur recovery units, most of them under license. Just as for sulfur recovery processes, they can be categorized according to the process implemented. • Catalytic reduction of SO2 to H2S then recovery of H2S by a solvent and treatment of H2S in the sulfur recovery unit: essentially SCOT, SCOT-LT, Resulf, LTGT, Sultimate, and HCR processes; • Catalytic reduction of SO2 to Sn and oxidation of H2S to Sn: SULFREEN, HYDRO SULFREEN, CLAUSPOL processes. These processes are based on the continuation of Claus’s reaction between H2S and SO2. The SCOT process will be the one discussed in this document (Shell Claus Offgas Treating, Shell Global Solutions B.V. license, marketed by Jacobs-Comprimo). However, most damage mechanisms and prevention solutions also apply to other processes. The SCOT process comprizes several options: • Conventional design (including all functions of the SCOT); • Economic design (standard in refining). Each option includes several possible configurations. A conventional design is considered here, with a high processing capacity comprising an on-line burner (or alternatively a heat exchanger), a radial reactor, a recovery boiler, a quench column, an ejector or a recycling extractor, a complete amine washing system (DIPA, MDEA, or Sulfinol M (mixture of Sulfolane and MDEA)), an amine regenerator and an incinerator. The process of LT-SCOT has been in use for several years. The catalyst provides a lower reaction temperature and improved conversion efficiency. The SCOT process provides an H2S to sulfur conversion rate of 99.8%.

4.3.8.1. Description of the process The tail gas of SRU units contains SOx (and traces of H2S) in amounts that are too great to be vented to the atmosphere. The process reduces the residual SOx to H2S, which is then recycled in the SRU unit. A conventional unit comprizes the following sections: • Heating of the feed: the tail gas is heated by mixing with the flue gas of a dedicated conventional burner (operating at slightly sub-stoichiometric conditions). A conventional burner is sufficient for most cases, given the reductive power of the tail gas. Nevertheless, a preliminary assessment must be

190 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

•

•

•

•

•

conducted, especially for E & P applications. In the LT-SCOT process, heat exchangers can be used instead of a burner; Reactor: the reduction is carried out on a special (licensed) catalyst; the SOx, S8, and COS gases are reduced to H2S. CO reacts with H2O to form H2 and CO2. Only about 85% of the CS2 is converted; about 35% is converted into CH4S and H2S at lower temperatures. There are several types of catalysts. Here, a conventional catalyst is considered, that can convert more CO; Cooling: After reduction, the processed gas is cooled in a recovery boiler. The heat is used to produce low-pressure steam. The gas leaving the boiler tubes is then cooled, and the water produced during the reduction reaction and by combustion in the line burner is condensed by direct contact with water circulating counter-current in the cooling column. During this stage, residual SO2 can dissolve in the cooling water. It is thus extremely important to monitor the pH in the cooling column; Recycled gas ejector or extractor: this system is used during start-up and shut-down phases and when the SRU is operating on by-pass. The system can only be used if high SOx emission rates are allowed for a limited time. Newer designs use an ejector. Older designs comprize a recycling extractor. Many corrosion problems were encountered owing to stand-by periods, which is why the ejector system is now preferred for new units; Amine absorption: gas cooled to 35–40 °C passes through an absorption column containing a selective solvent of H2S but not of CO2 (DIPA, MDEA, or Sulfinol M); the H2S is absorbed. The treated gas is directed to an incinerator. The gas leaving the incinerator is either directed to the flare or to a CO2 sequestration system; Amine regeneration: given the special solvents used, the operating conditions (low pressure in the absorber), and the presence of specific degradation products when large quantities of gas are treated, the best technical choice is to regenerate the solvent in a dedicated column (even though in the refining industry the solvent is often regenerated in the same regenerator as for the process unit).

4.3.8.2. Main damage mechanisms Sulfidation (DM#1) • Sulfidation can be observed at the reaction section level of the reactor and in the reactor outlet line: the standard temperature of the reactor is between 260 and 343 °C, it depends on the SO2 concentration of the load. If the exhaust temperature is above 350–370 °C, sulfidation corrosion may become significant. The corrosion rate normally does not exceed 0.25–0.4 mm/year because the partial pressure of H2S is very low. This damage does not occur if a “low-temperature” catalyst is used; • Sulfidation can also occur in the incinerator and flue system if there is circulation of H2S.

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Wet H2S Induced Cracking (Blistering/HIC/SOHIC/SSC) (DM#2) • If the unit is stopped without inerting, the entire unit may be subjected to conditions that promote H2S cracking corrosion. The most critical areas in normal service are: ○ The cooling section, the presence of H2S, even at very low partial pressures can cause such damage, ○ In the acid gas section and in the purge recovery circuits; the environmental severity is moderate to high, ○ Cold rich amine circuits: the environmental severity is considered low to moderate. The environmental severity is high in the hot rich amine circuit. Oxidation (DM#11) • High-temperature oxidation can potentially occur in the incinerator; it is unlikely to occur in the combustion chamber, except in cases of severe damage to the refractory. Corrosion by Acidic Condensates (DM#13) • The overhead gases of the quench column contain variable proportions of H2S and CO2; corrosion may develop in the presence of condensation. This form of corrosion is found mainly in the recycling line of the washing column; • The corrosion observed on wastewater equipment and piping may be assimilated to this type of corrosion; • The vapor phase of the regenerator reboiler is rich in CO2. Carbon steel may become corroded in the presence of condensation. Such corrosion is assimilated to corrosion caused by acidic condensates. Refractory Degradation (DM#14) • Refractory materials may suffer degradation in the burner, mixing chamber, and incinerator. Caustic Cracking (DM#18) • In the event of malfunction and if the water chemistry is not monitored, this damage mechanism could affect the LP steam drum and the outer wall of the recovery boiler tubes. The probability is negligible; • This can occur on non-heat-treated carbon steel in the cooling section when caustic solutions are used to readjust the pH. Caustic Corrosion (DM#19) • In the event of dysfunction, this damage mechanism could affect the LP steam vessel and the outer wall of the recovery boiler tubes. The probability is negligible;

192 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

• This can occur on non-heat-treated carbon steel in the cooling section when caustic solutions are used to readjust the pH. Neutralization is normally carried out with ammonia. Erosion - Corrosion (DM#P5) • Very low probability in low-pressure water-steam systems; • Corrosion-erosion can occur in rich amine circuits if the circulation rate is higher than 2 m/s but for carbon steel this is unlikely; • The vapor line from the reboiler to the column can be subject to erosion corrosion if there is excessive stripping. In SCOT units, it is accepted that the residual H2S in the stripping vapor must be higher than 100 ppm; • The gas outlet manifolds from the regenerator to the regeneration column are sensitive to erosion - corrosion in the event of fluid entrainment; • The cooling water recirculating pump of the column can be subjected to corrosion erosion if the water contains suspended solids. Carbonate Stress Corrosion Cracking (DM#21) • May occur in the cooling section if the pH is above 7.6. The probability of occurrence is higher when the pH exceeds 9.0 and the carbonate concentration exceeds 1000 ppm. Amine Cracking (DM#22) • This mechanism is only applicable to carbon steel. In practice, if DIPA-based solvent is used, all carbon steel equipment and piping that have not been thermally treated are susceptible to amine cracking. If an MDEA-based solvent is used, the probability of occurrence is lower and in practice limited to equipment that transports the hot lean amine. Chloride Stress Corrosion Cracking (DM#23) • Only applicable to austenitic stainless-steel equipment and pipes when the chloride concentration exceeds 1000 ppm weight. Sulfuric Acid Corrosion (DM#36) • In normal operation, the cooling wastewater contains H2S and NH3. The pH can be easily maintained within an acceptable operating range. In the event of a disturbance, residual SOx may become dissolved in the water thereby significantly lowering the pH; acid corrosion must be considered in such cases. The pH is controlled within an acceptable range with ammonia.

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CO2 and SOx Corrosion (DM#38) (Flue Gas Dew Point Corrosion) • If a unit is stopped without prior inerting, the entire unit may be subjected to conditions that promote CO2 and SOx corrosion. In normal service, the following elements must be monitored: ○ If the temperature in the steam generator is too low, water saturated with CO2 and SO2 may condense, thereby inducing the formation of a concentrated corrosive acid solution; corrosion is confined to condensation zones, ○ Acid gas circuit: this flow contains essentially N2 and CO2 with traces of SO2 and is water saturated, ○ Flue gas circuit: corrosion may occur if the temperature drops below the dew point. Such situations may happen if the steam generator, heater, or condenser tubes burst. The water concentration then increases in the tail gas, decreasing the dew point value. The probability is low in normal service. Amine Corrosion (rich and lean solvent) (DM#45) • All piping and equipment in the absorption and regeneration sections are potentially subject to this type of damage. The corrosion rate is usually negligible in the cold rich and lean amine circuit sections (less than 70 °C). It may be higher in the hot rich and lean amine sections, mainly in piping and heat exchanger tubes. The amine reboiler can be subjected to very severe corrosion. By order of severity, amine corrosion affects the reboiler tubes, the reboiler grate, the reboiler steam return line, the lower part of the regeneration column between tray 1 and tray 10, the hot amine lines and rich amine – lean amine exchangers. Generally, the corrosion rate is higher in SCOT sections than in AGRUs, due to the degradation compounds formed by reaction of impurities in the treated gas. Boiler Water / Condensate Corrosion (DM#50) • Specifically, in the boiler water circuit if the boiler water quality is not good. Low-Temperature Sulfur Corrosion (DM#P8) • The type of corrosion looks like oxygen induced corrosion, often with pitting or crevices. There may be an induction period of several hours to several months. It occurs in cold areas in the combined presence of sulfur and water; • In the cooling section, both sporadic occurrences and a chronically low SO2 concentration can be detrimental to carbon steel equipment. During SO2 conversion, a colloidal suspension of elemental sulfur forms in the solution. If it is not removed from the circuit, the sulfur may settle in certain areas of the quench column, where it may stagnate and lead to clogging and underdeposit corrosion; • In the acid gas circuit, low-temperature sulfur corrosion may be active if elemental sulfur is entrained from the quench column; • Can be found when sulfur accumulates in the dead legs of lean amine circuits.

194 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Formation of FexSy • Forms of iron sulfide can develop in the rich-lean amine exchangers, the regenerator and the reboiler. These compounds have no serious corrosion impact, but they can result in clogging.

4.3.8.3. Corrosion prevention solutions Materials used Carbon steel: are used in SRU tail gas circuits, preheating, catalytic conversion, SCOT tail gas, return lines to the SRU, feed water and steam. Carbon steel for wet H2S service: can be used in the quench column overhead circuits, the quench column, the amine absorption, and regeneration sections, and H2S lines to the SRU. Low-alloy steels: are used in the manufacturing of tail gas lines to the flue; the following alloys are used: 0.5 Mo, corten or equivalent, C-Mn, 1.25 Cr-0.5 Mo, or alternatively, hot lines to the flue can be partially coated with refractory materials. Instead, low-alloy steels are sometimes used to manufacture the shells of the line burner and the reactor. Austenitic stainless steels: are used in the construction of the reactor internals, and are often used to line the cooling column, in the construction of exchangers and air coolers in the cooling section, water pipes in the cooling column, water pumps. The amine regenerator is usually cladded, and the reboiler tubes are often made of austenitic stainless steel, as are the rich-lean amine exchangers. Conventional austenitic stainless steels do not withstand corrosion by sulfuric acid. Refractory steels and alloys: are used in the manufacture of heating elements and fasteners of ceramic materials. Ceramic materials: refractory concretes and cements as well ceramic fibers are used. Other corrosion prevention solutions Preventing sulfidation The mixing chamber, the reduction reactor, and the inlet of the recovery boiler may all be subjected to sulfidation conditions. The mixing chamber is insulated by a refractory and the rules governing its design and application are barriers to sulfidation. As for SRUs, the quality of the refractories used and of their installation are essential to long service lives. The corrosion rate is relatively low in equipment and lines that do not require being protected by a refractory. A corrosion allowance on carbon steel is sufficient for the intended service life. It is recommended that the skin temperature of the equipment and piping does not exceed 343 °C to limit the corrosion by sulfidation.

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Preventing generalized and localized CO2 + SOx Corrosion This is achieved essentially by design and construction rules that require maintaining the skin temperature 15 to 20 °C above that of the SO3 dew point. Unit shutdown rules must be focused on eliminating SOx from circuits or preventing condensation, and heat tracing as well as self-drainage of the gas lines should limit fugitive emissions. Valve bodies and their internals should be made of H2SO4 corrosion-resistant materials to protect them from corrosion by acid gases or liquids formed by dissolution of SOx. Additionally, seals should be installed to limit fugitive emissions. Preventing oxidation Implementation of operating rules for air monitoring according to the type of gas burnt, and rules for designing and installing refractories that can withstand corrosion. Preventing environmental stress cracking Stress cracking is usually due to the presence of wet H2S. The use of carbon steel complying with the NACE MR0175/ISO 15156 criteria is enough for protecting acid gas and condensate circuits. In the event of amine-induced stress corrosion, API RP 945 thermal heat treatment criteria should be applied [1]. In the event of carbonate stress corrosion cracking, stress-relieving heat treatment (at 650 °C) should be applied, (check construction codes exception criteria). Preventing fouling The recovery boiler tubes may lose their heat exchange efficiency under the effect of deposits caused by fouling due to two causes: • Unsuitable specification of refractory materials; • Clogging by sulfur deposits in the condenser tubes. Clogging is currently resolved by a periodic cleaning of the tubes. Integrity operating windows • Monitoring of [H2S]/[SO2] ratio: to monitor and prevent excess SO2, a constant [H2S]/[SO2] molar ratio specified by the licensor must be maintained in the feed. If the ratio is lower, there is a risk of elemental sulfur precipitation in the cooling water. This would result in rather significant corrosion. Excess SO2 increases the internal H2S recycling load. Too high concentration of SO2 increases the temperature in the reactor; • Monitoring the oxygen in the feed: oxygen consumes hydrogen, thereby reducing the conversion rate of SO2. The oxygen content in the feed must be kept to a minimum;

196 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

• Monitoring the temperature at the reactor outlet: target value 340–345 °C, with a maximum (critical) value around 355–360 °C to prevent sulfidation; • Recovery boiler outlet temperature: minimum 135 °C. Avoid SO2 and CO2 dewpoint corrosion. (Corrosion rates of about 3.0 mm/year have been observed); • pH of the cooling column water: standard limits are set to 6.5–8.5. The minimum threshold is defined for preventing acid corrosion of the neutralization column and related equipment. The maximum threshold is for preventing cracking in an alkaline environment (carbonates). The pH should be monitored every day; the measuring electrodes should be resistant to sulfides; • Turbidity of the water in the quench column: turbid water indicates the presence of elemental sulfur in the water, thereby increasing the probability of active corrosion. Turbidity should be monitored on a daily basis; black water indicates the presence of FexSy; • Temperature at the top of the quench column: the overhead temperature in the quench column must be above 32 °C in order to minimize entrainment of SO2 in the circulation water and the overhead circuit, should any SO2 remain. Below 32 °C SO2 is captured by the wash water; • Rich amine loading: depends on the type of amine, typically, for MDEA: Xc  0.02 to 0.05) This mechanism concerns the same equipment as above. 1. For the inlet vessels: the low points where iron sulfides and stagnant water accumulate are the most likely locations for such corrosion to appear; 2. For the gas section at the head of the column: corrosion is generally unlikely outside of areas where water accumulates, i.e., outside the bottom of the scrubbers and in the water drain lines, where the corrosion rate can reach 1 to 2 mm/year. The corrosion rate in tubes of coolers made of steel may also be very low, provided the gas flow rate is sufficient in the tubes (> 6 – 7 m/s). Nevertheless, it is probable that they will become corroded in the coldest part (30–50 °C), i.e., where condensation occurs when the flow rates are low. Under Deposit Corrosion (DM#P6) (fluids with and without H2S). In the absence of H2S: there is a potential risk of deposit accumulation (both mineral compounds and hydrocarbons) in the vessels at the column inlet. This problem of deposits and the related corrosion risks are nonetheless quite unusual, especially with light condensates. This is not a general problem that deserves special attention in the design phase. In the presence of H2S: there is a possibility that iron sulfide corrosion deposits may accumulate, as indicated above, and lead to preferentially induce corrosion locally. Also, whether or not H2S is present, potential salt deposits at the base of the stabilization column is a serious problem if the incoming fluid is insufficiently dehydrated and desalted (either due to lack of adequate desalting equipment, or to an insufficiently dehydrated fluid flowing into the process, and which cannot be fully supported by the “Stabilizer Feed Vessel”). In case salty water enters the system: • If the water is almost entirely evaporated, the salt from the water accumulates at the bottom, forming a thick, dry deposit, but without significant corrosion underneath; • If there is enough water left at the bottom (especially at moderate reboiler temperatures: ~120–150 °C), the salt deposit may be moist, and thereby cause corrosion of the metal underneath. Salt may also be deposited on the reboiler tubes; • This “moist salt” deposit situation would be even more critical with stainless steel at the bottom of the column or on the reboiler tubes, owing to the chloride-saturated water and high temperature combination; • A part of this salty water is mechanically entrained to the top of the column as a mist flow and is then found in the condensed water formed in the overhead cooling process of the extracted gas, possibly inducing serious Stress Corrosion Cracking issues if the selected material is not appropriate.

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Under deposit corrosion can also occur on the reboiler tube bundle if water remains in suspension in the liquid at the bottom of the column, as this water evaporates on the heating tubes. Sulfidation (DM#1) (streams with H2S) This is a sulfidation mechanism affecting steels with little or no chromium. It does not require any water as it is a reaction between the steel and the sulfides in the oils or condensates. This is a well-known phenomenon in refining units but rare in Exploration-Production processes. Sensitivity to this type of corrosion starts at temperatures in the range of 200–230 °C, which are rare in the E & P industry. In a stabilization unit, only the reboiler tube bundle is potentially subject to such corrosion, when temperatures in the lower part of the column reach at least 200 °C, and so higher for skin temperatures. In addition, the sulfur content in the condensate or oil must be greater than 0.1 to 0.2%. A first approximation used to predict this type of corrosion can be made as per the methodology described in API RP 571, section 4.4.2, using the McConomy charts. If the skin temperatures do not exceed 250 °C, the corrosion rate could remain within a range of 0.1 to 0.2 mm/year. Microbiologically Induced Corrosion (DM#P4) This corrosion is most likely affecting essentially the inlet filter, the separators and desalters upstream of the column, especially with fluids that do not contain H2S. In the case of desalting involving injected wash water, the water must not be contaminated by bacteria, to avoid corrosion in the desalter and in the water drain line. Finally, the oil or condensate storage tank is also a potential site of Microbiologically Induced Corrosion if water accumulates in the low points. Stress Corrosion Cracking of CRA (DM#P13) (fluids with H2S) Stress corrosion cracking has been encountered on coolers, scrubbers and on stabilization column outlets made of AISI 316L SS, in situations where chloride is abnormally present, as explained earlier [2]. Such corrosion occurs through a combination of chloride entrainment (defective desalting and probable concentration by evaporation of the water in the column), H2S and high temperatures in the coolers (50 to 130 °C). This combination is too severe for AISI 316L SS but alloy 825 has offered good resistance to this type of corrosion.

4.3.9.3. Corrosion prevention solutions Main solution: Carbon steel for the liquid section and CRA for the gas section General comment: The term “carbon steel” used herein includes types of steel specified for “H2S service” in cases where the H2S severity rating is ≥ 1 (according to NACE MR0175/ISO 15156). Carbon steel is the basic material for most equipment in contact with the liquid phase owing to dehydration in the upstream separation units, and to the fact that residual water is also usually subjected to upstream inhibitor treatment.

204 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

The pre-heater tube bundle should be composed of stainless steel (for use with fluids with little or no H2S) or of nickel alloy (for high H2S contents and acidic pH of the aqueous phase levels) if regular water ingress is expected (suspected deficiencies in the upstream separation processes). The column itself is usually made of carbon steel, in the upper gas-phase section: thermal insulation protects the wall from excessive water condensation, and thereby limits any corrosion to moderate levels. The only areas that must be made of non-corrodible materials are internals that may receive condensed water. However, the use of non-corrodible materials is the main solution for: • The internals of the stabilization column (trays or packing); • The entire wet gas section from the column outlet, where condensation water is present; • The liquid piping of the off-gas vessels. AISI 316L SS is resistant enough for the entire gas circuit: 1. In the absence or presence of only traces of H2S (up to 5.0 – 10.0 kPa), even in situations where there is potential chloride ingress from the produced water; 2. In the presence of up to several kPa of H2S, if it is certain that no chloride will be subsequently transported, owing to proper dehydration / desalting of the feed fluid. In other cases, 825-type nickel alloy can be used. Vigilance points The main vigilance point for such units is the dehydration and desalting quality of the fluid entering the stabilization tower. Special attention must be paid to start-ups and rapid flow variations, where there is a risk of transient flow dehydration/desalting. It is therefore important to monitor and control the emulsions upstream of the column inlet of this unit. Provided that dehydration and desalting are ensured by the proper design and operation of the upstream separation units, the liquid at the bottom of the column is practically anhydrous and the condensed water in the gas circuit contains only very little salty water, as it was so designed. Conversely, if the fluid is not properly desalted, there is a risk that salt may be deposited at the bottom of the column, thereby increasing the risk of corrosion in the sections transporting the liquid and gas phases, as discussed in section 4.3.9.1. Monitoring the water cut (BSW) and salinity of the inflowing fluid are therefore essential actions for these process units. Monitoring and controlling the foaming inside the column is also important, as foaming tends to entrain suspended water and oil contained in the feed.

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4.3.9.4. References 1 2

ASTM D323: “Standard Test Method for Vapor Pressure of Petroleum Products (Reid Method)”, American society for Testing and Materials. D. Zuili, G. Broye, A. Rabiniaux, “A case history of environmental cracking in sour service – Sulphide-Chloride ions Stress Corrosion Cracking on 316L Stainless Steel”, Eurocorr/2005, Lisbon, EFC, Sept. 2005.

Figure 68.  –  Sweet Oil – Condensate Stabilization Unit, P09a – Corrosion Location Diagram.

206 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 69. – Sweet Oil – Condensate Stabilization Unit, P09a – Material Selection Diagram.

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Figure 70.  –  Sour Oil – Condensate Stabilization Unit (CO2 + H2S), P09b – Corrosion Location Diagram.

208 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 71. – Sour Oil – Condensate Stabilization Unit (CO2 + H2S), P09b – Material Selection Diagram.

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4.3.10. Capture, Compression, Dehydration, and Transport of CO2 – P10 Given the environmental issues associated with global warming and the applicable Carbon Capture and Storage (CCS) laws, and despite the substantial additional cost of implementation, the deployment of an EOR (Enhanced Oil Recovery) and/or CO2 Storage policy becomes highly necessary. CO2 recovery is one of its components. After concentration and separation (the capture phase), the CO2-rich gas is compressed, then dehydrated, and finally transported up to its ultimate destination (EOR or final storage into geological layers). The processed CO2 can come from many types of units: AGRU, SRU, flue gas treatment (energy production, furnaces). In this document, we shall discuss only the compression and dehydration steps for a CO2- enriched gas containing little H2S. AGRU, SRU and/or TGTU upstream processes are covered in sections 4.3.4, 4.3.7, and 4.3.8.

4.3.10.1. Description of the process CO2 capture CO2 capture is highly developed in energy-producing industries (anthropogenic CO2), where three recovery routes are taken into consideration: • CO2 capture in pre-combustion: carbon is removed upstream from the fuels (syngas or HMU manufacturing units); CO is converted to CO2 in converters; CO2 is then captured by suitable system. This method is not used in E & P but is common in coal gasification and gas-to-liquid condensation units; • Oxy-Combustion: this consists in burning the fuel with oxygen previously separated from air. The method concentrates CO2 in the flue gas, making it easier to recover; • Post-combustion capture of CO2: this refers to the separation of CO2 from the flue gases using a physical or chemical absorbent. The flue gases contain a mixture of N2, CO2, H2O, O2, NOx and SOx; they may also contain halides and heavy metals. The aim of post combustion capture of CO2 is to selectively eliminate CO2 from the gas mixture. This is applicable in E & P for the recovery of CO2 from boiler or tail-gas incinerator flue. This classification is not fully applicable in oil and gas production where CO2 is essentially extracted from the produced gas, because when the CO2 concentration is high enough it can be picked up directly in the gas treatment section. Moreover, the CO2 contained in the produced gas is the main source of CO2 emitted by the EP industry, while the CO2 resulting from combustion processes or from Tail Gas Treatment units usually represents a much lower fraction. It is not excluded though that both sources of CO2 might be captured in a close future.

210 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

There are many ways of capturing CO2, and they are classified in several categories: • Phase separation by distillation or anti-sublimation, e.g.: Sprex®CO2 (Prosernat); • Absorption: ○ Chemical, ○ Physical, ○ Solid absorbents, • Adsorption; • Membranes. Chemical, physical or mixed (chemical and physical) absorption processes are the sole that are extensively used in E & P at the time of publication of this document. These are thus the sole ones covered in this section. Virtually all treatment processes are covered by licenses (solvent formulation, absorber design, operation). The solvent families used in E & P can be classified as follows: Chemical absorbents These are essentially the amine processes (AGRU) already described and covered in section 4.3.4. Physical or mixed absorbents Sulfolane – amine: the presence of sulfolane in solvents can effectively remove organic compounds (mercaptans, COS contained in the stream), the amine is usually activated or non-activated MDEA. In the EP industry, the main differences between the CO2 capture from produced gases, and from TGTU or from combustion processes are that: • The capture from produced gases is covered by the classical AGRU process described earlier. The sole significant impurity from a corrosion point of view can be H2S; • The capture from TGTU or from combustion processes (post-combustion or oxycombustion) concerns flue gases at low pressures (0.1 to 0.2 MPa(abs)) and they almost necessarily contain oxidizing impurities (O2, SOx and/ or NOx) and others: these impurities can have very severe corrosion impacts and they can also be very damaging to the amine solvents currently used for capturing the contained CO2. The following principles should be kept in mind, as long as the capture of TGTU or combustion gases is concerned: • The composition of flows to be treated is a sizing factor in the corrosion study: the NOx, SOx, O2, COS, CS2, halides and heavy metals (especially mercury) concentrations should be considered; • NOx and SOx can induce acid condensing waters with a pH lower than 1: flue gas is currently washed out with water to be cooled down before entering the capture unit. This cooling/ washing process must be well designed to remove the essential part of these SOx and NOx;

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• All amines, though most particularly MEA-based solvents tend to produce corrosive degradation compounds when exposed to SOx, NOx or to the oxygen contained in most flue gases. Large amounts of such degradation products must thus be anticipated when dealing with such units, even if some commercial amines are said to be inhibited. The solvents based on MEA (primary amine) and secondary amines (DEA, DGA, etc.) are not selective, so CO2 reacts with primary and secondary amines to form stable carbamates and bicarbonate that must, in some cases, be considered in corrosion mechanisms. DIPA exhibits reduced selectivity to CO2; • Tertiary amines, mainly MDEA, are selective as regards H2S absorption; there is no carbamate formation with CO2. However, degradation products, such as oxazolidones, can interfere with the absorption kinetics; • Activated tertiary amines (e.g.: ADIP-X (Shell), AMDEA (BASF) absorb CO2 without carbamate formation; their corrosiveness is comparable to that of non-activated MDEA; • There are few studies on the corrosiveness of sterically hindered amines, (e.g.: ExxonMobil’s FLEXSORB® process, KM CDR, Solvent KS-1 (MHI)). They are usually sensitive to the presence of SOx, which should be eliminated by pre-washing. The solvent is more or less selective as regards H2S absorption, depending on the formulation; • Mixed solvents (Sulfolane + MDEA) produce oxazolidones, their degradation products are very corrosive in the presence of CO2. Severe erosion-corrosion cases have been observed in units using these solvents; • In a hypothetical situation where CO2 captured from different sources should be mixed with some containing H2S, while others would contain some O2 and some residual SOx or NOx, the mixture of the two may induce the formation of free sulfur and strong acids: this combination of oxidizing impurities with some H2S is thus to be given a great attention. Compression, dehydration, transport, description of the process The gas to be treated consists of CO2 and water. It may also contain small quantities of impurities. As a rule, it enters the compression section slightly above 0.1 MPa (g). The temperature ranges between ambient and 50 °C. A first step is to remove most of the water by compressing the gas through several compression stages. The CO2-saturated water is condensed in the inter-stage condensers and evacuated to the wastewater treatment. Downstream of the 3rd compression stage, the gas phase contains very little water. The residual water can be eliminated by contact with tri-ethylene glycol (TEG) in a special section (usually package), this prevents the formation of hydrates downstream. The dehydration by glycol units is covered in § 4.3.5, so it is not detailed in this section. Dense CO2 is then compressed (or pumped, when it reaches a dense phase condition, in the liquid or super-critical phase) up to the necessary pressure for being injected to the receiving reservoir (a); it can be transported by pipeline or directly reinjected.

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As long as the dense phase is stable, no corrosion is expected because no free water is assumed to be present, even with 500 to 1000 ppm mol of residual water. However, if it is depressurized, it may separate into two phases if its dehydration is not low enough: a gaseous and an aqueous phase. Residual impurities (essentially H2S, NO2 and SO2) preferentially separate out into the liquid phase. Oxygen mostly remains in the gas phase but with a fraction being also dissolved in the aqueous phase. The resulting corrosiveness depends essentially on the nature of residual impurities, but it is always strong (with only CO2 and water) to extremely severe (e.g., with NO2 also being present). It is thus essential preventing the formation of such free aqueous phase, by a strict control of the level of water and impurities in the CO2 to very low levels. It is not within the scope of this document to state on acceptable limits, which are still a matter of testing and evaluation. Moreover, the acceptable level of one particular impurity is very dependent on the presence of others so not one sole “operating window” can be given. In particular, the most well-known compositional limits in 2019 are: • The Dynamis limits (Ref 20) coming from a synthesis done within the ENCAP European Project; • The NETL limits (Ref. 21) coming from a review of CO2 stream specifications from the literature (Department of Energy – USA). However, these limits better cover safety or toxicity matters than corrosion: more conservative or more specific limits may be needed if different impurities are combined.

4.3.10.2. Main damage mechanisms It is necessary to consider the presence of the impurities in the gas to be treated to determine the potential corrosion mechanisms. As outlined above, gas from the AGRU often contains traces of H2S while flue gases or gases from TGTU may bring impurities such as SOx, NOx, O2, halides… than can induce specific damages. These impurities are very important for characterizing corrosion in the dense phase. In this description, we consider that the gas to be treated contains CO2, water, less than 50 ppm H2S, and traces of NOx and SOx at few tens of ppm (which may come from TGTU). The presence of oxygen up to few % is also envisaged. Wet H2S Induced Cracking (Blistering/HIC/SOHIC/SSC) (DM#2) • If the wet gas circuit (up to the TEG absorber) contains traces of H2S, it is necessary to evaluate the sour severity at each compression stage. Within the scope of chosen assumptions, the severity of the fluids will remain at level 0, apart for pressures above 2 – 3 MPa, because of the low pH of the water ( 1.5 to 2 m/s). A high amount of acidic degradation products should enhance this corrosion tendency; • In the TEG absorber and TEG circuit: potential erosion-corrosion downstream of the pressure control valve located upstream of the flash drum. Degradation products can cause erosion - corrosion in the rich TEG pipes. Cavitation (DM#28) • Possibility in the pressure control valve located upstream of the flash drum in the TEG section, but with a very low probability. Brittle Fracture (DM#31) • It is necessary to assess the MDT (Minimum Design Temperature) value in the event of sudden depressurization of the equipment in the wet gas and dry gas circuits under high pressure, particularly from liquid or super-critical CO2 phase. The MDT is determinant in the selection of materials. CO2 Corrosion (DM#P1) • In the wet gas section, the gas to be treated consists essentially of CO2 and water (assuming no other impurity). The potential for CO2 corrosion is high, especially in the separators, the recirculating lines, the liquid drain lines and inside and downstream of the condensers. It is less intense in the gas lines. In service conditions, it should be negligible in the compressors’ outlet piping; • In the TEG section, the TEG becomes enriched with CO2 in the absorption column; it potentially becomes corrosive to carbon steel. However, the very low water content (few% max in the rich TEG) minimizes this corrosiveness, when compared to the upstream section; • In the dry gas and dense phase section, CO2 corrosion is negligible in normal operating conditions. There may be corrosion during the commissioning phases and during deviations from normal operation if some free water may be present. A defective dewatering is a particular concern during the start-up period. Oxygen Induced Corrosion (DM#P7) • Oxygen is first a strong degradation factor for amines used for CO2 capture from flue gases. This may have a very serious impact on the corrosiveness of the amine itself; • Oxygen in a dry CO2 has no corrosion impact. On the other hand, it enhances the CO2 corrosiveness of any free water, if present at any time; • Oxygen is also a glycol contaminant. It may cause pitting corrosion on steel, and at reboiling and purification temperatures, it promotes the development of crevices on austenitic and duplex stainless steels. It also may induce selective corrosion of the ferrite phase of some duplex stainless steels. It is however difficult to predict if this may result in serious corrosion issues as long as the TEG contains little amount of water and is not supposed to receive noticeable amounts of chlorides. It is thus essentially in a situation of accidental chlorides entry that this might become a problem.

214 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Corrosion by organic acids (as a reminder) • Oxidation of TEG or MEG can lead to the formation of organic acids – mainly glycolic, glyoxylic, oxalic, formic and CO2. Carbon steel may undergo corrosion by organic acids; corrosion sensitivity is low for CRA, despite the absence of oxygen. Corrosion rate can be fast above 204 °C. Sludge drainpipes are highly susceptible to such corrosion. The presence of oxygen promotes the formation of organic acids. Whether this problem is serious or not also depends on whether the TEG is pH stabilized or not as a preventive action. Explosive decompression of seals (as a reminder) • Owing to its high solubility in elastomers and its solvent properties, CO2 at high pressure poses the specific problem of elastomer resistance. This is especially true in cases of fast decompression in which the elastomers can decompress explosively, with blistering and/or tearing. However, CO2 may also induce a swelling of some elastomers. Corrosion by products of oxidizing impurities (as a reminder) • Depressurization of the dense phase causes the residual impurities in the liquid phase to become more concentrated, to react with residual oxidizing species, potentially forming corrosive compounds. The following simple reactions may occur, but also several others combining the contribution of other intermediate impurities: 2H 2 S  O 2 

2 S  2 H2O x x

4 NO2  O2  2H 2 O  4HNO3 SO2 

1 O  H 2 O  H 2 SO4 2 2

All of these impurities start causing severe corrosion problems despite moderate impurity levels, in the range of a few tens of ppm, with some water also being needed. A depressurization is particularly critical as it reduces most solubility limits of the by-products, making them form quickly. Products involving reactions with NOx are apparently more corrosive than those involving SOx. However, the two are severe enough not to accept the risk of such strong acid’s formation.

4.3.10.3. Corrosion prevention solutions Materials used Carbon steel: carbon steel is used only as a corrosion resistant material in dry CO2 environments and on TEG sections, as its use remains compatible with the MPT. Low-temperature carbon steel: used in dry and dense-phase CO2 sections, it can also be used in the dehydration section.

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CRA: mainly used in wet gas and the regeneration part of TEG units, either plain or as a lining or overlay. Austenitic or duplex stainless steels can be used. Grades of CP Titanium or titanium alloys are sometimes used in TEG sections. CRAs are also currently used in amine units treating flue gases, because of the large amount of degradation products that shall be formed. Other corrosion prevention solutions Preventing CO2 corrosion Wet CO2 sections: • Essentially by using CRA in wet areas; • If carbon steel is used in potentially wet sections, maintain sufficient slope for gas piping to prevent any water settlement and heat trace and insulate these same lines to limit condensation. Avoid low points and dead legs. Dense phase CO2: the key prevention is to assure no free water to be formed, by a sufficient drying and all necessary precautions to prevent down-graded situations with some free water. A particular care to be given to accidental depressurization and to down-graded dehydration situations. Prevention of H2S cracking corrosion in wet environments (HIC/SOHIC/SSC) Where necessary, select suitable materials compliant with NACE MR0175/ISO 15156. Prevention of brittle fracture Select suitable materials: low-temperature carbon steels, CRA. Prevention of corrosion by organic acids Select suitable materials, Integrity operating windows. Prevention of corrosion by oxidizing impurities Strictly limit the amount of impurities and water in the dense phase. Assure a robust monitoring to verify that these limits are followed. Prevention of erosion - corrosion downstream of pressure control valves Corrosion is prevented through the design of the piping system that prevents too high velocities, or the use of CRA if such velocities cannot be avoided. Prevention of cavitation Correct design of the pressure control valve; use of CRA.

216 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Prevention of explosive decompression of seals The elastomers used must be qualified for chemical resistance when exposed to CO2 high-pressure conditions, in particular their resistance to explosive decompression: several fluorinated elastomers (FKM) and per fluorinated (FFKM) are suitable for this service. However, they must be qualified in the condition’s representative of the maximum severity rating of the service. Integrity operating windows Amine units: same as for AGRU with a due attention to the thermal degradation and to the content in Heat Stable Salts and other degradation products. Wet Phase: check the partial pressure of H2S and other contaminants vs specified limits. Regeneration of TEG: temperatures vs. materials (prevention of brittle fracture); maximum regeneration temperature (avoid decomposition of TEG and formation of organic acids); flow rate (circulation rate < 2 m/s for CS, < 3 m/s for CRA); the pH must be maintained between 6.5 and 8.0; limit oxygen ingress to avoid decomposition and formation of oxygenated compounds; salts < 3.5% weight; check for filter pressure drop and replace cartridge depending on the pressure drop. Dry Phase: temperatures vs. materials (prevention of brittle fracture), temperature vs. dew point of water to avoid CO2 corrosion. Dense Phase: temperature vs. materials (prevention of brittle fracture), impurity levels versus specifications. Standard Steel: Which preventive solutions should be implemented? The use of carbon steel is relatively limited in the wet side of these units and in amine unit. The limiting factors are the MDT, often below – 60 °C and the potential corrosiveness of the wet phases. Low-temperature carbon steel can be used in the dry CO2 and dense CO2 circuits (provided the MDT value is compatible).

4.3.10.4. References 1

NACE TM0192, “Evaluating Elastomeric Materials in Carbon Dioxide Decompression Environments”, 2012.

2

NACE TM0297, “Effects of High-Temperature, High-Pressure Carbon Dioxide Decompression on Elastomeric Materials”, 2017.

3

Luuk Buit, Mohammad Ahmad, Wim Mallon, Fred Hage, “CO2 EuroPipe study of the occurrence of free water in dense phase CO2 transport”, Energy Procedia, vol. 4, 2011, pp. 3056 - 3062.

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4

Arne Dugstag, Malgorzata Halseid, Bjørn Morland, Anne Olaug Sivertsen, “Corrosion in dense phase CO2 corrosion and the impact of depressurisation and accumulation of impurities”, Energy Procedia, vol. 37, 2013, pp. 3057-3067.

5

Arne Dugstag, Malgorzata Halseid, Bjørn Morland, “Effect of SO2 and NO2 on corrosion and solid formation in dense phase CO2 pipelines”, Energy Procedia vol. 37, 2013, pp. 2877- 2887.

6

Yoon-Seol Choi, Srdjan Nešić, “Determining the corrosive potential of CO2 transport pipeline in high pCO2-water environments”, 2011, International Journal of Greenhouse Gas Control, 2011.

7

Capturing CO2, Global CCS Institute.

8

What is CCS, Factsheet, Global CCS Institute.

9

Geologically Storing CO2, Factsheet, Global CCS Institute.

10

CO2 Capture Technologies, Pre-Combustion Capture, 2012, Report, Global CCS Institute.

11

CO2 Capture Technologies, Oxy-Combustion with CO2 Capture, 2012, Report, Global CCS Institute.

12

CO2 Capture Technologies, Post-Combustion Capture, 2012, Report, Global CCS Institute.

13

CCS Learning from the LNG Sector, WorleyParsons for the Global CCS Institute, Report 401010-01060-00-PM-REP-0001, Dec. 2013.

14

Development of novel ionic liquid to Capture CO2, CSIRO, project 3-05100050, June 2012.

15

Project Environmental Impact of Amine-Based CO2 Post Combustion Capture (PCC) Process, Activity 3: Process Modelling for Amine Based Post Combustion Capture Plant, Deliverable 3.2, Progress Report, June 2012, CSIRO.

16

Arne Dugstag, “Knowledge Sharing Report: CO2 liquid Logistic Shipping Concept (LLSC) safety health and environment (SHE) report” Global CCS Institute, 2011.

17

Emily Ho, “Elastomeric seals for rapid gas decompression applications in high-pressure services”, HSE 2006, Research report 485.

18

Prachi Singh, “Amine Based Solvent for CO2 absorption: From Molecular Structure to Process”, Thesis, University of Twente, The Netherlands, ISBN 978-90-365-3200-6, 2011.

19

“Corrosion and Material Selection for Carbon Capture and Storage”, IEAGHG presentation 2010/3, April 2010, IEA Environmental.

20

E De Visser, C Hendriks, M Barrio, MJ Mølnvik, G de Koeijer, S. Liljemark, YL Gallo, ”Dynamis CO2 quality recommendations”, Int. J. Greenhouse Gas Control 2, (2008), 478.

21

NETL Quality Guidelines for Energy System Studies, ”CO2 impurity design Parameters”, DOE/NETL-341/011212, 2012.

218 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 72. – CO2 Capture, Compression and Dehydration Unit, P10 – Corrosion Location Diagram (1).

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Figure 73. – CO2 Capture, Compression and Dehydration Unit, P10 – Corrosion Location Diagram (2).

220 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 74. – CO2 Capture, Compression and Dehydration Unit, P10 – Material Selection Diagram.

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4.4. Utilities 4.4.1.

Water Treatment Units - U01

This chapter deals with conventional processes for treating produced water in oil production facilities, through the implementation of means such as cyclones, degassers, floatation units. It does not cover deoiling by aeration in retention tanks (API tanks), nor the ultimate biological treatments, usually in aerating ponds. Any possible specialized treatment for desalting, oxidation, etc. are also not included. Note: The U01 descriptive diagram illustrates a simplified water treatment unit. Comments are added below, as needed, for supplementary equipment (filters, flotation units).

4.4.1.1. Description of the process The objective of a produced water treatment process is to deliver water at the specifications required for subsequent use, which may be: • Release to the external environment, or even supply to third-party users, for whom the specifications are primarily of environmental concern; • Release to producing reservoirs or to “wastewater wells”, for which the specifications mainly have to do with the preservation of the injectivity, i.e., concerning solids and suspended hydrocarbons. The main treatment requirements for these processes (excluding the ultimate biological treatments) concern the following three functions: 1. The removal of solid particles (sand, sludge, etc.), often using hydro cyclones and retention tanks; 2. The reduction of dissolved and suspended hydrocarbons (using hydro cyclones, decanters, floatation units, etc.); 3. Degassing, including the elimination of dissolved H2S, for produced fluids from pressurized vessels (using degassers, strippers).

4.4.1.2. Main damage mechanisms General note: the water treatment units are designed to proceed partially degassed fluids, containing less dissolved CO2 and H2S than the process facilities further upstream. However, these units almost exclusively treat water containing only traces of hydrocarbons and often solid particles, so they do not benefit from any of the protective effects resulting from reduced water-wetting, as can be the case in upstream installations containing scarcely hydrated fluids subjected to flow rates high enough to ensure mixing of the oil and water phases.

222 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Sulfide Stress Cracking (SSC) (DM#2) (fluids containing enough H2S to reach a severity rating ≥ 1, according to the NACE MR0175/ISO 15156-2 severity chart). This is a significant risk as it is likely to generate fast cracking, either due to SSC of hard areas (improper welds, unsuitable materials) or HIC and SOHIC (laminated products, welded tubes with insufficient chemical purity). However, owing to the moderate service pressures of most of the relevant equipment and the high pH of the already partially degassed reservoir water, SSC is an issue only for produced fluids from gas fields, with high H2S concentrations (in the range of 0.1 to 1%). CO2 Corrosion (DM#P1) (fluids containing little or no H2S: H2S/CO2 < 0.02 to 0.05) This corrosion potentially concerns all the processing chain equipment made of steel, with a stronger corrosiveness of the equipment located upstream of the degassing unit, with waters containing the highest concentration of dissolved CO2. It decreases downstream of the degasser and in the water discharge lines. The corrosiveness is the higher as the treated waters are acidic (< pH 5 to 6), warm (40 to 60 °C) and still containing some dissolved CO2 (10 to 100 kPa). Corrosion rates ranging from 0.5 to 2 mm/year may occur if no preventive measures are implemented. H2S + CO2 Corrosion (weight loss corrosion) (DM#P2) (H2S content such as H2S/ CO2 > 0.02 to 0.05) This mechanism concerns almost all the same equipment as above. Severity is generally lower, at least partially due to the protective character induced by sulfide formation. This is true provided there is no oxygen ingress in the fluid due to low pressures and to the diversity of sources of treated water. Oxygen ingress due to lack of blanketing, of sealing, or supply of aerated water, is one of the main corrosion hazards in a water treatment unit, particularly in the presence of H2S. This is to be prevented with a great attention. Microbiologically Induced Corrosion (DM#P4) This mechanism is the main source of corrosion of processing unit vessels and water pipes. These units associate several factors favorable to microbiologically induced corrosion: • • • •

Water in abundance; Generally moderate temperatures, propitious to bacterial development; Moderate flow conditions, at least in the vessels; Frequent accumulation of deposits, especially in vessels.

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Theoretically therefore, microbiologically induced corrosion is the damage with the most adverse effects for the piping of water treatment processes; the vessels themselves being usually protected by coatings and sacrificial anodes. Under Deposit Corrosion (DM#P6) (with and without H2S). As deposits can accumulate in some parts of a produced water treatment process, “Under deposit corrosion” constitutes a potential damage mechanism. In practice the damage mechanism can also be microbiologically induced corrosion favored by the presence of deposits. Greater difficulty in controlling CO2 or H2S + CO2 Corrosion (weight loss corrosion) can also result from the formation of deposits. Erosion - Corrosion/ Erosion (DM#P5) (fluids with or without H2S) This erosion - corrosion mechanism can be observed in singular points of the treatment water process subject to high flow rates: 1. Tees; 2. Reductions; 3. Hydro cyclone inlets-outlets; 4. Produced water impact areas. The presence of solid particles suspended in the water to be treated is the main negative factor contributing to damage in critical flow zones, including when inhibitor treatment is implemented: solid particles impacting the metal surface may completely thwart the action of corrosion inhibitors. Even though no area is systematically subject to this type of corrosion, it concerns mostly the piping in the sensitive areas indicated above. Failure can occur in as short a time as 2 to 3 years. In short: 1. Water treatment unit piping on oil installations, e.g., drain systems, are particularly subject to corrosion failure for 4 main reasons: a. Moderate wall thicknesses, owing to relatively low pressures and diameters involved, b. Failure is considered less critical, so installations are subjected to lower vigilance, c. Easy, frequent bacterial development, favored by retention times and deposits in vessels, d. Legitimate reluctance to apply additional anti-corrosion treatment just to protect these installations when the water must then be discharged directly to the natural environment (environmental impact), 2. Oxygen ingress is a major contributor to corrosion. This is a major vigilance point on such a facility, as detailed in section 4.4.1.3, in the section on “Other preventive means and vigilance points”;

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3. Strong bacterial contamination is common: although this is not very dangerous for vessels protected by internal coatings and cathodic protection, bacteria are usually the most probable cause of leakage in steel piping. Therefore, non-corrodible materials should be used more systematically, rather than corrosion inhibitors.

4.4.1.3. Corrosion prevention solutions Main solution: standard steel General Note: The name “carbon steel” used herein includes the versions specified for “H2S service”, in situations where the H2S severity ranking (NACE MR0175/ISO 15156) is ≥ 1. Standard steel is usually the main solution for water treatment plants since it is also used for water systems in the upstream separation systems. This is particularly justified for vessels, which benefit from additional corrosion prevention by coating and cathodic protection. Conversely, using a non-corrodible solution (usually stainless steel) for upstream networks justifies a similar choice for most water treatment piping. The underlying reasons for using standard steel piping are: 1. An inhibitor treatment is used upstream to protect the piping and separation facilities: why would they not also apply to the produced water systems; 2. Less danger and criticality when accidental leakage occurs than on upstream facilities. This justification has several limitations, which explains why failures are more frequent than on upstream facilities: • Losses of most of the inhibitor injected upstream in the oil phase, during the separation process, owing to the unfavorable partitioning of the inhibitor in the oil phase: serious risk of lack of inhibition if no make-up is added to the produced water downstream the separation process; • Increased microbiologically induced corrosion in these networks, as noted above; • A mixture of water from various sources, diluting or altering the effectiveness of the inhibition treatments. The increased use of non-corrodible materials is therefore legitimate on such facilities. Use of non-corrodible materials Non-corrodible materials are systematically used for hydro-cyclones owing to the high risk of erosion-corrosion and mechanical erosion (duplex and ceramic materials for cyclone surfaces exposed to high flow rates).

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For piping systems that transport insufficiently inhibited and/or highly corrosive water, potentially non-corrodible materials that can be used include composite materials; these deserve to be used more extensively with respect to what most operators practice at the date of publication of this document. The use of stainless steel is the other possible solution. AISI 316L SS is suitable for most produced waters and oily waters, which are normally deaerated. The main danger here pertains to the risk of periodic or permanent oxygen ingress, which induces localized pit and crevice corrosion due to the high chloride concentrations in most produced waters. Strictly avoiding oxygen ingress in a water treatment plant is a normal challenge for facilities constructed of metallic materials, both standard steel and stainless steel. Otherwise, the use of non-metallic materials should be preferred. Coatings and cathodic protection The combination of internal coatings and cathodic protection (sacrificial anodes or impressed current) is a conventional, effective means of protecting parts of vessels filled with water, i.e., most of the treatment vessels of this process. Provided that the sizing is appropriate, the used anodes are periodically replaced during inspections, and that the coatings undergo proper maintenance, this solution ensures effective, durable vessel integrity. Chemical treatments The nature of the treatments carried out upstream and the destination of the waters that go through the treatment sequence determine the specific treatments for the produced water treatment loop. • Upstream inhibitory treatments: even though the water is subjected to upstream inhibitor treatment to protect the production lines and facilities, the treatment also applies to the water treatment chain, subject to the three following conditions: ○ The oil – water separation process does not transfer most of the inhibitor to the oil phase (unfavorable oil-water partitioning) in the separation facilities. Otherwise, additional treatment will be necessary; ○ The produced water treated following the separation treatment is not too diluted by uninhibited water from other processes (e.g., gas compression). Otherwise, further treatment will again be necessary; ○ Oxidizing agents (dissolved oxygen or other) do not flow into the water to be treated. As already indicated, such ingress induces significant corrosiveness but also further alters most of the inhibitors used in production facilities. • Upstream biocide treatments: ○ Even though the produced water is subjected to an upstream biocide treatment, it is unlikely that the treatment can also be effective for the

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water treatment chain. This chain contains several vessels that offer a significant residence time (decanter, floatation unit, storage tank), with a view to separating the residual oil from the water: a highly dosed biocide treatment, adapted only to the upstream facilities, has too high probability of being strongly diluted in the great water volume of these vessels to ensure effective decontamination; ○ Consequently, if the water treatment chain requires significant decontamination of its vessels and piping, a special complementary treatment must be implemented for that purpose. In this case, the treatment should start with any possible cleaning action to remove deposits in place and a purge at the minimum levels of water should be in place (to reduce the volume of product required and ensure the longest residence time). • Destination of treated water: ○ If the water is destined to be released to the environment, for example in an aerating pond, any addition of treatment products specific to the water treatment unit is unsuitable as it “lades” the water with products that the downstream units will have to eliminate before it is released: it is best not to add additional loads just for a single unit, and to focus on noncorrodible solutions instead; ○ If the water is to be reinjected into the production reservoir, the treatments, and overtreatments, as discussed above, are recommended, as the entire reinjection network will certainly not comprize non-corrodible materials. In the event of reinjection, it is particularly important that the “microbial load” be moderate, so that the water coming / leaving the last stages of the process will be properly decontaminated; ○ If the water is to be discharged to a wastewater well, the choice of either of the solutions above will depend on the selected materials (non-corrodible or corrodible) for the entire injection system. Other preventive means and vigilance points The two most important vigilance points concerning these facilities have been highlighted several times in this chapter: oxygen ingress and bacterial contamination. • Risks of oxygen ingress The most common sources of oxygen ingress are: 1. Poorly maintained sealing on vessels operated at atmospheric pressure. It is important to make sure that these seals are preserved and that the damaged joints are replaced; 2. Periodic ingress of oily water from external aerated sources (open drain vessels, settling tanks, slop tanks...). Before entering the installation, such waters must be treated with an oxygen scavenger, or rather with a product that combines anti-oxygen and bactericide properties; 3. Defective blanketing in vessels and tanks at atmospheric pressure (gas not fully deaerated or gas flowrate at inlet lower than the flowrate at the liquid intake pumps). In the first case, the blanketing gas must be “oxygen free”

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as much as possible, at least not exceeding 3% oxygen. It is also important to make sure that no water enters above the liquid level, to minimize turbulence and mixing between gas and liquid. In the second case, the flowrate of the blanketing gas must be adjusted to the capacity of the liquid recycling pumps. • Bacterial Contamination. According to chapters 4.4.1.2 and 4.4.1.3, bacterial contamination can be the cause of microbiologically induced corrosion.

Figure 75.  –  Water Treatment Unit, U01 – Corrosion Location Diagram.

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Figure 76.  –  Water Treatment Unit, U01 – Material Selection Diagram.

4.4.2.

Seawater Injection and Cooling Unit - U02

This chapter deals mostly with seawater injection units, as shown on sketches U02. The seawater is subjected to deaeration treatment. By extension, the chapter also briefly covers: 1. The potential use of the seawater for cooling purposes; 2. The potential mixing of the deaerated seawater with some produced water; 3. The possibility of injecting raw, i.e., not deaerated seawater.

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4.4.2.1. Description of the process A summary of the main functions of a seawater injection and cooling system is shown in figure 77 below. From produced water process

Cooling

Filtration

Oxygen removal

Sulfate removal

HP pumping

To injection pipeline & wells

Sea Water Lifting

Figure 77.  –  Functional description of a seawater injection and cooling network.

• Seawater lifting consists mostly of vertical centrifugal pumps immersed in seawater and contained in a vertical caisson. A chlorine-based chemical is injected at the inlet of the pump to prevent the development of marine fouling inside the caisson; • The cooling unit usually consists of seawater/cooling water exchangers used to cool down a closed cooling water network. Compact plate exchangers are currently used on offshore facilities, because of their very moderate size; • The filtration part is usually made of several successive steps, from a rough pre-filtration (sand or multi-media filtration) up to micro-filtration by membranes. The level of filtration is mostly dictated by the specified amount and maximum diameter of particles that can be accepted by the receiving formation. The successive filtration devices may be located at different positions along the unit, before or after the other parts mentioned here; • The oxygen removal unit aims at reducing the dissolved oxygen content to levels low enough to prevent any significant corrosion by O2 (DM#P8) downstream. Several deaeration processes exist, among which the most usual are: ○ Vacuum stripping, ○ Stripping by recycling nitrogen (Minox™ unit), ○ Fuel gas Stripping, • The HP pumping unit aims at providing the necessary pressure to the injected water to ensure its transportation along injection pipelines to injection wells and its injection to the receiving formation. The injection pressure can typically range from few mega Pascals to 20-30 MPa; • The injection network consists of pipelines and injection wells. This part is not formally included in the U02 unit covered in this section, even though most corrosion prevention actions taken on seawater injection units aim at protecting this final but essential part.

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Other secondary functions are also included in such units, though not shown in figure 77: • • • • • • •

Chlorine unit; Booster pumps; Oxygen scavenger treatment; Backwash processes for some filters and membranes; Vacuum pumps for vacuum stripping units; Biocidal treatment; Etc.

In addition to these basic functionalities, several options and specificities can be added to such units: 1. The Sulfate Reducing Unit (SRU) is an optional unit used when the seawater is injected into reservoirs whose waters contain large amounts of Barium and/or Strontium. Because of the low solubility of the barium and strontium sulfates, most sulfates contained in the seawater (~3000 mg/L) must be removed to prevent severe scaling where the injected water and the reservoir water might mix. Such units are made of specific membranes, in one or two successive stages; 2. The injected water may be a mix of seawater and produced water recovered from the produced fluids (from separation and produced water treatments). Over time, the fraction of produced water may range from 0 to more than 3/4 of all the injected water; 3. The seawater may be injected with no deaeration: this option may be of interest if the injection network is short, hence if it does not require significant investments in terms of weight and cost for corrosion resistant materials. In such cases, the benefit gained by not installing an oxygen removal unit may be worth the expense for corrosion resistant solutions along the injection network (pipeline and wells); 4. The seawater may be injected without deaeration or filtration: this may be of interest in similar conditions as above, for reservoirs with a permeability high enough to avoid the use of significant filtration. Another possibility, not covered in this section, is the possible use of raw seawater as a direct source of cooling water. The main issue in such case concerns the proper choice of heat exchangers that can accommodate, firstly, aerated seawater at quite high temperatures and secondly, process fluids.

4.4.2.2. Main damage mechanisms Oxygen Induced Corrosion (DM#P7) Even though the solubility of oxygen in seawater is quite moderate (4 to 8 mg/L depending on the temperature and the depth), this is enough to induce a serious corrosion on a carbon steel surface (within 0.5 to 1 mm/year at moderate flow velocities and ambient temperatures and several mm/year at high flow velocities).

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It is exactly because of this corrosiveness that bare carbon steel is never used as a base metal for aerated seawater networks unless it is subjected to cathodic protection. Plastic and GRP (Glass-reinforced plastic) materials, copper alloys, titanium and highly alloyed stainless steels are the usual materials used in such waters. It is also for this reason that seawater deaeration is the first corrosion mitigation solution used when considering building the main seawater injection network out of carbon steel. Corrosion by dissolved oxygen is also a possible damage mechanism along the deaerating section, if the deaeration is insufficient. The specified residual oxygen to prevent noticeable corrosion by oxygen is within a range of 20 to 30 ppb (parts per billion). Operators may then specify conservative limits (down to 5-10 ppb) to reinforce the emphasis on proper deaeration before water enters the main injection network. Microbiologically Induced Corrosion (DM#P4) MIC also is a major damage mechanism which can be observed on the carbon steel deaerated section of an injection network. The anaerobic nature of the water combined with the huge reserve of sulfates and likely the presence of enough quantities of nutrients makes such corrosion damage the most challenging to manage on the deaerated section of the network. This MIC is even more likely when a mixture of seawater and produced water are injected together: • The seawater provides plenty of sulfates for sulfate-reducing micro-organisms; • The produced water is frequently seriously contaminated with bacteria and provides much larger amounts of nutrients (carbon nitrogen, phosphorus) than filtered seawater. On the other hand, Sulfate Removing Units (SRU) may be installed in the seawater process, to prevent scaling where reservoir waters contain high enough amounts of strontium or barium cations, as indicated above. Such units can reduce the natural sulfate content in seawater, from 3000 mg/L down to 20 – 40 mg/L by nanofiltration using special membranes. Such treatment is very effective in terms of MIC, essentially for two reasons: 1. It significantly reduces the sulfate content; 2. It filters all micro-organisms that may be present at the membrane inlets, the only excepting being possible local by-passing of the membranes in the event of damage, SRUs can also filter most organic carbon compounds that act as microbial nutrients. However, this is not fully documented so it is not highlighted as a decisive benefit. Under Deposit Corrosion (DM#P6) Some water injection pipelines are subjected to the accumulation of some solids, from sand carry-over through the filters, from pre-existing rust and from particles

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entered after the pipes are laid, or from corrosion products formed by a residual corrosion during service. This has resulted in several cases of grooving corrosion at the bottom of water injec­ tion lines shown in paper [1], another example being also included in figure 78 below.

Figure 78.  –  Grooving corrosion morphology on a seawater injection pipeline.

Even though such corrosion damage has sometimes been ascribed to an erosioncorrosion process, this contribution is no longer seriously into consideration, as it occurred essentially at flow velocities that were low enough to allow solid particles to accumulate, whereas it is no longer observed at higher flow velocities. The most acknowledged mechanism is that the accumulation of solid particles favors local microbial development and activity, while hindering the effect of any biocidal treatment. So, corrosion continues with galvanic coupling between the particle-covered surface (anode) and the remaining part of the surface, subjected to a distinct surface coverage by a thin iron sulfide layer. It is not excluded that the flow velocity has an indirect influence on the stability of the local chemistry or on the local corrosion layer, but not as an erosion-corrosion process (it makes hardly any sense to ascribe a corrosion phenomenon to erosion if it disappears when the flow velocity is increased). Erosion-Corrosion (DM#P5) Local erosion-corrosion morphologies are sometimes observed on carbon steel at the outlet of elbows or on impact areas, when the two following conditions are combined: • High water velocities, above 3 to 5 m/s; • Presence of significant amounts of corrosive species, i.e., too much residual oxygen or some residual CO2 from produced water, if present. Erosion-corrosion is also a known corrosion issue on copper alloys that may be used on the aerated water network. Depending on the alloy used, limiting water velocities are in the range of 2 to 3 m/s.

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Galvanic Corrosion (DM#53) This type of corrosion is mostly observed in two cases. 1. On the seawater lift pump caisson (see next chapter describing this in more detail): ○ The outer caisson, usually made of carbon steel, facing successive pump bodies, made of stainless steel or copper-nickel alloys. These bodies represent quite a large developed surface (see drawing); ○ A severe galvanic attack has frequently been observed opposite each of these bodies, especially concentrated on the surface closest to the pump bodies; ○ In some cases, this annular corrosion has led to complete detachment of the lower part of the caisson; ○ The section most concerned is the one permanently immersed, but not close to the lower seawater inlet, as some external cathodic protection of the platform also benefits the internal caisson surface. 2. Occasionally on piping, vessels, and devices where the selection of the material was unsuitable, such as in the following cases: ○ The most usual mistake involves the use of copper alloy bolting or small components on stainless steel surfaces: copper alloy is the anodic material and hence corrodes quickly when it is the smallest surface (a small anode and a large cathode are the worst configuration for galvanic corrosion); ○ The accidental inclusion of a carbon steel component in equipment made of copper alloy or stainless steel is also a very likely cause of a rapid failure (e.g., carbon steel boxes on heat exchangers made of copper alloy). CO2 Corrosion (DM#P1) This damage mechanism may be observed on the deaerated water injection network, mostly in two conditions: • When the seawater is deaerated by gas stripping using produced gas containing a significant amount of CO2 (typically > 1%). Though only a moderate amount of CO2 is dissolved in the seawater, this is enough to decrease the pH by about one unit, hence making seawater more acidic and slightly more corrosive; • When injecting a mixture of seawater (supposedly with no dissolved CO2, unless as in the previous case) and of produced water, if not completely degassed with respect to the native dissolved CO2, and without enough corrosion inhibitor from the production side. As highlighted above, presence of such CO2 and its resulting acidification poses a problem essentially with high velocities, where erosion-corrosion damage may be observed. Pitting Corrosion (DM#P9) and Crevice Corrosion (DM#P10) of stainless steels These two types of localized corrosion damage are essentially an issue observed on stainless steels selected without enough alloying elements, when in contact with

234 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

aerated seawater. Both these types of corrosion damage can be very severe (failure within few months) for insufficiently alloyed stainless steels. It is particularly worth noting that the most usual AISI 304 SS, AISI 321 SS and AISI 316 SS stainless steel materials are not resistant to aerated seawater at ambient temperatures, unless subjected to cathodic protection. On the other hand, they are resistant to deaerated seawater, at least within the normal deaeration specifications for a seawater network. Several factors are detrimental to stainless steel, in terms of the damage mechanisms: 1. Stagnant conditions particularly as regards pitting: for any SS component immersed in aerated seawater, being in service is always preferable, under flowing conditions, to being out of service; 2. Addition of chlorine, as a bio- fouling inhibitor: chlorine (as chlorine, hypochlorite, etc.) represents an additional oxidizing species which shifts the corrosion potential to higher values, hence closer to the pitting potential of any stainless steel. The residual chlorine content must be confined to 0.5 – 0.7 ppm maximum, to minimize its detrimental effect; 3. Temperature: the more moderate the temperature, the lower the risk of pitting and crevices and the rate of propagation. However, each stainless steel has its own temperature limits for aerated seawater. This limit is even more difficult to define for any material if the salinity and oxygen content also vary. Cavitation (DM#28) This damage mechanism is potentially only a concern for pump impellers, in the event of too low a pressure at the pump inlet, for the required flow rate, if a too low local pressure (below the water vapor pressure) occurs on the impellers. In practice this problem is rarely observed on such water injection units as long as the pumps and their inlet piping are properly designed.

4.4.2.3. Corrosion prevention solutions Overall mitigation strategy The most usual corrosion prevention strategy used on water injection (and cooling) networks is easily summarized as follows: • Aerated seawater side, use of: ○ Corrosion resistant materials (plastics, GRP, Copper-Nickel alloys, NickelAluminum Bronzes (NAB), high-PREN stainless steels, titanium CP and titanium alloys), ○ Coated carbon steel + cathodic protection, where affordable, • Water filtration and deaeration; • Deaerated section: ○ Carbon steel (possibly with an internal coating or lining), ○ Biocide treatment for MIC control, ○ Inhibitor treatment If the water contains some dissolved CO2.

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Seawater lifting This first component of the unit consists mainly of: 1. An immersed centrifugal pump comprising several successive pump bodies and impellers driven by a common axis: copper – nickel alloys, NAB or 25Cr Duplex SS are the most usual materials for these pumps. The duplex stainless steel solution is used more and more owing to the significant erosioncorrosion issues observed on pump impellers made of copper – nickel or NAB material, 2. A surrounding cylindrical casing, inside which the pump is inserted: this caisson is usually made of carbon steel, 3. An engine powering the centrifugal pumps via the rotating axis: this engine is in atmospheric conditions above seawater level. It is protected mainly by painting, as for any other aerial device, 4. A capillary used for chlorine/hypochlorite (or any equivalent chemical) injection at the caisson inlet, to prevent the gradual marine fouling inside the caisson and inside further process facilities. The main corrosion issue observed on such lifting pumps is galvanic corrosion (DM#53) of the external casing, as described above. The specific mitigation solution consists of: 1. Painting the pump body in CRA, to minimize the cathodic surface area, 2. Install anodes on the pump bodies (this is the only place where they can be installed and replaced), 3. Preferably coat the internal surface of the carbon steel caisson, to minimize the consumption of the current, hence the size of the anodes. An alternate solution could consist in manufacturing the caisson out of GRP instead of carbon steel: this solution is however rarely put forward at present time. Another issue commonly observed on both copper alloys and stainless steels occurs when chlorine injection is continued while the pump is no longer pumping. The high concentration of chlorine /hypochlorite in the enclosed volume between the pump and the caisson is very detrimental for both materials. The solution to this simply consists in regulating chlorine injection to the ON/OFF status of each lifting pump. Water cooling The most common cooling system on seawater networks consists in the cooling of a secondary freshwater cooling network. The current solution consists in using compact plate heat exchangers, made of titanium (generally CP grades). No significant corrosion is observed on such exchangers.

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Filtration The aim of this section is not to detail all the corrosion mitigation solutions used in the variety of filtration systems, from cartridge filters, sand, multimedia filters, membranes, but only to highlight several common points: • Coated carbon steel is frequently used for vessels. This solution works well... provided efficient cathodic protection is implemented (sacrificial anodes or even impressed current) and regularly maintained (anode replacement, close monitoring of the impressed current system), • The key condition and limit for cathodic protection inside filters is the ability to install enough anodes at the right position to fully cover the entire carbon steel surface. Another difficulty is also observed when a large surface area of stainless-steel internals is present, which may consume most of the delivered current. Internal cathodic protection of a carbon steel filter vessel must involve close simulation of the effect of the internals on current consumption and on flow distribution, • 25Cr Duplex SS or 6Mo type SS are currently used for vessels with a small diameter, for internals... Seawater filters involving a large porous filtering media (sand filters, multi-media filters) are well known for their ability to develop a massive biomass, hence leading to widely contaminated water at their outlet, if not back-washed regularly enough or during too short intervals. Proper application of the periodic back-wash operation of such a filter is essential to corrosion control and to the integrity of the carbon steel network installed downstream the deaeration process. Seawater deaeration Whatever the deaeration process among the three mentioned above, the usual corrosion prevention solution used on large stripping tower(s) consists of internally coated carbon steel, with sacrificial anodes for the bottom, permanently wet, part. In addition, for the three processes, an oxygen scavenger injection point must be installed above the liquid level, in the center of the tower, to complement the physical deaeration process. It is important that the tower be designed to allow enough residence time for the liquid at the bottom, to ensure the necessary reaction time for the oxygen scavenger efficiency. This residence time is currently of 2 minutes. A few specific points regarding the different types of process are also highlighted. • Vacuum stripping: specific erosion-corrosion/cavitation issues can be observed inside vacuum pumps designed with impellers made of copper alloys, if the liquid annulus is not well controlled and if the control system not well designed. It is important that operators and maintenance personnel dealing with such vacuum pumps receive proper training on these specific pumps, both regarding corrosion and the ability of the pumps to maintain

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the required vacuum. The use of impellers made of high-PREN 3 steel instead of copper alloys can help solving corrosion issues, if not the effectiveness of the pump to supply the necessary vacuum, • Minox™ units: the principle of these units is to recycle the nitrogen gas used for stripping, and remove the oxygen retrieved from the water by combustion with methanol. Special competencies are required, and special attention must be given to this combustion system: ○ Insufficient deaeration if too limited a supply of methanol, ○ Excess of methanol in the water if the combustion is incomplete. The excess of methanol is a very efficient feedstock for microbial activity, which may induce serious biomass accumulation inside the 2nd deaeration tower, and as a result, contaminated water at the unit outlet, • Fuel Gas Stripping units: as outlined earlier, if the fuel gas used contains significant amounts of CO2, these units tend to acidify the seawater, making it more corrosive. Consequently, corrosion inhibition treatment usually needs to be implemented. Aerated Seawater Piping The basic solution consists of Glass Reinforced Plastics (GRP), i.e., composite materials. Such a solution has proved to show long term positive performance over more than 20-30 years, provided a few precautions are taken: • The outer liner must be designed for UV (ultraviolet) resistance; • The layout and the piping supports must be specially designed for such materials, and not as per practices used in carbon steel piping; • Qualified personnel only must be in charge of installation and assembly. The use of copper-nickel piping is also a practice implemented for seawater piping. However, it must be acknowledged that, although basically adequate for flowing seawater, such piping does not necessarily protect against all corrosion risks: • Erosion-corrosion, if flow velocities are too high; • Possible sulfide contamination during extended shutdowns, leading then to serious localized corrosion. Sulfate Removal Units • Such units may be installed either downstream or upstream of the deaeration process, i.e., subjected either to raw or deaerated seawater. Installing them upstream minimizes the deaeration process, as only the filtrated water is deaerated; • These membrane units are made mostly of plastics for membranes, GRPs for the piping and duplex stainless steel when mechanical properties are required. It is worth noting that such units must be regularly subjected to a biocide treatment on the inlet side, to control biofouling. DNBPA based biocides certified by

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membrane suppliers are currently used, the DNBPA biocides have shown to be specifically corrosive towards capillary tubes made of CRAs: suitable GRP / polymeric materials or titanium should be selected. Otherwise, if biofouling is controlled by other types of biocides, stainless steels can be used). HP injection pumps 25Cr Duplex SS material is currently used for HP water injection pumps, even though it may look slightly over-designed for normally deaerated water. In practice, the main advantage that warrants this choice is the high-yield strength offered by this material, which is important for HP pumps. Biocide Treatment The biocide treatment discussed here aims to prevent MIC along the water injection network, provided it is designed of carbon steel. It may also be aimed at minimizing the risks of reservoir souring due to microbial activity inside the reservoir. It differs from the special bacterial treatment of filtration membranes (micro- or nano-filtration) which is solely aimed at controlling biofouling of these membranes. Because of the usual limited compatibility of most biocides with oxygen scavengers, and because of the usual foaming tendency of biocides, this treatment is currently applied only at the outlet of the stripping tower, or downstream of an SRU Unit, if such a unit is installed downstream the deaeration tower. The current biocide treatment for water injection networks consists of periodic shock treatments (the concentration of biocide depends on biocide type and operator’s practices) during short periods of time (3 to 6 hours). Seawater injection pipelines and injection tubing Once the injected water is treated against all corrosiveness issues (oxygen removal, periodic biocide treatment and inhibition if some CO2 is also present), a carbon steel solution is considered appropriate for the HP injection network. However, more conservative approaches are sometimes selected by some operators: • Application of a thin internal epoxy coating (liquid epoxy or Fusion Bonded Epoxy) on pipe lengths only. This solution is generally aimed at minimizing well clogging from pre-existing rust and corrosion products formed during service life. As long as girth welds are not coated (i.e., 3 to 5% of the surface not being coated), the solution does not claim to prevent corrosion failure, but only to minimize the amount of corrosion products formed; • Application of a thin internal epoxy coating (liquid epoxy or Fusion Bonded Epoxy) on both pipe lengths and girth welds (possibly also on injection tubing’s). This solution is applied by some operators, mostly for large onshore pipelines (because of the time required to apply a surface preparation and

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coating application after welding of each girth weld). In addition to similar advantages as above, this complete internal coating aims to provide extra safety with respect to potential insufficient mitigation solutions during part of service life (i.e., with a corrosion risk limited to potential coating defects). However, application of this complete thin coating does not prevent application of the preventive solutions mentioned above, provided a full “defect free” coating is not envisaged; • Application of a thick internal lining along the entire length of the pipelines (polyethylene in general), including over girth welds and other pipeline junctions. A similar solution also exists for injection tubing, with carbon steel tubing internally lined with a GRP internal liner. This solution is considered to offer 100% coverage, i.e., not requiring any additional prevention solution, if it covers the entire surface in contact with the seawater. It is used in the following typical conditions: ○ Only partial confidence in the continuous application of mitigation solutions indicated above over the entire planned service life; ○ Repair solutions of already corroded pipelines, ○ Injection of raw seawater, or non-inhibited produced waters. As long as either raw seawater or a mixture of corrosive non-inhibited waters is injected, a corrosion resistant solution must of course be applied over the entire exposed surfaces: • CRAs on surface piping, manifolds, jumpers, well equipment...; • Internally lined pipelines, or flexible lines; • Internally lined injection tubing. In short, the most common corrosion prevention approach used on water injection networks consists in: • Using corrosion resistant solutions on the aerated side, with GRP as an essential solution for piping; • Removing the dissolved oxygen from seawater, down to a concentration of 10 – 30 ppb; • Inhibiting any water containing residual amounts of CO2, either from produced water or from seawater stripping columns; • Insuring periodic biocide treatments to prevent MIC and minimizing the risk of reservoir souring. Once such approach is adopted, it is of key importance to pay special attention to the limited microbial contamination of the injected waters along their processing in injection facilities: the lower the contamination on the water processing, the lower the risks of MIC and reservoir souring downstream. Continuous chlorination, rigorous filters backwash, and periodic decontamination treatment of the produced water, if injected, are of particular importance with respect to this issue. There is also a serious risk of galvanic corrosion on the casing of seawater lifting pumps if no adequate preventive solutions are applied.

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4.4.2.4. References 1

K.L. Heidersbach, A.C. van Roodselaar, “Understanding, preventing and identification of microbial induced erosion - corrosion (channeling) in water injection pipeline”, Corrosion – 2012, paper C2012-0001221, NACE International Houston TX.

Figure 79.  –  Seawater Injection and Cooling Unit, U02 – Corrosion Location Diagram.

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Figure 80.  –  Seawater Injection and Cooling Unit, U02 – Material Selection Diagram.

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4.4.3.

Semi-Open Type Cooling Water Circuits – U03a

Water is used as a cooling fluid in process coolers, machinery coolers, quench columns, etc. It comes from a wide variety of sources (seas and oceans, shallow and deep wells, rivers or ergs, lakes, ponds, or pools, etc.). Cooling water composition is highly variable and depends on the source. For any given source, it may depend on seasonal conditions, but can also vary with pollution. Cooling water treatment and the type of cooling system essentially depend on the water quality of the source, the characteristics needed to provide the requisite service, and the specified quality of the discharge. Cooling water quality The cooling water quality depends on several criteria: • • • •

Inlet and outlet temperatures; Scaling potential; Microbiology; Corrosiveness.

The different systems Cooling water systems are differentiated as follows: • Once-through systems. Any cooling water in the circuit comes from a source (sea, river, lake or well water). The water is taken upstream, pumped through the circuit, and discharged at a low point in the source or in a downstream weir, at temperatures 4 to 10 °C higher than the inlet temperature. The discharged water temperature must remain within the limits fixed by the environmental rules in effect. These systems use large amounts of water. The external treatments applied involve one or more stages of filtration, treatment against the micro and macro-organisms, and sometimes anti-scaling treatment. • Semi-open circuits. Water is constantly recycled between the process system to be cooled and a cooling system, (usually cooling towers) in which the water is cooled through partial evaporation. Two types of towers exist: ○ Open-cooling towers, in which the water that cools the process is the same as that in contact with the air tower; ○ Closed circuit cooling towers, characterized by the separation of the primary circuit (which cools the process), and the secondary circuit, in contact with the air of the tower. Water evaporation concentrates the mineral salts, suspended particles and organic substances. The concentration is controlled by a permanent purge, which therefore requires permanent make up. Water discharged to the purge must also comply with regulations in effect.

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Semi-open circuit cooling systems can save a large amount of water compared to that consumed in a once-through system. Releases are reduced and less is spent on chemical treatments. However, they have several disadvantages compared to once-through systems: ○ Evaporative cooling increases the concentration of dissolved solids in water, increasing propensity to corrosion and to the formation of deposits, ○ Relatively high temperatures can significantly increase the water corrosiveness, ○ Longer retention times and warmer water increase the propensity to bacterial growth, ○ Atmospheric gases such as sulfur dioxide, ammonia or hydrogen sulfide can be absorbed from the air, leading to increased corrosion rates, ○ Micro-organisms, nutrients, and potential fouling can also be absorbed by the water in the tower, • Closed-circuit systems. The water circulates in closed loop, it is heated by the process and is cooled, without contact with the air in an exchanger. Make-up water is only a small fraction of the total volume in circulation. Closed-type cooling systems are used particularly when it is important to minimize water consumption. As example, hot water from users can be cooled in a closed-circuit cooling tower or in an exchanger – it is not discharged outside the circuit. The following problems are inherent to cooling water systems: Scaling Scaling is essentially due to the formation of calcium carbonate. Depending on the water composition, it may contain mud and clays, algae residues, calcium sulfate or brucite Mg(OH)2. Scale formed from seawater may contain strontium sulfate. In general calcium carbonate precipitates first, usually in the form of calcite or aragonite, because its solubility is lower than that of other salts likely to precipitate. Whatever the substrate, the first nuclei formed can serve as a growth locus for any excess CaCO3 that may form. After the entire surface is covered, the calcium carbonate deposit serves as a support for new crystals – it can serve either as a growth locus or continue to trap CaCO3 seeds by electrostatic effect. The layer continues to grow as long as Ca and bicarbonate anions are present in the water. Scaling should be distinguished from sedimentation. Scaling may be controlled using several physical or chemical methods, such as: • Water softening: use of ion exchange resins that replace Ca2+ and Mg2+ ions by Na+ ions and are regenerated by brine; • Decarbonation on resins: use of weak cationic ion exchange resins that retain the bicarbonate bounded Ca2+ and Mg2+ cations;

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• Acidification / decarbonation: elimination of carbon dioxide TAC (bicarbonate and carbonate anions) by acidification; • Precipitation of carbonates by electromagnetic, catalytic or turbulence effects; • Use of scale inhibitors, consisting primarily of chelants, polyphosphatebased products, phosphonates, of acrylic, methacrylic, and maleic polymers, acrylic, or maleic copolymers or terpolymers. Development of a biofilm and of macro-organisms  The use of biocides limits the development of micro and macro-organisms. Biocides may be oxidizing or non-oxidizing. They are usually injected continuously (especially oxidizing biocides) but “shock” doses can also be injected. Many biocide families can be used; as a reminder, some act by oxidation, such as chlorine-based biocides. Bio dispersants and bio detergents help the biocides penetrate the biofilm. Physical and physicochemical treatments are also used [1]. Development of Legionella Legionella bacteria (Legionella Pneumophila) grow in fresh water between 25 and 45 °C. Cooling systems based on cooling towers are sensitive to these bacteria. The factors favoring the development of Legionella are temperature (development range 25–45 °C), the presence of a biofilm, the hydraulics of the circuit (low flow rates promote their development). Treatment with corrosion inhibitors  Several types of inhibitors can be used (mineral phosphates, zinc salts, triazoles derivatives, molybdates, fatty amines and polyamines, organo-phosphorous compounds, carboxylates and benzoates, plants-derived organic acids, etc.). Their use depends on the characteristics of the water and the materials requiring protection. Some act synergistically with scale inhibitors. Detailed information is available in the guide of recommendations for semi-open cooling circuits [1].

4.4.3.1. Description of the process The selected system described below is intended for cooling a circuit consisting of process exchangers and utilities exchangers. The cooling water comes from a seawater reverse osmosis treatment unit (see section 4.4.7). The circulating water is heated in the heat exchangers and cooled in an open-circuit cooling tower. Make-up water from the reverse osmosis unit compensates for water evaporation in the tower. The conductivity and chloride concentration can also be adjusted by making-up with demineralized water.

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4.4.3.2. Main damage mechanisms The corrosion mechanisms that can be encountered are: Chloride Stress Corrosion Cracking (DM#23) Austenitic stainless steels such as types AISI 304 SS, AISI 304L SS, AISI 316 SS, and AISI 316L SS are the most widely used for chemical circuits, drainage systems, mud extraction circuits, and concrete tank linings. They are sometimes replaced by lean duplex stainless steels (UNS S82011, S32003, S32101). Given the low chloride content usually maintained in the system (few hundreds of mg/L) and the controlled temperatures, the likelihood of stress corrosion cracking is negligible. However, where chloride contents may reach or even exceed 1 g/L chloride, e.g., when a leakage allows some more salty process water to be mixed with the cooling water, or when the water used for make-up is not within specifications, Stress Corrosion Cracking is then more likely, particularly at interstices between the plate and tubes of heat exchangers. Cavitation (DM#28) Can occur in valve bodies and gates, the pump housings, and impellers. The probability is negligible in semi-open refrigeration circuits when the pump inlet pressures are appropriate. Galvanic Corrosion (DM#53) Several forms of galvanic corrosion may be encountered. Usually, the more conductive the water, the higher the galvanic corrosion risk. • Electrochemical couple formed between two materials (carbon steel/copper alloys; carbon steel/graphite...). The higher the water conductivity and the higher the potential difference between the materials in contact, the stronger the galvanic corrosion. Remark: there is no significant galvanic corrosion between two passive stainless steels or nickel alloys, even showing different potentials, because the passive current is almost not changed over a large potential range … as long as the pitting potential of one of the alloys is not reached; • Local electrochemical couple caused by a difference in the metallurgical structure or in the local chemical composition of the materials or of the fluid. This category includes: ○ The preferential corrosion of welded joints of steels, copper, or other alloys in conductive water, ○ The selective corrosion, along the fusion line, of joints welded by an HFW (LR-ERW or EFW) electric resistance. This type of corrosion leads to the development of a narrow, deep groove, often filled with corrosion products. Few decades ago, it was encountered on carbon steel piping with a poorly controlled chemical composition and welded at high frequency by an electrical resistance (without filler metal). Current specifications for resistance welding (especially regarding control of the metallurgy,

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control of the fusion line, and of the post-welding annealing) constitute a sufficient barrier against this corrosion. Nevertheless, some manufacturing may remain uncontrolled, ○ “Ringworm Corrosion” is generally caused by a difference in the structure of the crystalline grains between two parts of the structure in the tubes of copper-alloy exchangers. The difference in the shape of the grains may appear after tube expansion. Ringworm corrosion is also encountered on steel, ○ Differential composition of the corrosive fluid on surrounding areas (pH, oxygen…) leading to galvanic current exchanges between these areas. Microbiologically Induced Corrosion (DM#P4) Microbiologically induced corrosion mainly affects ferrous materials, but cases have been encountered with other materials Potentially all ferrous materials can be affected as long as deposits and a bio film may form, mainly at the bottom of tanks, drainage circuits and mud circuits. Erosion - Corrosion/ Erosion (DM#P5) All metallic materials are potentially susceptible of erosion–corrosion. It may occur in once-through refrigeration water circuits and to a lesser extent to semi open and closed circuits. However, the probability of erosion-corrosion is low in both circuits, the one that carries solids (muds), due to the fact that mud extraction is not permanent and that the flow rate is quite low, and the intake air sucked into the packing and through louvers. Under Deposit Corrosion (DM#P6) This can potentially affect all materials; it occurs under a mineral or organic deposit, where the water circulation is not effective, especially in the drain circuits, the mud drain circuit, and the bottom of the cooling tower especially if it is lined. This corrosion may be related to the microbial corrosion mechanism discussed above (DM#P4) Oxygen Induced Corrosion (DM#P7) The cooling water circuits contain oxygen. The amount of dissolved oxygen mainly depends on the temperature, the atmospheric pressure, and the salinity. Semi-open circuits may be affected if inhibition is not effective. Pitting Corrosion (DM#P9) It can affect austenitic stainless steels, duplex stainless steels, copper alloys and aluminum alloys. Pitting corrosion is promoted by the presence of chlorides combined with dissolved oxygen. Among stainless steels, those containing no molybdenum are the most sensitive. High temperatures also enhance this type of corrosion unless it is high enough to eliminate almost all of the dissolved oxygen.

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Crevice Corrosion (DM#P10) Although it essentially concerns once-through refrigeration circuits, it can nevertheless occur in other cooling systems. It concerns all types of metallic materials, (steels, austenitic stainless steels, duplex stainless steels, copper alloys, etc.). In hard waters, crevice corrosion can initiate under any type of seal (PTFE, elastomers, etc.). As a reminder, other potential damage mechanisms: Physical and chemical aging of polymers The term “physical aging” applies to several damage mechanisms, as described in document (1). The main types of damage encountered in polymers are lamination, swelling, stress-induced damage, migration of adjuvants, hydrolysis, oxidation, leaching and diffusion. Formation of white rust on galvanized structures White Rust can develop on structures that have just been galvanized and be subjected to a damp atmosphere or to condensation. Concrete corrosion Structures and parts made of concrete may be affected by one or more types of concrete damage: corrosion of the reinforcement, direct chemical attack of the grouting or indirect chemical attack of the cover caused by the action of living organisms (some bacteria cause oxidation of sulfides which produces H2SO4), and leaching. Additional information on the concrete corrosion can be found in document (1).

4.4.3.3. Corrosion prevention solutions Materials used Hot-dipped galvanized steel When the conditions for the formation of a protective layer are met (pH, TAC, temperature, oxygen concentration, flow velocity), the carbon steel is suitably protected against corrosion. Galvanizing is not a sufficient preventive solution in conditions of permanent exposure to cooling water, especially for welded joints on which galvanizing is not restored. Structural elements made of galvanized steel are widely used around cooling towers and related equipment, because they are rather exposed to moisture and damp atmosphere than to a permanent water exposure. Austenitic stainless steels Austenitic stainless steels are sometimes used on the water side, but also because they are used against a corrosive fluid on the process side. They are sensitive to localized corrosion, and very sensitive to ferritic pollution. Their use is limited by the chloride concentration in the water and by the temperature, particularly when some dissolved oxygen is present. Austenitic stainless steels containing

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molybdenum are used as a minimum. Stainless steels such as AISI 316 SS and AISI 316L SS are acceptable in some cases. AISI 304L SS and AISI 316L SS enter in the manufacture of pumps used in semi-open refrigeration circuits. Duplex stainless steels Duplex stainless steels are widely used in seawater cooling systems. In systems where water salinity is low, the lean duplex stainless steels can be used, as they have a pitting resistance similar to those of austenitic stainless steels, but their mechanical resistance is much higher at room temperature. Copper alloys They are widely used. The most common alloys are: • Brass: many types of brass are used. Cu-Zn-Sn (UNS C40000 series), Admiralty brass (C44300, C44400) in particular, and marine brass (C46400), are used in freshwater and seawater service. Aluminum brass (UNS C68700) can be used in open circuits with well water or river water, in seawater circuits, provided that the water velocity does not exceed 1.8 m/s. This alloy is not sensitive to dezincification if the grain size and the arsenic or antimony contents are appropriate; • Cupro-nickel alloys: 90Cu-10Ni (UNS C70600) and 70Cu-30Ni (UNS C71500) alloys are the most widely used. In addition to good corrosion resistance, they offer better resistance to erosion-corrosion than brasses; • Cupro-aluminum alloys: they are used for the manufacture of tube sheets or certain types of piping and piping elements such as valves. Their use is widespread in seawater service (especially in the naval construction). They are really of interest in water service with moderate or low salt loads. Cast alloys may be porous and subjected to selective corrosion (dealumination); • When using such copper alloy steel in heat exchangers, it is of course essential verifying that they are also corrosion resistant on the process or utility side. From this point of view, it is worth reminding that copper alloys are quire rarely used on the oil and gas side and should definitely be excluded at least when some H2S is present. Composite materials: epoxy resins with glass or carbon fibers. Plastics PVC, polyethylene, polypropylene, vinyl, and epoxy coatings can be applied inside metallic piping; elastomers can be used for joints. Polyethylene is susceptible to stress induced damages – it is subject to oxidation. It tends to crack in chlorinated water, especially in the presence of chlorine dioxide. Polypropylene can also oxidize. PVC (Poly Vinyl Chloride) can undergo sequential elimination of hydrochloric acid, which causes it to become fragile. This occurs at temperatures above 80 °C and in the presence of strong bases. CPVC (Chlorinated Poly Vinyl Chloride is less sensitive. PVC and CPVC are rigid and can undergo mechanical failure.

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Epoxy resins have a hydrophilic character, which makes them susceptible to water absorption. In properly cross-linked resins, hydrolysis concerns only the epoxy groups located at the end of the chain. Corrosion prevention The different forms of corrosion in the semi-open cooling water circuits can be prevented by implementing the following solutions: Prevention of oxygen induced corrosion • Apply an adequate Inhibitor treatment and pH control or use of CRAs; • As the tower water is in contact with the atmosphere, degassing or oxygen scavenging treatment would have no effect. Prevention of erosion and corrosion-erosion • Limiting the circulation rate depending on the metal grade of the circuits: material specific velocity limits, within the 2 to 4 m/s range do exist for such units and for different materials; • The use of CRAs (austenitic stainless steels, duplex stainless steels, coppernickel alloys containing from 1.5 to 2% iron or Cu-Ni-Fe-Mn such as C71640) improves resistance to erosion and to erosion-corrosion, thereby allowing for higher circulation rates. Prevention of cavitation • Pump and valve designs; • Intake pressure control; • Use of austenitic stainless steels for manufacturing impellers and pump bodies. Prevention of pitting corrosion and stress corrosion of stainless steels • Avoid the use austenitic stainless steels from the 300 series when water temperatures are above 50 °C (60 °C for duplex stainless steels); • Use alloys of suitable PREN, depending on the chloride content in the water and the temperature; • Apply a regular monitoring of the water composition to prevent accidental durable increases of the chloride content and other critical components. Prevention of crevice corrosion • Proper design of joint systems minimizing interstices; • Prevention of liquid accumulation between the seal and metal; • Same monitoring concerns as above.

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Prevention of under deposit corrosion • Avoid dead zones in circuits and equipment; • Design the network under flow rates that are high enough to prevent sediment deposition (> 1.5 to 2 m/s); • Avoid temperatures that exceed the deposition thresholds of Ca, Mg, and Sr compounds in the water; • Same monitoring concerns as above regarding the water composition, with a particular attention to scale forming components. Prevention of Microbiologically Induced Corrosion • Avoid stagnant water; • Select and assure availability of a qualified biocide, in order to apply regular biocide treatment to the water; • clean the basins at regular intervals to remove all deposits, particularly the biofilm. Prevention of galvanic corrosion • Electrochemical couples: avoid direct contact between conductive materials whose corrosion potential difference in the medium is higher than 150 mV; • Selective corrosion of heat affected areas: Material dependent, e.g., heat treatment of welds, selection of suitable welding processes according to common codes and practices for such facilities; • Grooving corrosion HFW (ERW, EFW): if piping welded using the HFW process (ISO 3183) is used, make sure that a metallographic inspection of the welded joint is conducted to ascertain the absence of martensite, to ensure the absence of inclusions at the weld line, to ensure that the welded zone has undergone minimum heat treatment (this may be a complementary requirement if the material grade is lower than API 5L X42 (L290)); • Ringworm Corrosion: make sure that the exchanger’s tube expansion areas are not excessively hardened due to grain deformation. Prevention of physical and chemical aging of polymers • Only use polymers after having checked their stability in the medium (stability with respect to the injections of acids and chemicals); • avoid their use above 60 °C. Prevention of white rust formation • Avoid exposing recently galvanized structures to wet atmospheres (in order to allow the formation of protective zinc carbonates); • store the galvanized structural elements in such a way that any water condensation is avoided. Prevention of concrete corrosion • Have concrete basins coated with epoxy.

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Preventive solutions for standard steel Preventive solutions consist in applying physico-chemical treatments to be compliant with integrity operating windows given below and controlling water quality. Integrity operating windows (IOW) In addition to the mandatory analyses imposed by Local Regulations (which vary from one country to another), the following parameters should be monitored to limit corrosion in semi-open cooling water circuits: Monitoring requirements for make-up water • Suspended solids; • pH: continuous measurement, range according to standards (in General 7.0–9.0, at 20 °C); • TAC (total alkalinity or M alkalinity (methyl orange)): value according to standards, generally 1 g/L). Austenitic stainless steels of the 300 series are particularly at risk, for chloride contents within 1 g/L at a water temperature of 150 °C and even lower contents for higher temperature. Indeed, it is worth reminding that the tube-plate interstice is the hottest local area, i.e., the most sensitive. Monitoring of operating parameters, Integrity Operating Windows (IOW) The most important parameters are related to the quality of the circulating water and the quality of the make-up water. In the case of domestic hot water, or if there is a risk of Legionella, some of the limits are imposed by local legal regulations. The limit values are given in standards, professional standards, and legislative texts, which should be referred to.

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Water in circulation The parameters to be monitored are: • • • • • • • • • •

The pH at 25 °C, which should be maintained in the 8.8 to 9.5 range; The conductivity at 25 °C, that indicates the salt content; The residual dissolved oxygen content; The amount of excess of oxygen scavenger; The turbidity; The soluble iron and copper (if any copper alloy made vessel or piping); The total dissolved solids (TDS); The ammonia content (if copper alloys in circuits); The free alkalinity; The microbial activity, (according to regulations in force, from an integrity standpoint, sulfate reducing bacteria and ferruginous bacteria are important).

Make-up water The parameters to be monitored are pH at 25 °C, which should be maintained in the 7.0–9.0 range; hardness; soluble iron, soluble copper, free alkalinity, silica, and microbial activity (according to current regulations). Other parameters must be monitored to counter the particular risk of Legionella and the potential exposure of the public. The limits are set by the applicable local regulations. In addition to chemical analyses, corrosion monitoring can be carried out by direct measurements (ultrasonic methods (wall thickness), corrosion coupons (corrosion rate)), or indirect measurements (linear polarization resistance). Monitoring the oxygen concentration using a Zero Resistance Ammeter or dissolved oxygen measurement probes can be used to assess the possibility of Oxygeninduced corrosion The bacterial count, the iron and copper analyses help assess the probability of corrosion in the circuit. Deconcentration bleeds Deconcentration bleeds are necessary when the value of parameters such as conductivity or salt concentration is too high.

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4.4.5.4. References 1

ISO/TR 10217:1989, Solar energy – Water heating systems – Guide to material selection with regards to internal corrosion.

2

A non-chemical approach to oxygen corrosion control in closed loop systems, Edward S. Beardwood, Paper No. 00649, NACE, Corrosion 2000.

Figure 85. – Hot Water Production and Distribution Unit, U04 – Corrosion Location Diagram.

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Figure 86. – Hot Water Production and Distribution Unit, U04 – Material Selection Diagram.

4.4.6.

Steam Generators, Steam, and Condensate Circuits - U05

4.4.6.1. Description of the process The steam production, the steam distribution and condensate circuits are varied. Their design depends on the installation.

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It is customary to classify steam and condensate systems according to their service pressure and temperature, e.g., high, medium, and low pressure. However, this classification is variable from one operator to another and is disconnected from regulatory rules. Steam production, steam distribution and condensate circuits generally include: • The make-up water and condensate return lines to the water / condensate buffer tanks; • The condensate lines to the deaerator and the deaerator itself; • The boiler feedwater system from the deaerator to the main boiler and to any recovery boiler; • The steam lines from the main boiler and the recovery boilers to the turbines or/and the flash stations, the flashed steam up to the consumers; • Consumer condensate circuits to the condensate tank or to the contaminated condensates retreatment station; • Boilers. Apart from the industrial packages appearing on supplier catalogues, boilers are complex, and the potential damage needs to be identified based on the specific design and service conditions; • Recovery boilers are installed in some units where the process produces heat that can be advantageously recovered (SRU units for example). The steam production bundles installed in some furnaces are treated as recovery boilers; • The turbines and their condensation circuits. Condensate and demineralized make-up water are sent to the deaerator (thermal degasser) where they are cleared of a large part of the dissolved gases (the amount of waste gas is a function of pressure and temperature). Additional chemical treatments (oxygen scavengers, anticorrosion treatment, pH stabilization) are carried out in degasser or degassed water. The degassed water is sucked by the boiler’s feedwater pumps, this feedwater is sent to the upper drum, through a set of heaters and economizers (depending on the type of boiler and the desired steam quality). Some of this water can be disposed of to recovery boilers. From the steam drum, the water descends by gravity to the bottom of the boiler where it is collected in a manifold and is then vaporized in vaporizing tubes (boiler tube bank and screen tubes) connected to the steam drum. In the steam drum, water droplets are removed from the wet steam by a separation system consisting of cyclones or droplet separators. The saturated steam can then be superheated (usually a primary then a secondary superheater). The steam is de-superheated by injection of water through an attemperator located between the primary superheater and the secondary superheater. The superheated steam is distributed through a steam network to the turbines and to the intermediate flash stations to be de-superheated to medium pressure (MP). There, the MP steam can be again flashed to low-pressure steam.

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Waste heat boilers installed in E & P usually produce medium-pressure or lowpressure steam from energy sources that are process flows or flue gas. Sometimes they are not subjected at all to the action of flames. When there is a superheated steam system (usually high pressure), it feeds turbines (liquefied natural gas, energy production). The medium-pressure superheated steam system feeds process heater networks, and in some cases medium-pressure turbines (pump drive). The low-pressure steam system supplies heat exchangers. At the inlet of the equipment, the steam is generally slightly superheated and then it condenses on the exchanger tubes. Steam condensate networks are sometimes split into potentially polluted condensate networks and uncontaminated condensate networks. • Condensates that are polluted or potentially polluted by process fluids are reprocessed in a de-oiling and degassing station before being recycled; • Uncontaminated condensates are recycled directly to the buffer tank. It is important to keep this configuration in the subsequent modifications of condensates system.

4.4.6.2. Main damage mechanisms The damage mechanisms mentioned here apply to boilers fed with water of quality complying with criteria found in standards such as EN 12952 and to boilers heated with natural gas or with fuel oils whose sulfur content is limited to 20 ppm weight (environmental restrictions). Boilers operating with fuel oils containing more than 1.5% weight sulfur, those burning household waste or miscellaneous industrial residues and those operating above 10.0 MPa (g), are not covered. Creep/Stress Rupture (DM#3) This concerns all parts of boilers or steam circuits operating at temperatures above the lower threshold for the initiation of creep. Boiler superheater tubes are potentially the most prone to this type of damage, as are welded areas of the superheated steam collectors subjected to stress (base welds). Oxidation (DM#11) External oxidation of the boiler tubes on the flue gas side, depends on the skin temperature of the tubes and their metal grades. Steam Side Burning is an internal oxidation (on the steam side) due to a chemical reaction between the steam and the tube metal. It can be caused by too large an intake of heat due to an excessively slow circulation. In such conditions, a

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superheated steam film develops in the tubes of the superheaters. When the internal skin temperature reaches 400 °C in the vaporization tubes and 540 °C in the superheaters, the oxidation rate increases rapidly. Areas that are potentially affected are steam superheaters and vaporization tubes located on the ceiling. Internal oxidation can lead to overheating. Some alloyed and low-alloy steels (P91 (9Cr), 13Cr, 2.25 Cr-1Mo) are prone to high-temperature exfoliation. Graphitization (DM#15) Graphitization of carbon steel can occur above ~425 °C: limiting the use of carbon steel to 400 °C eliminates the problem. Caustic Cracking (DM#18) This is a form of stress corrosion cracking occurring in an alkaline environment. The damage is eliminated if the treatment of the feedwater is correct and if there is no priming that can lead to the presence of sodium in the superheaters. Water tubes, superheater tubes, heater tubes may be affected. Severe cases have been observed on the tubular plates of the steam drums (beneath expanded tubes). Caustic Corrosion (DM#19) Caustic corrosion is usually limited to water tubes located in areas subjected to significant heat flux, in horizontal or inclined tubes, under lime or hematite deposits, in thermal transfer zones or in areas where the hydraulic/heat flux may become disrupted. Cavitation (DM#28) Can occur in feedwater pumps and in high pressure condensate drain valves. Short Term Overheating – Stress Rupture, including Steam Blanketing (DM#30) Short term overheating can occur in superheater tubes due to local overheating of vaporization tubes, water tubes lapped by flames and tubes where fluid circulation is disrupted (due to leakage on an adjacent tube for example and reduction of flow). Steam Blanketing can occur in evaporator tubes if the equilibrium of the heat flux is disturbed. Under the effect of a nucleated boiling loss, tube rupture can occur quickly due local overheating. Flue Gas (acid gas) Dew Point Corrosion (DM#38) Essentially related to the flue gas composition, the respective partial pressures of SOx, NOx, HCl, HBr, CO2 and water play an important role in the probability

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of condensation and deposition of potentially strongly acidic and corrosive solutions. The quantity deposited also depends on the geometry of the channels and flue ducts. The areas that are potentially affected by this type of corrosion are all cold zones with a temperature below the condensation point on the corresponding vapor-liquid equilibrium (VLE) curve (generally in the 130–180 °C range, depending on the amount of acidic impurities present). Condensed liquids can be highly concentrated in acids and when the temperature drops below the dewpoint of the water- acid mixture, acidic solutions are diluted and can become highly corrosive. It is worth noting that a significant corrosion can still occur above the calculated dew point of the water – acid mixture (up to 20–25 °C above), because of the hydrophilicity of oxides that are currently present on the surface. Temperature margins used to prevent the corrosion must take account of this effect. Corrosion-Fatigue (DM#43) This type of damage may take place at several locations: • In degassers, where it is often called “deaerator cracking”. This type of corrosion-fatigue is related to oxygen contamination. It was revealed in the 1970s. The damage is now well known and has been properly managed since the 1980s: it can be prevented by degasser design and construction rules. If the degasser design, construction, and repair methods have factored in this potential damage, the probability may be neglected; • In areas where cyclic stresses are significant, i.e., usually in boilers that operate discontinuously or when there are numerous production peaks, units subjected to quick start-ups and shutdowns. Screen tubes, and reheater, superheater, and economizer tubes and the outlet of water tubes are also prone to this form of damage, as well as fastening points (braces of screen tubes, through-hole passages, etc.); • When water treatment is insufficient and there are thick deposits of hematite or other salts; • Turbine blades are sometimes affected by corrosion-fatigue. Galvanic Corrosion (DM#53) Galvanic corrosion is caused by the contact of dissimilar materials. The most common cause in feedwater circuits and boilers is the contact between copper (instruments, exchanger tubes) and steel. Concentration cells can also form when deposits are present. They can develop on welds due to existing stresses in thermally affected areas. There are other causes: scratches on the metal surface, stress/strain differences, temperature differences, presence of conductive deposits. Galvanic corrosion can occur in heat exchangers if different metals are in contact.

272 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

CO2 Corrosion (DM#42) Mainly encountered in condensate systems: the presence of gases in the condensate is due to the decomposition of carbonates and bicarbonates in boiler service conditions. Normally, thermal degassing removes CO2 from the feedwater. The CO2 can be more easily found in potentially polluted condensate networks. Erosion-Corrosion/ Erosion (DM#P5) This type of damage can be encountered in: • Flash drums located downstream of the boiler, steam drains and condensate drain circuits (downstream of the bleed points). The flash generates steam and water droplets carried by the steam, which can locally erode the pipelines and equipment; • Feedwater and economizer lines. Feedwater Line Erosion: at high flow rates, water and water-steam mixtures can cause erosion–corrosion of feedwater systems. Erosion–corrosion occurs in the bends of economizer bundles. It takes on a characteristic horseshoe shape. Similar problems occur in feedwater lines, where the circulation rate is not necessarily very high. An increased number of bends in the circuit can promote water spray and result in a local flow rate increase. In some conditions of pH and oxygen content in feed water, the mechanism is the flow induced corrosion; • Desuperheaters. The injection of water into the steam can lead to localized erosion. The causes can be related to the design of the desuperheater, to its assembly, and to mechanical deterioration; • Condensate circuits. major accidents occurred due to flow-induced corrosion of a high-pressure condensate collector such as [9]; • Steam turbines (blades). Moving and stationary blades can be eroded by water droplets. Oxygen Induced Corrosion (DM#P7) Oxygen induced corrosion is not common in properly operated boilers and steam circuits. It can occur in the event of failure of the physical degassing and chemical treatment systems. It may also happen if the circuits are not purged before commissioning. In boilers, this type of corrosion can occur in the economizers and feedwater heaters, on surfaces located at the water-steam separation line of the steam drum, and in water-steam separators. In the steam circuits, it is usually observed in the high points of the circuit. The following damages are mentioned as a reminder. Hydrogen Induced Damage Hydrogen induced damage results from electrochemical corrosion where hydrogen forms (cathodic reaction). It occurs in water tubes that are sensitive to rapid

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corrosion. It should be considered only for boilers that operate at pressures over 8.0 MPa (g). This type of corrosion can be found under deposits in zones of high thermal transfer. The damage may result from corrosion at high pH (caustic corrosion) or from corrosion at low pH conditions. When atomic hydrogen forms, it can diffuse into steel and attack the cementite, or recombine into dihydrogen, which contributes to the formation of microcracks. Acid Corrosion There are several potential causes: • Too low a pH of the feedwater can lead to attacks on the metal surfaces of heaters and boiler heating tubes; • Poorly managed chemical cleaning operations (ineffective inhibitor, cleaning solutions stagnating in circuits), that can attack all elements in the circuit; • Copper deposits causing pitting in steam drums and tubes. Copper deposits form during acid-based cleaning. The amount of copper deposited on the steel does not cover the entire metal surface, thus leading to the presence of localized pitting corrosion (resembling oxygen induced corrosion). Corrosion by complexing agents Corrosion by complexing agents (chelate corrosion) occurs when complexing salts are present in excess concentrations over a significant amount of time. Corrosion looks like a steady loss of thickness concentrated in areas subjected to stress. It causes thinning of the ends of the expanded tubes, of threaded elements and of separator ends. Annealed tubes and steam drum surfaces are not normally attacked. When corrosion occurs in a boiler whose water has been treated by a chelate, the corrosion is sometimes accompanied by steam blanketing. Nitrate-Induced Stress Corrosion Nitrate-induced stress corrosion can be encountered in cold areas (70–110 °C) of boiler flue gas circuits. The damage is caused by the transformation of NOx combustion byproducts into nitrates, and consequently the presence of nitrates in the liquid phase during condensation. Water preheaters, chimneys and ducts may be affected. Certain damage mechanisms cited in literature are unlikely to occur in boilers and steam circuits used in E & P: • Fuel ash corrosion (liquid or solid). Solid fuels are generally not used; the sulfur and vanadium content of liquid fuels is limited by standards and specifications; • Dealloying, including graphitic corrosion. Lamellar graphite cast iron pumps are no longer used.

274 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

4.4.6.3. Corrosion prevention solutions Materials used Standard steel Standard carbon steel is used for the construction of low-pressure boilers, in medium-pressure and low-pressure steam circuits, as well as in condensate circuits and boiler feedwater circuits. Low-alloy steels The superheaters of high-pressure boilers used in E & P or in natural gas liquefaction are made of low-alloy 1.25Cr-0.5Mo or 2.25Cr-1Mo, as are superheated steam lines operating at more than 450 °C. Alloyed steels P91 (9Cr) and P92 (9Cr) are also used. Corrosion prevention Prevention of creep, high-temperature oxidation Selection of materials according to design conditions and maximum service expected. Prevention of caustic corrosion and caustic cracking Feedwater treatment, pH control. Prevention of erosion-corrosion and cavitation Selection of materials, start-up procedures, operating procedures. Prevention of short term overheating and steam blanketing Monitoring of operating parameters, heating regulation. Prevention of corrosion induced by CO2, oxygen, and acids Chemical treatments followed by regular chemical analyses. Monitoring of chemical cleaning operations. Prevention of corrosion by complexing agents Control of water chemistry and processing additives. Prevention of acid dewpoint corrosion Control of the sulfur concentration in fuels, maintaining flue gas temperature significantly above the acid dewpoint.

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Prevention of nitrate-induced stress corrosion Use of low-NOx burners (where NOx is less than 20 ppmv), maintaining the flue gas temperature above 90 °C to limit condensation, use of Cr-Mo steels instead of carbon steel. Prevention of fatigue under corrosion Design and manufacture of thermal degassers, boiler feedwater quality, regular chemical cleaning depending on the rate of fouling in boiler tubes, design of turbine blades. Integrity operating Windows (IOW) Integrity thresholds should be established for each operating condition. It is advisable to first refer to the manufacturers’ documentation or failing that, to normative documents such as EN 12952.

4.4.6.4. References 1

NACE SP0590, Standard Practice: Prevention, Detection, and Correction of Deaerator Cracking, NACE.

2

CEN, EN 12952: Water-tubes boilers and auxiliary installations.

3

The Nalco Guide to Boiler Failure Analysis, Nalco Chemical Company, Authored by Robert D. Port and Harvey M. Hero, McGraw-Hill, Inc, Copyright © 1991 by the McGraw-Hill Companies, ISBN 0-07-045873-1.

4

Steam Turbine Corrosion and Deposits Problems and Solutions, Otakar Jonas & Lee Machemer, Proceedings of the thirty-seventh turbomachinery symposium - 2008.

5

Latest Advances in the Understanding of Acid Dewpoint Corrosion: Corrosion and Stress Corrosion Cracking in Combustion Gas Condensates, W.M.M. Huijbretgts, R. Leferink, Anti-Corrosion Methods and Materials, Vol. 51, 3 (2004), pp 173 - 188.

6

Under deposit Corrosion Mechanisms in Boilers, A. G. Howell, Paper 06458, Corrosion Nace 2006.

7

Program on Technology Innovation: Oxide Growth and Exfoliation on Alloys Exposed to Steam, 1013666, EPRI Project Manager R.B. Dooley, EPRI, Final Report, June 2007.

8

IMS 2005-11, Water Side Scaling, Deposition and Corrosion in Steam Generators, L. Hoehenberger, TÜV Industrie Service GmbH, TÜV SÜD.

9

Hajime Ito; Takehiko Sera, Secondary pipe rupture at Mihama unit 3, The 13th international conference on nuclear engineering abstracts, 2005, p. 16; 13., International Atomic Energy Agency Collaboration; 604 p; ISBN 7-5022-3400-4.

276 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 87. – Steam Generators, Steam and Condensate Circuits, U05 – Corrosion Location Diagram (1).

4 – Corrosion Prediction

277

Figure 88. – Steam Generators, Steam and Condensate Circuits, U05 – Corrosion Location Diagram (2).

278 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 89.  –  Steam Generators, Steam and Condensate Circuits, U05 – Material Selection Diagram.

4 – Corrosion Prediction

4.4.7.

279

Pretreatment and Desalination of Seawater-U06

4.4.7.1. Process description Successive phases and stages are schematized below:

Figure 90. – Pretreatment and desalination of seawater workflow.

The pretreatment sections provide a degree of physical and chemical cleanliness compatible with the subsequent treatments. Desalination processes are divided into three groups. • Membranes: Reverse Osmosis (RO), electro dialysis (ED), and membrane distillation (MD);

280 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

• Distillation: single-effect distillation, multi-effects distillation (MED), multieffect distillation with steam compression (MED-TVC), Flash process (MSF), steam compression distillation (MED-MVC); • Hybrid processes. This document covers only reverse osmosis and multi-effects distillation processes with steam compression. Common sections, pretreatment, and reverse osmosis Pretreatment sections usually consist of filtration systems, biocidal treatments (common to seawater systems) and sometimes coagulation and anti-scale treatments (specific to the desalination section). Many possible configurations exist. The seawater intake systems are often located a few meters below sea level, (usually 1 to 2 meters) but can sometimes be deeper, down to 20 m for offshore facilities: this depends on the tidal amplitude, the suspended organic matter, mineral content, and associated turbidity. The depth is always a compromise between the cleanliness of the water (suspended particles and organic matter) and the practical feasibility. When the seawater quality varies, (especially turbidity) it is advisable to use sampling taps in wells. The water intake grids are located at the end of the piping system and the fine mesh grids are backblown or back-washed to limit fouling. Chlorination treatment involves injection of an oxidant (chlorine, HClO, or other oxidant, ...) into seawater to destroy protozoa and bacteria. Hypochlorite can be obtained by electro-chlorination. In some cases, chlorine is injected from bottles. The use of chlorine dioxide or ozonation is rapidly developing. When flocculation is used, it is carried out by injection of ferric chloride. The particles settle out in a basin or a tank. Dechlorination can be achieved by addition of sodium bisulfite or by granular activated carbon filtration (multimedia filtration). Scale inhibition involves the injection of a product that prevents the deposition of carbonates and sulfates of alkaline earth metals present in the seawater. Before entering the membranes, pretreated seawater is pressurized to 5.5 - 8.5 MPa, using a high-pressure pump, depending on the water temperature and salinity. A typical reverse osmosis section consists of: • high-pressure pumps that bring seawater to the operating pressure of the osmosis system; • an osmosis system (one or more desalination stages): each stage comprizes several units arranged in a series of parallel membranes. The pressure loss in the cells is about 0.15 to 0.20 MPa. The osmosis system is composed of different types of membranes, pressure envelopes and of a system connecting the membranes to the brine and permeate circuits. To obtain potable water, the seawater has to pass through a second osmosis system designed for seawater or brackish water. Some systems are equipped with membranes that remove boron;

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281

• an energy recovery system (turbine or heat exchanger) which recovers the accumulated energy in the concentrate and restores it to the osmosis feedwater; • sometimes booster pumps, between the first and second stage of the osmosis system (a 2nd stage is not necessary if water production is not significant); • a brine rejection system; • a membrane washing system; • a set of pipes to transfer and interconnect the systems (seawater, brine (concentrate) and permeate). Membranes made of Spiral Wound Thin Composite film are the most commonly used for seawater desalination. These are flat sheets sealed and wound in spirals. The membranes are contained in a pressure envelope. A membrane can accept a maximum permeate flow of 1.4 to 37.9 m3/day (according to manufacturers’ catalogs), so it is necessary to use several membranes in parallel (1 to 8 membranes). A module consists of series of membranes laid out in parallel. The total number of membranes and pressure envelopes required, and their layout depend on the permeate flow and applied pressure. The membranes are subject to clogging by suspended solids present in seawater. The potential types of clogging are: • • • • • •

Biological: bacteria, micro-organisms, protozoa; Particulate: sand, miscellaneous debris, clay, suspended solids; Colloidal: organic and inorganic complexes, colloidal particles, micro-algae; Organic: organic matter (humic acids, biopolymers); Mineral: alkali-earth metals, sulfates, and carbonates; Oxidants: chlorine, ozone, potassium permanganate.

Membrane cleaning operations Membranes should be cleaned regularly by: • Post-service cleaning; • Annual chemical cleaning: usually from 1 to 4 times; • Specific chemical cleaning: depending on need. These operations are described in suppliers’ operating instructions. It is advisable to take them into account when designing the installation and assessing the potential damage. Multi-effect distillation with steam compression A MED evaporator consists of a series of several cells at decreasing pressure and temperature levels, from the first to the last cell. Each cell consists of a bundle of horizontal tubes. The upper rows are sprayed by seawater from the condenser, which then circulates on the outer surface of the tubes by gravity. Steam is introduced into the tubes. As the outside of the tubes is cooled by the seawater make-up, the steam condenses as distillate in the tubes. Meanwhile, the heated

282 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

seawater partially evaporates under the effect of latent condensation heat. Owing to this evaporation, the seawater gradually concentrates from the top to the bottom of the bundle and the brine is extracted at the bottom. The steam formed by the seawater evaporation is at a lower temperature than the temperature of the heating steam. However, it can be used to heat the next cell, where the process is repeated. The pressure drop from one cell to another allows the brine and distillate to move on to the next cell, where they are flashed, thereby producing steam at a lower pressure. In the last cell, the produced steam condenses in a conventional exchanger (usually called the distillate condenser) cooled using seawater. Part of the heated seawater at the condenser outlet is used as make-up for the unit whereas the other part is discharged to the sea. Brine and distillate are collected in each cell and extracted by centrifugal pumps. The thermal efficiency (Gained Output Ratio or GOR) is improved by placing a thermo-compressor between one of the cells and the hottest cell. Using LP or MP steam, this static compressor takes part of the steam from a cell and recycles it at a higher pressure so that it can be used to reheat the first cell. Disposal of the brine The salt concentration in the brine ranges from 50 to 75 g/L and its density is much higher than that of seawater (brine from RO units is usually more concentrated than that from MED units.). To limit the plume effect and its impact on the environment, the brine removal system consists of recovery pumps (in most cases), and pipes ending with a perforated diffuser whose apertures are fitted with a check valve.

4.4.7.2. Main damage mechanisms Pretreatment and RO Hydrochloric-Acid Corrosion (DM#9) (Chemical cleaning) Acid corrosion can occur on CRAs during chemical cleaning operations. The corrosion is generally localized in areas where acid accumulates. On the FRP, concentrated acid solutions can degrade the binder, thereby decreasing the mechanical resistance. Chloride Stress Corrosion Cracking (DM#23) (Common to RO and MED-TCV processes) Chloride stress corrosion cracking can occur on austenitic stainless steels at temperatures above 60 °C (some studies mention 50 °C, which has been retained by many projects). With duplex stainless steels, the temperature threshold is usually set at 80 °C; for super duplex, the threshold is around 100–110 °C. In fact, it also depends on the metallurgical structure of the steel. The temperature thresholds corresponding to austenitic and duplex stainless steels can be achieved in energy recovery systems, and MED-TVC distillers. Osmosis systems operates generally at lower temperatures

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283

It is advisable to check the suitability of the materials offered by vendors in actual service conditions. Cavitation (DM#28) (Common to RO and MED-TCV processes) Cavitation can take place in seawater pumps, though with a low probability, and in brine pumps, also with a low probability. Cases of cavitation of aluminum bronze brine pumps have been observed on MSF-type units. Galvanic Corrosion (DM#53) (Common to RO and MED-TCV processes) Galvanic corrosion can occur in an electrolytic medium (seawater, brine) if two materials whose electrode potential difference is greater than 150 mV are electrically coupled, the anode to cathode surface ratio is also important. Graphite gaskets, molybdenum disulfide-based lubricants can lead to galvanic corrosion. The circuits with permeates or distilled water are generally not affected. If titanium alloys are in contact with steel, stainless steel or other alloys, galvanic corrosion can be a major problem in extreme conditions (temperatures greater than 75 °C with certain titanium alloys) as this can also lead to titanium hydriding, to which titanium Gr 2 is less sensitive. Microbiologically Induced Corrosion (MIC) (DM#P4) (Essentially pretreatment system) If CRA or FRP is used, the probability is low due to the low sensitivity of the materials used and to the prior chlorination or ozonation pretreatment program. Microbiologically induced corrosion is still possible on carbon steel, especially in poorly ventilated areas. As a reminder, the biofilm can develop on GRP. The potentially sensitive areas are the seawater inlet upstream of the biocide treatment system and to a lesser degree the seawater system up to the osmosis plant or distiller intake. Erosion–Corrosion / Erosion (DM#P5) (Common to RO and MED-TCV processes) The probability is very low in circuits and equipment made of CRA, also due to pre-filtration and limited flow rates in piping systems. The probability is moderate in equipment and piping made of FRP, especially upstream of the sand filters. A form of erosion–corrosion (impingement attack) is possible on the impacted tubes of the distillation bundles (made of a copper-nickel alloy or aluminum brass) of the MED-TCV units, during commissioning operations. This damage is unlikely if the tubes are made of titanium or CRA. Under Deposit Corrosion (DM#P6) (Pretreatment, RO, MED-TVC) In the pretreatment section, a biofilm can form upstream of the biocide treatment. It contributes to Under Deposit Corrosion below sludge/particles deposition. Mineral scales can develop in the section downstream of the heat recovery system and in the pressure envelope of the membranes, especially if the anti-scale

284 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

treatment is not effective and if the temperature rises above 65 °C; under deposit corrosion is limited when CRA is used. The condenser tubes of the MED-TCV distillers may also undergo under deposit corrosion in the same conditions as membrane pressure envelopes. Oxygen Induced Corrosion (DM#P7) (Essentially pretreatment systems) CRAs and GRP are not sensitive to oxygen induced corrosion provided they are used in their range of service (as regards temperature and chloride content). As most equipment and pipelines are made of CRAs or GRP, oxygen induced corrosion should not be a problem (excluding pitting and crevice corrosion mentioned below, for which the presence of oxygen is also a decisive factor). Carbon steel equipment is sensitive if the internal coating is damaged. In very salty and hot environments, it is recommended to check the compatibility of CRAs and GRP with service conditions (for the latter, the quality of adhesion is the main concern when assembling). Pitting Corrosion (DM#P9) (Pretreatment, RO, MED-TVC) Pitting corrosion can occur on stainless steels and other CRAs, whereas titanium alloys are insensitive. All CRA equipment may be sensitive to pitting corrosion in a medium containing dissolved oxygen. PREN, the CPT, the service temperature, the local salinity, and the oxygen concentration must be taken into consideration to assess the probability of pitting occurrence. Crevice Corrosion (DM#P10) (Pretreatment, RO, MED-TVC) A very small amount of oxygen (within the 50 – 500 ppb range for the most sensitive CRAs) in seawater is enough to experience crevice corrosion on most CRAs, and particularly the less alloyed such as those of the AISI 300 series. The most critical areas are joints welded without enough penetration or with lack of fusion, the interstices at metal – graphite gasket, …, metals lubricated with a MoS2 grease, metal below mollusk concretions. The probability of crevice corrosion is lower under deposits with low adhesion. Degradation of non-metallic materials (as a reminder)(Pretreatment, RO, MED-TVC) Here we include surface degradation resulting from chemical reactions, dissolution, or degradation of the resin by the process, osmotic blistering, stress corrosion of bonded joints and mechanical damage such as fiber cracking and, surface cracking. Osmotic blistering due to permeation can occur on polyethylene-coated equipment and piping. Polyethylene is somewhat permeable to water and to oxygen, thereby leading to carbon steel corrosion below. Chlorine attacks on the GRP resin must be taken into consideration, as should be stress corrosion cracking of adhesive joints and all mechanical damage due to the construction or to service conditions.

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Specific forms of corrosion in MED-TCV distillers Corrosion by Boiler Water and Condensates (DM#50) CO2 dissolved in steam condensation circuits can induce CO2 corrosion. Vibration-Induced Fatigue (DM#54) This can occur in ejectors and in steam lines, mainly during the commissioning phases.

4.4.7.3. Corrosion prevention solutions The materials are selected according to the composition of seawater and brine, the service temperature, and the pretreatment operations. In general, proposed materials for low-pressure seawater piping will be GRP with a protective inner layer. Proposed materials for high-pressure piping will be CRAs with PREN > 40 and Copper Nickel alloys or NAB. Equipment materials, especially those included in RO and MED systems are often defined by manufacturers’ standards. The proposed metal-grade options must be verified according to the actual site conditions: 22% Cr duplex SS, often shown in catalogues, are not generally suitable for the service. They should be replaced at least by 25% Cr duplex SS, whose temperature limits do not exceed 25 – 30 °C in crevice corrosion situations (aerated sea water), or other CRAs adapted to the real conditions of use. Prevention of erosion-corrosion Use of CRAs and limiting the circulation rate of seawater and brine easily resolve this potential damage. Cavitation prevention Use of CRAs, (titanium alloys or super duplex) for the construction of pumps and satisfy a minimum inlet pressure when designing pumps and regulating valves of the brine flow. Prevention of Microbiologically Induced Corrosion Selection of materials, enough circulation rate, suitable biocide treatments (including injection program) – do not forget that micro-organisms can adapt to a treatment. Prevention of pitting corrosion Selection of materials according to service conditions (seawater salinity, temperature, seawater biology, brine salinity and temperature, dissolved oxygen) per indications given earlier.

286 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Prevention of crevice corrosion Equipment and piping design: use of materials that have a satisfactory CCT, apply correct scale inhibition treatment, maintain temperatures below the depositional thresholds of carbonates and alkali metal sulfates (depending on the anti-scale treatment). This damage mechanism is the main cause of failure in pipes and stainless-steel equipment in aerated seawater, and as such dictates the choice of materials to be used, per indications given earlier. Prevention of galvanic corrosion Equipment and piping design: avoid coupling materials whose potential difference is greater than 150 mV in conductive environments (consider the chemical cleaning of the facilities, and the fact that both osmosis plants and distillers can produce low-resistivity water over several days per year). Reminder: no galvanic corrosion between different passive stainless steels. Prevention of oxygen induced corrosion If carbon steel is not used, oxygen induced corrosion should not be a problem, assuming a right choice of CRAs (as pitting and crevice corrosion are driven by the amount of dissolved oxygen). However, implement air venting in the high points of seawater circuits, avoid air pockets during the facility commissioning operations. Prevention of acid corrosion during descaling Consider the procedure and the products recommended for chemical cleaning in the design phase. In general, chemical cleaning using weak acid solutions (citric, sulfamic acid) or complexing solutions (EDTA) should be preferred. It is not advisable to use hydrochloric acid (even inhibited) solutions. Standard steel: which preventive solutions? Carbon steel is usually not used except in temporary circuits dedicated to chemical cleaning (try to avoid ferritic pollution in this case). It can also be used along with a thick coating of HDPE in seawater and permeate pipelines. Characteristics of water entering the osmosis plant or the distiller: water entering the osmosis plant, or the distiller is treated seawater. The control parameters essentially depend on the type of membrane (osmosis process). The parameters and their thresholds are provided by the membrane supplier or licensor. The constraints are fewer in MED, MED-TVC and MED-MVC type distillers. Parameters to be monitored at the osmosis plant or distiller outlet: permeate salinity, flow rate, pressure loss, temperature.

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Integrity operating Windows IOW In terms of pressure-envelope integrity, no Integrity Operating Window (IOW) is defined. From an operational standpoint, the critical parameters and their values are provided by the licensor of the membranes or of the distiller. As an indication: • Free residual chlorine before de-chlorination: according to the licensor’s instructions and selected material; • Seawater pH: best is about 7.5 at 25 °C for optimal disinfection; • Maximum service temperature: defined according to acceptable limits of anti-scale treatment; • During chemical cleaning: monitoring of pH, flow rate, dissolved metals, and temperature of cleaning solutions.

4.4.7.4. References 1

2 3

4

5

6 7

8

9

10

Paper No 09193, Evaluation of Crevice Corrosion Resistance of Duplex and Super Duplex Stainless Steels for Sea Water Pumps, Hiroshi Yakuwa, Matsuho Miyasaka, Kenichi Sugiyama & Katsuhiro Mitsuhashi, Corrosion 2009. Corrosion, Vol 59, N° 4, pp 291 – 294, Crevice Corrosion of Stainless Steel in Hot Salt Water, M.I. Absulsalam & T. Shinohara. Corrosion, Vol 64, No 2, pp 143 – 154, February 2008, Modeling of LongTerm Corrosion Loss and Pitting for Chromium Bearing and Stainless Steels in Seawater, R.E. Melchers and R. Jeffrey. Corrosion, Vol 48, No 7, pp 608 – 612, July 1992, Mechanism for BarnacleInduced Crevice Corrosion in Stainless Steel, M. Eashwar, G. Subramanian, P. Chandrasekaran, and K. Balakrishan. D IDAWC/MP07-185, description of different water intakes for SWRO plants, G. Cartier, P. Corsin, ICL – France, IDA World Congress-Maspalomas, Gran Canaria-Spain October 21-26, 2007. The World Largest SWRO Desalination Plant 15 months of Operational Experience, Micha Taub, ADOM. Split Partial second pass design for SWRO plants, Stefan Rybar, Roman Boda, Craig Bartels, Hydranautics, Desalination and Water Treatment, 13 (2010), 186-194. IDA/PORT2011-056, Dual Membrane Systems in Seawater Desalination: Drivers for Selection and Field Experiences, Eduard Gasia-Bruch, Marcus Busch, Verónica Garcia-Molina, Udo Kolbe, Dow Water and Process Solutions, IDA Desalination Industry Action for Good / Santa Margherita, Portofino, Italy May 16-18, 2011. PER11-230, Evolution of production and energy savings in SWRO Plant of Las Palmas III, Raul Lemes, Jose Luis Perez Talavera, Raul Falcon, Rafael Arocha, Jacinto Curbeloo, Victor Platas, Laura De Lorenzo and Domingo Zarzo; IDA World Congress - 2011. Present Developments in the Design of SWRO Plants, Mohammed Saled Al.Ansari, Journal of Purity, Utility Reaction and Environment, Vol 1, No 4, June 2012, pp 184-199.

288 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 91.  –  MED – TVC Seawater Desalting Unit, U06 – Corrosion Location Diagram.

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289

Figure 92.  –  MED – TVC Seawater Desalting Unit, U06 – Material Selection Diagram.

290 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 93.  –  RO Seawater Desalting Unit, U06– Corrosion Location Diagram.

4 – Corrosion Prediction

Figure 94.  –  RO Seawater Desalting Unit, U06– Material Selection Diagram.

291

292 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

4.4.8.

Air Distribution Systems - U07

The selection of a compressed air production system depends mainly on what the compressed air will be used for, its amount and the energy cost of its production. The quality of the compressed air is defined by ISO 8573-1 [4]. It is classified according to three types of contaminants: solid particles, moisture or liquid water, and oil. The three ISO 8573-1 [4] tables are summarized in table 9. Table 9.  –  Compressed air purity classes for particles, moisture, liquid water, and oil. A - solid particles Class

Number of solid particles per m3 0.1–0.5 μm

0

0.5–1 μm

1–5 μm

B - dewpoint or liquid water

C - total oil mg/m3

Specified and more restrictive than Class 1

1

≤ 20 000

≤ 400

≤ 10

≤–70 °C

≤ 0.01

2

≤ 400 000

≤ 6 000

≤ 100

≤–40 °C

≤ 0.1

3

Not specified

≤ 90 000

≤ 1000

≤–20 °C

≤1

4

Not specified

Not specified

≤ 10 000

≤+3 °C

≤5

5

Not specified

Not specified

≤ 100 000

≤+7 °C

N/A N/A

6

≤ 5 mg/m3

≤+10 °C

7

5–10 mg/m3

≤ 0.5 g/m3

8

N/A

0.5 in –5G/m

N/A

9

N/A

5–10 G/m3

N/A

X

> 10 mg/m3

> 10 G/m3

>5

N/A 3

A compressed air production system is defined by combining each class (solid particles (A), dewpoint or water concentration (B), oil (C)). Obviously, the corrosiveness of the compressed air will vary from one installation to another, depending on class B (liquid water content). Compressed air generated by a system whose water content class (B) is lower than or equal to 4, may be considered potentially non-corrosive in warm or temperate climates.

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Use of compressed air Compressed air can be used for different purposes on a site. • Production of “service” air: this air is used to feed specific site locations to connect construction equipment, hoses, etc. It does not necessarily need to be very pure, nor does it need to have a very low dewpoint. An air quality class of [A (3), B (4), C (4)] is usually enough to avoid condensation most of the time in temperate climates, and to limit the risk of fouling to an acceptable level; • Production of “dry” air, formerly called “instrument” air: this air must have a low dewpoint. It feeds circuits that are not protected against freezing and/or circuits that supply instrument control systems, ignition, or combustion air circuits. This type of air must be clean (limited amounts of oil and dust): classes [A (2), B (2), C (2)] are usually adequate; • Production of air used for pressurizing “clean” rooms (infirmaries, pressurized control rooms, electric and instrument cabins, computer rooms): the required air quality depends mainly on its end use, but in all cases the air must be de-oiled, and the dust removed according to regulations or specifications in effect. This type of air is usually reconstituted from air corresponding to classes [A (0), B (1), C (0)]. Air used in control rooms is rehumidified to bring it to the desired saturation level. Atmospheric air quality Atmospheric air quality depends mainly on local site conditions, this includes the position of the air intake on the site. In addition to the corrosiveness of this air (can be defined according to ISO standard 9223 [1]) several other factors are taken into consideration: • Water content, characterized by absolute humidity, relative humidity, atmospheric dewpoint, and pressure dewpoint; • The content in contaminants other than those characterized in ISO 9223 [1], for example NOx, SOx; • The oil content, which can reach thresholds of 4 to 14 mg/m3 on industrial sites; • The dust content, which depends on the site, but which can also depend on the season. Air compression and distribution units An air compression unit installed on an E & P site consists of: • An air intake: atmospheric air intake, located above the compressor intake level (usually several meters). If the air contains a lot of dust, a dust filter is installed upstream of the compressor; • A compression system coupled to a water condensation system: the choice of compressor type depends on the desired air purity. Compressors can be lubricated, non-lubricated, screw-type, etc.;

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• A water condensation system: consisting of condensers (using a counter-flow of water or air), in which the compressed air temperature is lowered and some of the water contained in the air condenses. The amount of condensation depends on the compression ratio and the temperature; • Separators and condensate purge systems: separation can be achieved either by gravity settling or using cyclone-type separators. Automatic drains are usually level controlled; • A system for de-oiling, dust removal, and disposal of toxic compounds, according to the required compressed air quality: this system can consist of a combination of a pre-filter, a secondary filter, a micron filter used to separate oil and solid particles and activated charcoal filter for absorbing oil in the steam phase, and in some cases a sterile filter to eliminate bacteria; • An air-drying system: these are composed of adsorption dryers, which output air shows a dewpoint lower than –40 °C; • A buffer tank to regulate the downstream pressure of the network.

4.4.8.1. Description of the process This section describes a generic modular air production unit consisting of: • An atmospheric air intake equipped with a pre-particle filter; • A class service air production system [A4, B4, C4] comprising a conventional compressor with 3 stages of isotherm compression. Each stage is refrigerated by a water-based, counter-current heat exchanger. This system also includes condensate separator vessel downstream of the inter-stage condensers and of the final condenser. The separators are equipped with an automatic, level-controlled purge system; • A dust filtration system and NOx, SOx absorption system; • A service air distribution system consisting of a buffer tank equipped with an automatic level-controlled purge and distribution networks to user systems. The branches connecting to pneumatic equipment are equipped with lubricating pots allowing machine lubrication; • A modular system for producing class [A1, B2, C1] dry air. It consists of two activated alumina dryers. The alumina in the dryers is alternately regenerated by air that is superheated by an electric heater; it then passes through charcoal and particle filters. The dry air is kept at the operating temperature by passing through an exchanger located on the outlet of the drying circuit; • A dry air distribution system comprising a buffer vessel and distribution networks to users. Compressed air supply to premises, requiring class [A0, B0, C0] air, is not covered here. Atmospheric air intakes (also includes vents): the air is filtered before being sucked in by the compressor. It is at ambient temperature; it is saturated with water and contains industrial contaminants. It may contain sand that is trapped in the pre-filter. This circuit may be subject to atmospheric corrosion, which must be taken into consideration.

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Multi-stage isotherm compression system: air is compressed in three steps to a final value of approximately 1.5 MPa. It heats up during compression; the hot air is cooled in the first intermediate cooler at 25–30 °C; much of the water is condensed and separated out of the air. The air then enters the second compression stage and so on. At the outlet of the last cooler, the dewpoint of the air is less than or equal to +3 °C. Oxygen induced corrosion and corrosion by acidic condensates are to be taken into consideration in this section; sensitivity to such corrosion decreases from the first compression stage to the last compression stage. Condensate circuit: condensed water can potentially be highly corrosive (owing to the presence of dissolved oxygen, CO2, NOx, SOx...). Its pH is a function of the quantity of NOx, SOx, and other contaminants in the air. In this type of circuit, pH readings can be about 3 to 4. Corrosion by acidic condensate is to be taken into consideration. Compressed air circuits at a dewpoint ≤ 3 °C: no condensation is expected in normal operation. However, this circuit may contain water during commissioning as well as in cold weather. The corrosiveness can be assessed on a case-by-case basis according to site temperatures. It is relatively low in temperate and warm regions. Dryers and drying circuit: dryers contain an appropriate adsorbent that removes residual water from the air until it reaches a dewpoint value less than or equal to –40 °C. Dryers and drying circuits are pressurized during the regeneration phase. They are therefore subjected to alternating pressure – low amplitude depression (of the order of 1.5 MPa), and alternating temperatures between the regeneration phase and the adsorption phase. These differences are generally too low to reach a critical stress threshold, but fatigue should be checked during design. Dryers are supposedly subject to conditions like those of the compressed service air circuits. Dry air circuit: dry air is filtered through a dust filter and oil filter to achieve the quality required by the class. The dewpoint is less than or equal to –40 °C; there is no water condensation as long as the metal temperature remains above –30 °C; no corrosion is expected in this circuit. Refrigeration circuits: See U03b – Closed Type Cooling Water Circuits.

4.4.8.2. Main damage mechanisms The main forms of corrosion are related to the corrosiveness of the atmosphere, on components in contact with condensed water or moisture. According to convention, atmospheric corrosion applies to circuits operating at atmospheric pressure and oxygen induced corrosion applies to pressurized circuits. Atmospheric Corrosion (DM#47) Occurs essentially in the air intake circuit (supply air, heating air, and vents). The intensity of this type of corrosion depends on the humidity of the air, the wetting, the quality, and the quantity of contaminants in the air. SOx and NOx are

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particularly critical to this atmospheric corrosion, as well as chlorides contained in suspension in the air in marine atmosphere. Oxygen Induced Corrosion (DM#P7) Can be encountered in service-air circuits if the service temperature falls below the water dewpoint. It occurs especially in liquid condensates downstream of the compressors, due to dissolved oxygen in equilibrium with pressurized air. Acid Corrosion (as a reminder) Occurs as a complement of oxygen induced corrosion in condensate and air circuits containing condensed droplets, as well as at the bottoms of separator drums, when the air is significantly contaminated (CO2, SOx, NOx). The pH of the condensates is around 3 to 4, thereby causing a high corrosiveness.

4.4.8.3. Corrosion prevention solutions Materials used High pressure losses and/or excessive downtime are often due to (even low) internal corrosion of the networks where some water accumulation is experienced. Only plastics, aluminum, stainless steel, and copper can ensure a good surface condition. As long as the class requirements for solid particle content can be met, standard steel can be used in air compression systems. However, its use is de facto limited when the air class is more severe than [Ax, B4, Cx], given the risk of entrainment of solid particles that can originate from rust. Hot-dip galvanized steel can also be used. However, it deteriorates at joints, and it should not be welded in order to avoid the formation of potential corrosion cells (if water is present). Painted steel can also be used, but the joints can cause problems. For dry air systems, it is often best to use stainless steels and great care must be taken when making the joints. If allowed by specifications, aluminum, copper or brass and sufficiently resistant ductile plastic materials (nylon, composite materials) can be used. The use of the PVC is not recommended. At the end, even though this section only deals with quite rare internal corrosion problems, most failures of air circuits are due to external corrosion, particularly on offshore facilities: air piping are indeed generally of a low diameter and moderate pressure, hence quite thin, i.e., sooner leaking than most process piping. As utilities not posing any safety issue in case of a leak, they also tend being considered as less critical than process piping, so not on the top priority list for painting maintenance… until leakages start taking place on a regular basis.

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Corrosion prevention Prevention of atmospheric corrosion Use carbon steel coated with paint resistant to atmospheric corrosion or with surfaces that have been hot-dip -galvanized. Corrosion prevention of acid and/or oxygen induced corrosion (by acidic and/or aerated condensates) The basic solution is to use non-sensitive materials (plastics, composites, stainless steels). Carbon steel with enough corrosion allowance can also be used, but it will need to be replaced. As for plastic materials, they should be checked to make sure they are chemically compatible with the condensate – pH-resistant, oil-resistant). Integrity Operating Windows (IOW) • Monitoring of hygrometric degree, relative humidity, air pollutants (NOx, SOx, CO2, aerosols...); • Dewpoint control of compressed air; • Condensate pH control; • Control of the concentration of oil and particles of dry air (possibly). In order to fulfill the required hygrometry/ dew point and oil content it is essential that filters are regularly cleaned, and active charcoal filters are regenerated in due time.

4.4.8.4. References 1

ISO 9223, Corrosion of metals and alloys – Corrosivity of atmospheres – Classification, determination and estimation.

2

ISO 9224, Corrosion of metals and alloys – Corrosivity of atmospheres – Guiding values for the corrosivity categories.

3

ISO 9225, Corrosion of metals and alloys – Corrosivity of atmospheres – Measurement of environmental parameters affecting corrosivity of atmospheres.

4

ISO 8573-1, Compressed Air – Part 1: Contaminants and purity classes.

298 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 95.  –  Air Compression and Distribution Unit, U07 – Corrosion Location Diagram.

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Figure 96.  –  Air Compression and Distribution Unit, U07 – Material Selection Diagram.

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4.4.9.

HP/LP Flare Network Unit - U08

4.4.9.1. Description of the process The scope of this description is limited to the classic flares used in E & P applications. Flare systems are designed to evacuate and burn flammable and/or toxic gaseous compounds that may escape from equipment or a unit owing to the effects of: • Purges required for safety, overpressure or unintentional or voluntary opening of valves or pressure-relief valves; • Leaks on isolation systems. Combustible residues escaping to the flares are sometimes recovered, either continuously or selectively, depending on the fluid flow and composition, in which case they are recycled upstream of the flare. Hydrocarbons and other flared products are not recovered. According to [1], flaring is the controlled combustion of a gas in the routine oil and gas processing. The combustion takes place at the extremity of a flare drum or ramp. Flare systems are discussed in different standards [2, 3]. In many cases local legislation defines the rules governing the limitation of undesirable effects [4, 5]. A flare system consists of: • A piping system whose battery limit is the discharge flange of the valves, the downstream flange of the quick release valves, and in general, all the physical limits that allow to evacuate the fluid process to the flares system. The output temperature of the fluid in the mains is variable: in oil and gas production it is usually in the range –50 °C to +150 °C. In the downstream oil and LPG processing industries, it can vary from –50 °C to +400 °C at the output of process units. In the liquefaction of natural gas, it ranges from –165 °C to +150 °C. The temperature of the collectors is usually close to ambient, except in case of rapid relief of a system, where it can reach the temperature of the process (current case of the high-pressure flare systems), or on the contrary to reach low temperatures due to a strong depressurization downstream the relief valve. The piping system consists of: ○ Individual lines located at the outlet of the exhaust systems; ○ Secondary collectors (sub headers) connected to the individual branches and the main collector; ○ A main collector (header) that connects the secondary collectors to the separator drum (knock-out drum). • A condensate separation drum (knock-out or KO drum) which separates the liquid condensate (including water) out of the gas phase. Liquids that might be present in the gas or that condense in the piping system are separated in this drum (the drum may be laid out horizontally or vertically). It is located close to the base of the flare stack. This drum is essential for the safety of the

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•

•

•

•

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system: any liquid in the gas could extinguish the flame or cause irregular combustion and smoke. It could also generate a fog of ignited products; A liquid seal drum: it is usually located downstream of the KO drum or built in the flare drum. It prevents the flashbacks that could be caused by air ingress inside the flare. It maintains a positive pressure on the upstream system and acts as a damper in the event of a shock wave (flare protection). The liquid seal is sometimes replaced by a flame arrestor and purge system; Flare-tip supporting structures: they are available in different configurations which are described in various technical documents: ○ Self-supporting flare stacks: their height is limited to about 30 m; when the height increases and the force of the wind increases, the diameter and thickness of the stack must be increased, ○ Guyed flare stacks: often used for flare stacks between 30 m and 110 m; the flare stack is anchored to the ground by 3 sets of cables of different heights, each set vertically aligned in a plane, with the planes separated by 120°, ○ Derrick-supported flare stacks: this solution is used for flare stacks exceeding 110 m in height, ○ Offshore flare structures: the flare system is designed to allow a large volume of gas to escape quickly; the flares are either close to the production facilities or located on remote platforms. Offshore flares are typically mounted on an inclined ramp, vertical towers, or remote platforms far from the production unit, ○ Ground flares: this type of flare is used for burning liquids and sometimes gas, Gas sealing devices: such devices are placed on high flares to prevent air from entering the tower. Air mixed with gaseous hydrocarbons can form an explosive mixture. A purge gas maintains a hydrocarbon-rich atmosphere and the gas sealing device reduces the amount of gas consumed for this purpose. Two types of devices can be used: ○ The molecular type seals force the gas purge to pass through a labyrinth, thus forming a seal owing to the difference in molecular weights. The molecular seal is placed just below the flare tip, ○ The liquid seals are in the body of the tip. They provide low resistance to fluids circulating in one direction and a high resistance in the other direction, Flare tip: flare tips (also called flare burners) are designed to ensure the combustion of hydrocarbons. They are subject to highly variable and unpredictable service conditions. Flame temperatures may vary from less than 600 °C to over 1100 °C, depending on the calorific value of the gas and the flow rate. At these thermal cycles superimpose severe external environmental conditions (e.g., marine atmospheres), and degradation of materials at high temperature. Many types of flare tips are available on the market, they are generally patented [6, 7]. The maintenance of a flare tip is difficult (access, availability) and often expensive. The flare tips can be classified according to pressure or type;

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Flare pressure: ○ Low pressure flare tip: they are designed for short term peak speeds of 0.5 Mach and 0.2 Mach in normal operating conditions. They usually have a single burner, and the networks operate at pressures below 0.075 MPa, ○ Utility flare tips: designed for speeds of up to 0.8 Mach. They are used in applications that do not require smoke-free combustion or where smoke-free combustion can be obtained without additional means, ○ High-pressure flare tip: they are designed to operate in sonic mode and produce a very stable flame without smoke emission, however a strong counter pressure must be introduced into the flare system. The pressure of the escaping gas creates the turbulence, introducing the combustion air at the base of the flame to produce smoke-free combustion. Several types of HP flare tips exist, HP tube-mounted flares, sonic flares, and HP assisted flares. Sonic high-pressure flares are used when low-radiation, smoke-free flaring is desired. High-pressure flare tips typically operate at more than 0.1 MPa and often are of the multiburner type. Flare tip type: ○ Single burner: one burner, ○ Multi-burner: several burners, usually arranged around the perimeter of the tip, ○ Closed flares: mask the flame from direct view and considerably reduce noise and thermal radiation. These types of flares are often limited in terms of flow rate; they are common on hydrocarbon production sites, • Pilots: they maintain a continuous flame and are arranged around the outer perimeter of the flare tip. They are usually fed by an independent gas-oil source and are switched on manually or automatically. Pilots can be installed on retractable systems [8]; • Air assisted (assisted combustion) systems based on the injection of steam, low-pressure air, or high-pressure air: when present, such systems help improve combustion and reduce the production of smoke. High-pressure air assist systems (HPAAS) deliver smoke-free combustion. Many installation and equipment combinations are possible, mainly regarding the type of flare, the flare tip, the pilots, and the air assist systems.

4.4.9.2. Main damage mechanisms Several corrosion problems will be distinguished, those concerning: • • • •

The piping system, collectors, knock-out drum, and liquid seal; The flare stacks or the ramps; The flare tip and the pilots; Auxiliary piping of ignition systems, air, and steam injection.

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Piping systems, separator drums, liquid seal Wet H2S Induced Cracking (Blistering/HIC/SSC/SOHIC) (DM#2) If the streams contain H2S, occurrences of HIC may be encountered in carbonsteel flare collectors made of rolled, welded sheets. Cases of HIC/SSCC have been encountered in carbon-steel KO drums that are not NACE MR0175/ISO 15156 compliant. These forms of corrosion rarely occur in the piping system but are more frequent in separator drums. Thermal Shock (DM#27) This type of degradation is theoretically possible when hot or ambient-temperature metal is in contact with a very cold liquid (liquefied natural gas for example); this case is unlikely in E & P. Brittle Fracture (DM#31) When the resilience of materials is too low, and following a thermal shock caused by gas expansion or immediate vaporization of a liquid at valve outlets or when opening a valve, the temperature of the flashed gas can be less than the minimum permissible temperature of the metal composing the equipment. The stresses induced in the equipment may then cause it to crack. Vibration-Induced Fatigue (DM#54) This is essentially linked to pressure transitions (water hammer, steam hammer, condensation-induced shock). The piping system then moves intensely under the effect of shock waves generated by the overpressure. CO2 Corrosion (DM#P1) or H2S + CO2 Corrosion (weight loss corrosion) (DM#P2) Occurs essentially in the water compartment of the separator (KO) drum and the liquid seal, caused by inadequate purge. Water containing CO2 or CO2 + H2S, as well as NOx, SOx can stagnate and cause severe corrosion. These two damage mechanisms are to be considered respectively in both sweet (with no or little H2S) or sour systems (containing H2S). These damage mechanisms are usually not experienced along flare piping as long as pipes are well designed and installed with a self-draining profile, i.e., with no accumulated free water. Under Deposit Corrosion (DM#P6) Hydrocarbon sludges, sulfide, carbonate deposits, or a combination of them can form in the piping system and all the way into the separator drum. Owing to low circulation rates and the rather gaseous nature of the flow, the deposits develop mainly in the lower section (at positions 4:00 – 8:00) of pipes and collectors. The nature and quantity of the deposits depend on the hydrocarbon flow (chemical composition, flow rate, temperature). Products containing H2S and CO2 tend to

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generate more deposits than do clean products. Types of under deposit corrosion (whose nature can vary depending on the composition of the flow) commonly develop. The deposits reduce the cross section of the pipe and increase the weight of the structure. Deposits tend to develop more easily in low-pressure flare networks than in the high-pressure networks. The alternate day – night temperature, resulting in water condensation – evaporation on the piping surface particularly favors the precipitation of iron sulfide when H2S is present: cases have occurred where more than 1 cm of iron sulfide has been formed on pipe walls. Low-Temperature Sulfur Corrosion (DM#P8) In collectors containing H2S, traces of steam, and off oxygen, it is quite common to observe sulfur deposits. Cases of corrosion by elemental sulfur have been observed in flare networks and are associated with under deposit corrosion. There are also cases of elemental sulfur corrosion in equipment and piping of VRU (Vapor Recovery Unit) systems associated with flare-gas recovery. Flare stacks, ramps CO2 Corrosion (DM#P1) or H2S + CO2 Corrosion (weight loss corrosion) (DM#P2) • Basically, in clogged drains at the bottom of the flare stack, water loaded with CO2, or H2S + CO2 and possibly NOx, SOx can stagnate and cause severe corrosion. Corrosion-Fatigue (DM#43) • Fatigue cracking occurs at a lower stress threshold than expected, due to corrosion of the structure; failure of tension cables under the effect of external stress associated with corrosion have been observed. Vibration-Induced Fatigue (DM#54) • Cases of fatigue can be encountered on flare stacks, and tension cables due to excessive stresses produced by the wind. Flare tips, pilots Oxidation (DM#11) Degradation of the flare tip by high-temperature oxidation causing “internal combustion of the metal” is the main cause of flare tip failure. The mechanisms that can cause “internal combustion”, thereby causing the metal to burn (local fusion) depend essentially on the design and operations [9]. The key parameters to consider are the gas flow rate and pressure as well as the wind force. If, though the gas velocity is low by windy weather, the wind can create a recirculation profile near the

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end of the flare tip. The gas will then tend to migrate to the downwind side and will be pushed back into the recirculation area, or if mixed with air, it will ignite. These conditions are conducive to the formation of burned areas inside the flare tip. The possibility of internal burning is higher on horizontal flares and on those positioned at an angle. Steam-assisted combustion flares may undergo internal burning when the gas velocity is too low, and the steam velocity is too high. In these conditions steam jets from the upper nozzles can create a gas flow coverage effect. Severe attacks may occur when the gas contains H2S or/and SOx. Nickel sulfides (NiS and Ni3S2) can form above the spinel layer. These compounds have a melting point of about 787 °C; the sulfides therefore spread into the chromium oxide layer and destroy it. The metal is no longer protected by a stable and compact oxide, which leads to catastrophic corrosion.

Figure 97. – Profile of internal combustion in a flare tip, under the effect of wind.

When the flame encounters the external surface of a flare tip, the metal surface can be degraded by external burn. This occurs in windy weather with low gas flow conditions. Wind blowing against the flare tip causes depression zones to develop underneath it. If the gas flow rate is sufficiently high, the moment of the outgoing gas is high, and the gas is evacuated beyond the depression zone. This causes the flame to develop outside. If the gas flow rate is too low, the flame remains inside the depression zone and burns near the tip. The depth of the flame downwards varies with the diameter of the flare tip and the wind speed. Flare tip combustion occurs in conditions of high temperatures and relatively reductive atmosphere. These conditions are typically cyclic, depending on the direction and force of the wind, as well as on the gas flow rate. The sensitivity to “internal combustion” is not very affected by the metal grade but is rather a function of the flare tip design, the gas flow pressure, the gas flow rate, and the air assist combustion systems.

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Thermal Fatigue (DM#12) Cracks are often seen to develop from the holes in the plates bolted to the flame stabilizers. These cracks are related to fatigue caused by thermal stress and by the reduction of the mechanical resistance. In an aggressive external environment (e.g., sea fog), the salts that settle on the metal also accelerate the process. Refractory Degradation (DM#14) Some flare tips or closed-type flares are equipped with refractory materials; their degradation must be considered. Formation of Brittle Phases (e.g., sigma phase) (DM#32) Intermetallic phases and carbides can form on the alloys used in flare-tip service conditions. The sensitivity depends essentially on the nature of the alloy (silicon, molybdenum, niobium, aluminum, lanthanides, etc.) contribute to the formation of brittle phases. The probability of developing brittle phases differs depending on the alloy and combustion conditions. Nickel alloys such as 625 alloy, sometimes proposed, are particularly susceptible to embrittlement above 600 °C. Such embrittlement is associated with the formation of a γ” phase which turns into an incoherent orthorhombic form (δ phase) around 650 °C, and then to carbides, mainly M6C around 760 °C. Dissimilar Metal Weld Cracking (DM#39) In many cases, the Cr-Ni-Fe alloy elements used for manufacturing flare tips are welded to a part made of carbon steel. Corrosion around heterogeneous welds must be taken into consideration. Piping and auxiliary equipment (ignition lines, instrument lines, steam, or air injection lines) Internal corrosion is not likely in these parts, but such piping and equipment are susceptible to external corrosion (atmospheric corrosion, stress corrosion cracking under the effect of chlorides), which can lead to a functional loss in the systems.

4.4.9.3. Corrosion prevention solutions Materials used Standard steel The exhaust pipes of the valves are usually designed such that the material used is not susceptible to brittle rupture during flashing. Depending on the gas compositions and when the minimum pressurization temperature and corrosion resistance criteria are respected, carbon steel can be used, HIC/SSC resistant if H2S is present.

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The KO drums and the liquid seals are generally made of carbon steel that is compliant with NACE MR0175/ISO 15156-2 criteria, if required. Depending on the composition of the process fluids, they are usually entirely or partially coated with epoxy resins or acid-proof epoxy-ceramic coatings. Flare stacks can be constructed of carbon steel, or alloyed steel, depending on the exposure. Use of CRAs For systems where the fluid flash temperature is lower than the minimum exposure metal temperature, materials suitable for low-temperature service must be used (steels for low-temperature use (ASTM A333/A 333 M), austenitic stainless steels), the limit depends on the design conditions. Flare tips are made of austenitic stainless steel AISI 310 SS, at least, in order to withstand high temperature oxidation or the action of sulfur compounds in reductive atmospheres. Type 800H/AT® alloys, and special alloys such as UNS S30815, S35315, N06333, are also occasionally used. The presence of elements such as silicon, cerium and cobalt improve the antioxidation and anti- carburization properties. For flares burning large quantities of H2S, it is preferable to avoid using nickelrich alloys, such as alloy 800H. The pilots could be constructed of heat-resistant materials such as AISI 309 SS, AISI 310 SS, CK20 (cast 310SS) or nickel-based alloys such as 800H [3, 8]. The pipe section that feeds the pilot, potentially exposed to a flashback, can sometimes be made of AISI 304 SS or AISI 316 SS. Prevention solutions H2S + CO2 Corrosion (weight loss corrosion) Maintain the purges (preferably continuous) on the KO drums and functional flare stacks, to avoid any stagnant water. Make sure the KO drums are coated internally. Install sacrificial anodes. Flare piping is supposedly designed with a self-draining profile, at least for main and secondary collectors, in order to prevent large amounts of liquid to be displaced when check valves abruptly open. As long as this profile is well applied, this corrosion remains moderate on most flare networks. Under Deposit Corrosion Maintaining dry fuel-gas sweeping in the flare collectors can sometimes minimize the formation of deposits. Low-Temperature Sulfur Corrosion Minimize air intake in the system.

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Wet H2S Induced Cracking (Blistering/HIC)/SSC/SOHIC) When the streams contain H2S, use materials meeting the criteria of NACE MR0175/ISO 15156 [10]. Brittle Fracture The probability that the piping might undergo brittle rupture must be reduced to a minimum through the system design and construction. The temperatures reached in the circuits during rapid pressure relief must be calculated. The materials must be chosen according to the minimum temperature reached by the metal, and the system design must factor in the fast, dimensional changes the networks are subjected to, during rapid pressure relief. CO2 Corrosion Prevent water accumulation along the piping. Use of CO2 corrosion-resistant materials or internal coating + sacrificial anodes in the KO drum. Rupture by Vibration Fatigue In piping systems, the probability of this type of damage can be reduced through design rules that minimize the effect of shock waves caused by water hammer and steam shock due to condensate formation [2]. On flare stacks, it is important to make sure that the design rules for tensioning the cables are followed and that no corrosion occurs on these components (resulting in a reduction of the load bearing section). Corrosion-Fatigue Protect external elements subject to corrosion-fatigue caused by external corrosion (use materials that are insensitive to atmospheric corrosion and pitting corrosion under the effect of chlorides), use coatings. Prevention of oxidation For flare tips, use alloys that are at minimum AISI 310 SS type steels. Depending on conditions, use of steels resistant to high-temperature oxidation, containing elements favoring resistance to oxidation and carburization (silicon, cerium, etc.). Pilots are usually exposed to less harsh conditions, but they may suffer from the burner flames. Prevention of sulfidation The combination of high temperatures, and reductive, sulfide-rich atmospheres increases the sensitivity to corrosion of nickel-rich alloys, so chromium-rich alloys should be used instead.

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Prevention of low cycle fatigue Minimize bolt-on fasteners and weld beads with sharp angles. Bores for bolt-on passages must not have sharp angles. Prevention of refractory degradation Use suitable refractory materials, avoid joints with cemented seals (use ceramic fibers, wherever possible). Ensure that the specifications of the selected refractory materials and their implementation help reach the life-span objectives of the flare tips. Prevention of the formation of brittle phases Alloys containing silicon with identical nickel-equivalent are more susceptible to the formation of sigma phases than are low Si alloys. In this case, select alloys containing more nickel when the silicon content increases. If 800H type alloys are to be used, check the Ti/Al ratio as well as the grain size. These alloys should be avoided on flare tips exposed to H2S. The use of 625-type alloys should be avoided in the manufacture of deflector brackets (sometimes recommended [11]) as these alloys form fragile phases in the 500–600 °C temperature range. Cracking in heterogeneous welds Make sure that the weld design and construction are acceptable, and that under no condition will the welds be subjected to high temperatures during service. Integrity Operating Windows (IOW) It is difficult to develop an IOW system such as that proposed by API 584 [12]. However, the following rules help limit corrosion-related risks in flare systems: • Always maintain slopes on pipes and manifolds (keep stagnating liquids and formation of deposits to a minimum in piping systems); • Make sure that purging systems remain functional (separator drum, flare stacks), to minimize under‑deposit corrosion and corrosion by sulfidic waters; • Check liquid levels in the separator drum (make sure that the purge lines and valves are not clogged); • Check that the steam or air flow is maintained in the burners, if applicable (maintain design conditions at the flare tip); • The gas flow and the flame stability must be controlled to ensure that the system is effectively running under design conditions.

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4.4.9.4. References 1

Parameters for Properly Designed and Operated Flares, Report for Flare Review Panel, April 2012, Prepared by U.S. EPA Office of Air Quality Planning and Standards (OAQPS).

2

Selecting the Proper Flare Systems, Adam Bader, Charles E. Baukal, Jr., P.E. Wes Bussman, JOHN ZINK Co. LLC, CEP July 2011, Copyright © 2011 American Institute of Chemical Engineers (AIChE).

3

Production Flares, JOHN ZINK Company LLC, © 2004 by John Zink Company, Printed in USA No. 34611.

4

API Std 521, (ISO 23251), Petroleum and natural gas industries - Pressurerelieving and Depressuring Systems.

5

API Std 537, (ISO 25457:2008), Flare Details for General Refinery and Petrochemical Service.

6

New Technology: Saudi Aramco High Pressure Air Assist System (HPAAS) for upgrading Existing Flares to Smokeless Combustion, Mazen Mashour, Scot Smith, Nigel Palfreeman, Greg Seefeldt, International Flame Research Foundation 16th Members Conference, Combustion and Sustainability: New Technologies, New Fuels, New Challenges, Boston, USA, June 8-10, 2009.

7

Flare Pilot System Safety, John Bellovich, Jim Franklin, and Bob Schwartz, John Zink Company, LLC, published online 30 August 2006, in Willey InterScience (www.interscience.wiley.com). DOI 10.1002/prs.10154.

8

Flaring & venting in the oil & gas Exploration & Production industry, John Kearns, Kit Armstrong, Les Shirvill, Emmanuel Garland, Carlos Simon, Jennifer Monopolis, Report No. 2.79/288, January 2000, OGP, International Association of Oil & Gas Producers © OGP.

9

Corrosion of Flare Tips, Wes Bussman, Jim Franklin and Robert Schwartz, NACE97, Chicago, Illinois.

10

Long Life Flare Tips, Alistair Benjamin Fox, Yan Huang, Dena Rafik, SPE International Oilfield Corrosion Conference, 27 May, Aberdeen, UK, 2008, Publisher Society of Petroleum Engineers, Document ID SPE-114125-MS.

11

Code of Federal Regulations, “General Control Device Requirements,” 40 CFR 60.18.

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Figure 98.  –  HP and LP Flare Unit (Sweet), U08a – Corrosion Location Diagram.

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312 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 99.  –  HP and LP Flare Unit (Sweet), U08a – Material Selection Diagram.

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Figure 100.  –  HP and LP Flare Unit (Sour), U08b – Corrosion Location Diagram.

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314 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 101.  –  HP and LP Flare Unit (Sour), U08b – Material Selection Diagram.

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4.4.10. Closed Drain Networks - U09 This chapter concerns closed-drain systems on any oil or gas production facility, with or without CO2 and H2S. Therefore, these systems are exposed to a wide variety of environments.

4.4.10.1. Description of the process A closed drain system is usually a large, extensive piping network used intermittently to collect liquid purges from piping systems and pressure vessels and convey them to a closed drain vessel. This purge is carried out after the systems and devices to be purged, are decompressed. This way, the amount of gas entering the drainage system is low, except if accidentally, and even though some gas is also formed from liquid degassing. However, as accidental ingress cannot be excluded, the network must be capable of withstanding significant pressure, despite nominal operating conditions under pressures close to ambient. The residual gas is usually sent to the LP flare network, except if the gas is systematically recovered and recompressed in the relevant facility. Liquids are usually returned to production separators on the production line. A reheating bundle may be installed inside the closed drain drum, to prevent: • The solidification of hydrocarbon fluids received, due to moderate average service temperatures (close to ambient), e.g., in the presence of paraffinic oils; • Freezing of the liquids it contains, in cold countries. Except during purging, these systems are usually at around atmospheric pressure.

4.4.10.2. Main damage mechanisms N.B.: except for the closed drain vessel and the downstream liquid network, most of the system is designed to be self-draining, to prevent any liquid from stagnating in the collection network. Nevertheless, experience has frequently revealed failures around points of internal water accumulation. This demonstrates that the self-draining property is not totally effective, especially on distant parts of the facilities or on large platforms. On a large network, a downward gradient may not always be available along the entire circuit to the closed drain drum, thereby leading to a risk of failure in areas of water retention. The damage mechanisms specific to the drain systems described below are based on carbon steel as the basic material. Sulfide Stress Cracking (SSC) (DM#2) (fluids whose H2S concentration high enough for severity ≥ 1, based on the NACE MR0175/ISO 15156-2 severity chart) This is a theoretical risk, which could occur if the production fluid contains high concentrations of H2S and the produced water is highly acidic.

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In practice, a severity greater than 1 on the severity chart is seldom found in these systems because: • Purged liquids are previously degassed; • The mean operating pressure is atmospheric, outside periods of purging; • Of the highly transient nature of pressures higher than atmospheric pressure. It would be excessively conservative to calculate H2S severity (pH and partial pressure) for the maximum operating pressure. Because H2S is more soluble in water than lighter and more volatile gases, the residual gas present in the system after the purge may be much more concentrated in H2S than the gas contained in the purged pressure systems. It is cautious to consider a concentration 10 times higher, under a pressure of 0.1 MPa (a). Among the possible risks of sulfide stress cracking, HIC is the most serious, especially on the closed drain vessel, if the severity is high enough. Low pressures and the lack of need for a high strength material for such vessels make the risk of SSC less likely. Microbiologically Induced Corrosion (DM#P4) This damage mechanism is the main risk for these systems, due to the lack of flow, the close-to-ambient service temperature and the easy contamination by the different fluids injected into the system. The most critical locations are: 1. the dead-legs, the low points, the low flow lines witch allow potential accumulation of sediments and bacteria into the collection network; 2. the closed drain vessel, which is usually a great “fermenting system” for microbes; 3. the liquid piping network that returns to the production process. CO2 Corrosion (DM#P1) or H2S + CO2 Corrosion (weight loss corrosion) (DM#P2) The concentration of H2S (more or less significant) in gas compared to CO2 determines the respective potential corrosion of the steel by CO2 or by H2S + CO2. A H2S - CO2 ratio ≥ 0.05 is a commonly considered as the transition threshold [1, 2, 3]. These damage mechanisms concern the same equipment parts as those affected by microbiologically induced corrosion, i.e., those where water can accumulate. Even though the severity calculated from the partial pressures of the gas may appear moderate due to the atmospheric service pressure (see previous comments), the effects of over-concentrations of H2S also apply to CO2, so that acidic gas concentrations can easily exceed 5-10%, even if they are only 1 to 2% in the gas in the first separation stages. Consequently, localized corrosion of 0.3 to 1 mm/year can occur in areas where acid water (water of low bicarbonate content) tends to stagnate. The potential accumulation of deposits in stagnation points can also promote localized corrosion by CO2 or CO2 + H2S.

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When large quantities of H2S (typically over 0.2 – 0.5%) are present, abundant thick iron sulfide deposits can form over entire perimeter of the tubes. This phenomenon is akin to a “Top of line corrosion” mechanism. It can occur in a temperature range of 20 to 40–50 °C in a wet gas, especially when the system is subjected to regular temperature fluctuations (day – night), and thereby to regular wet/dry cycles. Even average moderate damage (< 1 mm of thickness loss) can be enough to generate a highly porous deposit, 5 to 10 mm thick that can cause serious operational problems. Although to the writer’s knowledge this phenomenon is rare, such cases have been observed in flaring and drainage systems, as well as in insufficiently dried gas pipelines (accumulation of “black powder” in gas pipelines, which is a recurrent subject for some companies). Finally, the possibility of oxygen ingress in this network is a major risk factor of severe localized corrosion, especially in the presence of dissolved H2S. In this case, it is best that the closed drain vessel be blanketed to avoid oxygen ingress. Stress Corrosion Cracking (DM#23) and Crevice Corrosion (DM#P10) These damage mechanisms would theoretically concern a closed drain system made of stainless steel. It is likely to occur in areas of water stagnation, in the event of oxygen ingress in the system. Highly salted produced waters (> 50–100 g/L) are obviously favorable to such localized internal attacks.

4.4.10.3. Corrosion prevention solutions The simplest and least costly solution for the collection network would be to ensure that it is fully self-draining all the way to the closed drain drum, so that water is not likely to accumulate anywhere. Nevertheless, operational experience shows that although this solution is the one “officially” chosen, in reality things are quite different: drainage systems undergo numerous types of internal corrosion, in areas where water, and potentially solids, accumulate. Preventive solutions that can secure satisfactory long-term integrity involve the use of: • Composite materials or stainless steels for the collection network and evacuation of liquids; • Carbon steel + internal coating + cathodic protection using sacrificial anodes for the closed drain vessel; • Carbon steel for the gas-to-flare exhaust system. However, given the intermittent use of this drainage system and its low operating pressure, reservations are often expressed concerning the excessive investment in

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non-corrodible materials. In this case, the “carbon steel solution” remains applicable, in any of the following conditions: • The network is small enough that a self-draining profile can be fully guaranteed (e.g., small offshore platform). Moreover, this needs to be verified in the construction phase; • The produced water is sufficiently alkaline that its corrosiveness is low (a total alkalinity typically of the order of or greater than 1500–2000 mg/L CaCO3); • The operator formally accepts the possibility of failure after about 10 years on such networks, therefore the possibility of leakage, the related maintenance, and the replacement costs. General comment: the term “carbon steel” as used above includes the versions specified for “H2S service”, provided the H2S severity is ≥ 1 (based on the NACE MR0175/ISO 15156-2 severity chart). The implementation of chemical treatments (inhibitors, biocides...) is not considered a reliable, easily applicable solution for a network with multiple branches: it is misleading to believe that corrosion can be managed using such means. Other preventive actions and points requiring special attention The essential point to watch out for in such units is that there must be no oxygen ingress; this applies for the presence of H2S as for the use of stainless steel in the networks. Moreover, if a self-draining profile has been chosen to prevent corrosion in a carbon steel network, it is important to verify, during the construction phase, that a regular gradient exists throughout the system to avoid water stagnation. In short: • Closed drain systems made of carbon steel often leak after 10-15 years of service, due to the stagnation of water at low points; • As a self-draining profile cannot be fully guaranteed (unfortunately common on large installations), it is therefore best to use non-corrodible materials for liquid piping systems; • If that is not possible, the facility operator must realize that leaks and failures will possibly occur, meaning that ultimately repairs and replacements will have to be done.

4.4.10.4. References 1

Bernardus F.M.  Pots, Sergio D.  Kapusta, Randy C.  John, M.J.J.  Simon Thomas, Ian J. Rippon, T.S. Whitham, Magdy Girgi, “Improvements on De Waard-Milliams corrosion prediction and applications to corrosion management”, Paper No 02235, NACE, CORROSION 2002.

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2

Michel Bonis, Magdy Girgis, Kevin Goerz, Reg MacDonald, “Weight loss corrosion with H2S: Using past operations for designing future facilities”, paper 6122, NACE, CORROSION 2006.

3

M. Bonis, “Weight loss corrosion with H2S: From facts to leading parameters and mechanisms”, paper n° 09564, NACE, CORROSION 2009.

Figure 102.  –  Closed Drain Network, U09 – Corrosion Location Diagram.

320 Predicting Internal Corrosion in Oil and Gas Exploration and Production Operations

Figure 103.  –  Closed Drain Network, U09 – Material Selection Diagram.

4.4.11. Open Drain Networks - U10 4.4.11.1. Description of the process Open drain systems are often large, extensive networks of collectors and piping used to collect potentially contaminated water from the process-unit containment bases, before conveying it to a collector (open drain vessel). The collection system itself includes both discharges, open manifolds (gutters) and closed piping. The waters collected include mainly rainwater, fire water, wash water, and any hydrocarbons and other contaminants that may have spilled into the containment areas. The water is usually discharged after treatment; the oily water is recovered either from the open drain tank or from the water treatment process. A reheating system can be installed inside the open drain vessel to avoid freezing in cold countries.

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4.4.11.2. Main damage mechanisms N.B.: as in the previous section, except for the open drain vessel and the downstream liquid network, most of the system should ideally be designed with a self-draining profile, to prevent any stagnant liquid in the collection network. Nevertheless, experience has frequently revealed failures around points of internal water accumulation. This indicates that this self-draining property is not fully effective, especially on extensive plants or large platforms. The extent of the network makes it very difficult to guarantee a regular downward gradient to the open drain Vessel, thereby leading to the risk of failure in areas where water stagnates. The damage mechanisms specific to the drainage systems described below are based on carbon steel as the base material. Oxygen Induced Corrosion (DM#P7) This is the first damage mechanism of open drains made of carbon steel, since all the water received contains air. This corrosion potentially concerns water retention zones, where localized corrosion can occur at rates of around 0.3 to 1.0 mm/year. The accumulation of solid deposits, as well as bacterial activity (see below), may be complementary factors that promote corrosion. Microbiologically Induced Corrosion (DM#P4) Microbiologically induced corrosion is the second type of corrosion in areas where water accumulates, especially if solid deposits also form. The aerated nature of the water does not mean that microbiologically induced corrosion is absent. It can occur: • Either when aerobic microorganisms are present; • Or when anaerobic species are present in a locally-deaerated environment, due to the synergistic action of the aerobic microorganisms. In fact, it is wise not to separate those damage mechanisms caused by dissolved oxygen from those caused by micro-organisms: these two mechanisms are quite synergistic rather than contradictory. Moreover, it is impossible to differentiate them by the damage morphology. It is important to remember that open-drain networks made of steel are likely to develop severe corrosion within a normal period of 10 to 20 years, when used in liquid piping or collection networks with localized points where water and solids can accumulate.

4.4.11.3. Corrosion prevention solutions As with closed drain networks, the simplest and most cost-effective solution for the collection network would be to ensure that it is self-draining all the way to

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the open drain vessel, so that it is not likely to include areas where water can stagnate. Nevertheless, as stated before, operational experience shows that, although this solution is the one “officially” chosen, in reality things are quite different. Preventive solutions and points of attention are mentioned in the section 4.4.10.3 of this document.

Figure 104.  –  Open Drain Network, U10 – Corrosion Location Diagram.

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Figure 105.  –  Open Drain Network, U10 – Material Selection Diagram.

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