SABP-A-019.pdf

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SABP-A-019 8

March

2010

Pipeline Corrosion Control

Document Responsibility: Materials and Corrosion Control Standards Committee

Saudi Aramco DeskTop Standards

Table of Contents

1 Scope and Purpose... 3

2 Conflicts and Deviations... 3

3 References... 3

4 Definitions and Abbreviations... 8

5 Pipeline System Description... 9

6 Damage Mechanisms... 12 7 Mitigation Options... 17 8 Corrosion Monitoring... 20 9 Validation... 36 10 Record Keeping... 40 11 Contributor Authors... 40

Detailed Table of Contents

1 Scope and Purpose 3

2 Conflicts and Deviations 3

3 References 3

4 Definitions and Abbreviations 8

5 Pipeline System Description 9

5.1 Gas Service 10

5.2 Crude Service 10

5.3 Condensate Service 11

5.4 NGL Service 11

5.5 Refined Product Service 11

6 Damage Mechanisms 12

6.1 External Damage Mechanisms 12

6.1.1 External Pipeline Corrosion 12

6.1.2 Sleeve Collapse 13

6.2 Internal Damage Mechanisms 13

6.2.1 Hydrogen Induced Cracking (HIC) and SOHIC 13

6.2.2 Sulfide Stress Cracking 14

6.2.3 Sweet corrosion 14

6.2.4 Sour Corrosion 15

6.2.5 Microbiological Induced Corrosion 15 6.2.6 Black Powder (Sales Gas & Refined Products) 16

7 Mitigation Options 17 7.1 Inhibition 17 7.2 Biocide Treatment 17 7.3 On-stream Scraping 18 7.4 Coatings 18 7.5 Cathodic Protection 19

7.6 Water Dew Point Control & Black Powder Filtration 20

8 Corrosion Monitoring 20

8.1 Types of Metal Loss Coupons 20

8.2 Corrosion and Pitting Rates Calculation 25 8.3 Corrosion Monitoring Location, Insertion & Orientation 25 8.4 Design Basis for Corrosion Monitoring Access Fitting 28 8.5 Safety Issues Related to Coupon Retrieval Operations 30

8.6 Inspection Data 30

8.7 Sampling 31

8.8 Corrosion Data Interpretation and Correlation 32 8.9 On-Line/Real Time Corrosion Monitoring 32 8.10 On-Line Monitoring Field Configuration 34

8.11 CP Monitoring 36

9 Validation 36

9.1 Hydrotest 37

9.2 In-line Inspection 37

9.3 On-stream Inspection 37

9.4 Test & Inspection (T&I) 39

9.5 Risk Based Inspection (RBI) 39

10 Record Keeping 40

1 Scope and Purpose

This Best Practice covers primarily transmission pipelines in gas, crude oil, condensate, NGL, sales gas, and refined product service. Its main intent is to serve as a resource for field personnel to provide the optimum corrosion management approach for

transmission pipelines. It covers applicable damage mechanisms and lists viable mitigation and validation options based on established industry guidelines and field experience.

Transmission pipelines play an extremely important role as a means of transporting hydrocarbon products from production sources to another facility or to terminals. Unprotected pipelines, whether buried in the ground, exposed to the atmosphere, or submerged in water, are susceptible to corrosion. Without proper maintenance, every pipeline system will eventually deteriorate. Corrosion can weaken the structural integrity of a pipeline and make it an unsafe means for transporting potentially hazardous materials.

Effective corrosion control can extend the useful life of all pipelines. The increased risk of pipeline failure far outweighs the costs associated with installing, monitoring, and maintaining corrosion control systems. Preventing pipelines from deteriorating and failing will save money, preserve the environment, and protect public safety.

2 Conflicts and Deviations

This Best Practice was written to be consistent with Saudi Aramco and applicable international standards. If there is a conflict between this Best Practice and other standards or specifications, please contact the Coordinator of ME&CCD/CSD for resolution.

3 References

The following list shows the recommended transmission pipelines corrosion management practices:

 API RP 570 "Piping Inspection Code: Inspection, Repair, Alteration and Re-rating of In-Service Piping Systems" - Addresses inspection, repair, alteration, and re-rating procedures for metallic piping systems that have been in service.

 API RP 580 “Risk Based Inspection”

 API RP 1632 "Cathodic Protection of Underground Petroleum Storage Tanks and Piping System"

 ISO 15156 (NACE MR0175) "Petroleum and Natural Gas Industries - Materials for Use in H2S-containing Environments in Oil and Gas Production"

 NACE 35100 “In-Line Nondestructive Inspection of Pipelines - Item No. 24211”

 NACE RP0102 “In-Line Inspection of Pipelines”.

Saudi Aramco Engineering Standards & Procedures

 SAES-A-007: Hydrostatic Testing Fluids and Lay-up Procedures

This standard establishes requirements to control corrosion and microbiological damage during and after hydrotesting of new, revalidated, and refurbished equipment when equipment is hydrotested in accordance with SAES-A-004, SAES-L-150 or as required by other standards that specifically reference SAES-A-007.

 SAES-A-205: Oilfield Chemicals

This standard establishes requirements for selection, quality assurance, quality control, and first fill purchase of oilfield chemicals in MSG (Materials Service Group) 147000. The purpose of this standard is to implement a program that results in the cost-effective purchase and performance of oilfield chemicals. This

document does not address other chemicals, such as drilling chemicals, water treatment chemicals, or chemicals used in refinery processes.

 SAES-A-206: Positive Material Identification

This standard defines the minimum mandatory requirements for positive material identification (PMI) of pressure-retaining alloy material components, flange bolting, welds, weld overlays and cladding. It is intended to ensure that the nominal

composition of the alloy components and associated welds have been correctly supplied and installed as specified. Where applicable, this entire standard shall be attached to and made a part of purchase orders. Although this document addresses PMI requirements for alloy materials, provisions are also given for carbon steels under certain conditions.

 SAES-A-301: Materials Resistant to Sulfide Stress Corrosion Cracking

This standard presents metallic material requirements for resistance to sulfide stress cracking (SSC) for petroleum production, drilling, gathering and flowline

equipment, field processing facilities, and refining facilities to be used in hydrogen sulfide (H2S)-bearing hydrocarbon service (liquid, gas, and/or multiphase). This

standard does not include and is not intended to include design specifications. Other forms of corrosion and other modes of failure, although outside the scope of this

standard, should also be considered in design and operation of equipment. Severely corrosive conditions may lead to failures by mechanisms other than SSC and should be mitigated by corrosion inhibition or materials selection. This standard includes a variety of materials that might be used for any given component. The selection of a specific material for use shall be made on the basis of operating conditions that include but not limited to: pressure, temperature, system corrosiveness, fluid properties, and level of applied and residual stress.

 SAES-H-002: Internal and External Coatings for Steel Pipelines and Piping This Standard defines the minimum mandatory internal and external coating selection requirements for steel pipelines and piping (including associated fittings and appurtenances) and the mandatory performance requirements of these coatings. Excluded from this Standard are temporary coatings. This Standard does not

preclude the use of galvanized, alloy, or nonmetallic pipe where allowed by other Saudi Aramco standards.

 SAES-L-105: Piping Material Specifications

This standard covers the minimum mandatory requirements for the material specifications for piping, valves, and fittings for new piping for use in general, refining, and utility services, whose design is in accordance with either ASME B31.1, B31.3, B31.4, or B31.8 Codes.

 SAES-L-132: Material Selection for Piping Systems

This standard covers the basic materials of construction for various piping systems as governed by the fluid to be transported, and supplements the requirements of piping codes ASME B31. The materials are also subject to the further requirements and limitations regarding chemical, mechanical and dimensional properties per specifications stated in this standard.

 SAES-L-133: Corrosion Protection Requirements for Pipelines/Piping This standard specifies minimum mandatory measures to control internal and external corrosion, and environmental cracking for onshore and offshore pipelines, plant and platform piping, wellhead piping, well casings, and other pressure-retaining process equipment.

 SAES-L-136: Pipe Selection and Restrictions

This Standard supplements the ASME B31 Piping Codes, provides requirements for the selection of metallic pipe, and sets certain restrictions on the use of metallic pipe.

 SAES-L-610: Nonmetallic Piping

This Standard covers requirements and limitations for the design, installation and testing of nonmetallic piping in all areas and in all applications.

 SAES-X-400: Cathodic Protection of Buried Pipelines

This standard prescribes the minimum mandatory requirements governing the design and installation of cathodic protection systems for onshore pressurized buried metallic pipelines outside of plant facilities.

 SAEP-20: Equipment Inspection Schedule

This procedure covers requirements for inspection and testing of static equipment and external inspection of general equipment as described in the procedure. This procedure does not cover requirements for preventive maintenance programs of rotating, electrical, instrumentation, and digital equipment.

 SAEP-306: Assessment of the Remaining Strength of Corroded Pipes

This procedure provides guidelines for assessing carbon steel pipelines containing corrosion metal-loss defects. Application of the guidance will establish the remaining strength of corroded pipelines and provide the technical basis for determining the acceptability of anomalies. The assessment methods described in this procedure are intended to be used on corrosion metal-loss anomalies in pipelines that have been designed to a recognized pipeline design code, including but not limited to ASME B31.4, ASME B31.8. The procedure can be used for in-plant piping designed and constructed.

 SAEP-310: Pipeline Repair and Maintenance

This SAEP describes the procedures to be followed for the repair and maintenance of onshore pipelines, as covered by ASME B31.4 and ASME B31.8. The methods and procedures set forth herein are minimum requirements and are not a release from the responsibility for prudent action that circumstances make advisable.

 SAEP-333: Cathodic Protection Monitoring

Monitoring of the cathodic protection (CP) systems is required to ensure that the CP systems perform satisfactorily and the structures receive adequate protection. This procedure provides the instructions and establishes the responsibilities to monitor (CP) systems for onshore and offshore facilities.

 SAEP-343: Risk Based Inspection

This Saudi Aramco Engineering procedure provides key requirements for conducting risk based inspection studies for in-plant piping and equipment.

 SAEP-355: Field Metallography and Hardness Testing

This procedure provides Saudi Aramco guidelines for performing satisfactory surface replication for the purposes of in-situ metallographic examination or field metallography and hardness testing on carbon and low-alloy steel plant equipment and in-plant piping. The procedure is designed to reveal general microstructural features such as those observed in new or aged metallic components; it is also tailored to help the metallurgical engineer in the identification/categorization of surface-breaking defects and flaws of fabrication or service induced origin. The procedure is also suitable for the assessment of high temperature equipment

operating in the creep domain. Replicas produced in accordance with this procedure will be acceptable to ASTM E1351-01 (Production and Evaluation of Field

Metallographic Replicas).

 SAEP-1135: On-Stream Inspection Administration

This procedure describes the steps necessary to plan and operate a program for the on-stream inspection (OSI) monitoring of fixed equipment. OSI Monitoring in this SAEP means the systematic monitoring of piping, pipelines, vessels and tanks for general loss of wall thickness and localized metal loss.

 SAEP-1143: Radiographic Examination

This Engineering Procedure establishes the minimum requirements and describes the techniques for Radiographic Examination.

 SAEP-1144: Magnetic Particle Examination

This Engineering Procedure establishes the minimum requirements and describes the techniques for magnetic particle (MT) examinations on welds and components conducted in accordance with the requirements of the referenced codes/standards.

 SAEP-1145: Liquid Penetrant Examination

This Engineering Procedure establishes the minimum requirements and describes the techniques for performing Penetrant Testing (PT) of welds and components conducted in accordance with the requirements of the referenced Codes and Standards.

 SAEP-1146: Manual Ultrasonic Thickness Testing

This Engineering Procedure provides the general instructions for manual ultrasonic thickness testing (UTT) of base materials in plates, tubing, pipes, tanks, vessels, castings and forgings having a nominal wall thickness of 0.050 inch (1.2 mm) to 6.0 inches (150 mm) in accordance with the referenced Codes and Standards. This procedure is limited to contact testing using longitudinal wave techniques only.

 00-SAIP-75: External Visual Inspection Procedure

This Saudi Aramco Inspection Procedure provides guidelines for the external visual inspection of all existing equipment within Saudi Aramco facilities including associated structures to identify deficiencies and maintain its integrity.

 SAER-2365: Saudi Aramco Mothball Manual

This manual provides basic guidelines and recommendations for the preparation of detailed procedures for mothballing buildings, oilfield production, processing, and refining equipment. Due to long range forecasts for crude production In-Kingdom, some buildings, operating plants and pipeline systems are being considered for mothballing for a period of 3 - 10 years. Various plants and facilities have already been mothballed for 2 ½ years and may remain mothballed for an additional 5 to 10 years.

4 Definitions and Abbreviations

API American Petroleum Institute

ASME American Society of Mechanical Engineers

BS&W Basic (Bottom) Sediment and Water

CO2 Carbon Dioxide

EIS Equipment Inspection Schedule

EMAT Electro-Magnetic Acoustic Transducer

FFS Fitness for Service

GAB General Aerobic Bacteria

GOSP Gas Oil Separation Plant

H2S Hydrogen Sulfide

HIC Hydrogen Induced Cracking

ILI In-Line Inspection

mpy Mils per Year

MSG Materials Service Group

MIC Microbiologically-Influenced Corrosion

MPT Magnetic Particle Testing

NGL Natural Gas Liquids

OSI Onstream Inspection

PT Penetrant Testing

PMI Positive Material Identification

RE Radiographic Examination

RBI Risk Based Inspection

SAES Saudi Aramco Engineering Standard

SAIP Saudi Aramco Inspection Procedure

SAMSS Saudi Aramco Materials Systems Specification

SCADA Supervisory Control and Data Acquisition

SCC Stress Corrosion Cracking

SMYS Specified Minimum Yield Strength

SOHIC Stress Oriented Hydrogen Induced Cracking

SRB Sulfate Reducing Bacteria

SSC Sulfide Stress Cracking

T&I Test and Inspection

TML Thickness Measurement Location

UT Ultrasonic Testing

VE Visual Examination

5 Pipeline System Description

This section of the Pipeline Corrosion Best Practice Manual describes and categorizes the pipeline network based on its service fluid type: gas, crude, condensate, NGL, and refined products. Furthermore, each service type is sub-categorized to sour, non-sour, and sweet services. The data provided in the attached tables include the name of the pipeline, service type, service condition, coating type, diameter, length, chemical treatment, and onstream scraping frequency (onstream scraping frequency is subject to change). Also, some of the pipelines listed in subsequent tables may be mothballed. Detailed SIS data,

drawings, etc. for each pipeline can be viewed at http://eptdv2/webforms/main.aspx website.

5.1 Gas Service

The gas service can be categorized under three service types: sour, non-sour, and sweet (CO2 containing gas). Sour gas service pipelines flow from the GOSP to

the gas plants. Some GOSPs reheat the sour gas stream up to 165°F to prevent liquid from dropping out as the gas cools down the pipeline. Enough corrosion inhibitor solution (Champion KR-2237X or ATROS Dodigen 1641X) is injected into the sour gas stream to turn it into a two phase regime to properly disperse the corrosion inhibitor. The specified amount of corrosion inhibitor injected in sour gas pipelines is based on the maximum operating temperature: 0.5 gallon inhibitor/MMSCFD at <50°C and 1.0 gallon inhibitor/MMSCFD at ≥50°C. The amount of water moisture in the sour gas stream varies from GOSP to GOSP. Sweet service gas pipelines flow from the well head to the gas plants at

Hawiyah. Champion KRN-264 corrosion inhibitor is injected into sweet service pipelines at 3.0 pints/MMSCFD of gas. The amount of water moisture in sweet service pipelines varies from non-detected to 1700 PPMV @ 120 psig

depending on which wells are produced.

Non-sour gas service pipelines flow from gas plants to Saudi Aramco customers. The sour gas flowing into the gas plants goes through sweetening and

dehydration processes to produce non-sour gas. The maximum water moisture in sales gas pipelines is 7.0 lbs. of water per MMSCFD of non-sour gas as specified in A120 Dry Gas Specifications. No corrosion inhibitor is injected in non-sour gas pipelines because it is considered as non-corrosive.

Tables 5.1.1, 5.1.2 and 5.1.3 in the Appendix list the sour, non-sour, and sweet gas service pipelines, respectively.

5.2 Crude Service

The crude service can be categorized under two service types: sour and non-sour. The sour crude service pipelines flow from the GOSPs to either Abqaiq Plant in the southern area or from Abu Ali to Ras Tanura Refinery in the northern operating area. Champion AR-505 corrosion inhibitor is injected into all sour crude pipelines at a rate of 20 ppm in the maximum water volume. The maximum BS&W allowed in sour crude service is 0.2 vol% but typically is about 0.1 vol% in actual operating situation.

Non-sour stabilized crude flows from Abqaiq Plant to either Ras Tanura Refinery or Yanbu Refinery and dehydrated and desalted crude flows from Safaniyah to Ras Tanura Refinery. Biocide will have to be injected into all non-sour crude

service pipelines due to the presence of Sulfate Reducing Bacteria (SRB). The recommended treatment program consists of 30 to 120 minutes of biocide slug at 250 ppm dosage every month depending on the non-sour crude pipeline. The maximum BS&W allowed in non-sour crude pipelines is 0.2 vol%.

Tables 5.2.1 and 5.2.2 in the Appendix list the sour and non-sour crude service pipelines, respectively.

5.3 Condensate Service

Condensate flows from Tanajib Onshore Plant condensate to Berri Gas Plant. Corrosion inhibitor (Champion 2237D or ATROS 1641D) is injected in all sour condensate pipelines inside the GOSP between the gas compressors and the fin fan coolers or Champion AR-505 at Tanajib Onshore Plant for the SBCL-1 pipeline. The amount of water in sour condensate service varies from 1.0 vol% from Tanajib Onshore Plant and varies from GOSP to GOSP.

Table 5.3.1 in the Appendix lists the condensate service pipelines. 5.4 NGL Service

The NGL service is normally non-sour and comes from either Abqaiq Plant or gas plants to Ras Tanura Refinery or Yanbu NGL Plant. Champion KR-2237D or ATROS Dodigen 1641D corrosion inhibitor is injected into QA-10/QRT-10 pipeline at a dosage of 20 ppm at total NGL volume because the service in this line is considered sour. The amount of water in NGL service varies from pipeline to another.

Table 5.4.1 lists the NGL service pipelines. 5.5 Refined Product Services

Refined product services include the following:

 Diesel

 Kerosene

 Jet Fuel.

All refined products come from the crude refinery and flows to either the bulk plant or airport fueling terminal. No corrosion inhibitor is injected in refined product pipelines because they are considered non-corrosive. Although, all diesel is allowed to have a maximum 0.05 vol% BS&W except bunker diesel which can have as much as 0.10 vol% BS&W.

6 Damage Mechanisms

Corrosion is the dominant contributing factor to failures and leaks in Saudi Aramco pipelines. Pipelines are susceptible to both internal as well as external corrosion. Internal corrosion in pipelines is influenced mainly by temperature, pH, carbon dioxide (CO2) and

hydrogen sulfide (H2S) content, water chemistry, flow velocity, microbial contamination,

oil or water wetting, and composition and surface conditions of the metal. For corrosion to occur in a pipeline there must be liquid water or other electrolyte and the water must be in a form that can wet the wall of the pipe. Once water wet, the pipe will corrode at a rate determined by the properties of the water. Pipelines, however, can act as long thin

separators and collect free water in low spots in the line if the velocity of the oil is less than the entrainment velocity for water in oil. Most of the failures in pipelines are caused by localized corrosion in the form of isolated pitting.

Internal corrosion in dry gas pipelines normally occurs when upstream gas processing/ dehydrating units deliver gas that does not meet quality specifications with regards to the water content of the gas or dew point. Presence of a liquid electrolyte (water) although necessary, is not sufficient for internal corrosion. Gas transmission pipelines transmit gas with a varied composition with respect to CO2, H2S and also significantly

different operating parameters. Presence of liquid water, although provides a medium for corrosion, the actual parametric conditions and composition define the extent of corrosion if any.

6.1 External Damage Mechanisms

Pipelines are subject to external damage due to corrosion and sleeve collapse. 6.1.1 External Pipeline Corrosion

1) Coating Deficiency: This problem can be due to defective coating (either from poor coating quality, unsuitable coating or application problem) or badly damaged coating.

2) Poor or Inadequate Cathodic Protection: Shielding of CP current has been experienced in buried pipelines, particularly, those with the old tape wrap or coal tar coating system.

3) Stress Corrosion Cracking: There are two types of external SCC normally found on buried pipelines, namely: high pH (9 to 13) and near-neutral pH external SCC (5 to 7).

The high pH external SCC caused numerous failures in Saudi Aramco. There are three common factors that have been found to cause this problem in Saudi Aramco:

b) High residual stress in the pipe.

c) Elevated operating temperature (> 100°F).

This experience is consistent with NACE Standard RP0204-2004 “Standard Recommended Practice” which states the following factors that make a buried pipeline susceptible to high-pH external SCC:

a) The operating stress exceeds 60% of specified minimum yield strength (SMYS).

b) The operating temperature exceeds 38°C.

c) The segment is less than 32 km (20 miles) downstream from a compressor station.

d) The age of the pipe is greater than 10 years.

e) The coating type is other than fusion-bonded epoxy (FBE). To date, near-neutral pH external SCC has not been recorded in Saudi Aramco.

6.1.2 Sleeve Collapse

Use of welded full encirclement metal sleeves has been employed to repair damaged pipe. There have been isolated cases in which the sleeved section of the main pipe has collapsed causing the scraper to jam. It is believed that the atomic hydrogen ions (either from the high CP current or as product of internal sour corrosion process) have combined to form hydrogen molecules and accumulated in the annulus between the sleeve and the main pipe. Once the pressure exceeds the metal yield strength, the pipe consequently collapses.

6.2 Internal Damage Mechanisms

6.2.1 Hydrogen Induced Cracking (HIC) and SOHIC

HIC and SOHIC failures occur in low strength steels and the failure mode is ductile. HIC occurs in the base metal along the plate rolling direction in the absence of any stress. SOHIC is a special form of HIC that mostly occurs adjacent to the heat affected zone (HAZ) of a weld seam due to the presence of high stress (applied and/or residual) and can develop in HIC susceptible or resistant steel. The through thickness cracks in SOHIC are aligned approximately perpendicular to the applied stress. These forms of corrosion again are usually controlled by proper material selection at the design phase of a project. 01-SAMSS-016

specifies the requirements for testing and qualifying materials for

resistance to HIC and SOHIC. A full discussion of those requirements is beyond the scope of this document.

Commentary Note:

Inhibition has been successfully used to control HIC in non-HIC-resistant steel pipelines that were purchased prior to the development of HIC-resistant pipe specification. Within Saudi Aramco, this technique is especially used in wet gas pipelines experiencing HIC damage. A pipeline with HIC damages can still hold its intended operating pressure as long as no stepwise cracking and/or large HIC blisters (crown cracks) are present.

6.2.2 Sulfide Stress Cracking

Sulfide stress cracking (SSC) is a form of hydrogen embrittlement cracking, which occurs when a susceptible material is exposed to a corrosive environment containing water and H2S at a critical level of

applied or residual tensile stress. SAES-A-301 defines the requirements for SCC-resistant materials. Generally, SSC is controlled at the

materials selection and fabrication stages of a project. However, as it is a corrosion phenomenon, controlling corrosion (through effective inhibition, for example) will also control SSC.

6.2.3 Sweet Corrosion

Material deterioration of carbon and low alloy steels in contact with CO2

dissolved in water is called "sweet corrosion" that has been one of the important problems in oil and gas industry since 1940 because of both high corrosion rate and severe localized corrosion. Sweet corrosion affects the materials used in production, gathering transportation and processing facilities, resulting in typically pitting (mesa-type) or uniform metal loss. Mesa can be formed when carbon or low alloy steels are exposed to flowing wet carbon dioxide conditions at slightly elevated temperatures. An iron carbonate surface scale will often form in this type of environment which can be protective rendering a very low corrosion. However, under the surface shear forces produced by flowing media, this scale can become damaged or removed and exposure fresh metal to corrosion. This localized attack produces mesa-like features by corroding away the active regions and leaving the passive regions relatively free of corrosion resulting in the surface profile reminiscent of the mesas produced in rock by wind and water erosion. There are many parameters controlling sweet corrosion: temperature, CO2 partial

type, and material characteristics. Continuous inhibitor treatments are highly effective in mitigating sweet corrosion.

6.2.4 Sour Corrosion

Sour corrosion occurs when metals are in contact with hydrogen sulfide dissolved in water. Signs of sour corrosion include the presence of black corrosion products of iron sulfide and shallow round pits with etched bottoms. Sour systems generally have lower corrosion rates than do CO2

system in many cases at temperatures below 100°C due to the formation of a protective film of iron sulfide especially at lower temperatures and low H2S partial pressures. But still sour corrosion can shorten the life

span of carbon steel production tubing in flowing conditions. Sour corrosion occurs in several forms of hydrogen embrittlement that cause materials to fail at stress levels below their normal yield strength: sulfide stress cracking (SSC), hydrogen-induced-cracking (HIC) and stress-oriented-hydrogen-induced-cracking (SOHIC). Hydrogen sulfide is a weak acid when dissolved in water, and can act as a catalyst in the absorption of atomic hydrogen in steel, promoting SSC and HIC in high and low strength steels, respectively. SOHIC can also occur if the metal is subjected to cyclic stresses or tensile stress. Selection of materials resistant to sour corrosion is primarily means of controlling the

embrittlement mechanisms. Inhibitor treatments are oftentimes effective when general or pitting corrosion occurs in carbon or low alloy systems. 6.2.5 Microbiologically Induced Corrosion (MIC)

Microbiologically induced corrosion (MIC) can degrade the integrity, safety, and reliability of piping or vessels. Early detection of MIC problems can only be achieved by routine monitoring of the physical, chemical, and biological characteristics of piping systems. Lab analyses are conducted to detect and quantify MIC.

The most harmful and notorious bacteria known to enhance corrosion are the sulfate-reducing bacteria (SRB). SRB reduce the sulfate to the corrosive H2S, which again reacts with the steel surface to form iron

sulfides. Both SRB colony populations and sulfide corrosion mechanisms are more pronounced in stagnant or near stagnant conditions.

SRB are anaerobes that are sustained by organic nutrients. Generally, they require a complete absence of oxygen and a highly reduced environment to function efficiently. Nonetheless, they circulate in aerated waters, including those treated with chlorine and other oxidizers, until they find a "ideal" environment supporting their metabolism and

multiplication. Most common strains of SRB grow best at temperatures from 25° to 35°C. A few thermophilic strains capable of survival at more than 60°C have been reported. SRB have been implicated in the corrosion of most common construction materials including steels, 300 series stainless steels, copper nickel alloys and high nickel molybdenum alloys.

SRB are ubiquitous, meaning that they are everywhere. They remain in soils, surface water streams and waterside deposits in general. Their mere presence, however, does not mean they are causing corrosion. The key symptom that usually indicates their involvement in the corrosion process of ferrous alloys is localized corrosion pits filled with black sulfide corrosion products.

6.2.6 Black Powder (Sales Gas/Refined Products)

Black powder solids are a worldwide phenomenon in sales gas transmission pipelines. These solid compounds can delay in-line inspection, erode control valves, affect metering accuracy and

contaminate customer supply. Saudi Aramco has developed multiple initiatives to identify the black powder compound types and sources, determine formation mechanisms and identify removal processes. These initiatives include:

1) using advanced mechanical cleaning tools,

2) performing basic research in identifying the black powder compound types and formation mechanism,

3) pilot testing chemical cleaning methods,

4) planning a field test for an inertial separator filtration system, 5) revising company standards and construction practices, and 6) assessing the economic and technical feasibilities of installing

particle filters.

Saudi Aramco characterized, through laboratory analysis, the black powder in sales gas pipelines as being mainly iron hydroxides and an iron oxide mixed with a small amount of iron carbonate. Other gas operators have stated that their black powder problem is either iron sulfides or iron carbonates. Research study showed that the main cause of the black powder formation is high water content in sales gas resulting from poor water dew point control.

7 Mitigation Options

7.1 Inhibition

Corrosion inhibition is utilized to protect pipelines from wet and/or sour service fluids that is considered as a corrosive medium by decreasing the rate of attack to retard or slow down the chemical reaction. The mechanisms of inhibition covers many type such as adsorption to form a thin film, bulk precipitates that coats the metal, metal passivation, etc. Typically, corrosion inhibitors used in pipelines are filming amine type.

There are many parameters that affects the effectiveness of a corrosion inhibitor type. Thus, it is advisable to perform a lab qualification tests to determine the adequate and most effective corrosion inhibitor available in the market.

Research & Development Center has the protocol to perform the screening tests for the best corrosion inhibitor (refer to SAES-A-205, Oilfield Chemicals, for guidelines on chemical selection and testing, quality assurance, quality control and first-fill purchase of oilfield chemicals).

In pipeline operations, corrosion inhibitor is injected at the GOSPs and is done on a continuous treatment method (refer to SABP-A-015 for guidelines on detailed design, materials selection, quality assurance, operations and inspections of chemical injection systems). Corrosion inhibitor residual is a required monitoring operation to determine if the chemical is carrying all the way through the entire pipeline that is being protected.

7.2 Biocide

Biocide is injected into transmission pipelines to control bacteria that could cause Microbiologically Induced Corrosion (MIC). Water is required in the pipeline to promote and sustain bacteria growth because water carries the nutrients that bacteria needs. The two typical bacteria type found in

transmission pipelines are the Sulfate Reducing Bacteria (SRB) and/or General Aerobic Bacteria (GAB). Typically, a transmission pipeline is contaminated if either SRB and/or GAB count is higher than 100 count/mL. These bacteria may exist in the pipeline as either in planktonic or sessile state. Planktonic bacteria flows with the service fluid and sessile bacteria attaches to the pipe internal wall. The sessile form of bacteria is the type that promotes and causes internal

corrosion pit.

Biocide treatment to control bacteria in transmission pipelines may be done in a batching mode or continuous injection. A batching type biocide treatment is typically associated with a bio-shock treatment where a high biocide dosage is injected in the pipeline in a short period of time to immediately kill the bacteria. On the other hand, continuous type biocide treatment is typically associated with

a bio-stat treatment where the existing low level of bacteria count is being maintained.

7.3 Onstream Scraping

Per SAES-L-133, 7.1.3 corrosion inhibition and scraping, as a combination, are considered an acceptable corrosion control measure when a corrosive

environment is determined to exist.

The main function of onstream scraping is to remove deposits and stagnant water in pipelines that could promote internal corrosion; thus, removal of these two media will assist in mitigating internal corrosion. The onstream scraping frequency is a function of many variables such as:

 Fluid velocity

 Amount of deposits in the line

 Amount of water in the service

 Corrosiveness of the service fluid

 Result of instrument scraping run.

The onstream scraping frequency may change with time depending on changes in the variables listed above.

7.4 Coatings

Coating on buried pipelines are used to minimize pipe metal surface area exposed to potentially corrosive soil environment. It is the first line of defense against external corrosion. However, coating applied on pipelines is never perfect. Thus, CP must also be applied on pipelines to protect metal surfaces exposed by coating damage such as holidays and cracks, which could otherwise result in potential external corrosion.

The coating type used historically for newly constructed pipelines have been; coal tar mastic, tape wrap, or fusion bonded epoxy (FBE) with the coating actually applied depending on the pipeline construction date. For example, coal tar mastic was typically applied before 1961, tape wrap from 1961 to 1981, and FBE after 1981. Currently, only FBE is applied on new pipelines and can only be applied in pipe coating plants.

Coal tar mastic and tape wrap coatings have a distinction of disbonding in wet soil (subkha) environment. Cathodic protection is ineffective in protecting pipelines with these type coating that disbonds because CP shielding occurs. On the other hand, a disbonded FBE coating does not have the same problem that a

disbonded coal tar mastic or tape wrap poses because FBE coating has enough porosity to allow cathodic protection.

The type of coating used during pipeline rehabilitation is either the two-component epoxy coating with <85% solids, two two-components epoxy coating with >85% solids, or STOPAQ with rubber like mastic. Coating rehabilitation is done for coating repair or replacement on existing operating pipelines. The two-component epoxy coating with <85% solids is only allowed to be used on pipelines in dry soil condition. The two-component epoxy coating with >85% solids is allowed to be used on pipelines in dry or wet soil condition. The STOPAQ coating is also allowed to be used on pipelines in dry or wet soil condition. Coal tar or tape wrap are generally not used in coating rehabilitation. 7.5 Cathodic Protection

In general, cathodic protection is an approach where the metal surface to be protected is forced to be the cathode of an electrochemical cell. Since corrosion and material loss occurs only at the anode, this approach protects the metal. The surface to be protected is provided with a supply of electrons, either from a direct current source or from the corrosion of a more active metal. Cathodic protection is the only technique for corrosion control that can be totally effective in eliminating corrosion; unfortunately, it is not universally applicable. CP requires an anode, a cathode (structure to protect), a common electrolyte shared by both the anode and cathode (water or soil) and an electron conductor

connecting the anode and cathode. Therefore, facilities that may be protected include buried pipelines or buried tanks (to protect the external surface only) and vessels or tanks with a continuous water phase on the bottom (anodes placed inside the vessel and located in the water, to protect the internal surface only). There are two types of cathodic protection, the sacrificial (galvanic) anode and the impressed-current method. The sacrificial anode method is the simpler method, and utilizes galvanic corrosion. Sacrificial anodes are castings of a suitable alloy electrically connected by a wire or steel strap to the structure to be protected. The alloys used must be less noble than steel (the common oilfield material), such as magnesium, zinc, or aluminum. The sacrificial anodes corrode, releasing electrons to the steel. As cathodic electrochemical reactions consume electrons, the steel surface becomes a preferential cathode and is thus protected from corrosion. Magnesium and zinc are usually used in soils, and zinc can also be used in brine environments. Sacrificial anodes are most often used when current requirements are relatively low, electric power is not readily available, and when system life is short, which calls for a low capital

investment.

Impressed current method uses an external energy source to produce an electric current that is sent to the impressed current anodes, which can be composed of

graphite, high silicon cast iron, lead-silver alloy, platinum, or even scrap steel rails. Impressed-current cathodic protection is used when current requirements are high, electrolyte resistivity is high, fluctuations in current requirements will occur, and when electrical power is readily available.

Buried pipelines (and plant piping) are protected with impressed current remote and distributed anodes, while short isolated piping and buried sections of normally above grade pipelines are protected with galvanic anodes. In plant areas, a combination of remote and distributed anode systems could be more feasible, viable, practical and cost-optimum than the distributed anode system alone.

7.6 Water Dew Point Control & Black Powder Filtration

As stated in Section 6.2.6, black powder is formed due to high moisture in sales gas service primarily coming from Uthmaniyah Gas Plants and Safaniyah Onshore Plant. Thus, water dew point control in these two plants is necessary to mitigate further black powder formation in sales gas pipelines. Water dew point control may be reached by having an effective dehydration process and liquid knockout drum in these plants to make sure that the sales gas service is delivered dry into the pipelines. Monitoring of the sales gas service’s water dew point is then essential in mitigating black powder formation.

On the other hand, filtration at the customer delivery end of transmission pipelines is needed to trap black powder that is already present in sales gas pipelines. Installation of filtration systems will prevent erosion of pressure control valves and contamination of sales gas customer’s supply.

8 Corrosion Monitoring

Pipelines present a unique challenge to monitoring because of the great geographical distances they cover, their burial depth, their age, and the need to keep the product flowing without much interruption.

Pipeline systems need monitoring systems that will provide early warnings to allow for mitigation measures to be adjusted and/or initiated to control the degradation. The primary goal of monitoring is to have a leading indicator of the potential for degradation to the pipeline systems before significant damage occurs and allow intervention to stop or reduce the rate of degradation to an acceptable level.

Monitoring can include operator checks, online process monitoring, corrosion

monitoring, and anything else that could possibly assist in the detection of the selected degradation mechanisms.

There are many corrosion monitoring techniques available to investigate the corrosion performance and reliability of operating pipelines, each technique has its strengths and weaknesses. Selection of the most appropriate techniques is dependent upon the service environment as well as the type of information required. No single technique stands out to meet all the needs. The factors that influence decisions for selecting the appropriate monitoring technique are: the reliability of the technique, its adaptability to operating conditions, cost benefit, and user-friendly operation. It should also be emphasized that many operating factors will affect the performance of corrosion measuring and

monitoring techniques. The factors, which are of equal importance, include:

temperature fluctuation, pressure fluctuation, environmental variation, and deterioration of ruggedness after installation and during operation. Usually more than one technique is used so that the weaknesses of one are compensated for by the strengths of another. So, it is highly recommended to combine multiple complementary monitoring

techniques in order to provide an added level of reliability of data and serve as back up in the event of pipelines failures. One technique should always be metal loss coupon. Corrosion monitoring tools are generally used for the monitoring and optimization of the chemical treatment efficiency. The intent is not the measurement of the precise value of the corrosion rate but of its variation in time as a function of changes in the environment. Monitoring methods are given in Table 8.1 for pipeline systems. Other methods that can be used to assess corrosivity are water and other fluid analyses, nondestructive testing (NDT) and solid or scraping debris analysis.

Table 8.1 – Corrosion Monitoring Methods

Method Comments

Corrosion Coupons Coupon should be of the same/similar material as the wall. May include weld.

Linear Polarization Resistance (LPR)

Requires normally minimum 30 % aqueous phase with minimum 0.1 % salinity mass fraction.

Galvanic probes Water supply/injection/disposal systems

Electrical Resistance (ER) To be installed downstream inhibitor injection points, (but as far downstream as feasible) see Figure 4 below Erosion & sand

monitoring probes

Systems with sand or solid particles susceptible to erosion damage

Hydrogen probes For sour service conditions

The corrosion coupons/probes readings should be used to create a corrosion rate loss indicator through the trending of data. Whenever this indicator shows an upwards trend, the corrosion inhibition and process parameters of the pipeline shall be reviewed by skilled corrosion engineer.

The following means should be considered for achieving quality corrosion monitoring & control and increasing the service life of the pipeline systems:

 Selection of sampling locations for stream analysis and monitoring locations for corrosion assessment

 Specification of sampling/monitoring frequency

 Application of the established operating procedures for stream analysis and corrosion monitoring

 Management of corrosion data and analysis

 Correlation of corrosion data with the inspection and operation data. 8.1 Types of Metal Loss Coupons

Metal loss coupons in the Oil and Gas industry are normally made from cold rolled mild steel, typically AISI 1018 or 1020 steel. They can be fabricated in many different sizes and shapes to fit a variety of applications. The design of the coupon usually matches the objective of the test, simple flat sheets for general corrosion or pitting, welded coupons for local corrosion in weldments, stressed or pre-cracked test specimens for stress corrosion cracking. The most common use of corrosion coupons is the determination of general corrosion rates.

From a practical perspective, general corrosion is relatively easier to monitor and to predict using metal loss coupon; whereas due to the random nature of localized corrosion, it is more difficult to monitor. Although the information may appear to be reliable and the data may be used to trend the corrosion

behavior over time in the case of general corrosion, such information may not be relied upon to provide longer term representative behavior of localized

corrosion. This is because localized corrosion events, such as pitting, do not corrode at a constant rate. The localized corrosion activity (e.g., pitting) can occur in a recurring process of initiation, propagation and repassivation.

To certain extent, metal loss coupons can provide information regarding pitting corrosion using a variety of techniques including visual/optical inspection or scanning electron microscopy. Information about pitting that can be useful includes the determination of pit shapes (known as morphology: profile, depth and diameter) and density (pits/unit area). They can be analyzed to determine the chemical nature of corrosion films and any deposits in pits.

Coupons in general can be used to provide information about the baseline corrosion rate or provide feedback to the chemical inhibition and inspection programs. For example, if the corrosion rates are higher than the target, then an increase in inhibitor concentration may be required. Conversely, if corrosion rates are substantially lower than the target then a reduction in inhibitor concentration may be warranted.

The coupons can be designed to intrude some distance into the fluid as in the strip coupons (intrusive styles) or be flush mounted with the surface of the pipeline as shown in Figure 1. This enables the monitoring to be positioned within the middle of the process stream or immediately adjacent to the pipe wall. Figure 2 shows an example of both strip and flush mounted coupons.

Where scraping is to be performed on the line to be monitored, monitoring devices must be mounted on piping that sees normal flow but does not see the scraper, i.e., the inlet and outlet piping of the scraping facilities. (Flush mount coupons or probes may be used, but extreme care must be taken in determining the maximum acceptable insertion length.).

Figure 2 – Strip and Flush Coupons

Generally, strip coupons (Figure 3) are the most economical, provide

satisfactory corrosion rate data, and are adequate for most applications unless particular problems, such as scraping or orientation, are encountered.

Figure 3 – Typical Strip Coupon Components

Strip Coupon Holder Solid Plug Access Fitting

Strip Coupons

O-Ring

Protective Cover Pipe Plug

Primary Packing Hexagonal Nut

8.2 Corrosion and Pitting Rates Calculation

The average corrosion rate is calculated from a metal loss of corrosion coupons while the pitting rate is calculated from the pit depth measurements. Using the weight loss and exposure interval, an average corrosion rate expressed in mpy can be mathematically calculated as follows:

Pit depths may be measured with a depth gauge or micrometer caliper with sharp, pointed probes. A microscope calibrated for depth measurement may also be used. Depth of deepest pit in mils times 365 and divided by exposure time in days will give an effective calculation of pitting rate.

) ( ) / ( 365 ) ( ) ( Rate Pitting days Times year days Mils Depth Pit Maximum mpy  

Calculated corrosion and pitting rates may be interpreted as shown in the Table 2.

Table 2: Interpretation of Corrosion and Pitting Rates

Classification Average Corrosion Rate

(mpy*)

Average Pitting Rate (mpy*)

Low < 1.0 < 12

Moderate 1.0 – 4.9 12 – 24

Severe 5.0 – 10.0 25 – 96

Very Severe > 10.0 > 96

*mpy = mils per year (one thousandth of an inch per year or 0.001 inch)

8.3 Corrosion Monitoring Location, Insertion & Orientation

In general, the selection of monitoring method and location of monitoring points shall take into consideration system criticality, exposure environment

corrosivity, water content and salinity, scarping facilities and maintenance. For chemically inhibited pipeline, the primary location of the monitoring point incorporated by industries, in order to get a better representation of the corrosion on the pipeline, is to place the coupons at the inlet of the pipe, to establish a base line for corrosion, and at the end of the pipelines where it is anticipated that the least amount of corrosion chemical will be present. The monitoring point upstream of the corrosion inhibitor injection can monitor the uninhibited fluids (worst case exposure). Where the downstream monitoring location provides

information on the treated system corrosion rates (Figure 4). Chemical injection volume should be adjusted, such that an acceptable corrosion rate is obtained at the downstream end of the line. For long lines intermediate injection and monitoring may be required. In that case, the positioning of the monitoring and injection fittings would be as illustrated for Facility A.

Effective corrosion monitoring of subsea pipeline remains a challenge. The monitoring points shall be installed at the inlet and outlet of the pipeline. For buried pipelines, access fitting corrosion monitoring probes are not always practical. However, if there are above grade facilities, in addition to the

launchers and receivers, such as, isolation valves, compressor or pump stations, it may be possible to install fittings in these locations. Other monitoring and technology should also be explored when more access for more conventional monitoring tools is limited.

Figure 4 – Monitoring for Single Pipeline

For corrosion monitoring coupons/probes the nature of the insertion into the pipeline to be monitored and the orientation of access point affect the quality of the data obtained. Coupons/probes for corrosion monitoring shall be located where there is a high probability of corrosion taking place, e.g., bottom of line in stratified flow pipeline, top of line in condensing pipeline and elsewhere in the corrosive phase.

In oil pipelines, periodically stratified flow conditions can develop at low flow rates where the brine separates from the oil leading to an increase in corrosion activity at the 6 o’clock position in the pipeline. A similar situation is found for reportedly “dehydrated” gas pipeline systems that were susceptible to periodic dew point conditions where the condensate (water and hydrocarbon) will be accumulated at the bottom of the gas pipeline.

Consequently, the orientation of a coupon/probe access point is generally most favorable at the 6 o’clock position as shown in Figure 5. This assures that the coupon would be continuously wetted by any free water, which is being swept along the bottom of the pipeline where the most likely location of corrosion since produced water denser than crude oil or natural gas. However, positioning conventional coupons/probes at the 6 o’clock position reduces, or in some cases,

Facility A Facility B Chemical Injection Monitoring Location Monitoring Location

eliminates accessibility to service operations, primarily insertion and retrieval. The 6 o’clock position has the additional drawback of possible shielding due to the presence of sediment or sludge in the pipe. Devices that extend into a pipeline flow stream may impact the ability to perform periodic scraping. So, the coupons/probes shall be mounted flush with the wall for scrapable pipeline.

Figure 5 – Proper Positioning of Access Fittings

For safety reasons, a provision to install corrosion monitoring manifolds at the bottom of line position (BOL) is recommended instead of connecting the access fitting direct to the pipe from bottom. Figure 6 shows the design of the

corrosion monitoring manifolds.

Figure 6 – One of the Options for Bottom of the Line Corrosion Utilizing Flange Connections

If a strip coupon will be selected, it should protrude further into the process stream, and part of the coupons/probe sensing element might not be wetted, unless it happens to be at a low spot along the pipeline, where water can

accumulate. If bottom of the line monitoring points have not been established, it may be advantageous to survey the layout of the pipelines, such that any low spots and possible monitoring points can be identified since water tends to accumulate at low spots.

Installation of corrosion monitoring points at the precise locations for monitoring top-of-the line corrosion in pipelines, is extremely difficult. As pipeline flow rates vary, the precise location of the heavy condensation of the water and the top-of-the line corrosion will vary. Hence, corrosion monitoring points installed at a specific point on the top-of-the line might not be able to detect the most active corrosion rates. Moreover, conventional monitoring techniques such as corrosion coupons and probes did not detect the problem. Typically corrosion coupons and probes are installed in the lower portions of a line in the liquid contact areas.

It is not recommended to install monitoring across the diameter of a pipeline. Additionally, if a coupon/probe is not sufficiently stout, it is possible that flow effects could set up vibrations, which might result in a fatigue failure of the probe. The coupon/probe holder design should be evaluated for possible stress, fatigue problems and flow induced vibration. Natural frequency and wake frequency calculations should be performed for large diameter pipeline where strip coupon/probe will be installed. The purpose of these calculations is to prevent the coupon/probe from entering a resonant vibration in which fatigue failure can occur. The wake frequency should be less than 80% of the

coupon/probe’s natural frequency to guarantee no resonant harmonic vibration. This can be determined by applying the thermowell calculations in SAES-J-400 Paragraph 5.3.

8.4 Design Basis for Corrosion Monitoring Access Fitting

The most common method in the oil & gas industry involves the use of an access fitting which is welded or bolted onto the equipment. These fittings provide an opening into the fluids through which a monitoring device can be inserted. The most common fitting, known as a 2 inch access fitting, has a 2 inch opening through it and can be purchased to contain pressures as high as 6,000 psig. High pressure access fittings are designed to permit safe, relatively easy insertion and retrieval of the monitoring equipment while under full operating pressure. The fittings can be attached onto the equipment wherever there is a suitable space.

meet the requirement of SAES-A-301, if coupon is required to be installed into a sour service process.

The access fitting shall be placed on the pipelines so that it will have the best chance to monitor the corrosion mechanism in question. However, once that location is determined the access fitting shall be conveniently located for

extraction and replacement of the monitoring instrumentation. When more than one access fitting multiple coupons/probes is installed in one location, the fittings must be separated by a minimum three (3) feet in order to avoid flow interference. In order to operate the retriever, a minimum of twelve (12) inches clearance is required around the access fitting body and a minimum of eight (8) feet is required above or to the side of the pipe for top and side mounted fittings, respectively as shown in Figure 7. Care should be taken to insure that adjacent equipment does not encroach on the exclusion zone around a fitting. Although, temperature, pressure and other process monitoring devices may have their tap point the required 12 inches from a fitting, valve handles, tubing, and cabling must also remain outside the 12 inch exclusion area so as not to adversely impact retrieval operations.

The typical design of the corrosion monitoring point is shown in the Library Drawing DA-950035 “2-Inch High Pressure Access System Chemical Injection and Corrosion Monitoring”.

8.5 Safety Issues Related to Coupon Retrieval Operations

Safety precautions must be established throughout the coupon retrieval operations at the field including, but not limited to the following:

 Safe operation requires a minimum of two (2) trained operators

 Do not use the retrieval equipment unless you have been trained in its safe operation

 Make sure you have complied with all plant safety requirements and environmental regulations

 Identify the type media, its pressure and temperature

 Insure you have all the required safety equipment for the given media, i.e., hard hat, safety glasses, protective clothing, safety gloves, breathing apparatus, etc.

 Any actions which could vary system pressure such as surges caused by opening and closing of valves and chokes should be delayed until completion of retrieval operations

 Insure you have enough clearance for safe operation

 Note wind direction prior to starting operations involving hazardous products.

8.6 Inspection Data

It is essential that the pipeline corrosion engineer combines corrosion

monitoring data with inspection data to determine if the monitoring technique is appropriate since the coupon/probe corrosion rates are only representative of the pipeline corrosion rates.

During downtime or while the pipeline is on operation, inspection can be conducted using non-destructive methods which commonly include:

 Visual Testing (VT)

 Radiographic Examination (RE)

 Ultrasonic Testing (UT)

 Magnetic Particle Testing (MT)

 Eddy Current Testing (ET).

Non-destructive testing (NDT) can be considered as one of the inspection tools to monitor corrosion. All of the above mentioned methods provide only a snapshot of information on the status of the integrity of the pipeline and they are often the best for assessment of general attack. However, some of these

techniques are implemented to measure wall thickness and estimate metal loss from the outside of a pipe, but excavation, cleaning, and other physical

constraints allow for only a small area to be inspected at a time.

In-line inspection (ILI) is also considered one of the methods of monitoring pipelines for internal wall thinning and corrosion damage. Scrapers, equipped with ultrasonic or similar sensors, are inserted in the pipeline and propelled by the liquid petroleum for long distances. However, this requires the pipeline flow to be interrupted during the inspection.

8.7 Sampling

An understanding of the process fluid chemistry is also essential in any

corrosion rate determination. To ascertain this information, samples should be obtained at predetermined points from each pipeline and, analyses conducted to determine the composition of all phases present.

The sampling frequency must take into account the potential corrosivity and flow pattern changes due to shifts in production practices or well declines. For this reason, a yearly sampling program is not suitable. Chemical sample analysis of the fluids and gases going into the pipeline should be made on regular basis. Any debris from the scraping runs should be also sampled and analyzed.

Determination of the corrosion inhibitor residual is one of the monitoring tools to insure effective inhibitor coverage. An effective corrosion inhibitor residual means that there is a sufficient concentration of inhibitor available to form a protective coating on the interior walls of a pipe. Sampling shall be taken in appropriate locations such as the end of the pipeline before the entrance to the plant or process facilities. It is important to avoid choosing inappropriate locations such as stagnant flow locations or locations such as slug catcher bottom since water is accumulated some time at the bottom and the readings may be misleading. Water samples from the slug catcher give indication of the presence of inhibitor throughout the system but does not define adequacy of protection in different parts through which the fluids flow.

Low water content of pipeline makes it nearly impossible to get a sample of water to perform an analysis or corrosion monitoring in a pipeline unless some collection mechanism is installed on the pipeline. Water traps and side stream

monitors are about the only methods of obtaining a water sample from a “dry” pipeline system.

Samples shall be sent to the lab for corrosion inhibitor residual analysis using the specific vendor analysis procedure. Trending of the data is an important tool to monitor any change in the corrosion inhibitor residuals. Samples shall be analyzed on a monthly basis or as recommended by the area corrosion engineer. For Microbiologically Influenced Corrosion (MIC), monitoring requires either that the pipeline be regularly opened for sampling or that accommodations be made in the system design to allow for regular collection of surface samples or on-line tracking of attached microorganisms during operation. BOL traps fitted with corrosion coupons or bio-probes can be used to obtain sessile population enumeration data.

8.8 Corrosion Data Interpretation and Correlation

With all the data being collected from the pipelines, it is important to turn that data into meaningful results. Any inspection or corrosion monitoring data can provide useful information. However, the real benefit is gained when these programs are combined and correlated with each other. Corrosion monitoring provides an early indication of problems while inspection measures the actual extent of any damage done. Moreover, availability of both corrosion monitoring and operational data history will enhance the level of confidence in the asset integrity and be the basis for optimization of scraping, chemical injection and inspection frequency.

The corrosion engineers along with inspection personnel should review the collected data, analyzes the monitoring, aids in technical support and reviews injected chemical. The data gathered from corrosion monitoring system, and analyzed by the pipeline corrosion engineer, shall be also shared with operations personnel and chemical company personnel to continue to refine the corrosion mitigation efforts. The chemical vendors play an important role to ensure ongoing performance testing, check that inhibitor rates are set correctly and help troubleshoot increases in corrosion.

8.9 On-Line/Real Time Corrosion Monitoring

Saudi Aramco has integrated the online recommended Advanced Electrical Resistance (AER) system in new oil and gas facilities since 2000. These online corrosion monitoring probes afford corrosion engineers with a proactive role by continuously assessing the fluid corrosivity online and in conjunction with process data. As a result, the potential for the occurrence of catastrophic corrosion problems is significantly reduced and changes in corrosion activity

can be rapidly assessed and mitigated. With this level of control in place, it is possible to enhance equipment reliability, availability and operational efficiency. The AER corrosion monitoring technology has been developed to substantially increase the speed of response over conventional ER monitoring techniques. The advanced electrical resistance measurement is based fundamentally on metal loss and is, therefore, directly comparable to ER probe and coupon data. It does not depend on the empirically determined electrochemical constants of LPR

measurements, or the complex and variable analysis of electrochemical noise techniques. Moreover, it doesn’t require an electrically conductive solution for accurate measurements. The new AER technology was subjected to a two-year extensive in-house laboratory test program and field trials in selected facilities. The active element of the advanced electrical resistance probe is measured to an 18 bit resolution, or 262,144 Probe Life Units (PLU). This compares to the 10 bit resolution (1000 divisions) of conventional ER system. The AER

measurement system is much less sensitive to fluctuations in temperature. The AER probes are available in two element forms, flush and cylindrical. Flush probes are suited for pipelines, where pigging may occur, and for bottom off-line monitoring in oil and gas, or multiphase flows where the corrosive water phase exists. Cylindrical probes with their all-welded construction are suited for more chemically aggressive environments. The AER instruments include high resolution transmitters, data loggers, 24 VDC power supply to power the transmitters, and special recording and retrieval software permits easy data acquisition and display. Multi-channel systems employ Amulet software, permitting interfacing of the AER with any process variables and parameters.

Figure 8 – On-line Corrosion Monitoring

8.10 On-Line Monitoring Field Configuration

A single multi-drop cable is used to connect the transmitters with the 24 VDC and the RS-485 communication bus. For remote communications, a transmitter is hardwired using copper-core cable to an RS-485 to RS-422 converter and then to an RS-422 to fiber optic converter connected to the fiber optic OTN system. A fiber optic communications system has been installed throughout the Facility area and is used to link the field AER probe/transmitter combinations to the central corrosion server in the control room. At a remote location, a solar power system is installed to provide the 24 VDC power along with a fiber optic cable running to the fiber optic backbone (ring) to provide the communications link. The corrosion server is supplied by the manufacturer with commercially available corrosion management software incorporating a SQL™ server database. Each transmitter probe combination has a unique address, and the corrosion management software has been programmed to take probe readings along with process parameters at specific intervals. This permits plotting of probe data with process parameters such as temperature, pressure, and flow rate. Remote seats are also provided with the software to allow users to access the corrosion server remotely via an Ethernet system. Figure 7 is a simplified schematic overview of the field integrated communications system.

The AER can be integrated in all pipelines. Due to the high corrosivity level predicted on carbon steel material in some fields, a corrosion inhibition program is implemented. Flush strip type AER probes are installed at both top of line (TOL) and bottom of line (BOL) positions to monitor the efficiency of the treatment program. At TOL positions, the probe element sits at the 12 o’clock position while at the BOL a special trap is used and the AER probe projects into the body of a Tee. These corrosion monitoring stations are located on the inlet and outlet laterals of transmission pipelines running between the main manifolds and the gas plant. In some cases, these probes can be installed at the middle of the pipelines in the aboveground sections.

AER sensor system can be used to assess and quantify the effectiveness of a chemical treatment program in gas and oil pipelines. The implemented system can function in sour or sweet environments. Moreover, the integrated AER system offers additional benefits:

 Indicator of equipment efficiency

 Quantify the effectiveness of the implemented inhibition program

 Remote data access with alarming capability

 Continuous monitoring

 Ability to network unlimited probes

 Data trending