SABP-A-019.pdf

Best Practice 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 2 3 4 5 6 7 8 9 10 11

Scope and Purpose........................................ 3 Conflicts and Deviations................................. 3 References..................................................... 3 Definitions and Abbreviations......................... 8 Pipeline System Description........................... 9 Damage Mechanisms................................... 12 Mitigation Options......................................... 17 Corrosion Monitoring.................................... 20 Validation..................................................... 36 Record Keeping........................................... 40 Contributor Authors...................................... 40

Previous Issue: 1 April 2008 Next Planned Update: TBD Page 1 of 41 Primary contact: Khamis, Jamal Najam on 966-3-8747975 Copyright©Saudi Aramco 2010. All rights reserved.

Document Responsibility: Materials and Corrosion Control Issue Date: 8 March 2010 Next Planned Update: TBD

SABP-A-019 Pipeline Corrosion Control

Detailed Table of Contents 1 2 3 4 5

6

7

8

9

10 11

Scope and Purpose Conflicts and Deviations References Definitions and Abbreviations Pipeline System Description 5.1 Gas Service 5.2 Crude Service 5.3 Condensate Service 5.4 NGL Service 5.5 Refined Product Service Damage Mechanisms 6.1 External Damage Mechanisms 6.1.1 External Pipeline Corrosion 6.1.2 Sleeve Collapse 6.2 Internal Damage Mechanisms 6.2.1 Hydrogen Induced Cracking (HIC) and SOHIC 6.2.2 Sulfide Stress Cracking 6.2.3 Sweet corrosion 6.2.4 Sour Corrosion 6.2.5 Microbiological Induced Corrosion 6.2.6 Black Powder (Sales Gas & Refined Products) Mitigation Options 7.1 Inhibition 7.2 Biocide Treatment 7.3 On-stream Scraping 7.4 Coatings 7.5 Cathodic Protection 7.6 Water Dew Point Control & Black Powder Filtration Corrosion Monitoring 8.1 Types of Metal Loss Coupons 8.2 Corrosion and Pitting Rates Calculation 8.3 Corrosion Monitoring Location, Insertion & Orientation 8.4 Design Basis for Corrosion Monitoring Access Fitting 8.5 Safety Issues Related to Coupon Retrieval Operations 8.6 Inspection Data 8.7 Sampling 8.8 Corrosion Data Interpretation and Correlation 8.9 On-Line/Real Time Corrosion Monitoring 8.10 On-Line Monitoring Field Configuration 8.11 CP Monitoring Validation 9.1 Hydrotest 9.2 In-line Inspection 9.3 On-stream Inspection 9.4 Test & Inspection (T&I) 9.5 Risk Based Inspection (RBI) Record Keeping Contributing Authors

3 3 3 8 9 10 10 11 11 11 12 12 12 13 13 13 14 14 15 15 16 17 17 17 18 18 19 20 20 20 25 25 28 30 30 31 32 32 34 36 36 37 37 37 39 39 40 40

Page 2 of 2


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 rerating 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"

Page 3 of 3





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 Page 4 of 4



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 pressureretaining 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.

Page 5 of 5





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 inplant 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.

Page 6 of 6





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.

Page 7 of 7





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

H2 S

Hydrogen Sulfide

HIC

Hydrogen Induced Cracking

ILI

In-Line Inspection

MFL

Magnetic Flux Leakage Page 8 of 8


5

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


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,

Page 9 of 9



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 nonsour. 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 Page 10 of 10



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. Table 5.5.1 in the Appendix lists the refined product pipelines.

Page 11 of 11


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: a)

Damaged coating, primarily, with tape wrap and coal tar. Page 12 of 12



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 Page 13 of 13



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 HICresistant 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 pressure, pH flow rate, flow character, water chemistry, hydrocarbon

Page 14 of 14



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 stressoriented-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 Page 15 of 15



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.

Page 16 of 16


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 Page 17 of 17



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

Page 18 of 18



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 twocomponent epoxy coating with <85% solids, 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 twocomponent 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 Page 19 of 19



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.

Page 20 of 20



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 Corrosion Coupons Linear Polarization Resistance (LPR) Galvanic probes

Comments Coupon should be of the same/similar material as the wall. May include weld. Requires normally minimum 30 % aqueous phase with minimum 0.1 % salinity mass fraction.

Erosion & sand monitoring probes

Water supply/injection/disposal systems To be installed downstream inhibitor injection points, (but as far downstream as feasible) see Figure 4 below Systems with sand or solid particles susceptible to erosion damage

Hydrogen probes

For sour service conditions

Electrical Resistance (ER)

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:

Page 21 of 21





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.

Page 22 of 22



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 1 – Common Coupon Design for Pipeline Application

Page 23 of 23



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. Protective Cover

Pipe Plug Hexagonal Nut

Solid Plug O-Ring Access Fitting Strip Coupon Holder

Primary Packing

Strip Coupons

Figure 3 – Typical Strip Coupon Components

Page 24 of 24


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.

Pitting Rate (mpy) 

Maximum Pit Depth ( Mils )  365 (days / year ) Times (days )

Calculated corrosion and pitting rates may be interpreted as shown in the Table 2. Table 2: Interpretation of Corrosion and Pitting Rates Average Corrosion Rate (mpy*)

Average Pitting Rate (mpy*)

< 1.0

< 12

Moderate

1.0 – 4.9

12 – 24

Severe

5.0 – 10.0

25 – 96

> 10.0

> 96

Classification Low

Very Severe

*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 Page 25 of 25



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. Chemical Injection

Facility A

Facility B Monitoring Location

Monitoring Location

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, Page 26 of 26



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

Page 27 of 27



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. The monitoring components, other than the access fitting body, shall be made out of 316L stainless steel or better and shall be suitable for sour service and Page 28 of 28



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.

Figure 7 – Corrosion Monitoring Access fitting Spacing Requirement

Page 29 of 29



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:

8.6



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.

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) Penetrant Testing (PT)

Page 30 of 30





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

Page 31 of 31



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

Page 32 of 32



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.

Page 33 of 33



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.

Page 34 of 34



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

Figure 9 – Schematic Representation of the Field Integrated AER Layout Page 35 of 35



Figure 10 – Advanced Electrical Resistance (AER) Probes 8.11

CP Monitoring Pipe-to-soil potential is measured annually on pipelines to determine their level of protection against external corrosion. The minimum level of CP for pipelines in Saudi Aramco is -1100 and -1000 millivolts (versus a copper-copper sulfate electrode) for dry and other soil type, respectively. A copper-copper sulfate electrode and a voltmeter are used to connect to a CP test station for the pipe-tosoil readings. Test stations on pipelines are approximate one kilometer apart but other pipeline structures such as valves, above ground flanges, etc., are also used as connection points to measure pipe-to-soil potentials.

9

Validation Validation of pipelines are meant to test their integrity to hold the required pressure. There are two periods when pipelines are validated or revalidated: 1) during new pipeline commissioning (initial validation) and 2) pipelines that are in operation (revalidation). Hydrotesting is normally used to validate new pipelines and In Line Inspection (ILI) is normally used to revalidate existing and scrapable pipelines already in operation. Pipelines Department is no longer using hydrotesting for revalidation of existing pipelines with scraping facilities. Unscrapable pipelines are initially validated with hydrotest and revalidated with On Stream Inspection (OSI) method using manual ultrasonic (UT) inspection. However, pipelines with known stress corrosion cracking (SCC) damage or severe hydrogen induced cracking (HIC) are revalidated either with hydrotest or with EMAT (Electro-Magnetic Acoustic Transducer) ILI tool in scrapable

Page 36 of 36



lines. Pipelines revalidation frequency typically is every three to five year except for the OSI program which is done annually. 9.1

Hydrotest Hydrotesting is a destructive/non-destructive validation/revalidation method. It will only show the location of critical flaws in the pipeline when they rupture or leak but will not show the locations of subcritical size flaws or indicate whether or not they are present. Hydrotesting will test the entire pipeline facility, which include flanges, fittings, etc and show whether it can hold the required pressure. If a pipeline passes a hydrotest without failure, testing is non-destructive. Pipelines are typically hydrotested at 90% of Specified Minimum Yield Strength (SMYS).

9.2

In Line Inspection Pipelines are typically revalidated using ILI method unless the pipeline has known cracking damages (especially stress corrosion cracking) which then requires hydrotest or EMAT tool inspection. ILI can actually pinpoint the location of the anomalies for further inspection and fitness for service (FFS) repair evaluation. ILI tools perform inspection qualification and not pressure revalidation. Typically, Magnetic Flux Leakage (MFL) tools are used to find external and internal corrosion. UT tools are used to find external and internal corrosion, as well as mid wall defects such as HIC. EMAT tool can find external and internal corrosion, HIC, coating disbondment, and SCC damage. Given the size and depth of flaws found through ILI, an FFS calculation can now be done to determine if the flaws require repair or not. The FFS calculation may utilize one of three popular methods such as the B31G, RSTRENG, or LPC equations. In-line inspection 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.

9.3

On Stream Inspection (OSI) On Stream Inspection (OSI) provides ultrasonic thickness (UT) wall thickness measurements for general and localized metal loss. The steps necessary to plan and operate an OSI program are described on SAEP-1135.

Page 37 of 37



On stream inspection method, using manual UT, can determine internal corrosion morphology, depth and length. Corrosion rate can be determined by comparison between two or more readings. Once these information are gathered, FFS analysis and/or corrosion mitigation technique can now be recommended. The OSI program may used to re-validate existing unscrapable lines per SAEP-20. Thickness measurements locations (TMLs) are assigned to locations, which are anticipated to best represent areas where deterioration would be most active. OSI monitoring levels (number of TMLs) depends on the corrosion class as per the following table: Corrosion Service

Quantity of TMLs (Recommended Minimum)

LOW CORROSIVE

Greater of 12 or 4% of High Loss Sites

MILD CORROSIVE


CORROSIVE


PERFORMANCE ALERT

Complete Area Scan of all Alert Zones

For effective monitoring the TML types should be selected according to the anticipated damage mechanism types. Single TMLs are assigned locations where corrosion and/or erosion are most likely to occur. Grid Points Multiple TMLs are used for monitoring localized flaw and aggressive wall thinning attack. Scanning points are normally employed for pitting corrosion where isolated wall thinning is identified. TML locations are assigned to the following locations: 

Flow change points: High loss is most likely to occur where high fluid velocity, turbulence, and impingement conditions are imposed by fittings and equipment such as elbows, u-bends, tees, reducers, nipples and branches



Water stagnation points: High loss sites are also most likely to occur where water collects and/or rivulets, entrapped pockets, water-oil interface and water-air tidal zones form. Areas where these conditions prevail are in deadlegs, drains, piping sag or low points, level gauges, scale or sludge deposits, and where there are significant drops in gas pressure or flow (50% or greater)



Near corrosion monitoring points.

OSI is includes visual external inspection, corrosion probe monitoring, temperature surveillance and leak detection. Pipeline systems should be visually inspected for corrosion, cracks, mechanical damages, leaks and insulation damages every two years in accordance with 00-SAIP-75. Page 38 of 38


9.4


Test and Inspection (T&I) Test and inspection (T&Is) is thorough internal and external inspection performed during plant or equipment downtime. Equipment shall have Equipment Inspection Schedules (EISs) that show inspection interval and procedures. The requirements for preparing original and revision of Equipment Inspection Schedules (EISs) for T&Is are outlined on SAEP-20. The initial T&I and subsequent (T&Is) intervals shall be based on equipment and service conditions or operating experience. Following factors determine (I-T&Is) and subsequent (T&Is) intervals: 

Remaining Life: Based on the existing corrosion allowance divided by OSI generated corrosion rates, or historical corrosion rates. T&I Intervals Based on Remaining Life interval shall be at no more than one half the calculated remaining equipment life or ten years whichever is less as per API STD 510.



Service Criteria: Table I shall be employed to establish the I-T&I and subsequent intervals: Table I – Maximum T&I Intervals versus Corrosion Service Corrosion Service

Class 0 (2) Performance Alert 1 Corrosive Service 2 Mild Corrosive Service 3 Low Corrosive Service

9.5

Criteria 380 µm/a (15 mpy) And up or Special Prob. 150 to 350 µm/a (6 to 14 mpy) 75 to 125 µm/a (3 to 5 mpy) Loss than 75 µm/a (3 mpy)

Initial T&I Interval (Months)

Subsequent

Standard Equipment

New Technology Equipment

T&I Intervals (Months)

24

12

30

24

12

60

24

12 – 24

120

24

12 - 24

120

Risk Based Inspection (RBI) Risk Based Inspection (RBI) is a systematic tool that helps plants to make informed business decisions regarding inspection and maintenance spending. RBI evaluates the risk and prioritizes the equipment for inspection activities. It defines risk as a measure of loss in terms of both likelihood of a vent and severity of the consequence. RBI also used to aid the assessment results of inspection, testing and corrosion monitoring programs. It can results in inspection effort being increasing, decreasing or being directed to higher risk area. RBI studies are performed in

Page 39 of 39



accordance with SAEP-343 and API RP 580. 10

Record Keeping Effective corrosion management requires meticulous record keeping. Fortunately, in today’s world, electronic records are relatively easily collected, stored and analyzed. The following information for each pipeline should be recorded, analyzed and filed by the Pipeline Corrosion Engineer:      

On-line Corrosion Monitoring data (resistance probes or linear polarization) Weight loss coupons corrosion rates (gives only average rate) NDT Testing results (OSI) T&I inspection results and repairs Maintenance conducted and reason for work order Laboratory analyses of the process stream     

11

Corrosion product analysis (recovered during T&I or with liquid samples) Inhibitor residual analysis Iron counts Bacteria counts Brine analyses

  

Changes in pressure, temperature and/or production rate Failure record keeping and visual inspection (after failures have occurred) Failure analyses



CP Monitoring System.

Contributor Authors Name J. N. Al-Khamis C. I. Cruz M. M. Al-Qarni A. S. Al-Omari J. P. Perez F. M. Al-Abbas B. W. Burgess

1 April 2008 8 March 2010

Affiliation Consulting Services Department Consulting Services Department Consulting Services Department Consulting Services Department Pipelines Department Inspection Department NA Producing Engineering Department

Revision Summary New Saudi Aramco Best Practice. Editorial revision to add the Appendix.

Page 40 of 40



Appendix I – List of Sour and Non-Sour Crude Service Pipelines Click here to view the Appendix  http://standards/docs/SupPages/XLS/SABP-A-019A.xls

Page 41 of 41

Pipeline

Service

Condition

Year Built

24GA1800 26GA1801 A5GT-1 A5GT-2 A5GT-3 A6GT-1 A6GT-2 A6GT-3 AA-1 AA-2 AA-3 AB-1 AB-2 ABGG-104 ABGG-203 ABGG-402 ABGG-503 ABGG-601 ABGG-701 ABGG-703 ABGG-704 ABGP-1 ABSRT-1 AD-1 AD-2 AD-3 ADT-2A ADT-2B ADT-2BL ADT-3A ADT-4A ADT-4B

SOUR GAS SOUR GAS ARABXLTE-SR ARABXLTE-SR SOUR GAS SOUR GAS SOUR GAS SOUR GAS ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SW ARABLITE-SW SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SWEETGAS SWEETGAS SOUR GAS SOUR GAS ARABMED ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR

sour sour sour sour sour sour sour sour sour sour sour non-sour non-sour sour sour sour sour sour non-sour non-sour sour sour non-sour non-sour non-sour non-sour sour sour sour sour sour sour

1975 1975 1972 1972 1972 1981 1981 1981 1952 1968 1972 1945 1947 1981 1981 1981 1981 1981 1981 1985 1981 1995 2004 1946 1947 1978 1951 1974 1974 1972 1952 1958

ADT-6A

ARABLITE-SR

sour

1972

Coating Type

PLICOFLEX PLICOFLEX PLICOFLEX FBE FBE FBE P2 SERVIWRAP PLICOFLEX/FBE PLICOFLEX

PLICOFLEX/FBE FBE FBE FBE FBE FBE FBE FBE FBE FBE P2 SERVIWRAP P2 SERVIWRAP PLICOFLEX PLICOFLEX PLICOFLEX P2 SERVIWRAP P2 SERVIWRAP A/G FBE/ SERVIWRAP

1 of 11

24 26 12 12 16 24 16 16 20 24 24 12 12 40 30 16 16 42 20 20 12 24 30 12 14 14 26 14 14 26 16 22

8.535 4.671 4.8 4.8 4.8 2 2.3 2.3 45.4 45.4 45 64.57 42.15 17.6 10.76 2.054 2.362 53.798 2.545 0.3 1.615 136.587 23.589 61.8 61.8 63.5 10.22 10.71 3.35 13.44 7.28 13.564

1 gal/mmscfd 1 gal/mmscfd 20 ppm in total vol. 20 ppm in total vol. 1 gal/mmscfd 0.5 gal/mmscfd 0.5 gal/mmscfd 0.5 gal/mmscfd 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. biocide treatment biocide treatment 0.5 gal/mmscfd 0.5 gal/mmscfd 0.5 gal/mmscfd 0.5 gal/mmscfd 0.5 gal/mmscfd none required none required 0.5 gal/mmscfd 0.5 gal/mmscfd biocide treatment biocide treatment biocide treatment biocide treatment 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol.

Onstream Scraping Frequency 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 1x per year 1x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 4x per year 4x per year 4x per year 4x per year 6x per year 6x per year

14

13.5

20 ppm in total vol.

12x per year

Dia. (inch) Length (km)

Corrosion Inhibition

Pipeline ADT-6B AGT-1 AH-1 AHT-1 ARTCL-1 AT-1 AT-2 AT-2L AT-5 AT-6 ATFG-1 ATNGL-1 AWT-1 AWTG-1 AY-1 AY-148L AY-1L BB-1 BCL-1 BFG-1 BGT-1 BJBET-1 BJBFG-1 BJBFG-2 BJNGL-1 BKTG-1 BRT-1 BRT-2 BRT-3 BT-1 BT-2 BT-3 BTETH-1 BTG-1

Service

Condition

Year Built

Coating Type

ARABLITE-SR SWEETGAS Product - DIESEL ARABLITE-SR KHUFFCONDENSATE ARABXLTE-SR ARABXLTE-SW ARABXLTE-SW ARABXLTE-SR ARABXLTE-SR SWEETGAS SOUR GAS Product - BUNKER SWEETGAS SWEETGAS ARABLITE-SW ARABLITE-SW ARABXLTE-SR SWEETGAS SWEETGAS SOUR GAS ETHANE SWEETGAS SWEETGAS NGL C3+ SOUR GAS NGL C3+ ARABXLTE-SR NGL C3+ ARABXLTE-SR ARABXLTE-SR ARABXLTE-SR ETHANE SWEETGAS

sour non-sour non-sour sour sour sour non-sour non-sour sour sour non-sour sour non-sour non-sour non-sour non-sour non-sour sour non-sour non-sour sour non-sour non-sour non-sour non-sour sour non-sour sour non-sour sour sour sour non-sour non-sour

1984 1954 1998 1962 2002 1948 1951 1955 1979 1982 2003 1982 1985 1978 1981 1981 1987 1972 1975 1975 1975 1982 1982 1992 1980 2007 1971 1973 1976 1950 1960 1969 1980 1982

FBE P2 SERVIWRAP FBE PLICOFLEX FBE P2 P2 PLICOFLEX PLICOFLEX FBE FBE FBE FBE FBE FBE FBE FBE PLICOFLEX

FBE FBE FBE TAPE WRAP FBE PLYMCO PLICOFLEX PLICOFLEX P2 SERVIWRAP P2 SERVIWRAP P2 SERVIWRAP FBE

2 of 11

Dia. (inch) Length (km) 20 20 8 12 24 22 12 16 20 24 12 24 16 24 48 48 56 30 8 10 32 30 36 36 24 30 16 40 16 16 16 16 26 30

13.5 28.56 63.9 5.2 117.804 10.4 10.289 10.48 1.548 2.428 5.131 4.366 0.6 0.3 1193.04 22.348 1203.14 78.9 39.376 39.326 42.443 6.871 6.81 6.201 7.356 68.827 58.305 59.787 59.728 6 6.01 6.01 1.199 1.78

Corrosion Inhibition 20 ppm in total vol. none required none required 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. biocide treatment biocide treatment 20 ppm in total vol. 20 ppm in total vol. none required 0.5 gal/mmscfd none required none required none required biocide treatment biocide treatment 20 ppm in total vol. none required none required 0.5 gal/mmscfd none required none required none required none required 0.5 gal/mmscfd none required 20 ppm in total vol. none required 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. none required none required

Onstream Scraping Frequency 12x per year 1x per year 1x per year 4x per year 1x per year 3x per year 3x per year 3x per year 3x per year 3x per year 1x per year 3x per year 1x per year 1x per year 1x per year 3x per year 3x per year 3x per year 1x per year 1x per year 12x per year 1x per year 1x per year 1x per year 1x per year 12x per year 1x per year 3x per year 1x per year 3x per year 3x per year 3x per year 1x per year 1x per year

Pipeline BTG-2 DEPCO-1 DM2FG-1 DR-1 DR-1 (EXT) DRT-3 DRT-4 EWG-1 EWRB-1 EWRGD-1 EWRGD-2 EWRGD1P7 EWRGD1RR FG-10 FG-4 FZT-1 GART-16 GART-22 GART-24 GART-24L GART-40L GHTG-1 GHTG-2 GHTLF-1 HAJFTL-1 HAJFTL-2 HAKHCL-1 HAKHTL-1 HAKHTL-2 HASHNGL-1 HAT-2 HAT-3 HAT-4 HDAKHCL1

Service

Condition

Year Built

SWEETGAS SWEETGAS SWEETGAS Product - GASOLINE Product - Misc Product - GASOLINE Product - GASOLINE SWEETGAS ARABLITE-SW SWEETGAS SWEETGAS SWEETGAS SWEETGAS ETHANE ETHANE ARABLITE-SR SWEETGAS SWEETGAS SWEETGAS SWEETGAS SWEETGAS SWEETGAS SWEETGAS ARABLITE-SW KHUFF SWEET GAS KHUFF SWEET GAS KHUFFCONDENSATE KHUFF SOUR GAS KHUFF SOUR GAS NGL C2+ ARABLITE-SR ARABLITE-SR ARABLITE-SR KHUFFCONDENSATE

non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour sweet sweet sour sour sour non-sour sour sour sour sour

1995 1977 2007 1998 2007 1979 1979 1989 2004 1999 2000 1999 2001 1982 1982 1961 1974 1974 1974 1974 1976 1980 2002 1978 1999 1999 1999 1999 1999 2007 1975 1976 1996 2001

Coating Type

PLICOFLEX FBE FBE

FBE FBE FBE FBE FBE FBE

PLICOFLEX FBE PLICOFLEX PLICOFLEX

FBE RAYCLAD RAYCLAD FBE RAYCLAD RAYCLAD FBE PLICOFLEX PLICOFLEX RAYCLAD FBE

3 of 11


1.47 19.148 17.5 395.427 5.5 36.8 36.8 1573 144.984 152.714 15.094 5.618 7.812 6.45 24.673 24.48 4.2 19.02 72.786 18.46 32.3 4.461 4.545 9.807 18.41 18.41 20.3 18.41 18.41 115.204 1.25 2.853 0.985 229

Corrosion Inhibition none required none required none required none required none required none required none required none required biocide treatment none required none required none required none required none required none required 20 ppm in total vol. none required none required none required none required none required none required none required biocide treatment 3 pints/mmscfd 3 pints/mmscfd 20 ppm in total vol. 0.5 gal/mmscfd 0.5 gal/mmscfd none required 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol.


Pipeline HDHDG-1 HDKHTL-1 HDKHTL-2 HDKHTL-3 HDKHTL-4 HDKHTL-5 HDT-1A HDT-2 HDUG-1 HDWGT-1 HEW3-1 HSGG-1 HUG-1 IYECLOOP JAPL JBTETH-2 JBTETH-3 JET-A-1 JJBUT-1 JJBUT-2 JJHEX-1 JJMULT-1 JJPRP-1 JP-4 JQJ-1 JRTNG-1 JRTNG-2 JRTNGL-1 JT-1 JTG-1 JTG-2 KAD-1 KBG-1 KJ-1

Service

Condition

Year Built

Coating Type

KHUFF SWEET GAS KHUFF SOUR GAS KHUFF SOUR GAS KHUFF SOUR GAS KHUFF SOUR GAS KHUFF SOUR GAS ARABLITE-SR ARABLITE-SR SWEETGAS SWEETGAS ARABSUPL SOUR GAS SWEETGAS ARABLITE-SW Product - GASOLINE ETHANE ETHANE Product - JETA Product - BUTANE Product - BUTANE Product - HEXANE Product - LPG Propane - PROPANE Product - JP4 SPIKECONDENSATE Product - NAPTHA Product - NAPTHA NGL C3+ ARABLITE-SW SWEETGAS SWEETGAS ARABLITE-SR SWEETGAS ARABLITE-SW

sweet sour sour sour sour sour sour sour non-sour non-sour non-sour sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour sour non-sour non-sour non-sour non-sour non-sour non-sour sour non-sour non-sour

2002 2000 2000 2000 2002 2002 1995 2002 2003 2002 1993 1999 1999 1992 1998 2002 2007 1982 1988 1993 1999 1992 2000 1950 1980 1980 2000 1980 2004 1978 2006 1968 2007 2007

FBE FBE&RAYCLAD FBE&RAYCLAD FBE&RAYCLAD FBE FBE FBE FBE FBE FBE FBE FBE FBE FBE FBE FBE FBE FBE FBE

FBE FBE PLICOFLEX FBE FBE

4 of 11


12.2 44.156 44.115 44.068 12.2 12.2 0.88 2 140.451 2.87 331.444 50.067 55.931 24 239.309 56.55 55.824 8 67.7 67.7 68 67.7 68 8 3.219 17.301 17.197 7.356 4.9 7.097 6.186 137.4 46.446 105.526

Corrosion Inhibition 3 pints/mmscfd 0.5 gal/mmscfd 0.5 gal/mmscfd 0.5 gal/mmscfd 0.5 gal/mmscfd 0.5 gal/mmscfd 20 ppm in total vol. 20 ppm in total vol. none required none required biocide treatment 0.5 gal/mmscfd none required biocide treatment none required none required none required none required none required none required none required none required none required none required none required none required none required none required biocide treatment none required none required 20 ppm in total vol. none required biocide treatment


Pipeline

Service

Condition

Year Built

Coating Type

NGL C2+ ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABHEVY ARABMED ARABHEVY ARABHEVY ARABHEVY ARABLITE-SR ARABMED

non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour sour non-sour

2007 1968 1979 NON 1980 1957 1960 1965 1966 1978 1981 1960

FBE PLICOFLEX PLICOFLEX

L-10

Product - NAPTHA

non-sour

1982

L-11

Propane - PROPANE

non-sour

1982

L-12 L-2

Product - HEAVY FO Product - FUEL OIL

non-sour non-sour

1982 1982

L-20

Product - Misc

non-sour

1982

L-21 L-3

Product - DIESEL Product - FUEL OIL

non-sour non-sour

1982 1982

L-6

Product - Misc

non-sour

1982

L-9

ARABLITE-SW

non-sour

1982

NQRT-1

Product - DIESEL

non-sour

1969

P-10

Product - BUTANE

non-sour

1982

P-12

Propane - PROPANE

non-sour

1982

KJNGL-1 KK-1 KK-2 KR-1 KR-2 KRT-1 KRT-2 KRT-3 KRT-4 KRTJ-1 KST-4 KT-1

P2 SERVIWRAP P2 SERVIWRAP PLICOFLEX PLICOFLEX FBE PLICOFLEX COAL TAR EXPOXY COAL TAR EXPOXY COAL TAR EXPOXY FBE COAL TAR EXPOXY COAL TAR EXPOXY COAL TAR EXPOXY COAL TAR EXPOXY COAL TAR EXPOXY COAL TAR EXPOXY COAL TAR EXPOXY

5 of 11

none required biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment 20 ppm in total vol. biocide treatment

Onstream Scraping Frequency 1x per year 3x per year 3x per year 3x per year 6x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year

2.3

none required

1x per year

4

2.3

none required

1x per year

10 14

2.3 14.8

none required none required

1x per year 1x per year

14

8.6

none required

1x per year

12 18

0.13 13.85



10

13.45

none required

1x per year

24

0.435

biocide treatment

3x per year

14

17.989

none required

1x per year

8

6.3

none required

1x per year

6

6.3

none required

1x per year

Dia. (inch) Length (km) 24 12 24 12 26 22 30 40 48 40 10 24

107.25 30.189 30.203 140 141.31 101.28 107.107 103.868 84.695 5.789 22.576 1.975

3


Pipeline

Service

Condition

Year Built

P-13

Product - PENTANE

non-sour

1982

P-15

Propane - PROPANE

non-sour

1982

P-2

ETHANE

non-sour

1982

P-40

Product - NAPTHA

non-sour

1982

P-5

Product - BUTANE

non-sour

1982

P-6

Product - BUTANE

non-sour

1982

NGL C3+ ARABXLTE-SW ARABLITE-SW ARABXLTE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW SOUR GAS ETHANE ARABLITE-SW ARABLITE-SW ARABLITE-SW SOUR GAS NGL C3+ ARABXLTE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SR CONDENSATE

non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour sour non-sour non-sour non-sour non-sour sour non-sour non-sour non-sour non-sour non-sour sour sour

1974 1951 1956 1966 1969 1973 1973 1974 2004 2004 1974 1975 1977 2004 1976 1968 1971 1972 1974 2004 2004

QA-10 QA-2 QA-3 QA-4 QA-5 QA-6 QA-7 QA-8 QBGG-1 QETH-1 QJ-1 QJ-2 QJ-3 QQGG-1 QRT-10 QRT-6 QRT-7 QRT-8 QRT-9 QT-2 QTCL-1

Coating Type COAL TAR EXPOXY COAL TAR EXPOXY COAL TAR EXPOXY COAL TAR EXPOXY COAL TAR EXPOXY COAL TAR EXPOXY POLYKEN/ PLICOFLEX P2 SERVIWRAP P2 SERVIWRAP PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX FBE FBE PLICOFLEX PLICOFLEX POLYKEN FBE PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX FBE FBE

6 of 11



Onstream Scraping Frequency

4

6.3

none required

1x per year

6

1.7

none required

1x per year

24

4.554

none required

1x per year

8

1.1

none required

1x per year

10

1.7

none required

1x per year

10

1.7

none required

1x per year

24 20 30 40 40 40 46 46 32 10 46 46 48 28 30 40 40 40 42 28 8

68.69 59.978 70.196 68.52 68.61 69.42 70.132 50.17 45.604 0.752 39.187 39.187 39.26 25.444 31.773 27.97 27.27 29.865 29.726 25.429 0.415

none required biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment 0.5 gal/mmscfd none required biocide treatment biocide treatment biocide treatment 0.5 gal/mmscfd none required biocide treatment biocide treatment biocide treatment biocide treatment 30 ppm in total vol. 20 ppm in total vol.

3x per year 3x per year 6x per year 6x per year 6x per year 6x per year 6x per year 3x per year 1x per year 6x per year 6x per year 6x per year 3x per year 3x per year 6x per year 6x per year 6x per year 6x per year weekly 1x per year

Pipeline QTCL-2 QTG-1 RQ-1 RS1-1 RTDB-1 RTDB-2 RTJ-1 RTJ-2 RTJBD-1 RTJPRP-1 RTQB-1 S1R-1 SBCL-1 SBKCTL-1 SHBAB-1 SHCL-101 SHCL-102 SHCL-104 SHCL-201 SHCL-206 SHCL-217 SHCL-401 SHFG-1 SHFG-3 SHGG-101 SHGG-102 SHGG-104 SHGG-112 SHGG-122 SHGG-132 SHGG-201 SHGG-206 SHGG-207 SHGG-301

Service

Condition

Year Built

Coating Type

CONDENSATE SWEETGAS Product - GASOLINE Product - GASOLINE Product - KEROSENE Product - Misc Product - BUNKER ARABXLTE-SW Product - BUTANE Propane - PROPANE Product - LPG Product - GASOLINE CONDENSATE CONDENSATE ARABXLTE-SR CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE REGENGAS SWEETGAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS

sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour sour sour sour sour sour sour sour sour sour sour non-sour non-sour sour sour sour sour sour sour sour sour sour sour

2004 2004 1999 1998 2000

FBE FBE

1973 1973 1980 2004 1998 1983 2007 1998 1978 1978 1978 1978 1978 1978 1978 1982 1982 1978 1978 1978 1984 1985 1985 1978 1978 1978 1978

FBE FBE FBE PLICOFLEX PLICOFLEX FBE FBE FBE FBE FBE FBE FBE PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX FBE FBE FBE PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX

7 of 11


0.391 0.769 355.525 18.143 106.298 106 17.184 20.46 17.197 20 47.522 18.29 153.67 10.072 638.282 9.55 5.6 4.18 24.42 23.9 20.09 19.95 6.4 11 9.556 5.86 4.15 5.79 3.66 3.64 24.49 11.03 33.7 12.75

Corrosion Inhibition 20 ppm in total vol. none required none required none required none required none required none required biocide treatment none required none required none required none required 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. none required none required 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd


Pipeline

Service

Condition

Year Built

Coating Type

SHGG-304 SHGG-305 SHGG-401 SHGT-1 SHGT-2 SHGT-2L SHJNGL-1 SHJNGL-2 SHKHCL-1 SHKHCL-2 SHKHTL-1 SHKHTL-2 SHKHTL-3 SHPFG-1 SHT-1A

SOUR GAS SOUR GAS SOUR GAS REGENGAS REGENGAS SWEETGAS NGL C2+ NGL C2+ KHUFFCONDENSATE KHUFFCONDENSATE KHUFF SOUR GAS KHUFF SOUR GAS KHUFF SOUR GAS SWEETGAS ARABLITE-SR

sour sour sour non-sour non-sour non-sour non-sour non-sour sour sour sour sour sour non-sour sour

1978 1978 1978 1980 1979

FBE FBE PLICOFLEX A/G A/G FBE FBE FBE A/G

SHT-1B SHT-3 SHT-4 SHT-5 SHT-6 SHTG-1 SHY-1 SJ-1 SJGT-1 SJKGT-1 SK-1 SK-2 SK-3 SK-4 SPAB-1 SPAD-1 SPAY-11 SPAY-110

ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR REGENGAS NGL C2+ ARABMED SAFANGAS SAFANGAS ARABHEVY ARABMED ARABHEVY ARABHEVY ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW

sour sour sour sour sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour

1967 1984 1972 1981 1984 1979 1979 1977 1983 2007 1957 1960 1965 1966 1985 1990 1986 1986

1984 2006 1985 1995 1984 1986 1999 1980 1954

FBE FBE PLICOFLEX A/G PLICOFLEX/ SERVIWRAP PLICOFLEX FBE FBE PLICOFLEX PLICOFLEX POLYKEN FBE FBE P2 SERVIWRAP P2 SERVIWRAP P/P P/P

8 of 11

24 24 30 24 8 12 30 30 6 8 16 16 20 24 16

1.64 1.64 23.1 18.8 10.9 10.9 155.66 177.135 3.16 5.5 11 11 5.84 2.4 2.75

1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd none required none required none required none required none required 20 ppm in total vol. 20 ppm in total vol. 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd none required 20 ppm in total vol.

Onstream Scraping Frequency 3x per year 3x per year 3x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 3x per year 3x per year 3x per year 1x per year 3x per year

30 24 24 24 20 36 26 46 40 30 22 30 36 48 0 0 48 48

2.75 6.15 2.4 3.3 0.15 5 1162.771 197.4 198.41 10.146 106.2 106.42 106.289 106.28 0 0 0 0

20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. none required none required biocide treatment none required none required biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment

3x per year 3x per year 3x per year 3x per year 3x per year 1x per year 1x per year 3x per year 1x per year 1x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year



Pipeline SPAY-111 SPAY-12 SPAY-13 SPAY-14 SPAY-15 SPAY-16 SPAY-17 SPAY-18 SPAY-19 SPAY-1L1 SPAY-1L10 SPAY-1L11 SPAY-1L2 SPAY-1L3 SPAY-1L4 SPAY-1L5 SPAY-1L6 SPAY-1L7 SPAY-1L8 SPAY-1L9 SPDR-1 SPHEW3-1A SPHEW3-1B SPKR-2 SRG-1 TFJB-1 TIHDG-1 TNBCL-1 TNBGT-1 TNKGT-1 TNT-1 U3FRG-1 UA-1 UA-1L

Service

Condition

Year Built

ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW ARABLITE-SW Product - Misc ARABSUPL ARABSUPL ARABLITE-SW SWEETGAS ARABLITE-SW KHUFF SWEET GAS CONDENSATE SOUR GAS SOUR GAS ARABMED REGENGAS ARABLITE-SR ARABLITE-SR

non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour sweet sour sour sour sour non-sour sour sour

1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1986 1994 1994 1985 1999 1984 2002 1984 1985 2007 1985 1974 1952 1964

Coating Type

PLICOFLEX RAYCLAD FBE FBE FBE FBE P2 SERVIWRAP PLICOFLEX

9 of 11


0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 245.175 24.355 43.605 13.534 145.25 10.222 13.581 1 178.25 36.2

Corrosion Inhibition biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment biocide treatment none required biocide treatment biocide treatment biocide treatment none required biocide treatment 3 pints/mmscfd 20 ppm in total vol. 0.5 gal/mmscfd 0.5 gal/mmscfd 20 ppm in total vol. none required 20 ppm in total vol. 20 ppm in total vol.


Pipeline UA-2 UA-2L UA-3 UA-4 UA-6 UBTG-1 UBTG-2 UBTG-3 UBTG-4 UCL-106 UCL-201 UCL-301 UCL-311 UCL-501 UCL-511 UCL-601 UGG-101 UGG-102 UGG-106 UGG-106L UGG-116 UGG-126 UGG-201 UGG-301 UGG-302 UGG-305 UGG-501 UGG-504 UGG-511 UGG-601 UHWGT-1 UHWGT-2 UJNGL-1 USGG-506

Service

Condition

Year Built

Coating Type

ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR SWEETGAS SWEETGAS SWEETGAS SWEETGAS CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS SOUR GAS REGENGAS REGENGAS SWEETGAS SOUR GAS

sour sour sour sour sour non-sour non-sour non-sour non-sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour non-sour non-sour non-sour sour

1966 1973 1971 1973 1973 1978 1997 1999 2001 1978 1978 1978 1978 1978 1978 1978 1978 1978 1978 1993 2002 2002 1978 1978 1978 1978 1978 1978 1990 1978 1992 1992 1978 1984

PLICOFLEX PLICOFLEX PLICOFLEX

PLICOFLEX FBE FBE FBE PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX FBE FBE FBE PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX FBE PLICOFLEX FBE PLICOFLEX PLICOFLEX

10 of 11


76.14 6.9 49 216.193 176.593 247.306 56 249.01 56.466 46.2 11.19 7.5 23.26 7.5 23.94 4.86 39.74 15.016 46.167 100.296 124.548 1.977 11.07 18.3 13 11.92 14.79 16.39 0.6 4.8 29.66 16.96 205.11 23.43

Corrosion Inhibition 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. none required none required none required none required 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd 1 gal/mmscfd none required none required none required 1 gal/mmscfd


Pipeline

Service

Condition

Year Built

Coating Type

SOUR GAS ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR REGENGAS

sour sour sour sour sour sour sour sour sour sour sour sour sour non-sour

1985 1953 1973 1973 1973 1974 1958 1973 1975 1973 1973 1973 1973 1981

UTFG-2

REGENGAS

non-sour

1981

UTFG-3 UTFG-4

REGENGAS REGENGAS

non-sour non-sour

1983 1982

UTFG-5

SWEETGAS

non-sour

1983

UTFG-6

SWEETGAS

non-sour

1983

FBE P2 PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX P2 SERVIWRAP PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX/ SERVIWRAP PLICOFLEX/ SERVIWRAP PLICOFLEX PLICOFLEX/ SERVIWRAP PLICOFLEX/ SERVIWRAP

USGG-516 UT-1 UT-10 UT-11 UT-12 UT-13 UT-2A UT-2B UT-4 UT-6 UT-7 UT-8 UT-9 UTFG-1

11 of 11

1 gal/mmscfd 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. none required

Onstream Scraping Frequency 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 1x per year

14

none required

1x per year

10 26

9.92 1.6



12

25.646

none required

1x per year

8

12.98

none required

1x per year

Dia. (inch) Length (km) 30 16 24 24 24 24 16 24 24 30 24 24 24 36

30.9 6.9 7.5 4.85 5.64 7.38 6.45 6.38 3 16.04 5.94 4.85 1.46 5.06

12


Table 5.1.1 - Sour Gas Pipelines Coating Type

Condition

Year Built

24GA1800

SOUR GAS

sour

1975

24

8.535

1 gal/mmscfd

3x per year

26GA1801

SOUR GAS

sour

1975

26

4.671

1 gal/mmscfd

3x per year

A5GT-3

SOUR GAS

sour

1972

PLICOFLEX

16

4.8

1 gal/mmscfd

3x per year

A6GT-1

SOUR GAS

sour

1981

FBE

24

2

0.5 gal/mmscfd

3x per year

A6GT-2

SOUR GAS

sour

1981

FBE

16

2.3

0.5 gal/mmscfd

3x per year

A6GT-3

SOUR GAS

sour

1981

16

2.3

0.5 gal/mmscfd

3x per year

ABGG-104

SOUR GAS

sour

1981

FBE PLICOFLEX /FBE

40

17.6

0.5 gal/mmscfd

3x per year

ABGG-203

SOUR GAS

sour

1981

FBE

30

10.76

0.5 gal/mmscfd

3x per year

ABGG-402

SOUR GAS

sour

1981

FBE

16

2.054

0.5 gal/mmscfd

3x per year

ABGG-503

SOUR GAS

sour

1981

FBE

16

2.362

0.5 gal/mmscfd

3x per year

ABGG-601

SOUR GAS

sour

1981

FBE

42

53.798 0.5 gal/mmscfd

3x per year

ABGG-704

SOUR GAS

sour

1981

FBE

12

1.615

0.5 gal/mmscfd

3x per year

ABGP-1

SOUR GAS

sour

1995

FBE

24


3x per year

ATNGL-1

SOUR GAS

sour

1982

FBE

24

4.366

BGT-1

SOUR GAS

sour

1975

32


12x per year

BKTG-1

SOUR GAS

sour

2007

FBE

30


12x per year

HAKHTL-1

KHUFF SOUR GAS

sour

1999

RAYCLAD

24

18.41

0.5 gal/mmscfd

3x per year

HAKHTL-2

KHUFF SOUR GAS

sour

1999

RAYCLAD

24

18.41

0.5 gal/mmscfd

3x per year

HDKHTL-1

KHUFF SOUR GAS

sour

2000

FBE&RAYC LAD

30


3x per year

HDKHTL-2

KHUFF SOUR GAS

sour

2000

FBE&RAYC LAD

30


3x per year

HDKHTL-3

KHUFF SOUR GAS

sour

2000

FBE&RAYC LAD

30


3x per year

HDKHTL-4

KHUFF SOUR GAS

sour

2002

FBE

24

1 of 3

Dia. (inch)

Length Corrosion Inhibition (km)


Service

Pipeline

12.2

0.5 gal/mmscfd

0.5 gal/mmscfd

3x per year

3x per year

Table 5.1.1 - Sour Gas Pipelines Service

Condition

Year Built

Coating Type

Dia. (inch)

HDKHTL-5

KHUFF SOUR GAS

sour

2002

FBE

24

HSGG-1

SOUR GAS

sour

1999

FBE

QBGG-1

SOUR GAS

sour

2004

QQGG-1

SOUR GAS

sour

SHGG-101

SOUR GAS

SHGG-102

Pipeline


12.2


0.5 gal/mmscfd

3x per year

30


3x per year

FBE

32


3x per year

2004

FBE

28


3x per year

sour

1978

PLICOFLEX

18

9.556

1 gal/mmscfd

3x per year

SOUR GAS

sour

1978

PLICOFLEX

28

5.86

1 gal/mmscfd

3x per year

SHGG-104

SOUR GAS

sour

1978

PLICOFLEX

26

4.15

1 gal/mmscfd

3x per year

SHGG-112

SOUR GAS

sour

1984

FBE

24

5.79

1 gal/mmscfd

3x per year

SHGG-122

SOUR GAS

sour

1985

FBE

28

3.66

1 gal/mmscfd

3x per year

SHGG-132

SOUR GAS

sour

1985

FBE

16

3.64

1 gal/mmscfd

3x per year

SHGG-201

SOUR GAS

sour

1978

PLICOFLEX

12

24.49

1 gal/mmscfd

3x per year

SHGG-206

SOUR GAS

sour

1978

PLICOFLEX

24

11.03

1 gal/mmscfd

3x per year

SHGG-207

SOUR GAS

sour

1978

PLICOFLEX

36

33.7

1 gal/mmscfd

3x per year

SHGG-301

SOUR GAS

sour

1978

PLICOFLEX

48

12.75

1 gal/mmscfd

3x per year

SHGG-304

SOUR GAS

sour

1978

FBE

24

1.64

1 gal/mmscfd

3x per year

SHGG-305

SOUR GAS

sour

1978

FBE

24

1.64

1 gal/mmscfd

3x per year

SHGG-401

SOUR GAS

sour

1978

PLICOFLEX

30

23.1

1 gal/mmscfd

3x per year

SHKHTL-1

KHUFF SOUR GAS

sour

1984

FBE

16

11

1 gal/mmscfd

3x per year

SHKHTL-2

KHUFF SOUR GAS

sour

1986

FBE

16

11

1 gal/mmscfd

3x per year

SHKHTL-3

KHUFF SOUR GAS

sour

1999

20

5.84

1 gal/mmscfd

3x per year

TNBGT-1

SOUR GAS

sour

1985

FBE

30


3x per year

TNKGT-1

SOUR GAS

sour

2007

FBE

20


3x per year

UGG-101

SOUR GAS

sour

1978

PLICOFLEX

16

39.74

1 gal/mmscfd

3x per year

UGG-102

SOUR GAS

sour

1978

PLICOFLEX

20

15.016 1 gal/mmscfd

3x per year

2 of 3

Table 5.1.1 - Sour Gas Pipelines Condition

Year Built

Coating Type

Dia. (inch)

UGG-106

SOUR GAS

sour

1978

PLICOFLEX

32

46.167 1 gal/mmscfd

3x per year

UGG-106L

SOUR GAS

sour

1993

FBE

32

100.296 1 gal/mmscfd

3x per year

UGG-116

SOUR GAS

sour

2002

FBE

24

124.548 1 gal/mmscfd

3x per year

UGG-126

SOUR GAS

sour

2002

FBE

20

1.977

1 gal/mmscfd

3x per year

UGG-201

SOUR GAS

sour

1978

PLICOFLEX

24

11.07

1 gal/mmscfd

3x per year

UGG-301

SOUR GAS

sour

1978

PLICOFLEX

32

18.3

1 gal/mmscfd

3x per year

UGG-302

SOUR GAS

sour

1978

PLICOFLEX

28

13

1 gal/mmscfd

24x per year

UGG-305

SOUR GAS

sour

1978

PLICOFLEX

38

11.92

1 gal/mmscfd

3x per year

UGG-501

SOUR GAS

sour

1978

PLICOFLEX

26

14.79

1 gal/mmscfd

3x per year

UGG-504

SOUR GAS

sour

1978

PLICOFLEX

36

16.39

1 gal/mmscfd

3x per year

UGG-511

SOUR GAS

sour

1990

FBE

16

0.6

1 gal/mmscfd

3x per year

UGG-601

SOUR GAS

sour

1978

PLICOFLEX

24

4.8

1 gal/mmscfd

3x per year

USGG-506

SOUR GAS

sour

1984

PLICOFLEX

42

23.43

1 gal/mmscfd

3x per year

USGG-516

SOUR GAS

sour

1985

FBE

30

30.9

1 gal/mmscfd

3x per year

UTKHTL-1

KHUFF SOUR GAS

sour

1984

FBE

16

7.69

1 gal/mmscfd

3x per year

UTKHTL-2

KHUFF SOUR GAS

sour

1984

FBE

16

7.69

1 gal/mmscfd

3x per year

UTKHTL-3

KHUFF SOUR GAS

sour

1999

20

7.69

1 gal/mmscfd

3x per year

UTKHTL-4

KHUFF SOUR GAS

sour

1999

20

7.69

1 gal/mmscfd

3x per year

3 of 3



Service

Pipeline

Table 5.1.2 - Non-Sour Gas Pipelines

Pipeline

Service

Condition

Year Built

Coating Type

Dia. (inch)

Length (km)



ABGG-701

SWEETGAS non-sour

1981

FBE

20

2.545

none required

1x per year

ABGG-703

SWEETGAS non-sour

1985

FBE

20

0.3

none required

1x per year

AGT-1

SWEETGAS non-sour

1954

P2 SERVIWRAP

20

28.56

none required

1x per year

ATFG-1

SWEETGAS non-sour

2003

FBE

12

5.131

none required

1x per year

AWTG-1

SWEETGAS non-sour

1978

FBE

24

0.3

none required

1x per year

AY-1

SWEETGAS non-sour

1981

FBE

48

1193.04 none required

1x per year

BCL-1

SWEETGAS non-sour

1975

8


1x per year

BFG-1 BJBET-1

SWEETGAS non-sour ETHANE non-sour

1975 1982

FBE

10 30

39.326 none required 6.871 none required


BJBFG-1

SWEETGAS non-sour

1982

FBE

36

6.81

none required

1x per year

BJBFG-2 BTETH-1


1992 1980

FBE

36 26

6.201 1.199



BTG-1

SWEETGAS non-sour

1982

FBE

30

1.78

none required

1x per year

BTG-2

SWEETGAS non-sour

1995

36

1.47

none required

1x per year

DEPCO-1

SWEETGAS non-sour

1977

PLICOFLEX

20


1x per year

DM2FG-1

SWEETGAS non-sour

2007

FBE

16

17.5

none required

1x per year

EWG-1

SWEETGAS non-sour

1989

FBE

48

1573

none required

1x per year

EWRGD-1

SWEETGAS non-sour

1999

FBE

48


1x per year

EWRGD-2

SWEETGAS non-sour

2000

FBE

36


1x per year

EWRGD1P7

SWEETGAS non-sour

1999

FBE

36

5.618

none required

1x per year

EWRGD1RR SWEETGAS non-sour FG-10 ETHANE non-sour FG-4 ETHANE non-sour

2001 1982 1982

FBE

16 30 36

7.812 none required 6.45 none required 24.673 none required

1x per year 1x per year 1x per year

GART-16

SWEETGAS non-sour

1974

GART-22

SWEETGAS non-sour

1974

GART-24

SWEETGAS non-sour

1974

16

4.2

none required

1x per year

FBE

22

19.02

none required

1x per year

PLICOFLEX

24


1x per year

1 of 3


Pipeline

Service

Condition


Year Built

Coating Type

Dia. (inch)

Length (km)

PLICOFLEX

24

18.46

none required

1x per year


GART-24L

SWEETGAS non-sour

1974

GART-40L

SWEETGAS non-sour

1976

40

32.3

none required

1x per year

GHTG-1

SWEETGAS non-sour

1980

26

4.461

none required

1x per year

GHTG-2

SWEETGAS non-sour

2002

FBE

40

4.545

none required

1x per year

HDUG-1

SWEETGAS non-sour

2003

FBE

48


1x per year

HDWGT-1

SWEETGAS non-sour

2002

FBE

12

HUG-1 JBTETH-2 JBTETH-3

SWEETGAS non-sour ETHANE non-sour ETHANE non-sour

1999 2002 2007

FBE FBE FBE

JTG-1

SWEETGAS non-sour

1978

JTG-2

SWEETGAS non-sour

KBG-1

SWEETGAS non-sour

2.87

none required

1x per year

56 40 38



FBE

26

7.097

none required

1x per year

2006

FBE

16

6.186

none required

1x per year

2007

40


1x per year

24 10

4.554 0.752



non-sour non-sour

1982 2004

FBE COAL TAR EXPOXY FBE

QTG-1

SWEETGAS non-sour

2004

FBE

10

0.769

none required

1x per year

SHFG-1

REGENGAS non-sour

1982

PLICOFLEX

24

6.4

none required

1x per year

SHFG-3

SWEETGAS non-sour

1982

PLICOFLEX

6

11

none required

1x per year

SHGT-1

REGENGAS non-sour

1980

A/G

24

18.8

none required

1x per year

SHGT-2

REGENGAS non-sour

1979

A/G

8

10.9

none required

1x per year

SHGT-2L

SWEETGAS non-sour

FBE

12

10.9

none required

1x per year

SHPFG-1

SWEETGAS non-sour

1980

PLICOFLEX

24

2.4

none required

1x per year

SHTG-1 SJGT-1 SJKGT-1

REGENGAS non-sour SAFANGAS non-sour SAFANGAS non-sour

1979 1983 2007

PLICOFLEX FBE FBE

36 40 30

5 none required 198.41 none required 10.146 none required


SRG-1

SWEETGAS non-sour

1999

56


1x per year

U3FRG-1

REGENGAS non-sour

1974

24

UBTG-1

SWEETGAS non-sour

1978

P-2 QETH-1

ETHANE ETHANE

PLICOFLEX

2 of 3

36

1

none required

1x per year


1x per year


Pipeline

Service

Condition

Year Built

Coating Type

Dia. (inch)

Length (km) 56

UBTG-2

SWEETGAS non-sour

1997

FBE

40

UBTG-3

SWEETGAS non-sour

1999

FBE

UBTG-4

SWEETGAS non-sour

2001

UHWGT-1

REGENGAS non-sour

1992

UHWGT-2

REGENGAS non-sour

1992

UJNGL-1

SWEETGAS non-sour

1978

UTFG-1

REGENGAS non-sour

1981

UTFG-2

REGENGAS non-sour

1981

UTFG-3

REGENGAS non-sour

1983

UTFG-4

REGENGAS non-sour

1982

UTFG-5

SWEETGAS non-sour

1983

UTFG-6 YRBETH-1


1983 2007



none required

1x per year

56


1x per year

FBE

48


1x per year

FBE

14

29.66

none required

1x per year

24

16.96

none required

1x per year

PLICOFLEX

28


1x per year

PLICOFLEX PLICOFLEX/ SERVIWRAP PLICOFLEX/ SERVIWRAP

36

5.06

none required

1x per year

12

14

none required

1x per year

10

9.92

none required

1x per year

PLICOFLEX PLICOFLEX/ SERVIWRAP PLICOFLEX/ SERVIWRAP FBE

26

1.6

none required

1x per year

12


1x per year

8 18



3 of 3

Table 5.1.3 - Sweet (CO2 containing) Gas Pipelines

Pipeline

HAJFTL-1 HAJFTL-2 HDHDG-1 TIHDG-1 WQHDG-1

Service KHUFF SWEET GAS KHUFF SWEET GAS KHUFF SWEET GAS KHUFF SWEET GAS KHUFF SWEET GAS

Year Built

Coating Type

Dia. (inch)

sweet

1999

RAYCLAD

24

18.41

3 pints/mmscfd

12x per year

sweet

1999

RAYCLAD

24

18.41

3 pints/mmscfd

3x per year

sweet

2002

FBE

28

12.2

3 pints/mmscfd

1x per year

sweet

2002

RAYCLAD

20

43.605 3 pints/mmscfd

1x per year

sweet

2002

FBE

30

49.832 3 pints/mmscfd

1x per year

1 of 1



Condition

Table 5.2.1 - Sour Crude Pipelines

Service

Condition

Year Built

A5GT-1 A5GT-2 AA-1 AA-2 AA-3 ADT-2A ADT-2B ADT-2BL ADT-3A ADT-4A ADT-4B

ARABXLTE-SR ARABXLTE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR

sour sour sour sour sour sour sour sour sour sour sour

1972 1972 1952 1968 1972 1951 1974 1974 1972 1952 1958

ADT-6A ADT-6B AHT-1 AT-1 AT-5 AT-6 BB-1 BRT-2 BT-1 BT-2 BT-3 FZT-1 HAT-2 HAT-3 HAT-4 HDT-1A HDT-2 KAD-1 KST-4 QT-2 SHBAB-1 SHT-1A

ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABXLTE-SR ARABXLTE-SR ARABXLTE-SR ARABXLTE-SR ARABXLTE-SR ARABXLTE-SR ARABXLTE-SR ARABXLTE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABXLTE-SR ARABLITE-SR

sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour

1972 1984 1962 1948 1979 1982 1972 1973 1950 1960 1969 1961 1975 1976 1996 1995 2002 1968 1981 2004 1998 1954

SHT-1B SHT-3 SHT-4 SHT-5 SHT-6 TNT-1 UA-1 UA-1L UA-2 UA-2L UA-3 UA-4 UA-6 UT-1

ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABMED ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR

sour sour sour sour sour sour sour sour sour sour sour sour sour sour

1967 1984 1972 1981 1984 1985 1952 1964 1966 1973 1971 1973 1973 1953

Pipeline

Coating Type PLICOFLEX PLICOFLEX P2 SERVIWRAP PLICOFLEX/FBE PLICOFLEX PLICOFLEX PLICOFLEX P2 SERVIWRAP P2 SERVIWRAP A/G FBE/ SERVIWRAP FBE PLICOFLEX P2 PLICOFLEX FBE PLICOFLEX PLICOFLEX P2 SERVIWRAP P2 SERVIWRAP P2 SERVIWRAP PLICOFLEX PLICOFLEX PLICOFLEX RAYCLAD FBE PLICOFLEX FBE FBE FBE A/G PLICOFLEX/ SERVIWRAP PLICOFLEX FBE FBE FBE P2 SERVIWRAP PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX

P2

1 of 2

12 12 20 24 24 26 14 14 26 16 22

4.8 4.8 45.4 45.4 45 10.22 10.71 3.35 13.44 7.28 13.564

20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol.

Onstream Scraping Frequency 3x per year 3x per year 3x per year 3x per year 3x per year 4x per year 4x per year 4x per year 4x per year 6x per year 6x per year

14 20 12 22 20 24 30 40 16 16 16 12 24 24 24 20 24 16 10 28 46 16

13.5 13.5 5.2 10.4 1.548 2.428 78.9 59.787 6 6.01 6.01 24.48 1.25 2.853 0.985 0.88 2 137.4 22.576 25.429 638.282 2.75

20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 30 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol.

12x per year 12x per year 4x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year weekly 3x per year 3x per year

30 24 24 24 20 40 30 24 34 30 30 36 46 16

2.75 6.15 2.4 3.3 0.15 13.581 178.25 36.2 76.14 6.9 49 216.193 176.593 6.9

20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol.

3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year

Dia. Length (inch) (km)


Table 5.2.1 - Sour Crude Pipelines

Pipeline UT-10 UT-11 UT-12 UT-13 UT-2A UT-2B UT-4 UT-6 UT-7 UT-8 UT-9

Service

Condition

Year Built

Coating Type

ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR ARABLITE-SR

sour sour sour sour sour sour sour sour sour sour sour

1973 1973 1973 1974 1958 1973 1975 1973 1973 1973 1973

PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX P2 SERVIWRAP PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX

2 of 2

Dia. Length (inch) (km) 24 24 24 24 16 24 24 30 24 24 24

7.5 4.85 5.64 7.38 6.45 6.38 3 16.04 5.94 4.85 1.46

Corrosion Inhibition 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol.

Onstream Scraping Frequency 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year 3x per year

Table 5.3.1 - Condensate Pipelines

Pipeline

Service

Condition

Year Built

ARTCL-1 HAKHCL-1 HDAKHCL1 JQJ-1 QTCL-1 QTCL-2 SBCL-1 SBKCTL-1 SHCL-101 SHCL-102 SHCL-104 SHCL-201 SHCL-206 SHCL-217 SHCL-401 SHKHCL-1 SHKHCL-2 TNBCL-1 UCL-106 UCL-201 UCL-301 UCL-311 UCL-501 UCL-511 UCL-601 UTKHCL-1 UTKHCL-2

KHUFFCONDENSATE KHUFFCONDENSATE KHUFFCONDENSATE SPIKECONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE KHUFFCONDENSATE KHUFFCONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE CONDENSATE KHUFFCONDENSATE KHUFFCONDENSATE

sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour sour

2002 1999 2001 1980 2004 2004 1983 2007 1978 1978 1978 1978 1978 1978 1978 1985 1995 1984 1978 1978 1978 1978 1978 1978 1978 1984 1989

Coating Type

Dia. (inch)

FBE FBE FBE

24 24 18 12 8 8 20 16 3 4 4 3 8 12 3 6 8 12 6 3 4 6 4 6 3 6 6

FBE FBE FBE FBE PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX A/G FBE PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX PLICOFLEX FBE FBE

1 of 1

Onstream Length Corrosion Inhibition Scraping (km) Frequency 117.804 20.3 229 3.219 0.415 0.391 153.67 10.072 9.55 5.6 4.18 24.42 23.9 20.09 19.95 3.16 5.5 13.534 46.2 11.19 7.5 23.26 7.5 23.94 4.86 2.63 2.63

20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. none required 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol. 20 ppm in total vol.

1x per year 1x per year 4x per year 1x per year 1x per year 1x per year 3x per year 3x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 3x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year

Table 5.4.1 - NGL Pipelines

Pipeline

Service

Condition

Year Built

BJNGL-1 BRT-1 BRT-3 HASHNGL-1 JRTNGL-1 KJNGL-1

NGL C3+ NGL C3+ NGL C3+ NGL C2+ NGL C3+ NGL C2+

non-sour non-sour non-sour non-sour non-sour non-sour

1980 1971 1976 2007 1980 2007

QA-10 QRT-10 SHJNGL-1 SHJNGL-2 SHY-1

NGL C3+ NGL C3+ NGL C2+ NGL C2+ NGL C2+

non-sour non-sour non-sour non-sour non-sour

1974 1976 1984 2006 1979

Coating Type TAPE WRAP PLYMCO PLICOFLEX FBE FBE POLYKEN/ PLICOFLEX FBE FBE PLICOFLEX

1 of 1

Dia. Length Corrosion Inhibition (inch) (km)


24 16 16 24 26 24

7.356 58.305 59.728 115.2 7.356 107.25

none required none required none required none required none required none required

1x per year 1x per year 1x per year 1x per year 1x per year 1x per year

24 30 30 30 26

68.69 31.773 155.66 177.14 1162.8

none required none required none required none required none required

3x per year 3x per year 1x per year 1x per year 1x per year

Table 5.5.1 - Product Pipelines

Year Condition Built

Pipeline

Service

AH-1 AWT-1 DR-1 DR-1 (EXT) DRT-3 DRT-4 JAPL JET-A-1 JJBUT-1 JJBUT-2 JJHEX-1 JJMULT-1 JP-4 JRTNG-1 JRTNG-2

Product - DIESEL Product - BUNKER Product - GASOLINE

non-sour non-sour non-sour

1998 1985 1998

FBE FBE

8 16 20



Product - Misc Product - GASOLINE Product - GASOLINE Product - GASOLINE Product - JETA Product - BUTANE Product - BUTANE Product - HEXANE Product - LPG Product - JP4 Product - NAPTHA Product - NAPTHA

non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour non-sour

2007 1979 1979 1998 1982 1988 1993 1999 1992 1950 1980 2000

FBE

20 12 12 14 12 10 16 10 16 4 12 12

5.5 36.8 36.8 239.31 8 67.7 67.7 68 67.7 8 17.301 17.197

none required none required none required none required none required none required none required none required none required none required none required none required

1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year 1x per year

L-10

Product - NAPTHA

non-sour

1982 COAL TAR EXPOXY

3

2.3

none required

1x per year

L-12 L-2

Product - HEAVY FO Product - FUEL OIL

non-sour non-sour

1982 COAL TAR EXPOXY 1982 FBE

10 14

2.3 14.8



L-20

Product - Misc

non-sour


14

8.6

none required

1x per year

L-21 L-3

Product - DIESEL Product - FUEL OIL

non-sour non-sour

1982 COAL TAR EXPOXY 1982

12 18



L-6

Product - Misc

non-sour


10

13.45 none required

1x per year

NQRT-1

Product - DIESEL

non-sour


14


1x per year

P-10

Product - BUTANE

non-sour


8

6.3

none required

1x per year

P-13

Product - PENTANE

non-sour


4

6.3

none required

1x per year

P-40

Product - NAPTHA

non-sour


8

1.1

none required

1x per year

P-5

Product - BUTANE

non-sour


10

1.7

none required

1x per year

P-6 RQ-1 RS1-1

Product - BUTANE Product - GASOLINE Product - GASOLINE

non-sour non-sour non-sour

1982 COAL TAR EXPOXY 1999 1998 FBE

10 16 10



RTDB-1 RTDB-2 RTJ-1 RTJBD-1 RTQB-1

Product - KEROSENE Product - Misc Product - BUNKER Product - BUTANE Product - LPG

non-sour non-sour non-sour non-sour non-sour

2000

20 24 24 12 10

106.3 106 17.184 17.197 47.522

12x per year 1x per year 1x per year 1x per year 1x per year

1973 1980 2004

Coating Type

Onstream Dia. Length Corrosion Inhibition Scraping (inch) (km) Frequency

FBE FBE FBE FBE

FBE FBE PLICOFLEX FBE FBE

1 of 2

none required none required none required none required none required

Table 5.5.1 - Product Pipelines

Pipeline

Service

S1R-1 Product - GASOLINE SPDR-1 Product - Misc YRBBUT-1 Product - BUTANE

Year Condition Built non-sour non-sour non-sour

1998 1986 2007

Coating Type FBE FBE

2 of 2

Onstream Dia. Length Corrosion Inhibition Scraping (inch) (km) Frequency 10 20 6

18.29 none required 0 none required 214.06 none required


SABP-A-019.pdf

Recommend Documents