11 Contributing Authors 40
1 Scope and Purpose
This Best Practice covers primarily transmission pipelines in gas, crude oil, condensate, NGL, sales gas, and refined product service. Its main intent is to serve as a resource for field personnel to provide the optimum corrosion management approach for
transmission pipelines. It covers applicable damage mechanisms and lists viable mitigation and validation options based on established industry guidelines and field experience.
Transmission pipelines play an extremely important role as a means of transporting hydrocarbon products from production sources to another facility or to terminals.
Unprotected pipelines, whether buried in the ground, exposed to the atmosphere, or submerged in water, are susceptible to corrosion. Without proper maintenance, every pipeline system will eventually deteriorate. Corrosion can weaken the structural integrity of a pipeline and make it an unsafe means for transporting potentially hazardous materials.
Effective corrosion control can extend the useful life of all pipelines. The increased risk of pipeline failure far outweighs the costs associated with installing, monitoring, and maintaining corrosion control systems. Preventing pipelines from deteriorating and failing will save money, preserve the environment, and protect public safety.
2 Conflicts and Deviations
This Best Practice was written to be consistent with Saudi Aramco and applicable international standards. If there is a conflict between this Best Practice and other standards or specifications, please contact the Coordinator of ME&CCD/CSD for resolution.
3 References
The following list shows the recommended transmission pipelines corrosion management practices:
API RP 570 "Piping Inspection Code: Inspection, Repair, Alteration and Re-rating of In-Service Piping Systems" - Addresses inspection, repair, alteration, and re-rating procedures for metallic piping systems that have been in service.
API RP 580 “Risk Based Inspection”
API RP 1632 "Cathodic Protection of Underground Petroleum Storage Tanks and Piping System"
ISO 15156 (NACE MR0175) "Petroleum and Natural Gas Industries - Materials for Use in H2S-containing Environments in Oil and Gas Production"
NACE 35100 “In-Line Nondestructive Inspection of Pipelines - Item No. 24211”
NACE RP0102 “In-Line Inspection of Pipelines”.
Saudi Aramco Engineering Standards & Procedures
SAES-A-007: Hydrostatic Testing Fluids and Lay-up Procedures
This standard establishes requirements to control corrosion and microbiological damage during and after hydrotesting of new, revalidated, and refurbished equipment when equipment is hydrotested in accordance with SAES-A-004, SAES-L-150 or as required by other standards that specifically reference SAES-A-007.
SAES-A-205: Oilfield Chemicals
This standard establishes requirements for selection, quality assurance, quality control, and first fill purchase of oilfield chemicals in MSG (Materials Service Group) 147000. The purpose of this standard is to implement a program that results in the cost-effective purchase and performance of oilfield chemicals. This
document does not address other chemicals, such as drilling chemicals, water treatment chemicals, or chemicals used in refinery processes.
SAES-A-206: Positive Material Identification
This standard defines the minimum mandatory requirements for positive material identification (PMI) of pressure-retaining alloy material components, flange bolting, welds, weld overlays and cladding. It is intended to ensure that the nominal
composition of the alloy components and associated welds have been correctly supplied and installed as specified. Where applicable, this entire standard shall be attached to and made a part of purchase orders. Although this document addresses PMI requirements for alloy materials, provisions are also given for carbon steels under certain conditions.
SAES-A-301: Materials Resistant to Sulfide Stress Corrosion Cracking
This standard presents metallic material requirements for resistance to sulfide stress cracking (SSC) for petroleum production, drilling, gathering and flowline
equipment, field processing facilities, and refining facilities to be used in hydrogen sulfide (H2S)-bearing hydrocarbon service (liquid, gas, and/or multiphase). This standard does not include and is not intended to include design specifications. Other forms of corrosion and other modes of failure, although outside the scope of this
standard, should also be considered in design and operation of equipment. Severely corrosive conditions may lead to failures by mechanisms other than SSC and should be mitigated by corrosion inhibition or materials selection. This standard includes a variety of materials that might be used for any given component. The selection of a specific material for use shall be made on the basis of operating conditions that include but not limited to: pressure, temperature, system corrosiveness, fluid properties, and level of applied and residual stress.
SAES-H-002: Internal and External Coatings for Steel Pipelines and Piping This Standard defines the minimum mandatory internal and external coating selection requirements for steel pipelines and piping (including associated fittings and appurtenances) and the mandatory performance requirements of these coatings.
Excluded from this Standard are temporary coatings. This Standard does not preclude the use of galvanized, alloy, or nonmetallic pipe where allowed by other Saudi Aramco standards.
SAES-L-105: Piping Material Specifications
This standard covers the minimum mandatory requirements for the material specifications for piping, valves, and fittings for new piping for use in general, refining, and utility services, whose design is in accordance with either ASME B31.1, B31.3, B31.4, or B31.8 Codes.
SAES-L-132: Material Selection for Piping Systems
This standard covers the basic materials of construction for various piping systems as governed by the fluid to be transported, and supplements the requirements of piping codes ASME B31. The materials are also subject to the further requirements and limitations regarding chemical, mechanical and dimensional properties per specifications stated in this standard.
SAES-L-133: Corrosion Protection Requirements for Pipelines/Piping This standard specifies minimum mandatory measures to control internal and external corrosion, and environmental cracking for onshore and offshore pipelines, plant and platform piping, wellhead piping, well casings, and other pressure-retaining process equipment.
SAES-L-136: Pipe Selection and Restrictions
This Standard supplements the ASME B31 Piping Codes, provides requirements for the selection of metallic pipe, and sets certain restrictions on the use of metallic pipe.
SAES-L-610: Nonmetallic Piping
This Standard covers requirements and limitations for the design, installation and testing of nonmetallic piping in all areas and in all applications.
SAES-X-400: Cathodic Protection of Buried Pipelines
This standard prescribes the minimum mandatory requirements governing the design and installation of cathodic protection systems for onshore pressurized buried metallic pipelines outside of plant facilities.
SAEP-20: Equipment Inspection Schedule
This procedure covers requirements for inspection and testing of static equipment and external inspection of general equipment as described in the procedure. This procedure does not cover requirements for preventive maintenance programs of rotating, electrical, instrumentation, and digital equipment.
SAEP-306: Assessment of the Remaining Strength of Corroded Pipes
This procedure provides guidelines for assessing carbon steel pipelines containing corrosion metal-loss defects. Application of the guidance will establish the remaining strength of corroded pipelines and provide the technical basis for determining the acceptability of anomalies. The assessment methods described in this procedure are intended to be used on corrosion metal-loss anomalies in pipelines that have been designed to a recognized pipeline design code, including but not limited to ASME B31.4, ASME B31.8. The procedure can be used for in-plant piping designed and constructed.
SAEP-310: Pipeline Repair and Maintenance
This SAEP describes the procedures to be followed for the repair and maintenance of onshore pipelines, as covered by ASME B31.4 and ASME B31.8. The methods and procedures set forth herein are minimum requirements and are not a release from the responsibility for prudent action that circumstances make advisable.
SAEP-333: Cathodic Protection Monitoring
Monitoring of the cathodic protection (CP) systems is required to ensure that the CP systems perform satisfactorily and the structures receive adequate protection. This procedure provides the instructions and establishes the responsibilities to monitor (CP) systems for onshore and offshore facilities.
SAEP-343: Risk Based Inspection
This Saudi Aramco Engineering procedure provides key requirements for conducting risk based inspection studies for in-plant piping and equipment.
SAEP-355: Field Metallography and Hardness Testing
This procedure provides Saudi Aramco guidelines for performing satisfactory surface replication for the purposes of in-situ metallographic examination or field metallography and hardness testing on carbon and low-alloy steel plant equipment and in-plant piping. The procedure is designed to reveal general microstructural features such as those observed in new or aged metallic components; it is also tailored to help the metallurgical engineer in the identification/categorization of surface-breaking defects and flaws of fabrication or service induced origin. The procedure is also suitable for the assessment of high temperature equipment
operating in the creep domain. Replicas produced in accordance with this procedure will be acceptable to ASTM E1351-01 (Production and Evaluation of Field
Metallographic Replicas).
SAEP-1135: On-Stream Inspection Administration
This procedure describes the steps necessary to plan and operate a program for the on-stream inspection (OSI) monitoring of fixed equipment. OSI Monitoring in this SAEP means the systematic monitoring of piping, pipelines, vessels and tanks for general loss of wall thickness and localized metal loss.
SAEP-1143: Radiographic Examination
This Engineering Procedure establishes the minimum requirements and describes the techniques for Radiographic Examination.
SAEP-1144: Magnetic Particle Examination
This Engineering Procedure establishes the minimum requirements and describes the techniques for magnetic particle (MT) examinations on welds and components conducted in accordance with the requirements of the referenced codes/standards.
SAEP-1145: Liquid Penetrant Examination
This Engineering Procedure establishes the minimum requirements and describes the techniques for performing Penetrant Testing (PT) of welds and components conducted in accordance with the requirements of the referenced Codes and Standards.
SAEP-1146: Manual Ultrasonic Thickness Testing
This Engineering Procedure provides the general instructions for manual ultrasonic thickness testing (UTT) of base materials in plates, tubing, pipes, tanks, vessels, castings and forgings having a nominal wall thickness of 0.050 inch (1.2 mm) to 6.0 inches (150 mm) in accordance with the referenced Codes and Standards. This procedure is limited to contact testing using longitudinal wave techniques only.
00-SAIP-75: External Visual Inspection Procedure
This Saudi Aramco Inspection Procedure provides guidelines for the external visual inspection of all existing equipment within Saudi Aramco facilities including associated structures to identify deficiencies and maintain its integrity.
SAER-2365: Saudi Aramco Mothball Manual
This manual provides basic guidelines and recommendations for the preparation of detailed procedures for mothballing buildings, oilfield production, processing, and refining equipment. Due to long range forecasts for crude production In-Kingdom, some buildings, operating plants and pipeline systems are being considered for mothballing for a period of 3 - 10 years. Various plants and facilities have already been mothballed for 2 ½ years and may remain mothballed for an additional 5 to 10 years.
4 Definitions and Abbreviations
API American Petroleum Institute
ASME American Society of Mechanical Engineers BS&W Basic (Bottom) Sediment and Water
CO2 Carbon Dioxide
EIS Equipment Inspection Schedule EMAT Electro-Magnetic Acoustic Transducer FFS Fitness for Service
GAB General Aerobic Bacteria GOSP Gas Oil Separation Plant H2S Hydrogen Sulfide
HIC Hydrogen Induced Cracking ILI In-Line Inspection
MFL Magnetic Flux Leakage
mpy Mils per Year
MSG Materials Service Group
MIC Microbiologically-Influenced Corrosion MPT Magnetic Particle Testing
NGL Natural Gas Liquids OSI Onstream Inspection PT Penetrant Testing
PMI Positive Material Identification RE Radiographic Examination RBI Risk Based Inspection
SAES Saudi Aramco Engineering Standard SAIP Saudi Aramco Inspection Procedure
SAMSS Saudi Aramco Materials Systems Specification SCADA Supervisory Control and Data Acquisition SCC Stress Corrosion Cracking
SMYS Specified Minimum Yield Strength
SOHIC Stress Oriented Hydrogen Induced Cracking SRB Sulfate Reducing Bacteria
SSC Sulfide Stress Cracking T&I Test and Inspection
TML Thickness Measurement Location UT Ultrasonic Testing
VE Visual Examination
5 Pipeline System Description
This section of the Pipeline Corrosion Best Practice Manual describes and categorizes the pipeline network based on its service fluid type: gas, crude, condensate, NGL, and refined products. Furthermore, each service type is sub-categorized to sour, non-sour, and sweet services. The data provided in the attached tables include the name of the pipeline, service type, service condition, coating type, diameter, length, chemical treatment, and onstream scraping frequency (onstream scraping frequency is subject to change). Also, some of the pipelines listed in subsequent tables may be mothballed. Detailed SIS data,
drawings, etc. for each pipeline can be viewed at http://eptdv2/webforms/main.aspx website.
5.1 Gas Service
The gas service can be categorized under three service types: sour, non-sour, and sweet (CO2 containing gas). Sour gas service pipelines flow from the GOSP to the gas plants. Some GOSPs reheat the sour gas stream up to 165°F to prevent liquid from dropping out as the gas cools down the pipeline. Enough corrosion inhibitor solution (Champion KR-2237X or ATROS Dodigen 1641X) is injected into the sour gas stream to turn it into a two phase regime to properly disperse the corrosion inhibitor. The specified amount of corrosion inhibitor injected in sour gas pipelines is based on the maximum operating temperature: 0.5 gallon inhibitor/MMSCFD at <50°C and 1.0 gallon inhibitor/MMSCFD at ≥50°C. The amount of water moisture in the sour gas stream varies from GOSP to GOSP.
Sweet service gas pipelines flow from the well head to the gas plants at
Hawiyah. Champion KRN-264 corrosion inhibitor is injected into sweet service pipelines at 3.0 pints/MMSCFD of gas. The amount of water moisture in sweet service pipelines varies from non-detected to 1700 PPMV @ 120 psig
depending on which wells are produced.
Non-sour gas service pipelines flow from gas plants to Saudi Aramco customers.
The sour gas flowing into the gas plants goes through sweetening and
dehydration processes to produce non-sour gas. The maximum water moisture in sales gas pipelines is 7.0 lbs. of water per MMSCFD of non-sour gas as specified in A120 Dry Gas Specifications. No corrosion inhibitor is injected in non-sour gas pipelines because it is considered as non-corrosive.
Tables 5.1.1, 5.1.2 and 5.1.3 in the Appendix list the sour, non-sour, and sweet gas service pipelines, respectively.
5.2 Crude Service
The crude service can be categorized under two service types: sour and non-sour. The sour crude service pipelines flow from the GOSPs to either Abqaiq Plant in the southern area or from Abu Ali to Ras Tanura Refinery in the northern operating area. Champion AR-505 corrosion inhibitor is injected into all sour crude pipelines at a rate of 20 ppm in the maximum water volume. The maximum BS&W allowed in sour crude service is 0.2 vol% but typically is about 0.1 vol% in actual operating situation.
Non-sour stabilized crude flows from Abqaiq Plant to either Ras Tanura Refinery or Yanbu Refinery and dehydrated and desalted crude flows from Safaniyah to Ras Tanura Refinery. Biocide will have to be injected into all non-sour crude
service pipelines due to the presence of Sulfate Reducing Bacteria (SRB). The recommended treatment program consists of 30 to 120 minutes of biocide slug at 250 ppm dosage every month depending on the non-sour crude pipeline. The maximum BS&W allowed in non-sour crude pipelines is 0.2 vol%.
Tables 5.2.1 and 5.2.2 in the Appendix list the sour and non-sour crude service pipelines, respectively.
5.3 Condensate Service
Condensate flows from Tanajib Onshore Plant condensate to Berri Gas Plant.
Corrosion inhibitor (Champion 2237D or ATROS 1641D) is injected in all sour condensate pipelines inside the GOSP between the gas compressors and the fin fan coolers or Champion AR-505 at Tanajib Onshore Plant for the SBCL-1 pipeline. The amount of water in sour condensate service varies from 1.0 vol%
from Tanajib Onshore Plant and varies from GOSP to GOSP.
Table 5.3.1 in the Appendix lists the condensate service pipelines.
5.4 NGL Service
The NGL service is normally non-sour and comes from either Abqaiq Plant or gas plants to Ras Tanura Refinery or Yanbu NGL Plant. Champion KR-2237D or ATROS Dodigen 1641D corrosion inhibitor is injected into QA-10/QRT-10 pipeline at a dosage of 20 ppm at total NGL volume because the service in this line is considered sour. The amount of water in NGL service varies from pipeline to another.
Table 5.4.1 lists the NGL service pipelines.
5.5 Refined Product Services
Refined product services include the following:
Diesel
Kerosene
Jet Fuel.
All refined products come from the crude refinery and flows to either the bulk plant or airport fueling terminal. No corrosion inhibitor is injected in refined product pipelines because they are considered non-corrosive. Although, all diesel is allowed to have a maximum 0.05 vol% BS&W except bunker diesel which can have as much as 0.10 vol% BS&W.
Table 5.5.1 in the Appendix lists the refined product pipelines.
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.
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.
c) The segment is less than 32 km (20 miles) downstream from a compressor station.