Overview of the Design, Construction, 

and Operation of Interstate Liquid 

Petroleum Pipelines

ANL/EVS/TM/08-1

Environmental Science Division
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Overview of the Design, Construction, 

and Operation of Interstate Liquid 

Petroleum Pipelines

ANL/EVS/TM/08-1

by

T.C. Pharris1

 and R.L. Kolpa2

1

Decision and Information Sciences Division

2

Environmental Science Division

Argonne National Laboratory

November 2007

iii 

CONTENTS 

NOTATION.............................................................................................................................. vii 

1 INTRODUCTION ........................................................................................................... 1 

 1.1 U.S. Pipeline Network ............................................................................................ 1 

 1.2 Fluids Handled........................................................................................................ 2 

 1.3 Types of Line Pipe.................................................................................................. 4 

 1.4 System Components................................................................................................ 5 

 1.4.1 Tankage....................................................................................................... 5 

 1.4.2 Piping Types ............................................................................................... 6 

 1.4.3 Pumping Stations ........................................................................................ 8 

 1.4.4 Metering Stations........................................................................................ 8 

 1.4.5 Valve Manifolds.......................................................................................... 8 

 1.4.6 Piping Manifolds......................................................................................... 8 

 1.4.7 Pigging Stations .......................................................................................... 9 

 1.4.8 Supervisory Control and Data Acquisition Systems................................... 9 

 1.4.9 Telecommunication Towers........................................................................ 9 

 1.4.10 Mass Flow Meters....................................................................................... 10 

 1.4.11 Valves ......................................................................................................... 10 

 1.4.12 Corrosion Control Systems......................................................................... 10 

2 PIPELINE DESIGN ........................................................................................................ 13 

 2.1 Factors Influencing Pipeline Design....................................................................... 13 

 2.1.1 General Pipeline Design Considerations .................................................... 13 

 2.1.2 Safety .......................................................................................................... 13 

 2.1.3 Industry Codes and Standards..................................................................... 14 

 2.1.4 Pipeline Coating.......................................................................................... 17 

 2.1.5 Sizing .......................................................................................................... 19 

 2.1.6 Pressure....................................................................................................... 19 

 2.1.7 Product Qualities......................................................................................... 20 

 2.1.8 Other Design Considerations ...................................................................... 24 

 2.1.9 Leak Detection............................................................................................ 29 

 2.1.10 Overpressure Protection.............................................................................. 31 

 2.1.11 Valve Spacing and Rapid Shutdown........................................................... 31 

 2.1.12 Pumps and Pumping Stations...................................................................... 32 

 2.1.13 Pigging Devices and Pig Launching/Receiving Facilities.......................... 34 

 2.1.14 Distribution Terminals................................................................................ 34 

 2.1.15 Measurement and Flow Control.................................................................. 34 

 2.1.16 Risk of Natural Hazards and Human Threats ............................................. 38 

 2.2 Colocation Issues in Corridors................................................................................ 38 

 2.2.1 Fire Hazards................................................................................................ 39 

 2.2.2 Coincident Construction ............................................................................. 39 

 2.2.3 Electrical Interference................................................................................. 39 
iv 

CONTENTS (Cont.) 

3 PIPELINE CONSTRUCTION ........................................................................................ 45 

 3.1 Scheduling............................................................................................................... 46 

 3.2 Preconstruction Activities....................................................................................... 46 

 3.2.1 Survey and Mapping................................................................................... 46 

 3.2.2 Staging Areas.............................................................................................. 48 

 3.2.3 Soil and Geology Studies............................................................................ 48 

 3.3 Construction............................................................................................................ 48 

 3.3.1 Movement and Staging of Pipeline Components 

 and Construction Equipment....................................................................... 51 

 3.3.2 Clearing and Grading.................................................................................. 51 

 3.3.3 Stringing Pipe Joints along the ROW ......................................................... 53 

 3.3.4 Ditching....................................................................................................... 55 

 3.3.5 Pipe Bedding Material ................................................................................ 56 

 3.3.6 Welding....................................................................................................... 57 

 3.3.7 Pipe Bending............................................................................................... 60 

 3.3.8 Pipe Coating................................................................................................ 60 

 3.3.9 Lowering the Pipeline into the Ditch.......................................................... 61 

 3.3.10 Backfilling the Ditch................................................................................... 61 

 3.3.11 Hydrostatic Testing..................................................................................... 62 

 3.3.12 Final Grading and Reclamation .................................................................. 64 

 3.3.13 Special Conditions ...................................................................................... 65 

4 PIPELINE OPERATIONS .............................................................................................. 79 

 4.1 Inspections and Markers ......................................................................................... 79 

 4.1.1 Inspections during Excavation.................................................................... 79 

 4.1.2 ROW Inspections........................................................................................ 79 

 4.1.3 Pipeline Markers and Aboveground Facilities............................................ 80 

 4.1.4 Change in Operating Rate........................................................................... 80 

 4.2 Pipeline Repairs ...................................................................................................... 80 

 4.2.1 Moving and Lowering Hazardous Liquid Pipelines ................................... 81 

 4.2.2 Remedial Action for Corrosion Deficiencies.............................................. 81 

 4.3 Pigging Activities.................................................................................................... 81 

 4.4 Chemical Additives................................................................................................. 82 

 4.5 Pipeline Security ..................................................................................................... 82 

 4.6 Waste Management................................................................................................. 82 

 4.7 Cathodic Corrosion Protection................................................................................ 83 

 4.8 Leak Detection........................................................................................................ 84 

 4.9 Integrity Assesments............................................................................................... 85 

 4.9.1 Metal-Loss Tools ........................................................................................ 86 

 4.9.2 Crack-Detection Tools................................................................................ 86 

 4.9.3 Geometry Tools .......................................................................................... 86 
v 

CONTENTS (Cont.) 

 4.9.4 Mapping Tools............................................................................................ 87 

 4.10 Pipeline Repair Techniques .................................................................................... 87 

5 Decommission and Demolition ....................................................................................... 89 

6 Emergencies and Off-Normal Events.............................................................................. 91 

7 References........................................................................................................................ 93 

FIGURES 

2.1-1 Coating Newly Installed Pipe for Corrosion Control ............................................. 18 

2.1-2 Examples of the Types of Pigs in Use Today......................................................... 35 

2.1-3 Pig Launcher/Receiver............................................................................................ 36 

3.3-1 Typical ROW with Topsoil Segregation................................................................. 49 

3.3-2 Typical ROW with Adjacent Pipeline .................................................................... 50 

3.3-3 Typical ROW Maintenance in Forested Areas ....................................................... 51 

3.3-4 Pipe Segments Arriving at Rail Off-loading Area.................................................. 52 

3.3-5 Pipe Segments in a Material Laydown Area........................................................... 52 

3.3-6 Sample Road Entrance to a Pipeline ROW............................................................. 54 

3.3-7 Stringing Pipe along the ROW ............................................................................... 54 

3.3-8 Delivering Pipe Segments to the Construction Site in Rugged Terrain 

 May Require Special Equipment ............................................................................ 55 

3.3-9 Pipeline Ditching .................................................................................................... 56 

3.3-10 Welding Pipe........................................................................................................... 58 

3.3-11 Pipe Bending Machine............................................................................................ 60 

3.3-12 Applying Coating to Pipeline.................................................................................. 61 

3.3-13 Lowering Pipe into Trench ..................................................................................... 62 

3.3-14 Backfilling Pipeline ................................................................................................ 63 

3.3-15 Final Contouring of Pipeline ROW ........................................................................ 64 
vi 

FIGURES (Cont.) 

3.3-16 Revegetated Pipeline ROW .................................................................................... 65 

3.3-17 Trenched Road Crossing......................................................................................... 66 

3.3-18 Bored Road/Railroad Crossing ............................................................................... 67 

3.3-19 Typical Waterbody Crossing .................................................................................. 68 

3.3-20 Dam-and-Pump River Crossing with Two Pipelines.............................................. 69 

3.3-21 Flume Water Crossing with Two Pipelines ............................................................ 70 

3.3-22 Typical Directional Drilling under Waterway ........................................................ 71 

3.3-23 Waterbody Crossing Containing a Second Pipeline ............................................... 72 

3.3-24 Saturated Wetland Crossing.................................................................................... 73 

3.3-25 Concrete-Coated Pipe in a Wetland........................................................................ 75 

3.3-26 Crude Oil Pipeline Pump Station............................................................................ 78 

3.3-27 Typical Pipeline Breakout Station at a Petroleum Terminal .................................. 78 

TABLES 

1.2-1 Characteristics of Liquid Hydrocarbons ................................................................. 3 

2.1-1 Live Loads .............................................................................................................. 26 

2.1-2 Impact Factors for Highways and Railroads Versus Depth of Cover..................... 26 

2.1-3 Degree of Component Vulnerability to Damage or Disruption 

 from Natural Hazards and Human Threats ............................................................. 40 
vii 

NOTATION 

 The following is a list of the acronyms, initialisms, and abbreviations (including units of 

measure) used in this document. Acronyms and abbreviations used only in tables and figures are 

defined in the respective tables and figures. 

ACRONYMS, INITIALISMS, AND ABBREVIATIONS 

AASHTO American Association of State Highway and Transportation Officials 

AC alternating current 

ACEC areas of critical environmental concern 

ALA American Lifelines Alliance 

ANSI American National Standards Institute 

AOPL Association of Oil Pipe Lines 

API American Petroleum Institute 

AREA American Railway Engineering Association 

AREMA American Railway Engineering Maintenance-of-Way Association 

ASCF American Society of Civil Engineers 

ASME American Society of Mechanical Engineers 

ASTM American Society for Testing and Materials 

AWS American Welding Society 

BTEX benzene, toluene, ethylbenzene, and xylene 

CDPD Cellular Digital Packet Data 

CFR Code of Federal Regulaions

CPS cathodic protection system 

DOE U.S. Department of Energy 

DOT U.S. Department of Transportation 

EIA Energy Information Administration (DOE) 

EPA U.S. Environmental Protection Agency 

FEMA Federal Energy Management Agency 

FERC Federal Energy Regulatory Commission 

GPS global positioning system 

HDD horizontal directional drilling 

IAPMO International Association of Plumbing and Mechanical Officials 

IEEE Institute of Electrical and Electronic Engineers, Inc. 
viii 

LNG liquefied natural gas 

LPG liquefied petroleum gas 

MAOP maximum allowable operating pressure 

MFL magnetic flux leakage 

MOP maximum operating pressure 

MTU master terminal unit 

NACE National Association of Corrosion Engineers 

NDT nondestructive testing 

NORM naturally occurring radioactive materials 

OPS Office of Pipeline Safety (DOT) 

OSHA Occupational Safety and Health Administration 

RCRA Resource Conservation and Recovery Act 

ROW(s) right(s)-of-way 

RP Recommended Practice 

RTU remote thermal unit 

SCADA supervisory control and data acquisition 

TAPS Trans-Alaska Pipeline System 

UHF ultrahigh frequency 

VHF very high frequency 

UNITS OF MEASURE 

cSt centistoke 

°F degree(s) Fahrenheit 

lb pound(s) 

ppm part(s) per million 

psi pound(s) per square inch 

psia pound(s) per square inch absolute 

psig pound(s) per square inch gauge 
 1 

1 INTRODUCTION 

1.1 U.S. PIPELINE NETWORK 

The U.S. liquid petroleum pipeline industry is large, diverse, and vital to the nation’s 

economy. Comprised of approximately 200,000 miles of pipe in all fifty states, liquid petroleum 

pipelines carried more than 40 million barrels per day, or 4 trillion barrel-miles, of crude oil and 

refined products during 2001. That represents about 17% of all freight transported in the United 

States, yet the cost of doing so amounted to only 2% of the nation’s freight bill. Approximately 

66% of domestic petroleum transport (by ton-mile) occurs by pipeline, with marine movements 

accounting for 28% and rail and truck transport making up the balance. In 2004, the movement 

of crude petroleum by domestic federally regulated pipelines amounted to 599.6 billion tonmiles, while that of petroleum products amounted to 315.9 billion ton-miles (AOPL 2006). As an 

illustration of the low cost of pipeline transportation, the cost to move a barrel of gasoline from 

Houston, Texas, to New York Harbor is only 3¢ per gallon, which is a small fraction of the cost 

of gasoline to consumers. 

Pipelines may be small or large, up to 48 inches in diameter. Nearly all of the mainline 

pipe is buried, but other pipeline components such as pump stations are above ground. Some 

lines are as short as a mile, while others may extend 1,000 miles or more. Some are very simple, 

connecting a single source to a single destination, while others are very complex, having many 

sources, destinations, and interconnections. Many pipelines cross one or more state boundaries 

(interstate), while some are located within a single state (intrastate), and still others operate on 

the Outer Continental Shelf and may or may not extend into one or more states. U.S. pipelines 

are located in coastal plains, deserts, Arctic tundra, mountains, and more than a mile beneath the 

water’s surface of the Gulf of Mexico (Rabinow 2004; AOPL 2006). 

The network of crude oil pipelines in the United States is extensive. There are 

approximately 55,000 miles of crude oil trunk lines (usually 8 to 24 inches in diameter) in the 

United States that connect regional markets. The United States also has an estimated 30,000 to 

40,000 miles of small gathering lines (usually 2 to 6 inches in diameter) located primarily in 

Texas, Oklahoma, Louisiana, and Wyoming, with small systems in a number of other oil 

producing states. These small lines gather the oil from many wells, both onshore and offshore, 

and connect to larger trunk lines measuring 8 to 24 inches in diameter. 

There are approximately 95,000 miles of refined products pipelines nationwide. Refined 

products pipelines are found in almost every state in the United States, with the exception of 

some New England states. These refined product pipelines vary in size from relatively small, 

8- to 12-inch-diameter lines, to up to 42 inches in diameter. 

The overview of pipeline design, installation, and operation provided in the following 

sections is only a cursory treatment. Readers interested in more detailed discussions are invited 

to consult the myriad engineering publications available that provide such details. The two 

primary publications on which the following discussions are based are: Oil and Gas Pipeline 

Fundamentals (Kennedy 1993) and the Pipeline Rules of Thumb Handbook (McAllister 2002). 
 2 

Both are recommended references for additional reading for those requiring additional details. 

Websites maintained by various pipeline operators also can provide much useful information, 

as well as links to other sources of information. In particular, the website maintained 

by the U.S. Department of Energy’s Energy Information Administration (EIA) 

(http://www.eia.doe.gov) is recommended. An excellent bibliography on pipeline standards and 

practices, including special considerations for pipelines in Arctic climates, has been published 

jointly by librarians for the Alyeska Pipeline Service Company (operators of the Trans-Alaska 

Pipeline System [TAPS]) and the Geophysical Institute/International Arctic Research Center, 

both located in Fairbanks (Barboza and Trebelhorn 2001), available electronically at 

http://www.gi.alaska.edu/services/library/pipeline.html#codes. The Association of Oil Pipe Lines 

(AOPL) and the American Petroleum Institute (API) jointly provide an overview covering the 

life cycle of design, construction, operations, maintenance, economic regulation, and 

deactivation of liquid pipelines (AOPL/API 2007). 

1.2 FLUIDS HANDLED 

The products carried in liquid pipelines include a wide range of materials. Crude oil 

systems gather production from onshore and offshore fields, while transmission lines transport 

crude to terminals, interconnection points, and refineries. The crude oil may be of domestic 

origin or imported. Refined petroleum product, including gasoline, aviation fuels, kerosene, 

diesel fuel, heating oil, and various fuel oils, are sizable portions of the pipelines business, 

whether produced in domestic refineries or imported to coastal terminals. Other materials include 

petrochemical feedstocks (also known as secondary feedstocks) such as benzene, styrene, 

propylene, and aromatics such as xylene, toluene, and cumene that are delivered by pipeline 

from refineries to petrochemical production plants or to other refineries. Also carried by pipeline 

are liquefied petroleum fuels such as liquefied natural gas (LNG) (albeit over relatively short 

distances), liquefied petroleum gas (LPG) and propane, all of which are gases at standard 

temperature and pressure but easily liquefied with the application of pressure.1 Still other 

materials transported by pipelines include carbon dioxide and anhydrous ammonia, both 

transported as liquids under their own pressure.2 In recent years, long-distance pipelines have 

been constructed to carry distillate fractions from the distillation of crude oils from refineries to 

production facilities for crude feedstocks such as bitumen recovered from tar sands and heavy 

oils. Such feedstocks are too viscous to be transported by pipeline. However, the distillate 

fractions are used to dilute these feedstocks, with the resulting mixture being suitable for 

delivery back to the refinery by pipeline for further processing. Also in recent years, longdistance pipelines have been constructed to carry “produced water”3 from oil and gas fields to 

refineries and other industrial facilities that use copious amounts of water, but are located in arid 

areas or areas where water availability is limited. Hydrogen is also delivered by pipeline, albeit 

over relatively short distances, typically connecting hydrogen production facilities with refineries 

and other industries that use hydrogen as a starting material in their processes. Table 1.2-1 

 

1 However, the majority of natural gas transported by pipeline over long distances is transported as a gas. 

2 Carbon dioxide is also transported by pipeline as a gas. 

3 As used here, produced water includes water recovered at the well head or crude oil and/or natural gas 

production wells. 
 3 

TABLE 1.2-1 Characteristics of Liquid Hydrocarbons 

Type 1(a): liquefied gases (liquefied petroleum gas, ethylene, propylene) 

 • Highly volatile 

 • Gas at ambient conditions; maintained at high pressures 

Type 1(b): very light grade oils (gasoline) 

 • Highly volatile 

 • Evaporates quickly, often completely within 1 to 2 days 

Type 2: light grade oils (jet fuels, diesel, No. 2 fuel oil, light crude) 

 • Moderately volatile 

 • Will leave residue (up to one-third of spill amount) after a few days 

 • Moderately soluble, especially distilled products 

Type 3: medium grade oils (most crude oils) 

 • About one-third will evaporate within 24 hours 

 • Typical water-soluble fraction 10−100 ppm 

 • May penetrate substrate and persist 

 • May pose significant cleanup-related impacts 

Type 4: heavy grade oil (heavy crudes, No. 6 fuel oil, bunker C) 

 • Heavy oils with little or no evaporation 

 • Water-soluble fraction typically less than 10 ppm 

 • Heavy surface contamination likely 

 • Highly persistent; long-term contamination possible 

 • Weathers very slowly; may form tar balls 

 • May sink in water, depending on product density 

 • May pose significant cleanup-related impacts 

 • Low acute toxicity relative to other oil types 

Type 5 low API fuel grade oils (heavy industrial fuel oils) 

 • Neutrally buoyant or may sink 

 • Weathers slowly; sunken oil has little potential for evaporation 

 • May accumulate on bottom under calm conditions and smother subtidal resources 

 • Sunken oil may be resuspended during storms, providing a chronic source of 

 shoreline oiling 

 • Highly variable and often blended with oils 

 • Blends may be unstable, and the oil may separate when spilled 

 • Low acute toxicity relative to other oil types 

provides an overview of the physical characteristics of the more common liquid hydrocarbons 

transported via pipeline. Typically, more than one product is transported through the same 

interstate pipeline. In those instances, the line pipe meets the most rigorous product-specific 

standards among all of the materials being transported. Increased numbers of products carried on 

a pipeline increase the support facilities, such as tankage, required to receive and segregate the 

different products. 
 4 

1.3 TYPES OF LINE PIPE

Steel pipe is used in most pipelines transporting hydrocarbons. It is manufactured 

according to the specifications of the American Petroleum Institute (API 1994, 2000), the 

American Society of Mechanical Engineers (ASME), the American National Standards Institute 

(ANSI), and the American Society of Testing Materials (ASTM). 

Various grades of line pipe are specified, based on yield strength.4 Grade A line pipe has 

a minimum yield strength of 30,000 pounds per square inch (psi), with Grade B having a 

minimum yield strength of 35,000 psi. Other grade categories may indicate special fabrication 

methods. For example, Grade X42 indicates a pipe made of steel with a 42,000 psi minimum 

yield strength; X60 pipe has a minimum yield strength of 60,000 psi, etc. Newer pipe grades X70 

and X805 are available, but are typically used in offshore or high-pressure gas pipelines for 

large-diameter or high-pressure applications.6 Additional information on line pipe grades can be 

obtained from the EUROPIPE and U.S. Steel Tubular Products websites http://www.europipe.de/ 

www/download/EP_TP47_02en.pdf and http://www.usstubular.com/products/seamslp.htm, 

respectively. A more detailed discussion of pipe fabrication can be found in Kennedy (1993). 

Line pipe is manufactured as either seamless or welded. These designations refer to how 

each length, or joint, of pipe is manufactured, not how the joints are connected in the field to 

form a continuous pipeline. Seamless steel pipe is made without a longitudinal weld by hotworking lengths of steel to produce pipe of the desired size and properties. Welded pipe is made 

using several manufacturing processes. The two types of pipe differ both by the number of 

longitudinal weld seams in the pipe and the type of welding equipment used. Welded pipe is the 

most common pipe used in petroleum pipeline service. 

The individual lengths of pipe are normally joined by welding sections of pipe together 

(20 or more feet in length). Pipe made of materials other than steel, including fiberglass, various 

plastics, and cement asbestos, has been used for special applications involving corrosive liquids, 

such as saltwater disposal or the transport of highly corrosive crude oils. 

Most pipe used in the United States is manufactured as seamless, or longitudinally 

welded, pipe. However, other parts of the world use spiral-welded pipe, which has a spiral weld 

along its length. 

 

4 Yield strength is the amount of tensile force that must be applied to cause a permanent deformation (elongation) 

in a test sample. The force is typically expressed in units of pounds per square inch. 

5 X80 line pipe is for large-diameter high-strength pipelines. See http://www.europipe.de/www/download/ 

EP_TP47_02en.pdf. (Accessed July 12, 2006.) 

6 See “General Description of Seamless Standard and Line Pipe Grades” at http://www.usstubular.com/products/ 

seamslp.htm. (Accessed July 14, 2006.) 
 5 

1.4 SYSTEM COMPONENTS 

1.4.1 Tankage 

Most pipeline systems have the ability to temporarily store and/or receive shipped 

product on each end of the pipeline, to facilitate product movements and, in some cases, to 

accommodate product blending. The size and nature of the storage depend on the business of the 

pipeline and the product(s) it carries. API and ASME standards have been promulgated to 

address the design and construction of these facilities.7 In addition, each facility needs to have 

waste handling and environmental control capabilities. Again, the nature and capacity of the 

storage depend on the business of the pipeline and the product(s) it carries. Since many pipelines 

originate or terminate at coastal facilities to enable marine movements, dock facilities are also 

often included in a comprehensive definition of a pipeline system. 

Along with meeting all of the tankage requirements mentioned above, most facilities 

have the ability to handle pipeline waste materials and/or interface materials when the pipeline 

handles multiple products. Transmix, which is the mixture of two hydrocarbons shipped 

together, must be segregated and either downgraded to an appropriate specification or 

reprocessed. Crude oil delivered through pipelines also often contains small amounts of 

produced water.8 If the crude is at a storage field, this is collected and trucked to wastewater 

treatment. As a first step in the refining process, refineries will process crude oils in a “desalter” 

to remove all water. Waters recovered in the desalter are typically combined with other refinery 

wastewaters and treated in on-site facilities before being used (recycled) or to meet the 

requirements and pollutant limitations of discharge permits. 

Nearly all pipeline terminal facilities have pumps, pig launching/recovery facilities 

(see Section 2.1.13), and the capability of handling pipeline sludge that can accumulate on 

pipeline walls and is removed during pigging activities. All pipeline terminals need to handle the 

drainage of lubricants and pipeline products, sampling dump stations, contaminated condensates, 

etc. Terminals are also required to develop spill prevention, control, and countermeasure plans 

for responses to accidental releases of products. Some materials recovered in responses to 

accidental releases, as well as waste materials generated through routine pipeline and terminal 

 

7 Over 51 API standards have been promulgated relating to storage tanks, dealing with such topics as design 

criteria, cathodic protection, and operational procedures. A catalogue of all storage tank-related API standards, 

as well as all other API publications, is available at the API website: http://www.api.org/Publications. (Accessed 

January 11, 2007.) API standards can be purchased electronically from a number of vendors. See, for example: 

http://global.ihs.com/search_res.cfm?currency_code=USD&customer_id=2125452C2E0A&shopping_cart_id= 

2825285B244A403C415B5D58250A&rid=Z56&mid=Z56&country_code=US&lang_code=ENGL&input_doc_

title=storage%20tanks&org_code=API. (Accessed January 11, 2007.) 

8 However, when the produced water recovered at the production well contains naturally occurring radioactive 

material (NORM), additional controls are typically employed to exclude this water from the pipeline to the 

greatest extent possible so as to prevent NORM contamination of the pipeline and its associated components. 

Produced water containing NORM is typically reintroduced into the oil-bearing formation through injection 

wells. 
 6 

operation, qualify as hazardous waste under federal or state environmental laws,9 so terminals 

typically also include facilities to temporarily store such materials before transport to permitted 

treatment and disposal facilities. A number of facilities have on-site waste water treatment 

facilities, which is more cost effective. Depending on the amount of production water that is 

allowed to be introduced into the pipeline and the source, pipelines that carry certain crude oils, 

as well as the terminals and refineries that receive them, may also generate waste from pigging 

operations or tank and equipment cleaning operations that contain naturally occurring radioactive 

materials (NORM). Such wastes require segregation and treatment or disposal in specially 

permitted facilities. 

The primary shipping and receiving terminals are adjacent to, but not necessarily within 

pipeline rights-of-way (ROWs) or designated energy corridors. However, interconnecting 

pipelines and surge or pressure-relief tanks or breakout tanks are integral to interstate pipeline 

transport and can be expected to be located close to, if not within, the pipeline’s ROW or within 

the designated energy corridor. Also, at changes in elevation, small tanks that serve as pressure 

stabilizing elements of overall pipeline operations will also be located close to the pipeline. 

In accordance with federal or state environmental regulations and to provide for safe 

operation, typical design and operational considerations that have been incorporated into industry 

standards are reflected at facilities where storage is occurring. Adherence to relevant standards 

results in features such as tank dikes, enclosed drainage systems, double seals on floating roof 

tanks, leak detection, corrosion monitoring and protection, requirements for periodic inspection 

and monitoring programs, procedures for purging tank vapor spaces and vapor 

recovery/treatment, and specification of minimum corrosion allowances. All storage locations 

with capacities above prescribed volumes are also required to develop and periodically exercise 

emergency response plans for accidental releases of stored product. Some of the API standards 

and recommended procedures described above address these requirements. Although storage 

could occur in both aboveground and underground tanks, aboveground tanks generally 

predominate. Various tank designs are employed, some specifically suited for particular products 

or conditions. These include cone roof tanks, open-top floating roof tanks, covered floating roof 

tanks, spherical tanks (typically used for gases stored at high pressure), or bullet-style tanks 

(typically used to store gases at high pressures, often in a liquefied state). 

1.4.2 Piping Types 

1.4.2.1 Flowlines 

Flowlines are used as part of a crude gathering system in production areas to move 

produced oil from individual wells to a central point in the field for treating and storage. 

Flowlines are generally small-diameter pipelines operating at relatively low pressure. Typical in 

the United States flowlines are between 2 and 4 inches in diameters. The size required varies 

 

9 This is especially true of pipelines that transport secondary feedstocks containing listed chemicals or distillate 

products that demonstrate flammability characteristics specified in hazardous waste regulations. 
 7 

according to the capacity of the well being served, the length of the line, and the pressure 

available at the producing well to force the oil through the line. Some wells are not pressurized 

and require pumping to collection systems. Flowlines typically operate at pressures below 

100 psi. 

Flowlines are normally made of steel, although various types of plastic have been used in 

a limited number of applications. Pipelines used for oil flowlines typically operate at low 

pressures, and therefore could be made of materials other than steel. Flowline pipe wall 

thicknesses of 0.216 inch for a 3-inch-diameter pipe are not uncommon, corresponding to a 

weight of 7.58 lb/lineal foot for a 3-inch-diameter pipe (Kennedy 1993). 

1.4.2.2 Crude Trunk Lines 

Crude is moved from central storage facilities over long-distance trunk lines to refineries 

or other storage facilities. Crude trunk lines operate at higher pressures than flowlines and could 

vary in size from 6 inches in diameter to as large as 4 feet, as in the TAPS in Alaska.10

1.4.2.3 Product Pipelines 

Pipelines carrying products that are liquid at ambient temperatures and pressures do not 

have to operate at excessive pressures in order to maintain the product in a liquid state. However, 

liquids that vaporize at ambient temperatures must be shipped at higher pressures. For instance, 

ethane pipelines can operate at pressures up to 1,440 psi. Product pipelines usually are 12 to 

24 inches in diameter, but can be as large as 40 inches in the case of the Colonial Pipeline, which 

carries gasoline and distillate from the Gulf Coast to northeast markets. 

Product pipelines are unique, since they are typically used to transport a variety of 

petroleum distillate products concurrently in a batch-wise manner. The petroleum products 

jointly carried in the same pipeline are always chemically compatible with each other, but may 

differ in physical properties such as density. Some intermixing occurs at the interface of two 

products sequentially introduced into the pipeline. Operating methods allow for minimizing the 

interface between products. Regardless of how the commodities are separated while in the 

pipeline, any mixtures of two commodities are segregated from the rest of the flow at terminals 

and handled by downgrading (i.e., marketing them as product mixtures of lower quality than the 

original individual products) or by recovering and refractionating each mixture into the two 

original petroleum products. In some instances, a sphere or a specially designed pig can be 

inserted between batches to reduce the amount of mixing. 

 

10 The TAPS is currently the largest operational crude oil pipeline in the United States. More typically, 42-inchdiameter pipe is the maximum size used, since it is the maximum size that is currently manufactured within the 

United States. Pipe used in TAPS was manufactured in Japan. 
 8 

1.4.3 Pumping Stations 

As with storage tanks, pump stations require an infrastructure of their own. They require 

waste handling, such as nearby sewer facilities or holding facilities for transfer in batches to an 

off-site waste-handling facility.11 Also, the handling and injection of additives, such as for 

viscosity reduction, often occurs at pump stations. Pumps are typically driven by electric motors; 

however, engines operating on a variety of fuels (but typically obtained from sources other than 

the pipeline itself) can also be used to drive the pumps. Depending on location, power may be an 

issue. In the event of power failures or other significant upset conditions, pump stations are 

typically equipped with sufficient emergency power generation to support monitoring and 

control systems to accomplish an immediate safe shutdown.12 

1.4.4 Metering Stations 

Although primarily utilized to measure the volume, quality, and consistency of product 

for billing purposes and delivery receipts, storage tank monitoring and product metering can be 

used with line pressure monitors to verify that pipeline integrity has not been compromised. Any 

discrepancy could indicate some sort of system leak. Typically there is some “shrinkage” in 

volume when products are transferred from pipeline to tanks to pipeline. Systems and processes 

are in place to determine when the shrinkage observed is outside expected values. 

1.4.5 Valve Manifolds 

Valves are installed at strategic locations along the mainline pipe to control flows and 

pressures within the pipe and to isolate pipe segments in the event of upset or emergency 

conditions. Regardless of design, all valves require regular monitoring and maintenance. Along 

with pump seals that require continuous leak detection and repair, valve manifolds must be 

closely monitored and periodically overhauled based on schedules established by the 

manufacturer (preventative maintenance), reduced performance, and/or observed deterioration 

and wear. 

1.4.6 Piping Manifolds 

Depending on the facility, the presence of piping manifolds can result in a very 

significant and complex operation at either the origin or destination of a pipeline. Since many 

interstate pipelines have blending facilities on one end or the other, the manifolds in which such 

 

11 For small-scale operations, wastes generated at pump stations are temporarily stored and then removed by 

vacuum tanker to off-site treatment or disposal facilities. 

12 Shutting down a pipeline is a complex operation. Pumps must be shut down and valves closed in a specific 

sequence to prevent overpressurization of some segments of the pipeline. Check valves that would prevent 

product within the pipeline from reversing flow and running downhill when pumps are stopped must also be 

closed in a specific sequence. 
 9 

blending is accomplished can be elaborate and have much more piping than what would 

normally be required for simple movements from one location to another. Such blending 

facilities may also be present within a pipeline ROW in a centralized corridor. 

1.4.7 Pigging Stations 

Pipeline operators may incorporate the use of pigs, depending on the nature and quality 

(purity) of the materials being transported. Pigs can be designed to clean accumulated sludge and 

debris off the inside walls of a pipe, or to monitor the pipe for conditions such as corrosion 

(known as “smart pigs”). Pigs are introduced at launching facilities located along the mainline 

pipe ROW, often in conjunction with a pump station. The pig’s outer diameter is the same as, or 

slightly larger than the internal diameter of the pipe, so that a portion of the pig is compressed 

when placed inside. In most instances, the pig itself has no power source to propel it along the 

pipe, but instead is carried along the pipe by the flow of the liquid in the pipe. Obviously, pigs 

must be removed before reaching the next pump station. Such pig recovery stations are typically 

immediately upstream of the next downstream pump station. Depending on the product and the 

age of the pipeline, cleaning and monitoring pigs are routinely introduced into and recovered 

from the pipeline without any interruption of pipeline operations. Data recorded by smart pigs 

are typically integrated with the data from the pipeline’s supervisory control and data acquisition 

(SCADA) system (see below) and are used to control inspection, maintenance, and repair 

activities. See Section 2.1.13 for an additional discussion of the various types and applications of 

pigs. 

1.4.8 Supervisory Control and Data Acquisition (SCADA) Systems 

Pipelines are monitored and operated using sophisticated SCADA systems. SCADA 

systems regulate pressure and flow by monitoring and controlling pump operation and the 

positions of valves. SCADA systems also perform a variety of additional functions including 

alarm processing, leak detection, hydraulic analysis, pump station monitoring, throughput 

analysis, and other functions deemed critical to the safe operation of the pipeline. 

Section 2.1.15.1 provides an expanded discussion on how SCADA systems are used to monitor 

and control the operations of a pipeline. 

1.4.9 Telecommunication Towers 

SCADA systems, regardless of their degree of sophistication, are only as good as the 

communication system that transmits data and commands throughout the pipeline system. A 

communication system includes equipment, such as telecommunication towers, and cabling to 

provide voice and/or data communications to the various facilities along the pipeline as well as 

to the SCADA system components. Real-time data communications are necessary between the 

control center, the various pump stations, storage/distribution terminals, delivery facilities, and 

mainline block valve sites. 
 10 

Real-time operational data communications can be supported through a combination of the 

following approaches: telephone company circuits, satellite terminals, microwave, point-to-point 

radio pairs, and fiber optic cable. Often, pipeline systems employ redundant communication 

links to ensure that critical data are communicated in the event of a failure in one of the systems. 

1.4.10 Mass Flow Meters 

There are two types of flow meters used in liquid pipeline systems. The first type is 

referred to as a volumetric flow meter. In the oil industry, the majority of transfers and sales are 

measured in volumetric units such as barrels or gallons, so this type of meter is usually applied. 

In other instances such as for petrochemicals, flow rates are measured in units of pounds by a 

mass meter. With both types of flow meters, the accuracy of the measurements is periodically 

checked by a “meter prover.” This process is conducted to insure the accuracy of the measured 

flow quantities. Flow meters are commonly used where custody transfers or sales are involved. 

Flow meters also offer the pipeline operator the opportunity to monitor for any leaks by 

performing volume or mass balance checks around specified sections of the pipeline network. 

These balance checks would typically be performed via the SCADA computer system. 

1.4.11 Valves 

Valve types and locations comprise an important facet of liquid pipeline design and 

operation. Valves located in the mainline must be compatible with pigging equipment. Valve 

location is a critical design issue to insure that discrete portions of the line can be isolated in the 

event of a line leak or when maintenance is required.13 Check valves that would prevent 

backflows of product down grades in the event of loss of power to pipeline pumps are also 

essential to prevent overpressurization of pipe segments at the base of grade changes. 

1.4.12 Corrosion Control Systems 

Corrosion control of pipeline systems primarily composed of steel and other metals is 

critical to system integrity. Buried metallic objects will corrode (chemically oxidize) through 

participation in electrochemical reactions if not adequately protected. Corrosion control is 

accomplished through a variety of means. In most instances, paints and protective coatings are 

applied followed by wrapping and taping sections of mainline pipe prior to burial to isolate the 

metallic pipe and prevent its participation in electrochemical reactions. In addition, cathodic 

protection is provided through the use of an impressed current or sacrificial anodes to counteract 

 

13 In some instances, valve placement is dictated by environmental factors. For example, mainline valves for TAPS 

are spaced such that no more than a prescribed amount of product would exist in the segment of pipe between 

any two valves or a valve and a pump station. Thus, valve spacing limits the amount of product that can be 

released to the environment in the event of catastrophic failure (relying on the SCADA system to identify the 

failure as a precipitous drop in system pressure and to automatically shut valves to isolate the apparent problem). 
 11 

those electrochemical reactions. Various polyethylene- or epoxy-based paints, some also 

including asphalt and/or coal tar, are used for buried pipe and valves. 

Cathodic protection involves either the use of an impressed current or sacrificial 

(or galvanic) anodes. For impressed-current systems, anodes are buried in the soil proximate to 

the section of buried pipe being protected. A current is applied to the anodes equivalent to the 

current that would result from the electrochemical oxidation of the pipe. This current is allowed 

to flow through the soil to the pipe which then completes the circuit. This impressed current 

counterbalances the flow of electrons from the pipe to the soil that would otherwise have resulted 

from the pipe’s oxidation, thereby canceling that reaction.. Impressed-current systems can be 

monitored from the ground as a demonstration of their continued proper performance. Unless 

malfunctions occur, impressed-current system components that are buried with the pipe will 

typically not need replacement for 20 to 25 years, and many last over the lifetime of the pipe. 

SCADA systems can be configured to monitor the performance of impressed-current systems. 

Alternatively, individuals using monitoring devices can check their performance (i.e., measure 

the voltage being applied to the pipe) at ground-level monitoring points installed along the length 

of the pipeline. 

An alternative to impressed-current systems is the use of galvanic electrodes. Electrodes 

composed of magnesium or zinc, both of which corrode more easily than the iron in the pipe, are 

electrically bonded to and buried along side of the pipe. Current is allowed to naturally flow 

from the pipe to the ground; however, it is the zinc or magnesium in the electrodes that looses 

electrons in the process. Thus, the electrodes are “sacrificed” to protect the iron pipe. Galvanic 

electrodes must be replaced periodically. Site-specific conditions of soil moisture and electrical 

conductivity determine the proper anode replacement intervals. Typically, such site-specific 

conditions are determined using a test electrode placed in virtually the identical electrochemical 

environment, but not connected in any way to the pipeline and easily recoverable, so that the 

extent of its degradation can be observed and replacement intervals established for the electrodes 

attached to the pipe, and excavations to expose those electrodes for replacement can be done 

only as necessary. 
 12 
 13 

2 PIPELINE DESIGN 

2.1 FACTORS INFLUENCING PIPELINE DESIGN 

2.1.1 General Pipeline Design Considerations 

The major steps in pipeline system design involve establishment of critical pipeline 

performance objectives and critical engineering design parameters such as: 

• Required throughput (volume per unit time for most petroleum products; 

pounds per unit time for petrochemical feedstocks); 

•

• Origin and destination points; 

•

• Product properties such as viscosity and specific gravity; 

•

• Topography of pipeline route; 

•

• Maximum allowable operating pressure (MAOP); and 

•

• Hydraulic calculations to determine: 

•

• Pipeline diameter, wall thickness, and required yield strengths; 

•

• Number of, and distance between, pump stations; and 

•

• Pump station horsepower required.14

2.1.2 Safety 

Safety in pipeline design and construction is achieved by the proper design and 

application of the appropriate codes and system hardware components, as detailed above. Design 

codes as set forth in U.S. Department of Transportation’s (DOT’s) Office of Pipeline Safety 

(OPS) regulations provide appropriate safety factors and quality control issues during 

construction. Metering stations and SCADA systems provide continuous monitoring oversight of 

pipeline operations. Training of pipeline operating and maintenance personnel is also a key 

ingredient in the ongoing efforts to insure system integrity and safety. Safe operations result 

from developing and strictly adhering to standard procedures and providing the workforce with 

 

14 As a practical matter, equipment selection and operating parameters are determined based on such factors as the 

density of the commodity to be transported, the desired throughput, delivery schedules committed to by the 

pipeline operator, and overall costs associated with ROW acquisition and construction and operating costs of 

sample components. 
 14 

adequate training, safety devices, and appropriate personal protective equipment. Standard 

operating procedures typically are developed with reference to government and standard industry 

practices, as well as corporate safety policies, experience, philosophy, and business practices. 

Regulations promulgated by the Occupational Safety and Health Administration (OSHA) and by 

counterpart agencies at the state level specify the procedures and controls required to ensure 

workplace safety, including, in some instances, the performance of process safety analyses and 

the development of very specific procedures for activities thought to represent potentially 

significant hazards to workers and the public. 

2.1.3 Industry Codes and Standards 

The ASME has a long history of developing standards for use in the oil and gas pipeline 

industry. The scope of the first draft of the ASME Code for Pressure Piping, which was approved 

by the American Standards Association in 1935, included the design, manufacture, installation, 

and testing of oil and gas pipelines (ASME B31.4). As the needs of the industry evolved over the 

years, rules for new construction have been enhanced, and rules for operation, inspection, 

corrosion control, and maintenance have been added. In addition to ASME, several other 

organizations, including the API and the National Association of Corrosion Engineers 

(now known as NACE International), also develop standards used by the pipeline industry.15

The industry adheres to the following summary of standards:16

• Tank operation and construction (15 standards maintained by a committee 

operated by API) 

• Underground storage caverns (2 API standards) 

• Manufacture of line pipe (4 API standards) 

• Cathodic protection against corrosion (8 NACE standards and guides) 

• Welding (15 American Welding Society [AWS] and 1 API standards) 

• Pipeline awareness (2 API standards) 

 

15 ASME codes can be purchased for electronic download from the ASME website at http://store.asme.org/ 

category.asp?catalog_name=Codes+and+Standards&category_name=&Page=1&cookie%5Ftest=1. (Accessed 

December 6, 2006.) 

 A catalogue of all API publications, including national consensus standards, is available for download at 

http://www.api.org/Publications/. (Accessed December 6, 2006). Ordering information for standards may also be 

found there. 

 NACE International standards can be purchased for electronic download at http://www.nace.org/ 

nacestore/dept.asp?Cat%5FID=2905. (Accessed December 6, 2006.) 

16 Association of Oil Pipelines – Regulations and Standards. Available at https://www.piersystem.com/external/ 

index.cfm?cid=888&fuseaction=EXTERNAL.docview&documentID=57733. (Accessed February 2, 2007.) 
 15 

• Pipeline integrity (API Recommended Practice 1129, “Assurance of 

Hazardous Liquid Pipeline System Integrity”) 

• Pipeline wall thickness (API Standard B31.G) 

The following is a list of some of the primary standards governing pipeline design, 

manufacturing, construction, and operation: 

• API standards (including standards issued jointly by ANSI): 

− “Pipeline Maintenance Welding Practices,” 3rd edition, API 

Recommended Practice (RP) 1107 

− “Specification for Pipeline Valves (Gate, Plug, and Check Valves),” 

21st edition, API 6D1, June 1998 Supplement 2 

− “Welding of Pipelines and Related Facilities,” ANSI/API Std. 1104, 

September 1999 

− “Specification for Line Pipe,” API 5L, March 2004 

− “Specification for Line Pipe,” API 5L Errata 1, January 2005 

− “Steel Pipelines Crossing Railroads and Highways,” API 1102 (1993) 

− “Marking Liquid Petroleum Pipeline Facilities,” 3rd edition, API 1109, 

July 2003 

− “Developing a Pipeline Supervisory Control Center,” API 1113, 

February 2000 

− “Movement of In-Service Pipelines,” ANSI/API 1117, August 1996 

− “Computational Pipeline Monitoring for Liquids Pipelines,” API 1130, 

November 2002 

− “Pipeline Variable Uncertainties and Their Effects on Leak Detectability,” 

API 1149, November 1993 

− “Evaluation Methodology for Software-Based Leak Detection Systems,” 

API 1155, February 1996 

− “Hydrostatic Test Water Treatment and Disposal,” API 1157, October 

1998 
 16 

− “Managing System Integrity for Hazardous Liquid Pipelines,” API 1160, 

November 2001 

− “In-Line Inspection Systems Qualification Standard,” 1st edition, 

API 1163, August 2005 

− “Pressure Testing of Liquid Petroleum Pipelines,” ANSI/API RP 1110, 

March 1997 

− “Repairing Crude Oil, Liquid Petroleum Gas, and Product Pipelines,” 

3rd edition, API RP 2200, May 1994 

− “Steel Pipelines Crossing Railroads and Highways,” API RP 1102, 

January 1993 

• ASTM standards17

• ASME standards18

− “Boiler and Pressure Vessel Code,” 2004 (triennial updates) 

− “Gas Transmission and Distribution Piping Systems,” ASME B31.8, 1999 

− “Refrigeration Piping,” ASME B31.5 and Addenda B31.5A, 1994 

− “Pipeline Transportation Systems for Liquid Hydrocarbons and Other 

Liquids,” ASME B31.4, 1998 

− “Power Piping,” ASME B31.1, 1998; Addenda B31.1A, 1999; 

Addenda B31.1B, 2000 

− “Process Piping,” ASME B31.1, 1999; Addenda B31.3A, 1999 

− “Slurry Transportation Piping Systems,” ASME B31.11, 1989; 

Addenda B31.11A, 1991 

− “Pipeline Transportation Systems for Liquid Hydrocarbons and Other 

Liquids,” ASME B31.4, 2002 

− “Gas Transmission and Distribution Systems,” ASME 31.8, 2003 

 

17 Numerous ASTM standards apply. ASTM standards can be purchased for electronic download at the ASTM 

website: http://webstore.ansi.org/ansidocstore/astm.asp. (Accessed December 5, 2006.) 

18 ASME standards are available for electronic purchase at http://store.asme.org/category.asp?catalog_name= 

Codes+and+Standards&category_name=&Page=1. (Accessed December 6, 2006.) 
 17 

− Annual Book of ASTM Standards, Volume 6: Paints, Related Coatings, 

and Aromatics; Section 6.02: Paint – Products & Applications; Protective 

Coatings; Pipeline Coatings 

• Institute of Electrical and Electronics Engineers, Inc. (IEEE), National 

Electrical Safety Code, 200719

• International Association of Plumbing and Mechanical Officials (IAPMO), 

Uniform Plumbing Code, 2003 (an American National Standards Institute 

national consensus standard)20 

• International Conference of Building Officials, Uniform Building Codes 

(13 codes in all), 200721

• International Conference on Building Officials, Uniform Fire Code,

2006 edition22

• National Fire Protection Association, National Electrical Code Handbook,

2005 edition23 

A December 2001 report for the API’s Pipeline Committee contains an interesting 

discussion on the evolution of pipeline technologies and standards, covering milestones from the 

first United States cast iron pipe in 1834 to the publication of API Standard 1160 in November 

2001 (Kiefner 2001). 

2.1.4 Pipeline Coating 

Corrosion-resistant coatings are applied to the exteriors of most pipes to inhibit corrosion. 

These may be applied at the manufacturing plant or a pipe coating plant located separately. 

However, coatings are also sometimes applied at the construction site. Even for precoated pipe, 

field dressings of joints and connections are also performed at the construction site just prior to 

burial. For particularly corrosive products (including some crude oils with high total acid 

numbers), pipes are also sometimes coated on the inside for corrosion resistance. In addition to 

the resistance to corrosion they provide, some interior coatings are also designed to reduce 

 

19 IEEE standards are available for electronic download at http://standards.ieee.org/nesc/. (Accessed 

December 6, 2006.) 

20 The IAPMO Uniform Plumbing Code is available for electronic purchase at http://www.nfpa.org/catalog/ 

product.asp?pid=res10703&src=catalog&cookie%5Ftest=1. (Accessed December 6, 2006.) 

21 Uniform Building Codes, published by the International Conference of Building Officials, are available for 

electronic purchase at http://www.techstreet.com/cgi-bin/browsePublisher?publisher=ICBO&orderBy=doc_no. 

(Accessed December 5, 2006.) 

22 The Uniform Fire Code is available for electronic purchase at http://www.nfpa.org/aboutthecodes/ 

AboutTheCodes.asp?DocNum=1. (Accessed December 6, 2006.) 

23 The National Electric Code Handbook is available for electronic purchase at http://www.nfpa.org/catalog/ 

product.asp?pid=70HB05&order_src=A291. (Accessed December 6, 2006.) 
 18 

frictional losses between the product and the interior walls of the pipe, thereby reducing the total 

amount of energy required to move the materials along the pipeline.24. Protective wrappings, 

followed by the application of tape to the edges of the spirally applied overlapping wrapping, are 

often installed on the exterior of the pipe to further assist in corrosion control, but also to 

primarily protect the pipe from mechanical damage at installation. Wraps and tape often are 

impregnated with tar or other asphalt-based materials and heated in place once applied, to ensure 

uniform coverage. Once cured, the exterior coatings are chemically stable and environmentally 

inert, resisting degradation by soil moisture and bacteria, yet remaining sufficiently flexible that 

they continue to provide a protective coating on the pipe throughout a wide temperature range. 

Likewise, wrapping materials and tape are stable and inert (including toward the material being 

transported in the pipeline) and do not pose a potential for adverse environmental impacts. 

Figure 2.1-1 illustrates installation of an exterior pipe tape wrap prior to the pipe’s installation in 

its trench. Other coatings, such as thin-film epoxy and extruded polymers are also used as 

alternative to wraps and asphaltic coatings. 

Depending on local soil conditions, material of uniform size is sometimes imported to the 

construction site to form a bed on which the pipe is placed. The same material may also be 

installed around the sides and top of the pipe before the trench is filled with indigenous soils. 

Such bedding material serves two principal functions: protection of the pipe from mechanical 

FIGURE 2.1-1 Coating Newly Installed Pipe for Corrosion 

Control (Source: Photo courtesy of Corrosion Control 

Products Co. Reproduced with permission.) 

 

24 Even with noncorrosive commodities, interior coatings are sometimes applied for the reduction of frictional 

losses they provide. Such interior coatings may also be used in conjunction with chemical additives that are 

sometimes added to especially viscous petroleum commodities such as crude oils with API gravities of 10 or less 

to reduce frictional losses. 
 19 

damage during installation and trench filling, and stabilization of the pipe in the event of seismic 

shifts or frost heaves. Sands and gravels are typical bedding materials and are tamped in lifts of 

12 to 18 inches per lift to ensure adequate compaction and avoid future subsidence. Bedding 

materials also assist in draining accumulated water from the vicinity of the pipe. 

All newly coated pipe used to transport hazardous liquids must be electrically inspected 

prior to backfilling to check for faults not observable by visual examination. Material faults such 

as microcracks demonstrate a characteristic response to applied current when the detector is 

operated in accordance with the manufacturer’s instructions and at the voltage level appropriate 

for the electrical characteristics of the coating system being tested. 

2.1.5 Sizing 

The dimensions of a pipeline — both the sizes and capacities of the various 

components — as well as the conditions under which the pipeline system operates dictate the 

system’s capacity. Larger diameter pipes allow for higher mass flows of materials, provided 

other components of the pipeline system, primarily pumps and pressure management devices, are 

properly sized and positioned. In general, the longer the segment of mainline pipe between pump 

stations, the greater the drop in line pressure. However, grade changes and the viscosity of 

the materials being transported can also have major influences on line pressures. API Standard 

5L provides dimensions, weights, and test pressures for plain-end line pipe in sizes up to 

80 inches in diameter. Several weights are available in each line pipe diameter. The weight of the 

pipe in lb/ft, in turn, varies as the wall thickness for a given outside diameter. For instance, API 

Spec 5L lists 24 different weights in the 16-inch-diameter size (five weights are special weights), 

ranging from 31.75 lb/foot to 196.91 lb/foot. The corresponding wall thickness ranges from 

0.188 inch to 1.250 inches. As the wall thickness increases for a given outside diameter, the 

inside diameter of the pipe decreases from 15.624 inches for the lightest weight pipe to 

13.500 inches for line pipe weighing 196.91 lb/foot. Greater wall thicknesses are selected for 

high-pressure applications or when the pipe segment might be subjected to unusual external 

forces such as seismic activities and landslides.25 Also, in hard-to-reach places, such as beneath 

transportation routes and at river crossings or difficult-to-access environmentally sensitive areas, 

overbuilding in size or quality is sometimes chosen to accommodate future expansion 

requirements. 

2.1.6 Pressure 

Operating pressure of a pipeline is determined by the design flow rate vapor pressure of 

the liquid, the distance the material has to be transferred, and the size of line that carries the 

liquid. Pipe operating pressure and pump capabilities and cost typically drive decisions on line 

 

25 Landslides would not necessarily directly impact buried pipe unless the slide action itself were to expose the 

pipe, making it subject to forces from additional landslide materials. However, even when the pipe is not 

exposed, landslides may cause substantial amounts of material to end up on the ground above the buried pipe, 

where the extra weight could crush or deform the buried pipe. 
 20 

size, the number of pump stations, and the like. Grades notwithstanding, line pressure follows a 

sawtooth curve between pump stations. The maximum and minimum line pressure that can be 

tolerated, together with the physical properties of the materials noted earlier, dictate the spacing 

of the pump stations and the motive horsepower of the pumps. 

2.1.7 Product Qualities 

 As noted earlier, critical physical properties of the materials being transported dictate the 

design and operating parameters of the pipeline. Specific gravity, compressibility, temperature, 

viscosity, pour point, and vapor pressure of the material are the primary considerations. These 

and other engineering design parameters are discussed in the following sections in terms of their 

influence on pipeline design. 

2.1.7.1 Specific Gravity/Density 

The density of a liquid is its weight per unit volume. Density is usually denoted as 

pounds of material per cubic foot. The specific gravity of a liquid is typically denoted as the 

density of a liquid divided by the density of water at a standard temperature (commonly 60°F). 

By definition, the specific gravity of water is 1.00. Typical specific gravities for the distilled 

petroleum products gasoline, turbine fuel, and diesel fuel are 0.73, 0.81, and 0.84, respectively.26

2.1.7.2 Compressibility 

Many gases that are routinely transported by pipeline are highly compressible, some 

turning into liquids as applied pressure is increased. The compressibility of such materials is 

obviously critical to pipeline design and throughput capacity. On the other hand, crude oils and 

most petroleum distillate products that are transported by pipeline are only slightly compressible. 

Thus, application of pressure has little effect on the material’s density or the volume it occupies 

at a given temperature; consequently, compressibility is of only minor importance in liquid 

product pipeline design. Liquids at a given temperature occupy the same volume regardless of 

pressure as long as the pressure being applied is always above the liquid’s vapor pressure at that 

temperature. 

 

26 The density of petroleum products is more commonly expressed as API gravity, a measurement convention 

independently established by the American Petroleum Institute for expressing the relative density of petroleum 

liquids to water; the greater the API gravity, the less dense the material. API gravities are close to, but not 

equivalent to specific gravities measured in the Baumé scale, the more conventional method of representing the 

density of a liquid; API gravity = (141.5/specific gravity at 60°F) – 131.5; thus, a petroleum liquid with an 

API gravity of 10.0 at 60°F has a specific gravity of 1.0 (same as water). Petroleum liquids with API gravities 

greater than 10 have densities less than water and will float; those with API gravities less than 10 will sink; the 

API gravity scale is calibrated such than most petroleum liquids (crude oils as well as distillate fuels) will have 

API gravities between 10 and 70 API gravity degrees. 
 21 

2.1.7.3 Temperature 

Pipeline capacity is affected by temperature both directly and indirectly. In general, as 

liquids are compressed — for example, as they pass through a pump — they will experience 

slight temperature increases. Most liquids will increase in volume as the temperature increases, 

provided the pressure remains constant. Thus, the operating temperature of a pipeline will affect 

its throughput capacity. Lowering temperatures can also affect throughput capacity, as well as 

overall system efficiency. In general, as the temperature of a liquid is lowered, its viscosity 

increases, creating more frictional drag along the inner pipe walls, requiring greater amounts of 

energy to be expended for a given throughput volume. Very viscous materials such as crude oils 

exhibit the greatest sensitivity to the operating temperatures of their pipelines. However, in the 

case of crude oils, the impacts are not only from increases to viscosity, but also due to the 

solidification of some chemical fractions present in the oils. For example, crude oils with high 

amounts of paraffin will begin to solidify as their temperature is lowered, and they will become 

impossible to efficiently transport via a pipeline at some point. 

2.1.7.4 Viscosity 

From the perspective of the pipeline design engineer, viscosity is best understood as the 

material’s resistance to flow. It is measured in centistokes. One centistoke (cSt) is equivalent to 

1.08 × 10–5 square feet per second. Resistance to flow increases as the centistoke value (and 

viscosity) increases. Overcoming viscosity requires energy that must be accounted for in pump 

design, since the viscosity determines the total amount of energy the pump must provide to put, 

or keep, the liquid in motion at the desired flow rate. Viscosity affects not only pump selection, 

but also pump station spacing. Typical viscosities for gasoline, turbine, and diesel fuels are 0.64, 

7.9, and 5 to 6 cSt, respectively. 

As the material’s viscosity increases, so does its frictional drag against the inner walls of 

the pipe. To overcome this, drag-reducing agents are added to some materials (especially some 

crude oils). Such drag-reducing agents are large molecular weight (mostly synthetic) polymers 

that will not react with the commodity or interfere with its ultimate function. They are typically 

introduced at pump stations in very small concentrations and easily recovered once the 

commodity reaches it final destination. However, often, no efforts are made to separate and 

remove these agents. Drag reduction can also be accomplished by mixing the viscous commodity 

with diluents. Common diluents include materials recovered from crude oil fractionation such as 

raw naphtha. Diluents are used to mix with viscous crude feedstocks such as bitumen recovered 

from tar sands and other very heavy crude fractions to allow their transport by pipeline from 

production areas to refineries. 

2.1.7.5 Pour Point 

The pour point of a liquid is the temperature at which it ceases to pour. The pour point for 

oil can be determined under protocols set forth in the ASTM Standard D-97. In general, crude 
 22 

oils have high pour points. As with viscosity, pour points are very much a function of chemical 

composition for complex mixtures such as crude oils and some distillate products, with pour 

point temperatures being influenced by the precipitation (or solidification) of certain 

components, such as paraffins. 

Once temperatures of materials fall below their respective pour points, conventional 

pipeline design and operation will no longer be effective; however, some options still exist for 

keeping the pipeline functional. These include: 

• Heating the materials and/or insulating the pipe to keep the materials above 

their pour point temperature until they reach their destination. 

• Introduce lightweight hydrocarbons that are miscible with the material, 

thereby diluting the material and lowering both its effective viscosity and pour 

point temperature. 

• Introduce water that will preferentially move to the inner walls of the pipe, 

serving to reduce the effective coefficient of drag exhibited by the viscous 

petroleum product. 

• Mix water with the petroleum material to form an emulsion that will exhibit 

an effective lower viscosity and pour point temperature. 

• Modify the chemical composition before introducing the material into the 

pipeline, removing those components that will be first to precipitate as the 

temperature is lowered. (This tactic is effective for crude oils, but is virtually 

unavailable when moving distillate products that must conform to a specific 

chemical composition.) 

Waxy crude can be pumped below its pour point; more pumping energy is required, but 

there is no sudden change in fluid characteristics at the pour point as far as pumping 

requirements are concerned. However, if pumping is stopped, more energy will be required to 

put the crude in motion again than was required to keep it flowing. When flow is stopped, wax 

crystals form, causing the crude to gel in the pipeline. If gelling occurs, the crude behaves as if it 

had a much higher effective viscosity; consequently it may take as much as five to ten times the 

energy to reestablish design flows in the pipeline than it did to support stable continuous 

operation when the crude’s temperature was above its pour point. 

For some products such as diesel fuels that still contain some waxy components 

(i.e., saturated, long-chain hydrocarbons), “gelling” may also occur as temperatures are lowered; 

however, such gelling problems are commonplace in storage tanks and vehicle fuel tanks where 

the fuel sits motionless for long period of time, but rarely materialize in pipelines where the 

materials are virtually in constant motion and where their passage through pumps typically 

imparts some amount of heat. Nevertheless, precipitation or gelling of products contained in 

pipelines can cause significant operational difficulties and may also result in environmental 
 23 

impacts if pipeline ruptures occur during attempts to restart the flow, when a pressure well above 

design limits could result. 

2.1.7.6 Vapor Pressure 

The vapor pressure of a liquid represents the liquid’s tendency to evaporate into its 

gaseous phase with temperature. Virtually all liquids exhibit a vapor pressure, which typically 

increases with temperature. The vapor pressure of water increases steadily with temperature 

increases, reaching its maximum of one atmosphere pressure (760 mm Hg, or 14.7 psi absolute 

[psia]) at the boiling point (212°F). 

Vapor pressures of petroleum liquids are determined using a standardized testing 

procedure and are represented as the Reid vapor pressure. Reid vapor pressures are critical to 

liquid petroleum pipeline design, since the pipeline must maintain pressures greater than the Reid 

vapor pressure of the material in order to keep the material in a liquid state. Blended (or 

“boutique”) vehicle fuels, required over some periods of the year for air pollution control 

purposes in some parts of the country, have unique chemical compositions and unique Reid 

vapor pressures (as mixtures). Consequently, pipelines handling such fuels must constantly 

monitor their vapor pressure and adjust operating conditions accordingly. Pipelines carrying 

liquids with high vapor pressures can be designed to operate under a variety of flow regimes. 

Single-phase flow regimes intend for the entire amount of the material in the pipeline to be in the 

liquid state. Operators of single-phase liquid pipelines attempt to control pressure and flow to 

maintain a “full face” of liquids in the pipeline, minimizing the amount of volatilization that is 

allowed to occur. This maximizes system efficiency and also the longevity of system 

components. Failure to maintain a full face of liquids in a single-phase liquid pipeline can result 

in increased risks of fires and explosions. Single-phase liquid pipelines are the most common 

designs for petroleum liquids. However, pipelines can also be designed as two-phase systems in 

which both vapor and liquid phases of the material are expected to be present. The variation of 

flow regimes in such two-phase systems can range from bubbles of vapor distributed in liquid to 

droplets of liquid suspended in vapor. Typical vapor pressures for gasoline, turbine fuel, and 

diesel fuel are 15, 2, and 2 psia, respectively. 

2.1.7.7 Reynolds Number 

The Reynolds number, named after Osborne Reynolds, the scientist who first proposed its 

usefulness in studying fluid dynamics, is a dimensionless number that represents the ratio of the 

inertial force to the viscous force — that is, the ratio of the force moving a fluid to the force that 

attempts to resist that movement. In a pipeline, the inertial force is related to the fluid’s velocity, 

which is a function of the force applied to it by the pumps. The viscous force is a product of the 

inherent viscosity of the fluid as well as the frictional drag created by interaction of the fluid with 

the interior surface of the pipeline. A low value for a Reynolds number (<2100) suggests that the 

fluid will be moved evenly, so-called laminar flow. Higher Reynolds numbers indicate that 

forces applied to a fluid are much greater than the forces resisting its movement; consequently its 

movement will be violent and turbulent. The Reynolds number representing the transition zone 
 24 

between laminar and turbulent flows is called the critical Reynolds number (Rcrit), which is 

typically assigned a value of 2320. The Reynolds number depends on the force applied by 

pumps, the material’s viscosity at operating temperature, and the physical size and crosssectional shape of the pipe through which the material is moving. Most pipeline designers select 

these components to establish operating conditions near Rcrit while still delivering the desired 

throughput.27

2.1.7.8 Darcy Friction Factor 

Named after the French engineer Henry Darcy, the Darcy friction factor is a 

dimensionless number that represents the linear relationship between the mean velocity of a 

moving fluid and the pressure gradient. The Darcy friction factor is critical in determining the 

necessary force capabilities of pumps as well as the spacing between pump stations to create the 

desired flow (and thus throughput) of a liquids pipeline. 

2.1.8 Other Design Considerations 

2.1.8.1 Thermal Stresses 

Except where local conditions prevent it, petroleum pipelines are typically buried. Burial 

depths vary with geographic location, but are typically designed to ensure that the entirety of the 

pipe is below the local frost line. At such depths, the ambient soil temperatures are relative 

constant with season, although some minor variations can occur. Despite predictably stable 

temperature environments, pipeline design also accounts for thermal stresses, both expansions 

and contractions for the pipe and other components. Expansion joints are employed, and, in some 

instances, trenches are made extra-wide to allow for lateral movements of the pipe with 

temperature. Thermal expansion joints, or loops, are also critical in locations where conditions 

require the pipe to be above ground, for example, at some river crossings. 

Thermal stress on pipeline components can also come from internal forces. The vapors of 

certain volatile hydrocarbon fuels will cause supercooling of the remaining liquids, if allowed to 

escape from the pipeline system at significant rates. Such supercooling can result in thermal 

cracking of pipes and pump housings. 

 

27 Laminar flow represents a condition of greatest overall efficiency, while turbulent flow introduces vibration and 

generally accelerates the wear on system components and increases the potential for system failure. Laminar 

flow is thus the preferred operating condition. However, economic performance requirements necessitate that 

pipelines be operated at a rate that induces turbulent flows for most commodities. Design and operational 

accommodations including the use of drag-reducing agents are utilized to mitigate the negative effects while still 

preserving the necessary economic margins. 
 25 

2.1.8.2 Soil and Load Design Considerations 

During the design and site preparation phases, soil samples are taken at many points 

throughout to determine mechanical and thermal stability, corrosivity, and electrical 

conductance. Soils and subsurface materials are also evaluated for their ability to support the 

weight of the pipeline support facilities at sensitive areas, such as river crossings. Soil properties 

such as seepage, slope stability, tensile strength, and soil structure are determined. Industry 

standards published by the American Society of Civil Engineers (ASCE) outline the necessary 

site characterization studies (ASCE 2001). In addition to engineering considerations, site 

characterizations regarding the presence of threatened or endangered plant species and soil 

organisms may also need to be conducted. 

2.1.8.3 Vertical External Load 

Under most conditions, the internal pressures imposed on the pipe by moving fluids far 

exceed the static pressures on the pipe from the weight of backfill and soil material above it. 

Consequently, vertical external loading is not typically a matter of serious concern to pipeline 

designers. However, there are some circumstances where vertical loading becomes critical, 

including when pipelines pass beneath rivers, railroads, or highways (also see the discussion 

below on dynamic vertical loads) or in areas with high snowfall or landslide potential. 

2.1.8.4 Surface Live Loads 

In addition to supporting dead loads imposed by earth cover, buried pipes may also be 

exposed to superimposed concentrated or distributed live loads. Large concentrated loads, such 

as those caused by truck-wheel loads, railway cars, and locomotive loads, are of most practical 

interest. 

Depending on the requirements of the design specification, the live-load effect may be 

based on American Association of State Highway and Transportation Officials (AASHTO) 

HS-20 (AASHTO 1998) truck loads or American Railway Engineering Association (AREA) 

Cooper E-80 railroad loads (AREMA 2006), as indicated in Table 2.1-1. The values of the liveload pressure, Pp, are given in psi and include an impact factor F = 1.5 to account for bumps and 

irregularities in the travel surface. Other important impact factors are listed in Table 2.1-2. Note 

that live loads depend on the depth of cover over the pipe and become negligible for HS-20 loads 

when the earth cover exceeds 8 feet, and for E-80 loads when the cover exceeds 30 feet. Casings 

can also be used to enhance the protection of the pipe. 

Other impacts of loads on pipelines can be deforming the pipe (ovalizing), through-wall 

bending, crushing side walls, and ring buckling. Because ovalizing the pipe will affect the 

Reynolds number, the pipeline throughput capacity would also be impacted by such 

deformations, and the deformed pipeline itself would be subject to accelerated wear and an 
 26 

TABLE 2.1-1 Live Loads 

Live Load Transferred to Pipe (lb/square inch) 

 

Live Load Transferred to Pipe (lb/ square inch) 

Height of 

Cover (ft) Highway H20a Railway E80b

 

Height of 

Cover (ft) Highway H20a Railway E80b

 

 1 12.5 –c 14 d 4.17 

 2 5.56 26.39 16 d 3.47 

 3 4.17 23.61 18 d 2.78 

 4 2.78 18.40 20 d 2.08 

 5 1.74 16.67 22 d 1.91 

 6 1.39 15.63 24 d 1.74 

 7 1.22 12.15 26 d 1.39 

 8 0.69 11.11 28 d 1.04 

10 d 7.64 30 d 0.69 

12 d 5.56 35 d d 

a Simulates a 20-ton truck traffic load, with impact. 

b Simulates an 80,000 lb/foot railway load, with impact. 

c Dash corresponding to Railway E-80, and 1-foot height of cover is nonapplicable. 

d Negligible influence of live load on buried pipeline. 

TABLE 2.1-2 Impact Factors 

for Highways and Railroads 

Versus Depth of Cover 

Installation Surface Condition 

Depth of 

Cover (feet) Highways Railroads 

 

0 to 1 1.50 1.00 

1 to 2 1.35 1.00 

2 to 3 1.15 1.00 

Over 3 1.00 1.00 

Note: Data available from AREMA 
 27 

increased potential for failure. Where buried pipe is subjected to large variations in cyclical 

surface loads, as in the case of pipe crossing under railroad tracks or highways, federal, state, or 

local regulations usually specify a minimum burial depth.28 These typically vary from 3 to 

6 feet, depending on the type of crossing, the type of excavation (rock or normal excavation), the 

pipe diameter, and the consequence of failure. For example, API RP 1102, “Steel Pipeline 

Crossing Railroads and Highways,” specifies a minimum depth of cover of 6 feet under railroad 

tracks and 4 feet under highway surfaces. 

If the pipe is buried with less than 2 feet of cover, the continual flexing of the pipe may 

cause a breakup of the road surface. If the pipe is mortar-lined or coated, the deflection limit due 

to the cyclic live load should be limited to an amplitude of 1%. 

2.1.8.5 Buoyancy 

Burying pipelines beneath the natural water table creates unique problems and 

challenges. During periods of saturation of the aquifer, pipeline segments may become buoyant, 

even when filled with product. This results in a net upward force on the pipeline segment that 

could be sufficient to compromise the pipe’s integrity. When such conditions are anticipated, 

special construction techniques need to be employed. Anchoring devices or concrete coatings 

over the corrosion coatings are installed to help the pipe resist the buoyant force. Mechanisms to 

reduce the hydraulic pressure of the groundwater in the local area of the pipeline can also be 

successfully applied. 

2.1.8.6 Movements at Pipe Bends 

When unusual internal or external forces are applied to the pipe, it is most likely to 

respond to such forces by moving at the apex of sidebends, sagbends, and overbends. Forces that 

can cause pipe movement can include a net outward force generated by internal pressure, thermal 

expansions or contractions of the pipe due to temperature extremes, hydraulic pressures from 

groundwater, or seismic activity in the vicinity of the pipe. Natural resistances to such forces 

include the axial stiffness of the pipe itself, the bearing and shear resistance of backfill and 

overburden materials, and the extent to which those materials were compacted during 

construction. 

2.1.8.7 Mine Subsidence 

Areas where extensive longwall mining of coal or other resources has occurred represent 

an increased potential for surface subsidence if mine reclamation activities were inadequate or 

not performed. Although such mining can occur to depths greater than 1,000 feet, collapse of a 

mined cavity can affect all overlying strata, causing bending and sagging of each and ultimately 

forming a subsidence basin at the surface. Typically, the area covered by such subsidence basins 

 

28 See, for example, DOT OPS regulations in Title 49, Part 195, of the Code of Federal Regulations (CFR). 
 28 

is substantially larger than the collapsed mine cavity that caused it. The vertical displacement is 

greatest at the center of a subsidence basin, but is typically less than the original height of the 

collapsed cavity. Vertical displacement as well as tilting and shearing forces throughout the basin 

are of greatest concern for surface structures that lie within the basin’s footprint. Forces on 

buried linear features within the basin’s footprint are unique. The bending moments of the 

sagging overburden strata result in horizontal forces that behave as tensile forces on the outer 

portions of the basin and compressive forces closer to the center of the basin. Depending on its 

exact location within the basin, a buried pipeline can be subjected to both forces. The strengths 

of these forces may be sufficient to buckle pipe or tear pipe connections apart. 

2.1.8.8 Effects of Nearby Blasting 

Blasting in the vicinity of a pipeline typically occurs as a result of mining or nearby 

construction activities. While normally an issue for existing pipelines, blasting effects may be 

considered for new designs if future land-use plans are known to include the construction of an 

adjacent pipeline or the development of mined areas. Pipeline stresses generated by nearby 

blasting can vary greatly, depending on local variations in site conditions, the degree to which 

the blast is confined, delays between multi-shot blasts, and the type of explosive used. 

Expressions for peak radial ground velocity (of the resulting pressure wave) and peak pipe stress 

are based on characterizing the blasting configuration as corresponding to either point or 

parallel-line sources. 

2.1.8.9 Fluid Transients 

Rapid changes in the flow rates of liquid or two-phase piping systems can cause pressure 

transients that generate pressure pulses and transient forces in the piping system. The magnitudes 

of these pressure pulses and force transients are often difficult to predict and quantify. As a result 

of water hammer, an unbalanced impulsive force called a “thrust” load is applied successively 

along each straight segment of a buried pipe. This causes a pressure imbalance between 

consecutive bends. Such hammering actions, if sufficiently strong and continued over long 

periods of time, can compromise the pipe’s integrity or introduce fatigue stress cracks. 

2.1.8.10 In-Service Relocation 

It is commonplace to relocate short pipeline segments without taking the pipeline out of 

service. The process involves careful excavation of the pipe, raising it out of its original trench, 

and placing it into a prepared parallel trench. Obviously, the new path for the pipeline must be 

located generally adjacent and proximate to the original path for this relocation to occur without 

the need of adding new pipe segments. Causes for such relocations include accommodating a 

new highway or rail crossing, performing over-the-ditch coating renovation, inspecting or 

repairing pipe submerged in shallow water, or avoiding encroachment. Even though the physical 

displacements of the pipe are minimal, the newly positioned pipe will be subjected to new 

longitudinal stresses during its move and thereafter. 
 29 

2.1.8.11 Earthquakes and Landslides 

Landslides involve the mass movement of native surface and subsurface materials in the 

uppermost portions of the soil mantle at a moderate to rapid rate (generally greater than 

1 feet/year). Landslides that are characterized as catastrophic in their impacts typically involve 

mass movements that are many orders of magnitude more rapid. However, landslides can also 

involve slow creep of materials over a relatively long period of time to a point where adverse 

impacts result. In most instances, the movement is downslope as a result of gravitational forces, 

often aided by water. Landslides are initiated by a variety of forces and events, both natural 

(e.g., earthquakes, seismic activity, excessive saturation of surface and subsurface soils, and 

volcanism) and anthropogenic (e.g., nearby use of explosives, surface disturbances on steep 

slopes brought about by construction activities without appropriate mitigation, clear-cutting of 

vegetative cover, improper use of herbicides, improper management and release of precipitation). 

Potential earthquake and landslide impacts to buried pipelines include transitory strains caused 

by differential ground displacement and permanent ground displacement from surface faulting, 

lateral spread displacement, soil mass displacement, and settlement from compaction or 

liquefaction.29 

2.1.8.12 Scour at Stream Crossings and Suspended Rock Crossings 

Pipelines buried beneath or adjacent to rivers can be compromised over time by the 

erosive force of the moving water. Scouring can occur that would displace the cover materials 

and expose the pipe, subjecting it to additional lateral forces and possibly even causing sufficient 

displacement to break the pipe. 

High velocities of water in rocky areas or watercourses with steep banks have the highest 

scouring potential. Areas prone to flooding can also experience excessive water flow velocities 

during those periods that can also result in scouring action. The typical response to traversing 

rivers or drainage ways with high scouring potential is to bury the pipe at greater depths or to 

suspend the pipe above these areas. In addition, major river crossings are required to be 

inspected every 5 years for indications of scour and/or exposed pipe. 

2.1.9 Leak Detection30

Beginning on July 6, 1999, under Title 49, Part 195, of the Code of Federal Regulations

(49 CFR Part 195), DOT’s OPS required all controllers of hazardous liquids pipelines engaged in 

 

29 A common consequence of earthquakes or other events involved in severe ground shaking is liquefaction of 

surface materials. Typically liquefaction occurs in soils where the pore space between soil particles is saturated 

with free water. The shaking of the ground causes the water in the pore spaces to exert such force on the soil 

particles that they begin acting independently of one another, resulting in the entire mass of soil taking on the 

properties of a liquid capable of rapid movement and displacement. 

30 Alaska Department of Environmental Conservation, Technical Review of Leak Detection Technologies – 

Volume 1: Crude Oil Transmission Pipelines. Available at http://www.dec.state.ak.us/spar/ipp/docs/ldetect1.pdf. 

(Accessed July 5, 2006.) 
 30 

pipeline leak detection to conform their programs to the objectives contained in the API 

document API 1130, “Computational Pipeline Monitoring.” 

Methods used to detect product leaks along a pipeline can be divided into two categories, 

externally based (direct) or internally based (inferential). Externally based methods detect 

leaking product outside the pipeline, and include traditional procedures such as ROW inspection 

by line patrols, as well as technologies like hydrocarbon sensing via fiber optic or dielectric 

cables. Internally based methods, also known as computational pipeline monitoring, use 

instruments to monitor internal pipeline parameters (i.e., pressure, flow, temperature, etc.), which 

are inputs for inferring a product release by manual or electronic computation (API 1995a). 

The method of leak detection selected for a pipeline depends on a variety of factors 

including pipeline characteristics, product characteristics, instrumentation and communications 

capabilities, and economics (Muhlbauer 1996). Pipeline systems vary widely in their physical 

characteristics and operational functions, and no one external or internal method is universally 

applicable or possesses all of the features and functionality required for perfect leak detection 

performance. Small leaks on large pipelines are very difficult to detect through these automated 

and measurement methods. 

However, the chosen system should include as many of the following desirable leak 

detection utilities as possible (API 1995a): 

• Possesses accurate product-release alarming, 

• Possesses high sensitivity to product release, 

• Allows for timely detection of product release, 

• Offers efficient field and control center support, 

• Requires minimum software configuration and tuning, 

• Requires minimum impact from communication outages, 

• Accommodates complex operating conditions, 

• Is available during transients, 

• Is configurable to a complex pipeline network, 

• Performs accurate imbalance calculations on flow meters, 

• Is redundant, 

• Possesses dynamic alarm thresholds, 
 31 

• Possesses dynamic line pack constant, 

• Accommodates product blending, 

• Accounts for heat transfer, 

• Provides the pipeline system’s real-time pressure profile, 

• Accommodates slack-line and multiphase flow conditions, 

• Accommodates all types of liquids, 

• Identifies leak location, 

• Identifies leak rate, 

• Accommodates product measurement and inventory compensation for various 

corrections (i.e., temperature, pressure, and density), and 

• Accounts for effects of drag-reducing agent. 

An overview and evaluation of some of the various commercially available systems for 

use in liquid pipeline leak detection is available from the Alaska Department of Environmental 

Conservation website.31

2.1.10 Overpressure Protection 

 A pipeline operator typically conducts a surge analysis to ensure that the surge pressure 

does not exceed 110% of the maximum operating pressure (MOP). The pressure-relief system 

must be designed and operated at or below the MOP except under surge conditions. In a blocked 

line, thermal expansion is a concern, especially if the line is above ground. 

2.1.11 Valve Spacing and Rapid Shutdown 

The spacings of valves and other devices capable of isolating any given segment of a 

pipeline are driven by two principal concerns: (1) maintaining the design operating conditions of 

the pipeline with respect to throughput and flexibility and (2) facilitate maintenance or repairs 

without undue disruption to pipeline operation and rapid shutdown of pipeline operations during 

upset or abnormal conditions. Valve spacing and placement along the mainline are often selected 

with the intention of limiting the maximum amount of material in jeopardy of release during 

upset conditions or to isolate areas of critical environmental concern to the greatest extent 

 

31 http://www.dec.state.ak.us/spar/ipp/docs/ldetect1.pdf. Follow the link to “Leak Detection Technology 

Evaluation.” (Accessed December 7, 2006.) 
 32 

possible. Valves designed to prevent the backward flow of product in the event of a pump failure 

(check valves) will also be installed in critical locations. Valves may also be required on either 

side of an exceptionally sensitive environmental area traversed by the pipeline. Finally, valves 

will be installed to facilitate the introduction and recovery of pigs for pipeline cleaning and 

monitoring. They also are required to be installed at river crossings over 100 feet wide. The 

design of these must comply with regulations and industry best practices. 

2.1.12 Pumps and Pumping Stations 

Desired material throughput values as well as circumstantial factors along the pipeline 

route are considered in designing and locating pump stations. Desired operating pressures and 

grade changes dictate individual pump sizes and acceptable pressure drops (i.e., the minimum 

line pressure that can be tolerated) along the mainline; grade changes also dictate the placements 

of the pump stations. Pump stations are often fully automated, but can also be designed to be 

manned and to include ancillary functions such as serving as pig launching or recovery facilities 

or serving as the base from which inspections of mainline pipe are conducted. Because there are 

a multitude of ways in which the desired operating conditions can be obtained and sustained, the 

outfitting and location of pump stations are also often influenced by economics, typically 

representing a compromise between few large-capacity pump stations and a greater number of 

smaller-capacity stations. The overall length of the pipeline (to its terminal destination) and the 

flexibility needed to add or remove materials along the course of the pipeline also dictate pump 

station placement. 

At a minimum, pump stations include pumps (components that actually contact the fluids 

in the pipeline and provide kinetic energy) and prime movers (power sources that provide power, 

typically some form of mechanical energy) to the pumps. To facilitate maintenance and to 

prevent disruptions of pipeline operation as a result of equipment failure, most pump stations use 

several pumps arranged in parallel fashion. Typically, all but one of the pumps is capable of 

producing the desired operating pressures and throughputs, so some pump is constantly off-line 

and in standby. Pump stations also represent locations where ownership or custody of the 

material is transferred. For the sake of accountability, such pump stations are also equipped with 

flow monitoring devices. Pump stations typically also have colocated facilities that support 

pipeline operation or facilitate shutdowns or maintenance on pipeline segments. Thus, breakout 

tanks for temporary storage of materials or for use in managing line pressures and controlling 

product surges are also present at pump stations. Finally, pump stations are, in some instances, 

colocated with terminal or breakout tankage facilities. 

Although certain pump designs are preferred for certain applications, all pumps require 

regular maintenance and are subject to failure from a variety of factors. Pump maintenance, 

therefore, is critical to continued safe performance of pipeline systems. 
 33 

2.1.12.1 Pump Designs 

Pumps of various designs are used in crude oil and petroleum product pipelines. Selection 

of pump design is based on desired efficiency as well as the physical properties of the materials 

being moved, especially viscosity and specific gravity. The pump’s head pressure, or the 

pressure differential it can attain, is critical for selecting pumps that are capable of moving fluids 

over elevation changes. 

Two fundamental pump designs are in common use: centrifugal pumps and positive 

displacement pumps. Centrifugal pumps are preferred for moving large volumes of material at 

moderate pressure, while positive displacement pumps are selected for moving small volumes of 

material at higher line pressures. Centrifugal pumps consist of two main components: the 

impeller and the volute. The impeller, the only rotating component of the pump, converts the 

energy it receives from the force that causes its rotation into kinetic energy in the fluid being 

pumped, while the volute converts the kinetic energy of the fluid into pressure. Positive 

displacement pumps can be of various designs; however, two designs predominate in pipeline 

applications: reciprocating and rotating pumps. Rotating pumps are often the pump design of 

choice for viscous fluids such as crude oils. Unlike a centrifugal pump where power demands 

rise sharply with increasing fluid viscosity, the performance of rotating pumps is generally 

unaffected by variations in either fluid viscosity or line pressure. 

2.1.12.2 Driver Selection 

The component that actually provides power to the pump is referred to as the prime 

mover. A wide variety of primer movers are in use, including electric motors, gas turbines, and 

diesel internal combustion engines. In recent years, most long-distance transmission pipelines 

have begun using electric motors or gas turbines. Virtually any prime-mover pump design 

combination is possible, with decisions resting primarily on the physical properties of the fluids 

being pumped, the desired throughputs, operating pressures, and transport speeds for the pipeline 

and for logistical needs such as meeting operating parameters, availability of power or fuel for 

the prime mover, and compatibility with SCADA systems in use and the sensors they rely on. 

Initial costs and maintenance demands can also influence selection. In terms of initial costs, 

electric motors are far less expensive than any other option. Operating costs (measured as 

$/brake horsepower/year) are generally uniform across all options; however, overall efficiencies 

of electric motors are substantially better than other options. When maintenance costs are 

considered, times between major overhauls of prime movers vary, with electric motors and 

industrial turbines expected to require the fewest overhauls over time (Kennedy 1993).32

 

32 Cost data are from 1981 and may not be relevant any longer, since technologies for all of the prime movers have 

advanced; however, the relative costs between prime movers are expected to be generally unchanged. 
 34 

2.1.13 Pigging Devices and Pig Launching/Receiving Facilities 

Pipeline pigs come in a wide variety of sizes and designs. Pigs are inserted into the 

pipeline while it is operational and are carried along by the fluid being pumped. Because they are 

solid devices constructed of various materials including metal, plastics, and rubber derivatives, 

pigs must be removed before reaching the next pump. Typically, pig traps, launchers, and 

recovery facilities are colocated with pump stations. Pigs are designed to perform a wide array of 

functions. Their basic purpose is threefold: (1) provide a way to clean debris and scale from the 

inside of the pipe, (2) inspect or monitor the condition of the pipe, (3) or act as a plug or seal to 

separate products in multi-product commercial pipelines or to isolate a segment for repair 

without depressurizing the remainder of the pipeline. Pigs designed to clean the pipe can use 

mechanical means (often called scraper pigs) or chemicals. Pigs that monitor the condition of the 

pipe are categorized as in-line inspection tools. Monitoring pigs, also sometimes called 

“instrument pigs” or “smart pigs,” can perform a wide variety of functions. Geometry pigs check 

for deformation of the pipe (which can greatly influence throughput efficiencies, but can also be 

an early indicator of significant problems that could compromise pipeline integrity). Pipeline 

curvature, temperature and pressure profiles, bend measurements, corrosion detection, crack 

detection, leak detection, and product sampling represent some of the other major functions 

performed by smart pigs. Magnetic flux leakage and ultrasonic technologies are employed for 

some of these inspections. Another type of pig recently developed is the gel pig. As the name 

implies, gel pigs consist of a series of gelled liquids that are introduced for a variety of purposes, 

including serving as a separator between products in a multi-product pipeline, collecting debris 

(especially after initial construction or repairs that involved opening the pipeline, and dewatering 

the pipeline. Figure 2.1-2 provides examples of the various types of pigs in use today, while 

Figure 2.1-3 depicts the typical configuration of a pig launching/recovery facility. 

2.1.14 Distribution Terminals 

Marketing and distribution terminals temporarily store products removed from the 

pipeline. There also may be loading racks and transfer operations. In most instances, terminals 

are proximate to, but not necessarily within the pipeline ROW, even if the terminal is owned and 

operated by the pipeline operator. 

2.1.15 Measurement and Flow Control 

2.1.15.1 SCADA 

A typical SCADA system collects data from, and supervises control of, third-party 

programmable logic controllers at each of the pipeline’s pumping stations, mainline valves, and 

other areas where monitoring of critical conditions takes place. Along the entire length of the 

pipeline, block valves are remotely monitored and controlled using advanced real-time SCADA 

processors designed to support complex remote applications. The communications for the system 
 35 

FIGURE 2.1-2 Examples of the Types of Pigs in Use Today 

(Source: Photos courtesy of T.D. Williamson, Inc. 

Reproduced with permission.) 
 36 

FIGURE 2.1-3 Pig Launcher/Receiver (Source: Image courtesy of the Pigging Products and 

Services Association. Reproduced with permission.) 

is typically over the Ethernet and fiber optic lines as the backbone, backed up by public switched 

telephone networks. 

SCADA system designs vary widely, but there are elements common to all. Operational 

data for liquid pipelines must be gathered from locations that are distributed widely across large 

geographical areas. Measurement transducers are polled frequently. To efficiently perform basic 

functions, data must be accessible by operations personnel located in the field and at a central 

pipeline control center. Operations are monitored and controlled using SCADA systems that 

provide thousands of data signals to pipeline controllers and operators. Some data are provided at 

intervals of a few seconds, other data are provided at intervals of a few minutes, and still others 

on an hourly or daily basis. As data are updated, the superseded older data are normally stored 

for a period of time to support system audits, identify trends (both good and bad), and establish a 

historical operating record. 

SCADA systems are configured with a variety of instrumentation. Electrical signals from 

measurement devices are typically converted to engineering units in computers, referred to as 

remote terminal units (RTUs), which are located at measurement sites. Communication links are 

provided by radio, cell phone, private microwave, leased line, or satellite. Polling frequencies 

can be predetermined or on-demand. 

Data from a given area of operations are often concentrated in computers at field offices, 

which are distributed throughout the pipeline system. SCADA software running on these field 

computers provides operational data and control to local operations personnel. Central computers 

located at a company’s pipeline control center, in turn, poll field computers. SCADA software 

runs on the central computers to provide pipeline controllers with displays of operational data 

and remote control capabilities. 

With so much data available at such high frequency, the effectiveness of the SCADA 

system hinges on appropriate data presentation, analysis, and alarming. A variety of data 

presentations are used to transform basic data into information. Trends, schematics, and other 

graphics are used to convey large amounts of data, which vary over time, in a concise and 

informative format. Often operational data is superimposed on facility and pipeline schematics, 

permitting presentation of the data in an operational context. Alarms are used to indicate that 

operating conditions are approaching or have exceeded prescribed tolerances. Attention can then 
 37 

be focused on problem diagnosis and appropriate actions. In addition to data collection and 

display, SCADA systems also often include data validation programs that seek to validate each 

piece of data before using it to support a calculation or represent a condition. Frequent and, in 

some cases, continuous data validation has been shown to greatly increase the sensitivity of the 

system while reducing incidents of false alarms. 

SCADA systems at remote control centers provide operators with complete operational 

information about the pipeline system in one location. Typical information includes: 

• Pipeline mimic/displays. The complete pipeline can be mimicked to provide 

the operator with instantaneous visual feedback on the status of any portion of 

the pipeline, including pumps, valves, tanks, etc. These visual schematics 

include overviews of the entire pipeline system or systems and drill-down 

screens that take the viewer to an individual location or piece of equipment. 

• Pump, compressor, and other equipment status. Equipment operation can be 

displayed with status (on/off) and other critical parameters associated with a 

piece of equipment such as flow, discharge pressure, vibration, case 

temperature, etc. 

• Valve status. Valve information can be displayed with valve positions 

(open/throttle/closed) depicted. 

• Alarms and alerts. Alarms and other operational indications are immediately 

available for operator response where complete system status is known and, in 

many cases, can be displayed. These can alert the controller to an unusual or 

abnormal operating situation or remind the controller about upcoming 

operating changes that need to be initiated. Often, system configurations allow 

the operator to intervene to validate the alarm or to take the necessary 

corrective actions. When operator intervention does not occur with a 

prescribed time frame, the system will automatically initiate actions that have 

been predetermined as being appropriate, given the circumstances. 

• Analytical tools. Trending history and other analytical tools and graphical aids 

are available to assist personnel in their decision making under routine, 

abnormal, and emergency conditions. 

The SCADA system is the central feature of a remote control center. Because the flow of 

product in the pipeline is typically a 24-hour-a-day, 7-day-a-week operation, the remote control 

centers are staffed continuously in order to monitor and maintain this round-the-clock operation. 

Due to the data being transmitted from potentially many miles away, the operator oftentimes 

must respond to the alarm and direct a corresponding response from the remote control center 

based on the information depicted on the display provided by the SCADA system; however, in 

other cases, decisions are made in conjunction with personnel located in the field at the affected 

location(s). 
 38 

2.1.15.2 Telecommunication Towers 

In all SCADA systems, the master terminal unit (MTU) and RTUs communicate through 

a defined network of some type. The early systems utilized wired communications, either private 

hard-wired systems owned by the operator (usually practical only for short distances) or the 

public switched phone network. Today there are still many systems using public phone systems, 

encompassing both wire and fiber optics technology. These facilities allow remote monitoring of 

the pipeline and communication with valves, compressors, and personnel during operation. 

Most new systems, and many retrofits, are using some form of wireless communications. 

Many pipelines own their own microwave infrastructure, including dedicated towers and radio 

frequencies licensed by the Federal Communications Commission. There are also systems using 

frequencies in the very high frequency (VHF) and ultrahigh frequency (UHF) ranges. These 

operators may own the communication towers or lease space on towers from other 

communication system operators. Many newer systems make use of low-power radio 

transmissions, such as spread-spectrum technology, to avoid the licensing requirements. Satellite 

communications are also used for long-distance and rugged-terrain communications. 

SCADA systems can also operate on cell phone technology, such as the Cellular Digital 

Packet Data. This requires no dedicated lines or other infrastructure, such as an antenna tower. 

Some SCADA systems operate directly through the Internet, thus eliminating certain 

maintenance concerns for the operator, but also simultaneously introducing cyber security 

concerns. 

2.1.16 Risk of Natural Hazards and Human Threats 

Natural and man-made hazards, such as shaking from earthquakes, flooding, and even 

human chemical, biological, or nuclear attacks can cause harm to pipeline components, such as 

pump stations, pipelines segments, and storage tanks, etc. Information in the following 

paragraphs was adapted from guidance published by the American Lifelines Alliance (ALA) and 

the Federal Emergency Management Agency (FEMA) (ALA and FEMA 2005). Table 2.1-3 

provides a summary of the degree of vulnerability of each type of pipeline component to damage 

or disruption by these natural or man-made disasters. 

2.2 COLOCATION ISSUES IN CORRIDORS 

Colocation of energy transmission systems within designated energy ROWs may result in 

some interference between the systems or other hazards that would not exist except for the 

physical proximity of the two transmission systems. The paragraphs below identify some of the 

possible unique consequences of colocation of such systems within an energy ROW. 
 39 

2.2.1 Fire Hazards 

The proximity of pipelines carrying volatile materials raises the potential of a fire in one 

transmission system causing heating, stress, and/or rupture in another one. The normal distance 

between buried pipelines will probably prevent significant transfer of heat underground. 

However, care should be taken at locations where the pipelines exit the ground, such as at pump 

and compressor stations and road/river crossings, to ensure adequate separation of lines and 

facilities or additional insulation and fire protection. 

In the event of a fire in a petroleum pipeline, overhead electricity transmission lines could 

be damaged if adequate distance is not maintained. 

2.2.2 Coincident Construction 

Coincident construction of two separate energy transmission systems within a designated 

corridor raises some potential problems if the construction activities are not well coordinated and 

well scheduled. Because of the proximity of two major construction activities, workers on one 

construction project may be exposed to hazards of the other. Logistics become quite complicated 

with both construction activities vying for the same transportation services and the same 

equipment laydown areas and using the same access roads to approach their respective 

construction sites with manpower and heavy equipment. On the other hand, with construction 

activities closely coordinated, impacts could be lessened, since opportunities are created for 

multiple uses of access roads, laydown areas, and other support systems that may be common to 

both construction processes. 

2.2.3 Electrical Interference 

The question of the impact of the colocation of metallic pipelines and high-voltage 

transmission lines can be framed by three broad concepts: (a) influence, (b) coupling, and 

(c) susceptibility. Other issues that add to the overall impact are identified and discussed below. 

Influence can be thought of as the sum total of the magnetic induction and ground-return 

currents. Coupling can be thought of as the “distance” between the source of the magnetic 

induction (power line) and the objects being affected (pipelines). Susceptibility relates to the 

vulnerability of the induction element (i.e., the metallic pipeline) to induced and ground-return 

currents. 

Colocation may mean that the pipelines are located on an electric utility ROW directly 

underneath the power lines, usually buried in earth. This is the worse case for the coupling of 

magnetic induction currents, since the separation between the power line and the pipeline is very 

small. Thus, the full effect of the magnetic induction from the power line into the pipeline takes 

place. 
TABLE 2.1-3 Degree of Component Vulnerability to Damage or Disruption from Natural Hazards and Human Th

Degree of Vulnerability Hazards Transmission Pipelines Pump Stations Compressor Stations Processing Facilities Storage Tanks Control Systems Maintenance and Operations Buildings and Equipment Pressure Regulating/ Metering Stations 

Natural Hazards Earthquake shaking L M M M H M H L 

Earthquake permanent ground deformation (fault rupture, liquefaction, landslide and settlement) H 

−

−

− L 

−

− L 

 Ground movements (landslide,  frost heave, settlement) 

H 

−

−

− L 

−

− L 

 Flooding (riverine, storm  surge, tsunami and seiche) 

L H H H M H H H 

 Wind (hurricane, tornado) L (Aerial) 

−

−

−

− L L 

−

 Icing L 

−

−

−

−

−

−

− 

 Collateral hazard: blast or fire M H H H H M L L 

 Collateral hazard: dam  inundation 

L H H H M H H H 

 Collateral hazard: nearby  collapse 

− L L L 

− L L L 

Human Threats 

 Physical attack (biological,  chemical, radiological and  blast) 

M M M M 

− M M 

− 

 Cyber attack 

− L L L 

− H L 

− 

Note: Degrees of Vulnerability: H-High, M-Moderate, L-Low, and – (dash) for not applicable. Comments such as (Buried) or (Aerial) apply to locat

as the column heading. 
 41 

Alternating current (AC) induction will be reduced for power lines that parallel pipelines 

but are located to the right or left of the pipelines, rather than directly above. For example, the 

magnitude of the induced currents and voltages will be reduced by a factor that is inversely 

proportional to the distance from the centerline. As the separation between the power line and the 

pipeline increases, radically smaller values of current and voltage will be induced. In many 

cases, especially under ideal conditions, the induced currents and voltages would be minimal 

beyond 300 to 500 feet. 

Each of the three broad concepts of influence, coupling, and susceptibility is highly 

variable for every situation, and each power-line and pipeline scenario must be considered 

separately. The system design, materials, and construction methods can themselves go a long 

way toward minimizing overall susceptibility of pipeline systems to magnetic induction and 

damage due to electrolysis and lightning. 

The pipeline industry has devoted considerable attention to the potential problem of 

interferences presented by nearby electricity transmission systems. The mechanisms of 

electromagnetic interferences between power systems and nearby buried pipelines have been 

generally placed in one of three categories: inductive coupling, conductive coupling, and 

capacitive coupling (Li and Dawalibi 2006). Computer models have been developed to 

approximate the contributions of each type of interference on pipelines existing within various 

ROW scenarios and to predict the effectiveness of mitigative techniques (Dawalibi et al. 2006; 

Christoforidis et al. 2001; Borts et al. 2006). During normal operating conditions of the 

electricity transmission system, only inductive voltages are imparted to the pipeline as a result of 

the magnetic field around the electric current conductors. Interferences increase with decreasing 

physical separation and the angle between the power conductors and the pipeline, with the 

greatest interference levels being observed when the pipeline is parallel to and directly below the 

conductors. Interference also increases with increasing soil resistivity and with the increasing 

magnitude and frequency of the electric power being transmitted. The effects of abnormal 

conditions in the electrical system such as faults have also been investigated 

(Christoforidis et al. 2005). Faulted conditions can impart conductive interference to the pipeline. 

The magnitude of this conductive interference is influenced by such factors as soil resistivity, the 

electrical transmission line’s grounding system, and the separation distance between the ground 

fault and the pipeline. During faults, both inductive and conductive interferences are present, 

placing in jeopardy both the pipeline and the pipeline workers in the vicinity. 

Research sponsored by the Ductile Iron Pipeline Research Association has further 

established the factors that can influence the three coupling mechanisms of capacitance, 

conductance, and induction (Bonds 1999). The severity of the effect that overhead power lines 

can have on buried pipelines depends on a number of factors, including primarily the electrically 

continuous length of pipeline that is parallel to the overhead line, the strength and nature 

(e.g., number of phases) of the electric power, soil resistivity, the continuity of the corrosion 

control coating or other wrapping on the pipe, and how well the pipe is otherwise (electrically) 

insulated from the ground. Bare pipe that is in continuous contact with the ground is effectively 

at the same electrical potential as the neutral ground wires of the overhead lines, so there is little 

if any potential for current to flow between the two systems. Ironically, improvements in pipeline 

coatings applied for the purpose of corrosion control can be counterproductive with respect to 
 42 

interferences from electricity transmission systems, effectively isolating the iron pipe from the 

ground and allowing considerable amounts of induced voltage to build up in the pipe. 

Construction techniques can also greatly influence the extent of interference between 

power lines and buried pipelines. Pipeline segments are typically 20 feet long and connected to 

adjacent segments by rubber gaskets, effectively isolating each pipe segment and making the 

entire pipeline electrically discontinuous. As noted above, installation mechanisms that involve 

tightly wrapping the pipe and/or applying a continuous corrosion control coating can make the 

pipe more susceptible to interferences from induced currents of nearby power lines, since those 

techniques can prevent the pipeline from remaining at the same electrical potential as the ground 

(and as the neutral wire of the electricity transmission system). To overcome this problem, 

ductile pipe manufacturers recommend a loose wrapping of polyethylene that still provides 

sufficient path to ground to keep the pipe and the neutral ground wires of adjacent power lines at 

the same potential. Some mitigative techniques have been shown to not only reduce induced AC 

voltages effectively and economically, but to simultaneously provide cathodic protection for the 

pipeline (Southey et al. 1994). 

As noted earlier, the precise alignment of the electric field with respect to pipeline 

orientation is critical to the severity of the potential interference. PC-based software is available 

that allows for calculation of both steady-state and fault-induced voltages on pipelines paralleling 

high-voltage overhead AC power lines.33

Experience has shown that colocation of electricity transmission lines and buried metallic 

pipelines creates additional monitoring, testing, and/or preemptive actions by the pipeline 

operator, especially after certain events have occurred. The following conditions and potential 

problems are unique to colocated pipelines: 

• Phase fault currents. Fault currents dumped to ground will naturally follow a 

path of least resistance involving the soil and the metallic pipeline. There can 

be many different scenarios depending on the resistance of the pipeline and 

the resistance of the surrounding soil. 

• Lightning strike currents. Instantaneous lightning currents can be very high, in 

excess of hundreds of thousands of amperes. As a result, these currents can 

stress the electrical system such that breakdown and flashover occur at weak 

points, resulting in damage. If the damage is not repaired, there will be 

continued deterioration and ultimately system failure. An explosive effect may 

be associated with a direct lightning strike, which can cause significant 

damage not only to the electric system, but also to nearby buried pipelines. 

Thorough inspections of affected areas of the electricity transmission system, 

as well as nearby pipeline segments, are warranted after lightning strikes have 

occurred. 

 

33 See, for example, http://www.prci.com/publications/L51835.htm. (Accessed December 12, 2006.) 
 43 

• AC-induced corrosion. AC-induced corrosion may result in significant metal 

loss and a significant threat to the integrity of the pipeline. 

• Impacts on pipeline cathodic protection systems. Some pipelines are protected 

by an impressed-current cathodic protection system (CPS). A CPS is intended 

to minimize the loss of metal in the pipeline due to electrolysis. Because the 

currents applied in a CPS are typically quite low (in the milliamp range), 

nearby electromagnetic fields from electricity transmission lines can disrupt 

proper CPS operation. Interferences from nearby electricity transmission lines 

can be compounded where multiple pipelines exist, each with its own CPS. 

Increased monitoring of CPS function is warranted for pipeline segments in 

close proximity to electricity transmission systems. 

• Compromised insulating coatings and pipeline joints. There may be damage 

to the pipeline insulating coating as a result of induced voltage. This can 

happen at underground sections of pipeline, as a consequence of the 

application of an excessive voltage stress across the pipeline coating. 

Likewise, insulating joints used to electrically isolate aboveground pipeline 

segments from those belowground, or to electrically isolate separate CPSs 

serving adjacent pipeline segments, can also be compromised by induced 

voltage. 

• Electrical shorts between carriers. Many times, there can be electrical shorts 

between the CPSs of adjacent pipelines. When two independent CPSs exist, 

special field techniques are required to monitor for such shorts. 

• Polarized pipe. Metal pipelines in proximity to electricity transmission lines 

may become electrically polarized, requiring special techniques to reveal the 

electrical potential differences between the pipe and the soil with which it is in 

contact; this is a critical consideration in designing and implementing an 

appropriate CPS for the pipeline. 

• Review, testing, and documentation of electrostatic or capacitive interference. 

When electromagnetic interference is possible, studies are warranted to ensure 

the safety of personnel and other pipeline assets and that a CPS is not 

adversely affected. 

• Review, testing, and documentation of resistive or ohmic interference. When 

lightning strikes a transmission structure, or when there is a phase-ground 

fault, it is important to measure and document the severity of the ohmic 

interference that has resulted and to verify that adverse impacts to nearby 

pipelines have not occurred. 

• Review, testing, and documentation of electromagnetic or inductive 

interference. Phase imbalances in nearby electricity transmission lines can 

result in inductive interferences in metallic pipelines that are close to and 
 44 

parallel with the transmission lines. Special investigations of adverse impacts 

to pipelines are warranted in the aftermath of such phase imbalance events. 

• Review, testing, and documentation of contact voltages. Contact voltages may 

cause AC current to flow to ground through a person touching the line. 

Therefore, to ensure worker safety, measurements to identify the existence of 

such conditions must be routinely made and mitigative actions taken, when 

necessary. 
 45 

3 PIPELINE CONSTRUCTION 

Designing and constructing a pipeline is a major undertaking, requiring a wide variety of 

engineering and construction skills. While is conceivable that a large pipeline operator would 

have the internal resources (both trained and experienced manpower and equipment) to 

undertake all phases of pipeline construction, it is more likely that virtually all of the major 

phases of construction will be contracted out to companies possessing the necessary expertise 

and capacities to complete the task. While that guarantees the critical requirements of pipeline 

construction will be met, it also introduces the need to control logistics to ensure that all 

contractor activities are coordinated and not mutually exclusive of one another. 

Construction can take place within a relatively narrow ROW because pipeline 

construction equipment is distributed along the pipeline route in a type of “moving assembly 

line” in which only one major item of construction equipment is normally needed at any one 

point along the line. The distance along the pipeline over which this equipment is deployed is 

relatively short, typically less than a mile, but there may be several sets of construction 

equipment operational along the pipeline route at any given time. These complete sets of 

equipment — for ditching, welding, coating, lowering in, and backfilling — are called spreads. 

A single pipeline may be built using several spreads, reducing the overall construction period, 

but also increasing the amount of people and secondary resources required to support them. A 

very large pipeline project may even be divided into two or more segments, and different 

construction contractors may be used to install each segment. Various construction activities may 

also occur simultaneously on a number of segments. Each of these contractors may field several 

spreads to build a segment. 

The actual installation of the pipeline includes these major steps: 

1. Clearing the ROW as needed. 

2. Ditching. 

3. Stringing pipe joints along the ROW. 

4. Welding the pipe joints together. 

5. Applying a coating and wrapping the exterior of the pipe (except for the 

portions of the pipe at each end, which is sometimes coated before being 

delivered to the job site). 

6. Lowering the pipeline into the ditch. 

7. Backfilling the ditch. 

8. Testing the line for leaks. 
 46 

9. Cleanup and drying the pipeline after testing to prepare it for operation. 

10. Reclaiming impacted environmental areas. 

Brief discussions of each of these major steps are provided in the following paragraphs. 

Images representative of each topic are also provided to augment the discussion. However, many 

more images and engineering schematics are available than are provided below. The reader is 

invited to consult the following Internet websites, which provide additional imagery relating to 

pipeline siting and construction: http://www.uspipeline.com/html/photo_gallery.html and 

http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=10595201. 

3.1 SCHEDULING 

Summer to fall months offer the best times for construction in mountains, due to lower 

water tables and expected better weather.34 Working around the clock may become more 

important for areas at higher elevations. For pipelines installed in lowland areas or areas that are 

perpetually wet, major construction may need to occur in the winter months when frozen ground 

allows access by heavy construction equipment with minimal damage. Likewise, pipelines 

crossing agricultural lands may need to be installed in the winter months to not disrupt 

agricultural activities. However, subfreezing conditions may preempt the application and proper 

curing of certain corrosion control coatings that, by necessity, must be field-applied. 

3.2 PRECONSTRUCTION ACTIVITIES 

3.2.1 Survey and Mapping 

Numerous surveying and mapping operations are essential not only for pipeline 

construction, but to support various engineering decisions, including calculations of desired flow 

capacity of the completed system, foundation designs, pump sizing, and pump station spacing 

along the route. Surveying will also identify unique circumstantial factors that must be 

accommodated during construction (e.g., sensitive environmental areas, archeological or cultural 

resources) and possible interferences to construction and/or operation (e.g., nearby utilities, 

buried or otherwise). While many types of surveys are dictated by regulation, others are also 

routinely conducted as a matter of prudent industry practice. Various types of surveys are 

possible, each satisfying a specific purpose or need. The types of surveys typically associated 

with long-distance, land-based pipeline installation and operation are itemized below 

(Ricketts 2003). 

 

34 However, under certain conditions (e.g., perpetually wet areas), construction may best be conducted in winter 

months when the ground is frozen, allowing better and safer access to the ROW than might exist when the 

ground is not frozen. Construction during winter months may also be less disruptive to adjacent agricultural 

activities. 
 47 

• Geodetic surveying takes into account curvature of the Earth. Applicable for 

large areas, long lines, and used to precisely locate basic reference points used 

for controlling other surveys. 

• Land, boundary, and cadastral surveys are usually closed surveys that 

establish property lines and corners. Cadastral surveys are typically conducted 

only for public lands. 

• Topographic surveys provide the location of natural and artificial features and 

the elevations used in mapmaking. Information on elevation (more precisely, 

elevation changes) is critical to the design and location of pump stations. 

• Route surveys typically connect control or reference points by the most direct 

routes possible, given field conditions. Route surveys may need to be 

amended in those instances when the most direct route encounters obstacles or 

features to be avoided (e.g., severe grade changes, environmentally sensitive 

areas, etc.). Nevertheless, route surveys are conducted to establish the most 

direct paths between control points, which are then amended based on field 

conditions. 

• Construction surveys are conducted during the construction phase to ensure 

design specifications are met. 

• As-built surveys are conducted after construction has been completed as a way 

to verify that design specifications were met or to capture the changes to 

original design specifications that were required to be made to adjust to field 

conditions. 

• Hydrographic surveys are required for all water crossings of pipelines to 

determine the shoreline and depths of the water bodies being crossed. 

• Satellite surveying provides positioning data and imagery captured by 

satellites. Doppler and global positioning data are used as standard practice in 

remote regions and on subdivided lands where other ground-based reference 

points may not exit. 

• Global positioning system (GPS) data are collected simultaneously by as 

many as 24 or a minimum of six high-altitude navigational satellites 

positioned in three orbital planes to precisely locate a point on the surface of 

the Earth. 

• Inertial surveying systems are installed on helicopters or ground vehicles to 

acquire coordinate data that are then used to control precision of geodetic and 

cadastral surveys. 
 48 

• Photogrammetric data acquisition derives from aerial photographs, unique 

terrestrial data, or other sensors that can be used to support any of the surveys 

described above. 

3.2.2 Staging Areas 

 In addition to laydown areas along the ROW, on a large project, centralized pipeline 

staging areas may be located in nearby cities with rail offloading capability where pipe can be 

collected and prepositioned. These areas could be 15 to 30 acres in size. In addition, another 

10- to 30-acre area may be required for use as a construction support yard that will serve as an 

assembly point for construction crews to meet prior to proceeding onto the ROW and for offices, 

storage trailers, and fuel tanks. See the additional discussion in Section 3.3.1 below. 

3.2.3 Soil and Geology Studies 

Soil deposits can be divided into six geologic groups: aeolian, alluvial, colluvial, glacial, 

marine, and residual. The Unified Soil Classification System classifies all soils as coarse, finegrained, or predominantly organic. Physical properties of relevance include water content, degree 

of saturation, porosity (the volume of space between soil particles), and void ratio (volume of 

pore space to the total volume of soil). Index parameters for soils include the liquid limit, the 

plastic limit, the shrinkage limit, shear strength (the amount of force required to separate soil 

particles), deformability (changes of shape in response to external forces), and the relative 

density. Measuring and understanding these and other physical parameters of soil will allow 

design engineers to anticipate how the soil will behave under certain conditions, especially how 

it will react to external stresses. Arctic conditions present additional, unique challenges. For 

example, the presence of permafrost (free water in the pore spaces of uppermost layers of soil 

remaining frozen throughout the year) markedly changes the character and behavior of soils and 

must be accommodated by specialized construction and operation techniques. Of particular 

concern is the potential for latent heat of the commodity being transported to be transmitted to 

the permafrost, thus destabilizing pipeline installation. In areas of variable permafrost 

(i.e., permafrost that may occasionally melt and refreeze), pipelines are often installed above 

ground, along with special construction of support members to prevent heat transfer to the soil. 

Rock is commonly characterized by its type, degree of alteration (weathering), and continuity of 

the core from core samples. Rock quality indices include fracture frequency and rock-quality 

designation. Other considerations are floodplains, active earthquake areas, and hurricane and 

tornado risks. 

3.3 CONSTRUCTION

Standard pipeline construction is composed of specific activities including survey and 

staking of the ROW; clearing and grading; trenching; pipe stringing, bending, welding, and 

lowering-in; backfilling; hydrostatic testing; and cleanup. In addition to standard pipeline 

construction methods, the pipeline construction contractor would use special construction 
 49 

techniques where warranted by site-specific conditions. Rugged terrain, waterbodies, wetlands, 

paved roads, highways, and railroads all dictate special construction techniques. 

Pipeline ROWs can vary in their cross-sectional details as they accommodate unique 

circumstantial factors or features. A comprehensive treatment of the various design variations 

that are required to address every conceivable circumstance is beyond the scope of this 

document. However, interested readers can consult the following Federal Energy Regulatory 

Commission (FERC) website for a more exhaustive display of ROW cross sections: 

http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=10595201.35 Selected images from 

that website which exemplify the most typical situations encountered are reproduced below. 

The typical ROW, as depicted in Figure 3.3-1, includes area for topsoil segregation, 

which is done in some situations.36 Overburden soils are stockpiled to one side as the pipeline 

trench is dug. This typically requires an area ranging from 15 to 35 feet aligned parallel to the 

pipeline. Additional areas may be required to segregate topsoils. The other side of the pipeline 

FIGURE 3.3-1 Typical ROW with Topsoil Segregation (Source: Modified from FERC Golden Pass 

LNG Terminal and Pipeline Project image) 

 

35 This website provides access to Appendix D of the Final Environmental Impact Statement (FEIS) for the Golden 

Pass LNG Terminal and Pipeline Project issued by FERC in 2005. The entire FEIS is available electronically at 

http://www.ferc.gov/industries/lng/enviro/eis/06-03-05-eis.asp. (Accessed January 4, 2007.) 

36 In virtually all instances, the natural native soil horizon will be reestablished after pipeline installation is 

complete, and the disturbed area will be revegetated using indigenous plant species or species approved by the 

landowner. However trees and woody plants whose roots could compromise pipe integrity would not be 

replanted in the vicinity of the pipe. 
 50 

trench is used for equipment access and work. This typically requires 25 to 30 feet, but can 

include additional workspace or staging areas. This construction area is wider at stream and river 

crossings to accommodate the additional construction requirements. 

Figure 3.3-2 shows a typical ROW with an adjacent pipeline in place. In this example, the 

full 25-foot ROW boundary on each side of each pipeline is maintained and should be sufficient 

for two pipelines, since construction can take place to either side. However, if multiple pipelines 

are running in parallel and transmission systems of other types are present, such as power lines, 

issues of construction and maintenance repairs require further consideration. Section 2.1.8.2 

provides further information on load and penetration risks. 

In addition to the ROW shown in the above figures, additional laydown areas, typically 

250 feet × 450 feet (variable with individual project requirements and terrain) are adjacent to the 

ROW at intervals corresponding to the spreads being worked. 

The ROW must be maintained free of trees and brush that could pose a fire hazard or 

obstruct visual identification of leaks. Trees and other woody plants also need to be eliminated 

from the ROW to prevent their roots from challenging the integrity of the pipeline by intrusion. 

Figure 3.3-3 below shows typical permanent ROW maintenance in forested areas. 

FIGURE 3.3-2 Typical ROW with Adjacent Pipeline (Source: Modified from FERC Golden Pass 

LNG Terminal and Pipeline Project image) 
 51 

FIGURE 3.3-3 Typical ROW Maintenance in Forested Areas 

(Source: Modified from FERC Golden Pass LNG Terminal and Pipeline 

Project image) 

3.3.1 Movement and Staging of Pipeline Components and Construction Equipment 

Pipe segments are normally delivered from their point of manufacture by rail to a rail 

off-loading yard conveniently located to the construction ROW (see Figure 3.3-4). From there, 

pipe segments are loaded onto flatbed trucks and taken to a material laydown yard that is 

temporarily maintained in an area close to the construction site (see Figure 3.3-5). Numerous 

laydown yards may be constructed to support individual pipe construction spreads. A truck 

typically carries a maximum of 20 pipe segments at a time; however, this varies by pipeline 

diameter, wall thickness, weight, and pipe stacking method. Trucks will make round-trips all day 

between rail off-loading areas and material laydown areas until all of the materials assigned to 

the laydown areas have been delivered. In areas with less road infrastructure, consolidation of 

crews and materials going to different spreads using the same public access roads is more likely, 

thereby potentially magnifying the impact. In addition to the laydown areas adjacent to the 

ROW, off-site staging areas used to collect equipment and workers could occupy several acres, 

but the amount of space would be highly dependent on the size and terrain of the project. 

Although their primary purpose is temporary storage of pipeline materials, laydown yards are 

also sometimes used for “double joining” two pipe segments before their delivery to the ROW. 

Laydown and staging areas could be in use from 3 to 12 weeks. 

3.3.2 Clearing and Grading 

 The survey crew will carefully survey and stake the construction ROW to ensure that 

only the preapproved construction workspace is cleared. The clearing and grading crew leads the 

construction spread. This crew is responsible for removing trees, boulders, and debris from the 
 52 

FIGURE 3.3-4 Pipe Segments Arriving at Rail Off-loading 

Area (Source: Photo courtesy of U.S. Pipeline, Inc. Reproduced 

with permission.) 

FIGURE 3.3-5 Pipe Segments in a Material Laydown Area 

(Source: Photo courtesy of U.S. Pipeline, Inc. Reproduced with 

permission.) 
 53 

construction ROW and preparing a level working surface for the heavy construction equipment 

that follows. Depending on existing soil conditions, this may require bringing in additional 

materials such as stone and sand to create a temporary work road adjacent to the pipeline. 

The clearing and grading crew is also responsible for installation of silt fences along the 

edges of streams and wetlands as necessary to prevent erosion of disturbed soil. Trees inside the 

ROW are cut down, roots are excavated; and timber is stacked along the side of the ROW for 

later removal. Brush is commonly shredded or burned.37 The amount of clearing required varies 

widely. Sometimes only one pass down the ROW with a bulldozer is required. Where the route 

passes through rough or forested terrain, however, clearing operations can be much more 

extensive. The purpose is to make it possible to move construction equipment along the ROW as 

needed. The clearing and grading crew is also responsible for clearing and grading ROW access 

roads. As with the ROW, access roads from public roadways may also need to incorporate 

measures such as silt fences and stone or paved transitions, as shown in Figure 3.3-6. 

Construction access roads are removed and reclaimed after the construction phase; however, 

some will remain in place throughout the operating life of the pipeline for access to the ROW by 

maintenance and inspection personnel. 

In virtually all circumstances, topsoils and subsoils are separately stockpiled adjacent to 

the trench. In most instances, the subsoil can be used to backfill the trench once appropriate 

bedding materials have been placed at the bottom of the trench and the pipe has been installed. 

An exception to this general procedure occurs when the subsoils contain rocks of varying sizes 

that could damage the pipe if they were used as backfill or when the subsoils are composed of 

heavy clays that would retain water in the vicinity of the pipe, thereby promoting accelerated 

corrosion. In those instances, appropriate backfill materials are brought to the site from the 

nearest practical source, and the original soils are disposed of elsewhere, typically under the 

auspices of a soil disposal permit or approved soil management plan. 

3.3.3 Stringing Pipe Joints along the ROW 

Normally, pipe segments are delivered to staging areas closest to the point along the 

mainline where they will be installed and then subsequently deployed along the ROW. This 

guarantees that each joint needs only to be moved over to the ditch when it is ready to be welded 

into the pipeline. Not only does this save cost and time, it also lessens the potential for damage to 

the pipe before installation. Figure 3.3-7 shows pipe segments being deployed along the ROW in 

preparation for welding and installation into the trench (not yet constructed in this photograph). 

In some rugged locations, pipe segments must be staged on the ROW with helicopters 

(see Figure 3.3-8). In those circumstances where longer lengths of pipe can be easily moved into 

place, pipe is brought to the job site in sections consisting of two single joints of pipe (typically, 

having an overall length of up to 40 feet). This “double-jointing” saves welding time on the job 

site, which often must be done under less desirable conditions than exist in a fabrication yard. 

 

37 Open burning of landscape waste will usually require a special permit issued by the local environmental 

regulatory authority. 
 54 

FIGURE 3.3-6 Sample Road Entrance to a Pipeline ROW (Source: Modified from FERC 

Golden Pass LNG Terminal and Pipeline Project image) 

FIGURE 3.3-7 Stringing Pipe along the ROW (Source: 

Photo courtesy of U.S. Pipeline, Inc. Reproduced with 

permission.) 
 55 

FIGURE 3.3-8 Delivering Pipe Segments to the 

Construction Site in Rugged Terrain May Require 

Special Equipment (Source: Photo courtesy of 

U.S. Pipeline, Inc. Reproduced with permission.) 

3.3.4 Ditching (Excavation and Filling) 

The ditch, or trench, in which the pipeline will be installed is usually made to one side of 

the center of the ROW rather than in the center, to provide adequate room for construction 

equipment and operations alongside the pipe as well as room for future installations. Ditching in 

relatively soft soil is done by a machine with a large wheel on which cutting teeth are mounted. 

The wheel rotates continuously as the machine moves along the pipeline route, and excavated 

material is continuously deposited alongside the ditch. In loose rock or hard soil, it may be 

necessary to use other equipment for trenching — for example, a backhoe or clamshell bucket. 

Blasting or special rock-cutting equipment may be required when the ditch must pass through 

solid rock. 

The depth of the ditch is based on minimum cover specifications or the distance from the 

top of the buried pipe to the ground surface. For the same minimum cover requirements, a largerdiameter pipe requires a deeper ditch. The minimum cover varies according to requirements of 
 56 

regulatory agencies, standard industry practice guidance, the type of area through which the 

pipeline passes, and features along the pipeline route. A minimum of 3 feet of cover is typical, 

but it may be less in open, unpopulated areas and more when the pipe passes under roads, rivers, 

and highway borrow ditches. Minimum cover for river crossings (the distance between the top of 

the river bed and the top of the pipeline) is set at 4 feet; however, additional cover may be 

necessary where scouring of river bed materials by moving water is possible. Most river 

crossings are directionally bored. 

The width of the pipeline ditch varies according to the size of the pipeline. Typically, this 

width ranges from 14 to 28 inches for intermediate pipeline diameters. Figure 3.3-9 shows a 

typical ditching operation. 

3.3.5 Pipe Bedding Material 

Bedding material must be clean sand or soil and must not contain stones having a 

maximum dimension larger than 0.5 inch. Material must be placed to a minimum depth of 

6 inches under the pipe and 6 inches over the top of the pipe. The remaining backfill must not 

contain rock larger than 6 inches. Organic material and wood are not permitted for bedding and 

backfill since they will deteriorate over time, allowing for subsidence and subsequent shifting 

and possible pipe damage. 

FIGURE 3.3-9 Pipeline Ditching (Source: Photo courtesy of 

U.S. Pipeline, Inc. Reproduced with permission.) 
 57 

3.3.6 Welding 

Welding procedures and metallurgy should comply with the service of the system. 

Engineering standards published by the American Petroleum Institute dictate what welding 

techniques should be used (API 1991, 1999). 

With the ditch made and the pipe delivered, welding can begin. The pipe joints are placed 

over the ditch for welding. As welding proceeds, a section of pipeline steadily increasing in 

length is in place above or alongside the ditch. Under some circumstances, pipe segments are 

lowered into their trench before being welded together. Pipeline welding is done with electric 

welding equipment, both manual and automatic. Welding machines are typically mounted on 

small trucks or pickups. The machines may also be mounted on tracked vehicles. A number of 

welders — each with a welding machine — work on each pipeline spread. Since a number of 

weld passes (a “bead” of weld material around the circumference of the pipe) must be made at 

each joint, a typical procedure is to have one welder make the initial passes at each joint. Other 

welders follow behind the lead welder, building up the weld metal at the joint by making 

additional weld passes until the appropriate number of passes have been deposited. The number 

of weld passes required depends on the wall thickness of the pipe and its physical characteristics, 

and is specified in the construction plans. The initial weld pass is one of the most critical aspects 

of pipeline construction and is carefully controlled and monitored. 

It is important that the two ends of pipe to be welded are properly aligned so the weld 

will be uniform around the circumference of the pipe. Line-up clamps are used for this purpose 

at each joint before welding begins. After all passes have been made, the alignment clamps can 

be moved to the next welding station. Figure 3.3-10 shows typical welding operations, which, 

depending on individual circumstances, can occur either before or after the pipe is placed in its 

trench. 

3.3.6.1 Welding Processes 

The sources of heat for welding include electric arc, electric resistance, flame, laser, and 

electron beam. Most processes used in field pipeline welding employ a filler metal, do not 

involve the application of pressure, and depend on an electric arc as the heat source. Types of 

welding include: 

• Shielded metal arc welding. The heat for this process is provided by an 

electric arc that melts a consumable electrode, with some of the metal being 

welded. When the weld metal cools, it hardens to form the weld. 
 58 

FIGURE 3.3-10 Welding Pipe (Source: Photos courtesy of 

U.S. Pipeline, Inc. Reproduced with permission.) 

• Submerged arc welding. In this process, heat is supplied by an electric arc, 

and a consumable electrode is used. A granular flux composed of silicates and 

other elements is deposited on the weld joint. The arc melts some of the flux 

and is submerged in the liquid slag that is produced by this melting. The 

electrode in this method is wire that is fed continuously to the weld joint. The 

high currents used in this technique allow the weld to penetrate deeper below 

the surface of the pipe wall than is possible with other welding processes. 
 59 

• Gas-metal arc welding. This process also uses the heat from an electric arc. 

The arc is covered by an inert gas, such as argon or helium. The insert-gas 

shielded metal arc process uses a consumable, continuous electrode. 

• Gas-tungsten arc welding. An inert gas shield is required when welding with 

tungsten electrodes using the gas-tungsten arc welding process. 

• Electron beam welding. Used primarily for offshore pipelines. 

3.3.6.2 Welding Inspection 

A key part of pipeline welding is inspection. For most projects, welders must be qualified 

by testing on the size and type of pipe to be used on the job. After the welds on the pipeline are 

made, however, they must be thoroughly examined to insure the safety of the pipeline. The most 

common inspection method relies on radiographic, or X-ray, examination of completed welds. 

Construction plans specify what type of inspection will be required and what portion of welds 

must be examined by each method. For instance, it might be specified that where the pipeline 

traverses open areas, 10% of the welds must be X-rayed, however, where the pipeline passes 

under railroads, highways, or rivers, all welds must be examined using radiography. In the X-ray 

inspection process, film wrapped around the circumference of the pipe over the weld is exposed 

to radiation. When the film is developed, bubbles, cracks, slag inclusions, and other defects are 

visible. It is desirable to make this inspection and find any defective welds before the pipe is 

buried because defective welds must be removed and new welds made. 

Welding Inspection Requirements. Pipeline welding must follow written welding 

procedures outlined in 49 CFR Part 195, Subpart D. These procedures are qualified under the 

ASME Boiler and Pressure Vessel Code and API standards. Certain steels require separate 

qualification of welding procedures. Each welding procedure must be recorded in detail during 

the qualifying tests and the record retained for the life of the pipeline. 

Nondestructive Testing (NDT). Nondestructive testing is the branch of engineering 

concerned with all methods of detecting and evaluating flaws in materials. Flaws can affect the 

serviceability of the material or structure, so NDT is important in guaranteeing safe operation as 

well as in quality control and assessing plant life. The flaws may be cracks or inclusions in welds 

and castings or variations in structural properties that can lead to loss of strength or failure in 

service. 

Nondestructive testing is used for in-service inspection and for condition monitoring of 

the operating plant. It is also used for measurement of components and spacings and for the 

measurement of physical properties such as hardness and internal stress. 

The essential feature of NDT is that the test process produces no deleterious effects on 

the material or structure under test. The subject of NDT has no clearly defined boundaries; it 
 60 

ranges from simple techniques, such as visual examination of surfaces, through the wellestablished methods of radiography, ultrasonic testing, and magnetic particle crack detection, to 

new and very specialized methods such as the measurement of Barkhausen noise 38 and positron 

annihilation. 

3.3.7 Pipe Bending 

As welding proceeds along the pipeline, a slight change in direction or a significant 

change in elevation may require a bend in the pipeline. Many such bends are made by a bending 

machine on the job site that bends a joint of pipe to the required curvature (see Figure 3.3-11). 

Even large-diameter pipe can be accommodated in today’s modern bending machines, but it may 

also be necessary to make some bends in a shop on a special machine. Depending on the 

diameter and the wall thickness of the pipe, slight changes in elevation may be accommodated by 

flexing the pipe without the bending machine. Very small changes in direction may sometimes 

be made by letting the pipe lie to one side of the ditch. But changes in direction or elevation 

without bending must be small, especially when large-diameter, heavy-wall pipe is being used. 

3.3.8 Pipe Coating 

If not precoated at the coating mill, the pipe exterior is coated and wrapped after welding 

is complete. Coating and wrapping are done using special machines that move along the pipeline 

ROW. Coal tar enamel is the most common pipeline coating; others include thin-film powdered 

epoxy and extruded polyethylene. Asphalt enamel and asphalt mastic are also used as pipe 

FIGURE 3.3-11 Pipe Bending 

Machine 

 

38 Named after the German physicist, Heinrich Georg Barkhausen who first discovered the phenomenon, 

Barkhausen noise is the audible signal delivered by ferromagnetic materials as they realign their magnetic 

domains in response to externally applied alternating magnetic fields. Material testing methodologies utilizing 

the Barkhausen noise phenomenon (Barhausen Noise Analysis or Micromagnetic Analysis) study the 

microstructures of materials and are capable of identifying the presence of stresses (e.g., in a pipe segment) and 

discontinuities (e.g., in a weld) that could indicate an increased potential for future structural failures. 
 61 

coating materials. Tape is then wrapped over this coating to provide additional protection to the 

pipe and to protect the corrosion coating, especially through rocky areas that might damage the 

pipe coating. 

In some cases, coating and wrapping are yard-applied to the pipe before the pipe is 

delivered to the job site (see Figure 3.3-12). When this is done, a short distance at each end of the 

pipe joint is left bare to permit welding. Then those areas are coated and wrapped over the ditch 

after welding is complete. 

3.3.9 Lowering the Pipeline into the Ditch 

When the welding and coating are complete, the pipe is suspended over the ditch by 

sideboom tractors, which are crawler tractors with a special hoisting frame attached to one side. 

Then the pipeline is gradually lowered to the bottom of the ditch (“lowering in”) 

(see Figure 3.3-13). In rocky soil or solid rock, it is sometimes necessary to put a bed of fine soil 

in the bottom of the ditch before lowering the pipeline. The fine fill material protects the pipe 

coating from damage. 

3.3.10 Backfilling the Ditch 

With new pipelines, or when conducting a maintenance activity for existing pipelines, 

backfilling and bedding must be provided in a manner that will offer firm support for the pipeline 

and not damage either the pipe or the pipe coating by the type of backfill material used or 

subsequent surface activities. 

If the backfill material contains rocks or hard lumps that could damage the coating, care 

must be taken to protect the pipe and pipe coating from damage by such means as the use of 

mechanical shield material; backfilling procedures must not cause a distortion of the pipe cross 

section that would be detrimental to the operation of the piping and the passage of cleaning or 

internal inspection devices. Typical backfilling operations are shown in Figure 3.3-14. 

FIGURE 3.3-12 Applying Coating 

to Pipeline 
 62 

FIGURE 3.3-13 Lowering Pipe into Trench 

(Source: Photos courtesy of U.S. Pipeline, Inc. 

Reproduced with permission.) 

3.3.11 Hydrostatic Testing 

All newly installed pipelines, including pipe segments that have been replaced in existing 

pipelines, undergo hydrostatic testing before being put into service. Hydrostatic testing involves 

isolating that portion of the pipeline undergoing testing, filling it with water, and then 

pressurizing the line to a specified pressure to check for leaks. U.S. federal safety regulations for 

pipelines require that pipelines used to transport hazardous or highly volatile liquids be tested at 

a pressure equal to 125% of the maximum allowable operating pressure (MAOP) for at least four 

continuous hours and for an additional four continuous hours at a pressure equal to 110% or 

more of the MAOP, if the line cannot also be visually inspected for leakage during the test. A 

batching pig driven ahead of the water is used to remove any air and forms an efficient seal to 

isolate that portion undergoing testing. Without a pig in downhill portions of the line, the water 

will run down underneath the air, trapping pockets at the highest points within the pipe. Long 

pipelines will normally be tested in sections; short pipelines may be tested as single units. 
 63 

FIGURE 3.3-14 Backfilling Pipeline (Source: 

Photos courtesy of U.S. Pipeline, Inc. Reproduced 

with permission.) 

Temporary connections for filling and draining the pipeline are used, and a pump is used 

to “pressure up” the line. Once the specified pressure is attained, the pump is shut off and the 

“static” leak test commences. A leak is indicated if the pressure falls over the period of the test. 

Once hydrostatic testing is completed, the water is removed and typically delivered to a 

wastewater treatment facility (e.g., a publicly owned sewage treatment works) for treatment. 

While the majority of the water will be removed simply by draining the water at appropriate 

locations along the segment undergoing a test, some water will still remain and will contaminate 

the subsequent product unless it is removed. Typically a pig is used that is designed specifically 

to capture water and deliver it to a point where it can be removed. This dewatering pig serves a 

dual purpose, removing water and also removing construction debris that may still remain in the 

pipeline and could be very damaging to downstream pumps, if not removed. Often, the pig is 

propelled along the pipeline by the products the pipeline was designed to carry, and once the pig 
 64 

and the water it has captured have been removed, the pipeline is considered to be fully 

operational. 

The water removal process described above is usually sufficient for crude oil and 

petroleum products. However, for some petrochemical feedstocks that would react adversely 

with water, additional steps are taken to remove the last vestiges of water before the product is 

introduced. Super-dry air, methanol, or inert gases such as nitrogen are typically used to flush the 

pipeline and capture any last remaining amounts of water. 

3.3.12 Final Grading and Reclamation 

Once backfill has been placed and properly compacted, the original topsoil is returned to 

its original location and final grading and contouring are performed. Depending on the 

vegetation reclamation plan that has been approved, reclamation of the disturbed area above the 

pipeline can begin at this time. Also at this time, as all construction work is completed for each 

spread, construction equipment is removed and the construction ROW is reclaimed. However, 

depending on access constraints, the construction road may remain in place until adjacent 

spreads are completed, if it provides the only access to those spreads. Figures 3.3-15 and 3.3-16 

show final contouring of a pipeline ROW and a reclaimed ROW, respectively. 

FIGURE 3.3-15 Final Contouring of Pipeline ROW 

(Source: Photo courtesy of FERC) 
 65 

FIGURE 3.3-16 Revegetated Pipeline ROW 

(Source: Photo courtesy of FERC) 

3.3.13 Special Conditions 

3.3.13.1 Road, Railroad, and Waterbody Crossings 

Even small pipeline projects often involve crossing roadways and streams; a 

long-distance pipeline may cross scores of each. A variety of techniques are used for crossing 

these obstacles, depending on the length of the crossing, the size of the stream or roadway, 

applicable regulations, and, where federal lands are involved, the extant policies of the federal 

land owner. 

Road and Railroad Crossings. Crossing roadways or railroads can be done by either 

trenching or boring. When trenching, the roadway must be closed to traffic for some period of 

time. The road itself must be removed in that portion that overlays the pipeline and reinstalled 

after pipeline installation is complete. Because of the obvious disruptions to traffic flow that will 

result, this method is often not permitted for busy thoroughfares, and instead a trenching 

technique that will allow the road to remain in service would be used. Similarly, an analogous 

approach to crossing a railroad would require that a section of the railroad directly above the 

pipeline path be removed and reinstalled after pipe installation is complete. Again, trenching 

alternatives are available if disruption of rail service cannot be tolerated. 

Virtually identical design considerations are made for road and railroad crossings. Of 

primary importance is a calculation of the maximum dynamic loading on the pipe from traffic or 

trains. This dictates the depth of cover between the road or railroad and the pipe and whether 

additional design features are added to disperse the load to a sufficient degree so as to not deform 

the pipe. A schematic of a typical trenched road crossing is shown in Figure 3.3-17. 
 66 

FIGURE 3.3-17 Trenched Road Crossing (Source: Modified from FERC Golden Pass LNG 

Terminal and Pipeline Project image) 

Boring is done with a horizontal boring machine that drills a hole under the roadway or 

railroad without disturbing the road surface or the trackbed. A casing pipe is normally installed 

in the bored hole, then the pipeline is placed inside the conductor. Spacers are used to center the 

pipeline within the conductor. This sleeve arrangement is effective not only in reducing the load 

on the pipe but also in reducing corrosion in the segment of the pipe underlying the roadway. 

The American Petroleum Institute document API RP 1102 provides guidance for pipelines 

running under roads. Generally, 4 feet of cover is adequate for pipelines 12 inches and smaller. 

Larger pipelines may require additional protection by way of more cover, pipe sleeves, or 

concrete slabs positioned above the pipe to disperse the dynamic loading from traffic and prevent 

deformation of the pipe. Figure 3.3-18 provides an example of a bored pipeline road crossing. 
 67 

FIGURE 3.3-18 Bored Road/Railroad Crossing (Source: Modified from FERC Golden Pass LNG 

Terminal and Pipeline Project image) 

Waterbody Crossings. Strategies for crossing waterbodies depend on a number of sitespecific factors, most importantly, the size and nature of the waterbody itself and the existing 

ecosystems. A schematic of a typical waterbody crossing is shown in Figure 3.3-19. 

Stream and river crossings can be made in a variety of ways. The first is the open-cut wet 

(in-stream) method. A backhoe or dragline can be used in minor stream crossings to make a ditch 

for the pipe to rest in. This technique does not use any method to divert the stream. The pipe is 

installed and backfilled while the river/stream continues to run through the site. The ditch is then 

backfilled, and the pipe may be fitted with concrete weights to hold it in place against the stream 

currents and movement of stream bed sediments. The benefits are low cost and a quick 

completion time, making this the method of choice when existing regulations or policies do not 

require other techniques. Disadvantages include potentially significant pollutant and sediment 

runoff, greatly increased total suspended sediment concentrations downstream, changes in 
 68 

FIGURE 3.3-19 Typical Waterbody Crossing (Source: Modified from FERC Golden Pass LNG 

Terminal and Pipeline Project image) 

channel morphology, and impacts to aquatic ecosystems. These problems can be mitigated only 

by a quick completion time. 

An alternative method of waterbody crossings is called the open-cut dry (isolated) 

method. Here the stream is isolated and diverted around the pipeline crossing. Then the trench is 

excavated, the pipe is installed and backfilled, and then water diversion structures are removed 

and the stream is allowed to restabilize over the buried pipe. It is best-suited for narrow streams 

and rivers with flows less than 141 cubic feet per second. The two main methods of isolated 

crossings are the dam-and-pump method (see Figure 3.3-20) and the flume method (see 

Figure 3.3-21). In the dam-and-pump method, the stream is dammed and water is transferred 

across the construction site by means of a temporary hose or pipe and pump. 

In the flume method, the stream is dammed and a culvert is installed. Isolated crossing 

methods usually have less sediment yield than a wet crossing, but are often more expensive and 

more time consuming. 

Additionally, the installation and removal of the dam can cause high releases of sediment. 

Other problems may arise from leakage around/underneath the dam, dam failures, flume failures, 

insufficient sump storage, insufficient pump capacity, and inadequate maintenance. 

For larger bodies of water, horizontal directional drilling (HDD) may be used. It offers 

several advantages, including no disruption of traffic on the waterway and minimum 

environmental impact. The process proceeds in three basic steps. First, a pilot hole is drilled. 

Secondly, the pilot hole is enlarged to a diameter larger than the diameter of pipe to be installed. 

A slurry composed of bentonite clay is typically used to lubricate the drill and bring cuttings out 

of the hole. A similar slurry is also often pumped into the enlarged hole to prevent it from 
 69 

FIGURE 3.3-20 Dam-and-Pump River Crossing with Two Pipelines (Source: Modified from FERC 

Golden Pass LNG Terminal and Pipeline Project image) 

collapsing before the pipe can be installed. Finally, the prefabricated pipe segment is pulled into 

the hole, using the same drill rig that bored the initial and enlarged holes. This sequence of steps 

is depicted in Figure 3.3-22. 

Heavy equipment is required on both sides of the waterbody crossing for HDD. The 

drilling rig spread requires a minimum 100-foot wide by 150-foot long area on each bank. The 

drilling operation requires large volumes of water for mixing the drilling slurry, often but not 

necessarily withdrawn from the waterbody being crossed. The length of workspace should be 

sufficient to permit fabricating the product pipeline into one string. The width should be what 
 70 

FIGURE 3.3-21 Flume Water Crossing with Two Pipelines (Source: Modified from FERC Golden 

Pass LNG Terminal and Pipeline Project image) 

is necessary for normal pipeline construction, although a workspace of 100-foot wide by 

150-foot long will also be required at the exit point, assuring that the pipe can be installed in one 

uninterrupted operation during the pullback. The recommended minimum cover depth is 20 feet 

for the lowest section of the crossing. 

Slurry pits are constructed in the construction zone to support boring operations. Slurries 

recovered from the hole are delivered to these pits where they can be recycled. At the completion 

of drilling, the slurries are removed for use at another drilling operation or used elsewhere in the 

pipeline construction project to be mixed with native soils to enhance slope stability or increase 
 71 

FIGURE 3.3-22 Typical Directional Drilling under Waterway 

(Source: Modified from FERC Golden Pass LNG Terminal and Pipeline 

Project image) 

water retention properties, where warranted. Otherwise, slurries are disposed of as nonhazardous 

wastes. 

Not all streams are crossed by installing the pipeline beneath the stream. Some pipelines 

are installed on “pipeline bridges,” steel structures built to suspend the pipeline above the stream. 

Use of this method depends on a number of factors, including the presence of traffic on the 

waterway. 

In addition, new pipeline construction may cross existing pipelines in service 

(see Figure 3.3-23). 

Instances in which anchoring is required include river crossings where currents can cause 

pipe movement or scour beneath the pipe installed on top of the river bed, a dry wash subject to 
 72 

FIGURE 3.3-23 Waterbody Crossing Containing a Second Pipeline 

(Source: Modified from FERC Golden Pass LNG Terminal and 

Pipeline Project image) 

temporary flooding or extraordinarily fast stream flows after heavy rains, or where certain types 

of backfill are used. 

3.3.13.2 Crossing Wetlands 

Crossing wetlands, if required and allowed by law, creates unique construction 

challenges. Figure 3.3-24 depicts a typical saturated wetland crossing with topsoil segregation. 

Construction equipment working in wetlands would be limited to that essential for 

clearing the ROW, excavating the trench, fabricating and installing the pipeline, backfilling the 

trench, and restoring the ROW. In areas where there is no reasonable access to the ROW except 

through wetlands, nonessential equipment would be allowed to travel through wetlands only if 

the ground was firm enough or had been stabilized to avoid rutting. Otherwise, nonessential 

equipment would be allowed to travel through wetlands only once. 

Clearing vegetation in wetlands would be limited to trees and shrubs, which would be cut 

flush with the surface of the ground and removed from the wetland. To avoid excessive 

disruption of wetland soils and the native seeds and rootstocks within the wetland soils, stump 

removal, grading, topsoil segregation, and excavation would be limited to the area immediately 

over the trench line. A limited amount of stump removal and grading could be conducted in other 

areas if dictated by safety-related concerns. 
 73 

FIGURE 3.3-24 Saturated Wetland Crossing (Source: Modified from FERC Golden Pass LNG 

Terminal and Pipeline Project image) 
 74 

During clearing, sediment barriers such as silt fences and staked certified weed-free straw 

bales would be installed and maintained adjacent to wetlands and within additional temporary 

workspace areas as necessary to minimize the potential for sediment runoff. Sediment barriers 

also would be installed across the full width of the construction ROW at the base of slopes 

adjacent to wetland boundaries. Silt fences and/or certified weed-free straw bales installed across 

the working side of the ROW would be removed during the day when vehicle traffic was present 

and would be replaced each night. Alternatively, drivable berms could be installed and 

maintained across the ROW in lieu of silt fences or certified weed-free straw bales. Sediment 

barriers also would be installed within wetlands along the edge of the ROW, where necessary, to 

minimize the potential for sediment to run off the construction ROW and into wetland areas 

located outside the work area. 

The method of pipeline construction used in wetlands would depend largely on the 

stability of the soils at the time of construction. If wetland soils are not excessively saturated at 

the time of construction and can support construction equipment on equipment mats, timber 

riprap, or certified weed-free straw mats, construction would occur in a manner similar to 

conventional upland cross-country construction techniques. In unsaturated wetlands, topsoil from 

the trench line would be stripped and stored separately from subsoil. Topsoil segregation 

generally would not be possible in saturated soils. 

Where wetland soils were saturated and/or inundated, the pipeline could be installed 

using the push-pull technique. The push-pull technique involves stringing and welding the 

pipeline outside of the wetland and excavating and backfilling the trench using a backhoe 

supported by equipment mats or timber riprap. The prefabricated pipeline would be installed in 

the wetland by equipping it with buoys and pushing or pulling it across the water-filled trench. 

After the pipeline was floated into place, the floats would be removed and the pipeline would 

sink into place. Most pipe installed in saturated wetlands would be encased in concrete or 

equipped with set-on weights to provide negative buoyancy (see Figure 3.3-25). 

Because little or no grading would occur in wetlands, restoration of contours would be 

accomplished during backfilling. Prior to backfilling, trench breakers would be installed where 

necessary to prevent the subsurface drainage of water from wetlands. Where topsoil has been 

segregated from subsoil, the subsoil would be backfilled first, followed by the topsoil. Topsoil 

would be replaced to the original ground level, leaving no crown over the trench line. In some 

areas where wetlands overlie rocky soils, the pipe would be padded with rock-free soil or sand 

before backfilling with native bedrock and soil. Equipment mats, timber riprap, gravel fill, 

geotextile fabric, and/or certified weed-free straw mats would be removed from wetlands 

following backfilling. 

Where wetlands are located at the base of slopes, permanent slope breakers would be 

constructed across the ROW in upland areas adjacent to the wetland boundary. Temporary 

sediment barriers would be installed where necessary until revegetation of adjacent upland areas 

was successful. Once revegetation was successful, sediment barriers would be removed from the 

ROW and disposed of properly. In wetlands where no standing water was present, the 

construction ROW would be seeded in accordance with the recommendations of local soil 

conservation authorities. Lime, mulch, and fertilizer would not be used in wetlands. 
 75 

FIGURE 3.3-25 Concrete-Coated Pipe in a Wetland (Source: Photo 

courtesy of U.S. Pipeline, Inc. Reproduced with permission.) 

3.3.13.3 Elevated Areas and Rugged Topography 

There may be multiple areas that would require additional workspace areas due to 

exceptionally rugged or steep terrain. Additional grading may be required in areas where the 

proposed pipeline route would cross steep slopes. Steep slopes often need to be graded down to a 

more gentle slope to accommodate pipe-bending limitations and the limits of pump capabilities 

to move product over a grade change. In such areas, the slopes would be cut away and, after the 

pipeline was installed, reconstructed to their original contours during final contouring and before 

restoration of surface vegetation. 

In areas where the proposed pipeline route crosses laterally along the side of a slope, 

cut-and-fill grading may be required to obtain a safe, flat, work terrace. Generally, on steep 

side-slopes, soil from the high side of the ROW would be excavated and moved to the low side 

of the ROW to create a safe and level work terrace. Under these circumstances, the topsoil would 

be stripped from the entire width of the ROW. After the pipeline is installed, the soil from the 

low side of the ROW would be returned to the high side, topsoil replaced, and the slope’s 

original contours would be restored. 

In steep terrain, temporary sediment barriers such as silt fences and certified weed-free 

straw bales would be installed during clearing to prevent the movement of disturbed soil off the 

ROW. Temporary slope breakers consisting of mounded and compacted soil would be installed 

across the ROW during grading, and permanent slope breakers would be installed during 
 76 

cleanup. Following construction, seed would be applied to steep slopes and the ROW mulched 

with certified weed-free hay or nonbrittle straw or covered with erosion-control fabric. Plants 

with noninvasive root systems and indigenous to the area or approved by the federal land 

steward’s vegetation management plan would be planted for long-term erosion control. Sediment 

barriers would be maintained across the ROW until permanent vegetation is established. 

When rock or rocky formations are encountered, tractor-mounted mechanical rippers or 

rock trenchers would be used for fracturing the rock prior to excavation. In areas where 

mechanical equipment could not break up or loosen the bedrock, blasting would be required. 

Whenever possible, excavated rock would be used to backfill the trench to the top of the existing 

bedrock profile; however, crushing the rock to a uniform size may be necessary to prevent 

damage to the pipe during placement and to ensure proper backfilling density and minimize the 

potential for future subsidence. 

3.3.13.4 Valves 

Valves are installed at various locations along the mainline for various operational 

controls and to isolate segments of the pipeline for maintenance or replacement or to limit the 

amount of product in jeopardy of spilling in the event of a pipeline break. Typically, valves are 

installed at either side of sensitive or potentially problematic segments such as waterbody 

crossings. Such check valves can serve to quickly and efficiently isolate those segments of the 

pipeline in the event a problem should occur. Such isolation limits the scale of the adverse 

consequences that could occur in the event of a pipeline rupture in those segments. Check valves 

are placed at each significant change in grade to prevent backflow of product in the event of a 

failure of the upstream pumps. Bypasses may need to be installed around mainline valves or 

damaged pipeline segments to facilitate maintenance, repair, or replacement without shutting 

down operation of the pipeline. Bypasses typically consist of the requisite length of substitute 

pipe, each end of which is attached to a manually operated valve and two “hot taps” (devices that 

cut into the pipeline and divert the flow from the mainline pipe segment to be isolated to the 

bypass pipe). Once the bypass is positioned, the bypass valves are opened and the hot taps are 

operated to tap into the existing pipe. Such bypasses are typically removed (and the hot taps 

repaired) once the task is completed. See Section 4.10 for additional discussions regarding 

repairs of operational pipelines. 

3.3.13.5 Pump Stations and Terminals 

Pumps that provide the operating capability of a pipeline are located within pump 

stations.. The location and number of pump stations, as well as the size and power of the pumps, 

are dictated by a number of factors, including topography along the ROW (elevation changes), 

the specific gravity and viscosity of the commodity, and the desired throughput. Liquids exiting a 

pump station will be at their highest pressure. Pressure will fall with distance from the pump 

station due to grade changes (if any) and frictional losses. To be effective, the pipeline’s 

operating pressure must be maintained at or above the design discharge pressure at the pipeline’s 

final destination. With the discharge pressure setting the lower pressure limit and the burst 
 77 

pressure of the pipe and other components setting the maximum pressure, calculations can 

determine the number and location of pump stations required, as well as the size and power of 

the pumps at each of these stations. 

Typical pump station configurations involve at least three pumps connected to the 

pipeline in parallel. Two of the three pumps operate while the third remains available, if needed, 

or in the event of a failure of one of the operating pumps. Such a configuration also allows 

pumps to be taken off-line for maintenance or replacement without affecting the operating status 

of the pipeline. 

While housing the pumps and their prime movers remains the primary function, other 

activities such as pig launching and recovery also are typically colocated at pump stations. Also, 

many pump stations have the ability to introduce commodities into the pipeline or to remove 

them and direct them to storage tanks located on-site. Such actions are typically further 

supported by the capability to meter volumetric flow, especially when such transfers into or out 

of the pipeline system represent a change in custody or ownership of the commodity. Storage or 

“breakout” tanks are used to support maintenance or replacement activities where draining 

pipeline segments is required and are also an essential part of emergency-response actions to 

limit the amount of commodity in jeopardy of release or to relieve pressure on damaged pipeline 

segments. Maintenance shops and parts warehouses are also often colocated at pump stations. 

Depending on the array of planned activities, pump station footprints can vary in size 

from a few acres to as many as 50 acres or more. Pump stations can be fully automated or 

manned, either continuously or during one or more shifts. Even for manned stations, however, all 

actions that could be taken at a pump station that affect operational conditions in the pipeline 

(e.g., shutting down or starting a pump) can also be controlled remotely from the pipeline control 

center. 

Figure 3.3-26 is an artist’s representation of Pump Station No. 1, the start of the 

Trans-Alaska Pipeline System (TAPS) at the North Slope, Alaska. Gathering pipelines from 

various production areas on the North Slope deliver a mixture of gas, water, and crude oil from 

wellheads to a central gathering facility where the gaseous and aqueous fractions are removed 

and the crude oil is metered and introduced into the TAPS for its journey to the Valdez Marine 

Terminal, 802 miles south on Prince William Sound. The TAPS terminus is the breakout station 

at the Valdez Marine Terminal where crude oil is recovered from the pipeline and sent to various 

storage tanks to await load-out to oceangoing tankers for delivery to refineries in the contiguous 

United States and elsewhere. 

The terminus of a pipeline is typically located within or adjacent to a petroleum bulk 

terminal. The pipeline ends at a breakout station where terminal personnel can perform final 

metering and distribute products to various storage tanks, redirect them to a different pipeline, or 

load them directly to truck transports or vessels for additional transport to points of use. The 

terminal may or may not be owned and operated by the same company that owns and operates 

the pipeline. A typical pipeline breakout station is shown in Figure 3.3-27. 
 78 

FIGURE 3.3-26 Crude Oil Pipeline Pump Station (Source: TAPS Final Environmental 

Impact Statement) 

FIGURE 3.3-27 Typical Pipeline Breakout Station (Terminus) at a Petroleum Terminal 

(Source: V. Yarborough, Argonne staff) 
 79 

4 PIPELINE OPERATIONS 

4.1 INSPECTIONS AND MARKERS 

The activities discussed below represent standard industry practices. Depending on the 

individual pipeline operator, company polices may result in more restrictive requirements for 

each of the actions. In some instances, regulation or lease stipulation specify how such activities 

will be conducted. 

4.1.1 Inspections during Excavation 

Whenever a pipe is exposed for any reason, the operator typically examines the pipe for 

evidence of mechanical damage or external corrosion, including the coating. Mechanical damage 

must be evaluated and repaired as necessary, in accordance with company repair procedures. 

Coating damage should be repaired prior to reburying the pipeline. If the operator finds active 

corrosion, general corrosion, or corrosion that has caused a leak, the operator should investigate 

further to determine the extent of corrosion. The pipeline should be inspected prior to and during 

backfilling of the exposed section. 

4.1.2 ROW Inspections 

ROW inspections occur with regularity. Depending on lease stipulations and other 

factors, frequencies can be as high as weekly. Inspections can involve individuals walking the 

ROW and also aerial surveillance. Flyover inspections are the most common and most efficient 

method for routine surveillance, but are not appropriate for many required inspection tasks. 

Unique opportunities exist for surveillance and inspection activities for multiple pipelines 

or other energy transmission systems on adjacent ROWs. Although no system operator would be 

willing to entirely relinquish inspection activities to another system operator, there are many 

surveillance activities that are common to all types of energy systems that might be adjacent to 

one another, creating the possibility for a more integrated approach to routine inspections. 

Agreements between system operators and the federal land manager to combine routine 

surveillance activities can reduce environmental impacts that would result from independently 

conducted inspections and could potentially increase operating efficiencies for all of the system 

operators within the ROW. Similarly, integration of passive surveillance systems can potentially 

save costs and increase overall observational frequencies for all of the energy systems present. 

Regardless of the opportunities for combining efforts and he resources of system operators for 

common tasks, system operators remain individually responsible for the integrity of their 

systems and consequently will retain certain surveillance tasks for themselves. 
 80 

4.1.3 Pipeline Markers and Aboveground Facilities 

Proper pipeline markers should be placed where hazardous liquid pipelines and any 

associated facilities are exposed. All hazardous liquid pipelines attached to bridges or otherwise 

spanning an area should have pipeline markers that are visible and readable at both ends of the 

suspended pipeline. 

4.1.4 Change in Operating Rate 

Each pipeline system is designed to a maximum operating rate, or throughput, expressed 

as volumetric flow of the carried commodity over time. This operating rate equates to a 

maximum operating pressure. The design maximum operating pressure, in turn, is the product of 

numerous engineering parameters and limits, the most critical of which from a safety perspective 

are the suite of minimum yield stress pressures, pressures above which pipeline components can 

break or burst. Burst pressures are calculated initially for pipe segments and other components 

and recalculated periodically over time, based on information obtained from various monitoring 

and inspection activities, especially those that determine the extent of external and internal 

corrosion, either of which can have a dramatic influence over the component’s burst or yield 

pressure. Regulations published by the DOT OPS in 49 CFR Part 195 require pipelines to 

calculate yield strengths and operate at a maximum percentage of that design minimum yield 

stress pressure, thus providing adequate safety margins against the minimum burst pressures of 

each pipeline component.39 Oversight by OPS inspectors, including their review of monitoring 

and inspection data or in response to a system failure that is related to pressure, can result in an 

order for the pipeline to be operated at a reduced operating pressure (expressed typically as a 

new lower maximum operating rate) until observed or indicated deficiencies are further 

investigated and resolved. 

4.2 PIPELINE REPAIRS 

In most instances, pipeline repairs are accomplished expeditiously to ensure minimal 

disruption to pipeline operations. Unless otherwise specified by applicable regulation or lease 

stipulation, pipeline repairs are typically made in accordance with ASME standard B31.4, 2002, 

“Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids.”40 ASME B31.4 

requirements and specifications extend to design, materials, construction, assembly, inspection, 

and testing of piping transporting crude oil, condensate, natural gasoline, natural gas liquids, 

liquefied petroleum gas (LPG), carbon dioxide, liquid alcohol, liquid anhydrous ammonia, and 

liquid petroleum products including petrochemical feedstocks and secondary refinery feedstocks. 

Pipeline components addressed in this standard include pipe, flanges, bolts, gaskets, valves, 

relief devices, fittings, and the pressure-containing portions of other support components. 

 

39 The required tests and the formulae for calculating minimum yield strength and the consequent maximum 

operating pressure of a liquid pipeline carrying hazardous materials are contained in 49 CFR 196.106. 

40 This and other ASME standards can be purchased through the ASME website at http://catalog.asme.org/Codes/ 

PrintBook/B314_2006_Pipeline.cfm. 
 81 

Additionally, this standard extends to marine pipelines and piping at tank farms, pump stations, 

terminals, pressure-reducing stations, and metering stations and all aspects of pipeline operation 

related to safety and protection of the general public, operating company personnel, 

environment, property, and the piping systems themselves. 

4.2.1 Moving and Lowering Hazardous Liquid Pipelines 

Prior to moving or lowering any hazardous liquid pipeline, hazardous liquid pipeline 

companies typically prepare a study to determine whether the proposed action will cause an 

unsafe condition. The study must include pipe stress calculations based on API RP 1117, 

“Movement of In-Service Pipelines.” 

4.2.2 Remedial Action for Corrosion Deficiencies 

Companies must initiate remedial action as necessary to correct deficiencies observed 

during corrosion monitoring. Industry standards for allowable advancements of internal and 

external corrosion establish the action levels for such remedial activities. Remedial action may 

involve replacing the sacrificial anodes of a corrosion control system, a relatively minor 

construction activity compared to wholesale replacement of compromised pipe involving 

long-term shutdown of operations and major construction efforts equivalent to initial installation. 

To limit operational downtime, temporary bypass segments isolating the damaged segments may 

also be installed. See additional discussions on corrosion control in Section 4.7. 

4.3 PIGGING ACTIVITIES 

A variety of inspection techniques and technologies are used to monitor pipeline 

condition and integrity. The most important goal of pipeline inspection is usually to assess 

corrosion-caused metal loss. But inspection also provides information on dents and other damage 

that may eventually cause failure and leaks. Pigs that perform a variety of functions are essential 

to pipeline internal inspections. 

Equipment is required to introduce the pig into the pipeline and to retrieve the pig at the 

end of the segment being pigged. A launcher is required at the upstream end of the section, and a 

receiver is required at the downstream end. The distance between these pig “traps” depends on 

the service, location of pump or compressor stations, operating procedures, and the material used 

in the pig. For obvious reasons, any launched pig must be retrieved from the mainline pipe 

before the pipe reaches the next pump station. Often, launching and recovery facilities are 

colocated at pump stations. 
 82 

4.4 CHEMICAL ADDITIVES 

Drag-reducing agents or other chemicals to improve the flow characteristics of the 

pipeline are always present and something to consider in any analysis of pipeline systems. 

Furthermore, dependent on the product, there may be other chemicals that affect the properties of 

the fluids in transmission systems, such as the static reducer added to diesels. For high-viscosity 

crude oils (i.e., low API gravity numbers), a diluent is often added to enhance the pumpability of 

the crude and reduce the frictional drag on the inside pipeline walls, thereby reducing the amount 

of energy needed to pump the crude. Such diluents are typically low-viscosity petroleum refining 

fractions such as raw naphtha. 

4.5 PIPELINE SECURITY 

Third-party damage and ROW encroachments are the biggest threats to pipeline safety. 

Pipeline operators use a combination of techniques to monitor pipeline ROWs. Aerial 

surveillance and satellite imaging combined with interpretive software that can survey and detect 

things such as heat, color, size, and shape, which can alert operators to potential encroachment 

concerns. Fiber optic broadband capabilities along ROWs typically are used to assist in this 

effort. Many pipeline operators are also enlisting the support of adjacent landowners in 

establishing programs for reporting observed suspicious activities along the ROWs. 

4.6 WASTE MANAGEMENT 

The Resource Conservation and Recovery Act (RCRA) plays a key role in determining 

environmental standards for the management of solid and hazardous wastes. Under RCRA, a 

solid waste is any material discarded or intended to be discarded; it may be solid, semisolid, 

liquid, or contain gases. A solid waste is a hazardous waste if it is one of more than 400 materials 

listed as a hazardous waste or it exhibits one or more of the characteristics of hazardous waste 

defined in federal or state regulations, such as ignitability, corrosivity, reactivity, or toxicity. For 

pipelines, benzene is an important hazardous material, as it is a component in crude oil and in 

many petroleum distillate fuels and secondary feedstocks that are routinely delivered by pipeline. 

In sufficient quantities, its presence can cause any spilled products to meet the regulatory 

definition of hazardous waste. 

Another important aspect of RCRA is the mixture rule, 40 CFR 261.3(a)(2)(iii and iv). 

Mixing any listed hazardous waste with a nonhazardous waste renders the entire mixture 

hazardous.41 Water can pose disposal problems for pipeline operators. Water used in hydrostatic 

testing of repaired pipelines that carried crude oil or petroleum products can become 

contaminated with hydrocarbons that require it to be managed as hazardous waste. Certain 

 

41 The mixture rule will always be in effect when “listed” hazardous wastes are involved. However, if mixing a 

“characteristic” hazardous waste with a nonhazardous waste results in a mixture that no longer exhibits the 

characteristic, the mixture is not considered a hazardous waste. However, undertaking such purposeful mixing of 

waste streams to avoid the application of hazardous waste regulatory controls is prohibited. 
 83 

constituents in crude oil or petroleum distillates are also listed as hazardous waste 

(e.g., benzene), and some of these constituents also have relatively high solubility in water. 

Consequently, condensates removed from pipelines carrying such commodities may need to be 

managed as hazardous wastes. Likewise, sludge and other materials removed from such pipeline 

systems during routine cleaning or repairs may also qualify as hazardous waste and must 

routinely undergo hazardous waste determinations against the standards and specifications 

contained in federal or state regulations before management and disposal options are selected. 

The Clean Water Act influences pipeline construction, especially through its 

requirements for permits for activities in wetlands and stormwater management (particularly 

during the construction and decommissioning phases). Stormwater controls must be established 

before construction begins and must be maintained until reclamation has progressed sufficiently 

to stabilize disturbed areas. Similar controls may need to be reinstated before major repair, 

replacement, or upgrading activities are conducted. 

Another important environmental consideration in pipeline construction and operation is 

impact to air quality. Substances of concern to pipeline operators include carbon dioxide, 

hydrogen sulfide, and mercaptan, a sulfur-containing hydrocarbon42 that is introduced into 

natural gas systems as an odorant. Pipeline operators must also be concerned about sources of 

nitrous oxide, carbon monoxide, and emissions from pump engines. “Fugitive” emissions of 

benzene from seals on pumps, valves, meters, and storage tanks must also be controlled. 

4.7 CATHODIC CORROSION PROTECTION 

Underground corrosion of steel pipelines can result from the flow of electrical current 

between areas of different electric potential. The area of higher potential (the anode) will be 

corroded, and the area of lower potential (the cathode) will not be subject to corrosion. In the 

case of a buried pipeline, the soil can act as an electrolyte, facilitating the transfer of electrons 

from a metallic object such as a buried pipe (the anode in this electrochemical engine) and the 

ground. Areas of different electrical potential exist throughout the trace of a pipeline, with the 

magnitudes of such electrical potential differences depending on soil types and myriad other 

local conditions. 

In a cathodic protection system, anodes made of materials that are more conducive to 

electrical current delivery than the steel of the pipeline are electrically bonded to the pipe and 

installed along the pipeline route, resulting in the subsequent flow of electrical current from the 

anodes to the ground. As electrons flow from these anodes, the anodes deteriorate, earning them 

the common name of “sacrificial anodes” since they are being sacrificed and allowed to corrode 

instead of the pipe. The pipeline becomes the cathode of the system, and its corrosion is 

prevented as long as some anode material remains. Keifner and Vieth (1990) established that the 

 

42 The most commonly used odorant is methyl mercaptan. Details on its chemical and physical properties can be 

obtained at the following website: http://www.praxair.com/praxair.nsf/d63afe71c771b0d785256519006c5ea1/ 

bd40c55346b4930f85256e5f007e8c2a/$FILE/MethylMercaptan-Canada.pdf. 
 84 

magnitude of the corrosion currents for a given potential difference between two electrodes 

(cathode and anode) depends on several factors: 

• Soil resistivity. This is determined by temperature, moisture content, and the 

concentration of ionized salts present. Generally, corrosion is high in lowresistivity soils and can be low in very high resistivity soils. 

• Chemical constituents of the soil. Corrosion can be low in very high resistivity 

soils. 

• Separation between anode and cathode. Corrosion is more likely to occur 

when the anode and cathode are close together. 

• Anode and cathode polarization. Protective films formed at the anode and 

cathode affect corrosion intensity. 

• Relative surface areas of cathode and anode. For a given magnitude of 

corrosion current, the depth of corrosion on the anode will be inversely 

proportional to anode area. 

Since power requirements for cathodic protection systems are relatively low, the 

application fits the capabilities of solar energy systems. 

4.8 LEAK DETECTION 

In addition to inspecting the pipeline route visually on the ground or by means of light 

aircraft, advanced methods are now employed to detect smaller leaks and others more rapidly. 

The minimum size leak that can be detected depends on a number of factors: 

• Type of fluid in the pipe. 

• Accuracy of the metering system and the accuracy of temperature and 

pressure transmitters. 

• Line size. 

• Wall thickness. 

• Length of line. 

• Steady-state or transient condition of the pipeline. 
 85 

• Analytical equipment. 

• Experience of the personnel involved. 

Metering accuracy plays a key role in leak detection because one important way to detect 

leaks is by direct observation of the pressure drop and volume loss, based on comparing the flow 

into a segment of pipeline and the flow out of the segment. This approach can be effective with 

relatively simple instrumentation, but can also be used with more complex leak detection 

models. Instrumented pigs have been used to monitor a pipeline for leaks. 

4.9 INTEGRITY ASSESMENTS 

Routine evaluation of the physical condition of an oil pipeline is critical for ensuring 

pipeline safety. The AOPL and the API have jointly published an overview of pipeline integrity 

programs in effect for liquid pipeline systems (AOPL/API 2006). Their overview is summarized 

below. Pipeline integrity can be determined through direct assessment methods, hydrostatic 

testing, and by the use of internal inspection tools. Using direct assessment methods, oil pipeline 

operators can determine the integrity of an oil pipeline through visual and physical (internal and 

external) observations. Internal inspections of oil pipelines involve the use of smart pigs. 

Hydrostatic testing involves pressuring the pipe to a level equal to or above its normal operating 

pressure. Oil pipeline operators generally use a combination of direct assessments, internal 

inspection tools, and/or hydrostatic tests for ensuring the safe and reliable operation. 

Direct assessment methods include various types of cathodic protection surveys, such as 

close interval surveys (to ensure that the pipe is not corroding) and physically uncovering 

selected segments of the pipeline and examining the external coating as well as the steel pipe. A 

detailed examination of the internal and external condition of the pipe also can be accomplished 

when sections of pipe are inspected or removed for any reason, such as pipeline relocation, 

installation of taps, installation of test leads, etc. The pipeline ROW may be assessed by ground 

and aerial surveillance to look for any discoloration of plants and grasses as well as to observe 

unusual activity in the area of the pipeline (for potential outside force damage). 

Smart pigs are routinely used by the oil pipeline industry to detect loss of metal and in 

some cases deformations in the pipeline. Inserted into the pipeline and propelled by the flowing 

liquid, smart pigs record physical data about the pipeline’s integrity (e.g., location of reduced 

pipe wall thickness, dents, etc.) as they move through the pipeline. Evaluation of smart pig data 

allows the pipeline operator to make integrity decisions about the pipeline and to find and 

mitigate potential problem areas before they become a problem. 

Since their development in the 1960s, smart pigs have undergone several generations of 

technological advancements. As smart pig technology has evolved, oil pipeline operators have 

required the use of specialized smart pigs. Specialized smart pigs have evolved into three types: 

metal-loss tools, crack-detection tools, and geometry tools. 
 86 

4.9.1 Metal-Loss Tools (Corrosion Tools) 

A number of smart pigs have been developed to inspect for metal loss. The magnetic flux 

leakage (MFL) smart pig induces a magnetic field in the pipe and monitors for anomalies in the 

magnetic field that are later interpreted as potential metal losses due to corrosion. Highresolution MFL smart pigs can not only locate potential corrosion, but can also collect data to 

allow for a determination of whether the corrosion is advancing from the inside or outside of the 

pipe. Industry standards have been developed for use of the collected data to perform 

calculations of such characteristics as the depth of corrosion pitting, but typically, corrosion must 

have advanced to a depth of at least 20% of the pipe wall thickness before smart pigs can detect 

it. However, smart pigs are not reliable for identifying flaws in the pipe that are oriented along 

the pipe’s long axis, such as stress corrosion cracking, selective seam corrosion, and axial 

gouges. 

The ultrasonic smart pig, also called the UT tool, measures pipe wall thickness by using 

ultrasonic technology. The UT tool transmits an ultrasonic pulse into the pipe wall and directly 

measures its thickness. However, the inside surface of the pipe must be relatively clean for the 

tool to be effective; consequently it is not typically used for crude oil or heavy oil pipelines 

where paraffins or other debris can accumulate on interior pipe walls. Further, its overall 

effectiveness decreases with decreasing wall thicknesses. 

4.9.2 Crack-Detection Tools 

A variety of smart pigs are now available with instrumentation that can identify cracks in 

pipe walls. One such tool uses ultrasonic sound, interpreting the reflection of that sound back to 

the instrument as a crack. However, because the ultrasonic signal would not travel effectively in 

a gaseous pipeline, this tool is effective only for use in liquid pipelines. 

 Another smart pig, known as the transverse magnetic flux leakage pig, is similar in 

operation to the magnetic flux smart pig discussed above; however, the magnetic field it creates 

is oriented along the long axis of the pipe, making this tool especially sensitive to longitudinal 

seams cracks and longitudinal seam corrosion. Nevertheless, small cracks may not be detected, 

and while the tool can detect the presence of a larger crack, it cannot determine its severity. 

Consequently, visual inspections of suspect areas typically follow the use of this pig. 

 Smart pigs are now under development that simultaneously send ultrasonic in two 

directions along the pipeline to locate and size longitudinally oriented crack and manufacturing 

defects. 

4.9.3 Geometry Tools 

As discussed above, the “roundness” of a pipe is critical to the overall performance and 

delivery capacity of the pipeline system. Thus, pipe deformations must be identified and 

corrected. Various smart pigs have been developed for that purpose. They are designed to 
 87 

identify external dents or damage to the pipe from external forces that have caused a change in 

overall pipe geometry. Two basic types of geometry pigs are in service, caliper pigs and pipe 

deformation pigs, and both operate on the same principles. Caliper pigs can use either 

mechanical arms or electromagnetic signals to identify the exact locations of the interior pipe 

wall. Data collected as the pig moves along the pipe can then be interpreted as dents or 

deformations in the pipe. Pipe deformation smart pigs are similar in function to caliper pigs, but 

incorporate a gyroscope for locating anomalies along the pipe’s circumference more precisely. 

4.9.4 Mapping Tools 

Smart pigs equipped with global positioning system (GPS) capabilities are also in 

service. With this feature, identified anomalies or suspect areas can be precisely located for 

directed repair and maintenance. 

4.10 PIPELINE REPAIR TECHNIQUES 

Leaks in the pipeline demand immediate attention. Repairs to mainline pipe can be 

accomplished in a variety of ways, from replacement of an entire segment to replacement of a 

small section within which the leak has occurred, to application of a patch to the existing pipe. 

None of these repair strategies can be selected until a thorough investigation is completed to 

fully understand the nature and causal factors of the leak. In addition to replacement of damaged 

pipe, repairs could also involve reburial or rerouting of the pipe to prevent reoccurrence of the 

damage. 

Although some repairs require an entire shutdown of the pipeline, many might involve 

only very temporary interruption of operations to isolate and bypass the damaged area, with the 

majority of the repairs occurring while the pipeline remains operational. Typically, plugs are 

inserted to temporarily isolate the damaged area so that isolating valves and a bypass could be 

installed. A variety of plugging pigs are available expressly for this purpose. Once the bypass 

components are in place, “hot tap” machines already attached to the newly installed bypass 

valves will tap the pipeline to allow product to flow through the bypass, isolating the damaged 

mainline pipe. With the damaged section drained of fluid and the pressure relieved, the damaged 

section can be removed and the repair made. Equipment is available to perform this type of 

operation on pipe sizes up to 48 in. in diameter. Hot taps can be made into pipelines operating at 

pressures up to 1,400 psi and temperatures from –20°F to 700°F. Plugging can be done at 

pressures to 1,200 psi and temperatures from –20°F to 650°F. Once the repair is completed, the 

bypass valves can be closed and the product flow returned to the newly repair segment of the 

pipeline. Bypass components may be left in place or removed. If removal is called for, the hot 

taps initially made to create the bypass must be patched, or, alternatively, the bypass valves can 

be left in place as a means of sealing the hot taps. 
 88 
 89 

5 DECOMMISSION AND DEMOLITION 

Decommissioning is the process of taking equipment out of service when it has reached 

the end of its useful life. From an operational perspective, that point is reached when 

maintenance and replacement costs for older equipment begin to outweigh the value obtained 

from continued operation. Advancements in technology can also signify the point in a system’s 

lifetime when decommissioning is warranted. Alternatively, decommissioning may be 

appropriate due to a change in demand for the commodity being transported or when the 

locations being served by the pipeline no longer align with locations of high demand for the 

commodity or when more economical alternative supply paths have been established. Finally, 

decommissioning may be specifically directed by lease or permit stipulation. 

The economic lifetime of a pipeline (the time necessary for depreciation of the initial 

investment) is typically around 50 years; however, with a sufficient commitment to maintenance 

and upgrading, pipeline systems can remain functional for much longer periods of time. Unless it 

is incompatible with future land uses planned for the ROW, industry practice is to leave a 

mainline pipe in the pipeline trench located in the ROW.43 This prevents the additional 

ecosystem disturbances that would result during removal of the pipe and other buried 

components. Removal costs also encourage abandonment in place. 

Typical abandonment-in-place processes include: 

• Removing any cathodic protection from the pipeline. 

• Physically disconnecting the pipeline from any operating facilities. 

• Removing the product from the line. 

• Cleaning the line by flushing it with fresh water, air, or inert gas. 

• Capping the pipe at all open ends by welding on steel caps. 

• Hardening foam is injected at certain locations along the pipe to prevent water 

and contamination migration through the pipeline. 

Any unnecessary surface facilities associated with the abandoned pipe are typically also 

removed. Land owners may also require removal of all belowground elements that exist within 

3 to 4 ft of the surface so as not to encumber reestablishment of vegetative cover or impede 

surface land uses such as agricultural uses. 

 

43 Because cost of removal may be as great as initial installation costs and the value recovered from recycling 

mainline pipe is not likely to cover removal costs, most mainline pipe is abandoned in place; however, valves, 

special fittings, and all aboveground features (e.g., pump stations and all of the equipment therein) are removed 

and recycled. DOT’s OPS maintains statistics regarding the lengths of interstate pipelines abandoned in place. 

See: http://ops.dot.gov/library/abandoned/abandon_pipelines_orig.htm. 
 90 

Decommissioning plans are very site-specific and may not call for the same techniques 

throughout the entire pipeline system. As suggested above, there can be circumstances in which 

removal of buried pipe or removal of pipe from beneath a waterbody can cause more disruption 

to ecosystems (including the disruption caused by constructing the necessary access roads for the 

heavy equipment needed for pipe removal) than abandoning those segments in place. In those 

instances, the decision may be to purge and clean the pipe of product, remediate any accidentally 

released products, and abandon the pipe and associated infrastructure in place. Typically, pipe 

corrosion control systems are also abandoned, allowing the pipe to corrode as circumstances 

would dictate. Eventually, this might lead to surface subsidence when the pipe corrodes to the 

point that the empty pipe can no longer support the weight of the overburden. In those instances, 

abandonment may also include filling the pipe segment to the greatest extent possible with inert 

material such as sand. 
 91 

6 EMERGENCIES AND OFF-NORMAL EVENTS 

Once pipelines are operational, monitoring the pipeline’s flow parameters, instituting 

operational procedures and controls, and performing periodic maintenance (especially, for 

example, in conformance with the principles of Reliability-Centered Maintenance)44 are all 

typically used to reduce the potential for accidental releases of commodities. Notwithstanding 

such efforts, mechanical system failures and human error can still occur, some of which may 

result in accidental releases of pipeline commodities. Consequently, all pipeline operators are 

required to develop written procedures within an emergency plan that must address all credible 

off-normal events. Each such credible event must be evaluated for its short- and long-term 

impacts and the appropriate response actions developed accordingly. 

Evaluations of off-normal events, including credible spill scenarios, consider relevant 

circumstantial factors (e.g., ecosystems potentially impacted); potential natural, mechanical, or 

human causal factors (e.g. earthquakes, equipment failure, human error); the expected 

frequencies of such events; and the potential magnitude and severity of the events in terms of the 

amounts and types of commodities released, to determine the short-term and long-term impacts 

of a release and to devise the appropriate response actions to mitigate those impacts without 

increasing the risk to facility response personnel or the public from inappropriate response 

actions. For example, releases of flammable liquids with high vapor pressures in lowland areas 

require a determination of the potential for formation of explosive vapor atmospheres before 

response actions involving internal combustion engines or spark-producing equipment could 

commence. Review of pipeline design features, such as distance from the release to the nearest 

upstream and downstream valves, would determine the maximum potential volume of product 

that would be in jeopardy of release. Such estimates, together with circumstantial factors such as 

environmental features and distance to areas of critical environmental concern (ACEC) or 

sensitive ecosystems, provide a basis for both the urgency and the necessary scale of the 

response action. 

For the purposes of impact analysis, there is no difference whether a leak or rupture 

occurs along the pipeline or at a pump station. The impact from a continuous low-volume leak in 

the pipeline would be similar to that from drips or spills at the pump station. Likewise, the 

impact from a pipeline rupture would be similar to that from a large release due to an equipment 

failure at a pump station. In all instances, the impacts depend on the environmental setting and 

the quantity and nature of the leaks. However, it is important to note that pipeline control centers 

routinely monitor pressures along the system as their primary leak detection capability. Pipeline 

ruptures will result in significant pressure drops, and operators observing such pressure drops 

would immediately recognize the possibility of a rupture and began shutting operations down 

and isolating the segments where pressure drops first occurred. Automated systems are typically 

 

44 Reliability-Centered Maintenance is a process for systematically and scientifically establishing appropriate 

maintenance actions, schedules, and priorities for mechanical systems and other physical assets. When applied to 

operations involving hazardous materials, the nature, scope, and priority of the maintenance actions are based on 

an understanding of the nature and extent of adverse consequences to workers, the public, and the environment 

that would result from component or system failure. 
 92 

designed to do the same if the operator does not act within a certain time frame after the initial 

pressure drop alarm is initiated. However, small-volume leaks may not necessarily result in 

pressure drops to which the system’s pressure monitors would respond; therefore, such small 

leaks can go undetected at the pipeline control center and may remain undetected until pipeline 

ground or aerial surveillance crews discover the leak by visual observation. 

Accidental releases of various commodities routinely conveyed by pipeline result in 

substantially different impacts and dictate fundamentally different response actions. In general, 

crude oil, due primarily to its viscosity, would be less mobile in the environment than less 

viscous refined products. However, toxic constituents in crude oil such as benzene can find their 

way to groundwater or surface water. Such toxic constituents are also present in many refined 

products. Some, such as the BTEX fraction of gasoline45 are composed of polar organic 

molecules with relatively high solubility in water, thus increasing their potential environmental 

mobility from the spill site. Each of these highly flammable components also has a relatively 

high vapor pressure under standard conditions and broad explosive ranges of their vapors in air, 

increasing the potential for their volatilization from the surface of a spilled fluid and the 

subsequent formation of vapor and air mixtures having explosive properties. Obviously, such 

properties must be considered in the development of appropriate spill response actions to prevent 

the response itself from exacerbating the impact of the initial spill. In addition to contributing to 

gasoline’s viscosity, specific gravity, and solubility, benzene and xylene can increase the 

permeability of clay over time. These chemicals can cause clay shrinkage and cracking, thereby 

increasing the chances of fracturing clay soils in the upper horizons and providing pathways for 

gasoline to move more rapidly to subsurface aquifers than might otherwise occur (EPA 2000). 

 

45 The BTEX fraction is composed of benzene, toluene, ethylbenzene, and the three isomers of xylene. 
 93 

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