# Overview of the Design, Construction, and Operation of Interstate Liquid Petroleum Pipelines ANL/EVS/TM/08-1



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## Overview of the Design, Construction, and Operation of Interstate Liquid Petroleum Pipelines ANL/EVS/TM/08-1

by

T.C. Pharris 1 and R.L. Kolpa 2

1 Decision and Information Sciences Division

2 Environmental Science Division Argonne National Laboratory

November 2007iii 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 La unching/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 In terference................................................................................. 39iv 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............................................................................................................ 4 8 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 .......................................................................................... 86v 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 ........................................................................ 64vi 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 Cro ssing 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 Contai ning 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 Stat ion 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 Ra ilroads Versus Depth of Cover..................... 26

2.1-3 Degree of Component Vulnerabil ity to Damage or Disruption from Natural Hazards and Human Threats ............................................................. 40vii NOTATION

The following is a list of the acronyms, initialisms, and abbreviations (including units of measure) used in this document. Acronyms and a bbreviations 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 Trans portation 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 Engineeri ng 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 an d 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 gauge1

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 fr eight 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 trans port (by ton-mile) occurs by pi peline, with marine movements accounting for 28% and rail and truck transpor t making up the balance. In 2004, the movement of crude petroleum by domestic federally re gulated pipelines amount ed to 599.6 billion tonmiles, while that of petroleum products amount ed to 315.9 billion ton-miles (AOPL 2006). As an illustration of the low cost of pipeline transporta tion, the cost to move a barrel of gasoline from Houston, Texas, to New York Harbor is only 3¢ pe r gallon, which is a small fraction of the cost of gasoline to consumers.

Pipelines may be small or large, up to 48 inch es in diameter. Nearly all of the mainline pipe is buried, but other pipe line components such as pump st ations 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 destina tion, while others are ve ry complex, having many sources, destinations, and interconnections. Many pipelines cross one or more state boundaries (interstate), while some are located within a sing le state (intrastate), an d still others operate on the Outer Continental Shelf and may or may not ex tend into one or more states. U.S. pipelines are located in coastal plains, dese rts, Arctic tundra, mountains, a nd 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 th e United States is extensive. There are approximately 55,000 miles of crude oil trunk lines (u sually 8 to 24 inches in diameter) in the United States that connect regi onal markets. The United States also has an estimated 30,000 to 40,000 miles of small gather ing lines (usually 2 to 6 inches in diameter) located primarily in Texas, Oklahoma, Louisiana, and Wyoming, w ith small systems in a number of other oil producing states. These small lines gather the oi l from many wells, both onshore and offshore, and connect to larger trunk lines meas uring 8 to 24 inches in diameter.

There are approximately 95,000 miles of refine d products pipelines nationwide. Refined products pipelines are found in al most 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, installati on, and operation provided in the following sections is only a cursory treatment. Readers interested in more detailed discussions are invited to consult the myriad engineeri ng publications available that provide such details. The two primary publications on which the fo llowing 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 sour ces of information. In partic ular, the website maintained by the U.S. Department of Energy’s En ergy Information Administration (EIA) (http://www.eia.doe.gov) is recommended. An excelle nt bibliography on pipeline standards and practices, including special consider ations for pipelines in Arctic climates, has been published jointly by librarians for the Alyeska Pipeline Se rvice Company (operators of the Trans-Alaska Pipeline System [TAPS]) and the Geophysical Ins titute/International Arctic Research Center, both located in Fairbanks (Barboza and Treb elhorn 2001), availabl e electronically at http://www.gi.alaska.edu/services/library/pipeline .html#codes. The Association of Oil Pipe Lines (AOPL) and the American Petroleum Institute (A PI) jointly provide an overview covering the life cycle of design, construction, operations, maintenan ce, 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 offshor e 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 va rious fuel oils, are sizable porti ons of the pipelines business, whether produced in domestic refineries or impor ted to coastal terminals. Other materials include petrochemical feedstocks (also known as seconda ry feedstocks) such as benzene, styrene, propylene, and aromatics such as xylene, toluen e, 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 pipe lines 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 vi scous to be transported by pipe line. 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 fu rther processing. Also in recent years, longdistance pipelines have been cons tructed to carry “produced water” 3 from oil and gas fields to

refineries and other indust rial facilities that use copious amounts of water, but are located in arid areas or areas where water availability is limite d. Hydrogen is also deliv ered by pipeline, albeit over relatively short distances, typically connect ing hydrogen production fac ilities with refineries and other industries that use hydroge n 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 recovere d 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 significan t 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 significan t cleanup-related impacts • Low acute toxicity re lative 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 re lative to other oil types

provides an overview of the physical characte ristics of the more common liquid hydrocarbons transported via pipeline. Typi cally, more than one product is transported through the same interstate pipeline. In those instances, the line pipe m eets the most rigorous product-specific standards among all of the materials being transported. Increased numbers of products carried on a pipeline increase the support faci lities, such as tankage, required to receive and segregate the different products.4

1.3 T YPES OF L INE PIPE

Steel pipe is used in most pipelines tr ansporting hydrocarbons. It is manufactured according to the specifications of the Amer ican 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 sp ecified, based on yield strength. 4 Grade A line pipe has a minimum yield strength of 30,000 pounds per squa re inch (psi), with Grade B having a minimum yield strength of 35,000 psi. Other grad e categories may indicate special fabrication methods. For example, Grade X42 indicates a pi pe 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 X80 5 are available, but are typically used in offshore or high-pressu re 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 Tubul ar 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 pi pe fabrication can be found in Kennedy (1993).

Line pipe is manufact ured as either seamless or welde d. These designations refer to how each length, or joint, of pipe is manufactured, not how the joints are conne cted in the field toform a continuous pipeline. Seamless steel pipe is made without a longitudinal weld by hotworking lengths of steel to produce pipe of the de sired size and properties. Welded pipe is made using several manufacturing pro cesses. 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 mate rials other than steel, in cluding fiberglass, various plastics, and cement asbestos, has been used for special applications i nvolving corrosive liquids, such as saltwater disposal or the tran sport of highly co rrosive 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.p df. (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 facil itate 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 standard s have been promulgated to address the design and constr uction of these facilities. 7 In addition, each facility needs to have waste handling and environmental control capabil ities. Again, the nature and capacity of the storage depend on the business of the pipeline an d the product(s) it carries . Since many pipelines originate or terminate at coastal facilities to en able marine movements, dock facilities are also often included in a comprehensive definition of a pipeline system.

Along with meeting all of the tankage requi rements mentioned above, most facilities have the ability to handle pipeline waste materi als and/or interface materi als when the pipeline handles multiple products. Transmix, which is the mixture of two hydrocarbons shipped together, must be segregated and either dow ngraded to an appropria te specification or reprocessed. Crude oil delivered through pipe lines 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 de salter are typically combin ed with other refinery

wastewaters and treated in on-site facilities before being used (recycled) or to meet the requirements and pollutant limita tions of discharge permits.

Nearly all pipeline terminal facilities ha ve pumps, pig launching/recovery facilities (see Section 2.1.13), and the capab ility of handling pipeline sludge that can accumulate on pipeline walls and is removed dur ing pigging activities. All pipelin e terminals need to handle the drainage of lubricants and pipeline products, sampling dump stations, contaminated condensates, etc. Terminals are also required to develop sp ill 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 numbe r of vendors. See, for example: http://global.ihs.com/search_res.cfm?currency_co de=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 contam ination 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. De pending on the amount of pr oduction water that is allowed to be introduced into the pipeline and the source, pipelines that car ry certain crude oils,

as well as the terminals and refineries that r eceive them, may also gene rate waste from pigging operations or tank and equipment cleaning operations that contain naturally occurr ing radioactive materials (NORM). Such wastes require segregat ion 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 designate d energy corridors. However, interconnecting pipelines and surge or pressure-relief tanks or brea kout tanks are integral to interstate pipeline transport and can be expected to be located clos e 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 operatio ns will also be located close to the pipeline.

In accordance with federal or state environm ental regulations and to provide for safe operation, typical design and operational considerations that have b een incorporated into industry standards are reflected at facilities where storag e is occurring. Adherence to relevant standards results in features such as tank dikes, enclos ed drainage systems, doubl e seals on floating roof tanks, leak detection, corrosion monitoring and pr otection, requirements fo r periodic inspection and monitoring programs, procedures fo r purging tank vapor spaces and vapor recovery/treatment, and specification of minimum corrosion allo wances. All storage locations with capacities above prescribed volumes are also required to deve lop 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 underg round tanks, aboveground tanks generally predominate. Various tank designs are employed, so me specifically suited for particular products or conditions. These include cone roof tanks, ope n-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 pr essures, often in a liquefied state).

1.4.2 Piping Types

1.4.2.1 Flowlines

Flowlines are used as part of a crude ga thering 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 lo w 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 se condary feedstocks containing listed chemicals or distillate products that demonstrate flammability character istics specified in haza rdous 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 we lls are not pressurized and require pumping to collecti on systems. Flowlines typicall y operate at pressures below 100 psi.

Flowlines are normally made of steel, although va rious 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 ma terials other than steel. Flowline pipe wall

thicknesses of 0.216 inch for a 3-inch-diamete r 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 facilitie s over long-distance trunk lines to refineries or other storage facilities. Crude trunk lines operate at higher pr essures 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. Pro duct 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, si nce 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 ch emically compatible with each other, but may differ in physical properties such as density. So me intermixing occurs at the interface of two products sequentially introduced in to 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 co mmodities 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 o il 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 sewe r 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 typi cally 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 fa ilures or other signif icant 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, st orage 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 pipelin e to tanks to pipeline. Systems and processes are in place to determine when the shrinka ge 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 requ ire regular monitoring and maintenance. Along with pump seals that require continuous leak detection and repair, va lve manifolds must be closely monitored and periodically overha uled 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 destin ation of a pipeline. Since many interstate pipelines have blending facilities on one end or the othe r, 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 overpr essurization 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 fr om one location to a nother. 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 stati on. The pig’s outer diameter is the same as, or slightly larger than the internal diameter of th e pipe, so that a portion of the pig is compressed when placed inside. In most instances, the pi g itself has no power sour ce to propel it along the pipe, but instead is carried along the pipe by the flow of the liqui d in the pipe. Obviously, pigs must be removed before reaching the next pump st ation. 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 pi peline operations. Data recorded by smart pigs are typically integrated with the data from the pipeline’s supervisory co ntrol 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 disc ussion of the various types and applications of pigs.

1.4.8 Supervisory Control and Data Acquisition (SCADA) Systems

Pipelines are monitored and operated us ing sophisticated SC ADA systems. SCADA systems regulate pressure and flow by mon itoring and controlling pump operation and the positions of valves. SCADA systems also perfor m a variety of additional functions including alarm processing, leak detection, hydraulic analysis, pump station monitoring, throughput analysis, and other functions deemed critic al 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, ar e only as good as the communication system that transmits data a nd commands throughout th e pipeline system. A communication system includes equipment, such as telecommunication towers, and cabling to provide voice and/or data communi cations to the various facilitie s 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, sa tellite terminals, micr owave, point-to-point radio pairs, and fiber optic cable. Often, pi peline 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 o il industry, the majority of transfers and sales are

measured in volumetric units such as barrels or gallons, so this t ype 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 co nducted to insure the accuracy of the measured flow quantities. Flow meters are commonly used where custody tr ansfers or sales are involved. Flow meters also offer the pi peline operator the opportunity to monitor for any leaks by performing volume or mass balan ce checks around specified secti ons of the pipeline network. These balance checks would typically be pe rformed via the SCADA computer system.

1.4.11 Valves

Valve types and locations comprise an impor tant 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 overpressu rization 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 thr ough the use of an impressed current or sacrificial anodes to counteract

13 In some instances, valve placement is dictated by environmen tal factors. For example, mainline valves for TAPS are spaced such that no more than a prescribed amount of product would exist in th e 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 ev ent 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 polye thylene- or epoxy-based paints, some also including asphalt and/or coal tar, ar e used for buried pipe and valves.

Cathodic protection involves either the use of an impressed current or sacrificial (or galvanic) anodes. For impresse d-current systems, anodes are buried in the soil proximate to the section of buried pipe being protected. A current is applied to the anod es 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 pi pe to the soil that woul d otherwise have resulted from the pipe’s oxidation, thereby canceling th at reaction.. Impressed-cu rrent 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 year s, and many last over th e lifetime of the pipe. SCADA systems can be configured to monitor th e 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 poi nts 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 co rrode 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 zi nc or magnesium in the electrodes that looses electrons in the process. Thus, the electrodes are “sacr ificed” to protect the iron pipe. Galvanic electrodes must be replaced peri odically. Site-specific conditions of soil mois ture 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 th e pipeline and easily recoverable, so that the extent of its degradation can be observed and re placement intervals established for the electrodes attached to the pipe, and excavations to expos e those electrodes for replacement can be done only as necessary.1213

2 PIPELINE DESIGN

2.1 FACTORS INFLUENCIN G 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 e ngineering 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 vi scosity 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 be tween, pump stations; and

•

• Pump station horsepower required. 14

2.1.2 Safety

Safety in pipeline design and constructi on 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 Tr ansportation’s (DOT’s) O ffice of Pipeline Safety (OPS) regulations provide appropriate safety factors and quality control issues during construction. Metering stations and SCADA systems provide con tinuous monitoring oversight of pipeline operations. Training of pipeline operating and mainte nance personnel is also a key ingredient in the ongoing efforts to insure system integrity an d safety. Safe operations result from developing and strictly adhering to standa rd 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 devi ces, and appropriate personal pr otective equipment. Standard operating procedures typically ar e developed with reference to government and standard industry practices, as well as co rporate safety policies, experien ce, philosophy, and business practices. Regulations promulgated by the Occupational Safe ty and Health Admini stration (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 stan dards for use in the oil and gas pipeline industry. The scope of the first draft of the ASME Code for Pr essure Piping, which was approved by the American Standards Association in 1935, included the design, manuf acture, 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 Na tional Association of Corrosion Engineers (now known as NACE Internationa l), also develop st andards used by the pipeline industry. 15

The industry adheres to the fo llowing summary of standards: 16

• Tank operation and construction (15 st andards maintained by a committee operated by API)

• Underground storage cave rns (2 API standards)

• Manufacture of line pipe (4 API standards)

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

• Welding (15 American Welding Soci ety [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 in formation 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 Standa rds. Available at https://www.piersystem.com/external/ index.cfm?cid=888&fuseaction=EXTERNAL.docview&documentID=57733. (Accessed February 2, 2007.)15

• Pipeline integrity (API Recomme nded 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 sta ndards issued jointly by ANSI):

− “Pipeline Maintenance Welding Practices,” 3rd edition, API Recommended Practice (RP) 1107

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

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

− “Welding of Pipelines and Relate d 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 Railr oads and Highways,” API 1102 (1993)

− “Marking Liquid Petroleum Pipeline Facilities,” 3rd edition, API 1109, July 2003

− “Developing a Pipeline Supervis ory 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

199816

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

November 2001

− “In-Line Inspection Systems Qualif ication Standard,” 1st edition, API 1163, August 2005

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

March 1997

− “Repairing Crude Oil, Liquid Petrol eum Gas, and Product Pipelines,” 3rd edition, API RP 2200, May 1994

− “Steel Pipelines Crossing Railr oads and Highways,” API RP 1102, January 1993

• ASTM standards 17

• ASME standards 18

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

− “Gas Transmission and Distributi on 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 Distri bution 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.o rg/ansidocstore/astm.asp. (A ccessed 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 & Appli cations; Protective Coatings; Pipeline Coatings

• Institute of Electrical and Electronics Engineers, Inc. (IEEE), National Electrical Safety Code, 2007 19

• 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), 2007 21

• International Conference on Building Officials, Uniform Fire Code,

2006 edition 22

• National Fire Protection Association, National Electrical Code Handbook

, 2005 edition 23

A December 2001 report for the API’s Pipe line Committee contains an interesting discussion on the evolution of pipeline technologi es 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 pipe s to inhibit corrosion. These may be applied at the manufacturing plant or a pipe coating plan t located separately. However, coatings are also sometimes applied at the construction site. Ev en for precoated pipe, field dressings of joints and connections are also performed at the construction site just prior to burial. For particularly corrosive products (i ncluding 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 down load at http://standards.ieee.org/nesc/. (Accessed December 6, 2006.)

20 The IAPMO Uniform Plumbing Code is available fo r 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 Internationa l Conference of Building Officials, are available for electronic purchase at http://www.techstreet.com/cgi -bin/browsePublisher?publishe r=ICBO&orderBy=doc_no. (Accessed December 5, 2006.)

22 The Uniform Fire Code is available for electr onic 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 produc t 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 applie d overlapping wrapping, are often installed on the exterior of the pipe to fu rther assist in corrosion control, but also to primarily protect the pipe from mechanical da mage at installation. Wraps and tape often are impregnated with tar or other as phalt-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 b acteria, yet remaining sufficiently flexible that they continue to provide a pr otective coating on the pipe thro ughout a wide temperature range. Likewise, wrapping materials and ta pe are stable and inert (incl uding toward the material being transported in the pipeline) a nd 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 func tions: 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 stab ilization of the pipe in the event of seismic shifts or frost heaves. Sands and gravels are typi cal 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 accumula ted water from the vicinity of the pipe.

All newly coated pipe used to transport haza rdous liquids must be electrically inspected prior to backfilling to check for faults not observa ble by visual examination. Material faults such as microcracks demonstrate a characteristic resp onse to applied current when the detector is operated in accordance with the ma nufacturer’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 capacitie s of the various components — as well as the conditions under wh ich the pipeline system operates dictate the system’s capacity. Larger diameter pipes allo w for higher mass flows of materials, provided other components of the pipeline system, primar ily pumps and pressure management devices, are properly sized and positioned. In general, the longer the segmen t of mainline pipe between pump stations, the greater the drop in line pressure. However, gr ade changes and the viscosity of the materials being transported can also have ma jor 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 availabl e in each line pipe diameter. The weight of the pipe in lb/ft, in turn, varies as the wall thic kness for a given outside diameter. For instance, API Spec 5L lists 24 different weights in the 16-inch-d iameter size (five weights are special weights), ranging from 31.75 lb/foot to 196.91 lb/foot. Th e 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 light est weight pipe to 13.500 inches for line pipe weighing 196.91 lb/foot . Greater wall thicknesse s are selected for high-pressure applications or when the pipe segment might be subjec ted 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 determin ed by the design flow rate vapor pressure of the liquid, the distance the material has to be tr ansferred, and the size of line that carries the liquid. Pipe operating pressure and pump capabiliti es and cost typically drive decisions on line

25 Landslides would not necessarily directly impact burie d pipe unless the slide action itself were to expose the pipe, making it subject to forces from additional lands lide 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 stati ons, and the like. Grades notwithst anding, line pressure follows a sawtooth curve between pump stations. The maxi mum and minimum line pressure that can be tolerated, together with the physic al properties of the materials not ed 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 pr essure of the material are the primary considerations. These and other engineering design parame ters 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, tu rbine 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 incr eased. The compressibility of such materials is obviously critical to pipeline de sign 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 ha s little effect on the material’s density or the volume it occupies at a given temperature; consequently, compressi bility 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 fl oat; those with API gravities less than 10 will sink; the API gravity scale is calibrated such than most petroleum li quids (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 bot h directly and indirect ly. In general, as liquids are compressed — for example, as th ey 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, th e operating temperature of a pipeline will affect its throughput capacity. Lowering te mperatures can also affect throughput capacity, as well as overall system efficiency. In ge neral, as the temperature of a liquid is lowered, its viscosity increases, creating more frictional drag along th e inner pipe walls, requ iring 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 te mperatures 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 thei r 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, viscos ity 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 fl ow increases as the centistoke value (and viscosity) increases. Overcoming viscosity requi res energy that must be accounted for in pump design, since the viscosity determin es the total amount of energy th e pump must provide to put, or keep, the liquid in motion at the desired flow rate. Viscosit y 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 so me materials (especially some crude oils). Such drag-reducing agents are larg e molecular weight (mos tly synthetic) polymers

that will not react with the comm odity 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 o il fractionation such as raw naphtha. Diluents are used to mix with visc ous crude feedstocks such as bitumen recovered from tar sands and other very heavy crude frac tions 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, crude22

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 loweri ng both its effective viscosity and pour point temperature.

• Introduce water that will pr eferentially move to the inner walls of the pipe, serving to reduce the effective coeffici ent 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 e ffective for crude oils, but is virtually unavailable when moving distillate produc ts that must conform to a specific chemical composition.)

Waxy crude can be pumped below its pour poi nt; more pumping energy is required, but there is no sudden change in fluid characteri stics at the pour poin t as far as pumping requirements are concerned. However, if pumpi ng is stopped, more ener gy 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 o ccurs, the crude be haves 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 flow s in the pipeline than it di d 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 hydrocarb ons), “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, prec ipitation or gelling of products contained in pipelines can cause significant operational difficulties and may also result in environmental23

impacts if pipeline ruptures occu r 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 liq uids exhibit a vapor pressure, which typically increases with temperature. The vapor pressure of water increases steadily with temperature increases, reaching its maximum of one atmosphe re 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 st andardized testing procedure and are represented as the Reid vapor pressure. Reid vapor pressures are critical to liquid petroleum pipeline design, since the pipeline mu st maintain pressures greater than the Reid vapor pressure of the material in order to k eep the material in a liquid state. Blended (or “boutique”) vehicle fuels, requi red 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, pi pelines handling such fuels must constantly monitor their vapor pressure and adjust opera ting conditions accordingly. Pipelines carrying liquids with high vapor pressures can be designed to operate unde r 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 ef ficiency and also the longevity of system components. Failure to maintain a full face of li quids in a single-phase liquid pipeline can result in increased risks of fires and explosions. Si ngle-phase liquid pipeline s 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 va por pressures for gasolin e, turbine fuel, and diesel fuel are 15, 2, and 2 psia, respectively.

2.1.7.7 Reynolds Number

The Reynolds number, named after Osborne Re ynolds, the scientist who first proposed its usefulness in studying fluid dynamics, is a dimensionl ess number that repres ents 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 resisti ng its movement; consequently its

movement will be violent and turbulent. The Reynolds number representing the transition zone24

between laminar and turbulent flows is called the critical Reynolds number (R crit ), which is typically assigned a value of 2320. The Reynolds number depends on the force applied by pumps, the material’s viscosity at operati ng temperature, and the physical size and crosssectional shape of the pipe thr ough which the material is moving. Mo st pipeline designers select these components to establis h operating conditions near R crit 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 pr event it, petroleum pipelines are typically buried. Burial depths vary with geographic locatio n, but are typically designed to ensure that the entirety of the pipe is below the local frost line. At such de pths, the ambient soil temperatures are relative constant with season, although some minor variat ions can occur. Despite predictably stable temperature environments, pipeli ne design also accounts for thermal stresses, both expansions and contractions for the pipe and other component s. Expansion joints are employed, and, in some instances, trenches are made extra-wide to al low for lateral movements of the pipe with temperature. Thermal expansion jo ints, or loops, are also criti cal 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 supercool ing of the remaining liquids, if allowed to escape from the pipeline system at significant rates. Such supe rcooling can result in thermal cracking of pipes and pump housings.

27 Laminar flow represents a condition of greatest overall efficiency, while turbulent fl ow introduces vibration and generally accelerates the wear on sy stem components and increases the pot ential for system failure. Laminar flow is thus the preferred operating condition. However, economic performance requir ements 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 ar e 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 phase s, soil samples are taken at many points throughout to determine mechanical and ther mal stability, corrosivity, and electrical

conductance. Soils and subsurface materials are al so evaluated for their ability to support the weight of the pipeline support faci lities at sensitive areas, such as river crossings. Soil properties such as seepage, slope stability, tensile stre ngth, 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 ad dition to engineering considerations, site characterizations regarding the presence of th reatened 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 pressure s 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 lo ading is not typically a matter of serious concern to pipeline designers. However, there are some circumstan ces 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 distribu ted live loads. Large concentrated loads, such as those caused by truck-wheel loads, railway car s, and locomotive loads, are of most practical

interest.

Depending on the requirements of the design sp ecification, the live-lo ad effect may be based on American Association of State Highw ay and Transportation Officials (AASHTO) HS-20 (AASHTO 1998) truck loads or American Railw ay Engineering Association (AREA) Cooper E-80 railroad loads (AREMA 2006), as indi cated in Table 2.1-1. The values of the liveload pressure, P p , are given in psi and include an impact factor F = 1.5 to account for bumps and irregularities in the travel su rface. Other important impact fact ors 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 cap acity would also be impacted by such deformations, and the deformed pipeline itself w ould be subject to accelerated wear and an26

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 H20 a Railway E80 b Height of Cover (ft) Highway H20 a Railway E80 b

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 AREMA27

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 sp ecify 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 c over of 6 feet under railroad

tracks and 4 feet unde r highway surfaces.

If the pipe is buried with less than 2 feet of cover, the cont inual flexing of the pipe may cause a breakup of the road surface. If the pipe is mort ar-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 th e pipeline segment that could be sufficient to compromise the pipe’s integrity. When such c onditions are anticipated, special construction techniques n eed to be employed. Anchoring de vices or concrete coatings over the corrosion coatings are installed to help the pipe resi st 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 ar e 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 outwar d 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 wh ich 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 mi ne reclamation activitie s 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 regulatio ns in Title 49, Part 195, of the Code of Federal Regulations (CFR).28

is substantially larger than the collapsed mine cav ity that caused it. The vertical displacement is greatest at the center of a subsiden ce basin, but is typically less th an the original height of the collapsed cavity. Vertical displacement as well as tilting and shearing forc es throughout the basin are of greatest concern for surface structures th at lie within the basin’s footprint. Forces on

buried linear features within the basin’s foot print are unique. The be nding 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 cl oser 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 buckl e 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 pl ans are known to include the construction of an adjacent pipeline or the development of mine d areas. Pipeline stresses generated by nearby blasting can vary greatly, dependi ng 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 th e resulting pressure wave) and peak pipe stress are based on characterizing the blasting confi guration 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 tran sient 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 in tegrity or introduce fa tigue 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 care ful excavation of the pipe, raisi ng it out of its or iginal trench, and placing it into a prep ared 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 ove r-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 nativ e surface and subsurface materials in the uppermost portions of the soil mantle at a modera te to rapid rate (gen erally greater than 1 feet/year). Landslides that are characterized as catastrophic in their impacts typically involve mass movements that are many orders of magnit ude more rapid. However, landslides can also involve slow creep of materials over a relativel y 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 fo rces and events, both natural (e.g., earthquakes, seismic activity, excessive sa turation 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 wi thout 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 incl ude transitory strains caused by differential ground displacement and permanent ground displacement from surface faulting, lateral spread displacement, soil mass displa cement, 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 late ral forces and possibly even causing sufficient displacement to break the pipe.

High velocities of water in rocky areas or wa tercourses with steep banks have the highest scouring potential. Areas prone to flooding can al so experience excessive water flow velocities during those periods that can al so result in scouring action. The typical response to traversing rivers or drainage ways with hi gh scouring potential is to bury the pipe at greater depths or to suspend the pipe above these areas. In additi on, major river crossing s are required to be inspected every 5 years for indicatio ns of scour and/or exposed pipe.

2.1.9 Leak Detection 30

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 controlle rs 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 gr ound causes the water in the pore spa ces to exert such force on the soil particles that they begin acting independently of one anot her, 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 prog rams to the objectives contained in the API document API 1130, “Computational Pipeline Monitoring.”

Methods used to detect product leaks along a pi peline can be divided into two categories, externally based (direct) or internally based (inferential). Externally based methods detect leaking product outside the pipeline, and includ e traditional procedures such as ROW inspection by line patrols, as well as technologies like hydrocarbon sensing via fibe r optic or dielectric cables. Internally based methods, also know n 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 manu al or electronic computation (API 1995a).

The method of leak detection selected for a pipeline depe nds on a variety of factors including pipeline characteristic s, product characteristics, inst rumentation and communications capabilities, and economics (Muhlbauer 1996). Pipeli ne 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 re quired 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 fr om 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 availabl e from the Alaska Department of Environmental

Conservation website. 31

2.1.10 Overpressure Protection

A pipeline operator typically conducts a surge analysis to ensure th at 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 th e MOP except under surge conditions. In a blocked line, thermal expansion is a concern, es pecially if the li ne is above ground.

2.1.11 Valve Spacing and Rapid Shutdown

The spacings of valves and other devices ca pable of isolating a ny given segment of a pipeline are driven by two princi pal concerns: (1) maintaining th e design operating conditions of the pipeline with respect to thr oughput and flexibility and (2) facilitate maintenance or repairs without undue disruption to pipe line 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 c oncern to the greatest extent

31 http://www.dec.state.ak.us/spar/ipp/docs/ldetect1.pd f. 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 instal led in critical locations. Valves may also be required on either side of an exceptionally sensitive environmenta l area traversed by the pi peline. Finally, valves

will be installed to facilitate the introduction and recovery of pigs for pipeline cleaning and monitoring. They also are require d to be installed at river cr ossings over 100 feet wide. The design of these must comply with regul ations and industry best practices.

2.1.12 Pumps and Pumping Stations

Desired material throughput values as well as circumstantial fact ors along the pipeline route are considered in designi ng and locating pump stations. De sired operating pressures and grade changes dictate individual pump sizes an d acceptable pressure dr ops (i.e., the minimum line pressure that can be tolerated) along the ma inline; grade changes also dictate the placements of the pump stations. Pump stations are often fu lly automated, but can also be designed to be manned and to include ancillary f unctions 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 th e desired operating conditions can be obtained and sustained, the outfitting and location of pump stations are also often infl uenced by economics, typically representing a compromise between few large-ca pacity pump stations and a greater number of smaller-capacity stations. The overa ll length of the pipeli ne (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 pr ime movers (power sour ces that provide power, typically some form of mechan ical energy) to the pumps. To facilitate maintenance and to prevent disruptions of pipeline op eration as a result of equipment failure, most pump stations use several pumps arranged in para llel fashion. Typically, all but one of the pumps is capable of producing the desired operating pr essures and throughputs, so some pump is constantly off-line and in standby. Pump stations also represent locations wher e ownership or custody of the

material is transferred. For the sake of accountabi lity, such pump stations are also equipped with flow monitoring devices. Pump sta tions typically also have colo cated facilities that support pipeline operation or facilitate shutdowns or maintenance on pi peline segments. Thus, breakout tanks for temporary storage of materials or fo r use in managing line pressures and controlling product surges are also present at pump stations. Finally, pump stat ions are, in some instances,

colocated with terminal or breakout tankage facilities.

Although certain pump designs are preferred fo r 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 produc t pipelines. Selection of pump design is based on desired efficiency as well as the physic al 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 co mmon use: centrifugal pumps and positive displacement pumps. Centrifugal pumps are prefe rred for moving large volumes of material at moderate pressure, while positive displacement pu mps are selected for moving small volumes of material at higher line pressures. Centrifuga l 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 it s rotation into kinetic energy in the fluid being pumped, while the volute convert s the kinetic energy of the fl uid into pressure. Positive displacement pumps can be of various designs; ho wever, 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 fl uid 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 engine s. In recent years, most long- distance transmission pipelines have begun using electric motors or gas turb ines. 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 pr essures, 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 compatibil ity 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 th an other options. When maintenance costs are considered, times between major overhauls of prime movers vary, with electric motors and industrial turbines expected to require th e 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 ne xt pump. Typically, pig traps, launchers, and recovery facilities are co located 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 condi tion of the pipe, (3) or act as a plug or seal to separate products in multi-product commercial pi pelines or to isolate a segment for repair without depressurizing the remai nder of the pipeline. Pigs desi gned to clean the pipe can use mechanical means (often called scraper pigs) or ch emicals. Pigs that monitor the condition of the pipe are categorized as in-line inspection t ools. 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 in fluence throughput efficiencies, but can also be an early indicator of signifi cant 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 li quids 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 th at involved opening the pi peline, and dewatering the pipeline. Figure 2.1-2 provides examples of th e various types of pigs in use today, while Figure 2.1-3 depicts the typical configuration of a pig la unching/recovery facility.

2.1.14 Distribution Terminals

Marketing and distribution terminals tem porarily store products removed from the pipeline. There also may be loading racks and tr ansfer 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 adva nced real-time SCADA processors designed to support complex remote a pplications. The communications for the system35

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 li nes as the backbone, backed up by public switched telephone networks.

SCADA system designs vary widely, but ther e 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. Opera tions are monitored and contro lled using SCADA systems that provide thousands of data signals to pipeline controllers and opera tors. 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, id entify trends (both good a nd bad), and establish a historical operating record.

SCADA systems are configured with a variety of instrumentation. El ectrical 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 so ftware 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 fi eld 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 hi gh frequency, the effectiveness of the SCADA system hinges on appropriate data presentati on, analysis, and alarmi ng. A variety of data presentations are used to transf orm 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 supe rimposed on facility and pipeline schematics, permitting presentation of the data in an operationa l context. Alarms are used to indicate that operating conditions are approaching or have exceeded prescribed tolerances. Attention can then37

be focused on problem diagnosis and appropriate actions. In addition to data collection and display, SCADA systems also often include data va lidation programs that seek to validate each piece of data before using it to support a calcul ation or represent a condition. Frequent and, in some cases, continuous data validation has been s hown 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 f eedback 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 in dividual 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 re mind the controller about upcoming operating changes that need to be initia ted. Often, system configurations allow the operator to intervene to validate the alarm or to take the necessary corrective actions. When operator in tervention does not occur with a prescribed time frame, the system will au tomatically initiate actions that have been predetermined as being appr opriate, given the circumstances.

• Analytical tools . Trending history and other analyt ical 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 typi cally a 24-hour-a-day, 7-day-a-w eek operation, the remote control centers are staffed continuously in order to mon itor and maintain this round-the-clock operation. Due to the data being transmitted from potentia lly many miles away, the operator oftentimes must respond to the alarm and direct a corres ponding response from the remote control center based on the information depicted on the di splay 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 termin al unit (MTU) and RTUs communicate through a defined network of some type. The early syst ems utilized wired communications, either private hard-wired systems owned by the operator (usually practical onl y 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 re mote monitoring of the pipeline and communication with valves, compressors, and pers onnel during operation.

Most new systems, and many retrofits, are using some form of wireless communications. Many pipelines own their own mi crowave infrastructure, includi ng dedicated towers and radio frequencies licensed by the Fede ral Communications Commission. Th ere are also systems using frequencies in the very high frequency (VHF ) and ultrahigh frequency (UHF) ranges. These operators may own the communication towe rs or lease space on towers from other communication system operators. Many newer systems make use of low-power radio transmissions, such as spread-s pectrum technology, to avoid the licensing requirements. Satellite communications are also used for long-d istance and rugged-terrain communications.

SCADA systems can also operate on cell phon e 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 al so simultaneously introducing cyber security

concerns.

2.1.16 Risk of Natural Hazards and Human Threats

Natural and man-made hazards, such as sh aking from earthquakes, flooding, and even human chemical, biological, or nuc lear attacks can cause harm to pipeline components, such as pump stations, pipelines segments, and storag e tanks, etc. Information in the following paragraphs was adapted from guidance published by the American Lifeline s 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 w ithin designated energy ROWs may result in some interference between the systems or othe r hazards that would not exist except for the physical proximity of the two transmission system s. 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 carry ing volatile materials raises th e potential of a fire in one transmission system causing heati ng, stress, and/or rupture in a nother one. The normal distance between buried pipelines will probably preven t significant transfer of heat underground. However, care should be taken at locations wher e 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 insu lation and fire protection.

In the event of a fire in a petroleum pipeli ne, overhead electricity transmission lines could be damaged if adequate distance is not maintained.

2.2.2 Coincident Construction

Coincident construction of tw o separate energy transmission systems within a designated corridor raises some potential prob lems if the construction activiti es are not well coordinated and well scheduled. Because of the proximity of tw o 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 equi pment. On the other hand, with construction activities closely coordinated, impacts could be lessened, since opportuni ties 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 br oad concepts: (a) influe nce, (b) coupling, and (c) susceptibility. Other issues th at 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 object s being affected (pipelines). Susceptibility relates to the vulnerability of the induction elem ent (i.e., the metallic pipeline ) to induced and ground-return

currents.

Colocation may mean that the pipelines are lo cated on an electric utility ROW directly underneath the power lines, usually buried in eart h. This is the worse ca se for the coupling of magnetic induction currents, since the separation be tween the power line and the pipeline is very small. Thus, the full effect of the magnetic induc tion from the power line into the pipeline takes place.40TABLE 2.1-3 Degree of Component Vulnerability to Damageor Disruption from Natural Hazards and Human ThreatsDegree of VulnerabilityHazardsTransmissionPipelinesPumpStationsCompressorStationsProcessingFacilitiesStorageTanksControlSystemsMaintenanceandOperationsBuildingsandEquipmentPressureRegulating/MeteringStationsDistributionPipelinesServiceLines orConnectorsNatural HazardsEarthquake shakingL M M M H M HLLMEarthquake permanent grounddeformation (fault rupture,liquefaction, landslide andsettlement)H−−−L−−L H (Buried) MGround movements (landslide,frost heave, settlement)H−−−L−−L H (Buried) MFlooding (riverine, stormsurge, tsunami and seiche)L H H H M H H H L MWind (hurricane, tornado) L (Aerial)−−−−L L−−−IcingL−−−−−−−L−Collateral hazard: blast or fire M H H H H M LLLMCollateral hazard: daminundationL H H H M H H H L MCollateral hazard: nearbycollapse−L L L−L L L M LHuman ThreatsPhysical attack (biological,chemical, radiological andblast)M M M M−M M−M−Cyber attack−L L L−H L−L−Note: Degrees of Vulnerability: H-High, M-Moderate, L-Low, and – (dash) for not applicable. Comments such as (Buried) or (Aerial) apply to location of the component listedas the column heading.41

Alternating current (AC) inducti on will be reduced for power li nes 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 w ill be reduced by a factor that is inversely proportional to the distance from the centerline. As the separation betwee n 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 indu ced currents and voltages would be minimal beyond 300 to 500 feet.

Each of the three broad concepts of infl uence, 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 ma gnetic induction and damage due to electr olysis and lightning.

The pipeline industry has devoted considerab le attention to the potential problem of interferences presented by near by electricity transmission systems. The mechanisms of electromagnetic interferences between power systems and nearby buried pipelines have been generally placed in one of th ree categories: inductive coupl ing, conductive coupling, and capacitive coupling (Li and Dawa libi 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 voltage s are imparted to the pi peline as a result of the magnetic field around the elect ric current conductors . Interferences incr ease 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 incr eases with increasing soil resi stivity 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). Faul ted conditions can impart conductiv e interference to the pipeline. The magnitude of this conductive in terference is influenced by such factors as soil resistivity, the

electrical transmission line’s grounding system, and the separa tion distance between the ground fault and the pipeline. During fa ults, both inductive and conductiv e interferences are present, placing in jeopardy both the pipeline and th e pipeline workers in the vicinity.

Research sponsored by the Ductile Iron Pi peline Research Asso ciation has further

established the factors that can influence th e three coupling mechanisms of capacitance, conductance, and induction (Bonds 1999). The severity of the effect that overhead power lines can have on buried pipelines depe nds on a number of factors, incl uding 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 pi pe is otherwise (electrically) insulated from the ground. Bare pi pe that is in continuous contact with the ground is effectively at the same electrical potential as the neutral gr ound wires of the overhead lin es, so there is little if any potential for current to flow between the two system s. Ir onically, improvements in pipeline coatings applied for the purpose of corrosion control can be count erproductive with respect to42

interferences from electricity tr ansmission systems, effectively is olating 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 ex tent of interference between power lines and buried pipelines. Pipeline segments are typically 20 feet long and connected to adjacent segments by rubber gaskets, effectivel y isolating each pipe segment and making the entire pipeline electrically discontinuous. As noted above, instal lation mechanisms that involve tightly wrapping the pipe and/or applying a continuous corrosion control coating can make the pipe more susceptible to interf erences from induced currents of nearby power lines, since those techniques can prevent the pipeline from remain ing at the same electri cal potential as the ground (and as the neutral wire of the electricity tr ansmission system). To overcome this problem, ductile pipe manufacturers reco mmend a loose wrapping of polye thylene that still provides sufficient path to ground to keep the pipe and the neut ral ground wires of ad jacent power lines at the same potential. Some mitigat ive techniques have been shown to not only reduce induced AC voltages effectively and economically, but to si multaneously provide cath odic protection for the pipeline (Southey et al. 1994).

As noted earlier, the precise a lignment of the electric fiel d with respect to pipeline

orientation is critical to the se verity of the potential interference. PC-based software is available

that allows for calculation of bot h steady-state and fault-induced voltages on pipeli nes paralleling high-voltage overhead AC power lines. 33

Experience has shown that colocation of elect ricity transmission lines and buried metallic pipelines creates additional monitoring, test ing, 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 ampere s. As a result, these currents can stress the electrical system such th at breakdown and flashover occur at weak points, resulting in damage. If the damage is not repaired, there will be continued deterioration and ultimately sy stem failure. An explosive effect may be associated with a direct lightni ng 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 th e integrity of the pipeline.

• Impacts on pipeline cathodic protection systems. Some pipelines are protected by an impressed-current cathodic protect ion system (CPS). A CPS is intended to minimize the loss of metal in the pipe line 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 pi peline, 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 requir ed to monitor for such shorts.

• Polarized pipe . Metal pipelines in proximity to electricity transmission lines may become electrically pol arized, requiring sp ecial 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 elec trostatic or capac itive interference

. When electromagnetic interference is possi ble, studies are warranted to ensure the safety of personnel and other pipe line assets and that a CPS is not adversely affected.

• Review, testing, and documentation of resistive or ohmic interference. When lightning strikes a transmi ssion 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 ve rify 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 me tallic pipelines that are close to and44

parallel with the transmission lines. Speci al investigations of adverse impacts to pipelines are warranted in the afte rmath 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, meas urements 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 majo r undertaking, requiring a wide variety of engineering and construction skil ls. 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 th at 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 gu arantees the critical requirements of pipeline construction will be met, it also introduces the need to control logistics to ensure that all

contractor activities are coor dinated and not mutually ex clusive 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 constructi on 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 backf illing — are called spreads. A single pipeline may be built using several spre ads, reducing the overall construction period, but also increasing the amount of people and s econdary resources required to support them. A very large pipeline project may even be divide d into two or more segments, and different construction contractors may be us ed to install each segment. Va rious 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 exte rior 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 st eps 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 ava ilable than are provided below. The reader is invited to consult the following Internet websit es, 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 construc tion equipment with minimal damage. Likewise, pipelines crossing agricultural lands may need to be in stalled in the winter months to not disrupt agricultural activities. However, subfreezing conditions may preempt the application and proper curing of certain corrosion c ontrol coatings that, by necessi ty, 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 calculat ions 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 envi ronmental areas, archeological or cultural resources) and possible interfer ences to construction and/or op eration (e.g., nearby utilities, buried or otherwise). While many types of survey s 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 specifi c purpose or need. The types of surveys typically associated with long-distance, land-based pipeline in stallation 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. Ca dastral surveys are typically conducted only for public lands.

• Topographic surveys provide the location of natura l and artificial features and the elevations used in mapmaking. Information on elevation (more precisely, elevation changes) is critical to th e design and location of pump stations.

• Route surveys typically connect control or refe rence points by the most direct routes possible, given field conditio ns. 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 survey s 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 cons truction phase to ensure design specifications are met.

• As-built surveys are conducted after construction has been completed as a way to verify that design spec ifications were met or to capture the changes to original design specifications that were re quired 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 bodi es being crossed.

• Satellite surveying provides positioning data and imagery captured by satellites. Doppler and global positioning da ta are used as standard practice in remote regions and on subdivided land s 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 hi gh-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 contro l precision of geodetic and cadastral surveys.48

• Photogrammetric data acquisition derives from aerial photographs, unique terrestrial data, or other sensors that ca n 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, cen tralized pipeline staging areas may be located in nearby cities wi th 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 pr ior to proceeding onto the ROW and for offices, storage trailers, and fuel tanks. See the a dditional 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 proper ties 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 ot her 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 stresse s. Arctic conditions present a dditional, unique challenges. For example, the presence of permafrost (free wate r in the pore spa ces of uppermost layers of soil remaining frozen throughout the year) markedly ch anges the character and behavior of soils and must be accommodated by specialized construc tion and operation techni ques. Of particular concern is the potential for latent heat of the commodity being transported to be transmitted to the permafrost, thus destabiliz ing pipeline installation. In ar eas of variable permafrost (i.e., permafrost that may occasionally melt a nd refreeze), pipelines are often installed above ground, along with special construc tion of support members to preven t 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 indi ces include fracture frequency and rock-quality designation. Other considerations are floodplains, active earthqua ke areas, and hurricane and

tornado risks.

3.3 C ONSTRUCTION

Standard pipeline construction is composed of specific activities including survey and staking of the ROW; clearing and grading; trench ing; pipe stringing, bending, welding, and lowering-in; backfilling; hydrostatic testing; and cleanup. In addition to standard pipeline construction methods, the pipeli ne construction contractor wo uld use special construction49

techniques where warranted by site-specific co nditions. Rugged terrai n, waterbodies, wetlands, paved roads, highways, and railroads all dictate special constr uction techniques.

Pipeline ROWs can vary in their cross-se ctional details as they accommodate unique

circumstantial factors or featur es. A comprehensive treatment of the various design variations that are required to address every conceiva ble circumstance is beyond the scope of this document. However, interested readers can consult the following Fe deral Energy Regulatory Commission (FERC) website for a more exha ustive 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 re quires an area ranging from 15 to 35 feet aligned parallel to the pipeline. Additional areas may be required to segreg ate topsoils. The other side of the pipeline

FIGURE 3.3-1 Typical ROW with Topsoil Segregat ion (Source: Modified from FERC Golden Pass LNG Terminal and Pipeline Project image)

35 This website provides access to Append ix D of the Final Environmental Imp act 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 Janu ary 4, 2007.)

36 In virtually all instances, the natural native soil horizo n 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 adjace nt pipeline in place. In this example, the full 25-foot ROW boundary on each side of each pipeline is ma intained and should be sufficient for two pipelines, since construction can take place to either side. However, if multiple pipelines are running in parallel and tran smission systems of other types ar e present, such as power lines,

issues of construction and ma intenance repairs require furt her 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 w ith 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 identifica tion of leaks. Trees and other woody plants also need to be eliminated from the ROW to prevent their roots from challe nging 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 Co mponents 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 a nd taken to a material laydown yard that is temporarily maintained in an area close to th e construction site (see Figure 3.3-5). Numerous laydown yards may be constructed to support in dividual pipe construc tion 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 a nd material laydown areas until a ll of the materials assigned to the laydown areas have been delive red. In areas with less road in frastructure, 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 e quipment and workers could occupy several acres, but the amount of space would be highly depend ent on the size and terra in 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 clea red. The clearing and grading crew leads the construction spread. This crew is responsible fo r removing trees, boulders, and debris from the52

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 worki ng 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 te mporary work road adjacent to the pipeline.

The clearing and grading crew is also respons ible for installation of silt fences along the edges of streams and wetlands as necessary to pr event erosion of disturbed soil. Trees inside the ROW are cut down, roots are excav ated; and timber is stacked al ong 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 w ith a bulldozer is required. Where the route passes through rough or forested terrain, however, clearing oper ations 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 pub lic 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 recl aimed 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 su bsoils 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 vici nity 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 elsewher e, 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 ove r to the ditch when it is ready to be welded into the pipeline. Not only does this save cost an d 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 instal lation 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 circum stances where longer lengths of pipe can be easily moved into place, pipe is brought to the job site in sections consisting of two single jo ints of pipe (typically, having an overall length of up to 40 feet). Th is “double-jointing” saves welding time on the job site, which often must be done under less desirabl e 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 cente r, 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 cu tting 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 equipmen t 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 c over specifications or the distance from thetop of the buried pipe to the ground surface. For the same minimum cover requirements, a largerdiameter pipe requires a deeper ditch. The mini mum cover varies accordi ng to requirements of56

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 ri ver 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 wa ter 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 intermed iate 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 co ntain stones having a maximum dimension larger than 0.5 inch. Materi al must be placed to a minimum depth of 6 inches under the pipe and 6 inches over the t op of the pipe. The remaining backfill must not contain rock larger than 6 inches. Organic ma terial 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 pi pe 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 ditc h. 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 we lder make the initial passe s 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 de pends 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 pi pe. 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 eith er 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 pi peline welding employ a filler metal, do not involve the application of pressu re, 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 a llow the weld to penetrate deeper below the surface of the pipe wall than is po ssible 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, weld ers 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 inspec tion 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, wh ere the pipeline passes under railroads, highways, or rivers, all welds mu st be examined using radiography. In the X-ray inspection process, film wrapped around the circumference of the pi pe 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 pro cedures are qualified under the

ASME Boiler and Pressure Vessel Code and API standards. Certain stee ls require separate qualification of welding procedures . Each welding procedure must be recorded in detail during the qualifying tests and the record re tained 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 asse ssing plant life. The fl aws may be cracks or inclusions in welds and castings or variations in stru ctural properties that can lead to loss of strength or failure in

service.

Nondestructive testing is used for in-servi ce inspection and for condition monitoring of the operating plant. It is also used for meas urement 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 pr oduces no deleterious effects on the material or structure under test. The subjec t of NDT has no clearly defined boundaries; it60

ranges from simple techniques, such as vi sual examination of surfaces, through the wellestablished methods of radiogra phy, 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 sl ight 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 pi pe to the required curv ature (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. Ve ry small changes in direction may sometimes be made by letting the pipe lie to one side of the ditch. But ch anges 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 pipe line coating; others in clude 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 cap able 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 addi tional protection to the pipe and to protect the corrosi on 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 Figur e 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 a nd 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 ma intenance activity for existing pipelines, backfilling and bedding must be provided in a ma nner that will offer firm support for the pipeline and not damage either the pipe or the pipe co ating by the type of backfill material used or subsequent surface activities.

If the backfill material contai ns rocks or hard lumps that could damage the coating, care must be taken to protect the pi pe 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 operatio n of the piping and the passage of cleaning or internal inspection devices. Typical backf illing operations are shown in Figure 3.3-14.

FIGURE 3.3-12 Applying Coating to Pipeline62

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 se gments that have been replaced in existing pipelines, undergo hydrostatic test ing before being put into servi ce. Hydrostatic testing involves isolating that portion of the pipeline undergoing testing, fillin g it with water, and then pressurizing the line to a specified pressure to ch eck for leaks. U.S. federal safety regulations for pipelines require that pipelines used to transpor t hazardous or highly volatile liquids be tested at a pressure equal to 125% of the maximum allowa ble operating pressure (M AOP) for at least four

continuous hours and for an additional four con tinuous hours at a pressure equal to 110% or more of the MAOP, if the line cannot also be vi sually inspected for l eakage 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; sh ort pipelines may be te sted 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 pres sure is attained, the pump is shut off and the

“static” leak test commences. A leak is indicated if the pressure fa lls over the period of the test.

Once hydrostatic testing is completed, the wate r is removed and typically delivered to a wastewater treatment facility (e.g., a publicly owned sewage trea tment works) for treatment. While the majority of the water will be remove d 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 wher e it can be removed. This dewatering pig serves a dual purpose, removing water and also removing cons truction debris that may still remain in the pipeline and could be very damaging to downstr eam pumps, if not removed. Often, the pig is propelled along the pipeline by the products the pi peline was designed to carry, and once the pig64

and the water it has captured have been remove d, 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 petroche mical 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 compact ed, the original topsoil is returned to its original location and fi nal 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 constructio n road may remain in place until adjacent spreads are completed, if it provides the only ac cess 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 invol ve crossing roadways and streams; a long-distance pipeline may cross scores of each. A variety of t echniques are used for crossing these obstacles, depending on th e length of the crossing, the si ze 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 railroa ds can be done by either trenching or boring. When trenchi ng, 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, a nd instead a trenching technique that will allow the road to remain in service would be used. Similarly, an analogous approach to crossing a railroad w ould require that a section of th e 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 ar e made for road and railroad crossings. Of primary importance is a calculation of the maxi mum dynamic loading on th e pipe from traffic or trains. This dictates the depth of cover between the road or ra ilroad and the pipe and whether additional design features ar e added to disperse the load to a su fficient 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 dril ls 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 insi de the conductor. Spacers are used to center the pipeline within the conductor. This sleeve arrang ement is effective not only in reducing the load on the pipe but also in reduci ng 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 ad ditional protection by way of more cover, pipe sleeves, or concrete slabs positioned above the pipe to disper se 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 waterbod ies depend on a number of sitespecific factors, most importan tly, 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 fi rst is the open-cut wet (in-stream) method. A backhoe or dr agline can be used in minor str eam 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 sediment s. The benefits are low cost and a quick completion time, making this the method of choi ce when existing regulations or policies do not require other techniques. Disadva ntages include potentially signi ficant pollutant and sediment runoff, greatly increased total suspended sedi ment concentrations downstream, changes in68

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 ecosy stems. These problems can be mitigated only by a quick completion time.

An alternative method of waterbody crossing s 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, an d 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 a nd a culvert is instal led. Isolated crossing methods usually have less sediment yield than a wet crossing, but are of ten more expensive and more time consuming.

Additionally, the installation a nd removal of the dam can cause high releases of sediment. Other problems may arise from leakage around/undern eath the dam, dam failures, flume failures, insufficient sump storage, insufficient pum p capacity, and inadequate maintenance.

For larger bodies of water, horizontal direct ional 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 thr ee basic steps. First, a pilot hole is drilled. Secondly, the pilot hole is en larged to a diameter larger than th e 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 enla rged hole to prevent it from69

FIGURE 3.3-20 Dam-and-Pump River Crossing wi th Two Pipelines (Source: Modified from FERC Golden Pass LNG Terminal and Pipeline Project image)

collapsing before the pipe can be installed. Finall y, 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 side s of the waterbody crossing for HDD. The drilling rig spread requires a minimum 100-f oot wide by 150-foot long area on each bank. The drilling operation requires large vo lumes of water for mixing the drilling slurry, often but not necessarily withdrawn from the waterbody bein g crossed. The length of workspace should be sufficient to permit fabricating the product pipeli ne into one string. The width should be what70

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 construc tion, 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 th e pullback. The recommended minimum cover depth is 20 feet

for the lowest secti on of the crossing.

Slurry pits are constructed in the construction zone to suppo rt 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 rem oved for use at another drilling ope ration or used elsewhere in the pipeline construction project to be mixed with native soils to enhance slope stabili ty or increase71

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 structur es 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 ma y cross existing pipelines in service (see Figure 3.3-23).

Instances in which anchoring is required incl ude river crossings where currents can cause pipe movement or scour beneath th e pipe installed on top of the rive r bed, a dry wash subject to72

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 allo wed by law, creates unique construction challenges. Figure 3.3-24 depicts a typical saturated we tland 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 th rough wetlands only if the ground was firm enough or had been stabiliz ed to avoid rutting. Otherwise, nonessential equipment would be allowed to travel through we tlands 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 rem oved from the wetland. To avoid excessive disruption of wetland soils and the native seeds a nd rootstocks within the wetland soils, stump removal, grading, topsoil segregation, and excav ation 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 (S ource: Modified from FERC Golden Pass LNG Terminal and Pipeline Project image)74

During clearing, sediment barriers such as si lt fences and staked cer tified weed-free straw bales would be installed and maintained adjace nt 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. Alternativ ely, 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 in stalled within wetlands along the edge of the ROW, where necessary, to minimize the potential for sediment to run o ff 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 tim e of construction. If wetland soils ar e not excessively saturated at the time of construction and can support c onstruction 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 unsat urated wetlands, topsoil from the trench line would be stripped and stored separately from subsoil. Topsoil segregation generally would not be possi ble 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 involv es stringing and welding the pipeline outside of the wetland and excavating and backfilling the tr ench using a backhoe supported by equipment mats or timber riprap. Th e prefabricated pipeline would be installed in the wetland by equipping it with buoys and pushi ng or pulling it across the water-filled trench. After the pipeline was floated into place, the fl oats would be removed and the pipeline would sink into place. Most pipe installed in satura ted wetlands would be encased in concrete or equipped with set-on weights to prov ide 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 backfilli ng, 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 certi fied 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 inst alled where necessary until revege tation of adjacent upland areas was successful. Once revegetation was successful, se diment 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 accordan ce with the recommendations of local soil conservation authorities. Lime, mulch, and fe rtilizer 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 terr ain. 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 lim itations 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, reconstruc ted to their original contours during final contouring and before restoration of surface vegetation.

In areas where the proposed pipeline route cr osses 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 terr ace. Under these circumstances, the topsoil would be stripped from the entire width of the ROW. Af ter the pipeline is installed, the soil from the

low side of the ROW would be returned to th e high side, topsoil re placed, and the slope’s original contours would be restored.

In steep terrain, temporary sediment barriers su ch as silt fences and certified weed-free

straw bales would be installed dur ing clearing to prevent the move ment 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 during76

cleanup. Following construction, seed would be applied to steep slopes and the ROW mulched

with certified weed-free hay or nonbrittle straw or covered w ith 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 pl anted for long-term erosion control. Sediment

barriers would be maintained across the ROW until permanent vegetation is established.

When rock or rocky formations are encounter ed, tractor-mounted m echanical rippers or rock trenchers would be used for fracturing the rock prior to excavation. In areas where mechanical equipment could not break up or lo osen the bedrock, blasting would be required. Whenever possible, excavated rock would be used to backfill the tr ench 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 se nsitive 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 th e 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 chan ge 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 mainte nance, 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 attach ed 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 ar e 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 opera ting capability of a pipeli ne are located within pump stations.. The location and number of pump statio ns, as well as the size and power of the pumps, are dictated by a number of factors, including topography along the RO W (elevation changes), the specific gravity and viscosity of the comm odity, and the desired th roughput. 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 fric tional losses. To be e ffective, the pipeline’s operating pressure must be maintained at or above the design discharge pre ssure at the pipeline’s final destination. With the discharge pressure setting the lower pressure limit and the burst77

pressure of the pipe and other components se tting the maximum pressure, calculations can determine the number and location of pump statio ns 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 thir d remains available, if needed, or in the event of a failure of one of the ope rating 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 introdu ce 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 cu stody or ownership of the commodity. Storage or “breakout” tanks are used to support mainte nance 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 je opardy 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, pu mp station footprints can vary in size from a few acres to as many as 50 acres or mo re. 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 th at affect operational cond itions 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 Nort h Slope deliver a mixture of ga s, 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 Sou nd. The TAPS terminus is the breakout station

at the Valdez Marine Terminal where crude oil is recovered from the pipe line and sent to various storage tanks to await lo ad-out to oceangoing tankers for delive ry to refineries in the contiguous

United States and elsewhere.

The terminus of a pipeline is typically locat ed within or adjacent to a petroleum bulk terminal. The pipeline ends at a breakout sta tion where terminal pers onnel can perform final metering and distribute products to various storage tanks, redirect th em 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 operate d 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 st andard industry practices. Depending on the individual pipeline operator, company polices ma y result in more restrictive requirements for each of the actions. In some instances, regulation or lease stipulation spec ify how such activities

will be conducted.

4.1.1 Inspections during Excavation

Whenever a pipe is exposed for any reason, th e operator typically examines the pipe for evidence of mechanical damage or external co rrosion, including the coating. Mechanical damage must be evaluated and repaired as necessary, in accordance w ith company repair procedures. Coating damage should be repaired prior to rebu rying the pipeline. If the operator finds active corrosion, general corrosion, or corrosion that ha s caused a leak, the opera tor 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 individua ls walking the ROW and also aerial surveillance. Flyover inspec tions are the most common and most efficient method for routine surveillance, but are not appropriate for ma ny required inspection tasks.

Unique opportunities exist for surveillance and inspection activities for multiple pipelines or other energy transmission systems on adjacen t ROWs. Although no system operator would be willing to entirely relinquish inspection activitie s to another system operator, there are many

surveillance activities that are co mmon to all types of energy system s that might be adjacent to one another, creating the possibi lity for a more integrated ap proach to routine inspections. Agreements between system operators and th e federal land manager to combine routine

surveillance activities can reduce environmental impacts that would result from independently conducted inspections and could pot entially increase operating efficien cies 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 fo r combining efforts and he res ources of system operators for common tasks, system operators remain individu ally 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 expose d. All hazardous liquid pipelines att ached to bridges or otherwise spanning an area should have pipe line 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 ma ximum 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 tu rn, 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 abov e 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, especia lly 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 OP S in 49 CFR Part 195 require pipelines to calculate yield strengths and ope rate 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, incl uding their review of monitoring and inspection data or in response to a system failure that is rela ted to pressure, can result in an order for the pipeline to be ope rated at a reduced operating pre ssure (expressed typically as a new lower maximum operating rate) until obser ved or indicated defi ciencies are further investigated and resolved.

4.2 PIPELINE REPAIRS

In most instances, pipeline repairs are acco mplished expeditiously to ensure minimal disruption to pipeline operati ons. Unless otherwise specified by applicable regulation or lease stipulation, pipeline repairs ar e 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, c ondensate, natural gasolin e, natural gas liquids, liquefied petroleum gas (LPG), carbon dioxide, li quid alcohol, liquid anhydrous ammonia, and liquid petroleum products includi ng petrochemical feedstocks and secondary refinery feedstocks. Pipeline components addre ssed in this standard include pipe , flanges, bolts, gaskets, valves, relief devices, fittings, and the pressure-con taining 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 sta tions, 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, hazar dous liquid pipeline companies typically prepare a study to determin e 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. Indus try standards for allowable a dvancements of internal and

external corrosion establish the action levels fo r such remedial activities. Remedial action may involve replacing the sacr ificial anodes of a corrosion c ontrol system, a relatively minor construction activity compared to wholesale replacement of compromised pipe involving long-term shutdown of operations and major constr uction efforts equivalent to initial installation. To limit operational downtime, temporary bypass segments isolating the damaged segments may

also be installed. See ad ditional discussions on corro sion control in Section 4.7.

4.3 PIGGING ACTIVITIES

A variety of inspection techniques and t echnologies 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 introdu ce the pig into the pipeline an d to retrieve the pig at the end of the segment being pigged. A launcher is re quired at the upstream end of the section, and a receiver is required at the dow nstream end. The distance betwee n these pig “traps” depends on the service, location of pump or compressor stations, operating pro cedures, 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 fl ow characteristics of the pipeline are always present and something to co nsider 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 st atic reducer added to dies els. 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 frictiona l drag on the inside pipeline wa lls, thereby reducing the amount of energy needed to pump the crud e. Such diluents are typically low-viscosity petroleum refining fractions such as raw naphtha.

4.5 PIPELINE SECURITY

Third-party damage and ROW encroachments ar e the biggest threats to pipeline safety. Pipeline operators use a combination of tec hniques to monitor pipeline ROWs. Aerial surveillance and satellite imaging combined with interpretive softwa re that can survey and detect things such as heat, color, size, and shape, wh ich can alert operators to potential encroachment concerns. Fiber optic broadband capabilities along RO Ws typically are used to assist in this effort. Many pipeline operators are also en listing 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 intende d to be discarded; it may be solid, semisolid, liquid, or contain gases. A solid wa ste 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 ig nitability, corrosivity, reactivity, or toxicity. For pipelines, benzene is an important hazardous mate rial, as it is a component in crude oil and in many petroleum distillate fuels and secondary feedst ocks that are routinel y 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 th e mixture rule, 40 CFR 261.3(a)(2)(iii and iv). Mixing any listed hazardous waste with a nonh azardous waste renders the entire mixture

hazardous. 41 Water can pose disposal pr oblems for pipeline operators. Water used in hydrostatic testing of repaired pipelines that carried crude oil or petroleum products can become contaminated with hydrocarbons th at require it to be managed as hazardous waste. Certain

41 The mixture rule will always be in effect when “liste d” hazardous wastes are involved. However, if mixing a

“characteristic” hazardou s waste with a nonhazardous wast e 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 al so 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 ma y also qualify as hazardous waste and must routinely undergo hazardous wast e determinations ag ainst the standards and specifications

contained in federal or state re gulations before management and disposal options are selected.

The Clean Water Act influences pipelin e construction, especi ally through its requirements for permits for activities in wetlan ds and stormwater management (particularly during the construction and decomm issioning phases). Stormwater co ntrols must be established before construction begins and must be maintain ed until reclamation has progressed sufficiently

to stabilize disturbed areas. Similar controls ma y need to be reinstated before major repair, replacement, or upgrading activities are conducted.

Another important environmental considerati on in pipeline constr uction and operation is impact to air quality. Substances of concer n to pipeline operators include carbon dioxide, hydrogen sulfide, and mercapta n, a sulfur-containing hydrocarbon 42 that is introduced into natural gas systems as an odorant. Pipeline operat ors must also be concerned about sources of nitrous oxide, carbon monoxide, and emissions fr om 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 pot ential (the cathode) will not be subject to corrosion. In the case of a buried pipeline, the soil can act as an electrolyte, facilit ating the transfer of electrons from a metallic object such as a buried pipe (the anode in this electroc hemical engine) and the ground. Areas of different electric al 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 el ectrically bonded to the pipe and installed along the pipeli ne route, resulting in the subsequent flow of electrical current from the anodes to the ground. As electrons flow from thes e anodes, the anodes deteriorate, earning them

the common name of “sacrificial anodes” since th ey are being sacrificed and allowed to corrode instead of the pipe. The pipeline becomes th e 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.praxa ir.com/praxair.nsf/d63afe71c771b0d785256519006c5ea1/ bd40c55346b4930f85256e5f007e8c2a/$FILE/MethylMercaptan-Canada.pdf.84

magnitude of the corrosion currents for a give n potential difference between two electrodes (cathode and anode) depends on several factors:

• Soil resistivity . This is determined by temperat ure, moisture co ntent, and the concentration of ionized salts presen t. 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 corro sion on the anode will be inversely proportional to anode area.

Since power requirements for cathodic prot ection 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 dete cted 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 de tection because one important way to detect leaks is by direct observation of the pressure drop and volume lo ss, based on comparing the flow into a segment of pipeline and the flow out of th e 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 us ed to monitor a pi peline 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 join tly published an overview of pipeline integrity programs in effect for liquid pi peline systems (AOPL/API 2006). Th eir overview is summarized below. Pipeline integrity can be determined through direct assessment methods, hydrostatic testing, and by the use of internal inspection tool s. Using direct assessment methods, oil pipeline operators can determine the integr ity of an oil pipeline through vi sual and physical (internal and external) observations. Internal inspections of oil pipelines involve the use of smart pigs. Hydrostatic testing involves pre ssuring the pipe to a level equal to or above its normal operating pressure. Oil pipeline operator s generally use a combination of direct assessments, internal inspection tools, and/or hydros tatic tests for ensuring the sa fe and reliable operation.

Direct assessment methods include various t ypes of cathodic protection surveys, such as close interval surveys (to ensu re that the pipe is not corro ding) 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 in spected or removed for any reas on, such as pipeline relocation, installation of taps, inst allation of test leads, etc. The pi peline ROW may be assessed by ground

and aerial surveillanc e to look for any discoloration of plan ts and grasses as well as to observe unusual activity in the area of the pipeline (for potential outsid e force damage).

Smart pigs are routinely used by the oil pipe line industry to detect loss of metal and in some cases deformations in the pipeline. Insert ed into the pipeline and propelled by the flowing liquid, smart pigs record physical data about the pipeline’s inte grity (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 pi peline and to find and mitigate potential problem areas before they become a problem.

Since their development in the 1960s, smart pi gs have undergone several generations of technological advancements. As smart pig tec hnology has evolved, oil pipeline operators have required the use of specialized sm art 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 (C orrosion Tools)

A number of smart pigs have been develope d 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 in terpreted as potential metal lo sses 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 in side or outside of the pipe. Industry standards have been developed for use of the collected data to perform

calculations of such characteris tics as the depth of corrosion pi tting, but typically, corrosion must have advanced to a depth of at least 20% of the pipe wall thickne ss before smart pigs can detect it. However, smart pigs are not reliable for iden tifying flaws in the pipe that are oriented along the pipe’s long axis, such as stress corrosi on cracking, selective seam corrosion, and axial

gouges.

The ultrasonic smart pig, al so called the UT tool, measur es pipe wall thickness by using ultrasonic technology. The UT tool transmits an u ltrasonic 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; consequen tly 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 re flection 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 eff ective 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 discusse d above; however, the magnetic field it creates is oriented along the long axis of the pipe, maki ng this tool especially sensitive to longitudinal seams cracks and longitudinal seam corrosion. Neve rtheless, small cracks may not be detected,

and while the tool can detect th e 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 lo cate and size longitudinally or iented 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 develo ped for that purpose. They are designed to87

identify external dents or damage to the pipe fr om 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 sa me principles. Caliper pigs can use either mechanical arms or electromagnetic signals to id entify the exact locations of the interior pipe wall. Data collected as the pig moves along the pipe can then be inte rpreted 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 anomalie s or suspect areas can be precisely located for directed repair and maintenance.

4.10 PIPELINE REPAIR TECHNIQUES

Leaks in the pipeline demand immediate at tention. Repairs to mainline pipe can be accomplished in a variety of ways, from replaceme nt of an entire segment to replacement of a small section within which the leak has occurred, to application of a patc h to the existing pipe. None of these repair strategies can be select ed until a thorough investig ation is completed to fully understand the nature and causal factors of th e leak. In addition to replacement of damaged pipe, repairs could also involve re burial or rerouting of the pipe to prevent reoc currence 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 pi gs are available expressly fo r this purpose. Once the bypass components are in place, “hot tap” machines al ready 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. Equi pment is available to perform this type of operation on pipe sizes up to 48 in. in diameter. Ho t 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, a lternatively, the bypass valves can be left in place as a means of sealing the hot taps.8889

5 DECOMMISSION AND DEMOLITION

Decommissioning is the process of taking equi pment out of service when it has reached

the end of its useful life. Fr om an operational perspective, that point is reached when maintenance and replacement costs for older e quipment begin to outweigh the value obtained from continued operation. Advancements in technol ogy can also signify the point in a system’s lifetime when decommissioning is warrante d. Alternatively, decommissioning may be appropriate due to a change in demand for th e 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 alternativ e 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 functi onal for much longer periods of time. Unless it is incompatible with future land uses planne d 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 dur ing removal of the pipe and other buried components. Removal costs also encourage abandonment in place.

Typical abandonment-in-pl ace processes include:

• Removing any cathodic protec tion from the pipeline.

• Physically disconnecting the pipeline from any operating facilities.

• Removing the product from the line.

• Cleaning the line by flushing it with fr esh 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 wi th 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 in stallation costs and the valu e recovered from recycling mainline pipe is not likely to cover re moval costs, most mainline pipe is abandoned in place; however, valves, special fittings, and all aboveground feat ures (e.g., pump stations and all of the equipment therein) are removed and recycled. DOT’s OPS maintains statistics regarding th e lengths of interstate pipelines abandoned in place. See: http://ops.dot.gov/library/abandoned/abandon_pipelines_orig.htm.90

Decommissioning plans are very site-specifi c 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 fr om 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, reme diate any accidentally released products, and abandon the pipe and associ ated infrastructure in place. Typically, pipe corrosion control systems are also abandoned, allo wing 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 fillin g the pipe segment to the great est extent possible with inert

material such as sand.91

6 EMERGENCIES AND OFF-NORMAL EVENTS

Once pipelines are operational, monitoring th e pipeline’s flow parameters, instituting operational procedures and controls, and perf orming periodic maintenance (especially, for example, in conformance with the principles of Reliability-Centered Maintenance) 44 are all typically used to reduce the potential for accide ntal releases of commodities. Notwithstanding such efforts, mechanical system failures and hum an error can still occu r, some of which may

result in accidental releases of pipeline commodities. Conseque ntly, all pipeline operators are required to develop written proced ures 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 respons e actions developed accordingly.

Evaluations of off-normal even ts, including credible spill scenarios, consider relevant circumstantial factors (e.g., ecosystems potentially impacted); potential natural, mechanical, or human causal factors (e.g. ear thquakes, equipment failure, human error); the expected frequencies of such events; and the potential magnit ude 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 re sponse actions to mitigate those impacts without increasing the risk to facility response pers onnel or the public from inappropriate response actions. For example, releases of flammable liqui ds 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 desi gn 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 estimat es, 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 n ecessary scale of the response action.

For the purposes of impact analysis, there is no difference whethe r a leak or rupture occurs along the pipeline or at a pump station. Th e 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, th e impacts depend on the e nvironmental 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 th eir primary leak detect ion capability. Pipeline ruptures will result in signifi cant 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 mechani cal 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, sm all-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 disc over the leak by visual observation.

Accidental releases of various commodities routinely conveyed by pipeline result in substantially different impacts a nd 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 gasoline 45 are composed of polar organic molecules with relatively high solubility in wate r, thus increasing their potential environmental mobility from the spill site. Each of these hi ghly flammable component s also has a relatively high vapor pressure under standard conditions and br oad explosive ranges of their vapors in air, increasing the potential for their volatilizati on 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 developmen t of appropriate spill response actions to prevent the response itself from exacerbating the impact of the initial spill. In add ition to contributing to gasoline’s viscosity, specific gravity, and solubility, benzen e and xylene can increase the permeability of clay over time. These chemicals can cause clay shrinkage and cracking, thereby increasing the chances of fractur ing clay soils in the upper hori zons and providing pathways for gasoline to move more rapidly to subsurface aq uifers than might otherwise occur (EPA 2000).

45 The BTEX fraction is composed of benzene, toluene, ethylbenzene, and the three isomers of xylene.93

7 REFERENCES

ALA (American Lifelines Alliance) and FEMA (F ederal Emergency Management Association), 2005, Guideline for Assessing the Performance of Oil and Natural Gas Pipeline Systems in
Natural Hazard and Human Threat Events

, April. Available at http://www.americanlifelinesalliance.org/ pdf/PipeguideFinalP osted061705.pdf. Accessed July 15, 2006.

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