corrosion control in the oil and gas industry || the oil and gas industry

The Oil and Gas Industry

CHAPTER

1
1.1 IntroductionThis chapter provides a birds-eye view of the oil and gas industry. It discusses the importance ofenergy from hydrocarbons, describes different types of hydrocarbons, indicates their sources, andprovides a brief history of the industry. The chapter then explains how the industry is regulated byvarious government agencies in North America, and finally presents the impact of corrosion on theindustry.
1.2 Energy from hydrocarbonsThe progress of civilization over the past two centuries has depended on the energy derived fromcrude oil, natural gas, coal, and nuclear reaction, as well as from renewable (wind, sun, biofuels, andhydroelectric) sources. Table 1.1 lists sources of energy in 2005; of these hydrocarbons (crude oiland natural gas) and coal comprised 84%.1 Total global energy demand in 2030 is projected to be50–60%more than current levels. Figure 1.1 presents the anticipated sources of energy in 2030; energyfrom nuclear and renewable sources could increase substantially, but energy from hydrocarbons andcoal would nevertheless be up to 80% of the total.2

The industry has produced 1.063 trillion barrels (bbl) of oil since its inception in the late 1800s. Theglobal demand for oil in 2000 was 76 million bbl/day (27.74 billion bbl/year). Table 1.2 presents

Table 1.1 Current Sources of World Energy1

Energy Source Supply Percentage)

Crude oil 38

Natural gas 23

Coal 23

Nuclear 7

Renewable 9

)Based on 2005 estimates

Corrosion Control in the Oil and Gas Industry. http://dx.doi.org/10.1016/B978-0-12-397022-0.00001-7

Copyright � 2014 Elsevier Inc. All rights reserved.1

http://dx.doi.org/10.1016/B978-0-12-397022-0.00001-7

FIGURE 1.1 Anticipated Sources of Energy in 2030.2

Reproduced with permission from Cambridge University Press.

Table 1.2 ) Worldwide Oil Production3

Crude Oil Production (Thousand Barrels Per Day)

Country 1970 1980 1990 1991 1992 1993 1994 1995 1996

Saudi Arabia 3,789 9,903 6,414 8,223 8,308 8,087 8,000 8,074 8,083

United States 9,648 8,597 7,355 7,417 7,171 6,847 6,662 6,560 6,471

Russia NA)) NA 10,325 9,220 7,915 6,875 6,315 6,135 6,010

Iran 3,831 1,662 3,252 3,358 3,455 3,671 3,585 3,612 3,675

China 602 2,113 2,769 2,785 2,835 2,908 2,961 3,007 3,127

Norway 0 528 1,620 1,876 2,144 2,264 2,580 2,782 3,086

Venezuela 3,708 2,165 2,085 2,350 2,314 2,335 2,463 2,609 2,955

Mexico 420 1,936 2,648 2,774 2,668 2,673 2,685 2,722 2,854

United Kingdom 2 1,619 1,850 1,823 1,864 1,922 2,469 2,565 2,633

United ArabEmirates

691 1,702 2,117 2,416 2,322 2,195 2,223 2,205 2,217

Nigeria 1,090 2,058 1,811 1,867 1,902 1,905 1,883 1,890 2,014

Kuwait 2,983 1,661 1,235 200 1,050 1,870 2,000 2,007 2,060

Canada 1,305 1,424 1,518 1,548 1,604 1,677 1,742 1,806 1,820

Indonesia 855 1,576 1,289 1,411 1,346 1,327 1,319 1,498 1,516

Libya 3,321 1,830 1,374 1,509 1,493 1,361 1,380 1,390 1,403

Algeria 976 1,020 794 803 772 747 750 764 816

Iraq 1,563 2,514 2,080 283 425 448 550 600 600

Kazakhstan NA NA 515 530 515 460 405 415 460

)Based on Table 1, page S2 of reference 1.3))Not available

2 CHAPTER 1 The Oil and Gas Industry

1.2 Energy from hydrocarbons 3

annual production of the major oil-producing countries.3 In 2030, global oil demand is estimated to beabout 37.6 to 50.4 billion bbl/year.

The industry has also produced 3,000 trillion cubic feet (TCF) [85 trillion cubic meters (TCM)] ofgas. The remaining gas reserve is estimated to be 7,000 TCF (200 TCM). The global demand fornatural gas in 2000 was 88.7 TCF (2.51 TCM) per year. In 2030, gas demand is estimated to be about130–212 TCF per year (3.7–6.0 TCM per year).

The energy (heat) content is a unique property of each type of hydrocarbon. The normal unit used forheat is the British Thermal Unit (BTU). The amount of heat required to raise the temperature of onepound (lb) of water by 1�F is one BTU. The heating value may be reported as higher heating value(HHV) and lower heating value (LHV). HHV is a measure of the gross amount of heat produced whenthe hydrocarbon burns. LHV considers the loss of heat due to vaporization ofwater during the burning ofhydrocarbon. The thermal efficiency (TE) can be calculated from the HHVand LHVusing (Eqn. 1.1):

TE ¼ LHV

HHV(Eqn. 1.1)

Table 1.3 presents the HHVand LHV values of some hydrocarbons.4 The oil and gas industry strives toproduce and supply hydrocarbons with higher thermal efficiencies as economically as possible.

Table 1.3 Heating (Energy) Values of Hydrocarbons and Other Substances4

EnergySubstances

ChemicalFormula

HHV LHV ThermalEfficiency(LHV/HHV)KJ/m3 BTU/ft3 KJ/m3 BTU/ft3

Methane CH4 37,694 1,010 33,936 909 0.90

Ethane C2H6 66,032 1,770 60,395 1,618 0.91

Propane C3H8 93,972 2,516 86,456 2,315 0.92

Normal butane C4H10 121,779 3,262 112,384 3,011 0.92

Iso butane C4H10 121,426 3,252 112,031 3,000 0.92

Normal pentane C5H12 149,654 4,009 138,380 3,707 0.92

Iso pentane C5H12 149,319 4,001 138,044 3,699 0.92

Normal hexane C6H14 177,556 4,756 164,402 4,404 0.93

Normal heptane C7H16 205,431 5,502 190,398 5,100 0.93

Normal octane C8H18 233,286 6,249 216,374 5,796 0.93

Normal nonane C9H20 261,189 6,700 242,398 6,493 0.93

Normal decane C10H22 289,066 7,743 268,396 7,189 0.93

Hydrogen sulfide H2S 23,791 637 21,912 589 0.92

Carbon monoxide CO 11,959 321 11,959 321 1.00

Hydrogen H2 12,091 324 10,230 274 0.85

Helium He 0 0 0 0 0

Water H2O 0 0 0 0 0

Oxygen O2 0 0 0 0 0

Nitrogen N2 0 0 0 0 0

Carbon dioxide CO2 0 0 0 0 0


1.3 What are hydrocarbons?Hydrocarbons are chemical species containing only carbon and hydrogen atoms. Hydrocarbons can bechemically classified into several categories, but with respect to the oil and gas industry three types areimportant: alkanes, cycloalkanes, and aromatic compounds.

1.3.1 Alkanes (Paraffins)In the oil and gas industry alkanes are known as paraffins. Alkanes are saturated (all bonds betweencarbon and hydrogen atoms are single bonds) hydrocarbons. Alkanes have a general formula CnH2nþ2;where ‘n’ is the number of carbon atoms. Table 1.4 presents the chemical and physical properties ofsome alkanes.

The simplest hydrocarbon, having just one carbon atom (n ¼ 1), is methane. Methane is the pri-mary component of natural gas. Natural gas containing only methane is called ‘dry gas’. In the past,natural gas was simply burned (known as flaring), but now it is used as a major fuel source. Theadvantage of natural gas is that it produces less CO2 when combusted compared with other hydro-carbons. Hence it is considered a clean fuel.

Hydrocarbons with values of ‘n’ between 2 and 5 [(ethane (C2), propane (C3), butane (C4), andpentane (C5)] are collectively known as natural gas liquids (NGLs), liquid petroleum gases (LPGs), orcondensates. At atmospheric pressure they exist in the gaseous state, but the application of pressureturns them into liquids. Natural gas containing NGLs is known as wet natural gas.

The alkanes with ‘n’ values between 5 and 8 [pentane (C5), hexane (C6), heptane (C7), and octane(C8)] are refined into gasoline (petrol). Due to its high energy density, easy transportability and relativeabundance, gasoline has become the most commonly used fuel in automobiles. Table 1.5 presents thecommon names and uses of different alkanes.

Table 1.4 Properties of Alkanes (Saturated Hydrocarbons or Paraffins)

Name Chemical Formula Melting Point (�C) Boiling Point (�C) State at 25�C

Methane CH4 �183 �164 Gas

Ethane C2H6 �183 �89 Gas

Propane C3H8 �190 �42 Gas

Butane C4H10 �138 �0.5 Gas

Pentane C5H12 �130 36 Liquid

Hexane C6H14 �95 69 Liquid

Heptane C7H16 �91 98 Liquid

Octane C8H18 �57 125 Liquid

Nonane C9H20 �51 151 Liquid

Decane C10H22 �30 174 Liquid

Undecane C11H24 �25 196 Liquid

Dodecane C12H26 �10 216 Liquid

Eicosane C20H42 37 343 Solid

Triacontane C30H62 66 450 Solid

Table 1.5 Use of Various Hydrocarbons

Number of Carbonsin the Paraffin Chain Commonly Known as Used as

1 Natural gas Domestic fuel

2 to 4) Natural gas liquids (NGL)Liquid petroleum gases (LPG)Condensates

Fuel, blended with gasoline, rawmaterial for producing ethylene,propylene, and butylene

5 to 8 Gasoline (petrol) Automobile fuel

9 to 10 Naphtha Raw material for chemical and plastics

11 to 15 Kerosene Heating oil and fuels for jet

16 to 20 Diesel Fuel in automobile and trucks andheating oil

21 to 25 Greasy material Grease and lubricants

26 to 35 Asphalt Construction materials to pave roadsand protective coatings

Above 35 BitumenCoke

Refined into hydrocarbons with lowernumber of carbons in the chain

)Pentane (number of carbon 5) is also included

1.3 What are hydrocarbons? 5

1.3.2 Cycloalkanes (Naphthenes)Cycloalkanes are known as naphthenes. Cycloalkanes are saturated hydrocarbons having one or morecarbon rings with a general formula CnH2n. Figure 1.2 compares the structures of hexane (paraffin) andcyclohexane (naphthane); both have six carbon atoms. Cycloalkanes have similar properties to alkanesbut higher boiling points. Cyclohexane is commonly used as a solvent in the chemical industry andlaboratories. It is also the raw material used to produce nylon.

CH3–CH2–CH2–CH2–CH2–CH3

(A) Hexane

(B) Cyclohexane

(Each corner of the hexagon representing a –CH2 group)

FIGURE 1.2 Comparison of the Structures of Hexane and Cyclohexane.

(A) Hexane. (B) Cyclohexane. (Each apex of the hexagon represents a –CH2 group).

(A) Cyclohexane(Each corner of the hexagon representing a –CH2 group)

(B) Benzene (Each corner of the hexagon representing a –CH group)

FIGURE 1.3 Comparison of the Structures of Cyclohexane and Benzene.

(A) Cyclohexane. (Each apex of the hexagon represents a –CH2 group). (B) Benzene. (Each apex of the hexagon

represents a –CH group; ring represents double-bond structure).


1.3.3 Aromatic hydrocarbonsAromatic hydrocarbons are unsaturated hydrocarbons with the formula CnHn. They have at least onecharacteristic ‘six carbon ring’ called a benzene ring. Figure 1.3 compares cyclohexane and benzene,which both have an ‘n’ value of six. Aromatic hydrocarbons tend to burn with a sooty flame. Many ofthem have aroma (smell) and are carcinogenic (cancer causing).

1.4 Hydrocarbon sourcesHydrocarbons occur naturally in the earth. According to the most widely accepted theory, hydrocar-bons were formed when organic matter (such as the remains of plants or animals) was compressedunder the earth, at very high pressure and high temperature for a very long time.

Hydrocarbons may occur in the earth either as liquid or as gas. Liquid hydrocarbon is commonlyknown as crude oil and gaseous hydrocarbon is commonly known as natural gas. Crude oil is alsoknown as ‘petroleum’ – derived from ‘petros’ (a Greek term for stone or rock) and ‘oleum’ (a Latinterm for oil). An ancient term for petroleum is ‘rock oil’. An oil-producing well may also producegas. The gas produced from an oil well is commonly known as ‘associated gas’. The relative pro-portion of gas and oil in the well is expressed as the gas to oil ratio (GOR). At relatively lowertemperatures, more crude oil is formed and at higher temperatures more gas is formed. As we go

Table 1.6 Characteristics of Some Bench Mark Crude Oils

Name API Gravity Sulfur, % Source Remarks

Brent crude 38.3 0.37 North Sea 15 oils from fields in the Brentand Ninian systems in theEast Shetland Basin of theNorth Sea

West TexasIntermediate (WTI)

39.6 0.24 North America

Tapis 45.1 0.10 Malaysia Light far east oil

Minas 35.0 0.80 Indonesia A weighted average of thesecrude oils are known as TheOrganization of the PetroleumExporting Countries (OPEC)reference basket

Arab light 34.1 1.78 Saudi Arabia

Bonny light 35.0e37.0 0.15 Nigeria

Fateh 31.0 2.00 Dubai

Isthmus 32.3e34.8 1.50 e 1.86 Mexico

Saharan Blend 43.5e47.5 0.10 Algeria

1.4 Hydrocarbon sources 7

further beneath the earth’s crust, the temperature increases. For this reason, gas is usually associatedwith oil in wells that are within one to two miles from the earth’s crest. Wells deeper than two milesprimarily produce natural gas.

In addition to oil and gas, wells may produce several other substances, including salt water(commonly known as formation or produced water), organic compounds (nitrogen, oxygen, andsulfur-containing species), metals (iron, nickel, copper, mercury, and vanadium), and radioactivematerials (commonly known as NORM – naturally occurring radioactive materials). The gas phasemay contain, in addition to hydrocarbons, carbon dioxide (CO2), hydrogen sulfide (H2S), hydrogen,and helium. The term ‘sweet’ is commonly used to refer to environments containing CO2 with noH2S. The term ‘sour’ is used to refer to environments containing H2S. Sour environments may alsocontain CO2.

The less the hydrocarbons are contaminated with other non-energy substances, the easier it is toextract them from the earth. To quickly express the value of crude oils, some industry bench markcrude oils have been established. Table 1.6 presents some commonly used key industry benchmarkcrude oils. The value of crude oil is also ranked using American Petrochemical Institute (API) gravity.API gravity and density are inversely related, i.e., the higher the density, the lower the API gravity(Table 1.7) and the higher the API value, the more valuable is the crude oil.5

In general, hydrocarbon sources may be broadly classified into conventional, unconventional, andrenewable.

1.4.1 ConventionalThere are no strict definitions of conventional oil and gas sources, but in general hydrocarbons can beproduced from conventional hydrocarbon sources with little or no effort. For a source to be identifiedas conventional, 40% or more of the fluids it contains should be hydrocarbons; the undergroundpressure and temperature should be high enough for the hydrocarbons to reach the surface on their own(or with minimal pumping); the API gravity should be high enough for oil to flow easily; and the

Table 1.7 Relationship Between API Gravity and Density5

Classification of Crude Oil API Gravity Scale,�Density (kilogramsper cubic meter)

Light 45.4 800

40.0 825

35.0 850

31.1 870

Medium 30.2 875

25.7 900

22.3 920

Heavy 21.5 925

17.4 950

13.6 975

10.0 1000

Extra heavy (Bitumen) 6.5 1025

3.3 1050

0.1 1075


properties of rock in the reservoir should be conducive to the free flow of hydrocarbons. The oil andgas industry uses five rock properties to determine whether the reservoir can produce hydrocarbons byconventional methods. They are:

• Porosity: the ratio of the void space in a rock to the bulk volume of rock;• Permeability: a measure of the ability of rock to permeate hydrocarbons through it;• Fluid saturation: a measure of oil, water, and gas contents of a rock;• Capillary pressure: a measure of ability of hydrocarbon to pass through a capillary tube which is

an indirect measure of whether the rock is wetted with water or oil;• Electrical conductivity: a measure of conductivity of bulk fluid in the rock. The oil-phase has low

conductivity and the water-phase has high conductivity.

Conventional production may take place in three stages: primary production, secondary, and tertiary.During the early stages of production, the reservoir pressure and hydrocarbon content are high. As thereservoir pressure and hydrocarbon content decrease, water is pumped into the well to continue toproduce from it. This process is known as secondary recovery or water flooding. Secondary recoveryby water injection increases the amount of oil recovered over primary production, but may still leavemore than 80% of oil in the reservoir. To recover more oil, gas (CO2, N2 or methane) may be injected.The process of recovering oil by injecting gas is known as tertiary recovery.

A few countries with the largest conventional oil reserves account for more than 70% of hydro-carbon production. Table 1.8 presents one estimate of the remaining quantities of conventional oil insome countries.2

1.4.2 UnconventionalUnconventional sources may be defined as those that cannot produce hydrocarbons at economic flowrates and in economic volumes unless the reservoir is first stimulated. The stimulation techniques

Table 1.8 Supply of Oil in Selected Countries2

Country

Years Remaining for ConventionalOil Reserves Producing at CurrentOil Flow Rates

Iraq 168

Kuwait 105

Iran 87

Saudi Arabia 75

United Arab Emirates 70

Venezuela 52

Russia 20

United States 16


include heat treatment, hydraulic fracture treatment, multilateral wellbores, and some other techniquesthat expose more of the reservoir to the wellbore. According to estimates, the world’s remainingsupplies of unconventional resources are 13–15 trillion barrels of crude oil and 32,000 TCF (910TCM) of natural gas (Table 1.9).6 Unconventional sources of hydrocarbons include oilsands, oil shales,gas shales, tight gas, coal bed methane, and gas hydrates.

1.4.2a OilsandsOilsands are a naturally occurring mixture that typically contains 10–12% bitumen, 80–85% minerals(clays and sands) and 4–6% water. Bitumen is a mixture of large hydrocarbon molecules containing upto 5% sulfur compounds by weight, small amounts of oxygen, heavy metals, and other materials.Physically, bitumen is denser than water and more viscous than molasses (sometimes existing as asolid or semi-solid). Bitumen-containing oilsand deposits are found in over 70 countries, but three

Table 1.9 Global Unconventional Gas Sources6

Region

Volume (TCF)

Shale Gas Tight Gas Coal Bed Methane Total

North America 3,842 1,371 3,017 8,228

South America 2,117 1,293 39 3,448

Western Europe 510 353 157 1,019

Central and Eastern Europe 39 78 118 235

Russia 627 901 3,957 5,485

Middle east and North Africa 2,548 823 0 3,370

Africa (Sub-Saharan) 274 784 39 1,097

Central Asia and China 3,528 353 1,215 5,094

Pacific 2,627 1,254 470 4,349

South Asia 0 196 39 235

World 16,112 7,406 9,051 32,560


quarters of the world’s known reserves are in Canada and Venezuela. Oilsands represent about 66% ofthe world’s total reserves of oil. According to estimates, the volumes of oil in Canadian and Ven-ezuelan oilsands are at least 1.7 trillion barrels (270 x 109 m3) and 235 billion barrels (37 x 109 m3)respectively.7–9

Most of the oilsands in Canada are located in three principal deposits in Northern Alberta:Athabasca, Cold Lake, and Peace River. The deposits encompass nearly 47,845 miles (77,000 km2) ofland area. The first Canadian oilsand mining operations started in 1967, the second began in1978, and the third began in 2003. Currently several further mining operations are either underdevelopment or commercial consideration. In 2005, oilsands accounted for 50% of Canada’s totalcrude oil output.

The Venezuelan oilsands are commonly known as ‘extra heavy oil’. Bitumen and extra heavy oilare essentially the same. The Venezuelan oilsands occur at higher temperatures 120�F (50�C) and theCanadian oilsands occur at freezing temperatures. For this reason, the Venezuelan oilsands existmostly in the liquid state, whereas Canadian oilsands exist in semi-solid and solid states. Hence theextraction of Venezuelan oilsands is relatively easier than Canadian oilsands.

In the USA, oilsands are primarily concentrated in eastern Utah, with an estimated 32 billionbarrels (5.1 x 109 m3) of oil. These oilsands have been quarried since the 1900s and are used mainly aspaving materials.

Oilsands are extracted by surface mining, or by in situ methods including cyclic steam stimulation(CSS), steam-assisted gravity drainage (SAGD), toe to head air injection (THAI), cold heavy oilproduction with sand (CHOPS), and the vapor extraction process (VAPEX) (see sections 2.8 and 2.9).

1.4.2b Shale oilShale oil is a fine-grained rock containing significant amounts of hydrocarbons.10 The global depositsof shale oil from which crude oil can be recovered are estimated to be about 3 trillion barrels (w500 x109 m3). Shale oil deposits occur in the USA, Estonia, China, Brazil, Germany, Israel, and Russia. TheUSA possesses 68% of the world shale oil resources, but in 2009 Estonia produced 80% of its oilrequirements from oil shale.11

The most common method of extracting shale oil is by surface mining. The in situ combustionprocess is used for extracting shale oil from far below the surface. The extracted shale oil thenundergoes pyrolysis at 842 to 932�F (450 to 500�C) to produce oil shale (synthetic crude oil), shale gasand residue (solid). This process also produces sulfur, ammonia, alumina, soda ash, uranium, arsenic,and nitrogen. Thus, similar to oilsands, the production of oil from shale oil is energy intensive andenvironmentally challenging.

Most shale oil is used as fuel in power generation plants. For example, 90% of the shale oil pro-duced in Estonia is used for power generation. Countries such as Romania and Russia also use shale oilfor power generation. It may also be used to produce several products including carbon fibers,adsorbents, carbon black, phenols, resins, glues, tanning agents, mastic, road bitumen, cement, bricks,construction and decorative blocks, soil additives, fertilizers, rock-wool insulation, glass, and phar-maceutical products. When the price of oil is high, however shale oil is used to produce crude oil.

1.4.2c Shale gasGas produced from shale is known as shale gas.12 Shales containing gas have a high organic materialcontent (up to 25%), to which the natural gas is adsorbed. For this reason, the shale has low


permeability for gas flow. The shale must be fractured to increase gas permeability. Techniques used tofracture the shale include hydraulic fracturing, horizontal drilling, and injection of large volumes ofwater containing sand particles at high pressure.

1.4.2d Tight gasTight gas refers to the natural gas trapped in reservoirs of low permeability. The low permeability ofthe reservoir is due to the fine-grained nature of the sediments, compaction, carbonates and silicatesfilling the pores. Gas from these reservoirs is produced by using similar special techniques to thoseused to produce gas from shale gas resources.

1.4.2e Coal bed methaneMethane adsorbed onto the surface of the coal bed is known as coal bed gas or coal bed methane(CBM).13 Coal beds predominantly contain methane, but they may also contain small amounts ofethane, propane, light liquid hydrocarbons, and CO2. To produce commercially, the methane content inthe coal bed should be more than 92%. Extraction of methane from a coal bed depends on its porosity,the adsorption strength of methane onto carbon, fracture permeability, thickness of the formation, andinitial reservoir pressure. Methane is extracted from the coal bed by drilling a steel pipe into the coalseam to release the pressure. As the pressure in the coal seam decreases, methane adsorbed onto coaldesorbs and escapes to the surface through the steel pipe.

1.4.2f Gas hydratesGas hydrates are solids with a cage-like chemical structure, in which natural gas (methane) moleculesare enclosed in water molecules. Hydrates are formed naturally at sub-zero temperatures, whenmethane produced by the breakdown of organic materials solidifies with water. Hydrates containimmense volumes of methane. For example, one unit volume of methane hydrate may produce 160unit volumes of methane at a given pressure. In addition ethane, propane, and butane hydrates alsooccur.

Globally, the amount of methane in gas hydrates is estimated to be 1 x 104 gigatons.14 Canada hasthe most concentrated deposits of gas hydrates in the world. Russia, USA, India, Japan, and China alsohave substantial deposits of gas hydrates. The first hydrate core was obtained from water 5,635 feet(1,718 m) deep in Guatemala. The second hydrate core was obtained from water 1,738 feet (530 m)deep in the Gulf of Mexico. The Malik field in the Canadian Arctic was the first experimental field toproduce natural gas from gas hydrates.

The formation and breakdown of gas hydrates depend on water content, composition of water,pressure (normally high pressure facilitates hydrate formation), and temperature (normally low orsub-zero temperatures facilitates hydrate formation). By varying the pressure, temperature, andadding chemicals (e.g., methanol or ethylene glycol), hydrates may be broken down to producenatural gas.

1.4.3 RenewablesAt this time, renewable hydrocarbon technology is not mature enough to replace fossil fuels, but ismature enough to supplement them. In some countries, fossil fuels used in automobiles contain 10 to20% biofuels. Many governments have passed legislation encouraging the use of renewable fuels.

Table 1.10 Global Production of Bioethanol15

CountryMillions of GallonsProduced (in 2006)

USA 4,855

Brazil 4,491

China 1,017

India 502

France 251

Germany 202

Russia 171

Canada 153

Spain 122

South Africa 102

Others 1,623

Total 13,489


Among the renewable fuels, biofuels (bioethanol and biodiesel) are most promising. Bioethanol ismixed with gasoline and biodiesel is mixed with diesel.

According to a 2006 survey, the worldwide production of bioethanol was 126 million barrels(15 billion liters) and that of biodiesel was 33 million barrels (4 billion liters). The production of bothbioethanol and biodiesel is anticipated to increase 10-fold over the next ten years. Currently, Brazil andthe USA are leaders in the production of bioethanol. Table 1.10 presents the amount of bioethanolproduced in different countries in 2006.15 The world trend shows a nearly five-fold increase in worldproduction over the next 20 years. The primary sources for bioethanol are corn and sugarcane. Othersources include hemp, sugar beets, maize, barley, potatoes, cassava, sunflower, wood pulp, andbrewing wastes.

Biodiesel is predominantly produced in Europe (90% of total biodiesel production). The remaining10% is produced in the USA (8%) and other countries, including Argentina, Brazil, Canada, India, andMalaysia. In 2007, the USA produced 2,392 million liters (632 million gallons) of biodiesel. In 2004,Canada produced approximately 3.5 million liters (875,000 gallons) of biodiesel, and in 2010 theproduction is expected to reach 500 million liters (132 million gallons).1,16

Biodiesel is produced from a variety of sources. Figure 1.4 presents various sources of bio-diesel.17,18 About 80% of the biodiesel in Europe is produced from rapeseed oil and about 20% fromsoybean oil. In the USA, most biodiesel is produced from soybeans. In Canada, biodiesel is producedfrom yellow grease, tallow, canola, and soybeans. Both the US and New Zealand are conductingexperimental studies to produce biodiesel from algae. In India, biodiesel is produced from two non-edible plants – Jatropha curcas and Pongamia pinnata.

The content of biodiesel in the blend is identified using the designation ‘B’, followed by thepercentage of biodiesel. For example, B2 indicates 2% biodiesel and 98% petroleum diesel and B20indicates 20% biodiesel and 80% petroleum diesel. Of the various blends, B20 is most commonly used.The energy content of biodiesel (as measured, for example in BTU) is about 7–9% less than that ofpetroleum diesel.

FIGURE 1.4 Some Resources for the Production of Biodiesel.17,18

1.5 History of the oil and gas industry 13

1.5 History of the oil and gas industry19–24

The oil and gas industry has been maturing over the past two centuries and continues to evolve. Thissection presents a brief history of the oil and gas industry so that we can appreciate its magnitude,knowledge, wealth, breadth, and impact.

4000 BC Oil seep was reported on the banks of the Euphrates River (currently Iraq). It was considered as
the ‘fountains of pitch’. Asphalt obtained from this pitch was used as mortar between buildingstones.
347 AD
Oil wells of depths 800 feet (240 meters) were drilled in China using bits attached to bamboopoles.
1482
A barrel of volume 42 US gallons (159 liters) was established as the standard for the packing offish. This scale is now commonly used to measure crude oil.
1500
Hydrogen was first recognized as inflammable air by Paracelsus.
1594
Oil wells of 115 feet (35 meters) deep were hand-dug in Baku, Persia (currently Iran).
1742
Oilsands were used by the ancient Mesopotamians and Canadian first nations.
1742
Corrosion protection of steel by zinc coating was first described.
1766
Hydrogen was first recognized as a substance by Cavendish.
1783
The name ‘hydrogen’ was coined by Lavoisier.
Continued


dContinued

1815
Oil was produced as an undesirable byproduct from brine wells in Pennsylvania, USA.
1824
Copper was successfully protected from corrosion by coupling it with either steel or zinc. This isthe origin of cathodic protection.
1836
Steel was protected from corrosion by dipping it into molten zinc. This procedure is known asgalvanizing and the product is known as galvanized steel.
1848
The first modern oil well was drilled in Baku, Iran.
1849
Abraham Gesner of Canada distilled kerosene from cannel coal and bituminous shale for the firsttime.
1853
Kerosene was extracted from petroleum.
1853
Biodiesel was first produced by Duffy and Patarick.
1854
The first European oil well was drilled in Bobrka, Poland.
1854
The first oil company (Pennsylvania Rock Oil Company) was formed in USA.
1858
The first North American oil well was drilled in Southern Ontario, Canada.
1859
The first commercially successful oil well was drilled in Pennsylvania, USA.
1860
The first real-time, end-to-end communications system along railway right of way wasestablished using telegraphic line (this technology was later adopted for use in pipeline right-of-way).
1860s
A company started manufacturing blue containers of volume 42 gallons. The company called itthe blue barrel and abbreviated it as ‘bbl’. This term is still being used.
1860s
Hydrotransport process was used during the construction of the Suez Canal. The sametechnology is currently being used to transport oilsands from mines to processing centers.
1861
Railroad tracks were laid in Pennsylvania, USA to transport oil from the field to the market. Oilfrom the wells to the railway station was transported in horse-drawn wagons.
1862
Atmospheric distillation was used in the refinery to produce kerosene.
1863
Dmitri Mendeleev first proposed the idea of transporting petroleum using pipes.
1863
The first oil transportation pipeline was constructed in Pennsylvania, USA. This 2 inch diameter(51 mm) and 2.5 mile (4 km) long cast iron pipeline used three pumps to transport oil over a 400foot (22 meters) ridge. It was however quickly abandoned because it developed several leaks.
1865
Another 6 inch (152 mm) diameter pipeline was constructed in Pennsylvania. This pipelinetransported oil along a gradient of 52 feet per mile (10 meters per kilometer). About 7,000 barrelsof oil per day were transported through this pipeline without any pump.
1865
Wrought iron was used to construct pipelines to overcome the leakage problems associated withcast iron. The first wrought iron pipeline transported petroleum distillates over a distance of threemiles. Subsequently, another 2 inch (51 mm) diameter, 6 mile (10 km) long wrought iron pipe wasconstructed. Three pumps were installed along the pipeline to increase the flow. This pipelinealso had the distinction of having first data acquisition and communications system; a telegraphline was used to communicate data on oil shipments.
1866
The practice of extracting oil from the well and storing it temporarily in tanks was established. Asa result, the cost of gathering the oil dropped from $1.00 to $0.25 per barrel.
1870
Vacuum distillation was established in the refinery.
1872
The Petroleum Producers Association endorsed 42 gallons (159 L) as equivalent to one barrel forreporting the volume of crude oil. This was the first consensus standard in the oil and gasindustry.
1873
The first oil-tank steamer was built in Belgium, but it was not successful due to many safetyconcerns.

1.5 History of the oil and gas industry 15

dContinued

1878
The first successful oil tanker (Zoroaster) was built in Sweden to transport oil from Baku toAstrakhan. Zoroaster carried 242 tons of kerosene in two iron tanks joined by pipes. This shipwas 184 feet (56 m) long, with a 27 feet (8.2 m) long beam and 9 feet (2.7 m) long draft.
1881
A tanker carrying kerosene exploded in Baku. A pipe was pushed out of its holding tank when agust of wind hit the tanker, and as a consequence oil tanker design drastically changed.
1893
Rudolf Diesel operated the first diesel engine, using peanut oil as the fuel.
1897
The first offshore well was drilled in Summerland, California, USA.
1800e1900
Europe and USA started using gas containing a mixture of hydrogen, methane, carbon dioxide,and carbon monoxide as fuel. This fuel was commonly known as ‘town gas’.
1900
Rotary drilling technology was first used to drill an oil well.
1901
Henry Ford formed the Ford Motor Company; as a consequence crude oil demand started toincrease.
1901
Hydraulic rotary drilling technology was first used.
1903
Two tankers (Vandal and Sarma) were built with internal combustion engines (until then tankersused steam engines). Each was capable of carrying 750 tons of refined oil and was powered by a360 horsepower (270 kW) diesel engine.
1908
Offshore production started in the shallow waters of Caddo Lake, Louisiana, USA.
1910e12
Impressed-current cathodic protection system was first used to protect underground structure.
1910s
Underwater drilling activities started in Caddo Lake, Louisiana, USA and Maracaibo Lake,Maracaibo, Venezuela. Initially, wells were drilled from onshore piers and subsequently they weredrilled from offshore wooden platforms.
1911
The volume of gasoline production exceeded that of kerosene as motor cars required them torun. Until then gasoline was discarded as a wasteful byproduct.
1913
The thermal cracking process was established in the refinery.
1916
The sweetening process was established in the refinery.
1920s
Steel piers from onshore extended up to a quarter of a mile into the ocean in California, USA.
1924
Offshore platforms were constructed on top of timber or concrete pilings in Lake Maracaibo,Venezuela.
1930
The thermal reforming process was established in the refinery.
1932
The first offshore steel platform (60 x 90 feet/18 � 27 meters) was completed in 38 feet (w12 m)deep water.
1932
The hydrogenation process was established in the refinery.
1932
The coking process was established in the refinery.
1933
The solvent extraction process was established in the refinery.
1935
First airline was successfully flown. This started the demand for jet fuel.
1935
The solvent dewaxing process was established in the refinery.
1935
The catalytic polymerization process was established in the refinery.
1937
The catalytic cracking process was established in the refinery.
1938
An offshore field was discovered in the Gulf of Mexico, USA.
1938
The first hydrogen pipeline was constructed in Germany.
1939
The visbreaking process was established in the refinery.
1940
Divers were used for the first time to remove wall casing under the ocean.
Continued


dContinued

1940
The alkylation and isomerization processes were established in the refinery.
1941
An offshore well was drilled to 9,000 feet (2,743 meters) in depth, in Texas, USA.
1942
The fluid catalytic cracking process was established in the refinery.
1947
The first ‘out off sight of land’ (drilling platform), i.e., far away from the coast, oil well wasconstructed off the coast of Louisiana, USA.
1940s
Two long pipelines, commonly known as ‘Big Inch’ and the ‘Little Big Inch’, were constructedbetween Texas and the east coast of the USA. The Big Inch pipeline was a 24 inch (61 cm)diameter pipeline to transport 300,000 barrel per day (BPD) of crude oil, and the Little Big inchwas a 20 inch (51 cm) pipeline to transport 235,000 BPD of refined oil.
1950
The deasphalting process was established in the refinery.
1950
The first successful application of cathodic protection to control corrosion of ships in Canada,along with protective coating. Previous attempts made between 1824 and 1827 had failed due tofouling by marine organisms.
1952
The catalytic reforming process was established in the refinery.
1953
The first floating rotary drilling vessel was operated. It was capable of drilling through 400 feet(122 meters) of water to depths of 3000 feet (914 meters).
1954
The hydrosulfurization process was established in the refinery.
1955
The drilling rig was moved from the side to the center of the ship to reduce the impact of vesselmotion.
1957
The catalytic isomerization process was established in the refinery.
1950s
The discovery of major crude oil and natural gas fields in Western Canada led to theestablishment of pipeline grid across Canada.
1960
The hydrocracking process was established in the refinery.
1963
The first commercial oil field was discovered in Alaska, USA.
1964
The first vessel carrying liquid natural gas (LNG) (Methane Princess) started operation.
1964
The first hydrogen pipeline was constructed in Canada.
1967
First commercial oilsands production started in Alberta, Canada.
1968
Fourteen platforms started producing oil and gas in Alaska, USA.
1969
A storage steel dome capable of storing 500,000 bbl oil was installed in the Arabian Gulf. Thisdome resembles an inverted champagne glass.
1960s
The Colonial pipeline of diameter ranging between 30 inches (76 cm) and 36 inches (91 cm) wasconstructed. Currently this pipeline is the longest petroleum product transportation system.
1970
Buoyant articulated columns were installed in the North Sea for loading crude oil directly into oiltankers (ships).
1972
Sand and gravel islands were constructed in Alaska, USA for exploratory drilling in water depthsof 100 feet (w31 meters).
1972
Flexible steel pipe was first used.
1974
The catalytic dewaxing process was established in the refinery.
1975
A two-piece jacket was installed in 850 feet (259 meters) of water off the coast of California, USA.
1976
A one-piece jacket in 680 feet (207 meters) of water was installed in the Gulf of Mexico, USA.
1977
The Trans-Alaska crude oil pipeline was constructed. This 48 inch (1.22 m) diameter, 798 mile(1,284 km) long pipeline transported approximately 1.7 million bpd of oil. Due to the extremearctic climate, rugged mountain terrain, earthquake regions (geological faults), and stringentstandards to preserve the arctic environment, the construction cost of the pipeline was $9 billion,making it by far the most costly pipeline project in the world.

1.6 Regulations 17

dContinued

1978
A three-piece jacket was installed in 1,025 feet (312 meters) of water in the Gulf of Mexico, USA.
1970s
Oil production activities started in the North Sea, Europe. Eighteen concrete structures wereinstalled in water depths between 240 and 540 feet (73 and 165 meters) with loads up to 40,000tons.
1981
A one-piece jacket was installed in 915 feet (279 meters) of water.
1983
A floating conical drilling unit was first deployed in the Canadian Beaufort Sea.
1984
A tension-leg platform was installed in 485 feet (148 meters) of water in the North Sea, Europe.
1980s
Horizontal drilling was successfully used in France and Italy.
1991
The first industrial-scale biodiesel plant started operation in Austria.
Current
The Comecon pipeline transporting oil from the Urals, Russia to Eastern Europe over a distanceof 3,800 mi (6,115 km) is the longest pipeline in the world. The world’s longest gas pipeline is alsoin Russia. This pipeline is 3,400 mile (5,500 km) long.
There are more than 2.5 million miles (4 million kilometers) of pipelines in North America. If thesepipelines were laid end-to-end they would circle the earth about 100 times. This pipeline networkincludes:

• 170,000 miles (274,000 kilometers) of onshore and offshore hazardous liquid pipelines• 295,220 miles (475,110 kilometers) of onshore and offshore gas transmission pipelines• 1,900,000 miles (3 million kilometers) of natural gas distribution pipelines and propane

distribution pipelines

Future hydrocarbons will increasingly be produced from frontier (arctic) as well as from deepwater (deeper than 33,000 feet (10,000 meters)) regions.

As conventional sources become depleted, more and more efforts will be made to producehydrocarbons from unconventional and renewable sources.

1.6 RegulationsChapter 2 describes different entities of the oil and gas industry network. Most parts of these networksare underground, except for some huge facilities such as storage tanks and refineries. The existence ofunderground facilities is indicated with aboveground markings in many countries. For example, inUSA the American Public Works Association (APWA) uses yellow color code to indicate oil and gasstructure. Table 1.11 presents the APWA color code to indicate various infrastructures.

The vast underground oil and gas networks are strictly regulated by a number of governmentregulatory agencies; from the design and construction stages to operation and discontinuation (oftenreferred to as abandonment) stages. These agencies ensure that the oil and gas network is operatedsafely, responsibly, and in the public interest. Table 1.12 presents typical types of approvals requiredfor operating an oil and gas network in Canada, and Table 1.13 presents typical types of applicationrequired for approval.25 Table 1.14 presents the types of regulators for gas networks in the USA.Table 1.15 presents some regulators in Canada and USA.

While different countries have different regulations, they are all more or less based on the sameprinciple; i.e., to safeguard people, the environment, and the facility. Table 1.16 compares differentregulators’ approaches.26 Some regulations are prescriptive in nature, while others are descriptive. Inprescriptive regulations, the steps to be taken to maintain the integrity of the infrastructure are

Table 1.11 American Public Works Association Color Code)

Infrastructure Color

Electric Red

Oil and Gas Yellow

Communication/Cable Orange

Water Blue

Sewer Green

Proposed excavation White

)American Public Works Association (APWA) color code


prescribed. Generally, prescriptive regulations are to be considered only as a minimum. Responsibleoperation may need to go further. In descriptive regulations, the expectations of the regulators areoutlined, leaving the steps to be taken with the operators. There are many terms for this style ofregulation: goal-based, outcome-based, goal-oriented. All describe the desired outcome and leave themechanics of how to achieve that to the operator.

Because transmission pipelines operate at elevated pressure, travel long distances, and pass throughother infrastructure such as roads, buildings, railway lines, electric towers, and industrial complexes,the regulations governing their operation can be more stringent than those governing other parts of theoil and gas industry. Regulations in Canada (mostly descriptive) and in US (mostly prescriptive) fortransmission pipelines are discussed in the following paragraphs as illustration.

In Canada, the National Energy Board (NEB) regulates the design, construction, operation, andabandonment of interprovincial and international pipelines within Canada. According to the NEB Act(OPR 99), ‘pipeline’ means a line that is used or to be used for the transmission of oil, gas, or any othercommodity and includes all branches, extensions, tanks, reservoirs, storage facilities, pumps, racks,compressors, loading facilities, inter-station systems of communication by telephone, telegraph orradio and real and personal property and works connected therewith, but does not include sewer orwater pipeline that is used or proposed to be used solely for municipal purposes.

Pipelines within the province are regulated by provincial regulators. For example, in Alberta, mostactivities related to the planning, construction, operation, and abandonment of oil and gas pipelines areregulated by the Alberta Energy Regulator (AER). The AER is responsible for issuing approvals forgathering and transmission lines as well as high pressure (greater than 700 kPa) distribution lines thatlie fully within Alberta. Alberta Transportation and Utilities (ATU) board regulates lower pressurelines.

Regulations may require the operator to have manual describing operations, maintenance, repair,corrosion control, and integrity management processes as well as to have documents to demonstratecompliance. Regulations may also require the operator to evaluate, inspect, and/or test annually theoperating or discontinued pipelines and the operator to submit corrosion control experience, moni-toring data and inspection data.

It is generally expected that the operators are responsible for ensuring that their operations areconducted in accordance with regulations and best practices. However, in certain situations, regula-tions may be enforced. Table 1.17 presents the enforcement ladder that AER uses to categorize thelevels of non-compliance.27

Table 1.12 Typical Approval Requirements in Alberta, Canada

Activity

Regulatory/Reference Documents from Regulatory Agencies

Alberta Energy Regulator (AER) Alberta Environment)

Construction operation or reclamation ofan oil production site

Directive 056: Energy developmentapplication guide and schedules

Activities designation regulation; conservationand reclamation regulation, Section 3: Code ofpractice for oil production sites - IL 95e3 andIL 94e6

Single sour oil well Directive 056

Multiple sour oil or gas wells Directive 056

Multiple sweet oil or gas wells Directive 056

Conduct of an exploration operation for oilsands

Activities designation regulation, code of practicefor exploration operations

Oil sands mine Environmental assessment; Mandatory andexempted activities regulation

Sweet gas plant processing less than16 kg/hr of nitrous oxide (NOx)

Oil and Gas Conservation Act, Section 21and Directive 056

Code of practice for compressor and pumpingstations and sweet gas processing plants;Activities designation regulation, A.R. 211e96

Sweet gas plant processing more than16 kg/hr of nitrous oxide (NOx)

Oil and Gas Conservation Act, Section 21and Directive 056

Code of practice for compressor and pumpingstations and sweet gas processing plants;Activities designation regulation, substancerelease regulation, Section 14e1

Sour gas processing plant Directive 056 Activities designation regulation; environmentalassessment; Mandatory and exempted activitiesregulation

In situ oil sands or heavy oil processingplant

Activities designation regulation

Commercial oil sands, heavy oilextraction, upgrading or processing plantproducing more than 2000 m3 of crudebitumen or derivatives/day

Guide 23: Guidelines respecting anapplication for a commercial crudebitumen recovery and upgrading project

Environmental assessment; Mandatory andexempted activities regulation

Sweet or sour compressor or pumpstations

Directive 056 Code of practice for compressor and pumpingstations and sweet gas processing plants

Tank farm or Bulk petroleum storagefacility

Activities designation regulation

Pipelines Directive 056

Oil refinery Activities designation regulation; environmentalassessment; Mandatory and exempted activitiesregulation

)The Government of Alberta which administers and enforces Environmental Protection and Enhancement Act

1.6

Regulations

19

Table 1.13 Energy Resources and Conservation Board Pipeline

Application Procedure24

Schedule Category Type of Application

1.0 Energy development application

2.1 Facility development license

2.2 Gas plants e facility

2.3 H2S information

2.4 Compressor/Pump e facility

3.0 Pipeline license

4.1 Well license

4.2 Multiple wells pad location

4.3 Well H2S information

Table 1.14 Examples of USA Regulatory Bodies for Gas Networks

Sector Regulator

Gas wells Unregulated

Production pipeline Regulated in some states by State regulators

Transmission pipeline Federal Energy Regulatory Commission (FERC) and PipelineHazardous Materials Safety Administration (PHMSA)

Storage Regulated in some states by State regulators

Distribution Regulated in some states by State regulators


In addition, Canadian environmental protection agencies may regulate conservation andreclamation activities on private land for gathering, transmission, and distribution pipelines.Additional approvals from environmental, fisheries, and ocean governing agencies may also berequired to construct, operate, or discontinue the pipelines. In addition to these governmentapprovals, operators must also obtain the landowner’s permission for construction and maintenance ofpipelines.

The Federal Energy Regulatory Commission (FERC) oversees the USA interstate natural gaspipeline industry. The commission regulates both the construction of interstate natural gas pipelinesand transportation of natural gas in interstate commerce. Companies wishing to build interstatepipeline facilities or operate pipelines must first obtain a Certificate of Public Convenience andNecessity from FERC. This is done to ensure that pipeline facilities benefit consumers, are compatiblewith the environment, and minimize interference with the public’s and landowners’ rights-of-wayalong the pipeline.

The Office of Pipeline Safety (OPS), within the US Department of Transportation (DOT), Pipelineand Hazardous Materials Safety Administration (PHMSA), regulates hazardous liquid and gas onshorepipelines. Offshore pipelines are regulated by the US Department of Interior’s Minerals ManagementService (MMS).

Table 1.15 Some Government Bodies Regulating Oil and Gas Industry in Canada and USA

Country Regulator Function

Canada National Energy Board (NEB) Federal regulator of pipelines crossingcountry and provincial borders

Canada Transportation Safety Board Failure investigation

Canada Alberta Energy Regulator (AER), Alberta Regulator of all oil and gasinfrastructure in Alberta, Canada

Canada British Columbia Oil and GasCommission

Regulator of oil and as infrastructurein British Columbia

Canada New Brunswick Board of Commissionof Public Utilities

Regulator of oil and as infrastructurein New Brunswick

Canada Resources, Economic Development,Minerals, Oil and Gas, North WestTerritories

Regulator of oil and gas infrastructurein North West Territories

Canada National Energy Board (COGOA) Regulator of oil and gas infrastructurein Northwest Territories and Nunavut

Canada Northern Pipelines Beaufort-MackenzieMineral Development Commission

Regulator of oil and gas infrastructurein Beaufort and Mackenzie area

Canada Nova Scotia Offshore Petroleum Board Regulator of offshore oil and gasinfrastructure in Nova Scotia

Canada Nova Scotia Utility and Review Board Regulator of onshore oil and gasinfrastructure in Nova Scotia

Canada Ontario Energy Board and TechnicalStandards and Safety Authority

Regulators of Ontario

Canada Quebec Regie de l’Energie (QuebecEnergy Board)

Regulator of Quebec

Canada Saskatchewan Energy and Mines Regulator of Saskatchewan

Canada Yukon Territory Department ofEconomic Development Oil and GasResources Branch

Regulator of Yukon

Canada Manitoba Public Utilities Board andManitoba Department of Energy andMines

Regulators in Manitoba

Canada Prince Edward Island Energy and Mines Regulator in Prince Edward Island

USA FERC Regulator of gas network

USA Pipeline and Hazardous MaterialsSafety Administration (PHMSA)

Regulator of onshore pipeline

USA US Department of Interior - MineralsManagement Service

Regulator of offshore pipeline

USA California Office of Spill Prevention andResponse

Regulator in California state

USA California Division of Oil, Gas, &Geothermal Resources Pages


USA California State Fire Marshall’s OfficePages


Continued

1.6 Regulations 21

Table 1.15 Some Government Bodies Regulating Oil and Gas Industry in Canada and USA Continued

Country Regulator Function

USA California State Lands Commission Regulator in California state

USA Washington Utilities & TransportationCommission

Regulator in Washington state

USA Oregon Department of EnvironmentalQuality

Regulator in Oregon state

USA Alaska Department of EnvironmentalConservation

Regulator in Alaska state

USA National Transportation Safety Board(NTSB)

Failure investigators

USA Office of Pipeline Safety Regulator of oil and gas pipelines

USA US Coast Guard (USCG) Security of ocean infrastructure

Table 1.16 Comparison of Different Philosophies of Regulations25

Aspects ofRegulations

Type of Regulations

PrescriptiveGoal-Oriented(Descriptive)

Goal-Based(Descriptive)

Regulations provide Direction onmethods

Direction on methods anddescription of desired endstates

Description of desiredend states

Compliancemeasured by

Check lists Check lists and professionaljudgment

Professional judgment

Risk approach Deterministic Risk informed Risk based

Compliance determinedprimarily through

Inspection Inspection and audit Audit


The minimum pipeline safety standards are prescribed in the US Code of Federal Regulations(CFR), Title 49, ‘Transportation’, Parts 192–195.

• Part 192: Transportation of natural and other gas by pipeline• Part 193: Liquefied natural gas facilities• Part 194: Response plans for onshore oil pipelines• Part 195: Transportation of hazardous liquids by pipelines

Regulations of pipelines are often based on rigorous standards and best practices developed by variousindustry, technical, and scientific associations. The voluntary consensus standards and best practicesare developed as a method of improving the individual quality of a product or system. Table 1.18presents some organizations that develop standards pertaining to oil and gas industry.

Table 1.17 Alberta (Canada) Provincial Government’s Enforcement Ladder26

Compliance Magnitude of the Issue Types of Issue Level Enforcement Ladder

Minor non-compliance Does not result in a directthreat to the public and/or theenvironment and does notadversely effect oil and gasoperations

Well/facility/pipelineidentification sign(s) are notposted and are inadequateValve handle(s) missingOil or salt water staining onleaseRequired calibration tag notattached to measurementdevice

1 Instruction

2 Instruction

3 Full or partial suspension ofoperations when safe to do so. Anon-compliance event will beadded into the corporate datainformation system.

4 Full or partial suspension ofoperation when safe to do so.Suspension will remain in effectuntil documented meeting withsenior company representativewith provincial authority (VP/Pres)is held.

Major non-compliance The operator has failed toaddress an issue and/or theissue has the potential tocause an adverse impact onthe public and/or theenvironment

Blowout preventer failed tooperate properlyTank vapor recovery unit notfunctional allowing H2S to ventUnaddressed spill on or offleaseNo crossing agreement onpipeline construction

2 Level: Instruction and temporarysuspension of certain operationsto correct deficiencies andalleviate impact or potentialimpact.

3 Full or partial suspension ofoperations to alleviate impact orpotential impact when safe to doso. Suspension will remain ineffect until documented meetingwith senior companyrepresentative (Vice president/President) with provincialauthority is held.

4 Immediate suspension (full orpartial) of operations to alleviateissue when safe to do so.Suspension will remain in effectuntil documented meeting withsenior company representative

Continued

1.6

Regulations

23

Table 1.17 Alberta (Canada) Provincial Government’s Enforcement Ladder26 Continued

Compliance Magnitude of the Issue Types of Issue Level Enforcement Ladder

with provincial authority is held.Company also confirmscompliance at this and all similarfacilities and submits a writtenacceptable action plan includingexamination of cause and futureprevention plans andcommitments.

Serious non-compliance Causing or may cause asignificant impact on thepublic and/or environment

Blowout preventer(s) missingUnaddressed spill into water,operator aware, no action isbeing takenConducting an activity withoutan approval and/or licensewhere requiredH2S odor present, operatoraware, no action is beingtaken

3 Full or partial suspension ofoperations to alleviate impact orpotential impact when safe to doso. Suspension will remain ineffect until documented meetingwith senior companyrepresentative with provincialauthority is held.

4 Immediate suspension (full orpartial) of operations to alleviateissue when safe to do so.Suspension will remain in effectuntil documented meeting withsenior company representativewith provincial authority is held.Company also confirmscompliance at this and all similarfacilities and submits a writtenacceptable action plan includingexamination of cause and futureprevention plans andcommitments.

24

CHAPTER1

TheOilandGasIndustry

Table 1.18 Selected Technical Organizations Developing Standards for Oil and Gas Industry

Association Abbreviation

Association Francaise de Normalization AFNOR

Association Suisse de Normalization SNV

American Bureau of Shipping ABS

American National Standards Institute ANSI

American Petroleum Institute API

American Society of Mechanical Engineers ASME

ASTM International (formerly American Society of Testingand Materials)

ASTM

American Welding Society AWS

American Water Works Association AWWA

American Petroleum Industry API

American Gas Association AGA

American Society of Mechanical Engineers ASME

American Nation Standard Institute ANSI

American Society of Petroleum Engineers ASPE

Association of Oil Pipelines AOP

Badan Kerjasama Standardisasi Lipi-Ydni (Indonesiastandard organization)

British Standards Institute BSI

Bureau of Indian Standards BIS

Canadian Association of Petroleum Producers CAPP

Canadian Energy Pipelines Associations CEPA

Canadian Standards Association CSA

Canadian Gas Association CGA

China Association for Standardization

Commission Venezolana de Normas Industriales(Venezuela)

COVENIN

Composites Engineering and Applications Center CEAC

Deutsches Normenausschub (Germany) DIN

Direccion General de Normas (Mexico) DGN

Ente Nazionale Italiano de Unificazione (Italy) UNI

Gas Research Institute GRI

Gas Technology Institute (formerly Gas Research Institute) GTI

Indian Standards Institute ISI

International Organization for Standards ISO

Interstate Natural Gas Association of America INGAA

Japanese Industrial Standards Committee JISC

Nederlands Normalisatie Instituut NNT

Norges Standardiseringsforbund SSF

NACE International (Formerly National Association ofCorrosion Engineers)

NACE

Continued

1.6 Regulations 25

Table 1.18 Selected Technical Organizations Developing Standards for Oil and Gas

Industry Continued

Association Abbreviation

NORSOK/Standard Norge NORSOK

National Fire Protection Association NFPA

Oesterreichisches Normungsinstitut (Austria) ONORM

Pipeline Research Council International PRCI

Standards Association of Australia SAA

Saudi Arabian Standards Organization SASO

Singapore Institute of Standards and Industrial Research SIRU

Standardisering Kommissionen (Sweden) SIS

Society of Protective Coating SSPC

United Kingdom Offshore Operators Association UKOOA

US Coast Guard USCG

USSR State Committee for Standards (Russia)


Despite the best efforts of companies, industry, regulatory agencies, and stakeholders, oil and gasinfrastructure may sometimes fail, releasing their contents to the environment. The impact of thefailure depends on its size and type, the location and type of infrastructure, and the products beingtransported. The failures may be broadly classified into accidents, incidents, and leaks. Accidents aremajor occurrences, such as a line rupture or an instantaneous tearing or fracturing of material, whichimmediately shut down the system. Incidents are minor leaks and operational malfunctions that affectthe safety of the system and that curtail operations. Leaks are loss of product through small openings,cracks, or holes that do not immediately affect pipeline operation and which may have gone unnoticedfor a long time.

When a failure occurs, normally another government body investigates it. In Canada, for example,the Transportation Safety Board (TSB) investigates incidents on federally regulated infrastructure toidentify direct causes and contributing factors. In the USA, the National Transportation Safety Board(NTSB) investigates pipeline significant accidents (fatality or substantial property damage; typicallyany failure causing more than five gallons or equivalent amounts of hydrocarbon release). Theinvestigatory agencies conduct failure analysis and root-cause analysis. The investigatory agenciesmay also issue safety recommendations aimed at preventing future accidents.

1.7 The significance and impact of corrosion in the oil and gas industryIn order to use hydrocarbons as energy source, they must be extracted from underground, all other non-energy containing products separated from them, and the different types of hydrocarbons separatedfrom one another. These processes occur at various stages between the wells where the hydrocarbonsare found and the locations where they are used as fuels. Between the sources of the hydrocarbons andthe locations in which they are used as fuels, there is a vast network of oil and gas infrastructure.

Table 1.19 Annual Corrosion Cost in Major Sectors of USA Oil and Gas Industry3

SectorAnnual Cost of Corrosionin US (Million US Dollars)

Production) 1,372

Transmission- pipeline 6,973

Transportation-Tanker)) 2,734

Storage 7,000

Refining 3,692

Distribution 5,000

Special Not known

)The amount is only for production from conventional sources (corrosion cost for production fromnon-conventional and renewal sources is not included)))World total

Table 1.20 Types of Failures and their Causes in Oil and Gas Industry27

Location

Causes

Pre-Service In Service

Main body Mechanical damage Mechanical damage

Defective material Defective material

Transportation damage Corrosion (internal and external)Cracking (Hydrogen-stress, stress-corrosion,sulfide-stress and stepwise)

Joints (including weld) Defective joints Defective weldWeld (heat-affected) zone corrosionIncompatibility between main body and joint

All components Secondary loads from soil movementEarthquakeInternal combustionSabotagesInterferences (telluric, alternating current, and stray)Incompatibility between material and environment(i.e., selection of wrong material)

1.7 The significance and impact of corrosion in the oil and gas industry 27

Table 1.19 presents the major sectors of oil and gas network and Chapter 2 describes their charac-teristics. This vast network comprises different materials exposed to different environmentsand to different operating conditions (flow, temperature, and pressure). As consequence of variousinteractions, the integrity of the infrastructure may be compromised resulting in failures. In general,the causes of failure may be classified into two categories: pre-service and in service. Table 1.20summarizes the major factors that can compromise the integrity of the oil and gas network.28 FromTable 1.20 it is obvious that corrosion is a key cause of failure. Recently, the cost of corrosion in the


USAwas surveyed. The cost of corrosion in the oil and gas industry from that survey3 and from otherstudies is summarized in the following sections.

1.7.1 Production sectorComponents of production sector include drill pipe (see section 2.2), casing pipe (see section 2.3),downhole tubular (see section 2.4), acidizing pipe (see section 2.5), water generator (see section 2.6),gas generator (see section 2.7), wellhead (see section 2.10), production pipeline (see section 2.11), gasdehydration facility (see section 2.14), oil separator (see section 2.15), lease tank (see section 2.18),and waste water pipeline (see section 2.19). The oil and gas production sector may be broadly clas-sified into downhole and surface units.

• The downhole unit consists of drill pipe, casing pipe, downhole tubular, acidizing pipe, watergenerator, and gas generator.

• The surface unit consists of the wellhead, production pipeline, gas dehydration facility, oilseparator, lease tank, and waste water pipeline.

The annual capital expenditure of onshore oil and gas production sector in the USA is estimated at $4.0billion; of which $320 million (8%) is directly related to corrosion control. The annual operatingexpenditure of the onshore oil and gas production sector in the USA is estimated at $1.372 billion; ofwhich $1.052 billion (76%) is directly related to corrosion control. Of that $1.052 billion, $589 millionis spent on controlling corrosion in downhole units, and $463 million is spent on controlling corrosionof surface units.

There are approximately 0.6 onshore downhole tubular failures per year per well, and 30% of thesefailures are caused by corrosion. Each onshore downhole tubular failure incurs $3,000 of direct cost. Itis difficult to repair and replace downhole tubulars operating offshore. Therefore additional pre-cautions are taken when maintaining these infrastructures. For this reason, the cost of corrosion controlfor offshore downhole tubulars is higher than onshore downhole tubulars. Table 1.21 presents theaverage corrosion cost associated with maintaining a surface unit in the USA; as the amount of waterproduced, along with oil, increases the cost of corrosion also increases.

There is a vast network of production pipelines between the wellhead and gas dehydration facil-ities, as well as between wellhead and oil separators. Figures 1.5, 1.6, and 1.7 present statistics forproduction pipelines in Alberta, Canada.29,30 Figure 1.8 presents factors that cause failure of pro-duction pipelines. Figure 1.9 presents the number of failures caused by corrosion. More than 70% offailures were caused by corrosion; of which about 58% were due to internal corrosion and 12% weredue to external corrosion.

Table 1.21 Corrosion Cost in Production Pipeline Unit in the USA3

Production Cost per Barrel, $

Offshore oil 0.40

Onshore oil 0.20

Offshore water 0.14 to 0.18

Onshore water 0.07 to 0.09

0

100,000

200,000

300,000

400,000

1980 1985 1990 1995 2000 2005 2010Year

Le

ng

th

, K

mCrude oilNatural gasSour gasWaterMultiphaseOthersTotal

FIGURE 1.5 Lengths of Production Pipelines in Alberta, Canada.28,29 (The reduction of pipeline length in 1998 is

due to transfer of regulatory responsibility of some pipelines to federal regulator).

60.3

(2)

88.9

(3)

114.

3 (4

)

168.

3 (6

)

219.

1 (8

)

273.

1 (1

0)

323.

9 (1

2)

355.

6 (1

4)

406.

4 (1

6)

457.

0 (1

8)

508.

0 (2

0)

559.

0 22

)

610.

0 (2

4)

660.

0 (2

6)

762.

0 (3

0)

864.

0 (3

4)

914.

0 (3

6)

1067

.0 (4

2)

1219

.0 (4

8)

0

20,000

40,000

60,000

80,000

100,000

60.3

(2)

88.9

(3)

114.3

(4)

168.3

(6)

219.1

(8)

273.1

(10)

323.9

(12)

355.6

(14)

406.4

(16)

457.0

(18)

508.0

(20)

559.0

22)

610.0

(24)

660.0

(26)

762.0

(30)

864.0

(34)

914.0

(36)

1067

.0 (42

)

1219

.0 (48

)

Diameter mm (inches)

Len

gth

, km

FIGURE 1.6 Typical Diameter of Gas Production Pipelines in Alberta, Canada.28,29


0

500

1,000

1,500

2,000

2,500

3,000

3,500

60.3

(2)

88.9

(3)

114.3

(4)

168.3

(6)

219.1

(8)

273.

1 (10

)

323.9

(12)

355.6

(14)

406.4

(16)

457.0

(18)

508.0

(20)

559.0

22)

610.0

(24)

660.0

(26)

762.0

(30)

864.0

(34)

914.0

(36)

Diameter, mm (inches)

Len

gth

o

f P

ip

elin

es, K

m

FIGURE 1.7 Typical Diameter of Oil Production Pipelines in Alberta, Canada.28,29


Some components, such as open mining (see section 2.8), in situ production (see section 2.9),heavy crude oil pipelines (see section 2.12), hydrotransport pipelines (see section 2.13), recoverycenters (see section 2.16), upgraders (see section 2.17), and tailing pipelines (see section 2.20), areexclusively used in producing oil from oilsands. This part of the industry is relatively new andexpanding rapidly. The corrosion cost of these components is not fully understood. Oilsands plants cancost $10 billion or more to build. Individual companies in Canada spend over $20 million in corrosioncontrol program per year on just one operating field. One study does however indicate that the annualcorrosion cost for just one company producing oil from oilsands is over $450 million.31

1.7.2 Transportation – pipeline sectorTransmission pipeline sector normally includes pipelines (see section 2.21), compressor stations (seesection 2.22), pump stations (see section 2.23), and pipeline accessories (see section 2.24). Theyoperate mostly onshore, transporting large quantities of products across countries or continents. InUSA, there are more than 483,000 km (300,000 mi) of natural gas transmission pipelines operated byover 60 companies, and 217,000 km (135,000 mi) of hazardous liquid transmission pipelines operatedby more than 150 companies. In Canada there are approximately 45,000 km of oil and gas transmissionpipelines.

In the USA as of 1998, total investment for establishing gas pipeline network was $63.1 billion andthat for establishing the liquid pipeline network was $30.2 billion; i.e., the total capital investment forthe transmission pipeline industry was $93.3 billion. If this transmission pipeline network were to be

FIGURE 1.8 Alberta, Canada Production Pipeline Failure Data for 1980–2005.28,29


replaced today the cost would be $541 billion. The annual capital investment is estimated at $8.1billion, based on construction cost of $746,000 per km ($1.2 million per mi). The annual maintenancecost is estimated at between $470 and $875 million.

Table 1.22 presents the annual cost of corrosion in the USA transmission pipeline sector. The totalannual cost ranges between $5.40 billion and $8.56 billion (with an average of approximately $7billion). Of the 7 billion dollars, 52% is for operation and maintenance (O&M), 38% is capital(including replacement cost), and 10% is for repair after failures (non-related O&M). It should benoted that the corrosion cost estimated in the survey also included the corrosion cost of 45,000 km(38,000 mi) of natural gas gathering pipelines and 34,000 km (21,000 mi) of crude oil gatheringpipelines.1,3

Table 1.23 summarizes the accidents and incidents associated with transmission pipelines. 25% ofthese accidents were caused by corrosion. Of these, approximately 35% of gas transmission pipelinefailures were due to external corrosion, and approximately 65% were caused by internal corrosion.Approximately 65% of oil transmission pipeline failures were due to external corrosion andapproximately 35% were due to internal corrosion.

0

200

400

600

800

1,000

1975 1980 1985 1990 1995 2000 2005 2010Year

Nu

mb

er o

f F

ailu

re

s

P

erc

en

ta

ge

o

f fa

ilu

re

s

0

20

40

60

80

100Failures due to internal corrosion

Percentage of failures due tointernal corrosion

FIGURE 1.9 Failures Caused by Corrosion of Production Pipelines in Alberta, Canada.28,29

Table 1.22 Summary of the Total Annual Cost of Corrosion in USA Transmission Pipeline Sector3

Corrosion Cost

Estimate ($ x million)

PercentMinimum Maximum Average

Cost of capital 2,500 2,840 2,670 38

Operations and maintenance(O&M)

2,420 4,840 3,630 52

Cost of failures(Non-related O&M))

471 875 673 10

Total cost due to corrosion 5,391 8,555 6,973 100

)non-related O&M costs include indirect costs associated with fatalities, injuries, loss of throughput, and legal expense


Table 1.24 presents the data for the transmission pipeline sector in the USA between 1970 and1984.32 There were 5,872 failures during this period, of which approximately 17% were caused bycorrosion. Of the corrosion failures, 40% were due to external corrosion and 27% were due to internalcorrosion. About 40% of the failures occurred in pipelines of diameter 10 or 20 inches; almost allfailures were due to corrosion. Most failures of larger diameter pipelines were due to externalcorrosion, and most failures of smaller diameter pipelines were due to internal corrosion. About 50%of corrosion failures occurred in pipelines that were 30 years old, or older. Over 90% of corrosionfailures were due to localized pitting corrosion.

Table 1.23 Transmission Pipeline Accidents and Incidents in USA3

Accidents/Incidents Natural Gas Transmission Hazardous Liquid

Number of major accidents) 500 675

Number of accidents/10,000 miles) 14 42

Number of injuries) 100 100

Number of fatalities) 22 16

Property damage ($M)) 180 330

Total accidents)) 448 1,116

Total accidents due to corrosion)) 114 270

Percent of accidents due tocorrosion))

25.4 24.3

Percent of accidents due to externalcorrosion))

36.0 64.9

Percent of accidents due to internalcorrosion))

63.2 33.6

Percent of non-corrosion accidents)) 0.8 1.5

)Based on data between 1989 and 1998e this data does not distinguish the accidents/incidents caused bycorrosion))Based on data between 1994 and 1999

Table 1.24 Service Failures of Natural Gas Transmission and Gathering Lines

Between 1970e1984 as Reported to DOT USA32

Cause Number of Events Percentage

Outside force 3,144 53.5

Material failure 990 16.9

Corrosion 972 16.6

Other 437 7.4

Construction defect 284 4.8

Construction of material 45 0.8

Total 5,872 100.0


1.7.3 Transportation – other modes sectorIn addition to pipelines, oil tankers (ships) (see section 2.25), railcars (see section 2.27), and trucks (seesection 2.28) transport oil and gas. Table 1.25 presents some characteristics of these modes oftransportation.

Currently there are more than 9,320 tankers and carriers transporting oil across the world. Thesetankers constitute approximately 11% of the world’s total number of ships. The total gross tonnage oftankers and carriers is 168,011,588 metric tons (185,200,000 tons). They transport oil and gas,chemicals, liquefied gas, ores, and other materials; of which 35% transport oil and gas. The global

Table 1.25 Some Modes) of Transportation of Oil and Gas3

TransportationAcross Vehicle

Loading/UnloadingFacilities Containers

Land Trucks Refineries, terminals, andconsumer tanks

Tanks

Trains Stations Tanker train cars

Water Ships Directly from productionwells and docks

Tanks anddrums

Air Airplanes Airports Specialcontainers

)Other than pipelines

Table 1.26 Average Annual Corrosion Cost for Construction of Ships to Transport Oil and LNG3

Type of Ship Number

Percentage Costof ConstructionDue to Corrosion

Average Cost ofVessel ($ x million)

Average CorrosionCost per Year($ x million)

Oil tankers 6,920 13 50 1,799

LNG(Refrigerated cargo)

1,441 10 6 35


annual cost of corrosion in the shipping industry is approximately $7.5 billion. Based on the proportionof ships carrying oil and gas, the average annual cost attributable to transport of oil and gas is estimatedat approximately $1.835 billion (Table 1.26). This estimate however does not include corrosion costsin liquefaction and regasification facilities for LNG (see section 2.26).

More than 483,000 car loads of petroleum and coke are transported annually by railroad cars inUSA. Based on the percentage of commodity transported, the annual cost of corrosion in USA fortransporting petroleum and coke by the railroad industry is estimated at $11.16 million.

Trucks are used when construction of pipelines is not economical, the materials are only to betransported for shorter distances, or the volume of materials transported is small. In the USA annually,there are at least 300 million shipments transporting over 3.1 billion metric tons of hazardous mate-rials, of which about 2.6 billion metric tons are petroleum products. The average annual cost ofcorrosion for all hazardous materials transportation is over $887 million. The annual corrosion costincludes the cost of the transporting vehicles ($400 million per year), the cost of specialized packaging($487 million per year), and indirect costs ($0.5 million per year). The indirect costs include the cost ofcleaning due to accidental release of hazardous materials.

1.7.4 Storage tank sectorThere are approximately 8.5 million aboveground storage tanks (ASTs) and underground storage tanks(USTs) for storing hazardous materials (HAZMAT) in the USA. Table 1.27 presents details of thesestorage tanks. Most of these storage tanks are used to store oil (see section 2.30) and gas (see section2.29). Most of the storage tanks are regulated in the USA by Spill Prevention Countermeasure and

Table 1.27 Statistics of Aboveground and Underground Storage Tanks in USA3

Types ofTanks Regulated by Product

Type ofStorage Tanks

Numberof Tanks

Various Miscellaneous UST 133,400

Office of UndergroundStorage Tanks (OUST)

Petroleum & HAZMAT UST 742,805

Unregulated Heating oil AST and UST 3,283,752

LPG/Propane Mostly AST 1,825,984

Kerosene Mostly AST 147,383

TOTAL 8,506,600

Table 1.28 Volume Capacity of Storage Tanks Under SPCC Regulation3

Used in Total Capacity, m3 x million)

Oil production 54.4

Petroleum refining and relatedindustries

288.3

Petroleum bulk stations and terminals 44.0

Gasoline service stations 37.0

Fuel oil storage 0.9

)Based on 1995 survey


Control (SPCC) or by the Office of Underground Storage Tanks (OUST). A total of 2.5 million tanksare regulated by SPCC, 0.75 million tanks are regulated by OUST, and 5.25 million tanks are non-regulated. Table 1.28 presents the volume capacity of the tanks regulated by SPCC. The averageannual cost of corrosion for storage tanks in USA is estimated at $7.0 billion.

1.7.5 Refinery sectorThe annual average cost of corrosion in refineries (see section 2.31) in the USA is estimated at $3.692billion. This cost includes $1.767 billion for maintenance, $1.425 billion for vessel turnaround, and$0.5 billion for cleaning.

1.7.6 Distribution sectorThere are approximately 95,000 miles of refined petroleum product pipeline (see section 2.32) in theUSA. These pipelines carry refined products from the refineries to consumer terminals (see section2.33) and to storage tanks.

The natural gas distribution systems connect transmission pipelines to city gates as well as citygates to customers (see section 2.34). In the USA, the gas distribution system consists of 2,785,000 km(1,730,000 mi) of relatively small diameter pipelines operating at relatively low pressure. They may be

Table 1.29 Leak Incidence by Cause for Distribution Pipelines3

Type ofDistributionLines

Number of Leaks

TotalLeaksCorrosion

ThirdParty

OutsideForce

ConstructionDefect

MaterialDefect Other

Mains 83,864 29,566 12,107 6,466 12,835 64,999 209,837

Services 99,024 95,555 21,814 20,965 32,356 138,267 407,981


broadly divided into 1,739,000 km (1,080,000 mi) of mainlines connecting transmission pipelines andcity gates and 1,046,000 km (650,000 mi) of service lines connecting city gates and customers. Theservice lines are connected to approximately 55 million customers. The diameters of distributionmainlines are typically between 40 mm and 150 mm (1.5 in and 6 in) and those of service lines aretypically between 13 mm to 20 mm (0.5 to 0.75 in). The distribution mainlines and service linesserving commercial and industrial establishments are typically larger in diameter than those servinghomes. In addition the natural gas may also be distributed using compressed natural gas (CNG)cylinders (see section 2.35).

The gas distribution pipelines operate at low pressures, and failures in these pipes result in leaksrather than the ruptures which may occur in high pressure natural gas transmission pipelines. Theprimary concern regarding the gas distribution pipeline is the accumulation of leaked gases in aconfined space, as these will eventually ignite and explode. Table 1.29 presents the causes of failures ingas lines. Corrosion causes approximately 40% of the leaks in mainlines and 24% of the leaks inservice lines. In terms of frequency, corrosion causes 8.4–12 leaks per 100 km (13.6–19.3 leaks per 100mi) in mainlines and 3.9–7.4 leaks per 1,000 services in the service lines. The average annual cost ofcorrosion in distribution pipelines is approximately $5.0 billion.

One data source shows that over a five year period in the USA, 83,864 corrosion leaks occurred indistribution mainlines and 99,024 leaks occurred in service lines. The majority of these leaks weredetected and repaired without major incident, but there were 26 major incidents resulting in 4 fatalitiesand 16 injuries. The cost of these major incidents was $4,923,000 in property damage. The cost ofrepairing minor leaks is typically between $1,200 and $2,500 per leak in distribution mainlines and$800 and $1,500 per leak in service lines. Table 1.30 presents another set of data obtained between1989 and 1998.

There is currently a tendency to replace metal distribution lines with plastic, but plastic pipes arealso susceptible to aging and degradation processes. There were 36,948 leaks in plastic (polyethylene)distribution mainlines and 134,448 leaks in plastic service lines within one year in the USA. In terms offailure frequency, there were 8.5 leaks per 100 km (13.7 leaks per 100 mi) in polyethylene mainlinesand 6.21 leaks per 1,000 polyethylene service lines. The leaks in plastic pipes are slightly smaller thanthose in metallic pipeline, but their frequency is still significant. Recent studies however have indicatedthat by improving durability of plastic materials and testing the materials under realistic operatingconditions, failure frequency of plastic pipeline may be reduced.

1.7.7 Special sectorThe oil and gas industry also operates pipelines for transporting special products. Some of thosespecial pipelines include diluent pipeline (see section 2.36), high vapor pressure pipeline (see section

Table 1.30 Gas Distribution Pipeline Accidents and Incidences in USA3

Accidents/Incidents Natural Gas Distribution

Number of major accidents) 900

Number of accidents/10,000 miles) 4

Number of injuries) 700

Number of fatalities) 162

Property damage ($M)) 140

Total accidents)) 708

Total accidents due to corrosion)) 26

Percent of accidents due to corrosion)) 3.7

Percent of accidents due to externalcorrosion))

84.6

Percent of accidents due to internalcorrosion))

3.8

Percent of non-corrosion accidents)) 11.6

)Based on data between 1989 and 1998 e this data does not distinguish the accidents/incidents caused by corrosion))Based on data between 1994 and 1999

References 37

2.37), CO2 pipeline (see section 2.38), hydrogen pipeline (see section 2.39), ammonia pipeline (seesection 2.40), and biofuel infrastructure (see section 2.41). In general, the operating conditions(pressure, temperature, flow conditions, and compositions of fluids) in these infrastructure systems aremore severe than those of traditional oil and gas pipelines. As a consequence, the corrosion cost ofoperating these infrastructures is anticipated to be higher. But this sector has only emerged recently,and its corrosion costs have not yet clearly been documented.

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4. Mohitpour M, Golshan H, Murray A. In: Pipeline Design and Construction: A Practical Approach. 3rd ed.Three Park Avenue, New York, 10016: The American Society of Mechanical Engineers; 2007. Table 3.1a,p. 66. ISBN: 0-7918-0257-4.

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References 39

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29. Utilities Board (ERCB) 91-G Report. Alberta Energy Regulator (AER), 250–5th Street SW, Calgary, Alberta,Canada, T2P 0R4 (Historical report) due to database merger in 2007 there was some correction in the lengthof the pipelines.

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