Pipeline_Rules_of_Thumb_Handbook_5E

Pipe Design 89

Properties of Pipe d W Ao Vm Af I Z

Dt 0.098516 4.12 1.83
0.095662 5.03 2.24
4.500 0.125 4.250 5.840 1.178097 92.644911 0.094206 5.49 2.44
0.156 4.188 7.240 1.734421 89.961575 0.092761 5.93 2.64
STD 0.172 4.156 7.950 2.258020 88.592057 0.089993 6.77 3.01
6.625 0.188 4.124 8.660 87.233042 0.088405 7.56 3.36
STD 0.219 4.062 10.010 2.814343 84.629845 0.087266 7.56 3.36
8.625 0.237 4.026 10.790 3.337942 83.136406
0.250 4.000 11.350 3.665191 82.066080 0.212985 19.7 6.0
STD 0.208779 22.6 6.8
10.750 0.188 6.249 12.93 200.292532 0.204616 25.5 7.7
STD 0.219 6.187 14.99 196.337808 0.200627 28.1 8.5
12.750 0.250 6.125 17.02 192.422518 0.196415 30.9 9.3
STD 0.280 6.065 18.98 188.671072 0.188254 36.1 10.9
14.000 0.312 6.001 21.04 184.710235
0.375 5.875 25.03 177.035128 0.371133 44.4 10.3
STD 0.365575 51.1 11.9
0.188 8.249 16.94 349.016785 0.360059 57.7 13.4
0.219 8.187 19.66 343.790038 0.355289 63.4 14.7
0.250 8.125 22.36 338.602723 0.349153 70.5 16.3
0.277 8.071 24.70 334.116868 0.347410 72.5 16.8
0.312 8.001 27.70 328.346391 0.343590 76.9 17.8
0.322 7.981 28.56 326.706916 0.338243 82.9 19.2
0.344 7.937 30.43 323.114514
0.375 7.875 33.05 318.086203 0.579980 87.0 16.2
0.573027 113.7 21.2
0.219 10.312 24.63 545.418061 0.566560 125.9 23.4
0.250 10.250 28.04 538.879221 0.560352 137.5 25.6
0.279 10.192 31.20 532.797939 0.547599 160.8 29.9
0.307 10.136 34.24 526.959102
0.365 10.020 40.49 514.966704 0.826770 169.3 26.6
0.818464 191.9 30.1
0.219 12.312 29.31 777.500935 0.810200 214.1 33.6
0.250 12.250 33.38 769.690071 0.801978 236.0 37.0
0.281 12.188 37.43 761.918639 0.785398 279.0 43.8
0.312 12.126 41.45 754.186639 0.768991 321.0 50.4
0.375 12.000 49.57 738.594720 0.753014 363.0 56.7
0.438 11.874 57.60 723.165661
0.500 11.750 65.42 708.140511 1.003171 226.0 32.3
0.994020 255.0 36.5
0.219 13.562 32.24 943.389822 0.984910 285.1 40.7
0.250 13.500 36.72 934.783943 0.975843 315.0 45.0
0.281 13.438 41.18 926.217495 0.966527 344.3 49.2
0.312 13.376 45.62 917.690481 0.957545 373.0 53.3
0.344 13.312 50.18 908.929763 0.939420 429.0 61.4
0.375 13.250 54.58 900.482886 0.921752 484.0 69.1
0.438 13.124 63.45 883.438151
0.500 13.000 72.10 866.822970

D = Outside diameter, in. I = Moment of Inertia, in.4
t = Wall thickness, in. Z = Section modulus, in.3
d = Inside diameter, in. Gals/ft. = d2 ¥ 0.0408
W = Pipe weight #/ft. Gals/mile = d2 ¥ 215.4240
Ao = Outside surface area sq. ft./ft. Bbls/mile = d2 ¥ 5.1291
Vm = Displacement, bbls/mile I = 0.0491 (D4 - d4)
Af = Flow area, sq. ft. Z = 0.0982 (D4 - d4)/D

90 Pipeline Rules of Thumb Handbook

D t d W Ao Vm Af I Z
16.000 4.188790
0.219 15.562 36.92 1242.151387 1.320864 338.0 42.3
STD 0.250 15.500 42.06 4.712389 1232.273483 1.310360 384.0 48.0
18.000 0.281 15.438 47.18 5.235988 1222.435011 1.299899 429.0 53.6
STD 0.312 15.376 52.28 6.283185 1212.635972 1.289479 474.0 59.3
20.000 0.344 15.312 57.53 6.806784 1202.562197 1.278766 519.0 64.8
STD 0.375 15.250 62.59 7.853982 1192.843296 1.268432 562.0 70.3
24.000 0.438 15.124 72.81 8.377580 1173.213479 1.247558 649.0 81.1
STD 0.500 15.000 82.78 1154.054250 1.227185 732.0 91.5
26.000
STD 0.250 17.500 47.40 1570.796063 1.670335 549.0 61.0
30.000 0.281 17.438 53.18 1559.685567 1.658520 614.2 68.2
STD 0.312 17.376 58.95 1548.614504 1.646747 679.0 75.5
32.000 0.344 17.312 64.88 1537.227671 1.634639 744.0 82.7
STD 0.375 17.250 70.60 1526.236746 1.622952 807.0 89.6
0.438 17.124 82.16 1504.021848 1.599329 932.0 103.6
0.500 17.000 93.46 1482.318570 1.576250 1053.0 117.0

0.250 19.500 52.74 1950.351683 2.073942 756.6 75.7
0.281 19.438 59.19 1937.969163 2.060775 846.5 84.6
0.312 19.376 65.61 1925.626075 2.047650 935.5 93.5
0.344 19.312 72.22 1912.926185 2.034145 1026.5 102.6
0.375 19.250 78.61 1900.663236 2.021105 1113.8 111.4
0.438 19.124 91.52 1875.863256 1.994733 1288.6 128.9
0.500 19.000 104.14 1851.615930 1.968950 1457.2 145.7

0.250 23.500 63.42 2832.562043 3.012056 1315.7 109.6
0.281 23.438 71.19 2817.635474 2.996184 1473.1 122.8
0.312 23.376 78.94 2802.748338 2.980354 1629.2 135.8
0.344 23.312 86.92 2787.422334 2.964056 1789.1 149.1
0.375 23.250 94.63 2772.615336 2.948311 1942.8 161.9
0.438 23.124 110.23 2742.645193 2.916442 2251.3 187.6
0.500 23.000 125.51 2713.309770 2.885247 2550.0 212.5

0.250 25.500 68.76 3335.216783 3.546564 1676.8 129.0
0.281 25.438 77.20 3319.018190 3.529339 1878.0 144.5
0.312 25.376 85.61 3302.859030 3.512155 2077.7 159.8
0.344 25.312 94.27 3286.219968 3.494462 2282.3 175.6
0.375 25.250 102.64 3270.140946 3.477364 2479.1 190.7
0.438 25.124 119.59 3237.585722 3.442746 2874.5 221.1
0.500 25.000 136.19 3205.706250 3.408846 3257.8 250.6

0.250 29.500 79.44 4463.625383 4.746477 2585.8 172.4
0.281 29.438 89.20 4444.882741 4.726547 2897.5 193.2
0.312 29.376 98.94 4426.179533 4.706659 3207.1 213.8
0.344 29.312 108.97 4406.914357 4.686173 3524.7 235.0
0.375 29.250 118.66 4388.291286 4.666370 3830.4 255.4
0.438 29.124 138.30 4350.565898 4.626254 4445.7 296.4
0.500 29.000 157.55 4313.598330 4.586943 5043.5 336.2

0.250 31.500 84.78 5089.379243 5.411884 3143.2 196.4
0.281 31.438 95.20 5069.364577 5.390601 3522.7 220.2
0.312 31.376 105.60 5049.389344 5.369360 3899.9 243.7
0.344 31.312 116.32 5028.811111 5.347478 4287.0 267.9
0.375 31.250 126.67 5008.916016 5.326322 4659.7 291.2
0.438 31.124 147.66 4968.605547 5.283457 5410.3 338.1
0.500 31.000 168.23 4929.093930 5.241442 6140.2 383.8

Pipe Design 91

Length of pipe in bends

Calculation of pipe bends

Reprinted with permission—Crane Company

Calculation of pipe bends

Reprinted with permission—Crane Company

94 Pipeline Rules of Thumb Handbook

Spacing of pipe supports

For chart on deflection of horizontal pipe lines, see next page

When a horizontal pipeline is supported at intermediate Example: What is the maximum distance between sup-
points, sagging of the pipe occurs between these supports, the ports for a 4≤ Standard pipeline assuming a pitch or average
amount of sag being dependent upon the weight of the pipe, gradient of 1≤ in 30 feet?
fluid, insulation, and valves or fittings which may be included
in the line. If the pipeline is installed with no downward pitch, Using the chart on the opposite page, find the point where
pockets will be formed in each span in which case condensa- the diagonal dotted line for an average gradient of 1≤ in
tion may collect if the line is transporting steam. In order to 30 feet intersects the diagonal solid line for 4≤ pipe. From
eliminate these pockets, the line must be pitched downward this point, proceed downward to the bottom line where the
so that the outlet of each span is lower than the maximum sag. maximum span is noted to be approximately 22 feet.

Crane has conducted tests to determine the deflection of Code for Pressure Piping: The Code for Pressure
horizontal standard pipelines filled with water, in pipe sizes Piping, ASA B 31.1, makes the following statements relative
3/4≤ to 4≤ inclusive, the results of which have indicated that for to installations within the scope of the Code:
pipes larger than 2≤ and with supports having center to center
dimensions greater than 10 feet, the resultant deflection is “605 (g) Supports shall be spaced so as to prevent excessive
less than that determined by the use of the formula for a uni- sag, bending and shear stresses in the piping, with special
formly loaded pipe fixed at both ends. For pipe sizes 2≤ and consideration given to those piping sections where flanges,
smaller, the test deflection was in excess of that determined valves, etc., impose concentrated loads. Where calculations
by the formula for pipe having fixed ends and approached, for are not made, suggested maximum spacing of hangers
the shorter spans, the deflection as determined by the use of or supports for carbon steel piping operating at 750° F
the formula for pipelines having unrestrained ends. and lower are given in Table 21a (see the table below).
“Where greater distance between supports, concentrated
Page 96 gives the deflection of horizontal standard pipe- loads, higher temperatures, or vibration considerations are
lines filled with water, for varying spans, based upon the involved, special consideration should be given to effects of
results obtained from tests for sizes 2≤ and smaller, and upon bending and shear stresses.”
the formula for fixed ends for the larger sizes of pipe. The
deflection values given on the chart are twice those obtained “623 (b) The design and spacing of supports shall be checked
from test or calculation, to compensate for any variables to assure that the sum of the longitudinal stresses due to
including weight of insulation, etc. weight, pressure, and other sustained external loading
does not exceed the allowable stress (S value) in the hot
The formula given below indicates the vertical distance that condition.”
the span must be pitched so that the outlet is lower than the
maximum sag of the pipe. Suggested Maximum Spacing Between Pipe Supports For
Straight Runs of Standard Wall and Heavier Pipe (At
h = 144S2 y Maximum Operating Temperature of 750 F)
36S2 - y2

where: Nominal Maximum Nominal Maximum
h = Difference in elevation of span ends, inches Pipe Size Span Pipe Size Span
S = Length of one span, feet Inches Feet Feet
y = Deflection of one span, inches Inches

By eliminating the inconsequential term “-y2” from the 1 7 8 19
denominator, the formula reduces to:
11/2 9 10 22

2 10 12 23

h = 4y 21/2 11 14 25
3 12 16 27

The pitch of pipe spans, called the Average Gradient, is a ratio 31/2 13 18 28
between the drop in elevation and the length of the span. This
is expressed as so many inches in a certain number of feet. 4 14 20 30

5 16 24 32

6 17 .. ..

Average Gradient = 4y Notes: The values in the table do not apply where there are concen-
S trated loads between supports such as flanges, valves, etc.

The dotted lines as shown on the chart on the opposite page Spacing is based on a combined bending and shear stress of
are plotted from the above formula and indicate average gra- 1500 psi when pipe is filled with water and the pitch of the line
dients of 1≤ in 10¢, 1≤ in 15¢, 1≤ in 20¢, 1≤ in 30¢, and 1≤ in 40¢. is such that a sag of 0.1 inch between supports is permissible.

Reprinted with permission—Crane Company

Spacing of pipe supports

Reprinted with permission—Crane Company

96 Pipeline Rules of Thumb Handbook

American standard taper pipe threads (NPT)

Reprinted with permission—Crane Company

Pipe Design 97

British standard taper pipe threads

Reprinted with permission—Crane Company

98 Pipeline Rules of Thumb Handbook

Normal engagement between male and female threads to make tight joints

Normal engagement Dimensions, in Inches
Dimensions given do not allow for variations in
The normal amount of engagement to make a tight joint
for various types of screwed material is given in the table. tapping or threading
These dimensions have been established from tests made
under practical working conditions. Size A Size A

The normal engagement specified for American Standard 1/8 1/4 2 1/2 15/16
Pipe Thread and API Line Pipe Thread joints is based on 1/4 3/8 3 1
parts being threaded to the American Standard for Pipe 3/8 3/8 3 1/2 1 1/16
Threads or the API Standard for Line Pipe Threads. 1/2 1/2 4 1 1/8
3/4 9/16 5 1 1/4
In order to obtain the thread engagements listed in the 1 11/16 6 1 5/16
table it is necessary to vary the torque or power applied 1 1/4 11/16 8 1 7/16
according to the size, metal and weight of material used. For 1 1/2 11/16 10 1 5/8
example, it requires considerably less power to make up a 2 3/4 12 1 3/4
screwed joint using a light bronze valve than a high pressure
steel valve.

Reprinted with permission—Crane Company

Hand-held computer calculates pipe weight, contents, velocity

Programs, written for the HP 41 CV computer equipped with printer, work with English or metric units
Frank E. Hangs, P. E., Sovereign Engineering, Inc., Houston

Pipeline engineers, accountants, and system operators are A printer is essential.
deeply involved with data concerning line pipe such as:
Results for the WEIGHT category are calculated by an API
How much does it weigh (lb/ft, tons/mi)? What are the formula and given as: Pounds (mass) per ft; kg per m. Short
corresponding metric units? tons (2,000 lb) per mile; metric tons per km.

How much will it contain (bbl/mi, gal/100 ft, cu m/km)? The content results are: bbl/mi, gal (U.S.)/100 ft, cu ft/mi,
What are velocities at various feed rates (ft/sec, mi/hr, L/m, cu m/km.
m/hr)?
The following program, written for the Hewlett Packard Flowrates can be input to give: b/h or b/d; gal
HP 41 CV hand-held computer, develops a lot of useful data (U.S.)/min; or gal/hr or gal/d; cu ft/min, /hr, /d; cu m/min,
for steel pipe for any outside diameter and wall thickness. /hr, /d.
Either English or metric units may be entered.
Velocity results: mph; fps; km/hr; m/sec.

Pipe Design 99
Figure 1. Examples of the program printed by the HP 41 CV printer.

100 Pipeline Rules of Thumb Handbook

All results, as well as the input, are printed out, so the tape 21 M/S—m per sec
becomes a permanent record. 22 FT3/MI—cu ft per mi

A good feature of the program is that, for a given size 23 KG/M—kg per m
pipe (after executing PWCV and A, content routine, to
store data concerning that particular size pipe), velocity LABEL PWCV Calls up program
routine, B, can be run as often as wanted. Press B, then LABEL A Calls content calculations
key in desired flowrate after the prompt, then press the RUN LABEL B Calls for feed rate and velocity
key. calculations

When a different size pipe is needed: XEQ PWCV, press Note. A and B are XEQ in user mode.
A, then B, as often as needed for different flowrates. Numeric labels 01 to 06 are used in the program to
provide necessary GTO directions. They are not stand-alone
Basic data calculated by this program can be used for deter- routines.
mining the following criteria:
User directions. Size 25. Set user mode. Input program.
• Weight: Cost of construction, hauling and stringing, If it is desired to use units as prompted, key in value and run
key. If metric units are wanted, key in 0 for English units then
investments. run key.

• Content: Amount of water for hydrostatic test, line Example. Display: Pipe OD in.? Key in 0, press run key,
see pipe OD MM? Key in value and run key. See pipe T MM?
fill, oil stocks. Amount of one grade to be displaced for
another to reach a station, shut-off valve, or terminal. After weights are calculated: If content is wanted, XEQ
When a segment must be drained, barrels or gallons to “A.” Calculations can be terminated at this point.
be removed.
When velocities are desired, XEQ “B” input feed rate in
• Velocity: Time for interface or scraper to traverse desired units. Label “B” can be run for several feed rates as
often as desired for the given size pipe. If other pipe sizes are
distance between two points. Time to accumulate or needed, XEQ PWCV and “A,” then run “B” as many times as
withdraw a given quantity of fluid. Locating head needed for different feed rates.
of column of a grade of oil or a scraper from given
station after a certain time. Determining expected Note. If feed rates other than BBL/HR are to be input,
time of arrival (ETA) of interface or scraper at a given first key in 0 and run. This causes display to move up. See
point. GPM? No. Gallons? Key in 0 and run key. See FT3/MIN?
Continue to M3/HR? If you have this figure, key it in and run.
Register List of registers and legend Now suppose you have M3/DAY. This does not agree with
00 prompt; enter M3/DAY, divide by 24, then press run key. This
01 Content routine can be used for BBL/DAY, GAL/HR (divided by 60),
02 Not used FT3/DAY (divide by 24), etc.
03 Pipe OD in.
04 Pipe OD mm Note. When results such as OD, ID, T Values, Weight
05 Pipe T in. KG/M are compared with printed values in API STD 5L,
06 Pipe T mm small discrepancies are sometimes found, usually on the order
07 Pipe ID in. of 0.1% or less. This is evidently due to truncation differences
08 Pipe ID mm in making conversions.
09 LBM/FT—lb(mass)/ft
10 ST/MI—short tons/mi Formulas
11 MT/KM—metric tons/km
12 BBL/MI—bbl(42 U.S. gal) per mi Pipe weight LBM/FT (plain end) is calculated by formula
13 GAL/100 FT—gal (U.S.) per 100 ft used by API:
14 L/M—liters per m
15 M3/KM—cu m per km LBM FT = 10.68(D - T)T
16 BBL/HR—bbl (42 U.S. gal) per hr
17 GPM—gal (U.S.) per minute
18 FT3/MIN—cu ft per min
19 M3/HR—cu m per hr
20 MI/HR—mi (statute) per hr
KM/HR—km per hr
FT/S—ft per sec

Pipe Design 101

Weights in other units are found by multiplying by conver- 55.35 ¥ 1.609 = 89.058km
sion factors:
3. How many bbl are in (a) 150 ft? (b) gal? (c) cu ft?
BBL MI = 5.129131(D - 2T)2
a. 150/5,280 ¥ 738.595 = 20.983 bbl
Basic velocity relation: b. 150/100 ¥ 587.519 = 881.279 gal
c. 150/5,280 ¥ 4,146.902 = 117.810 cu ft
BBL ∏ BBL = MI
HR MI HR 4. Suppose, in an emergency, you have to dig a pit to hold
oil from 150 m of this 12-in. line. Volume? (a) cu m (b)
This is converted to other units. cu ft

Example 1. Size 25, Fix 3, Set user mode. Put PWCV in a. 150/1,000 ¥ 72.966 = 10.945 cu m
calculator. XEQ PWCV. Input 12.75 in. Press run key. See b. 10.945 ¥ 34.315 = 386.519 cu ft
Pipe T in.? Input 0.375. Press run key. After calculator stops,
press “A” for content. If velocities are desired, press “B.” 5. How long will it take a scraper to traverse 67.85 mi of
Input 4,000 BBL/HR. Press run key. Results are printed. this 12-in. line at 4,000 bbl/hr?

Now “B” can be run as often as needed. 67.85/5.351 = 12.680 hrs Hours min. sec? Fix 4.
Change feed rate units. Note zeros were put in for three
feed rates, and 635.948 M3/HR input was keyed in. This is to XEQ Alpha HMS Alpha = 12 HR 40 MIN 48 SEC
demonstrate how other feed rates are input and the accuracy
of the conversions (6 decimals). Put in feed rate 96,000 BPD. Useful conversions
Enter, divide by 24, press run key.
Meters ¥ 3.281 = feet
Example 2. This shows how to input OD and T in MM. Miles ¥ 1.609 = kilometers
Key in 0 for pipe OD IN.? Then press run key. See Pipe OD Cubic ft ¥ 7.481 = gallon (U.S.)
MM? Key in metric units. Results are calculated and printed. Kilogram ¥ 2.205 = pounds
Cubic meters ¥ 35.315 = cubic feet
Questions and answers Cubic meters ¥ 6.290 = barrels
Cubic meters ¥ 264.172 = gallons (U.S.)
1. How many short tons are in a 55.35-mi segment of Barrels ¥ 5.615 = cubic feet
12.75 in. ¥ 0.375 in. WT? (Use data from Ex. 1.) Barrels ¥ 42.00 = gallons (U.S.)
Barrels ¥ 35.00 = Imperial gallons

55.35 ¥ 130.843 = 7,242.160ST Source

2. How many km are in this segment above? Pipe Line Industry, May 1986.

Formulas and constants of value in solving problems relating to tubular goods

Area of Metal in Tubular Section: where B100 = Barrels per 100 ft
Area in square inches = 3.1416(D - t)t A = Internal area of pipe, in.2
where D = Outside diameter, in.
D = Internal diameter, in.
t = Wall thickness, in.
and FB = 808.5 = 1, 029.4
Capacity A D2
B100 = .1237A = .0972D2
where FB = Number of feet filled by one barrel
A = Internal area of pipe, in.2

D = Internal diameter, in.

102 Pipeline Rules of Thumb Handbook

Complete tables giving capacities of different types of tubular Lt = Lo(1 + .0000069 t)
goods are given in chapters dealing with these types.
where Lo = Length at atmospheric temperature
Steel constants* (applicable to tubular goods)
Lt = Length after change of temperature t
One cubic inch = 0.2833 lb
One cubic foot = 489.542 lb ( )Modulus: Section Modulusp
Specific gravity = 7.851 64 D4 - D14

Approximate coefficient of expansion for commercial casing, ( )Polar Modulus p
drill pipe, and tubing is 32 D4 - D14
Coefficient = 6.9 ¥ 10-6 per ° F, over range from 0 to 400° F
where D = Outside diameter
Formula for expansion of pipe due to change of temperature
is as follows: D1 = Inside diameter
p = 3.1416
* Engineering data Spang-Chalfant Division of the National Supply Co.
Relation between twisting effort, torsional strain and stress of
cylindrical shaft or tube

q = T = Cq
rJ L

How to calculate the contraction or expansion of a pipeline

Steel pipe contracts or expands approximately 0.8 inch per = 0.8 ¥ 10 ¥ 1
100° F temperature change for each 100 feet of pipe. For con- = 8 inches
struction in the U.S., slack is not normally needed in welded
lines for contraction or expansion unless abnormal variations Large temperature changes may arise on exposed line or in
are encountered. However, slack is often provided near road lines downstream from compressor stations.
crossings where the pipe may have to be lowered at some
future time. When slack is desired in a line, the amount of sag or rise
needed may be estimated quickly. To provide for 0.8 inch of
Contraction = 0.8 ¥ movement longitudinally along the pipe, a sag of 21 inches
would be needed in a 100-foot loop. For a 150-foot loop, 31
length of pipe (feet) ¥ temp. change (∞ F ) inches are necessary. Such slack put into the line at time of
construction might allow for lowering the pipe under road-
100 100 beds without putting excessive stress upon the pipe.

Example. Calculate the amount a 1,000-foot section of Location of overbends, sags, and side bends should be con-
pipeline would contract if laid at a temperature of 100° F and sidered when laying slack loops. When loops are placed, parts
cooled to a low of 0° F during winter operation. (Assuming of the line should be backfilled to serve as a tie-down. Loops
the line were free of soil or other resisting loads.) should be lowered during the coolest part of the day when
the line is the shortest. After lowering in, sags should rest on
Contraction = 0.8 ¥ 1, 000 ¥ 100 the bottom of the ditch; overbends should “ride high.” Side
100 100 bends should rest on the bottom of the ditch and against the
outside wall. The line should be lowered so that all sections
of the pipe are in compression.

Estimate weight of pipe in metric tons per kilometer

To estimate the weight of pipe in metric tons per kilo- Actual answer from pipe tables is 79 metric tons per
meter, multiply the nominal diameter by the number of six- kilometer.
teenths of an inch in wall thickness.
This rule of thumb is based on a density of 490 pounds per
Example. Find the weight of pipe in metric tons per kilo- cubic foot for steel. For larger diameter thin wall pipe, this
meter for 20-inch diameter pipe, wall thickness 1/4 -inch. approximation gives an answer usually about one percent low.
The accompanying table gives a comparison between actual
4 ¥ 20 = 80 tons (metric) per kilometer weights in metric tons per kilometer, as compared to that
calculated by this rule of thumb.

PIPE WALL ACTUAL Pipe Design 103
DIAMETER TONS (METRIC)
THICKNESS R. O. T.
10-inch 31.5 TONS (METRIC)
12-inch 3/16 -inch 62
16-inch 5/16 -inch 109 30
20-inch 7/16 -inch 79 60
20-inch 1/4 -inch 99 112
20-inch 5/16 -inch 137 80
24-inch 7/16 -inch 118 100
24-inch 5/16 -inch 189 140
28-inch 8/16 -inch 139 120
30-inch 5/16 -inch 148 192
32-inch 5/16 -inch 221 140
36-inch 7/16 -inch 143 150
36-inch 4/16 -inch 285 224
8/16 -inch 144
288

How to find pipe weight from outside diameter and wall thickness

Weight (pounds per foot) = (Dt - t2 ¥ 10.68) W = (4.5 ¥ .25 - .252 ) ¥ 10.68
= (1.125 - .0625) ¥ 10.68
where D = outside diameter, in.
t = wall thickness, in. = 1.0625 ¥ 10.68
= 11.35 pounds per foot
Example. Outside diameter = 4.500≤, thickness =
0.250≤ The above equation is based on a density of 490 pounds
per cubic foot for the steel. High-yield-point, thin-wall pipe
may run slightly heavier than indicated.

What is the maximum allowable length of unsupported line pipe?

For Schedule 40 pipe, the maximum span between sup- Example. How wide a ditch can be spanned with four-inch
ports is given by line pipe without the use of intermediate supports?

S = 6.6 P S = 6.6 4.5 = 6.6 ¥ 2.12 = 13.99 (14 feet)

where S is the span length in feet and P is the actual outside S = 7 4 = 7 ¥ 2 = 14 feet
diameter of the pipe in inches. For pipe smaller than 12-inch,
the nominal size may be used, and Note. The above rule is approximate, but conservative. It
does not assume that the pipe is held fixed at either end; this
S=7 N condition can make longer spans safe. Also, it does not guar-
antee that the pipe will not be damaged by floating logs or
debris! This hazard must be evaluated from the conditions
encountered.

Identify the schedule number of pipe by direct measurement

Add three inches to the actual inside diameter; divide this Schedule 120 13 to 15
by the wall thickness; the schedule number can then be iden- Schedule 140 11 to 13
tified by the following table: Schedule 160 9 to 11

Schedule 30 40 to 50 Example. Pipe measures 12.5 inches inside diameter, wall
Schedule 40 29 to 39 thickness .75 inch; 15.5/.75 = 20.2; pipe is Schedule 80, 14
Schedule 60 25 to 29 inches outside diameter.
Schedule 80 20 to 23
Schedule 100 16 to 18 The rule fails on small diameter pipe (under 6 inches), and
also on schedules 10 and 20, because of the use of “standard”
thicknesses in this range.

104 Pipeline Rules of Thumb Handbook

Determine buoyancy of bare steel pipe

Multiply the square of the outside diameter of the pipe, in = 162.56 ¥ 0.341 - 33.4
inches, by 0.341, and subtract the pipe weight in lb/ft; the = 55.4 - 33.4 = 22 lb/ft
answer is the buoyancy per foot in fresh water.
Since all of the coating materials in common use are
Example. 12≤ (12.75≤ OD) 33.4 lb pipe (1/4≤ wall). heavier than water (but not as much so as steel), coated pipe
will have less buoyancy than indicated by the rule. For sea
Buoyancy = 12.752 ¥ 0.341 - 33.4 water, use 0.350 for the constant.

Determine buoyancy of bare and concrete coated steel pipe in water and mud

To find the buoyancy of bare steel and concrete coated pipe
in water in lb/ft:

Buoyancy (B) = D (D - 32t) + 11t2
3

for bare pipe, and

B = D (D - 32t) + t1D 63 - Wc
3 48

for coated pipe

where D = outside diameter of pipe, in.

t = wall thickness of pipe, in.

t1 = thickness of concrete coating, in.
Wc = weight of concrete, lb/ft3

To find the buoyancy of bare steel and coated pipe in mud To give this pipe a negative buoyancy of 100 lb/ft:
in lb/ft:
20 [20 - 32(1 2)] + t1(20)ÊË 63 - 143ˆ
-100 = 48 ¯
3
(B) 10.7ÊË DWm tˆ¯ 11t2
Buoyancy = 2, 000 - + -100 = 26.7 - 33.3t1

t1 = 3.8 in. of concrete coating.

for bare pipe, and

B = 10.7ÊË DWm - tˆ¯ + t1DËÊ Wm - Wc ˆ The error introduced by this method is about 15% but
2, 000 48 ¯ would be less as the thickness of coating decreased.

for coated pipe, where Wm is weight of mud, lb/ft3. Example 2. Bottom conditions at a certain crossing that
require the pipe to have a negative buoyancy of at least
Example 1. Find the buoyancy of steel pipe with 20-inch 50 lb/ft. Let’s check to see if a 10-inch pipe having a 2-inch
OD and 1/2-inch wall thickness in water. What thickness of coating of concrete (Wc = 143) has sufficient negative
concrete coating would be required to give this pipe a nega- buoyancy.
tive buoyancy of 100 lb/ft (Wc = 143)?
B = 10 (10 - 32(1 2)) + 2(10)ËÊ 63 - 143ˆ
(B) = 20 [20 - 32(1 2)] +11(1 2)2 3 48 ¯

3 B = -20 - 33.3 = -53.3 lb/ft; so coated pipe meets design
= 26.7 + 2.8 = 29.5lb ft positive buoyancy. requirements.

Pipe Design 105

Weights of piping materials

The weight per foot of steel pipe is subject to the follow- where G = Specific gravity of contents
ing tolerances: T = Tube wall thickness, in.
D = Tube outside diameter, in.
SPECIFICATION TOLERANCE
The weight of welding tees and laterals is for full size fit-
͖A.S.T.M. A-53 STD WT +5%, -5% tings. The weight of reducing fittings is approximately the
XS WT +5%, -5% same as for full size fittings.
A.S.T.M. A-120 XXS WT +10%, -10%
The weight of welding reducers is for one size reduction,
A.S.T.M. A-106 SCH 10–120 +6.5%, -3.5% and is approximately correct for other reductions.
SCH 140–160 +10%, -3.5%
Pipe covering temperature ranges are intended as a guide
͖A.S.T.M. A-158 12≤ and under +6.5%, -3.5% only and do not constitute a recommendation for specific
over 12≤ +10%, -5% thickness of material.
A.S.T.M. A-206
A.S.T.M. A-280 Pipe covering thicknesses and weights indicate average
conditions and include all allowance for wire, cement, canvas,
API 5L All sizes +65%, -3.5% bands, and paint. The listed thicknesses of combination cov-
ering is the sum of the inner and the outer layer thickness.
Weight of Tube = F ¥ 10.6802 ¥ T ¥ (D - T) lb/ft When specific inner and outer layer thicknesses are known,
add them, and use the weight for the nearest tabulated
where T = wall thickness, in. thickness.
D = outside diameter, in.
F = relative weight factor To find the weight of covering on fittings, valves, or flanges,
multiply the weight factor (light faced subscript) by the
The weight of tube furnished in these piping data is based weight per foot of covering used on straight pipe. All flange
on low carbon steel weighing 0.2833 lb/in.3 weights include the proportional weight of bolts or studs
required to make up all joints.
Relative weight factor F of various metals
Lap joint flange weights include the weight of the lap.
Aluminum = 0.35 Welding neck flange weights are compensated to allow for
the weight of pipe displaced by the flange. Pipe should be
Brass = 1.12 measured from the face of the flange.
All flanged fitting weights include the proportional weight
Cast Iron = 0.91 of bolts or studs required to make up all joints.
To find the approximate weight of reducing-flanged fittings,
Copper = 1.14 subtract the weight of a full size slip-on flange and add the
weight of reduced size slip-on flange.
Lead = 1.44 Weights of valves of the same type may vary because of
individual Manufacturer’s design. Listed valve weights are
Ferritic Stainless Steel = 0.95 approximate only. When it is possible to obtain specific
weights from the Manufacturer, such weights should be
Austenitic Stainless Steel = 1.02 used.
To obtain the approximate weight of flanged end steel
Steel = 1.00 valves, add the weight of two slip-on flanges of the same size
and series to the weight of the corresponding welding-end
Tin = 0.93 valves.

Wrought Iron = 0.98

Weight of contents of a tube = G ¥ 0.3405 ¥ (D - 2T)2 lb/ft

Allowable working pressure for carbon steel pipe

Based on formula No. 7 of the ASA Code for Pressure The formula is:
Piping, Section 3B, this table was computed for 65/8-inch OD
to 36-inch OD carbon steel seamless pipe, API Specifications t = PD + u + c

5L Grade A, 5L Grade B, and API 5LX Grade X-42. 2(S + YP)

106 Pipeline Rules of Thumb Handbook

where t = wall thickness, in. Substituting in formula and solving for P:
P = allowable working pressure, psi
D = outside diameter, in. P = 1.75S(t - 0.057)
S = allowable stress, psi
Y = a coefficient D + 0.04 - 0.7t
u = under-thickness tolerance, in.
c = allowance for threading, mechanical strength, and The S-values are:
corrosion, in.
Spec. API 5L Grade A—25,500 psi
In calculation of the tables, the values of Y, u, and Spec. API 5L Grade B—29,750 psi
c were: Spec. API 5LX Grade X-42—35,700 psi

Y = 0.4 Example. Find pipe specification for a 12-inch line oper-
ating at 1,078 psi: In the 123/4-inch column these conditions
u = 0.125t (u = 12 1 2% of t) will be met using Grade X-42 pipe with 0.281-inch wall thick-
ness, Grade B pipe with 0.330-inch wall thickness, or Grade
c = 0.050-inches A pipe with 0.375-inch wall thickness.

Find the stress in pipe wall due to internal pressure

Multiply 1/2 by diameter by pressure and divide by wall 1 2 ¥ 24 ¥ 800 ∏ 1 4 = 38,400 psi
thickness to get stress in psi.
What wall thickness should be specified for a 30-inch dis-
Example. Find the wall stress due to internal pressure in charge line where pressure runs 1,000 psi and wall stress is to
a 24-inch pipeline having a 1/4-inch wall thickness if the pres- be limited to 30,000 psi?
sure gauge reads 800 psi:

Pipe Design 107

1 2 ¥ 30 ¥ 1,000 ∏ thickness = 30,000 inside diameter of the pipe in calculating this stress. This gives
Wall thickness = 1 2inch. a slightly lower figure for the transverse tensile stress and
consequently gives less safety factor. The method used here
This method of calculating transverse tensile stress due to is based on the assumption that maximum stress occurs at
internal pressure on the pipe is the Barlow formula. Actually, outside diameter of the pipe. The results give a conservative
there are two accepted variations, and some designers use value for safety factor calculations.

How to calculate stress in above/below ground transition

Design of gas gathering/gas reinjection project in southern Iran provides solutions for deflection and
anchor block forces in long underground lines

P. J. Schnackenberg, Design Engineer, Iran-Texas Engineering Co., Tehran, Iran

Stresses and deflections occur in pipelines at the transition Figure 1. Area A–B depicts transition from fully restrained (left)
from the below ground (fully restrained) to the above ground to fully unrestrained (right).
(unrestrained) condition.

Analysis of the stresses and deflections in transition areas,
resulting from internal pressure/temperature change, is nec-
essary in determining anchor block requirements and design.
Longitudinal deflections are used to determine whether an
anchor block is required. Anchor block forces required to
maintain the pipe in a fully constrained condition are then
determined.

Iran-Texas Engineering Co. recently completed an analysis
for a gas gathering/compression/reinjection project in south-
ern Iran under contract to Oil Service Co. of Iran (OSCO).
Each of the two fields, Bibi-Hakimeh and Rag-E-Safid have
two gas/oil separation plants, and at present the gas is being
flared. The broad scope of the project is as follows:

• Provision of gas gathering lines from existing and new Figure 2. Transition of stress and strain between points A and
B varies as linear function of length.
wellhead separation to a production unit

• Design of four production units (each adjacent to the

GOSP) comprising knockout facilities, compressor sta-

tions, and dehydration plant

• Provision of transfer pipelines to send gas plus conden-

sate as a two-phase flow to a natural gas liquid separation

plant (under design by Foster Wheeler)

• Provision of reinjection system to inject lean gas back into

a number of wells

• Some 9.4 MM m3/d (330 MM scfd) of gas plus 15,000 bpd

condensate will be going to the NGL plant. LPG will be

used as feedstock and for export.

Following is a brief review of the analysis that resulted in
more accurate solutions for deflection and anchor block
forces. Sample calculations are for line sizes up to 41-cm (16-
in.) CD, pressure to 193 bars (2,800 psig) and temperatures
to 72°C (162°F).

Case I—no anchor. Considering the pipeline as shown Figure 3. Distribution of stress where anchor is required to
in Figure 1, the section up to point A is fully restrained, the contain longitudinal deflections.

108 Pipeline Rules of Thumb Handbook

In a section of unrestrained pipe at B, the longitudinal
stress caused by only internal pressure will be half the hoop
stress.

s LB = sH psi (3)
2

The associated strain will be made up of a

(i) Temperature effect

eTE = a DT
(ii) Pressure effect

e PR = s LB = sH
E 2E
Figure 4. Sectional plan for anchor block design.

(iii) Poisson effect

e PO = us H
E

The net longitudinal strain at Point B will therefore be

eB = aDT + sH (1 2 -u)in. in. (4)
E
Figure 5. Sectional elevation for anchor block design.

section A–B is a transition from fully restrained to The transition of stress and strain between points A and B
unrestrained and beyond point B is unrestrained. (Fully is assumed to vary as a linear function of length as shown in
restrained is taken to be a condition of zero longitudinal Figure 2.
strain.)
In order to establish the length L over which the transition
Analyzing a short section of fully restrained pipe, subject to occurs, the longitudinal resistance of the soil needs to be
internal pressure and a temperature change, there is a tensile known. For this part, it is assumed that any tendency to
stress due to a Poisson effect of move will be counteracted by constant and opposite soil
force. Wilbur1 has recommended a design value for average
soils of

s PO = us H where s H = PDi Fs = 80ÊË Do ˆ2 lbf . ft (5)
2t 12 ¯

and a compressive stress due to a temperature change of Between A and B equilibrium of forces exists and
therefore,

s TE = Ea DT FsL = Am (s LB - s LA )
The net longitudinal stress therefore at Point A will be
From which

s LA = us H - Ea DTpsi (1) L = Am (s LB - s LA ) ft

and the strain at point A, being fully restrained, will be Fs (6)
zero

eA = 0 (2) Total movement at B will be average strain between A and
B over length L or

Pipe Design 109

Table 1
Summary of results for high pressure gas transmission lines under design in Iran

d = eB (12 L)in. (7) values of lateral soil bearing pressure with due consideration
2 to possible slip have been used.

Cell II—with anchor. Where an anchor is required to For large blocks, friction between the block and the soil
contain longitudinal deflections, the stress distribution will may also be figured in obtaining its resistance to imposed
be as shown in Figure 3. The transition from being fully forces. The block should be reinforced concrete cast against
restrained to unrestrained will occur at the anchor. Resultant undisturbed soil. Figures 4 and 5 indicate in broad detail the
force on the anchor will simply be the difference in stress anchor block design.
on each side times the pipe metal area (equilibrium of forces)
or Care should also be taken to ensure that connected surface
piping has sufficient flexibility to absorb a degree of lateral
F = (s LB - s LA )Amlb (8) anchor movement. Scraper traps should be installed such
that they can move with the piping rather than being rigidly
Note that for the case of an increase in wall thickness at attached to blocks. Numerous examples of traps together
and beyond the anchor block, the result will be essentially with their support blocks being displaced a few inches are not
the same—the decrease in stress being compensated by an uncommon.
increase in pipe metal area.
References
It can be shown that this force is equal to that to produce
a deflection of 2d in Equation 7 over length L. 1. Wilbur, W. E., Pipe Line Industry, February 1963.
2. Timoshenko, S., Theory of Elasticity.
Table 1 is a summary of results for a number of high pres-
sure gas transmission lines currently under design in Iran. Nomenclature
Lines 1 through 4 are transfer lines from a number of pro-
duction units to an NGL separation plant. Lines 5 through 7 Am Pipe metal area = p(Do = t)t, sq. in.
are injection lines from the NGL separation plant to a number Do Pipe outside diameter, in.
of wellheads. The following values were used for the various Di Pipe inside diameter, in.
parameters:
t Pipe wall thickness, in.
Young’s modulus, E, 29 ¥ 106, psi E Young’s modulus of elasticity, psi
F Anchor force, lb
Poisson’s ratio, v, 0.3 Fs Soil resistance, lb/ft
L Transition length, ft
Thermal expansion coefficient, 6.5 ¥ 10-6, in./in. °F P Design pressure, psig
Ti Installation temperature, °F
Installation temperature, Ti, 80°F (minimum summer tem- To Operating temperature, °F
perature when construction is in progress) DT Temperature difference = (To - Ti), °F
a Coefficient of thermal expansion, in./in.-°F
Negative stress values denote a compressive stress. s Stress, psi
e Strain, in./in.
Discussion v Poisson’s ratio
d Deflection, in.
As shown in Table 1, anchor block forces can be quite large
and therefore, careful attention must be paid to the design.
In order to minimize the size of the block, upper design limit

110 Pipeline Rules of Thumb Handbook B Point B, unrestrained
PR Pressure
Subscripts (for Greek letters only) TE Temperature
L Longitudinal PO Poisson
H Hoop
A Point A, fully restrained

How to identify the series number of flanged fittings

Divide the flange thickness, expressed in sixteenths of an 23 18 = 1.28; the flange is series 30.
inch, by the nominal pipe size + 12. If the answer is less than
1.00, the flange is Series 15; if between 1.15 and 1.33, it is The rule is not applicable to fittings below four inches in
Series 30; if between 1.37 and 1.54, it is Series 40; and if it is size; it also fails for a four-inch Series 60, which comes out
between 1.60 and 1.85, it is Series 60. 1.50.

Example. A six-inch flange has a thickness of 17/16 inch =
23/16 inch.

Dimensions of three-diameter ells with tangents

Here are face-to-face and center-to-face dimensions of the
three-diameter radius weld ells being used in natural gas com-
pressor station piping.

Pipe Design 111

Polypipe design data

Internal pressure

Polyethylene pipe for industrial, municipal, and mining SDR = Standard dimension ratio, (D/t)
applications is manufactured to specific dimensions as pre- D = Outside diameter, inches
scribed by applicable American Society for Testing and t = Minimum wall thickness, inches
Materials (ASTM) standards. Piping outside diameters meet F = Design safety factor (0.5 for water @ 73°F)
the IPS system. Wall thicknesses are based on the Standard
Dimension Ratio (SDR) system, a specific ratio of the outside Use of other factors determined from Figures 1, 2 and 3
diameter to the minimum specified wall thickness. Selected will provide for a more accurate performance characteristic
SDR numbers are from the ANSI Preferred Number Series. for systems operating at other temperatures for shorter
Use of the SDR number in the ISO equation, recognized as periods of time.
an equation depicting the relationship of pipe dimensions’—
both wall and o.d.—internal pressure carrying capabilities and The ISO equation now becomes:
tensile stress, in conjunction with a suitable safety factor (F),
will give the design engineer confidence that the pipe will not P = 2S ¥ F ¥ F1 ¥ F2 ¥ F3
fail prematurely due to internal pressurization. SDR - 1

A pressure differential is required to move a material F1 = Operational life factor
through a pipeline. For atmospheric systems (gravity flow), F2 = Temperature correction
gravitational forces provide the impetus for movement of F3 = Environmental service factor (Figure 3)
heavier-than-air mass. Internal pressure requirements must
be recognized in the design stage in order to provide desired Other design factors may be necessary in the design of
operational life. In some cases a gravity flow system must be systems where abrasion, corrosion or chemical attack may be
treated comparable to the design considerations of a pressure a factor.
flow system.
Example: A horizontal process water line, 2,000 ft. in length,
Polyethylene pipe under pressure is time/temperature/ 125°F water, 60 psig pressure, with a desired life of five
pressure dependent. As the temperature increases and the years, is proposed. Determine the standard pipe SDR for the
pressure remains constant the creep rupture strength application.
decreases. Conversely, as the temperature decreases the
strength increases. Varying these parameters, in conjunction 60 = 2 ¥ 1600 ¥ 0.5 ¥ 1.09 ¥ 0.620
with the SDR, can provide the desired service within the SDR - 1
capabilities of polyethylene pipe.

Calculations for determining the pressure rating of Poly
pipe is based on the ISO equation as follows:

P = 2S ¥ F SDR - 1 = 1081
SDR - 1 60

where SDR = 18 + 1 = 19
P = Internal pressure, psi Therefore use SDR = 17.
S = Long term hydrostatic strength, psi (1,600 psi for Note: Using SDR 17 is conservative.

Poly pipe)

Figure 1

Internal Pressure Ratings (psi) (PE Pipe at 73°F for 50 years).

SDR 7.3 9 11 13.5 15.5 17 21 26 32.5

Pressure Rating 250 200 160 125 110 100 80 64 50

112 Pipeline Rules of Thumb Handbook

Figure 2
Operational Life

To use Figure 1 for determining
operational life multiplier, F1, select
expected operating life (less than 50
years) on the horizontal time line,
move upwards to intersect the
diagonal turn line and then left to
take reading at vertical axis.

Example: 5 year operational life will
yield F1 = 1.094.

Figure 3
Environmental Service Factor F3

Substance Service Factor (F3)
Crude Oil 0.50
Wet Natural Gas 0.50
Dry Natural Gas 0.64

Figure 4. Temperature Correction.

Example: A polyethylene pipe operat-
ing at 125°F would have an F2 factor of
0.62

Pipe Design 113

Figure 5 Figure 6
Recommended Liquid Velocities ID to OD Ratio

Pipe Size-Inches SDR F SDR F
7 0.706 13.5 0.852
3–10 10–28 28–48 7.3 0.719 15.5 0.873
9 0.774 17 0.884
Water and Similar 1 to 4 Velocity, fps 5 to 8 9.3 0.781 21 0.909
Viscosity Fluids 3 to 5 3 to 6 6 to 12 11 0.817 26 0.928
3 to 5 4 to 8 6 to 10 32.5 0.944
Pump suction* 4 to 8
Pump discharge
Gravity drain system

Viscous liquids 0.5 to 2 1 to 4 2 to 5 Pressure drop
Pump suction* 3 to 5 4 to 6 5 to 7
Pump discharge Refer to Section 13: Liquids—Hydraulics and use the
Hazen-Williams equation. Use a C of 150.

* It is important in the selection of the pipe size that the Fitting equivalent length
designated pump suction velocity be lower than the
discharge velocity.

Pipe diameter The exact pressure loss through fittings cannot readily be
calculated because of the geometry of the fitting. The
values shown in Figure 7 are the result of general industry
consensus.

Volumetric flow, Q, can be determined from the continu- Figure 7
ity equation Q = A ¥ V by selecting a suitable velocity from Equivalent Length of Fittings
Figure 5 for a given pipe size. When modified for flow in
gallons per minute, the equation becomes: Fitting Type Equivalent length of pipe
90 deg. elbow 30 D
Q = 2.449 ¥ V ¥ d2 60 deg. elbow 25 D
45 deg. elbow 16 D
where 45 deg. wye 60 D
Q = flow rate in gpm Running tee 20 D
V = velocity if feet per second Branch tee 50 D
d = inside diameter, inches Gate valve, full open 8D
Butterfly valve (3≤ to 14≤) 40 D
or d = (Q ∏ 2.449 ¥ V)1 2 for pipe size determination. Butterfly valve ≥14≤ 30 D
Swing check valve 100 D
Example: If the required water flow rate for a system is Ball valve full bore full open 3D
2,000 gpm and the flow velocity is to be maintained below
8 fps, the pipe diameter can be found as follows: Example: A running tee has an equivalent length of 20 D. For
an 18≤ SDR 11 line, this represents 20 ¥ ID. From Figure 6,
d = (Q ∏ 2.449 ¥ V)1 2 ID = OD ¥ F = 18 ¥ 0.817 = 14.7≤ ¥ 20 = 294 ∏ 12 and is
equal to 24.5 feet. In calculating the total pressure drop in
d = (2000 ∏ 2.449 ¥ 8)1 2 the system, 24.5 feet of 18 inch pipe should be added to the
total line length to account for the increased pressure loss due
d = 10.1 inches inside diameter to the presence of the tee.

OD = ID ∏ F (F from Figure 6) Published with permission—CSRTM PolyPipe

4: Electrical Design

Electrical design.................................................................................. 115
Hazardous locations ............................................................................ 116
NEMA Enclosure Types..................................................................... 117
Size portable electric generators........................................................ 118
Typical wattages for tools and appliances.......................................... 119
Knockout dimensions.......................................................................... 119
National Electrical Code Tables ........................................................ 120
Electrical formulas .............................................................................. 124
Full load currents—single phase transformers ................................. 124
Full load currents—three phase transformers .................................. 125
Motor controller sizes ......................................................................... 125
Voltage drop on circuits using 600 V. copper conductors in steel

conduit ............................................................................................. 126
Determine the most economical size for electric power

conductors ....................................................................................... 126
How to find the resistance and weight of copper wires ................... 127
What you should remember about electrical formulas .................... 127
How to calculate microwave hops on level ground .......................... 127
For quick determination of the horsepower per ampere for

induction motors (3 phase) at different voltages .......................... 128
Chart gives electric motor horsepower for pumping units .............. 128
Pumping stations ................................................................................. 129

Floodlighting Concepts.........................................130

Terms ................................................................................................... 130
Floodlighting calculations................................................................... 130
Point-by-point method........................................................................ 130
Beam-lumen method .......................................................................... 131
Design procedure................................................................................ 131
Conductor size conversion chart—Metric to AWG .......................... 132

114

Electrical Design 115

Electrical design

Most pipeline facilities use electrical equipment of some 3. Speeds—Single speed motors are the most common, but
sort or another, ranging from simple power circuits of a few when a range of speeds is required multispeed motors will
amperes capacity to sophisticated supervisory control and give 2, 3 or 4 fixed speeds.
data acquisition systems. It is beyond the scope of this manual
to provide a complete section on electrical information for 4. Service factors—Open, general purpose motors have a
pipeline facilities. This section is intended to provide some service factor depending upon the particular rating of the
basic data that will prove useful to field personnel responsible motor (usually between 1.15 and 1.25).
for electrical installations.
5. Selection of motor type

Electric motor selection There are three main types:

Based on known facts and calculations, the best selection (a) DC motors are designed for industrial drives requiring a
is made after a close study of the installation, operation and controlled speed range and constant torque output on
servicing of the motor. Basic steps in proper selection are adjustable voltage control systems. Because the speed of rota-
numbered 1 through 8 and are briefly described. tion controls the flow of current in the armature, special
devices must be used for starting DC motors.
1. Power supply
(b) Single phase alternating-current motors also require some
(a) Voltage-NEMA has recommended the following auxiliary arrangement to start rotation.
standards.
(c) Polyphase motors are alternating-current types (squirrel
Nominal Motor cage or wound rotor).
Power System Nameplate
Applications—Some driven machines require a low-
Volts Volts starting torque which gradually increases to full-load speed;
others require higher-starting torque. NEMA code letters A,
240 230 B, C, D, etc., on the motor nameplate designate the locked-
480 460 rotor kVa per horsepower of that particular motor design.
600 575 The diagram shows representative speed-torque curves for
polyphase and single-phase NEMA design motors Types A
through D.

(b) Frequency—Motors rated 200 horsepower or less can
vary not to exceed 5 percent above or below its rated
frequency.

(c) Phases—Three-phase power supplies are found in most
industrial locations; for most residential and rural areas, only
single-phase power is available.

2. HP and duty requirements

(a) Continuous duty—means constant load for an indefinite
period (about 90 percent of all motor applications).

(b) Intermittent duty—means alternate periods of load and 6. Torque definitions
no-load, or load and rest.
(a) Locked rotor torque, or “starting torque” is the minimum-
(c) Varying duty—means both the load and time operation torque which the motor will develop at rest for all angular
vary to a wide degree. positions of the rotor.

116 Pipeline Rules of Thumb Handbook

(b) Breakdown torque is the maximum-torque at rated voltage (c) NEMA Type II—A weather protected machine which has
and frequency without abrupt speed drop. in addition to the enclosure defined for a Type I weather-
protected machine, its ventilating passages at both intake and
(c) Full-load-torque is the torque necessary to produce rated discharge so arranged that high velocity air and airborne par-
horsepower at full-load speed. ticles blown into the machine by storms or high winds can be
discharged without entering the internal ventilating passages
(d) Locked-rotor current is the steady-state current of the leading directly to the electric parts of the machine itself. The
motor with the rotor locked at rated voltage and frequency. normal path of the ventilating air which enters the electric
parts of the machine shall be so arranged by baffling or sepa-
Code Ltr Locked Rotor rate housings as to provide at least three abrupt changes in
kVa/hP direction, none of which shall be less than 90 deg. In addition,
A an area of low velocity, not exceeding 600 ft/min., shall be pro-
B 0–3.14 vided in the intake air path to minimize the possibility of
C 3.15–3.54 moisture or dirt being carried into the electric parts of the
D 3.55–3.99 machine.
E
F 4.0–4.49 (b) Totally Enclosed Non-Vent means that a motor is not
4.5–4.99 equipped for cooling by external means.

5–5.59 (c) Totally Enclosed Fan-Cooled means the motor has a fan
integral with the motor but not external to the enclosed parts.

7. Selection of enclosure—The two general classifica- (d) Explosion-Proof means the enclosure is designed to with-
tions are open, which permits passage of air over and around stand an explosion of a specified gas which may occur within
the windings; and totally enclosed, which prevents exchange the motor and to prevent the ignition of gas around the motor.
of air between inside and outside of frame (but is not strictly
airtight). 8. End shield mountings—Three types of end shields
with rabbets and bolt holes for mounting are standard in the
(a) Open Drip-Proof—means that liquid or solid particles industry:
falling on the motor at an angle not greater than 15 degrees
from vertical cannot enter the motor. (a) Type C Face provides a male rabbet and tapped holes.

(b) NEMA Type 1—A weather protected machine with its (b) Type D Flange has a male rabbet with holes for through
ventilating passages constructed to minimize the entrance of bolts in the flange.
rain, snow and airborne particles to the electric parts and
having its ventilating openings so constructed to prevent the (c) Type P base has a female rabbet and through bolts for
passage of a cylindrical rod 3/4 in. in diameter. mounting in the flange (used for mounting vertical motors).

Hazardous locations

Definition of Class Locations

Reprinted with permission from NFPA 70-1990, the 500-5. Class I Locations. Class I locations are those in
National Electrical Code®, Copyright© 1989, National Fire which flammable gases or vapors are or may be present in the
Protection Association, Quincy, MA 02269. This reprinted air in quantities sufficient to produce explosive or ignitible
material is not the complete and official position of the mixtures. Class I locations shall include those specified in (a)
National Fire Protection Association, on the referenced and (b) below.
subject which is represented only by the standard in its
entirety. (a) Class I, Division 1. A Class I, Division 1 location is a loca-
tion: (1) in which ignitible concentrations of flammable gases
The National Electrical Code and NEC are registered or vapors can exist under normal operating conditions; or (2)
trademarks of the NFPA.

Electrical Design 117

in which ignitible concentrations of such gases or vapors may (FPN No. 1): This classification usually includes locations
exist frequently because of repair or maintenance operations where volatile flammable liquids or flammable gases or vapors
or because of leakage; or (3) in which breakdown or faulty are used, but which, in the judgment of the authority having
operation of equipment or processes might release ignitible jurisdiction, would become hazardous only in case of an acci-
concentrations of flammable gases or vapors, and might also dent or of some unusual operating condition. The quantity of
cause simultaneous failure of electric equipment. flammable material that might escape in case of accident, the
adequacy of ventilating equipment, the total area involved,
(FPN): This classification usually includes locations where and the record of the industry or business with respect to
volatile flammable liquids or liquefied flammable gases are explosions or fires are all factors that merit consideration in
transferred from one container to another; interiors of spray determining the classification and extent of each location.
booths and areas in the vicinity of spraying and painting oper-
ations where volatile flammable solvents are used; locations (FPN No. 2): Piping without valves, checks, meters, and
containing open tanks or vats of volatile flammable liquids; similar devices would not ordinarily introduce a hazardous
drying rooms or compartments for the evaporation of flam- condition even though used for flammable liquids or gases.
mable solvents; locations containing fat and oil extraction Locations used for the storage of flammable liquid or of
equipment using volatile flammable solvents; portions of liquefied or compressed gases in sealed containers would
cleaning and dyeing plants where flammable liquids are used; not normally be considered hazardous unless subject to other
gas generator rooms and other portions of gas manufacturing hazardous conditions also.
plants where flammable gas may escape; inadequately venti-
lated pump rooms for flammable gas or for volatile flamma- Group A: Atmospheres containing acetylene.
ble liquids; the interiors of refrigerators and freezers in which
volatile flammable materials are stored in open, lightly stop- Group B: Atmospheres containing hydrogen, fuel and
pered, or easily ruptured containers; and all other locations combustible process gases containing more than 30 percent
where ignitible concentrations of flammable vapors or gases hydrogen by volume, or gases or vapors of equivalent hazard
are likely to occur in the course of normal operations. such as butadiene,* ethylene oxide,** propylene oxide,** and
acrolein.**
(b) Class I, Division 2. A Class I, Division 2 location is a loca-
tion: (1) in which volatile flammable liquids or flammable Group C: Atmospheres such as cyclopropane, ethyl ether,
gases are handled, processed, or used, but in which the ethylene, or gases or vapors of equivalent hazard.
liquids, vapors, or gases will normally be confined within
closed containers or closed systems from which they can Group D: Atmospheres such as acetone, ammonia,***
escape only in case of accidental rupture or breakdown of benzene, butane, ethanol, gasoline, hexane, methanol,
such containers or systems, or in the case of abnormal oper- methane, natural gas, naptha, propane or gases of vapors of
ation of equipment; or (2) in which ignitible concentrations equivalent hazard.
of gases or vapors are normally prevented by positive mechan-
ical ventilation, and which might become hazardous through * Group D equipment may be used for this atmosphere if such equipment
failure or abnormal operation of the ventilating equipment; is isolated in accordance with Section 501-5(a) by sealing all conduit 1/2-inch
or (3) that is adjacent to a Class I, Division 1 location, and to or larger.
which ignitible concentrations of gases or vapors might occa- ** Group C equipment may be used for this atmosphere if such equipment
sionally be communicated unless such communication is is isolated in accordance with Section 501-5(a) by sealing all conduit 1/2-inch
prevented by adequate positive-pressure ventilation from a or larger.
source of clean air, and effective safeguards against ventila- *** For classification of areas involving ammonia atmosphere, see Safety
tion failure are provided. Code for Mechanical Refrigeration, ANSI/ASHRAE 15-1978, and Safety
Requirements for the Storage and Handling of Anhydrous Ammonia,
ANSI/CGA G2.1-1981.

NEMA Enclosure Types1

Nonhazardous Locations

Type Intended Use and Description 2 Enclosures are intended for indoor use primarily
to provide a degree of protection against limited
1 Enclosures are intended for indoor use primarily amounts of falling water and dirt.
to provide a degree of protection against limited 3 Enclosures are intended for outdoor use primarily to
amounts of falling dirt. provide a degree of protection against rain, sleet,

118 Pipeline Rules of Thumb Handbook

windblown dust, and damage from external ice longed submersion at a limited depth, and damage

formation. from external ice formation.

3R Enclosures are intended for outdoor use primarily to 12 Enclosures are intended for indoor use primarily to

provide a degree of protection against rain, sleet, and provide a degree of protection against circulating

damage from external ice formation. dust, falling dirt, and dripping noncorrosive liquids.

3S Enclosures are intended for outdoor use primarily to 12K Enclosures with knockouts are intended for indoor

provide a degree of protection against rain, sleet, use primarily to provide a degree of protection

windblown dust, and to provide for operation for against circulating dust, falling dirt, and dripping

external mechanisms when ice laden. noncorrosive liquids.

4 Enclosures are intended for indoor or outdoor use pri- 13 Enclosures are intended for indoor use primarily to

marily to provide a degree of protection against wind- provide a degree of protection against dust, spraying

blown dust and rain, splashing water, hose-directed of water, oil, and noncorrosive coolant.

water and damage from external ice formation.

4X Enclosures are intended for indoor or outdoor use Hazardous (classified locations)
primarily to provide a degree of protection against

5 corrosion, windblown dust and rain, splashing water, 7 Enclosures are intended for indoor use in locations
6 hose-directed water and damage from external ice 8 classified as Class I, Groups A, B, C, or D, as defined
6P formation. 9 in the National Electrical Code.
Enclosures are intended for indoor use primarily to 10 Enclosures are intended for indoor use in locations
provide a degree of protection against settling air- classified as Class I, Groups A, B, C, or D, as defined
borne dust, falling dirt, and dripping noncorrosive in the National Electrical Code.
liquids. Enclosures are intended for indoor use in locations
Enclosures are intended for indoor or outdoor use classified as Class II, Groups E, F, or G, as defined
primarily to provide a degree of protection against in the National Electrical Code.
hose-directed water, the entry of water during occa- Enclosures are constructed to meet the applicable
sional temporary submersion at a limited depth, and requirements of the Mine Safety and Health
damage from external ice formation. Administration.
Enclosures are intended for indoor or outdoor use

primarily to provide a degree of protection against Reference NEMA Standards Publications/No. 250-1991
hose-directed water, the entry of water during pro- Used with permission—National Electrical Manufacturer’s Association.

Size portable electric generators

A power plant must be properly sized for the required load. Total motor load = 600 ¥ 3 = 1,800 watts
Electric motors are particularly difficult for portable plants
since they require 2 to 3 times motor nameplate amps or Total other load = 2,100 watts
wattage.
Total load = 3,100 watts
A portable power plant’s surge capacity is limited by engine
horsepower and inertia of its rotating parts. Thus, a current Add 25% for future = 975 watts
surge of short duration can be supplied by a power plant, but
a current demand of longer duration such as a heavily loaded Total load for sizing power plant = 4,875 watts
motor starting a high inertia load, can overload the power
plant and possibly damage the power plant and the motor. A A generator capable of supplying 5,000 watts continuously
3,450 rpm air compressor is a prime example of this type of will be adequate.
load.
When more than one motor is connected to a power plant,
Example: always start the largest motor first. If the total load is con-
nected to one receptacle on the power plant, be sure the
Load Requirements: ampere rating of the receptacle is not exceeded.

Electric Heater 1,000 watts
11–100 watt lamps 1,100 watts
Motor
600 watts

Electrical Design 119

Typical wattages for tools and appliances

Equipment Running
Watts
1,000
1/2≤ drill 1,100
1≤ drill 800
6≤ circular saw 2,000
10≤ circular saw 1,100
14≤ chain saw 50 to 200
Radio 200 to 500
Television 1,200
Toaster, coffeemaker 1,100 to 5,500
Water heater (storage type) 1,000
Hot plate or range (per burner) 10,000
Range oven 1,200
Skillet 50 to 200
Fan 1,000
Floodlight 500
Water pump 200 to 300
Vacuum cleaner 200 to 300
Refrigerator (conventional) 250 to 600
Refrigerator (freezer-combination) 500 to 700
Furnace fan (blower)

Knockout dimensions

Conduit Min. Knockout Max.
Size Dia. Ins.
Ins. 0.859 0.906
1.094 Nominal 1.141
1/2 1.359 1.406
3/4 1.719 0.875 1.766
1 1.958 1.109 2.016
1 1/4 2.433 1.375 2.500
1 1/2 2.938 1.734 3.000
2 3.563 1.984 3.625
2 1/2 4.063 2.469 4.156
3 4.563 2.969 4.672
3 1/2 5.625 3.594 5.750
4 6.700 4.125 6.844
5 4.641
6 5.719
6.813

Reference NEMA Standards Publications/No. 250-1991
Used with permission—National Electrical Manufacturer’s Association.

120 Pipeline Rules of Thumb Handbook Table 310–16
Ampacities of insulated Conductors Rated 0-2000 Volts,
National Electrical Code Tables
60° to 90°C (140° to 194°F) Not More Than Three
Table 430–150 Conductors in Raceway or Cable or Earth (Directly
Full-Load Current* Three-Phase Alternating-Current Buried), Based on Ambient Temperature of 30°C (86°F)

Motors

* These values of full-load current are for motors running at speeds
usual for belted motors and motors with normal torque characteristics.
Motors built for especially low speeds or high torques may require more
running current, and multispeed motors will have full-load current
varying with speed, in which case the nameplate current rating shall be
used.
† For 90 and 80 percent power factor the above figures shall be multi-
pled by 1.1 and 1.25 respectively.
The voltages listed are rated motor voltages. The currents listed shall
be permitted for system voltage ranges of 110 to 120, 220 to 240, 440
to 480, and 550 to 600 volts.

† Unless otherwise specifically permitted elsewhere in this Code, this
overcurrent protection for conductor types marked with an obelisk (†)
shall not exceed 15 amperes for 14 AWG, 20 amperes for 12 AWG, and
30 amperes for 10 AWG copper; or 15 amperes for 12 AWG and 25
amperes for 10 AWG aluminum and copper-clad aluminum after any
correction factors for ambient temperature and number of conductors
have been applied.

Reprinted with permission from NFPA 70-1990, The National Electrical Code®, Copyright © 1988, National Fire Protection Association, Quincy,
MA 02269. This reprinted material is not the complete and official position of the National Fire Protection Association, on the referenced subject
which is represented only by the standard in its entirety.

Electrical Design 121
Table 3A
Maximum Number of Conductors in Trade Sizes of Conduit or Tubing
(Based on N.E.C. Table 1, Chapter 9)

Note: This table is for concentric stranded conductors only. For cables with compact conductors, the dimensions in N.E.C.
Table 5A shall be used.

Table 3B
Maximum Number of Conductors in Trade Sizes of Conduit or Tubing (Based on Table 1, Chapter 9)

Note: This table is for concentric stranded conductors only. For cables with compact conductors, the dimensions in N.E.C.
Table 5A shall be used.
Reprinted with permission from NFPA 70-1990, The National Electrical Code®, Copyright © 1988, National Fire
Protection Association, Quincy, MA 02269. This reprinted material is not the complete and official position of the National
Fire Protection Association, on the referenced subject which is represented only by the standard in its entirety.

122 Pipeline Rules of Thumb Handbook

Table 3C
Maximum Number of Conductors in Trade Sizes of Conduit or Tubing

(Based on N.E.C. Table 1, Chapter 9)

Note: The table is for concentric stranded conductors only. For cables with compact conductors, the dimensions in N.E.C.
Table 5A shall be used.

Reprinted with permission from NFPA 70-1990, The National Electrical Code®, Copyright© 1988, National Fire Protection
Association, Quincy, MA 02269. This reprinted material is not the complete and official position of the National Fire
Protection Association, on the referenced subject which is represented only by the standard in its entirety.

Tables 4 and 5 give the nominal size of conductors and sions represent average conditions only, and variations will be
conduit or tubing for use in computing size of conduit or found in dimensions of conductors and conduits of different
tubing for various combinations of conductors. The dimen- manufacture.

Table 4
Dimensions and Percent Area of Conduit and of Tubing

Reprinted with permission from NFPA 70-1987, National Electrical Code, Copyright 1986, National Fire Protection
Association, Quincy, MA 02269. The reprinted material is not the complete and official position of the NFPA on the
referenced subject which is represented only by the standard in its entirety.

Electrical Design 123
Table 5
Dimensions of Rubber-Covered and Thermoplastic-Covered Conductors

* The dimensions of Types RHH and RHW.
† Dimensions of THW in sizes No. 14 through No. 8. No. 6 THW and larger is the same dimension as TW.
*** Dimensions of RHH and RHW without outer covering are the same as THW No. 18 through No. 10, solid; No. 8 and larger, stranded.
**** In Columns 8 and 9 the values shown for sizes No. 1 through 4/0 are for TFE and Z only. The right-hand values in Columns 8
and 9 are for FEPB, Z, ZF, and ZFF only.
‡‡ No. 14 through No. 2.
Reprinted with permission from NFPA 70-1987, National Electrical Code, Copyright 1986, National Fire Protection Association,
Quincy, MA 02269. The reprinted material is not the complete and official position of the NFPA on the referenced subject which is
represented only by the standard in its entirety.

124 Pipeline Rules of Thumb Handbook eff = Efficiency (decimal)
PF = Power Factor (decimal)
Electrical formulas kVA = Kilovolt amperes
kW = Kilowatts
Single Phase hp = Horsepower
KVA = VA 1,000 rpm = Revolutions per minute

hp = (VA ¥ eff ¥ PF) 746 Three Phase
kw = (VA ¥ PF) 1,000
(31 2 V ¥ A) 1,000
PF = kW kVA
(31/2 VA ¥ PF ¥ eff ) 746
Torque (ft-lb) = hp ¥ 5,250 rpm
Motor kVA = (hp ¥ 0.746) eff ¥ PF (31 2 VA ¥ PF) 1,000
Motor kW = (hp ¥ 0.746) eff
(kW ¥ 1,000) 31 2 ¥ VA
V = Line-to-line volts
A = Amperes

Full load currents—single phase transformers

Voltage—Volts

kVA 120 240 480 2,400 4,160 7,200
Rating
8.3 4.2 2.1 0.4 0.2 0.1
1.0 25.0 12.5 6.3 1.3 0.7 0.4
3.0 41.7 20.8 10.4 2.1 1.2 0.7
5.0 62.5 31.3 15.6 3.1 1.8 1.0
7.5 83.3 41.7 20.8 4.2 2.4 1.4
10.0 125.0 62.5 31.3 6.3 3.6 2.1
15.0 208.3 104.2 52.1 10.4 6.0 3.5
25.0 312.5 156.3 78.1 15.6 9.0 5.2
37.5 416.7 208.3 104.2 20.8 12.0 6.9
50.0 625.0 312.5 156.3 31.3 18.0 10.4
75.0 833.3 416.7 208.3 41.7 24.0 13.9
100.0 1,041.7 520.8 260.4 52.1 30.0 17.4
125.0 1,395.8 697.9 349.0 69.8 40.3 23.3
167.5 1,666.7 833.3 416.7 83.3 48.1 27.8
200.0 2,083.3 1,041.7 520.8 104.2 60.1 34.7
250.0 2,775.0 1,387.5 693.8 138.8 80.0 46.3
333.0 4,166.7 2,083.3 1,041.7 208.3 120.2 69.4
500.0

Electrical Design 125

Full load currents—three phase transformers

kVA 240 480 Voltage (line-to-line) 4,160 12,470
Rating
7.2 3.6 2,400 0.4 0.1
3 14.4 7.2 0.8 0.3
6 21.7 10.8 0.7 1.2 0.4
9 36.1 18.0 1.4 2.1 0.7
15 72.2 36.1 2.2 4.2 1.4
30 90.2 45.1 3.6 5.2 1.7
37.5 108.3 54.1 7.2 6.2 2.1
45 120.3 60.1 9.0 6.9 2.3
50 180.4 90.2 10.8 10.4 3.5
75 240.6 120.3 12.0 13.9 4.6
100 270.6 135.3 18.0 15.6 5.2
112.5 360.9 180.4 24.1 20.8 6.9
150 481.1 240.6 27.1 27.8 9.3
200 541.3 270.6 36.1 31.2 10.4
225 721.7 360.9 48.1 41.6 13.9
300 1,082.6 541.3 54.1 62.5 20.8
450 1,202.8 601.4 72.2 69.4 23.2
500 1,443.4 721.7 108.3 83.3 27.8
600 1,804.3 902.1 120.3 104.1 34.7
750 2,405.7 1,202.8 144.3 138.8 46.3
1,000 3,608.5 1,804.3 180.4 208.2 69.5
1,500 4,811.4 2,405.7 240.6 277.6 92.6
2,000 6,014.2 3,007.1 360.9 347.0 115.8
2,500 12,028.5 6,014.2 481.1 694.0 231.5
5,000 24,057.0 12,028.5 601.4 1,387.9 463.0
10,000 1,202.8
2,405.7

Motor controller sizes Single Phase Motors

Polyphase Motors

Maximum Horsepower Maximum Horsepower
Full Voltage Starting Full Voltage Starting
(Two Pole Contactor)

NEMA 230 460–575 NEMA 115 230
Size Volts Volts Size Volts Volts

00 1.5 2 00 1.3 1
0 3 5 0 12
1 7.5 10 1 23
2 15 25 2 3 7.5
3 30 50 3 7.5 15
4 50 100
5 100 200
6 200 400
7 300 600

126 Pipeline Rules of Thumb Handbook

Voltage drop on circuits using 600 V. copper conductors in steel conduit

To determine the voltage drop, multiply the length in feet loss. This table takes into consideration reactance on AC cir-
of one conductor by the current in amperes and by the cuits and resistance of the conductor. Unless otherwise noted,
number listed in the table for the type of system and power the table is based on 60 Hz.
factor and divide the result by 1,000,000 to obtain the voltage

Three Phase Single Phase
Lagging Power Factor Lagging Power Factor

Wire Direct 100% 90% 80% 70% 60% 100% 90% 80% 70% 60%
Size Current
5,280 4,800 4,300 3,780 3,260 6,100 5,551 4,964 4,370 3,772
14 6,100 3,320 3,030 2,720 2,400 2,080 3,828 3,502 3,138 2,773 2,404
12 3,828 2,080 1,921 1,733 1,540 1,340 2,404 2,221 2,003 1,779 1,547
10 2,404 1,316 1,234 1,120 1,000 1,520 1,426 1,295 1,159 1,017
1,520 880
8 840 802 735 665 590 970 926 850 769 682
6 970 531 530 487 445 400 614 613 562 514 462
4 614 420 425 398 368 334 484 491 460 425 385
3 484 331 339 322 300 274 382 392 372 346 317
2 382 265 280 270 254 236 306 323 312 294 273
1 306 208 229 224 214 202 241 265 259 247 233
0 241 166 190 188 181 173 192 219 217 209 199
00 192 132 157 158 155 150 152 181 183 179 173
000 152 105 131 135 134 132 121 151 156 155 152
0000 121 118 123 125 123 103 136 142 144 142
250M 102 89 104 111 112 113 120 128 130 131
300M 74 101 105 106 86 108 117 121 122
350M 85 63 94 100 73 100 110 113 116
400M 73 55 87 95 98 64 104 106
500M 64 45 76 85 90 92 52 88 98 101
600M 51 38 69 79 85 87 44 80 91 98
700M 43 33 64 74 80 84 38 74 86 92 97
750M 36 31 62 72 79 82 36 72 83 91 95
800M 34 29 61 71 76 81 33 70 82 88 93
900M 32 26 57 68 74 78 30 66 78 85 90
1000M 28 23 55 66 72 76 27 63 76 83 88
26

Determine the most economical size for electric power conductors

To calculate quickly the most economical size copper wire as well as economics. Once these are considered, the most
for carrying a specified current load, use the formula: economical size conductor is that for which the annual energy
cost equals the copper cost. This method can be used for
A = (59)(I) Ce ¥ t other metallic conductors.
Cc ¥ F
Example. Determine the most economical size copper
where A = Conductor cross-sectional area (circular mils) conductor for an installation operating 365 days a year, 8
I = Current load (amperes) hours per day, with a 100 ampere load. Energy costs are
$0.00875 per KWH. Fixed charges are 23 percent, consider-
Ce = Cost of electrical power (cents per KWH) ing a five-year amortization with 3 percent for insurance and
Cc = Cost of copper (cents per lb) taxes. Copper costs $0.46 per lb.

t = Hours of service per year A = (59)(100) 0.00875 ¥ 365 ¥ 8
F = Factor for fixed charges (amortization, insurance,
0.46 ¥ 0.23
taxes, etc.) = 91,686 circular mils

Selection of the proper size electric conductor will depend on
the load to be carried and the mechanical strength required,

Electrical Design 127

How to find the resistance and weight of copper wires

It is easy to calculate mentally the approximate resistance Number 10 wire has a resistance of 1 ohm per thousand ft.
and weight of standard sizes of copper wires, by remember- (Rule 1)
ing the following rules:
Number 20 wire has a resistance of 10 ohms per thousand ft.
Rule 1: Number 10 wire has a resistance of 1 ohm per thou- (Rule 2)
sand ft. Number 2 wire weighs 200 lb per thousand ft.
Number 17 wire has a resistance of 5 ohms per thousand
Rule 2: An increase of ten numbers in the size is an increase ft. (Rule 3)
of ten times in the resistance, and a decrease to one-tenth
of the weight. Number 18 wire has a resistance of 6.25 ohms per thousand
ft. (Rule 4)
Rule 3: An increase of three numbers in the size doubles the
resistance and halves the weight. Number 18 wire has a resistance of 1.25 ohms per 200 ft.
Answer.
Rule 4: An increase of one number in the size multiplies the
resistance by 5/4 and the weight by 4/5. Number 2 wire weighs 200 lb per thousand ft. (Rule 1)
Number 12 wire weighs 200 lb per thousand ft. (Rule 2)
Always proceed from the known value (No. 10 for resis- Number 22 wire weighs 2 lb per thousand ft. (Rule 2)
tance, No. 2 for the weight) in the smallest number of jumps; Number 19 wire weighs 4 lb per thousand ft. (Rule 3)
that is, go by tens, then by threes, and finally by ones; the Number 18 wire weighs 5 lb per thousand ft. (Rule 4)
jumps do not all have to be in the same direction. Number 18 wire weighs 1 lb per 200 ft. (Answer)

Example. What is the weight and resistance of 200 ft of The weight determined by the above rules is that of bare
No. 18? Apply the rules in order, as follows; resistance first: copper wire. Weight of insulated wire varies widely according
to the type of insulation. Resistance values are correct for bare
or insulated wire, and for solid or stranded. Errors resulting
from the use of the rules will rarely exceed 2 percent.

What you should remember about electrical formulas

Ohm’s law Other facts

Easily Remember It, or E = RI The number of watts in a hp is equal to the year Colum-
bus discovered America divided by two, or 1492/2 = 746
Power watts/hp.
DC Power Is Easy, or P = IE
It Really Is, or P = IRI = I2R The horsepower of a reciprocating engine necessary to
drive a three phase, 60 cycle electric generator can be deter-
mined by multiplying KW by 1.5.

How to calculate microwave hops on level ground

Rule. Excluding obstructions such as hills, etc., the horizon can be found by adding the square root of the tower
microwave (line-of-sight) distances between two towers will height to the square root of the first square root (the latter of
be twice the distance from the transmitter to the horizon. The course is the fourth root).
line-of-sight distance in miles from the top of the tower to the
x = h + h or h + 4 h

Example. How far apart can 100-foot-high towers be
spaced to provide line-of-sight transmission if there are no
obstructions between them?

128 Pipeline Rules of Thumb Handbook

X = 100 + 10 Example. How far is the line-of-sight distance to the
horizon in an airplane flying at an altitude of 4,900 ft?
X =10 + 3 + or + 13miles
( 4,900 = 70)
Distance between towers can be 2X or 26 miles.
This same formula can be used to estimate distances in X = 4,900 + 70
an airplane. X = 70 + 8

Distance to horizon is 78 miles.

For quick determination of the horsepower per ampere for induction motors (3 phase)
at different voltages

Voltage hp per ampere

480 1
2,400 5
4,160 8

Chart gives electric motor horsepower for pumping units

This chart provides a means of determining the power
requirements for a beam pumping installation powered by an
electric motor based on a fluid with a specific gravity of one,
with fluid at the pump. The power requirement determined
by the chart includes a mechanical efficiency factor of 0.45
and a cyclic factor of 0.75, which factors are frequently
applied to motors used in sucker rod pumping service.

An arrangement is available for correcting the power
requirement in the case of an underloaded pumping unit. The
example shown in the chart is self-explanatory.

After the power requirements are determined from the
chart the next higher size of commercially available motor
is used.

Electrical Design 129

Pumping stations

Table gives capacitor multipliers for kilowatt loads for different desired power factor improvements

130 Pipeline Rules of Thumb Handbook

FLOODLIGHTING CONCEPTS

This material is intended as a helpful guide in the evaluation of lighting requirements and is intended to serve only as a
guide.

Terms

Candela or Candlepower—Light sources do not project the the lumens are falling. A density of one lumen per square foot
same amount of light in every direction. The directional char- is one footcandle. One footcandle is equal to 10.76 lux.
acteristic of a lamp is described by the candlepower in spe-
cific directions. This directional strength of light or luminous Lux, lx—The SI unit of illuminance. This metric measure-
intensity is measured in candelas. ment is based upon the density of lumens per unit surface
area similar to footcandle, except one lux is one lumen per
Lumen—Light quantity, irrespective of direction, is mea- square meter. One lux is equal to 0.09 footcandle.
sured in lumens. Lamp lumens are the quantity of light pro-
duced by a lamp. Average light level calculations use total Light Loss Factor, LLF—These factors are used to adjust
lamp lumens as a basis and then adjust for all factors that lighting calculations from laboratory test conditions to a closer
lower this quantity. The amount of useful light in a floodlight approximation of expected field results. The I.E.S. Lighting
beam is measured in beam lumens. Handbook, 1984 Reference Volume, defines LLF as follows:
“a factor used in calculating illuminance after a given period
Footcandle, fc—Specifications are usually based on density of time and under given conditions. It takes into account tem-
of light or level of illumination which is measured in foot- perature and voltage variations, dirt accumulations on lumi-
candles. Footcandles are the ratio of quantity of light in naire and room surfaces, lamp depreciation, maintenance
lumens divided by the surface area in square feet on which procedures and atmosphere conditions.”

Floodlighting calculations

Floodlighting encompasses many variations. Since the loca- The most commonly used systems for floodlight calcula-
tion of the floodlight relative to the object to be lighted can tions are the point-by-point method and the beam-lumen
be in any plane and at any distance from the source . . . flood- method.
lighting application is often considered the most complex and
difficult of all lighting techniques.

Point-by-point method

The point-by-point method permits the determination of E = I D2 (1)
footcandles at any point and orientation on a surface and the
degree of lighting uniformity realized for any given set of
conditions.

In such situations, the illumination is proportional to the
candlepower of the source in a given direction, and inversely
proportional to the square of the distance from the source.
See Figure 1.

Footcandles on Plane = Candlepower of Light Ray
Distance in Feet From
(Normal to Light Ray)

Source to Point-Squared Figure 1. Inverse Square Law.

Electrical Design 131

When the surface on which the illumination to be determined Then b equals the angle between the light ray and a per-
is tilted, the light will be spread over a greater area, reducing pendicular to the plane at that point.
the illumination in the ratio of the area of plane A to the area
of plane B as shown in Figure 2. This ratio is equal to the
cosine of the angle of incidence; thus:

Footcandles on Plane B = Candlepower of Light Ray
Distance in Feet From

Source to Point-Squared

x Cosine of Angle b (2) Figure 2. Cosine of Angle Law.

E = (I D2 ) ¥ Cosine b

Beam-lumen method

The beam-lumen method is quite similar to the method Coverage. It is recommended that sufficient point-by-point
used for interior lighting except that the utilization factors calculations be made for each job to check uniformity and
must take into consideration the fact that floodlights are not coverage.
usually perpendicular to the surface and therefore not all of
the useful light strikes the surface. Light Loss Factor (LLF). The maintenance or light loss
factor is an allowance for depreciation of lamp output with
Beam lumens are defined as the quantity of light that is age and floodlight efficiency due to the collection of dirt on
contained within the beam limits as described as “beam lamp, reflector, and cover glass. The total factor may vary from
spread.” Beam lumens equal the lamp lumens multiplied by 0.65 to 0.85 depending on the type of lamp and luminaire
the beam efficiency of the floodlight. used and may include losses due to lamp orientation, or “tilt.”

Design procedure

Step 1—Determine the level of illumination. See Table 1 CBU = Utilized Lumens (4)
for some typical levels of illumination (fc). The basic formula BL
is:

fc = N ¥ BL ¥ CBU ¥ LLF (3) The exact CBU can be determined graphically by projecting
A the outline of the area to be lighted upon the photometric
data and totaling the utilized lumens. This procedure is
detailed in the I.E.S. Lighting Handbook. See Table 3.

where Table 1
N = quantity of luminaires Typical Illumination Levels
A = area in square feet
Area fc Area fc
BL = beam lumens
CBU = Coefficient of beam utilization
LLF = Light loss factor

Step 2—Determine type and location of floodlights. Building exteriors 5 Storage tanks 1
Regardless of light source there are industry standards on Entrances 1 Pump areas 2
beam spreads. See Table 2. Active 5 Parking 1
Inactive 3 Substation 2
Step 3—Determine the coefficient of beam utilization. Vital locations 5 Storage yards
This factor, CBU, written as a decimal fraction, is expressed 5 20
in the following ratio: Catwalks Active 1
Stairs Inactive
Barge or truck unloading

132 Pipeline Rules of Thumb Handbook

Table 2 Table 3
Outdoor Floodlight Luminaire Designations Typical CBU’s

Beam Spread, Degrees NEMA Type Area CBU Area fc

10 up to 18 1 Baseball 0.65 Tennis 0.75
>18 up to 29 2 Infield 0.85 Large parking lots 0.80
>29 up to 46 3 Outfield 0.60 Building facades 0.65
>46 up to 70 4
>70 up to 100 5 Football
>100 up to 130 6
>130 up 7 As an approximation, the average CBU of all the floodlights
in an installation should fall within the range of 0.6 to 0.9. If
The following general principles apply in the choice of beam spread: less than 60% of the beam lumens are utilized, a more eco-
1. The greater the distance from the floodlight to the area to be lighted, nomical lighting plan should be possible by using different
locations or narrower beam floodlights. If the CBU is over
the narrower the beam spread desired. 0.9, it is probable that the beam spread selected is too narrow
2. Since by definition the candlepower at the edge of a floodlight beam and the resultant illumination will be spotty. An estimated
CBU can be determined by experience, or by making calcu-
is 10% of the candlepower near the center of the beam, the illumi- lations for several potential aiming points and using the
nation level at the edge of the beam is one-tenth or less of that at average figure thus obtained.
the center. To obtain reasonable uniformity of illumination the beams
of individual floodlights must overlap each other as well as the edge Step 4—Determine the quantity of floodlights (N)
of the surface to be lighted. required. Rearrange the basic formula in Step 1 as follows:
3. The percentage of beam lumens falling outside the area to be lighted
is usually lower with narrow-beam units than with wide-beam units. N = A ¥ fc (5)
Thus narrow-beam floodlights are preferable where they will provide CBU ¥
the necessary degree of uniformity of illumination and the proper
footcandle level.

BL ¥ LLF

Conductor size conversion chart—Metric to AWG

Table 4

Metric Size AWG Size

2.5 mm2 #14
4 mm2 #12
6 mm2 #10
10 mm2 #8
16 mm2 #6
25 mm2 #31
35 mm2 #2
35 mm2 #11
50 mm2 #1/0
70 mm2 #2/0
95 mm2 #3/0
95 mm2 #4/01
120 mm2 250 kcmil
150 mm2 300 kcmil
185 mm2 350 kcmil1
185 mm2 400 kcmil1
240 mm2 500 kcmil
300 mm2 600 kcmil
400 mm2 700 kcmil
400 mm2 750 kcmil
400 mm2 800 kcmil1

1 This AWG size is the closest equivalent to the metric size.

5: Hydrostatic Testing

Hydrostatic testing for pipelines ........................................................ 134

Appendix A.............................................................140

Volume of water required to fill test section..................................... 140
Volume required at test pressure....................................................... 141

Appendix B ............................................................142

How to use charts for estimating the amount of pressure
change for a change in test water temperature ............................ 142

Compressibility factor for water......................................................... 145

133

134 Pipeline Rules of Thumb Handbook

Hydrostatic testing for pipelines

After construction of a pipeline is completed, or if pipe has data, will be used to determine the length and number of
been replaced or relocated, it is necessary to hydrostatically test sections. Figure 1 shows a typical pipeline elevation
test the pipeline to demonstrate that the pipeline has the gradient.
strength required to meet the design conditions, and to verify
that the pipeline is leak free. Figure 1. Pipeline elevation profile.

The U.S. Federal Safety Regulations for Pipelines require Where the pipeline traverses hilly terrain, the elevation gra-
that pipelines used to transport hazardous or highly volatile dient must be carefully considered in selecting the pipeline
liquids be tested at a pressure equal to 125% of the maximum test segments. Different companies have differing philoso-
allowable operating pressure (MAOP) for at least four con- phies on how to do this. Some limit the amount of elevation
tinuous hours and for an additional four continuous hours at difference while others may specify a range of allowable per-
a pressure equal to 110% or more of the MAOP if the line is centages of the SMYS of the pipe—i.e., 90 to 95% or 90 to
not visually inspected for leakage during the test. A design 100% of the SMYS of the pipe. In any case, the test gradient
factor of 72% of the specified minimum yield strength should be plotted to be sure the test pressure falls within the
(SMYS) of the pipe is used to determine the maximum allow- specified pressure limits.
able operating pressure. The requirement to test to 125% of
the MAOP will therefore cause the pipe to be tested to a pres- The test gradient must be based on water head in feet, if
sure equal to 90% of the SMYS of the pipe. See Section 3— water is used as the test medium. Water pressure may be con-
Pipe Design for additional information on calculating the verted to head by dividing the pressure by 0.433. If sea water
MAOP. is being used as the test medium, a factor of 0.445 should be
used. This assumes a specific gravity of 1.02 for sea water. In
The Regulations for gas lines specify design factors based any case, the factor of 0.433 should be modified according to
on the class location of the pipeline. The class location is the specific gravity of the test medium.
determined by the number of buildings in a specified area on
either side of the pipeline. Refer to Part 192.111 of the Let’s assume that we have a line that is to be tested and the
Minimum Federal Safety Standards for Gas Lines for the elevation at the test site is 1,000 feet and the elevation at
details on how to determine the class location. See Section 3, the end of the line is 1,200 feet. Fresh water will be used
Pipe Design for a listing of the design factors for the differ- as the test medium and it is desired to test the pipe to a
ent class locations. The Regulations specify that the test pres- minimum of 90% and a maximum of 96% of the SMYS of
sure must be maintained for at least eight hours and must be the pipe. The pipe is 30≤ OD ¥ 0.390≤ wt API 5LX X60. There
equal to at least 125% of the maximum allowable operating is a difference in elevation of 200 feet and this is equal to
pressure. The Regulations should be consulted for the spe-
cific testing requirements as the Regulations are subject to
change.

Usually, operators will specify a test pressure range from
90% to 95% of the SMYS of the pipe. Some will allow test
pressures as high as 100% of the SMYS of the pipe and some
will test to slightly beyond the SMYS of the pipe. Specify-
ing a test pressure at least equal to 90% of the SMYS of
the pipe will qualify it for the maximum allowable operating
pressure. In some cases, the test pressure will be based on
the minimum yield strength determined from the mill test
reports.

Hydrostatic testing a pipeline is certainly a major operation
and should be carefully planned. Most companies have hydro-
static test manuals that detail the procedures to be followed
to complete the test. Usually, this work is performed by a
hydrostatic testing contractor hired by the pipeline owner, or
hydrostatic testing may be included as a part of the main
construction contract.

One of the first steps in planning the hydrostatic test oper-
ation is to examine the elevation gradient. The gradient, along
with the location of the water source, and the pipe design

Hydrostatic Testing 135

86.6 psig (200 feet ¥ 0.433 = 86.6 psig). A test pressure equal Figure 2. Typical pressure manifold. Courtesy Milbar
to 90% of SMYS is 1,404 psig. Since the test site is lower Hydrotest.
than the high end of the line, the 86.6 psig is added to
1,404 psig to obtain a test site pressure of 1,491 psig. The pres-
sure at the end of the line will be 1,404 psig which equates to
90% of SMYS. The pressure at the low point equates to 96%
of SMYS.

Now, let’s assume a line has a high point elevation of 1,100
feet, a low elevation point of 1,000 feet, and the elevation
at the test site is 1,050 feet. The test pressure at the high
point will need to be 1,404 psig in order to meet the
90% of SMYS requirement. The pressure at the low point
will be 1,447 psig, and the pressure at the test site will be
1,426 psig.

When testing offshore lines, the pressure at or below the
water surface will be the same as at the low elevation point
due to the offsetting external sub-sea pressure head. If the
line previously described was laid offshore, the test pressure
at the water surface would be 1,404 psig. The elevations are
as follows:

Top if riser +11 feet
Test site +7 feet
Water surface
Pipe depth 0 feet
-168 feet

The test pressure at the test site would be 1,404 - (7 ¥ 0.445) Figure 3. Typical test manifold. Courtesy Milbar Hydrotest.
or 1,401 psig. At the top of the riser, the test pressure would Figure 4. Typical fill site. Courtesy Milbar Hydrotest.
be 1,404 - (11 ¥ 0.445) or 1,399 psig.

The typical profile shown in Figure 1 represents a pipeline
that requires testing. The pipeline crosses a river at approxi-
mately MP 5 and river water will be used to test the line. Test
sections 1 through 5 have been chosen as indicated. The
lengths of sections 3 and 4 are limited by elevation difference.
This line was designed to operate at 936 psig or 72% of the
SMYS of 30≤ ¥ 0.375≤ wt API 5LX X52 pipe for Class I loca-
tions, and 60% of the SMYS of 30≤ ¥ 0.390≤ wt API 5LX X60
pipe for Class II locations, and 50% of the SMYS of 30≤ ¥
0.438≤ wt API 5LX X65 for Class III locations.

The pipeline crosses one railroad, one highway, and the
river. It also includes one main line block valve assembly.
The valve assembly, river crossing, and road crossing were
pre-tested before installation and are tested again after
installation.

Four test manifolds were installed to facilitate filling the
line and for isolating the test sections during the test opera-
tion. See Figure 2 for a typical pressure sectionalizing mani-
fold. Two-way pigs were loaded at each of the intermediate
manifolds. The pigs are moved by the fill water and are nec-
essary to remove the air from the line.

It is generally a good idea to test the section most distant
from the water source first. If it should rupture, then testing
on intermediate sections can continue while repairs on the
failed section are completed.

136 Pipeline Rules of Thumb Handbook

Figure 5. Test thermometer placement. Courtesy Milbar Hydrotest.

The pumps used to fill the line should have sufficient capac- accept the leakage test if there is no pressure drop in a three
ity to fill the line at a rate of about 1/2 mile per hour. Water hour period.
filters should be used and are normally equipped with one
hundred mesh screens. See Figure 4 for a typical fill site A pressure-volume plot may be required, especially if the
arrangement. Some companies may specify a finer mesh test pressures approach or exceed the SMYS of the pipe.
screen. The filling unit should be equipped with a flow meter The plot is made manually during the pressuring operation
to measure the amount of water pumped into the pipeline. by recording pump strokes on the X-axis and pressure on
Temperature recorders will be used to record ambient tem- the Y-axis. A straight line will be produced until the plastic
perature, the temperature of the pipe and water, and ground range of the pipe is reached or until a leak occurs. This type
temperature. See Figure 5 for typical test thermometer place- of plot is also useful should a joint of lighter wall thickness
ment. A pressure recorder will be used to provide a record- or lower yield strength pipe be inadvertently placed in the
ing of the pipeline test pressure. A deadweight tester will be pipeline.
used to calibrate the pressure recorder. A high pressure pump
capable of delivering 70 to 150 gpm at a pressure exceeding Small leaks during the testing operation can be difficult to
the required test pressure will be used in the final pressuring locate. A change in the water/pipe temperature may give
operation. Small high pressure units with a capacity of 6 to the appearance of a leak. If the temperature of the pipe/
30 gpm may be used for short sections of large diameter lines water decreases, the test pressure will decrease. An increase
and smaller diameter lines. in water/pipe temperature will cause the test pressure to
increase. The effect of a temperature change may be esti-
Deadweight pressure and temperature readings are re- mated using the equations and data contained in Appendixes
corded after the prescribed test pressure has been reached A and B. To achieve any degree of accuracy in these calcula-
and the pressures and temperatures have stabilized. A pres- tions, it will be necessary to have accurate temperature and
sure vs. time plot may also be made. Readings are usually pressure readings.
made at fifteen minute intervals for the first hour and at thirty
minute intervals thereafter. The procedure for accepting a The pipeline test temperature may be affected by river/
leakage test will vary from company to company. Some will creek crossings along the pipeline route. Also, if cold
river water is used, there will be a changing temperature
gradient. Air, either trapped or entrained, will also affect the

Hydrostatic Testing 137

Figure 6. Typical pressure unit set-up. Courtesy Milbar Hydrotest.

pressure-temperature calculations since the coefficient of natural gas and certain chemicals are usually dewatered using
expansion for air is not the same as for water. If the calcula- compressed air. Care must be exercised in the dewatering
tions are made and the decrease in pressure cannot be attrib- operation to make sure that no air is introduced into the test
uted to a temperature change, then it may be necessary to section, thus minimizing the possibility of air locks. An air lock
sectionalize the test section by manifolding and repressuring is probably the most severe problem involved in dewatering.
the shorter segments to facilitate locating the leak. Once the Air locks are caused by air accumulating in the downhill leg
leak has been located and repaired, testing operations can and water accumulating in the uphill leg, which creates a
resume. manometer in the pipeline. In some instances, extremely high
pressures may be required to overcome the manometer. Care
Air compressors will be required to remove the water once should be exercised to be sure the maximum allowable
the testing is complete. The maximum head for this particu- pipeline operating pressure is not exceeded. It may also be
lar project was 450 feet (195 psig). Allowance will need to be necessary to tap the line and vent air at the high points.
included for friction loss in the cross-over manifolds. The
compressors will need to have sufficient capacity to remove If it is necessary to pipe the water away from the right-of-
the water at about the same rate as the fill rate. Most portable way, welded pipe should be used. The pipe must be securely
compressors are limited to approximately 125 psig. In this anchored. The use of tractors and skids will probably provide
case, booster compressors will be needed for the 195 + psig. sufficient anchoring.
See Figure 7 for a typical dewatering connection.
Always use a valve to control the amount of water being
Upon completion of testing, the test pressure is bled off to bled from the pipeline.
leave approximately 10 to 20 psig at the high point in the test
section. Dewatering may be accomplished using the air com- If there will be a delay in placing the pipeline in operation,
pressors discussed earlier. Some companies may elect to dis- and it is decided to leave the test water in the line until
place the test water with the material that will normally be operations begin, consideration should be given to the use
pumped through the line. This is usually the case with crude of a corrosion inhibitor. Long term storage of the line may
oil and refined product pipelines. Pipelines used to transport necessitate the use of oxygen scavengers in addition to the
inhibitor.

138 Pipeline Rules of Thumb Handbook
Figure 7. Dewatering arrangement. Courtesy Milbar Hydrotest.

Figure 8. Typical test report. Courtesy Milbar Hydrotest.