pipeline optimization a surface roughness approach by
TRANSCRIPT
1
PIPELINE OPTIMIZATION –
A SURFACE ROUGHNESS APPROACH
By
Fred F. Farshad
Abstract
Worldwide, the pipeline industry has been experiencing an increased urgency to achieve
pipeline flow efficiency. Currently, the primary objectives of pipeline companies focus on
maximizing flow capacity and prolonging the life of piping systems. Chemical and
mechanical cleaning ahead of in-line inspection pigging and internal pipeline coating
projects have aided in increasing flow efficiency. These measures have also facilitated
the detecting and managing of internal corrosion. Aging pipeline systems are imposing
higher maintenance and operating costs to comply with pipeline safety and reliability
standards. These pipeline standards, coupled with operation and maintenance costs,
have forced the international and national pipeline communities to focus on pipeline
efficiency. Transportation of hydrocarbons requires energy both to overcome friction
pressure losses in the pipeline and to deliver the products to customers. This paper will
focus on methods for determining pipeline efficiency as it relates to surface roughness of
the pipeline. An attempt will be made to illustrate the significance of surface roughness,
transmission factor, and thruput efficiency as they are used in the natural gas industry.
Introduction
Getting saleable products from the supply areas to the consumer utilizing cross-country
pipelines has been, and will continue to be, an efficient, cost-effective, and
environmentally safe means for transport. The maximum carrying capacity of a pipeline
is limited by its initial parameters of construction. Consequently, the physical and
thermodynamic properties of the natural gas affect the flow and compression
characteristics of the gas, hence the product thruput efficiency1.
Knowledge of the pipe internal surface roughness value is economically important in
optimizing the design of pipeline systems. Surface roughness influences the flow
characteristics in a pipe by creating unfavorable pressure and energy losses due to
friction2. Corrosion and black powder accumulation in pipelines can create unwanted
roughness, which will reduce the full pipe flow rate of hydrocarbons and will also
increase costs thereby, impeding a smooth operation and creating a reduction in the life
of the pipe.
2
The application of liquid epoxy internal coating3 and newly developed corrosion
resistance alloys2 (CRA) started when the pipeline industry first became challenged with
corrosion in pipelines in the Gulf Coast region of the United States. Increasing concern
with such problems has also occurred in the upstream petrochemical industry. The
primary use of coatings was to extend the life of the pipe by preventing interaction of the
metals with the corrosive fluids. However, industry has discovered that there is a
beneficial advantage in the use of internally coated pipe, which improves the flow thruput
by reducing the wall surface roughness and the friction factor values.
Pipeline – Flow
For pipelines, the equations used to interrelate capacity, diameter, and pressure drop have
evolved concurrently with the growth in gas utilization. There are several equations used
in the industry for calculating the flow of gases in pipelines. As line pressures increased
along with pipeline size, more complex equations were required. Data was taken from
the pipeline test systems and correlated. This process has continued. Hence, there is not
one universal gas flow model equation that is superior under all conditions for all gases.
The most common gas pipeline flow equation is the Weymouth4 equation, which is
generally preferred for smaller-diameter pipelines such as gas gathering lines and pipe
with diameters less than sixteen inches. Other equations that are also frequently used are
the Panhandle A, Panhandle B5 (modified Panhandle), and AGA formula6. All of the
equations used depended on the friction factor correlation being used and the method of
incorporating the friction factor. Weymouth’s equation is based on friction factor being a
function of the diameter only. The Panhandle formulas are based on friction factor with
the friction factor being a function of the Reynolds number, or some modified version
thereof. The equations presented here are not all that have been advanced, but each has
been used widely. The choice is often arbitrary, based on policy, government
regulations, or merely personal choice.
Weymouth4
Weymouth’s equation has been widely accepted in industry, yet has been used far beyond
the original intent. The equation was designed for gas line operations at pressures from
35 to 100 psig. It is important to realize that the formula concerning the design of higher-
pressure gas systems has been modified by including a gas compressibility factor
evaluated at mean gas line pressure and temperature.
EdLZT
PP
P
Tq
mmgsc
sc
3
85.0
2
2
2
149.433
Where implicit in the formula, the following friction factor must be included:
33.0008.0
df f
3
Where:
L= Pipe length, miles.
E= Pipeline efficiency, expressed as a fraction
d= Internal pipe diameter, in.
ff = friction factor, dimensionless
Psc= Standard pressure of the pipe, psia
P1= Inlet pressure of the pipe, psia
P2= Outlet pressure of the pipe, psia.
Pm= Mean pressure, psia.
q= Gas rate at Ts and Ps SCF/Day
Tm=Mean absolute temperature in line segment, 0R.
Tsc= Standard temperature of the Pipe, 0R.
Zm =Mean gas deviation factor, dimensionless.
g = Specific gravity of gas (Air =1.00)
Also Zm may be evaluated as a mean pressure given by:
21
2121
3
2
PP
PPPPPm
Industry wide experience indicates that data taken on small size field gathering lines
operating at 1600 to 3200 psig showed reasonable agreement between volumes predicted
by Weymouth’s formula and metered volumes. In addition, industry experience indicates
that the friction used by Weymouth in general is too high for large diameter lines.
Furthermore, for gas transmission through long pipelines, Weymouth’s equation is not
recommended. In general, Weymouth’s equation is conservative and can be used with
confidence in low-pressure field gas gathering system.
Panhandle A Formula5
With the rapid increase in the number of large diameter transmission pipelines, it soon
became evident that Weymouth’s equation was not entirely satisfactory in predicting
volumes and pressures under widely varying loads. To present a useful equation to
practicing engineers and operators for predicting flow performance in large diameter gas
transmission pipelines, Panhandle Eastern Pipeline Company conducted a series of
pressure drop tests of gas flow in a 24-inch (.609 m) pipeline. This led to the
development of the Panhandle “A” formula. As pressures and flow rates increased with
time, a second set of tests was performed. The results produced a different equation.
Hence, in order to distinguish between them, the equations that have emerged are
commonly called Panhandle “A” and Panhandle “B”.
The average efficiency factor of 0.92 normally used in the Panhandle “A” equation was
obtained from empirical experience with the metered gas flow rates corrected to standard
conditions. An efficiency factor of “1” may be considered to be a perfect line under
perfect operating conditions within a Reynolds Number range of 5,000,000 to
4
14,000,000. The actual capacity of a commercially installed line will always be less.
For smaller diameter pipelines, experts recommend that the factor should be smaller.
Similarly, for large diameter pipelines, such as 36-inch (.914 m) and larger, they found
the efficiency to be as high as 0.98. In addition, the efficiency varied markedly in
different sections of the pipeline.
There is no definitive answer concerning which of the two equations is better, although
Panhandle “A” probably is more widely used. Neither of the Panhandle formula
equations is particularly suitable for low pressure lines, such as those with less than 100
psi (690 kpa), pipeline diameter smaller than 8-inch (20 mm), and systems operating at a
Reynolds Number less than 100,000.
07881..1
87.435
sc
sc
P
Tq Ed
LZT
PP
gmm
6182.2
4606.5394..2
2
2
1 1
Implicit in this equation is the following equation for friction factor:
1461.
0192.0
d
qf
g
f
In the above equation, the units are the same as those used in the Weymouth equation.
Note this equation is recommended for use in smaller diameter pipelines ID < 16 inches.
Modified Panhandle, B Formula5
EdLZT
PP
P
Tq
gmmsc
sc 530.2
510.
961.
2
2
2
1
02.1
737
Implicit in the modified Panhandle A formula is the following equation for friction
factor:
03922.0
00350
d
q.f
g
f
Again, the units are the same as those used in Weymouth’s equation. Note that the
modified Panhandle formula was specifically designed for use with high pressure, large
diameter pipelines, i.e. > 16 inches I.D., where the flow rates may vary quite widely. In
terms of pipeline networks, Panhandle A is normally used for the smaller lateral lines and
the Modified Panhandle is used for the main lines. Most experts recommend using a
value of .9 to .92 for E (pipeline efficiency) for a dry gas flow through new pipe. Since
the pipe is subject to various degrees of corrosion, contamination (i.e., black powder,
5
salts, etc.), paraffin deposition, hydrate formation, this efficiency will decline with time,
even for a dry gas system. For larger diameter pipes, i.e. > 36 inches I.D., the efficiency
may be as high as .98.
The AGA Equations6
The AGA equations were developed to approximate partially and fully turbulent flow
using two different transmission factors. The fully turbulent flow equation accounts for
the relative pipe roughness /D, based on the rough-pipe law4. This equation uses the
following transmission factor:
D
f f
7.3log4
110
Transmission factor can be roughly defined as the capacity of a pipeline relative to
pressure drop.
When the transmission factor for fully turbulent flow is substituted in the general energy
equation, the AGA equation for fully turbulent flow becomes:
EdZTL
PPD
P
TQ
avgavgmgsc
sc 5.2
5.02
2
2
110
7.3log477.38
The partially turbulent flow equation5 is based on the smooth pipe law and is modified to
account for drag-inducing elements. The transmission factor for this equation is:
6.01
Relog4
110
f
ff
f
The general equation for Steady State, Isothermal flow is:
EdZTL
PP
fP
TQ
avgavgmgfsc
sc 5.2
5.02
2
2
1177.38
6
Substituting ff
1 from above equation into the general energy equation for steady state,
isothermal flow would yield:
EdZTL
PP
fP
TQ
avgavgmgfsc
sc 5.2
5.02
2
2
1
1
Relog477.38
When dealing with a partially turbulent flow, a frictional drag factor must also be applied
to account for the effects of pipe bends and irregularities.
Pipeline Efficiency (E)
With most gas pipeline equations, an efficiency (E) usually is added to correct for small
amounts of liquid, general debris, weld resistance, valve installations, line bends, and
other factors which reduce gas flow rate below the basis rate predicted by the equation1.
The design value of efficiency E in a new clean gas line usually is estimated at 0.92.
Some operators back-calculate an E value from line operating data and “pigging” when
the value reaches a number lower than some set standard. Some pipeline companies
arbitrarily use a graduated efficiency, such as:
E = 0.85 - adverse (corroded), unpigged, old, dirty pipe
E = 0.92 - average to good condition, normal pipe design
E = 0.95 - excellent conditions with frequent pigging
E = 1.00 - new straight pipe without bends, seldom used in pipeline design
Pipeline efficiency can vary between 85 and 95 per cent, and an average value of 92 per
cent is often used. If the inside walls of the pipe are clean and smooth, and if the pipeline
is in perfect condition, an efficiency of 100 per cent can be attained. With standard piping
and compression design considered, it is common for the velocity to be that of enhanced
efficiency in many clean, large diameter, gas transmission cross-country pipelines and to
range from 10 to 17 feet per second or greater. Velocities below 10feet per second can
result in liquid and contaminant fallout.
Transmission Factor – Friction factor
Included in the AGA Equation is the transmission factor (1/ff). Transmission factor can
be roughly defined as the capacity of a pipeline relative to pressure drop. Moody’s
(1944) friction factor diagrams7 - as seen in Figures 1A & 1B, depict a plot of friction
factor, ƒ, as a function of Reynolds number, NRe and relative roughness, /D. In addition,
newly corrosion-resistant pipe is being utilized worldwide. Consequently, absolute
surface roughness values for these recently-fabricated pipes are required to properly
7
model the piping hydrodynamics. Farshad et al. 8,9,10 provided the relative roughness for
internal coated and bare Cr13 pipe surface profiling technology. Their results were
compared to Moody’s data by plotting the lines on Moody’s pipe roughness chart as
shown in Figure 3.
Fluid flow ranges in nature between two extremes, laminar and turbulent flow. In
laminar flow, friction factor is independent of surface roughness of the pipe. For flow in
the transition regime and in the turbulent regime, determination of the absolute pipe
roughness is necessary for obtaining a value of the friction factor. In turbulent flow, with
Reynolds numbers in excess of 2100, the friction factor is dependent on the Reynolds
number as well as pipe relative roughness. Dimensional analysis of pressure losses in
piping also shows the dependence of the friction factor on these parameters. The effects
of deterioration with age due to corrosion, contaminant deposition, erosion, and scale
buildup considerably increases the roughness factor, thereby reducing the pipe’s effective
diameter. Any appreciable increase in surface roughness must be adjusted.
The inside wall of commercially manufactured API high-pressure line pipe (API 5 LX)11
is not smooth. In turbulent flow, the surface roughness affects the friction factor, and thus
the pressure gradient in the pipe. The degree of surface roughness 8,9,10 in the pipe wall
is a function of the pipe material, method of descaling, and the environment to which it
has been exposed. For a given pipe diameter, the higher the transmission factor, the more
efficiently the pipe is being utilized. In addition, the higher the pipeline’s line pack
(pressure closest to but not over the maximum allowable operating pressure), the higher
the transmission factor and the greater the storage capacity of product in the pipeline.
Thus properties affecting the transmission factor are dependent upon the pipeline’s
operating flow regime. Two flow regimes often encountered in natural gas transmission
are partially turbulent flow and fully turbulent flow.
Flow Regimes
When a pipeline is operated in the partially turbulent regime, the main gas flow stream is
protected from contact with the pipe’s inner surface by a slower moving layer of gas
known as a boundary layer12. Therefore, the condition of the pipe surface has little effect
on pipeline performance in partially turbulent flow. In this regime, the transmission
factor is only a property of thruput. When thruput is increased, the transmission factor is
increased. This is due to transmitting more gas with little increase in drag (friction) due to
the protective boundary layer. Partially turbulent flow is predominant in large diameter,
low flow velocity systems.
When in partially turbulent flow, an increase in thruput indicates a more effectively used
pipeline. But as thruput continues to increase, the boundary layer is decreased.
Eventually, with further increases in thruput, the boundary layer will become so thin that
the pipe’s inner surface will be exposed to the main flow stream. At this point, the flow
is acted upon by the rough surface and becomes fully turbulent. Since further increases
in thruput will also increase drag, due to the exposed surface, the transmission factor
becomes a constant. The thruput at which fully turbulent flow will develop depends upon
the roughness of the internal pipe surface. The value of the fully turbulent flow
8
transmission factor will, therefore, also depend on surface roughness. For a given pipe
diameter, a lower surface roughness will indicate a higher fully turbulent transmission
factor or a more effective and efficient pipeline. Fully turbulent flow is predominant in
moderate to small diameter, high flow velocity systems.
Factors Affecting Flow Modeling
Many offshore gas pipeline designs have been performed using single-phase flow
equations with an efficiency factor, which is adjusted with flow rate. Researchers have
shown that the efficiency does not change with flow rate for horizontal lines, and that the
efficiency does in fact change with corrosion, contaminant deposition, liquid loading and
the inclination angle of the pipe. Flanigan13 and Baker14 were the first to recognize that
the efficiency changed with increase in liquid loading.
A) Liquid Loading of the Gas Stream - Liquid may be introduced into the flow stream
from several sources (i.e., hydrostatic tests, carryover upsets from oil & gas production,
upsets from gas storage fields, gas exchange points, condensation effects, etc.) and in
most cases offshore pipelines are transporting “wet gas”, even though field operations
consider the line “dry”. In addition, there is usually some consideration of either water or
hydrocarbon components as the gas is transmitted through the pipeline. Furthermore,
many pipeline contracts call for the mixing of certain volumes of liquid hydrocarbons
(BTU value) to be moved with the gas. Flanigan13 and the AGA5 have established that
the single-phase gas flow efficiency decreases with increasing liquid loading.
B) Pipeline Elevation Changes – When gas pipelines are considered to be dry gas
systems, it is reasonable to neglect elevation changes. However, elevation will have a
pronounced affect on the performance of a wet gas pipeline. Elevation has an especially
pronounced effect when it concerns gas and liquid upstream pipeline flow. The liquid
will tend to accumulate or “holdup” on the downstream side of the pipeline allowing the
gas to “slip” by on the topside of the pipe. Offshore pipelines exhibit some degree of
inclination, and a slight rise over the entire length of the line can significantly increase
the liquid holdup. Consequently, the liquid holdup is a function of flow regimes, flow
rates, pipe diameter, and many other variables as has been shown by many investigators
including Beggs and Brill15.
C) Black Powder - Black Powder contamination occurs in most gas pipelines and can
be described as any of several forms of iron sulfide or iron oxide with other contaminants
such as water, oils, salts, sand and dirt. In wet gas pipelines, it may appear visually as a
wet tar-like slurry substance. In dehydrated gas transmission systems, it can be described
as a dry, very fine black powder or “smoke-like”. Black powder will fill pitted areas on
internal pipe surfaces masking anomalies and can create protrusions, which vary in
height, width, length, shape and will directly affect the surface roughness of the pipe, and
hence, reduce the flow efficiency of the pipeline16.
D) Multi-Phase Flow- In turbulent flow, the surface roughness affects the frictional
pressure drop. As previously stated, the degree of surface roughness on the internal pipe
9
wall is a function of the pipe material, method of descaling, environment to which it has
been exposed, and the pigging frequency of the pipeline. Based on the above factors, the
relationship between single-phase flow efficiency and two-phase flow correlation must be
developed. When two-phase flow is considered, three parameters must be determined to
map out the hydrodynamics inside the pipeline: 1) the liquid holdup, 2) two-phase
friction factor, and 3) flow patterns or regimes. The holdup is the in-situ volume fraction
accounting for slippage. The value of liquid holdup depends on flow regime, inclination
angle, flow rates, mixture fluid properties, and Froude number. There are several
correlations available for multi-phase flow in pipelines. The authors prefer the Beggs
and Brill correlation15 for many reasons well established in the literature. In addition,
multi-phase flow correlations are too lengthy to present here and are out of the scope of
this article.
Field Case Histories
Two cases will be considered illustrating how surface roughness affects pipeline
operations17. The first will show how pipe roughness in a pipeline limits thruput and thus
gas sales when operating near maximum capacity. The second will show how roughness
will affect pressure drops and resulting fuel requirements necessary when excessive
horsepower is required.
Thruput Enhancement
For a pipeline or flow line operating near maximum capacity, the thruput will be limited
by a maximum allowable pressure drop due to pressure ratio limits at the compressor
station downstream. By decreasing the pipe’s internal surface roughness, a higher
thruput can be obtained without increasing the pressure drop.
The amount of additional thruput available will depend on the line’s diameter, pressure
range, original roughness, and how much the interior surface roughness is improved.
Two typical cases are shown in Figures 2 and 3. These curves represent the results from
pigging operations in two valve sections of the XYZ Line. The field data used to create
these graphs are shown in Tables 1 and 2. The original pipeline roughness is indicated by
the dashed line labeled “Before Pigging”. Other measured roughness is given for 3
months after pigging and 5 months after pigging. As shown, pipeline revenue is a
function of thruput. It is clear that thruput is drastically reduced in the first three months
of operation due to black powder contamination and other factors.
The bottom curves show a projected thruput versus effective surface roughness for the
same pressure drop measured in the before-pigging test. The top curves represent
revenues in sales versus roughness, assuming all additional thruput could be sold. Note
that the lines tend to revert back with time to a higher surface roughness and reduced
flow efficiency. Additional piggings or other measures will be required to maintain
optimization of system operation in this pipeline.
10
Efficiency Savings
Figures 4 and 5 represent surface roughness studies on two additional large diameter
pipelines (Lines AAA and BBB), each with 60 mile plus in length pipeline-combined
valve sections. These figures illustrate the effect of pipeline roughness on the pipeline
downstream pressure and the downstream station fuel cost. The field data used to
generate Figures 4 and 5 are shown in Tables 3 and 4.
With fixed thruput and pipeline upstream pressure, a pipeline section can achieve a
higher downstream pressure by decreasing the surface roughness of the pipe 9,18 .
A higher suction pressure (therefore, a lower compression ratio) will result in a lower fuel
cost at the downstream compressor station. The amount of fuel savings depends on the
degree of the roughness improvement. It is important to note that there will exist a
roughness value beyond the point of which the downstream compressor station will not
be able to compress the gas to the desired discharge pressure (i.e. station compression
ratio is too high). This can constitute a serious problem to a pipeline system. The mixed
effect of the lower discharge pressure and the higher line pressure drop, resulting from
too high a pipeline roughness, can cause a chain reaction in the pipeline system to a point
that the system will no longer deliver the gas at the desired pressure.
Surface Roughness Parameters
Table V utilizes the results from the actual tests on the XYZ Line to illustrate typical
variations in thruput for various degrees of line surface improvement. An ideal
roughness of 500 micro-inches could possibly be obtained from a thorough and complete
pigging operation on internally bare steel pipe19. In order to obtain this roughness, many
consecutive brush and scraper pigs would have to be run. On the XYZ Line, only a few
pigs were run, thus the resulting roughness was somewhat higher. For an internally
coated pipeline, an ideal roughness of 200 micro-inches could possibly be obtained. The
smooth internally coated surface would experience over time less contamination build-up
(drag). On a recently pigged internally bare steel pipeline, regularly scheduled pigging
will be required in order to maintain a minimal roughness; whereas, on an internally
coated (smooth) line, regular pigging will probably not be necessary. A company savings
in manpower, fuel savings (compressor horsepower) and pig-corrected pipeline flow
restrictions can be realized in an internally coated pipeline.
Table VI illustrates the variations in compressor fuel utilization that could theoretically be
attributed to a change in the surface roughness of the AAA and BBB pipelines. The
values given in Tables V and VI apply only to those valve sections. As the surface
roughness in each valve section decreases, the thruput variation values (Table V), and the
fuel consumption variation values decrease (Table VI). While they are somewhat
representative of the other valve sections on the pipeline system, each section must be
evaluated independently in order to determine the actual effects of pipeline internal
surface improvement.
11
Guidelines for Pipeline Flow Efficiency Application
Table VII is a pipeline flow efficiency questionnaire designed to aid field engineering
personnel in acquiring pertinent field data. The data will be useful in determining current
flowing pipeline efficiency, as well as, to assist in improving future pipeline
performance.
Conclusion
The most accurate approach for evaluating a pipeline’s performance involves defining its
surface roughness, transmission factor, and pipeline efficiency. All three factors can be
used to reflect the increase or decrease in pipeline hydraulics as it relates to operating
costs. But, these numbers are not self-explanatory and they do require some analysis to
determine their meaning. The term “efficiencies”, or adjustment factors, have been
applied to these transmission line flow equations in the past to compensate for
discrepancies.
Field data has shown that these efficiencies must be determined to correlate predicted gas
equation behavior to agree with flow data. Based on the effects of velocities,
compression, inclinations, pressures and surface roughness associated with the gas being
transmitted through the pipeline system, emphasis must be placed on the point to point
determination of resultant pressure drops as it relates to flow efficiency.
With expanded emphasis on maintaining the integrity of the world’s aging pipeline
infrastructure, as well as, emphasis on pipeline efficiency relating to transmission
company profits for shareholders, pipeline engineers may use the presented field studies
on which to model their pipeline system flow optimization programs.
A rigorous design of an offshore pipeline subject to simultaneous flow of gas and liquid
must use a multi-phase flow correlation in order to account for all the important variables
in the pipeline system.
12
Nomenclature
qsc= gas rate at Tsc, Psc
P1 = upstream Pressure
P2 = downstream Pressure
P = absolute pressure
Psc= pressure, standard conditions
Tm= mean absolute temperature of line
Tsc= temperature, standard conditions
Tg = ground temperature
d = inside diameter of pipe
L = pipe length
= viscosity
g = gas specific gravity ( Air= 1.0)
S = gas specific gravity ( Air= 1.0)
Zm= mean compressibility factor
ff = friction factor, dimensionless
E = pipeline efficiency
Re = Reynolds number
K = constant dependent on units used in table
1/f = transmission factor
= pipe absolute surface roughness
D=inside diameter of pipe
scf/d
psia
psia
psia
psia oR oR oR
in.
mile
lb./ft-s
--
--
--
--
--
--
--
--
ft
ft
References
1. Katz, D.L. et al.: Handbook of Natural Gas Engineering, McGraw-Hill Book Co.,
New York City (1959) 625.
2. Arnold, K.E.: API RP 14E - “Recommended Practice for Design and Installation of
Offshore Production Platform Piping Systems” Paragon Engineering Services, Inc.,
NACE Gulf Coast Corrosion Control Seminar, Houston, Texas, 1995.
3. Klohn, C.H.: “Flow Test on Internally In-Place Coated Pipe” Pipeline Industry, July
1959.
4. T. R. Weymouth, Transactions of the American Society of Mechanical Engineers,
Vol. 34, 1912.
5. Campbell, John M.: “Gas Conditioning and Processing”, Norman, Oklahoma, 1969.
6. Gas Processors Suppliers Association, Engineering Data Book, Volume II.
13
7. Moody L., Friction Factors for Pipe Flow, Trans. ASME, 66, 1944.
8. Farshad, F., Rieke, H., and Garber, J.: “New Developments in Surface Roughness
Measurements, Characterization, and Modeling Fluid Flow in Pipe,” Journal of
Petroleum Science and Engineering (2001) 29, No. 2, 139.
9. Farshad, F., and Garber, J.D.: “Relative Roughness Chart for Internally Coated Pipes
(OCTG),” paper SP 56587 presented at the 1999 54th SPE Ann. Fall Tech. Conf.
Exhibit., Houston, Texas.
10. Farshad, F., Pesacreta, T.C., Bikki, S.R., and Davis, D.: “Surface Roughness in
Internally Coated Pipes (OCTG),” paper OTC/SPE 11059 presented at the 1999 Ann.
Offhsore Tech. Conf. Exhibit., Houston, Texas.
.
11. Craig, B.D.: Practical Oilfield Metallurgy and Corrosion. 2nd Edition, Pennwell
Books Co. Inc., Tulsa, OK, 258 pp.
12. C. F. Colebrook, “Turbulent Flow in Pipes with Particular Reference to the Transition
Region Between the Smooth and Rough Pipe Laws”, J. Inst. Civil Engineers, London,
1939.
13. Flanigan, O.: “Effect of Uphill Flow on Pressure Drop in Design of Two-Phase
Gathering Systems” Oil and Gas Journal, March 10, 1958, pp. 132-141.
14. Baker, O., et al.: “Gas-Liquid Flow in Pipelines, II. Design Manual” AGA-API
Project NX-28, October, 1970.
15. Beggs, H.D., Brill, J.P., 1973.: “A Study of Two-Phase Flow in Inclined Pipes”
J. Pet. Technol. 25, 607-617.
16. Winters, R.H.: “The Black Powder Problem in Gas Pipelines” presented at the 2002
Pipeline Pigging, Integrity Assessment, and Repair Conference, Houston, Texas.
17. Choate, L.C., Unpublished Research, “Discussion of Transmission Factor Surface
Roughness and Pipeline Efficiency as Related to Research Findings and Verified
Under Actual Field Conditions”, Huntsville, Texas, 2001.
18. Rauschenberger, R.R., “Chemical Pigging Boosts Results” Gas Utility and Pipeline
Industry, November 1999, p. 28.
19. Choate, L.C., “Developing and Advancing the State-of-the-Art Technology of the In-
Situ Internal Cleaning and Coating of Oil & Gas Pipelines” CORROSION/2001,
Houston, Texas, Paper #01612
14
Table I
Pipeline Valve Section XYZ-1 to XYZ-2
Upstream Pressure, PSIG
Downstream Pressure, PSIG
Upstream Temperature, 0F
Downstream Temperature, 0F
Upstream Elevation, Feet
Downstream Elevation, Feet
Pipe diameter, Inches
Pipe Length, Miles
Gas Gravity (Air=1)
January 1993 Roughness Micro-inches
December 1993 Roughness Micro-inches
February 1994 Roughness Micro-inches
Original Thruput, MMCFD
December 1993 Projected Thruput, MMCFD
December 1993 Thruput Increase, %
February 1994 Projected Thruput, MMCFD
February 1994 Thruput Increase, %
1011
861
75
51
1787
1358
23.25
19.110
0.577
4796
1413
2383
469.9
528.5
12.5
503.4
7.1
15
Table II
Pipeline Valve Section XYZ-3 to XYZ-4
Upstream Pressure, PSIG
Downstream Pressure, PSIG
Upstream Temperature, 0F
Downstream Temperature, 0F
Upstream Elevation, Feet
Downstream Elevation, Feet
Pipe diameter, Inches
Pipe Length, Miles
Gas Gravity (Air=1)
January 1993 Roughness Micro-inches
December 1993 Roughness Micro-inches
February 1994 Roughness Micro-inches
Original Thruput, MMCFD
December 1993 Projected Thruput, MMCFD
December 1993 Thruput Increase, %
February 1994 Projected Thruput, MMCFD
February 1994 Thruput Increase, %
1027
933
68
54
1308
1445
23.25
15.238
0.577
3831
1600
2052
469.9
528.5
12.5
503.4
7.1
16
Table III
Pipeline Valve Section AAA-1 to AAA-2*
Date
Station AAA-1 Discharge pressure, PSIG
Station AAA-2 Suction Pressure, PSIG
Station AAA-2 Discharge Pressure, PSIG
Upstream Temperature, 0F
Downstream Temperature, 0F
Upstream Elevation, Feet
Downstream Elevation, Feet
Pipe Diameter, Inches
Pipe Length, Miles
Gas gravity (air=1)
Thruput, MMCFD
April 12th, 1994
865
606
793
114
65
218
635
29.25
64.06
0.572
1667.1
* Estimated Station AAA-2 Fuel Rate:
(at constant thruput)
)1(54.32 21875.0 ratioThruputMCF
FuelCF
where Ratio is station compression ratio.
17
Table IV
Pipeline Valve Section AAA-1 to AAA-2*
Date
Station BBB-1 Discharge pressure, PSIG
Station BBB-2 Suction Pressure, PSIG
Station BBB-2 Discharge Pressure, PSIG
Upstream Temperature, 0F
Downstream Temperature, 0F
Upstream Elevation, Feet
Downstream Elevation, Feet
Pipe Diameter, Inches
Pipe Length, Miles
Gas gravity (air=1)
Thruput, MMCFD
January 31st, 1992
819
615
820
114
54
235
390
29.25
62.82
0.572
562.637
* Estimated Station AAA-2 Fuel Rate:
(at constant thruput)
)1(83.44 21875.0 ratioThruputMCF
FuelCF
where Ratio is station compression ratio.
18
Table V
Roughness
(Micro Inches)
Thruput
(MMSCFD)
Thruput
Variation
(%)
Pipe Line Section
XYZ-1 to XYZ-2
Base Condition
Assumed Conditions
4796
2000
1500
500
200
469.9
511.7
525.8
578.4
622.1
--
+8.9
+11.9
+23.1
+32.4
Pipe Line Section
XYX-3 to XYZ-4
Base Condition
Assumed Conditions
3831
2000
1500
500
200
416.9
444.0
455.7
501.5
539.5
--
+6.5
+9.3
+20.3
+29.4
19
Table VI
Roughness
(Micro Inches)
Thruput
(MMSCFD)
Fuel
Consumption*
Variation (%)
Pipe Line Section
AAA-1 to AAA-2
Base Condition
Assumed Conditions
700
2000
1500
500
200
7929
11143
10111
7156
5462
--
+40.5
+27.5
-9.7
-31.1
Pipe Line Section
BBB-3 to BBB-4
Base Condition
Assumed Conditions
700
2000
1500
500
200
5946
7906
7264
5492
4516
--
+33.0
+22.2
-7.6
-24.1
Thruput on AAA line is 1667.1 MMSCFD
Thruput on BBB line is 562.6 MMSCFD
* The negative fuel consumption values represents fuel savings.
20
Table VII GAS PIPELINE FLOW EFFICIENCY QUESTIONAIRE
The following information should be supplied by field personnel on the actual parameters
affecting the segment of gas pipeline under study for flow efficiency.
Company: _______________________________________ Date: ______________
Company Address: _____________________________________________________
Pipeline Identification (Location): _________________________________________
Contact/Operator: ______________________________________________________
Phone: _________________________ E-mail: _____________________________
Type of Product: __________________________ Specific Gravity: ____________
Flow Rate: ________________ (SCF/D) Standard Temperature: ___________ (F)
Standard Pressure: __________ (psig) Velocity: ______________ (feet per second)
Commercial steel pipe (Manufacturer): _______________________Age: _____ (yrs.)
O.D. ______ (in.) I.D. _____ (in.) Wall thickness: _________________ (in.)
Segment Length under study: _________________________________(miles)
(i.e., distance in miles between beginning and end of segment)
Piggable: Yes ( ) No ( )
Upstream compressor station: Suction pressure: ___ psi Discharge pressure: ___ psi
Downstream comp. station: Suction press: _____ psi Discharge pressure: _____ psi
Pipeline Inlet Temperature: _______F Pipeline Outlet Temperature: _______F
Any internal corrosion or leak history? (I.D. surface roughness question) __________
_____________________________________________________________________.
Type of efficiency problem (if known):
a.) Low flow ______
b.) Solids _________
c.) Sludge ________
d.) Scale _________
e.) Filtration ______
f.) Paraffin _______
g.) Other _______________________________
21
Figure 1 A. Pipe Roughness after Moody1
22
Figure 1 B. Friction factor Chart after Moody1
23
Figure 2. Comparison of relative roughness plots for internally coated pipes,
commercial steel, and drawn tubing
0.000001
0.00001
0.0001
0.001
0.01
1 10 100
Diameter, D(inches)
Rela
tive r
ou
ghn
ess, e/D
Commercial Steel ( after Moody)
Internally coated (after Farshad et al.)
Draw n Tubing (after Moody)