RP 14E: Offshore Production Platform Piping Systems 23

d. Compressor Piping. Reciprocating and centrifu- gal compressor piping should be sized to minimize pulsation, vibration and noise. The selection of allowable velocities requires an engineering study for each specific application.

e. General Notes. (1) When using gas flow equations for old pi

build-up of scale, corrosion, liquids, parafg : etc., can have a large effect on gas flow efficiency.

(2) For other .empjrical equations, refer to the GPSA Engineering Data Book.

2.5 Sizing Cri ter ia f o r Gas/Liquid Two-Phase

a. Erosional Velocity. Flowlines, roduction mani- folds, process headers and other Enes transporting gas and liquid in two-phase flow should be sized primarily on the basis of flow velocity. Experience has shown thaq loss of wall thickness occurs by a process of erosion/corrosion. This process is accel- erated by high fluid velocities, resence of sand, corrosive contaminants such as 802 and HzS, and fittings which disturb the flow path such as elbows.

The following procedure for establishing an “ero- sional velocity’ can be used where no specific information as to the erosive/corrosive properties of the fluid is available.

(i) The velocity above which erosion may occur can be determined by the following empiri- cal equation:

Lines.

ve = c (pm

Eq. 2.14

where:

Ve C = empirical constant

pm

= fluid erosional velocity, feet/second

= gas/liquid mixture density at flowing pressure and temperature, lbs/fts

Industry experience to date indicates that for solids-free fluids values of c = 100 for continuous service and c = 125 for intermittent service are conservative. For solids-free fluids where corrosion is not anticipated or when corrosion is controlled by inhibition or by employing corrosion resistant alloys, values of c = 150 to 200 may be used for continuous service; values up to 250 have been used successfully for intermittent service. If solids production is anticipated, fluid velocities should be significantly reduced, Different values of *“c” may be used where specific application studies have shown them to be appropriate.

Where solids and/or corrosive contaminants are present or where “c” values higher than 100 for continuous service are used, periodic surveys to assess pipe wall thickness should be considered. The design of any piping sjrstem where solids are anticipated should consider the installation of sand probes, cushion flow tees, and a minimum of three feet of straight piping downstream of choke outlets. (2) The density of the gaslliquid mixture may

be calculated using the following derived equation:

12409SiP + 2.7 RSgP Eq. 2.15 198.7P + RTE pm =

where : P = operating pressure, psia. Si = liquid specific gravity (water = 1;

use average gravity for hydrocarbon- water mixtures) at standard conditions.

R = gasfliquid ratio, fts/barrel a t standard conditions.

T = operating temperature, “R. Sg = gas specific gravity (air = i) at standard

B = gas compressibility factor, dimensionless. (3) Once Ve is known, the minimum cross-

sectional area required to avoid fluid erosion may be determined from the following derived eauation:

conditions.

ZRT 9.35 + - 21.25P Ve

Eq. 2.16 A =

where: A = minimum pipe cross-sectional flow

area required, in211000 barrels liquid per day.

(4) For average Gulf Coast conditions, T = 535”R, SI = 0.85 (35” API gravity oil) and Sg = 0.65. For these conditions, Figure 2.6 may be used to determine values of A for essentially sand free production. The mini- mum required cross-sectional area for two- phase piping may be determined by mul- tiplying A by the liquid flow rate expressed in thousands of barrels per day.

b. Minimum Velocity. If possible, the minimum velocity in two-phase lines should be about 10 feet per second to minimize slugging of separa- tion equipment. This is particularly important in long lines with elevation changes.

c. Pressure Drop. The pressure drop in a two-phase steel pi ing system may be estimated using a sim- plified garcy equation from the GPSA Engineer- ing Data Book (1981 Revision).

Eq. 2.17 0.000336f W2 A P = di5 Om - . where :

A P = pressure drop, psi1100 feet. di = pipe inside diameter, inches f = Moody friction factor, dimensionless.

pm = gaslliquid density at flowing pressure and temperature, lbs Ift3 (calculate as shown in Equation 2.15).

W = total liquid plus vapor rate, lbslhr. The use of this equation should be limited to a

10% pressure drop due to inaccuracies associated with changes in density.

If the Moody friction factor is assumed to be an average of 0.015 this equation becomes:

Eq. 2.17a

W may be calculated using the following derived equation:

where: W = 3180 Qg S g + 14.6 QI Si Es. 2.18

Qg = gas flow rate, million cubic feetlday (14.7 psia and 60°F).

S g = gas specific gravity (air = i). QI = liquid flow rate, barrelslday. Si = liquid specific gravity (water = 1).

It should be noted this pressure drop calculation is an estimate only.

COPYRIGHT 2003; American Petroleum Institute

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