Page 78 - Handbook Of Multiphase Flow Assurance

Hydraulic restrictions boundaries and management 73

E = efficiency, typically E = 0.92; D = diameter [inch], L = length [miles], Z = gas compress-
ibility at average conditions, T = inlet gas temperature [°R], S = gas gravity relative to air, P 1
= upstream pressure, P 2 = downstream pressure [psia].
Average conditions for gas compressibility are estimated as log-mean temperature and
line-average pressure.
+
T AVERAGE = T AMBIENT ( T − T OUT )/ln( ( T − T AMBIENT )/( T OUT − T AMBIENT ))
IN
IN
T
2
3
.
P AVERAGE = 0 667 P ( IN 3 − P OUT ) ( P IN 2 − P OUT )
/
Compressibility may be estimated with McCain or Hanafy correlations. Alternatively it
may be looked up in property tables.
Typical pressure drop for a gas flow line from a well to a processing facility is around
0.5 bar per km or 12 psi per mile. For multiphase lines the pressure drop may be as high as
10 bar per km, but typically is less. If the pressure drop is higher than this, then the backpres-
sure on the wells is high and reservoir may produce less. If the pressure drop is lower, then
the pipe may be oversized and capital cost may reduce profitability. Export pipelines will
have different pressure drops.
A similar performance comparison is possible for a multiphase flow line from a well to a
processing facility. The main objective of a multiphase flow calculation similarly is to find
pressure drop in a line of a given size. Secondary objective is to forecast conditions to mini-
mize the occurrence of a slugging flow regime. Evaluation of a multiphase flow pressure drop
is more complex than for a single phase flow and involves series of formulaic or graphic-
analytical computations, with or without account for the gas-liquid dispersion flow regime.
Virtually all multiphase flow pressure drop calculations are done by computer software, with
the account for the flow regime.

Hydraulics technologies
A number of technologies may help economically produce fluids from a distant asset.
Technologies which should be considered in formulating an asset development project con-
cept may include the following:

• Hydraulic lines of different size and insulation type and thickness
• Slug catcher vessel
• HIPPS system
• Periodic scraping
• Production chemical
• Subsea booster pump
• Subsea multiphase pump
• Subsea gas separator if proven for use in the region
• Subsea water separator if proven in the region
• Riser base caisson gas separator if proven in the region
• Downhole and/or riser base gas lift
• Drag reducing agent chemical
• Active heating of flowlines with electrical energy or with heating medium fluid