Task 9.1 Accumulation of sand and liquid
A vertical well produces gas and small amounts of water.
- gas density at downhole conditions
- f.v.f. at downhole conditions
- gas viscosity at downhole conditions
- density water, downhole conditions
- interfacial tension, gas and water
- inner diameter, production tubing
150 kg/m3
6.10-3 m3/Sm3
0.015 cP
1000 kg/m3
60 dyn/cm
10 cm
a)
Sand grains of diameter 0.1 mm and density 2400 kg/m3 may
be produced. Estimate gas rate to secure sand removal
b)
Estimate gas rate to avoid water accumulation
c)
Estimate maximum water droplet size
Task 9.2 Droplets in flowing gas
In Task 9.1 we found droplet velocity: 1.2 m / s According to the
Turner criterion, the gas speed should exceed this. At gas velocity
1.2m / s, we may assume wall friction factor: f = 0.02
a) Check if flow turbulence will affect droplet sizes.
b) Estimate the maximum droplet size
Task 9.3: Two-phase flow in the production tubing
The following data is given for an oil-well:
- Oil production:
- Gas content in reservoir oil:
- Lift gas injection
- Specific gas gravity:
- Specific oil gravity:
- tubing length
- inclination
1194 Sm3/d
110 Sm3/ Sm3
2.5.105 Sm3/d
0.7
0.84
2010 m
22o
At downhole conditions:
- solubility gas:
- formation volume factor, oil:
- formation volume factor, gas:
- temperature
- pressure
- viscosity, oil:
- viscosity, gas:
- inner diameter, production tubing
- interfacial tension:
- gas z-factor
210 Sm3/ Sm3
1.54 m3/ Sm3
4.52.10-3 m3/ Sm3
90 C
307 bar
0.5 cP
0.0012 cP
10 cm
10-3 N/m
0.95
Estimate at downhole conditions:
a)
b)
c)
d)
e)
Superficial velocity for liquid and gas.
Flux fraction
Flowregime.
Pressure gradient at downhole conditions
Tubing head pressure, by linear extrapolation
Task 9.4: Two-phase flow and pressure loss
From the previous exercise (9.3), we have estimated the following at
downhole conditions:
- superficial velocity, gas
- superficial velocity, oil
- gas density
- oil density
0.875 m/s
2.71 m/s
189 kg/m3
662 kg/m3
Additional data:
- viscosity, oil:
- viscosity, gas:
- inner diameter production tubing:
- inclination:
- production tubing length:
- inflow pressure:
- bubble distribution parameter:
- rise velocity of bubbles:
- friction factor correlation:
Estimate:
a)
Liquid and gas fraction.
b)
Liquid and gas velocity.
c)
Pressure gradient.
d)
Wellhead pressure
0.5 cP
0.0012 cP
10 cm
22 o
2010 m
198 bar
Co = 1.1
vo = 0.2 m/s
fo = 0.16/Rem0.172