API RP 11V8:2003(2015) pdf download
API RP 11V8:2003(2015) pdf download.Recommended Practice for Gas Lift System Design and Performance Prediction.
• tinloading Pressure
The unloading pressure ftr each valve is used in the calculation to set the test rack pressure of each. The first valve (shallowest) has an unloading pressure nearly equal to the kickoff pressure. Succeedingly lower unloading valves have unloading gas pressures reduced by a pressure difference of about 25 psi between valves (10 psi is a minimum for low pressure systems up to So psi for high pressure systems). Each deeper unloading valve lowers the gas pressure until the operating valve, or orifice, and operating pressure is reached.
• Operating Pressure
The gas pressure needed for continuous operation at the point of lift. The pressure depends on whether a valve or orifice is used:
— when a valve is used, the operating pressure is controlled by the valve set pressure, port size, gas rate, temperature, and fluid production pressure.
— when an orifIce is used, the operating pressure is controlled by the orifice size, gas rate, and fluid production pressure.
Available operating gas pressure at the lift point is directly related to the number of unloading valves and the gas pressure difference between valves. For example. a well with a kickoff pressure of l(XX) psig, six unloading valves, and 25 psi gas pressure difference between valves, would have a surftice operating pressure of approximately l50 psig when lifting at the design point.
The valve design method affects the gas pressure difference that is used, which in turn affects operating pressure available at the point 01’ lift.
Thus the operatilig pressure available for i*clion is a function of:
• Compressor discharge pressure.
• Kickoff pressure at the casing.
• Number of unloading valves.
• Unloading gas pressure difference between valves.
New compressor systems and new wells should be designed to provide gas pressures to accommodate the highest productfly P1) wells, as these wells have the highest pressures needs. The lower P1 wells will he easily lifted with this design approach.
Existing systems may need revisions to maximize oil:
I. The first step is to make available the highest coinpressoc and kickoff pressure.
2. The next step is to reset (and possibly re-space) the valves to utilize this higher unloading pressure.
ThL1S. (he highest compressor discharge pressure will yield the highest kickoff, which will result in higher operating pressure. deeper liii. and more tutal fluid (and hopefully more oil).
RECOMMENDED PRACTICE: The gas supply should be the highest possible compressor pressure and should be dry (processed to reduce both water and hydrocarbon). This gives the steadiest supply with the highest kickoff and operating pressure that maximizes the oil production.
B. NI inimum Wellhead Pressure
Flowing wellhead pressure for a gas lifted well no choke at the wellhead or at the inlet to (he station) is dependent on:
• Reservoir pressure and productiviy.
• Density and friction pressure losses in the wellbore.
• Separator pressure plus flow line pressure losses due to friction, terrain effects, and elevation changes.
High reservoir pressure plus good productivity, and low density, gaseous Iluid result in the reservoir energy being transmitted to (he wellhcad, if tubular friction loss is not excessive. [.0W pressure at the inlet separator and a relatisely large flowline minimize the resistance to flow (hackpressure). Addition of lil gas aids welibore delivery hu( adds to friction losses in the hori7ontal Ilowline. and in the tubing. if the diameters are too small.
The minimum achievable wellbead pressure is a function of the hackpressure produced by:
• Separator pressure.
• Losses from terrain effects and elevation changes.
• Rate (velocity) induced flowline friction, which is caused by:
I. Tubular pipeline internal diameter.
2. Fluid propenies.
3. Gas-liquid ratio.
4. Liquid flow rate.
When the wellbore tubular. f1osline, and separator facility is designed, the anticipated well rate can be calculated and then reservoir withdrawal constraints (or regulatory limits) can be imposed. The tubing and flowline size to achieve the needed rate can then he selected.
l)uring this design calculation procedure.
