With the ever increasing need to optimize production, the accurate
understanding of the mechanics of multi-phase flow and its effect on the
pressure drop along the oil-well flow string is becoming more
pertinent. The efficient design of gas-lift pump, electric submersible
pumps, separators, flow strings and other production equipment depends
on the accurate prediction of the pressure drop along the flow pipe.
Pressure is the energy of the reservoir/well and it is crucial to
understand how a change in fluid properties, flow conditions and pipe
geometric properties affect this important parameter in the oil and gas
industry. Extensive work on this subject has been done by numerous
investigators albeit in small diameter pipes. Reliance on the empirical
correlations from this investigators has been somewhat misleading in
modelling pressure drop in large diameter pipes (usually >100 mm)
because of the limitations imposed by the diameter at which they were
developed and the range of data and conditions used in deriving them.
In this work, experimental data from the experimental study by Dr.
Mukhtar Abdulkadir was used as the data source. The gas velocities,
liquid velocities, film fraction, gas and liquid properties and the pipe
geometric properties from the above mentioned experiment were used to
model the frictional and total pressure drop from six correlations.
Results were analyzed and compared with the experimental results.
1.1 General introduction
Profitable production of oil and gas fields relies on accurate prediction of the multi-phase well
flow. The determination of flowing bottom-hole pressure (BHP) in oil wells is very important
to petroleum engineers. It helps in designing production tubing, determination of artificial lift
requirements and in many other production engineering aspects such as avoiding producing a
well below its bubble point in the sand-face to maintain completion stability around the wellbore (Ahmed, 2011). Well
fluids above bubble point pressure exist as a single phase as it is
being produced from the reservoir. However, as they navigate their way
through the network of interconnected pores in the reservoir to the
wellbore, there is a continuous reduction in pressure as overburden
stress is gradually reduced. This phenomenon leads to the liberation of
the entrained gas. As the single-phase fluid rises in the tubing, a
critical point is reached where some of the gases begin to come out of
solution along the length of the pipe. In other words, it changes from
single-phase flow to multi-phase flow.
This leads to some level of complexity as regards to the
identification of the physical properties of the individual phases, the
flow pattern, the relative volume occupied by the separate phases inside
the pipe, and most importantly the implication of the phase separation
on the pressure drop along the well tubing string.
Although most if not all calculations for flow lines in multiphase
production systems have been and continue to be based on empirical
correlations, there is now a strong tendency to introduce more
physically based (so called mechanistic) approaches to supplement if not
replace correlations. This is because the latter are well known for
their unreliability when applied to systems operating under conditions
different to those from which the correlations are derived; such
conditions encompass: pressure, temperature, fluid properties and pipe
diameter. Furthermore, correlations exist for limited geometrical
configurations (i.e. vertical or horizontal pipes) and simple physical
phenomena (no mass transfer between phases, constant temperature, etc.).
With the advent of more complex production systems involving deviated
wells as well as the move to exploit gas condensate resources the
production of which will inevitably involve strong mass transfer
effects, calculation methods will be required to account for such