Domain of Gas & Oil well simulator
Reservoir pressure decreases as liquid is removed from the reservoir. At pressures above the bubble point, the oil, water, and reservoir rock must expand to fill the void created by the removal of liquid. The rock and remaining liquids are not very compressible. So a large decrease in pressure is necessary to allow the rock and remaining liquids to expand enough to replace a relatively small amount of oil produced. Thus, as long as reservoir pressure is above the bubble point, pressure decreases rapidly during production. At pressures below the bubble point, gas forms in the pore space. This free gas occupies considerably more space as a gas than it did as a liquid. Also, the gas readily expands as pressure decreases further. The forming and expanding gas replaces most of the void created by production. Reservoir pressure does not decrease as rapidly as it does   when pressure is above the bubble point. Excessive production of this gas is detrimental to maintenance of reservoir pressure.
During production, reservoir pressure will drop and the well reaches a point where slug flow will occur.
Slug flows are characterized by large pockets of gas, followed by large pockets of liquid. The bubble size is of the order of the pipe diameter, leading to a large rise velocity of the gas phase. A film of liquid exists around the pocket flowing downward relative to the gas bubble. This flow pattern has a negative influence on the production and gas-lift technique.

This flow regime is therefore strongly non-stationary. Strong fluctuations of the liquid flow rate and pressure are observed in this regime. Non steady state flowing systems are hard on surface separator facility (complete separation depends on a certain residence time in the separator). Varying density of the lifted liquid exerts a backpressure on the formation and decreases flow.
Gas & Oil well simulator
Gas & Oil well simulator is used to optimize the flow of the well.
Properties gas, oil and water
Simulator calculates the properties of gas, oil and water (such as densities, viscosities, interfacial tension and etc.) at any point of well by knowing wellhead (pressure and temperature) and bottom hole temperature:
When the composition of the gas, oil and water is known
When producing gas-oil ratio, gas specific gravity, and stock tank oil gravity are known.

Simulator calculates the flow of fluids from the reservoir to the wellhead through the completion string by using 4 famous methods for multiphase flow:

  1- Orkiszewski
  2- Govier and Aziz
  3- Hagedorn-Brown
  4- Hasan-Kabir

The flow regime, pressure, temperature, physical properties, liquid holdup, etc. is calculated for every foot of the wellbore. Velocity string can be specified anywhere along the wellbore. Well could be with different diameters.
The gas-lift technique is a gravity-based pumping technique used for recovering oil from a production well. Gas injected at the bottom of the production pipe reduces the gravity component of the pressure drop and thereby, stimulates the supply of oil from the reservoir. This results in an enhanced oil production.
A gas lift option is also included in the simulator. The injection depth can be specified anywhere along the wellbore with any composition of gas.
Water is often flowing together with the oil, forming a liquid mixture composed of a dispersed phase and a continuous phase, either oil drops in water (O/W), or water drops in oil (W/O). The transition from O/W to W/O, called the phase inversion, is accompanied by a sharp increase of the mixture viscosity, which, in turn, can give rise to an undesired increased pressure drop. Gas injection tends to increase the pressure drop around phase inversion which is undesired for gas-lift applications. Simulator calculates phase inversion if it occurs.
Over the life of a gas/oil well, pressure and gas flow rate will decrease. At some point, this situation would cause accumulation of liquids at the bottom of the well since the producing gas rate would be insufficient to lift all of the liquid, which will lead to erratic flow behavior and inevitably loss of production. If the symptoms of liquid loading are recognized at early stages, losses in gas production that may eventually cost the life of the well may be avoided. Production data history of a gas well can be informative about future production and future behavior of gas&oil well if properly analyzed. This prediction could be an important indication of future slug flow and liquid loading which eventually cause the well to deplete earlier than reservoir estimations and possibly die prematurely. By installing remedial solution, slug flow, liquid loading, earlier depletion and dead of a well could be prevented.

Small bubbles travel slower up through liquid column than big bubbles; the bubbles travel slower the total mass flow increases. When static mixer is used, it breaks slug and big bubbles to small and dispersed bubbles then the column of mixture of liquid and gas becomes lighter and pressure drop along wellbore decrease, so by the same quantity of gas total mass flow rate increase.
A powerful model of well when static mixers installed has been developed. Simulator indicates the right places and type of static mixers for installing.
At low pressure slug flow occurs, by installing adequate static mixers at right places of the well and injecting gas, slug flow and liquid loading will be prevented. Less gas is needed for injection when static mixers are used comparing to gas injection without using static mixers.

At moderate pressure slug flow may occur, by installing adequate static mixers at right places of the well slugs and big bubbles breaks to small and dispersed bubbles, then total mass flow rate increase  and liquid loading will be prevented without consuming external energy.
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Dynamic Systems Modeling