Pump data are stored at 3 500 RPM. During equipment selection, recalculation is performed based on the frequency selected by the user. For details, see Pump.

A high head may be caused by a high WHP or frictional losses. Additionally, the total dynamic head is calculated using the fluid’s PVT properties and current operating parameters. This value differs from the nominal head which is typically determined using water.

All correlations are described in the corresponding section of this guide. For details, see Appendix A: PVT Correlations.

At the operating frequency.

Most likely, the pump has not been added. If this is the case, it is impossible to determine the pressure/temperature conditions at the intake, which means it is impossible to assess gas separation parameters in a non-flowing well before running the equipment. For details, see Pump.

In the Wellbore section, on the Deviation survey tab, click Add (+) to add a new row or click Paste () (or press Ctrl+V) to paste data from another table.
The inserted data must contain numerical values only. If the data includes a row with zero values or NaN (not a number) values, delete them after insertion.
For details, see Deviation survey.

The temperature gradient calculation is only possible after selecting the cable, as it depends on the properties of its conductors and insulation.

The length of the power cable is set automatically based on the pump setting depth. The lengths of the high temperature cable and motor lead extension (MLE) must be set manually. They are subtracted from the power cable length.
For details, see Cable.

Ensure that the cable is selected, as the data for calculating the surface electrical equipment is taken from this section. It is also necessary to verify that all equipment components—from the pump to the cable—are selected and the corresponding sections are filled out. For details, see Cable.

Both the friction and hold-up factors are taken into account when calculating the total pressure loss in the wellbore. The following formula is used:

ΔP=friction factor ΔP_f+ hold up factor ΔP_a  + ΔP_g where:

• ΔPf – frictional losses
• ΔPa – hydrostatic gradient
• ΔPg – losses due to phase acceleration

The default value of the friction and hold-up factors is 1. Values entered manually can be used for the purpose of testing or empirical data matching.

The swap angle defines the threshold at which vertical correlations are applied instead of horizontal ones. If the inclination angle is less than or equal to 45°, horizontal correlations are used. If the angle is greater than 45°, vertical correlations are applied.

IFT stands for interfacial tension. In multiphase flow calculations, it is used for the following purposes:

• Flow regime determination: IFT affects the shape of bubbles and droplets, influencing whether the flow is classified as bubbly, slug, or annular.
• Interfacial interaction calculations: IFT affects friction and phase distribution, which, in turn, affect pressure losses.
• Gas holdup estimation: IFT is used in empirical correlations (e.g., Duns & Ros, Hasan & Kabir) to estimate the fraction of gas retained in the liquid phase.

The Heat Transfer tab is designed to calculate the temperature distribution along the wellbore. To start, you need to specify input data such as surface and reservoir temperatures. Then, select a calculation method that will determine the required input parameters. For details, see Heat transfer.

The Hasan-Kabir method provides higher accuracy as it considers individual heat transfer coefficients for casing, tubing, cement, and the surrounding earth, as well as the thermal conductivity of the rock.

The Rough Approximation method uses a generalized heat transfer coefficient to estimate the temperature profile, making it simpler but less precise.