DESIGN OF

ESP INSTALLATION

Reliable information on well productivityFluid rate = input parameterSelection of ESP highly dependent on the

flow rateDifferent pump have different recommended

application ranges

Data Requirement

1. Well Physical Data◦ Casing & liner sizes, weights and depths◦ Tubing size, type, weight & thread◦ Total well depth◦ Depth of perforation or open hole interval◦ Well inclination data

2. Well Performance Data◦ Tubing head pressure at desired rate (FTHP)◦ Casing head pressure◦ Desired liquid production rate◦ SBHP or static liquid level◦ FBHP or dynamic liquid level◦ Productivity data (PI or qmax for the Vogel Model)

Input Data

2. Well Performance Data-cont’d◦ Gas-oil ratio (GOR)◦ Water cut or water-oil ratio◦ Bottomhole temp at desired rate

3. Fluid properties◦ Specific or API gravity of produced oil◦ SG of water◦ SG of gas◦ Bubble point pressure◦ Viscosity of produced oil◦ PVT data

Input Data-cont’d

Input Data-cont’d

Conventional design

The specific gravity (SG) need to be known from the water cut

The SBHP need to be known

Well Inflow Calculations

oilwater SGSGSG

SGLLSBHP statperf 433.0

Based on the flowing pressure at perforations, the pressure at pumps’ intake pressure (PIP) is found from the following formula, if the fluid gradient in the annulus is known

To check the amount of free gas at the pump’s suction conditions, the solution gas-oil ratio at the pump intake is calculated from Standing’s bubble point pressure correlation:

5.13160

5141

Fsg oil@

. Oil API

By comparing above value to the well’s producing GOR, it can be established whether a free gas enters the submersible pumps.

The liquid volumetric rate to be handled by ESP pump is found from the water and oil rates.

In the above formula, the oil volume factor can be ontained from Standing correlation:

To determine number of pump stages, the total head to be overcome by the ESP pump need to identified.

This is called Total Dynamic Head (TDH) and is the sum of the following, all in length units:◦Wellhead pressure at the given liquid rate◦Net hydrostatic pressure acting on the pump◦Frictional pressure drop that occurs in the tubing

string

TDH Calculations

The second term equals the true vertical depth (TVD) of the dynamic liquid level, at which the fluid level in the casing annulus stabilizes while producing the desired liquid rate.

It is easily found from the value of the pump intake pressure, PIP, assuming that an oil column exists in the annulus above the pump setting depth:

It should be noted here that the pump is usually set below this depth in order to provide for a sufficient submergence required for proper pump operation.

A rule of thumb value is at least 500 ft of fluid over the pump (FOP), the other limit being the depth of the sandface(perforations).

The frictional head loss in the tubing string can be estimated from Fig A where the head loss for 1,000 ft of pipe length, is plotted versus liquid rate. The total loss in the tubing string is found as:

Frictional Head Loss

Figure A

Now, the TDH is calculated in head (ft) units as follows:

TDH Value