Tag Archives: ESP pump curve

ESP design – Step 6: Optimum Size of Compounds

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ESP compounds have different sizes and can be assembled in a variety of combinations. These combinations must be carefully determined to operate the ESP with production requirement, downhole conditions, material strength and temperature limits, etc. to select the optimum size of compounds.

Pump:

To determine the required number of stages of the pump to produce the anticipated capacity; just divide the Total Dynamic Head (TDH) by the Head developed by Stage.

Refer to the article “ESP design – Step 4: Total Dynamic Head” to review how the TDH is calculated.

The Head developed per stage is deducted from the published performance curve which shows the discharge head developed by the pump. It is an experimental curve given by the manufacturer and obtained with fresh water at 60 F under controlled conditions detailed in API R11 S2. Refer to the articles “Pump Performance Curves – part 01” and “Pump Performance Curves – part 02” for more details.

Once calculated, divide the TDH by the Head developed per stage to get the Total Number of Stages required to produce the anticipated capacity.

Total Stages = TDH / [(Head / stage)]

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ESP design – Step 4: Total Dynamic Head

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The step4 of the ESP design consists on determining the total dynamic head required to pump the desired capacity. It is common to simplify the procedure by combining or summarizing the additional energy that the pump must supply into a single term, Total Dynamic Head (TDH). TDH is a summation of the net vertical distance fluid must be lifted from an operating fluid level in the well, the frictional pressure drop in the tubing and the desired wellhead pressure.

TDH = HD + HF + HT

  • TDH: total dynamic head in feet (meters) delivered by the pump when pumping the desired volume.
  • HD: vertical distance in feet (meters) between the wellhead and the estimated producing fluid level at the expected capacity.
  • HF: the head required to overcome friction loss in tubing measured in feet (meters).
  • HT: the head required to overcome friction loss in the surface pipe, valves, and fittings, and to overcome elevation changes between wellhead and tank battery.

PS: HT is normally measured in gauge pressure at the wellhead. It can be converted to head, in feet (meters) as follows: HT = (psi / (0.433 psi/ft x sp. gr.)

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Total Dynamic Head Calculation

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In this article “ Total Dynamic Head Calculation ”, the concept of the dynamic head is further detailed. As discussed in the previous article titled: “Total Dynamic Head (TDH)”, TDH is the sum of three basic components:

  1. Net Vertical Lift (NL) = is the net distance where the fluid must be lifted,
  2. Tubing Friction Loss (TFL) = Flow disturbance in the tubing string during pumping process,
  3. Tubing Head Pressure (THP) = Pressure which the unit must pump against (back pressure caused by choking on well head).

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Total Dynamic Head (TDH)

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To properly select the pump, well performance must be estimated. Fundamentally, well performance estimates define what additional energy (i.e., volumetric flow rate and differential pressure or head) must be supplied by the pump to deliver a desired stock tank flow rate (API RP11 S4).

It is common to simplify the procedure by combining or summarizing the additional energy that the pump must supply into a single term, Total Dynamic Head (TDH). TDH is a summation of the net vertical distance fluid must be lifted from an operating fluid level in the well, the frictional pressure drop in the tubing and the desired wellhead pressure.

TDH = HD + HF + HT

Continue reading →