Category Archives: 9 Step Design Procedure

ESP design – Step 5: Pump Type

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In order to select the most suitable pump, Refer to the pump selection data table in the manufacturer’s catalog for pump type, range and pump performance curve. Based on expected fluid production rate and casing size, select the pump type which will be operating within the recommended operating range and nearest to the pump’s peak efficiency.

When two or more pump types have similar efficiencies at the desired production rate, the following recommendations should be considered to select the most adaptable pump to the well conditions:

The shape of the pump performance curve:

The  ability  of  a  pump to  adapt to  changes in  well  performance  depends  on  the characteristic  shape of  the pump performance  curve. A pump with a steep characteristic (i.e.  large  change  in  head with  respect  to  flow  rate)  is  less  suited  to  a well with  poorly defined  inflow  performance  (IPR),  especially  if  it  is  intended  to  produce  with  a  fixed drawdown.  For  such pumps,  a  small  loss  in  IPR  translates  to  a  large  fall  in pump  intake pressure and may result in gas locking. Conversely, the head produced by a pump with a flatter characteristic will change less for a given  change  of  flow  rate  and  can  therefore  be  used  over  a wider  variety  of  IPR’s with limited changes in intake pressure.

Refer to the article “Pump Performance Curves – part 02” for more details.

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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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ESP design – Step 3: Gas Calculations

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The presence of free gas in the tubing above the pump changes the fluid density, consequently reduces the required discharge pressure. Also the performance of centrifugal pumps is considerably affected by the presence of free gas in the pumped fluid. The pump starts producing lower than normal head as the produced GLR (Gas to Liquid Ratio) at the pumping conditions increases beyond a critical value. The critical value of the ratio or percentage of free gas present at the pump intake to the total volume of fluid depends on the pump impeller design (typical critical values are shown in the article “ESP: Gas handling device “). Therefore, it is essential to determine the percentage of free gas by volume at the pumping conditions in order select the proper pump and gas handling device (if required).

Percentage of free gas by volume:

Assuming that Solution GOR (Rs), Gas Volume Factor (Bg) and Oil Formation Volume Factor (Bo) are known, the total volume of fluids and the percentage of free gas released at the pump intake should be calculated.

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ESP design – Step 2: Production Capacity

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Once the first step “Collect basic data” is performed, we pass to the ” step 2: Production Capacity “ of the ESP Nine Step Design Procedure. It consists on predicting the well inflow performance which represents the relationship between pressure and flow rate at the well face of an individual well and it is physically defined as the well flowing bottom-hole pressure (Pwf) as a function of production rate. It describes the flow in the reservoir.

Many inflow performance relationships (IPR’s) are described in the literature. In this article, we will briefly present three of the most widely used IPR’s to describe the well performance:

 

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ESP design – Step 1: Basic data

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As described in the previous article ESP nine step design procedure, Centrilift has established a nine-step procedure to design the appropriate electrical submersible pump. The first step of this ESP design procedure, and certainly the most important step, consists on collecting the basic data. This is the most important step because all the others design steps will depend on the basic data selected in step 1. If the basic data quality is good the design will be good and the ESP will operate at its optimum conditions. Otherwise, if the input data quality is poor the design will usually be marginal.

A list of required data is outlined next: