Effect of CO2 on downhole flowrate calculation

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Downhole flow rate can be calculated from surface flow rate (stock tank barrels) using the following equation. It is assumed that no gas is dissolved in the water phase and the water formation volume factor is equal to one.

Downhole flow rate = [(Oil rate)sc × Bo] + [(Free GOR) × (Oil rate)sc × Gas FVF] + (Water rate)sc

Free GOR = Producing GOR – Solution GOR, therefore:

q = ( Qo × Bo ) + [ ( R – Rs) × Qo × Bg × 1000] + Qw

Where:

  • q = downhole flow rate (bbl/d or m3/d)
  • Qo = Oil flow rate at standard conditions (stb/d or m3sc/d)
  • Bo = Oil formation volume factor (bbl/stb or m3sc/m3sc)
  • R = Producing gas-oil ratio (scf/stb or m3sc/m3sc)
  • Rs = Solution gas-oil ration (scf/stb or m3sc/m3sc)
  • Bg = Gas formation vol. factor (bbl/mscf or m3sc/m3sc)
  • Qw = Water flow rate at standard conditions (stb/d or m3sc/d)

Effect of CO2 on downhole flowrate calculation:

If CO2 is present, the calculation of downhole flow rate becomes more complex for many reasons:

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ESP Design – Hand Calculations

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This article walks through the suggested nine step procedure for selecting and designing an electric submersible pump. This nine step procedure for ESP design is a basic hand-design of simple water and light crude oil. For more complicated well conditions, such as high GOR, viscous oil, high-temperature wells, etc. a number of computer programs are available to automate this process.

Step 1: Basic Data:

As detailed in the article “Step 1: Basic data ”, step 1 of the nine step design procedure is the most important step because all the others design steps will depend on the basic data selected in this step.

In this example, a high water cut well is considered. This is the simplest type of well for sizing submersible equipment.

  • Well Profile:

Vertical Well

Casing: 7” 26#

Tubing: 3 ½” 9,2# N80 NU

Top perforation: 2003m

Pump Intake depth: 1713m

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PVT Properties and Correlations

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Ideally, laboratory measured PVT data should be utilized. Many times, laboratory data is not available and correlations must be used instead. This post will discuss PVT properties and correlations that can be used to estimate them. It is difficult to say which correlation should be used when. This is because most of the correlations were developed with regional crude samples. The best correlation is the one that matches your data.

Many investigators have used PVT laboratory test results, and field data, to develop generalized correlations for estimating properties of reservoir fluids. The main properties which are determined from empirical correlations are the bubble point, gas solubility, volume, density, compressibility, and viscosity. The correlations typically match the employed experimental data with an average deviation of less than a few percent. It is not unusual, however, to observe deviations with an order of magnitude higher when applied to other fluids.

  1. Bubble Point Pressure (Pb):

The bubble point pressure, also known as the saturation pressure, is the pressure, at some reference temperature, that the first bubble of gas is liberated from the liquid phase. The reference temperature is usually the reservoir temperature, but any temperature can be used. Note that the bubble point pressure is a function of temperature and changing the reference temperature will change the bubble point pressure.

Statistical analysis of correlations:

Al-Shammasi, in his SPE paper “A Review of Bubble point Pressure and Oil Formation Volume Factor Correlations” (SPE-71302-PA, April 2001), compiled a databank of 1,243 data points from the literature. This was supplemented by 133 samples available from a GeoMark Research database (GeoMark Research. 2003. RFD base (Reservoir Fluid Database)), bringing the total number of data points to 1,376. These data were then used to rank the bubble point pressure correlations. The following Table summarizes the ranges of data used for bubble point pressure, temperature, oil FVF, Solution GOR, oil gravity, and gas specific gravity.

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PVT Experiments: Constant Composition Expansion

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Once we have a sample of reservoir fluid, either directly or by recombination, we need to do reservoir fluid measurement, often called PVT analysis. There are mainly 6 fluid properties measured: oil density, gas density, solution GOR, bubble point pressure, formation volume factor, and viscosity. This post will discuss how the bubble point pressure is measured and what the Constant Composition Expansion Experiment is?

Experimental apparatus:

The bubble point pressure is determined by an experiment called Constant Composition Expansion (CCE). It’s also called Constant Mass Expansion (CME) experiment or Pressure-Volume (PV) relationship.

The apparatus used to perform this experiment is the PV cell, as shown in the figure below. The fluid is charged in the PV cell after recombining the oil and gas in the correct proportions. The temperature, controlled by a thermostat, is maintained constant throughout the experiment (the measured reservoir temperature). The cell pressure is controlled by a positive displacement pump and recorded on an accurate pressure gauge.

Bubble Point Pressure:

The bubble point pressure is the pressure, at some reference temperature, that the first bubble of gas is liberated from the liquid phase. It is also known as the saturation pressure.
The reference temperature is usually the reservoir temperature, but any temperature can be used.
Note that the bubble point pressure is a function of temperature and changing the reference temperature will change the bubble point pressure.

Bubble Point Measurement:

A schematic of a Constant Composition Expansion experiment steps is shown in the figure below. The PV cell pressure is initially raised to a value greater than the bubble point pressure. the pressure is subsequently reduced in stages, and on each stage, the volume of the cell is recorded.

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Why Rod Lift?

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Rod Pumping System is a system of artificial lift using a surface pumping unit to impart reciprocating motion to a string of rods. Rod string then extends to a positive displacement pump placed in well near producing formation. In other words, the primary function of a rod pumping system is to convert the energy supplied at the prime mover into the reciprocating motion of the pumping unit required to transmit energy through the rod pumping to the downhole pump in order to artificially lift the reservoir.

Rod Pumping System:

The rod pumping system is made up of three components:

  • The surface pumping unit: which provides the means of turning the rotating power and motion of the motor into the reciprocating motion at the correct speed needed at the pump.
  • The rod string: that connects the surface unit to the pump and provides the force at the pump to lift the fluid to the surface.
  • The pump: which pumps the fluid to the surface.

The integrity of this pumping system is only as good as each of the links or components.

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