Class room exercise

1.1 Inflow performance

A well produces 400 Sm3/d, at well bottom pressure 190 bar. Closing the well, the bottom hole pressure rises to 200 bar.

  1. Estimate the productivity index
  1. Predict bottom hole pressure if production is raised to 700 Sm3/d
  1. We consider installing a down hole pump, to draw the bottom hole pressure down to 160 bar. Estimate necessary rate capacity for such a pump.
  1. After 2 years of production, we expect the reservoir pressure to have decreased 180 bar. How much can the well then be expected to produce at bottom hole pressure of 160 bar?

1.2 Flow and pressure loss in well tubulars

The well considered above, in problem 1.1, is drilled vertically and is planned to be completed with id 50 millimeter production tubing. The following data are given

Viscosity of reservoir oil1.5 cP

Formation volume factor1.05m3/Sm3

Producing gas/oil-ratio10 Sm3/Sm3

Oil gravity (specific density)0.83

Gas gravity (specific density)0.6

Reservoir temperature60 C

Separator pressure20 bar

Length, production tubing 1600 m

  1. Predict pressure profile along the tubing, p(x), for closed in well
  1. Predict pressure profile along the tubing, when the well produces 400 Sm3/d
  1. Predict natural production rate
  1. Predict blow out rate

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Suggested friction factor correlation:

1.3 : Pumping

The productivity index has been estimated: 40 Sm3/d/bar. In problem 1.3 we calculated

Rate (Sm3/d) / 0 / 400 / 700
Bottom hole pressure (bar) / 200 / 190 / 182
Static pressure loss (bar) / 126 / 126 / 126
Flow friction loss (bar) / 0 / 19 / 52
Tubing head pressure (bar) / 74 / 46 / 5
  1. How much will the well produce naturally after 2 years, when the reservoir pressure has declined to 180 bar
  1. How much pressure increase must a down hole pump provide to make the well produce 700 Sm3/d
  1. How much power must the pump engine provide, if the pump efficiency factor is 0.6
  1. How much will the well produce naturally, when the reservoir pressure has declined to 150 bar
  1. How much pump power is needed to maintain 700 Sm3/d

1.4 : Production regulation

In 1.2we estimated that the well may naturally provide 550 Sm3/d, initially. But the rate will decline when the reservoir pressure declines. A development concept may be to install some smaller initial processing capacity, e.g.: 300 Sm3/d. In that case reduction of the natural rate is initially required. That may be provided by a choke between the tubing head and the inlet separator

  1. Estimate necessary pressure reduction across the choke, to make the well produce 300 Sm3/d, against separator pressure 20 bar
  1. Estimate choke size necessary
  1. How much will the well produce through this choke, when the reservoir pressure has declined to 180 bar
  1. How large choke is needed to produce 300 Sm3/d, when the reservoir pressure has declined to 180 bar

1.5: Future production prediction

The well has been completed and produced as outlined above.

Constant production 300 Sm3/d has been maintained during 2 years, by gradually opening the choke to compensate for declining reservoir pressure. Reservoir pressures have been measured at 6 months intervals, as listed below

Production time / 0.5 år / 1 år / 1.5 år / 2 år
Reservoir pressure / 195 bar / 191bar / 188bar / 183 bar

a)How long time can we expect to continue production atplateau rate 300 Sm3/d?

b)To extend plateau production, we consider reduction of inlet separator pressure, to 10 bar. How much will this extend the plateau period?

c)Predict production after the end of the plateau period.

d)Economic break-even is expected to occur at production: 25 Sm3/d. How long time may we expect to produce

e) May the predictions obtained may be considered optimistic, or pessimistic

f)Consider means to extend production.

1.6 Fluid properties

I problem 1.2 was given

Viscosity of reservoir oil1.5 cP

Formation volume factor1.05 Sm3/Sm3

Producing gas/oil-ratio10 Sm3/Sm3

Saturation pressure12 bar

Reservoir temperature60 C

Density, oil at reservoir conditions800 kg/Sm3

In addition has been measured

Separator gas gravity0.66

Stock tank oil gravity0.82

Check if the data above are consistent with estimates by the black oil correlations.

a)Saturation pressure

b)Formation volume factor

c)Oil density at reservoir condition