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46 Intelligent Digital Oil and Gas Fields

submergible pumps (ESP), generally the ESP is equipped with a downhole
intake pressure gauge (inlet before the ESP’s motor) and a discharge pressure
(outlet after the ESP’s motor) plus the motor temperature. Gas lift (GL) wells
are equipped with a downhole gas valve, which use differential pressure to
estimate the gas injected and the flowing pressure at the tubing. In natural
flow wells, we recommend setting up gauges at the end of tubing with a
packer; the information is transmitted using electrical cables. Fig. 2.1 shows
an example of downhole gauges, sensors, and devices useful for DOF oper-
ations. Internal control valves (ICV) are included in this figure; ICV devices
are explained in Chapter 7.

2.1.3 Surface Flowmeters
One extremely important trend used at all asset types is the increase in indi-
vidual well measurement—especially in flowmeter technologies. Any
instruments that provide real-time accurate measurements of well produc-
tion liberate many DOF workflows. There are three ways to develop well
flow rate: direct measurement, direct calculation, or virtual measurement
using analytic or empirical models. Now operations workflows do not have
to depend first on an allocation workflow, which has different objectives and
requirements than most operations activities. Comprehensive work on
multiphase flow is described by Falcone et al. (2009).
Themostcommonmeansofmeasurementistoinstallaseparatorfollowed
by individual component flowmeters. Flowmeters have improved beyond
the typical orifice plate meters and their prices have fallen. It is very common
to find Coriolis meters used for oil or water flows. Orifice plates work well for
gas flows. Turbine or Venturi types are also commonly deployed. A major
benefit of the Coriolis type, which uses principles of mechanics of fluid flow
in a vibrating tube, is that it measures fluid density along with rate so that the
operator can tell if gas or even water is flowing along with the oil measured.
However, flow rate instruments have two disadvantages. First, their use
requires a dedicated process to ensure that the meter is calibrated and fit for
use as the well production declines. For example, Coriolis meters do not
perform well at low turndowns and at high gas volume fraction (GVF),
and orifice plates need to be changed to fit the flow rate range throughout
a well’s life cycle. The second disadvantage is that to use separate meters on
each fluid stream, one or more separators must be installed. Separators are
expensive to purchase and maintain. However many old or even low rate
wells are now using individual fluid meters.
Another alternative to separators and individual fluid meters is a three-
phase meter. Technologies for these meters are rapidly progressing and