Page 74 - Intelligent Digital Oil And Gas Fields

Instrumentation and Measurement 45

Fig. 2.1 The whole set of gauges, sensors, and meters required for real-time DOF. The
figure shows surface and downhole gauges with surface remote-controlled valve and
ICVs. An artificial list system is also added; note that the wells can be equipped with
GL or ESP but rarely both.

The following are the essential data required for surface monitoring:
• Tubing head pressure (THP) and tubing head temperature (THT)
gauges, if wells flow through tubing.
• Casing head pressure (CHP) and THT gauges, if wells flow through cas-
ing or annular area, including gas lift in shallow well completions.
• Flowline pressure (FLP) and flowline temperature (FLT).

2.1.2 Downhole Gauges
In dry and wet gas wells, downhole gauges are not required because a two-
phase flow correlation (such as that of Gray, 1978; Beggs and Brill, 1973)can
be used to estimate the bottom-hole flowing pressure with acceptable accu-
racy. However, when a multiphase flow occurs and produces gas, vapor, oil,
gas-in-solution, and water, then downhole pressure and temperature gauges
can generate tremendous value to DOF workflows to measure well and res-
ervoir performance. Moreover, during well shut-in periods, the downhole
gauges can capture the essential data to perform a pressure transient analysis
(PTA) to estimate the static reservoir pressure (p*), reservoir conductivity
(k.h), and skin factor (S).
To be able to measure performance and optimize lift, then wells with
artificial lifts must have all necessary gauges installed. In wells using electrical