Page 212 - Intelligent Digital Oil And Gas Fields

166 Intelligent Digital Oil and Gas Fields

IT-agnostic solutions. Technology changes so fast that there is often not
time to debug an entire workflow. Ideally, smart workflows should be
defined independent of the applications or commercial software and sys-
tems used to implement them. Al-Abbasi et al. (2013) explains that a
well-defined DOF program allows technology to change without signif-
icant impact to the structure or performance of the whole solution.
Asset team engagement. As smart workflows are highly automated and can
execute quickly, a potential problem can be maintaining people’s interest
and engagement within the system. Ultimately, the goal of smart
workflows is to provide a more effective working environment for asset
teams, allowing better communication and analysis to solve operational
problems. Al-Abbasi et al. (2013) have described key success factors for
keeping people engaged, which includes making sure workflows meet
asset team expectations and finding mechanisms to integrate people into
daily activities such as daily operational meeting, design of fracture, or
drilling the lateral section of a well. New workflows inevitably change
the way teams work; all team members must be brought into the pro-
gram early and should be pretrained to manage the high-stress environ-
ment of real-time operations.
Additional details on these topics can be found in Chapter 8.

5.3 VIRTUAL MULTIPHASE FLOW METERING-BASED
MODEL

A virtual multiphase flow (virtual flow meter, VFM) metering-based
model is an engineering production model that computes multiphase vol-
umes based on pressure and temperature data. Typically, most oil wells (since
about the 1990s) are equipped with pressure and temperature gauges to cap-
ture frequent readings (e.g., every minute), but production rates are only
measured monthly or less frequently with separator tests. Physical
multiphase flow meters are very useful and provide significant value to mon-
itor multiphase production in real time, particularly in wells with high pro-
duction rates where immediately identifying important changes in pressure
is crucial. However, these meters are very expensive, and require extensive
pressure-volume-temperature (PVT) data and frequent calibration.
Virtual metering is a mathematical model that continuously computes
the three-phase flow (water, gas, and oil) rates based on primary real-time
data, such as surface and down-hole pressure and temperature, and chokes