American Oil and Gas Reporter - August 2015 - 90

SpecialReport: Production Automation
Working against production optimization strategies are ongoing retirements
and consolidations. At a time when their expertise is needed more than ever, many experienced measurement professionals are
reaching retirement age. Exiting with them
is vast knowledge of measurement processes and technology. Fortunately, state-of-theart measurement automation applications
encompass the vast expertise that previously was reserved for only the most accomplished and experienced measurement professionals. The applications process the considerable data that are provided by measurement equipment at remote well sites and
presents them to management in an effective and timely manner.
Moreover, as a result of the multiphase
nature of unconventional reservoir production streams as well as acquisition and
merger activity over the years, measurement departments must track and measure
multiple production flows containing oil,
natural gas, natural gas liquids and heavier hydrocarbons.
These increasingly diversified operations combined with rapidly changing production profiles are making the system balancing process more complicated for
many measurement professionals. Within the diversified systems can be a variety
of meters ranging from the traditional orifice, positive displacement and turbine
types to newer technologies, including
cone, Coriolis and ultrasonic. Sitting on top
of those meters is a broad assortment of
correctors, and gas- and liquids-flow
computers.
An automated operation that tracks

multiple fluids must consolidate all the information from the varying technologies,
verify its accuracy, apply any required fluid quality samples, and then recalculate as
needed. Only when those steps are completed can the measurement department attempt a systemwide inventory balance.
Data anomalies, missing data and unaccounted-for inventory can result in a
time-consuming investigation for analysts, which is the last thing a company's
measurement department needs.
Meanwhile, evolving industry standards are expanding database management
requirements. Changes to the American
Petroleum Institute Manual of Petroleum
Measurement Standards (MPMS) include
the introduction of three-dimensional,
physical properties tables and a completely updated, second edition to Chapter 21.1, Flow Measurement Using Electronic Metering Systems: Electronic Gas
Measurement. It is crucial for the measurement function to stay current with all
standards.

Measurement Expertise
In today's business climate, how can
measurement departments more effectively use flow rate and well performance
information and automated workflows
to balance their systems and optimize production?
Built into the latest generation of
measurement automation applications are
vast measurement expertise and capabilities, including static and dynamic measurements, metering technologies, meter
proving, physical properties, flow calcu-

FIGURE 1
Accumulated Totals for Example Meter Location

90 THE AMERICAN OIL & GAS REPORTER

lations, calibration, data processing, auditing and verification processes.
Key capabilities include auto-estimating for missing data, data drill-down, editing, forecasting, system balancing, and
validations of all data that are generated
throughout the measurement process. A
variety of statistical tests can be applied
to any data from meters, gas quality
sources, flow computers, calibration and
verification reports, field test reports and
laboratory analyses.
In addition, a broad array of standard
displays and reports provide complete
functionality, which allows understaffed
measurement departments to operate most
effectively.
Advanced measurement automation
applications incorporate the ability to
manage natural gas, NGLs and crude oil
in a single database. Included in such an
application is a full implementation of calculations and tables that compute mass and
volume, account for the physical properties of practically all hydrocarbons, and account for the properties of all meters that
are used in oil and gas flow measurement.
The extensive functionality complies with
American Gas Association reports and
standards that have been published by the
American Petroleum Institute and Gas
Processors Association.
This unprecedented scope allows measurement personnel to bypass the formidable effort that otherwise would be required
to implement the various standards and
calculations with in-house applications.

Pulling Information Together
Measurement automation applications
can pull together information from a
broad array of sources with widely varying formats and time bases. For a particular meter, the application checks calibration and verification reports from a technician, tracks hourly data from a flow computer, and is able to coordinate that with
a gas analysis report that just arrived from
a laboratory.
The measurement automation application can track performance information for
all measurement assets such as meters,
tanks, vessels, gas quality instrumentation,
differential pressure transmitters, pressure
and temperature measurement, flow computers, remote terminal units and any other equipment that is used in the measurement process.
Typically, measurement automation applications are scalable and can expand to
meet the user's requirements. For exam-

American Oil and Gas Reporter - August 2015

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