The operating characteristics are defined by the manufacturer.


The operating characteristics are defined by the manufacturer. In the
diagram above, the blue lines mark constant speed lines. The maximum
operating limits are set by the orange line as described above. The surge
domain is the area to the left of the red surge curve.
The objective of compressor performance control is to keep the operating
point close to the optimal set point without violating the constraints by means
of control outputs, such as the speed setting. However, gas turbine speed
control response is relatively slow and even electric motors are not fast
enough, since surge response must be in the 100 ms range. Anti-surge
control will protect the compressor from going into surge by operating the
surge control valve. The basic strategy is to use distance between operating
point and surge line to control the valve with a slower response time, starting
at the surge control line. Crossing the surge trip line will cause a fast
response opening of the surge valve to protect the compressor.
Operation with recirculation wastes energy (which could result in
unnecessary emissions) and produces wear and tear, particularly on the
surge valve. Each vendor supplies several variants of compressor control
and anti-surge control to optimize performance, based on various corrective
and predictive algorithms. Some strategies include:
• Set point adjustment: If rapid variations in load cause surge valve
action, the set point will be moved to increase the surge margin.

 • Equal margin: The set point is adjusted to allow equal margin to
surge between several compressors.
• Model based control: Outside the compressor itself, the main
parameter for the surge margin is the total volume from the surge
valve to the compressor suction inlet, and the response time for the
surge valve flow. A model predictive controller could predict surge
conditions and react faster to real situations while preventing
unnecessary recirculation.
Since compressors require maintenance and are potentially expensive to
replace, several other systems are normally included:
Load management: To balance loading among several compressors in a
train and between trains, the compressor control system
often includes algorithms for load sharing, load shedding
and loading. Compressors are normally purged with inert
gas, such as nitrogen during longer shutdowns, e.g., for
maintenance. Therefore, startup and shutdown sequences
will normally include procedures to introduce and remove
the purge gas.
Vibration: Vibration is a good indicator of problems in compressors,
and accelerometers are mounted on various parts of the
equipment to be logged and analyzed by a vibration
monitoring system.
Speed governor: If the compressor is turbine driven, a dedicated speed
governor handles the fuel valves and other controls on the
turbine to maintain efficiency and control rotational speed.
For electrical motors this function is handled by a variable
speed drive.
The final function around the compressor itself is lube and seal oil handling.
Most compressors have wet seals, which are traps around shafts where oil
at high pressure prevents gas from leaking out to atmosphere or other parts
of the equipment. Oil is used for lubrication of the high speed bearings. This
oil gradually absorbs gas under pressure and may become contaminated. It
needs to be filtered and degassed. This happens in smaller reboilers, in
much the same way as for the glycol reboilers described earlier.
4.4 Oil and gas storage, metering and export
The final stage before the oil and gas leaves the platform consists of
storage, pumps and pipeline terminal equipment.
4.4.1 Fiscal metering
Partners, authorities and customers all calculate invoices, taxes and
payments based on the actual product shipped out. Often, custody transfer
also takes place at this point, which means transfer of responsibility or title
from the producer to a customer, shuttle tanker operator or pipeline operator.
Although some small installations are still operated with a dipstick and
manual records, larger installations have analysis and metering equipment.
To make sure readings are accurate, a fixed or movable prover loop for
calibration is also installed. The illustration shows a full liquid hydrocarbon
(oil and condensate) metering system. The analyzer instruments on the left
provide product data such as density, viscosity and water content. Pressure
and temperature compensation is also included.
Figure 9. Metering system
For liquids, turbine meters with dual pulse outputs are most common.
Alternatives are positive displacement meters (pass a fixed volume per
rotation or stroke) and coriolis mass flow meters. These instruments cannot
cover the full range with sufficient accuracy. Therefore, the metering is split
into several runs, and the number of runs depends on the flow. Each run
employs one meter and several instruments to provide temperature and
pressure correction. Open/close valves allow runs to be selected and control
valves can balance the flow between runs. The instruments and actuators
are monitored and controlled by a flow computer. If the interface is not
digital, dual pulse trains are used to allow direction sensing and fault finding.
To obtain the required accuracy, the meters are calibrated. The most
common method is a prover loop. A prover ball moves though the loop, and
a calibrated volume is provided between the two detectors (Z). When a
meter is to be calibrated, the four-way valve opens to allow oil to flow behind
the ball. The number of pulses from it passes one detector Z to the other and
is counted. After one loop, the four-way valve turns to reverse flow direction
and the ball moves back, providing the same volume in reverse, again
counting the pulses. From the known reference volume, number of pulses,
pressure and temperature the flow computer can calculate the meter factor
and provide accurate flow measurements using formulas from industry
standard organizations such as API MPMS and ISO 5024. 

The accuracy is
typically ± 0.3% of standard volume.
Gas metering is similar, but instead,
analyzers will measure hydrocarbon
content and energy value (MJ/scm or
BTU, Kcal/scf) as well as pressure
and temperature. The meters are
normally orifice meters or ultrasonic
meters. Orifice plates with a diameter
less than the pipe are mounted in
cassettes. The pressure differential
over the orifice plate as well as
pressure and temperature, is used in
standard formulas (such as AGA 3
and ISO 5024/5167) to calculate normalized flow. Different ranges are
accommodated with different size restrictions.
Orifice plates are sensitive to a buildup of residue and affect the edges of the
hole. Larger new installations therefore prefer ultrasonic gas meters that
work by sending multiple ultrasonic beams across the path and measure the
Doppler effect.
Gas metering is less accurate than liquid, typically ±1.0% of mass. There is
usually no prover loop, the instruments and orifice plates are calibrated in
separate equipment instead.
LNG is often metered
with mass flow meters
that can operate at the
required low temperature.
A three run LNG
metering skid is shown
At various points in the
movement of oil and gas,
similar measurements
are taken, usually in a
more simplified way.
Examples of different gas
types are flare gas, fuel
gas and injected gas, where required accuracy is 2-5% percent.

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