Hydrocarbon Processing - January 2022 - 19

Sustainability
a conventional CEMS. A PEMS creates a model (FIG. 4) of the
combustion process using data from the EMIS, historians, asset
management systems or other process databases.
Since the PEMS is monitoring all relevant factors, such as
fuel flow, air flow, fuel type, etc., it can calculate the effluent
output in real time based on a sophisticated combustion model.
The model says, in effect, given this set of operating parameters,
here is the profile of effluents.
This methodology is outlined under relevant regulations,
including U.S. EPA CFR 40, Part 60-61-63-75 and in the European
Union under CEN/TS 17198:2018. The regulatory body
will insist on evaluating a given installation to ensure the process
is done correctly. Certifying an installation normally calls
for a series of steps:
* Verify the application is suitable for a PEMS
* Validate sensors for accuracy and reliability
* Evaluate the emissions model's integrity
* Review documentation and training.
Once these tests are passed and the system is installed and running,
the application must be tested and validated on a regular
basis. Some of these will be internal checks, but the regulatory
agency will participate on, at least, an annual basis with its own
surveillance test.
Using a PEMS saves money over a traditional CEMS (FIG. 5)
when considering both capital cost and lifetime operating cost,
especially when including maintenance and consumables for
conventional analyzers. However, equally as important as cost,
a PEMS can work in concert with the EMIS because it is part
of the larger EMIS.
Therefore, it provides insight into the process in ways that
are not practical with a CEMS. It can also be part of larger process
optimization strategies and energy efficiency efforts.
Mass balance: Production for energy input. The question
all refinery managers should be asking is, how much product are
we getting for each unit of energy input? This is a very important
calculation, but it is highly complex since there are so many variables.
The larger picture also includes the basic capabilities and
limitations of a production unit based on conversions, yields,
catalyst selectivity, fractionator cut points and energy efficiency.
An EMIS can provide the energy side of the equation, which
is another benefit of such a system, but for many facilities, the
weak link of examining mass balance turns out to be accurate
measurements of product flows at critical points in the process.
The critical point is measuring mass flow, but in many facilities,
flow instrumentation only measures volume. This is a
problem because volume measurements do not take product
density into account, which can lead to miscalculations. The
following are several typical examples of issues:
* Since density is not measured, it is assumed to be
constant, using the same value in all situations
for a given product.
* Processing batches of opportunity crudes causes
changes in feedstock characteristics, which can be
recognized with a true mass flow reading but may be
undetected if density is assumed to be constant.
* If a critical density reading is necessary, some facilities
use lab analysis of grab samples; however, this does not
track changing conditions.
FIG. 5. A PEMS is much less expensive than a CEMS and
far more versatile.
Hydrocarbon Processing | JANUARY 2022 19
FIG. 4. A PEMS uses a process model to determine the output of
pollutants from a fired heater or boiler.
* Converting volume to mass for high-temperature streams
is troublesome since American Petroleum Institute's
Volume Correction Factor tables stop at 400°F (204°C).
* Deploying density instruments in the field is possible, but
there are limitations of temperature and viscous products.
* Since mass is not measured accurately, process
optimization via advanced process control strategies
is not practical.
Moving to mass flow measurement. Arguably, the best flow
meter technology for refinery applications is Coriolis (FIG. 6).
These flowmeters not only measure mass flow natively, but they
also measure density directly in real time and have internal temperature
compensation. Most designs include a sophisticated
transmitter able to deliver the range of variables required to support
mass balance calculations. In addition, they are very accurate
across a wide turndown and temperature range.
Their downside is relatively high cost vs. alternate measurement
technologies, along with a small internal free passage
compared to the line size. Where product flows are not clean,
they can be clog-prone, particularly with small line sizes. However,
while cost is a consideration, the higher purchase price is
far smaller than the savings realized by facilities that install them
at critical points. Even a slight improvement in production can
pay for the flowmeter in weeks or months.
A more common flowmeter configuration in refineries is
differential pressure (dP). This technology works well in all
types of installations, but it cannot provide a mass flow measurement
without knowing the product's density. If the density
is relatively consistent, the transmitter or automation host system
can use the density value, with appropriate adjustment for
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