N. Pongboot, Avantium, Amsterdam, the
Netherlands; K. BOONWONG, Global R&D, Samut Prakan, Thailand; and S. DYKE, PetroQuantum, Northland, New
centrifugal compressor has been the workhorse of the oil and gas industry for
decades. Its applications vary from the delivery of natural gas from the
wellhead to the distribution network to downstream refining and petrochemical
process applications. A centrifugal compressor’s main objective is to compress
a certain volume of gas to the desired pressure by imparting kinetic energy
into the gas stream, increasing
the gas's velocity using a rotating component (e.g.,
impeller), and then converting this kinetic energy into potential energy in the
form of pressure. As a general rule of thumb, centrifugal compressors should be
selected for rated discharge flow conditions > 300 m3/hr (175 ft3/min
first design step, the gas flow range the centrifugal compressor must deliver
should be specified. The maximum flow is for rated operation, while the minimum
flow corresponds to turndown operation. In general, a centrifugal compressor
must be designed and selected in such a way that the devastating surge (too low
flow) and choking (too high flow) phenomena can be avoided with an effective
safeguarding system (e.g., installing a recycling or surge control valve).
the fluid property (composition) and conditions (temperature and pressure)
should be specified for all critical process scenarios. The selected
centrifugal compressor must cope with all potential variations.
but not least importantly, the inlet and discharge pressures must be specified
to determine the rated polytropic head. As a quick guide, the maximum pressure
ratio per stage is somewhere between 3 and 7, depending on the heat capacity
ratio, process application and sealing material. As a precaution, gases
cracked gas from a steam cracker or wet gas from a fluid catalytic cracking
lower than usual discharge temperature limits to avoid polymerization or
coking, usually < 100°C.
The higher the olefinic content, the lower the discharge temperature limit.
most large centrifugal compressors have been installed with a steam turbine
drive, which has allowed an additional degree of freedom for the centrifugal
compressor's control system (i.e., the turbine's speed controller), which acted
in many designs as the capacity controller for the compressor system. This type
of prime mover is particularly energy-efficient when high-pressure steam levels
(> 40 barg) are available in the facility and low-pressure steam levels of 2
barg–4 barg (e.g.,
steam stripping) are needed. Additionally, steam turbines offer improved
reliability over motors as a steam header is less affected by power failure and
does not immediately trip when overloaded.
a safety perspective, a non-sparking operation is also safer for explosive
atmospheres (e.g., hydrogen service). Despite their advantages, steam turbine
drivers are unsuitable for certain applications (e.g., offshore centrifugal
compressors or water-scarce areas where steam production is economically infeasible).
in the case of a centrifugal compressor with a constant-speed electric (or
turbine, in niche applications) drive, this capacity control flexibility does
not exist. In this case, what is the best way to control the flow through the
compressor system? Several control schemes with different advantages and
disadvantages are possible.
the authors’ experience, design explanations behind each capacity control
option available in most engineering textbooks/standards are incomplete,
focusing only on compression energy and turndown ratio. This article will
provide a better understanding of selecting the optimum capacity control
technique by incorporating other design aspects using refinery case studies.
control basics for a constant speed centrifugal compressor. Generally, there are two main methods (FIG. 1) to control a
constant speed centrifugal compressor:
The authors have intentionally disregarded how the inlet guide vane (IGV)
positioning technique works here, as its concept is somehow similar to suction
throttling but with even better energy efficiency and turndown ratio.
the surface, the discharge throttling technique sounds less efficient from the perspective
of compression energy and flexibility. Why is this inefficient design still prevalent
in engineering textbooks/standards, and why don’t textbook/standard authors
remove it to prevent confusion? It must be noted that the majority of
engineering textbooks/standards known to the authors do not provide any other
explanations than compression energy and flexibility. The answer is simple.
Saving compression energy and flexibility are not the only reasons behind the
final design. Interesting examples and explanations are shared here.
fractionator. The FCC fractionator feed is a hot
vapor stream from the FCC reactor with a temperature > 500°C—flashing is not a problem here, as the
feed is already vapor. Conversely, the main functions of this column are to
condense the vapor products and fractionate them into various product
shown in FIG. 2A,
using a suction throttling valve is not an issue in terms of column operation,
as a slight increase in column pressure (typically < 2.5 bara) does not
negatively affect product recovery—it actually helps a little if only the fractionator is
considered. As described above, this application can fully benefit from the
suction throttling design. The same design logic applies to a similar
application, such as a delayed coker fractionator, where feed quenching is
required rather than flashing.
distillation unit (CDU). Typically, the
crude feed is heated to 340°C–390°C (depending on the
design) to flash as much diesel as possible from the atmospheric residue.
Losing too much diesel in the atmospheric residue would result in a loss of
yield and, therefore, profit, as the diesel fraction in the atmospheric residue
will be recovered with the vacuum gasoil (VGO) and cracked into lower-value
products in the downstream conversion units. This problem will worsen if there
is no diesel recovery section in the vacuum distillation unit (VDU).
the conversion unit is an FCCU, 60%–70% of the remnant diesel will end up as a low-value light cycle
oil (LCO). Similarly, hydrocracking processes will convert 30%–40% of the remaining
diesel into lower value products, such as offgas, liquefied petroleum gas (LPG)
or naphtha. A well-designed CDU/VDU produces FCC or hydrocracker feed streams
containing < 5 vol% diesel boiling-range material.
maintaining a low and stable flash zone pressure (typically 2.1 bara–2.5 bara, total
pressure) is crucial to achieving this goal. Any slight increase in the
pressure drop upstream of the overhead compressor would add to the flash zone
a suction throttling valve to control the overhead compressor capacity might
not be the best choice for this application. Any increase in the column top
pressure (and, therefore, the flash zone pressure) increases the heater outlet
temperature and energy required to maintain the desired diesel/atmospheric residue
cut point. More diesel will be lost into the atmospheric residue if the crude
heater outlet temperature is held constant. Increasing the crude heater outlet
temperature has operational and metallurgical limitations that may result in a
more complicated and expensive heater design to ensure acceptable
coking/corrosion rates, and fired heaters are generally expensive equipment.
demonstrated in FIG.
2B, this CDU recontacting system employs discharge throttling valves
to maintain a low and stable top column and flash zone pressure. This unit was
designed by one of the most prominent petroleum companies, which would have
known that the discharge throttling valve would require additional compression
power yet decided to use it anyway for the explained reasons.
Hydrocracker. A typical heavy oil hydrocracker requires a large volume of
circulating hydrogen (usually between 1,000 Nm3/m3 and 2,000
Nm3/m3 of liquid feed) to ensure the minimum hydrogen
partial pressure, good heat removal (highly exothermic reactions inside the
reactor), acceptable catalyst deactivation (or coking) rate, and good product
qualities. This circulating hydrogen flow, also known as recycle gas, carries
heat from the fired heater to raise the combined feed temperature at the inlet
of the reactor to initiate hydrotreating and hydrocracking reactions and acts
as a heat sink after the desired chemical reactions propagate.
multiple-bed reactor scheme is widely adopted as an industry standard to better
control the temperature rise across each catalyst bed by injecting quench gas
between each reactor bed. Obviously, accurate control of recycling gas and
quench flows is critical here. For example, an abnormally low recycle gas flow
can cause coking of the catalyst and potential tube ruptures in the fired
heater, while an inadequate quench flow will increase the risks of a
recycled gas and quench flows are delivered by the same heavy-duty centrifugal
compressor, it is necessary to place the flow sensors and control (throttling)
valves near their dedicated destinations (FIG. 3). As such, the centrifugal compressor
capacity control choice is dictated by the system functionality here. Note: The same logic
also applies to other hydroprocessing units, such as a diesel hydrotreater.
Takeaways. Popular arguments, such as compression energy and
flexibility, are not the only key considerations when designing a capacity
control system for centrifugal compressors. A holistic design approach is
essential to ensure good operability, reliability, energy efficiency and
flexibility of the overall system, as briefly elaborated by the refinery case
authors hope this short explanation provides better insights into how different
centrifugal compressor capacity control techniques can be selected to suit
specific applications. HP
NATTAPONG PONGBOOT is an experienced
chemical engineer with hands-on knowledge in refining and petrochemical
technologies as both licensor and refiner. He is currently a Project Manager
under the Refinery Catalyst Testing group at Avantium Catalysis, delivering
high-quality catalyst testing services for customers worldwide. He holds an
M.Eng. degree in chemical engineering from Kasetsart University. The author can
be reached at Nattapong.Pongboot@avantium.com
KONGPHOP BOONWONG is a Senior Process Design
Engineer for Global R&D in Thailand. His expertise includes process
troubleshooting, conceptual, basic and detailed engineering of processes and
equipment. He is also a technical support engineer for FLUIDFLOW and VISIMIX
engineering software. He obtained his B.Eng. degree (1st in class) in chemical
engineering from Naresuan University in Thailand. Dr. Boonwong received a
scholarship from SCG chemicals during his PhD degree at Chulalongkorn
University to research computer-aided modeling of heterogeneous catalysts. The
author can be reach at email@example.com.
SHAUN DYKE is an experienced chemical engineer who
has worked in the refining and petrochemical industries for more than 40 yr in
numerous technical, managerial, governance and consulting roles around the
world. He lives in and works from New Zealand and writes in his spare time. Mr.
Dyke earned a BSc degree (First Class Honors) in chemistry from Massey
University, New Zealand. The author can be reached at firstname.lastname@example.org.