J. Lines, Graham Corp., Batavia, New York
condensers are used throughout the refining, petrochemical and chemical industries
The two principal applications are:
In either service, the steam-surface condenser
maintains a sub-atmospheric or vacuum condition at the turbine discharge. This
enables the turbine to effectively create more power than if the turbine
exhausted to atmospheric pressure.
A condenser is seemingly
straightforward static equipment: in one respect, this is true, as it condenses
steam with water typically as the coolant; conversely, a condenser is rather
complex, as it is the heat sink for a turbine that is always considered
critical equipment inside battery limits or within the utility plant. If a
turbine underperforms due to poor surface condenser performance, plant
throughput is affected negatively—therefore, the steam-surface condenser will
often be considered critical equipment for ethylene, methanol, ammonia,
nitrogen, propane dehydrogenation and other process services.
complexity arises from the steam-surface condenser along with its ejector
venting package is what maintains the turbine power output capability by
achieving design backpressure on the turbine. The operating pressure of a steam-surface
condenser is under vacuum, and there is air in-leakage into the system—thus, a low
pressure-drop condensation under vacuum conditions (with the necessary
gathering, subcooling and continual evacuation of non-condensable gases from
the condenser bundle) makes this design and construction complex and quite
different from conventional shell-and-tube heat exchangers.
This article details the complexity of
this static equipment, along with the consequences for the end user when the performance
of a steam-surface condenser is not at design.
type of condenser receives steam exhaust from a turbine. The steam is condensed
on the outside surface of the tubing, with water used as the coolant within the
tubes. Condensation is essentially isothermal, owing to only a small quantity of
non-condensable gases within the turbine exhaust steam. The Heat Exchange
Institute (HEI) provides critical design information for this type of
The condenser is what creates the
vacuum condition at the discharge of the turbine, while the ejector venting
system that supports the condenser is designed to continuously evacuate non-condensable
gases from the condenser. Under normal circumstances, and when performance is
as expected, the ejector system will not set the operating pressure of the
condenser. An ejector system can, and will, set the operating pressure if
something is wrong, such as high air leakage, poor motive steam conditions or a
mechanical issue with the ejector system (FIG. 2).
The condenser is a critical heat sink
for the turbine exhaust steam. Provided the ejector system is not establishing
the operating pressure of the condenser, the condenser pressure is established
via thermal equilibrium and from balancing the thermal duty equation: Q = U*area
mean temperature difference (LMTD). Once a condenser is installed, the heat
transfer surface area is fixed. The thermal duty, total heat transfer rate and
LMTD can vary. TABLE 1
is directional in nature, describing how condenser pressure will vary as
operating variables change.
The author’s company routinely surveys
condenser installations to provide operating assessments, troubleshoot
underperformance, train end user operators, and provide recommendations
regarding performance risk mitigation and opportunities to improve performance
and operational reliability, or to lower energy consumption.
The following are five case studies to
identify the root causes for condenser underperformance and the resultant plant
throughput constraints for the end user.
Caribbean ammonia plant. An
ammonia plant in the Caribbean had been in operation for approximately 40 yr.
The turbine driving the syngas compressor was operating at an elevated
backpressure due to an undesirable increase in the operating pressure of the
steam-surface condenser that condenses the turbine’s exhaust flow. The
condenser was the original supply, and the last plant turnaround for
maintenance had been 10 yr prior to the 2019 visit by the author’s company.
This original surface condenser was
supplied in 1980 and was designed to maintain a backpressure of 11.86 kPa (1.72
psia) at the steam turbine exhaust. The unit was cooled by seawater and was designed
for inlet and outlet temperatures of 28.9°C (84°F) and 46.1°C (115°F),
respectively. The designed heat load to the condenser was 293 MMBtu/hr (85.9
Plant data showed that the pressure
maintained by the condenser was 38.6 kPa (5.6 psia), which was well above the design
basis (FIG. 3).
Furthermore, the turbine exhaust flow was about 50% above design, as the plant
pushed more steam through the turbine to compensate for lost generated power,
which was attributed to the elevated turbine exhaust pressure. The cooling
water supply temperature to the condenser was 30.6°C (87°F), which also
negatively impacted the operating pressure—it was 1.7°C (3°F) warmer than the
design basis. Seawater flow was comparable to the design basis.
The excessive turbine exhaust flow was
50% higher than the design basis, which was a cause for the elevated operating
pressure. Upon deeper analysis, the thermal duty was up approximately 50%, due
to a 50% higher turbine exhaust flow, while the LMTD was greater by more than a
factor of three times. The designed LMTD was 16.4°F, while the actual observed
LMTD was 30.6°C (55°F). This suggests that the overall heat transfer
coefficient in operation was well below the design basis. This implies a potential fouling issue. The condenser had 3,716
m2 (40,000 ft2) of surface area. The Udesign was 2,175 kcal/hr
m2 °C (446 Btu/hr ft2 °F). Uworking was approximately 975
kcal/hr m2 °C (200 Btu/hr ft2 °F).
The installation was shut down, and the
condenser internals were opened for inspection. It was identified that tube-side
fouling and tube blockage had occurred, thereby reducing the overall heat
transfer rate. It had been more than 10 yr since the condenser was cleaned. FIG. 4 shows the
solidified deposits on the tubes, along with blocked tube holes. In addition,
the condenser water box (channel) had corroded due to a loss of the coating,
which led to seawater corrosion (FIG. 5). This corrosion resulted in a loss of seal between
the first and second water passes in the condenser, leading to bypassing and
The author’s company recommended the
Gulf Coast ethylene plant. During a 2016 outage, an ethylene producer on the U.S. Gulf Coast replaced
a cracked-gas compressor turbine exhaust condenser that had been in operation
since 1990. Upon bringing the plant back online, it was not possible to achieve
production capacity due to the cracked-gas compressor’s performance. The
horsepower generated by the turbine was below design due to the replaced steam-surface
condenser operating at 19 kPa (2.75 psia) rather than the designed 15.2 kPa (2.2
Because the condenser was newly
installed, fouling on the tube side was not suspected. The plant requested a
site visit by the author’s company. The engineer assessed the installation and
completed a set of field measurements to compare to the design basis (FIG. 6).
The field measurements confirmed an
elevated operating pressure by the steam-surface condenser. Several options
were available to determine if the condenser was setting the elevated pressure
or if it was being caused by the downstream ejector system used for
continuously removing non-condensable gases from the condenser. The engineer
turned on the hogging ejector—which is used only at startup to quickly evacuate
air and establish a vacuum condition—while running the evacuation ejectors.
When this was done, the condenser pressure was reduced to 12.9 kPa (1.8 psia).
This quick test confirmed that the condenser was not thermally limiting
performance. It was the ejector system venting package that was causing the elevated
the ejector system is a cause for poor performance (such as elevated pressure),
various potential causes include:
To assess air leakage, an air leakage
meter on the after-condenser vent can be used; however, one was not available
in this case. While not sophisticated, a 33-gal industrial trash bag was used.
It was placed on the after-condenser vent, and the time to fill the bag was
recorded. This simple test confirmed that air in-leakage was 2.25x the design
level. This excess air leakage overloaded the venting ejector system, causing
pressure in the condenser to rise. The ejector system was setting the pressure—an
unwanted condition under all circumstances.
can seem odd that a rather small ejector system downstream of a large condenser
can cause elevated pressures to occur. This can be called “the tail wagging the
dog.” The little ejector system (vs. the large surface condenser) can, and will,
establish the operating pressure for the condenser when that condenser can no
longer thermally establish the operating pressure.
Having identified excessive air
leakage as the root cause, it became necessary to find the location of the
leakage. Third-party helium leak testing was performed. It was identified that
the expansion joint between the turbine exhaust and surface condenser had cracked
at the bellows, permitting air to leak into the system, as it was operating at
Upon repairing the cracked bellows,
air leakage was restored to normal, the condenser operating pressure held at
satisfactory pressure and the turbine-compressor performance enabled the
ethylene plant to run at capacity.
American nitrogen plant. A
nitrogen production plant in Latin America had replaced an original surface
condenser—which started operations in 1966—with a design by a shell-and-tube
company rather than by the original equipment manufacturer. This replacement was
completed in 2011. While steam-surface condensers fall under the broad umbrella
of shell-and-tube heat exchangers, they are designed very differently due to
sub-atmospheric operating conditions and internal configurations to collect, subcool
and evacuate non-condensable gases that inevitably enter the process due to the
condenser’s operation under vacuum.
After trying to understand and resolve
the performance issues with the shell-and-tube supplier, the end user reached
out to the author’s company. The designed operating pressure of the turbine
exhaust condenser was 12.7 kPa (1.85 psia), but the new condenser was achieving
33.9 kPa (4.9 psia). At such an elevated pressure, the steam turbine was able
to run at only 60% of its designed power output capacity—thus, the plant’s
production capacity was seriously below nameplate capacity. The consequence of
the elevated pressure was less power generated from the turbine that drives the
critical process compressor, resulting in lower plant production capacity. To
rectify this situation, the end user needed assistance quickly. An engineer was
dispatched to the site to collect performance data, review drawings and develop
a course of action (FIG.
A complete performance survey was not
undertaken for the ejector system venting package. A no-load test was completed
by isolating the ejector system from the surface condenser to evaluate
pressures when exposed to no air load. The no-load test confirmed that the
ejector system was performing properly.
The engineer requested a review of the
condenser drawings, which showed that the nameplate on the condenser was that
of a shell-and-tube supplier and not a company considered a steam-surface
was identified that the shell-side tube bundle design was the cause for the elevated
operating pressure. Two design concerns were identified. First, there was a
perforated plate running the full width and length of the tube bundle atop the
tube field. The engineer envisioned that this was done to ensure uniform steam
flow distribution into the tube field of the condenser. However, this resulted
in a high pressure drop as the steam passed through the perforations, causing the
condenser’s operating pressure to rise in response. Secondly, there was no
location within the tube bundle for separating the non-condensable gases from
the condensate, gathering and subcooling the gases, and ultimately extracting
them from the condenser. The shell-and-tube company did not appropriately
consider the venting of non-condensable gases within the condenser. This
elevated the operating pressure, as well.
is a depiction of the shell-and-tube
supplier’s design using a perforated plate for flow distribution, which resulted
in a large pressure drop and an elevated operating pressure. This approach by
the shell-and-tube supplier is very different from the methods used by surface
condenser suppliers to create uniform bundle penetration and to gather non-condensable
gases separated from the condensate for subcooling and extraction/evacuation
from the condenser, as shown in the steam-surface condenser model in FIG. 9.
The engineer’s recommendations were to
replace the recently installed condensers, since little could be done to alleviate
the performance shortfall due to the perforated flow distribution plate and a lack
of non-condensable-gas handling within the condenser. The shell-and-tube company
did not design the condenser for operating under vacuum or for venting the
Middle East aromatic plant process. A
benzene, toluene and xylene (BTX) aromatics plant in the Middle East had a
surface condenser serving a turbine powering a recycle gas compressor. The
condenser started operations in the late 1990s. Between the first and second turnarounds,
it was noted that many tubes in the surface condenser failed, developing leaks
and those tubes had to be plugged. The tubing experienced corrosion, which led
to cooling water leaking into the steam side of the condenser.
This condenser had been in operation
for about 15 yr. The end user requested that the author’s company visit the
site to evaluate the situation and aid the third-party contractor that was to
remove the failed tubes from the condenser.
Upon arriving at the site and
inspecting the tube sheet of the condenser, it was evident that the tubes in
the air-cooling section of the condenser had failed and were plugged. The
tubing material was admiralty brass, and the tubes only failed in the air-cooling
section (FIG. 10).
This type of failure can occur with
brass tubing when ammonia is present. Boiler treatment chemicals can introduce
ammonia into the steam cycle. Normally, this does not present issues; however,
in the air-cooling section of a steam-surface condenser where the concentration
or mole fraction (partial pressure) of ammonia and oxygen is highest, these
gases can dissolve into the condensate, causing it to become corrosive. Where
the brass tubing passes through the support plates, the corrosive condensate is
continually wetting this area, causing a condition called “condensate grooving”
on each side of the support plate.
The engineer recommended replacing the
admiralty brass tubes in the air-cooling section with material better suited to
resist this form of corrosion. The recommendation was to install 316SS or alloy
2205 duplex tubes in the air-cooling section. The thermal conductivity of the
suggested material is inferior to that of admiralty brass; however, the air-cooling
section is generally less than 10% of the overall tubes in a surface condenser.
Therefore, the greater thermal resistance of stainless steel or duplex
stainless steel will not materially impact condenser performance, but will
eliminate the corrosion experienced by the brass tubes.
U.S. purified terephthalic acid (PTA) plant. A
U.S. PTA plant had begun commercial operations and had a 30-MW turbine-generator
producing electrical power from internally sourced waste steam. Since startup,
an ongoing issue was unstable turbine exhaust pressure due to steam-surface
condenser operating pressure rhythmically varying between 6.9 kPa and 4.8 kPa (1
psia and 0.7 psia). The operating condition of the turbine was unstable, and
the variation in turbine exhaust pressure was unacceptable.
The site shared a trend of condenser
pressure vs. time that highlighted this unusual and rhythmic pattern (FIG. 11). The
author’s company was dispatched to the site to assess the installation and to gather
operating data. An issue with the steam ejector evacuation system was suspected.
FIG. 12 details
the site’s design basis vs. field measurements.
It was observed that the pressure
between the first- and second-stage ejectors was very low, which indicated that
the overall system was very tight with no air leakage. The pressure between the
ejectors was anticipated to be in the range of 2.8 psia with normal levels of
air leakage into the system. The measured data was 1.3 psia.
The engineer then took the system
offline to perform no-load testing on the ejectors. It was identified that the
second-stage ejector was unstable at no-load. This means that it was unable to
maintain its compression shockwave, and it cycled between operating correctly
and losing shockwave, which would lead to a rise in surface condenser pressure.
ejectors in a surface condenser venting package can be designed for no-load
stability based on the diffuser style and the amount of motive steam. It is
rare to not have air leakage into a process under vacuum, but, in this instance,
there was none. In this case, the ejector was already installed, and the time
to provide a replacement ejector was unsatisfactory for the customer. While
typically counterintuitive, the solution for providing stable operating
pressure was to bleed a small amount of air into the suction side of the steam
ejector venting package. A valve was added to permit ambient air to be drawn
into the system so that the second-stage ejector would operate in a stable
condition. Only a very small amount of air was needed; however, upon adding a
little air load into the system, the turbine exhaust pressure became stable.
Takeaways. While surface
condensers are often considered to be an accessory to steam turbines, they are critical
for achieving satisfactory turbine performance. This seemingly straightforward
heat exchanger is quite complex to design and construct, and to achieve desired
performance. End users can learn numerous lessons from performance improvement
engineers in the field. Four of the examples provided in this article are
rather common when end users are experiencing elevated operating pressures. The
fifth example—where the condenser operating pressure rhythmically varied
between 6.9 kPa and 4.8 kPa (1 psia and 0.7 psia)—was unusual.
It is recommended to conduct a
baseline operating survey of the surface-condenser system shortly after
installation during warm summer months when the system should be experiencing
its most challenging operating conditions. Operators should also periodically
assess performance against benchmark data. If there is a noticeable and
undesirable change to operating pressure, a surface condenser performance
improvement engineer should be brought in to aid the system in getting back to
designed performance. Several variables are at play when it comes to condenser
performance, and operators can quickly troubleshoot challenges by bringing in
planning of a scheduled turnaround should permit a performance survey
approximately 15 mos–18 mos before the shutdown. This will permit time to
analyze current performance, to vet opportunities for improving performance or for
returning to designed performance, and to fabricate replacement equipment on a
non-urgent timeline. HP
JIM LINES is
an engineer recently retired from Graham Corp. He worked at the organization
for 37 yr, and has authored numerous articles related to heat transfer, vacuum
process condensers and ejector systems. He has also held various engineering
and management positions at Graham Corp.