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Refrigeration Compression, Turbine Performance, Compressor Advances, Carbon Capture, and Energy Storage
Texas A&M hosted the 51st Turbomachinery and Pump Symposia in Houston during September. Attendance returned to pre-pandemic levels. The show featured a lively exhibit and a large collection of sessions, discussion groups, and case studies.
Michael Welch, Industry Marketing Manager, Siemens Energy, kicked off an early session on how to integrate turbomachinery into CO2 capture plants aimed at smaller, open cycle gas turbine applications. He reviewed one carbon capture approach based on the traditional amine capture system and another using pressurized hot potassium carbonate (HPC) concept.
Traditional systems are largely solvent based on absorption towers. The drawbacks include the need for power and heat, as well as a lot of space. They currently capture about 90% of the carbon, although this could be pushed up above 95% through additional investment. Additionally, the solvent must be regularly topped up. Electrical and heat consumption are a significant proportion of plant output. The small scale makes amine tower system costs relatively high.
“Advances such as rotating packed beds (RPB) can be used to reduce energy and space requirements,” said Welch. “The size of the absorption system is reduced by 7 to 10 times.”
However, low flue gas temperatures are still required. There is currently a limit as to how large they can be scaled up. As a result, the price tag comes down for small CO2 capture plants, with forecasts that $50/tonne could be achievable.
HPC, meanwhile, scales well and generates its own power and steam. But this approach has a high space requirement (about the same as amine towers). On the plus side, HPC can accept high temperature flue gas from gas turbines without the need to reduce the flue gas temperature. This pressurized high temperature system can generate sufficient electricity for its own use, even producing surplus for export in some cases. It can be configured to recover waste heat, too, for various purposes.
But the big barrier to broad adoption of carbon capture is cost. Amine towers have CO2 capture costs that work out around $80 to $150 tonne for a small capture plant. RPB and HPC could achieve around $50 to $80 tonne in the right circumstances. Mixing hydrogen with natural gas can bring costs down further.
“If you add 30% hydrogen into the mix, you can achieve an 11% reduction in carbon emissions, so there is less CO2 to capture,” said Welch.
Another way to reduce costs is to consider boosting the CO2 concentration in the flue gas by using exhaust gas recirculation. This reduces the amount of solvent required in the process and hence the size of the reaction vessels
Waste heat recovery is an additional strategy being used to improve project economics. There are various ways to recover heat from the CO2 compression process and integrate it back into the amine system. Recovering and integrating CO2 heat of compression, for example, can reduce the parasitic burden of carbon capture and lower compressor cooling requirements. This approach could be used with either single-shaft or integrally geared compressors. The latter was found to offer more flexibility in optimizing compressor pressure ratio splits.
The carbon capture theme continued with a presentation by Klaus Brun, Director of R&D at Elliott Group and long-term Myth Buster for Turbomachinery International. He outlined the new for new approaches to compression of carbon dioxide for separation, pipeline, transportation, and storage injection. For every kg of blue hydrogen that is produced through steam reforming or partial oxidation gasification, for example, about 10 kg of CO2 is also produced. This CO2 needs to be compressed from near-atmospheric conditions for pipeline transportation and then to geological formation storage pressures for long-term sequestration.
One promising technology for large-scale carbon storage compression applications is a hybrid combination of a centrifugal compressor to compress the gas to slightly above its critical point in series with a dense phase pump to reach the desired process discharge pressure. This combination of turbomachinery can be packaged with a driver with a single gearbox for the compressor and direct drive for the pump.
“We have about 250 years of storage capacity for CO2 in the U.S. in old mines and geological formations,” said Brun. Putting it in the ground requires about 1800 psi compression per mile of depth. Pipelines are needed to transport the CO2 as well. That means the carbon dioxide needs to be cleaned and dried and a boost compressor is needed after capture to maintain pipeline pressure. CO2 transportation requires very high pressure ratio compressors with intercooling.
“Centrifugal compressors are preferred as recips have issues with pulsation control, lube oil contamination, leakage, and reliability,” said Brun.
LONG-DURATION ENERGY STORAGE
Tim Allison, Director of the Machinery Department at Southwest Research Institute provided a rundown of the different mechanical approaches to long-term storage of energy. Batteries are good for short-term storage. But the longest duration approaches are machinery-based, such as compressed air energy storage (CAES) and pumped hydro systems (PHS).
“As we seek to decarbonize electricity, there is a variable demand mismatch coming from wind and solar resources,” said Allison. “Studies show that storage on the order of current daily energy production or more may be needed.”
He gave the example of metropolitan Phoenix. 10 hours of energy storage for the city would amount to 125 GWh. Five of the world’s largest PHS units would be needed to supply that amount of storage. To match the energy capacity of the U.S. natural gas storage system, 57,000 PHS systems would need to be installed.
Allison noted that the figures used to support the low cost of solar and wind tend not to take into account capacity factor and storage costs. Solar has a 25% capacity factor, and wind has about 35%.
“When you add in storage costs, capacity factor, and round-trip efficiency, gas turbines remain much cheaper,” said Allison. “Machinery based solutions offer long-duration storage at the lowest cost.
Medhat Zaghloul of Compressor Control Corporation delivered a session on compressor refrigeration in oil & gas. The pressure ratio requirement of refrigeration compression depends on seasonal ambient conditions, rather than on process cooling demand variations. Machines in the summer typically require more horsepower to drive them. Overdesign in controls is a common problem.
If a control element is placed between the economizer and high-power suction drum, there is a chance for upstream pressure to raise in a partially closed valve scenario. Having a control system in this configuration negates economizer benefits. Single mixed refrigeration (SMR) compressors in small LNG plants are straightforward. The setup involves a two-section SMR, with a variable speed gas turbine driver. The mixed vapor from the cryogenic heat exchanger (CHE) is compressed in the low-pressure section. It produces a mixed phase stream, with the liquid portion used for process cooling and the vapor portion further compressed in the high-pressure section, and then condensed for process cooling.
Jim Sorokes, an independent centrifugal compressor consultant, examined advances made during the last seventy years in design, analysis, and manufacturing methods.
Compressors were driven by cost and ability. Machining limitations pushed design philosophy. The industry relied on cast internals for manufacturing, and performance wasn’t as important. Rising energy costs forced consideration of performance. There became a desire to consume less fuel, have a smaller footprint, fewer stages, and a wider flow range.
One of the most significant changes was dimensional design considerations. 2D blade performance is what led to 3D blade production. Achievable in 3D is high Mach, matching inlet flow angles, better control of area distribution through the bladed passage, uniform exit velocity, and diffuser performance.
Additive manufacturing (AM) is a modern discovery. Creating parts with AM methods increases freedom in blade shape. Size limitations and surface finish treatments can alleviate issues from printing, such as webbing.
Mark Sandberg, independent consultant, covered compressor configuration, sizing, selection, and arrangement. Configurations were initially straight-through versions – a single collection of stages with a common inlet and discharge. Beam style rotor designs limit the number of stages to ten, although high flow coefficient stages can limit this further.
Compound configurations comprise two or more sections in a single casing. Since controlled leakage seals replace one stage in this design, stage number is limited to nine or less. Space for multiple inlet and discharge nozzles also caps possible sections. Other types are back-to-back, double suction, and sideload.
Important considerations for sizing and selection are flow rate, suction pressure, temperature, discharge pressure, gas composition or specific gravity, unique side stream flows or pressure requirements, and any rotational speed requirements. Common selection parameters are volumetric flow rate, polytropic head, polytropic efficiency, and gas power.
Compressor arrangement is the external structure and organization of compression hardware. Series arrangement considers that as head requirements increase, multiple casings are needed to achieve desired compression ratios. There is a separate driver for each casing. Tandem arrangement means one driver handles multiple casings. Required flow rate and driver type can influence selection between series and tandem arrangements. Casing selection must be optimized based on specific operating parameters. Compressors laid out in series arrangement are less reliable due to additional drivers.
Sandberg said, “Proper setup allows centrifugal compressors to run roughly seven years without maintenance.” ■