Turbomachinery & Pump Symposia 2024: Emerging Technologies in the Spotlight

The 2024 Turbomachinery & Pump Symposia (TPS), held Aug. 20 - 22 at the George R. Brown Convention Center in Houston, boasted over 4,500 attendees and more than 300 exhibitors. Organized by Texas A&M’s Turbomachinery Laboratory, attendees from over 50 countries gathered to hear engineers, directors, and managers discuss optimizing compressor anti-surge control systems, integrating CO₂ capture plants, bottoming cycles, and more.

George R. Brown Convention Center in Houston, TX. Credit: Adobe Stock

ANTI-SURGE CONTROL SYSTEMS

Presenters from Compressor Controls Corp. (CCC) and Petrobras hosted a paper presentation, Optimizing Compressors Anti-Surge Control to Reduce Power Consumption and Greenhouse Gases Emissions in Oil Production Units, analyzing the energy and carbon performance of compressor anti-surge control systems on existing offshore platforms in the Brazilian pre-salt fields.

According to Fabio Jacinto Zanetti De Souza, Brownfield Account Manager at CCC: “The primary function of the anti-surge control system is to prevent the centrifugal compressor from operating under surge conditions, which is a potentially damaging phenomenon for the compressor. However, the secondary functions of an anti-surge control system are often overlooked or unaddressed by many providers. It can help maintain specific suction pressure in centrifugal compressors through a Ps limit loop or prevent reaching a high discharge pressure through a Pd limit loop. The system also avoids high discharge temperature that could lead to a trip due to high Td or manipulate the anti-surge valve for periodic stroke tests and send operators an alarm if the valve demonstrates some level of stickiness. The anti-surge control can also be used to avoid critical speeds during startup of an expander-recompressor arrangement in natural gas liquids plants or even prevent overspeed.”

FPSO Compressor Challenges

Pedro Barbosa, Turbomachinery Advisor at Petrobras laid out several challenges with running a gas compressor on a floating production, storage, and offloading (FPSO) vessel in the Brazilian pre-salt fields:

• Gas compressors are the largest power consumers and greenhouse gas emitters aboard an FPSO vessel „
• FPSOs have highly variable operating conditions over unit lifecycle „
• Following startup, gas compressors are difficult to tune „
• Pre-salt FPSOs contain complex plants with high CO₂ content „
• Gas reinjection increases CO₂ content, affecting compressor curves and surge lines

Barbosa addressed further compressor difficulties that could be assisted by anti-surge control. “When the unit is treating gas for exportation, it passes through a CO₂ removal plant to the export compressors, then to a gas pipeline,” said Barbosa. “The compressors begin to work in a non-flow-sharing mode, meaning that one machine can be used for exportation and the other rejects non-treated gas. The machines begin to compete, with one increasing flow and the other decreasing— this is when surge control becomes important.”

Controlling the Surge

According to Serge Staroselsky, Chief Technology Officer at CCC, Petrobras leveraged an anti-surge control system to achieve multiple performance benefits: equipment protection, improved efficiency, increased reliability, and enhanced safety.

Equipment Protection: Anti-surge systems detect when a compressor is approaching surge conditions and take corrective action to prevent the condition from occurring. By preventing surge, these systems can help to reduce the frequency and cost of maintenance and repairs.

Improved Efficiency: They can help to optimize compressor operation by maintaining their most efficient point, thus reducing energy consumption. Minimizing unnecessary power output keeps gas compressors from emitting large amounts of CO₂ from FPSOs.

Increased Reliability: The systems reduce compressor downtime and improve overall plant productivity and process stability. Controlling system margins, such as anti-surge valve performance and flow measurement signal quality, can also reduce gas recycling.

Enhanced Safety: Surge can lead to dangerous conditions, such as sudden pressure surges or vibrations. Anti-surge systems can help reduce the risk of accidents and improve overall safety on FPSO vessels.

Following anti-surge control integration, “We calculate the operating point of the machines, we calculate power, and then we assess anti-surge valve closing to see how much we’ll save,” said Staroselsky. “After the calculations, we reduced the margin by 5% and, in the minimum case, saved 170 kW of power. In the maximum case, during operation over the entire year, we could generate around 500 kW in potential savings.”

Carbon Mitigation

Combining optimized turbomachinery controls with the appropriate energy and carbon-performance management system help decarbonize offshore operations, “by ensuring that energy consumption and emissions are minimized through precise control and monitoring,” De Souza said. “Optimized controls enhance the efficiency of turbomachinery, reducing the power required for operation, while the performance management system tracks energy use and carbon emissions in real-time. This integrated approach allows for continuous adjustments and improvements, ensuring that operations remain as efficient and low-emission as possible, ultimately leading to significant reductions in the carbon footprint of offshore oil production units.”

After utilizing the compressor anti-surge control system, De Souza said the reduction in recycle flow on the Petrobras project would lead to an overall efficiency increase of 4%. “On an FPSO powered by gas turbogenerators, it will reduce fuel-gas consumption by 630,000 standard cubic meters per year. The carbon emissions saved with this optimization would reach 1,600 tons of CO₂ per year. All these numbers are calculated for a single 11-MW compressor train—an FPSO contains five to six of these trains.”

INTEGRATING CO₂ CAPTURE PLANTS

The industry is familiar with carbon-capture technologies’ ability to remove CO₂ from flue gas streams. Still, the challenges of providing the flue gas in the correct conditions and supplying the energy required for the CO₂ capture process are less well-known.

The technical session, Integration of CO₂ Capture Plants with Open Cycle Gas Turbines, reviewed the most common types of carbon-capture technologies and explored how open-cycle gas turbines could achieve similar results.

Technology Selection

Mike Welch, Industry Marketing Manager at Siemens Energy, said gas turbines can achieve decarbonization by firing low-carbon fuels and their plants can be equipped with post-combustion capture technology. Despite these carbon capabilities, users typically favor traditional technologies over gas turbines for capture applications, citing low CO₂ concentration in exhaust (3 - 4%) and high exhaust gas temperatures as the primary challenges.

He outlined several considerations for choosing carbon-capture technologies, including:

• Desired capture rate
• CO₂ capture amount
• Available space at location
• Energy and water availability
• Impact of NOx and SOx on solvent life and replacement rate

According to Welch, carbon capture is a difficult process when using gas turbines: “The only certain thing about CO₂ capture is that you’ll need a lot of space, and it’ll cost you a lot of money—it’s not a cheap solution. Most processes are designed to operate at low ambient temperatures, so you become limited to the available technologies when operating with a gas turbine. There are only a few that don’t require cooling of the gas turbine exhaust and most of the emerging technologies can’t support large-scale turbines.”

Available Systems

Despite the inherent challenges of running current carbon-capture technologies in conjunction with gas turbines, there are many available systems in use today. The most common are amine-based systems, which utilize proven solvents to absorb CO₂ with low toxicity and low energy demand for desorption. However, these solutions have large footprints and long construction times, with higher energy demand for absorption.

Modular Amine Towers: Often applied to smaller emitters that generate less than 1,000 tons of CO₂ per day. With a smaller footprint, towers have shorter construction times and can be used at space-constrained sites, such as offshore platforms.

Rotating Packed Beds: Features enhanced CO₂ adsorption through centrifugal force, but generally lower capture rates at approximately 100 tons per day.

Potassium Carbonate: Proven for gas processing and scalable to large CO₂ capture volumes. The energy demand is similar to amine towers, but these systems can use hot water for solvent desorption. On the downside, potassium carbonate operates with low flue gas inlet temperatures.

Hot Potassium Carbonate: Unlike typical potassium carbonate, it operates at high flue gas temperatures in a pressurized process. It can generate its own electricity and gas turbine supplementary firing can increase CO₂ concentration.

Membranes: These are also proven for gas processing but struggle when applied to gas turbines, as multiple modules are required to achieve the desired capture rate and purity. Membrane contactor modules are a hybrid solution combined with amine solvents.

Cryogenics: Freezes CO₂ out of the flue gas stream.

Electrochemical: Electro-swing adsorption can be used on gas streams with any CO₂ concentration and, according to electrochemical operators, can selectively capture NOx and SOx.

CO₂ Compression and Utilization

Lukas Biyikli, R&D Portfolio Manager of Integrally Geared Compressors at Siemens Energy, outlined the basics of CO₂ compression and utilization processes following capture. Although compression is the primary electricity consumer in carbon-capture plants, it is a critical step for transportation via pipeline—the most economical way to move CO₂ from point A to point B. The main equipment for compression applications is reciprocating, single-shaft, and integrally geared compressors.

Although compression is the primary electricity consumer in carbon-capture plant, it is a critical step for transportation via pipeline—the most economical way to move CO₂ from point A to point B. - Lukas Biyikli

Biyikli pointed out: “Through heat recovery from compressors, hot water for district heating or process steam up to 10 bar is available via heat exchangers by adapting the compressor design slightly. There is a great synergy between the heat and steam demand that conventional amine-based capture systems have and the steam provided by the compressors since amine systems typically require high amounts of saturated steam between 3 and 6 bar—in range of what the compressor can deliver. Siemens Energy’s concept provides up to 80% of the steam demand for an amine system while only increasing the power requirement of the compressor by onesixth of that heat provided compared to conventional compressor operation, which means a coefficient of performance of up to 6.0 for the system.”

ANALYZING GAS TURBINES

The tutorial, Performance of Industrial Gas Turbines and Bottoming Cycles, led by Karl Wygant, Senior Manager at Ebara Elliott Energy, Klaus Brun, Director of Global R&D at Ebara Elliott Energy, and Rainer Kurz, Principal of RKSBenergy, discussed control strategies and performance characteristics for the engine compressor, combustor, and turbine section.

In addition to covering energy flow concepts between turbine components, the panel outlined control concepts for single- and two-shaft machines, driving generators, compressors, and pumps. Bottoming cycle performance is also discussed, with methods to use performance data for trending and comparison analyses.

Thermodynamics

Brun led the discussion on gas turbine thermodynamics, which began with descriptions of both enthalpy and entropy. “Enthalpy has many definitions, but from the easiest perspective it’s energy per unit/ mass or how much energy you have in the process fluid, which is air in a gas turbine and water in a steam turbine. Entropy can be described as the second law of thermodynamics. If entropy is very high, you have a lot of losses in the system.”

Gas turbine thermodynamic cycles are typically based on the Brayton cycle, which consists of four main processes:

• Isentropic Compression: The working fluid (usually air) is compressed in a compressor, increasing its pressure and temperature.
• Constant Pressure Heat Addition: The compressed air is heated in a combustion chamber by burning fuel, increasing its temperature at constant pressure.
• Isentropic Expansion: The hot, high-pressure gas expands through a turbine, producing mechanical work and decreasing its temperature and pressure.
• Constant Pressure Heat Rejection: The expanded gas is cooled in a heat exchanger (if present), rejecting heat to the surroundings at constant pressure.

Bottoming Cycles

Wygant closed out the tutorial by highlighting the three most common bottoming cycles for industrial gas turbines: the Steam Rankine, Organic Rankine, and Closed Brayton cycles.

The Steam Rankine cycle uses water or steam as the working fluid—waste heat is used to boil water into steam, which drives the turbine to generate electricity. This cycle is less efficient at lower temperatures due to water’s high boiling point.

Organic Rankine Cycles use organic fluids, such as hydrocarbons and refrigerants, in a similar process to the aforementioned steam cycle. With a lower boiling point working fluid, it allows for efficient operation at lower temperatures, flexible design, and a wider range of applicable fluids.

Lastly, the Closed Brayton Cycle uses gas as its working fluid—waste heat is used to heat a gas, which expands through a turbine to generate electricity. The gas is then compressed and the cycle repeats. It maintains high efficiency at high temperatures, potential for combined-cycle applications (with a gas turbine), and a relatively simple design.