Methane from flaring, leakage, and other fugitive emissions is now public enemy number one on the environmental front. Courtesy of Shutterstock

The U.S. Environmental Protection Agency (EPA) and other regulatory bodies around the world are turning their attention to the policing of fugitive emissions from sources such as fuel leakage, unburned methane, and other greenhouse gases (GHG) sources besides those related directly to the combustion process. A big reason for the surge of interest in methane is that it is said to be anywhere from 20 to 90 times more potent than carbon dioxide as a GHG (depending on the time frame considered). Thus, it has been labelled as environmental danger number one.

The Inflation Reduction Act, for example, reduced the amount of allowable methane leakage to 1% and placed a fee of up to $1,500.00 per ton for excess methane. Canada, too, has passed methane emissions reduction rules for upstream oil and natural gas facilities. These encompass extraction, primary processing, transport, storage, leakage from compressors, and fracked gas wells.


Natural gas producers, transporters, plant operators, and the industry in general, therefore, can expect the pressure to ramp up on the monitoring, measurement, and capture of fugitive methane emissions. Previous efforts centered around the minimization of methane flaring. The latest rules, standards, and net zero commitments take things to a whole new level.


The vendor community is responding. Solutions are coming to market that measure the amount of methane that spills out from oil & gas sites, detect various sources of fugitive emissions, capture any leaked methane and reuse it in combustion and other processes, and provide better sealing technology for pipelines and compressors. It is becoming important, too, to be able to report how much methane comes into a facility and compare it to how much is burned and recaptured.


“Natural gas, which is primarily composed of methane, has been regarded as a pollutant as well as a commodity since 2016 based on standards targeting oil & gas operations,” said Brian Kromer, Managing Director and Principal, Step2Compliance. “Controls must now be able to accurately calculate GHG emissions as well as the conventional pollutants. Facilities must learn to track the amount of methane leakage and find ways to recapture it and put it to use.”


Some are even flying airborne infrared spectrometers over oil & gas production basins in attempt to quantify methane point sources. They measure wavelengths in light to estimate the amount of methane. Some say their estimates are questionable. But inflated or not, they will be used to condemn production facilities. The best response is to do everything possible to prevent leakage.


Here are some of the things the vendor community has evolved to address this issue:


EagleBurgmann has developed RoTechBooster technology to reduce methane emissions. If compressors are stopped frequently, dry gas seals may become contaminated. This can be avoided by depressurizing the compressor housing. However during this process, large amounts of methane can escape. To avoid this and maintain pressure in the compressor housing during downtime, a rotating seal gas booster can be used such as RoTechBooster. It is an electrically driven seal gas booster that keeps dry gas seals clean during standby conditions, and at any time insufficient seal gas flow occurs. Its rotating design allows the compressor to be placed in a pressurized hold for nearly unlimited time. No venting or flaring is required.


The company has also released the CobaDGS zero emission compressor seal. In higher pressure applications such as natural gas compressors, conventional tandem dry gas seals are typically used to minimize leakage of natural gas/methane. Due to their tandem design, they meet safety requirements, and reduce emissions by up to 90% compared with oil-lubricated compressor shaft seals. In addition, less friction occurs, and the service life is longer. Nevertheless, tandem dry gas seals still leak some methane into the atmosphere during operation. Another possibility to eliminate seal leakage is to use dry gas seals in double arrangement supplied with nitrogen (N2). However, this seal configuration is less safe and only approved for low pressures. Besides, if the N2 supply is interrupted, the double seals can get damaged.


“For the CobaDGS dry gas seal, EagleBurgmann adapted the coaxial design of its CobaSeal for use at higher pressures,” said Benjamin Hellmig of EagleBurgmann. “The Cobaseal is a separation seal is a coaxial design that is also supplied with N2 but is resilient to gas supply interruptions. It can remain pressurized with N2 during operation and shutdown without contamination.”


Matthias Grapow, Vice President Business Intelligence and Business Development, MAN Energy Solutions, believes that producing biogas from organic waste will grow rapidly in the coming years. The company’s HOFIM-based Factory LNG technology is used at organic waste collection sites where biomethane (aka renewable natural gas) can be liquefied from biogas. Biogas or biomethane can be used for combined heat and power (CHP) operations or turned into electricity. This approach can also be used for small-scale LNG to enable natural gas to be supplied to places not directly tied to a mainline natural gas pipeline.

HOFIM high-speed oil-free integrated motor-compressor by MAN Energy Solutions


“Through a fleet of cryogenic transport tanks, the produced LNG can be transported over long distances by truck or trains to enable the provision of energy to isolated regions,” said Grapow.


The hermetically sealed and electrically driven compression HOFIM consists of a single rotating element, two radial and one axial bearing, no couplings, no gearbox, no lube oil and no shaft seals to atmosphere. These zero emission compressors are suitable for use in midstream gas transport, gas storage, small-scale LNG, upstream subsea, and topside compression.


“Instead of flaring production-related gas losses, the gases can be reused within the process for power or heat generation, or can be converted into transportation fuel or LNG,” said Grapow.


Tom Harper, Vice President, Emissions Management and Commercial Development Leader, Climate Technology Solutions at Baker Hughes, believes that the global oil and gas industry can eliminate 40% of its methane emissions at no net cost. It has developed various tools to meet this challenge.


The company’s Lumen Terrain and Lumen Sky technologies, for example, use analytics to detect, localize, and quantify methane leaks. This information can be used to prioritize recommendations for abatement, as well as supporting the verification of emissions reductions.

The emissions profile of gas turbines, particularly methane emissions is much better than reciprocating engines. Courtesy of Siemens Energy.


Another abatement solution is flare.IQ. It enables higher-efficiency flare combustion and reduced methane slip emissions. The Egyptian Ministry of Petroleum and Mineral Resources is deploying it in the refining sector in Egypt.


“This will lower flaring emissions from oil and gas operations by digitalizing emissions management infrastructure and pulling information about flare systems, substantially reducing emissions by ensuring a higher-efficiency flare combustion rate,” said Harper.


Siemens Energy’s flagship methane offering is the Spontaneous Leak Detection Service (powered by ProFlex) for gases, liquids and multi-phase fluids transported through pipelines. It utilizes signal processing on edge computing devices, Internet of Things (IoT) software, and data processing algorithms to identify leaks in near real-time.


“Our technology can detect leaks as small as ½ inch to 2 inches within seconds and provide accurate localization to as little as +/- 20 feet, while minimizing false positives,” said Anand Sengupta, Vice-President, Head of Global Sales,
Siemens Energy Compression.

The company has also developed predictive analytics technologies and digital twins that are used in Predictive Emissions Monitoring Software (PEMS) across the Siemens Energy small gas turbines portfolio. It helps operators predict regulated emissions accurately.


“Although methane slip or unburned hydrocarbons (UHC) in the exhaust of gas turbines is orders of magnitude lower compared to other engines, we’ve received many queries from customers, and are planning to incorporate the prediction of UHC into PEMS for small gas turbines,” said Sengupta


ABB has released of HoverGuard, an addition to its ABB Ability Mobile Gas Leak Detection System. HoverGuard is an Unmanned Aerial Vehicle (UAV)-based system that detects, quantifies and maps leaks up to 300 ft from natural gas distribution and transmission pipelines, gathering lines, storage facilities, and other potential sources. It automatically generates digital reports that summarize results and can be shared in minutes after a survey.


The cloud-connected, multi-gas solution quantifies the three most important greenhouse gases (methane, carbon dioxide and water vapor) continuously while flying. Cavity-enhanced laser absorption spectroscopy detects methane with a sensitivity more than 1,000 times higher than conventional leak detection tools. It can detect leaks while flying at altitudes of 130 ft or higher, and at speeds greater than 55 mph.

Enclosed Vapor Combustors (EVCs) are available from several vendors. They are being used, for example, in some Canadian gas facilities to address leakage at compressor and meter stations. Burners convert methane into water vapor and CO2. Testing has shown this technology to be 99.6% efficient in converting methane.


Klaus Brun, Director, Research and Development, Elliott Group, said his company is using technologies from others to improve methane emissions along its product line.


“We can utilize leak-free dry-gas seals or seal vent gas capture and recovery when a client requests it,” said Brun. “Our new 140 TCH pipeline compressor has a single dry gas seal instead of two seals to reduce dry gas seal leakage by 50%.”


He noted, though, that the biggest reduction in GHG emissions from compressors can be achieved by improving compressor efficiency or by converting the driver from an engine/gas turbine to an electric motor drive. Another way to lower methane spillage is to avoid shutdowns for blowdowns. That entails improving reliability and availability and eliminating false alarms.


Solar Turbines, too, is doing a number of things to reduce methane emissions. The company uses a system that gathers the leakage from dry gas seals and recompresses it back either to fuel gas pressure or compressor suction pressure.


ExxonMobil has reduced U.S. unconventional methane emissions by approximately 40% as of year-end 2021 when compared to 2016 by conducting tens of thousands of leak surveys and eliminating all its high bleed pneumatic devices. The company has developed ground-based continuous sensors, as well as aerial, airplane and satellites technologies to help with methane reduction.


“By 2030, we’re planning a 20% to 30% reduction in corporate greenhouse gas intensity, a 70% to 80% reduction in corporate methane intensity, and a 60% to 70% reduction in corporate-wide flaring intensity,” said Matt Kolesar, Chief Environmental Scientist at ExxonMobil.


BP has targeted zero routine flaring emissions by 2025 in its U.S. onshore operations and globally by 2030. It is deploying a variety of detection and monitoring technologies and is phasing out remaining pneumatic controllers.


Teledyne Flir’s FLIR GF320 detects hydrocarbon and volatile organic compound (VOC) emissions from natural gas production and use. With this optical gas imaging camera, inspectors can check components and see potential gas leaks in real-time. The GF320 is lightweight, offers both a viewfinder and LCD monitor, and has direct access to controls. Embedded GPS data helps in identifying the precise location of faults and leaks.

The ABB drone can detect leaks and measure gases


Vortex Services of Canada offers the Vortex Emissions Target Solution. It packages a elements that address methane measurement such as a fuel measurement, fuel valves, a display panel, sensors (O2 and NOx) a catalyst monitor, and several venturi elements to improve the fuel/air mix.


Continental Controls Corp. (CCC) offers a range of fuel control, fuel measurement, and emissions monitoring tools to accurately measure GHGs. Its Catalyst Monitor continuously measures pressure across the catalyst as well as pre- and post-catalyst temperature and notifies the user if minimum or maximum temperatures are exceeded. When combined with the CCC Air Fuel Ratio Controls (AFRC), it can make corrections to set points to maintain low emissions levels and extend the useful life of catalysts. This arrangement can be used to provide evidence of engine compliance and fuel consumption over an extended period of time.


“CCC continuously measures the true rate of methane compliance,” said Kromer. “Its tools can help monitor methane related to the exhaust as well as fugitive emissions.”

The Continental Controls Catalyst Monitor continuously measures pressure across the catalyst as well as pre- and post-catalyst temperature


Utilities, owners, operators, and plant personnel are grooved in to measuring emissions in the exhaust, but not methane.


“Methane is not easy to eliminate and doesn’t go away when you use a three-way catalyst,” said Rick Fisher, Vice President at Continental Controls Corp. “Every compressor station and any plant running a gas turbine or gas engine is going to suffer methane leakage. Even something as simple as a shutting off a valve in a compressor station often leads to some venting of methane.”


Traditional monitors and controls are not set up to accurately measure methane. But owners and operators can expect stricter methane reporting such as on the amount of fuel that comes into a facility, how much was combusted, and how much methane leakage has been collected for reuse. ■


HOW THE INDUSTRY IS DEALING WITH NEW METHANE REQUIREMENTS

METHANE CAPTURE

Conventional wisdom held that President Biden’s plan to decarbonize the U.S. Power industry was wounded critically, if not fatally, by the one-two punch of the U.S. Supreme Court’s Clean Air Act ruling in West Virginia v. EPA and U.S. Senator Joe Manchin’s (D-W.Va.) resistance to supporting Biden’s plan to fight climate change.


But Manchin reversed course and agreed to support a slimmed-down piece of legislation, the Inflation Reduction Act of 2022, that would direct an estimated $369 billion to renewable energy and climate-change measures. That law broadened and extended the federal government’s intervention in the power industry that stemmed from the 2021 Infrastructure Investment and Jobs Act (IIJA), which directed tens of billions of dollars into various aspects of electric power generation and grid reliability and resilience. But the U.S. power business appears to be headed for cleaner and greener pastures, according to new-build power plant data tracked by Industrial Info Resources (IIR).


Whether the U.S. generating fleet is cleaning and greening fast enough to make a dent in global climate change is the question. The Paris Agreement of 2015 pledged to take action to limit global temperature gain to either 1.5°Celsius or 2°C above pre-industrial times. The globe is nearly there, with cumulative temperature gain of approximately 1.2° C through 2022.
As the U.S. emerged from COVID-19 restrictions in 2021 and the government distributed trillions of dollars of aid, consumers engaged in “vengeance spending,” scooping up cars, taking vacations, and renovating homes.


The reckoning started in late 2021 and mounted in 2022 as prices rose for all goods and services — including energy. Gradually, the U.S. public became familiar with supply chain bottlenecks. Across the U.S. economy, inflation rose to a four-decade high, scrambling the energy sector. For the power generation industry, the wait list for new transformers stretched as long as three years.


As natural gas prices shot up, coal made some opportunistic market-share gains among operating power plants. But the sharp price increase of fossil fuels is expected to cause U.S. electric demand growth to revert to the mean of between 0% and 1% in 2022 and 2023, according to a global electricity report from International Energy Agency (IEA).


There is, however, no evidence that gas vs. coal jockeying for market share among operating power plants has had any bearing on the power industry’s new-build rush to renewables.


Figure 1: Annual carbon emissions from coal-fired power plants.


In 2014, when then-President Barack Obama first proposed his Clean Power Plan to reduce carbon emissions from coal-fired power plants by an estimated 870 million metric tons by 2030 compared with a 2005 baseline. The rule was finalized in 2015, but was never implemented because the U.S. Supreme Court, in a highly unusual step, blocked it. Years of litigation followed. The Clean Power Plan was the most litigated rulemaking that never went into effect in U.S. history.


While litigants wrestled, the market moved. For more than a decade, electric utilities, perhaps seeing the writing on the wall but certainly driven by the Clean Air Mercury Rule of 2005 and the Mercury and Air Toxics Standards rule finalized by the EPA in 2012, began closing coal-fired generators or switching them to burn natural gas instead. Federal activity on carbon regulation was also backstopped by state public utility commissions, which compelled utilities to file integrated resource plans (IRPs) on their proposed long-term electric generation options. Increasingly, those IRPs focused on decarbonization as well as low-cost options. As renewable energy became more competitive with traditional fossil-fueled generation, regulators pressed utilities to switch to the cleaner generation.


Long before the Supreme Court handed down its decision in West Virginia v. EPA, the market accomplished what lawmakers and regulators could not: meaningfully reducing CO2 emissions from coal-fired power plants. Between 2005 and 2020, according to the U.S. Energy Information Administration (EIA), CO2 emissions from coal-fired power plants dropped by about 1.2 billion metric tons — far exceeding the aims of the Obama Clean Power Plan (Figure 1).


As a demonstration of how far and fast the market has moved, renewable energy is now expected to account for about 94% of all new-build power plant construction over the 2023-2027 period. That is up from 88% of all new-build project kick-offs only a year ago. Five years ago, renewable energy was expected to account for about 56% of all new-build power plant activity over the 2018-2022 period.


For the 2023-2027 period, the rush to renewables is generalized across the U.S., but is particularly pronounced in New England, where renewables are scheduled to account for 100% of planned power plant construction, the Midwest (98%), the West Coast and Rocky Mountains (both 96%), and the Northeast (92%) (see map).


Overall, developers have scheduled the construction of about 405 GW of new generation over the next five years. That is up about 28% from a year ago, and nearly double the planned capacity additions from two years ago (Figure 2).

Not all of that new generating capacity will be built as scheduled over the next five years. Depending on the technologies involved and developers’ ability to secure financing, lock down offtake arrangements, and achieve regulatory support, we typically see between one-quarter and one-half of all announced projects delayed or cancelled. Higher interest rates mean that fewer projects will pencil out. But then again, as we have seen over the last 30 years, new power projects are announced on a near-daily basis.


Bottom line: Renewable power developers are in the green, and carbon-based developers are singing the blues.


Figure 2: Planned new-build capacity additions increase sharply.

Figure 3: Coal burn by U.S. electric generators.


IIR is not aware of any new-build coal-fired power project that is scheduled to begin construction between 2023 and 2027. This continues a long downward trend for new-build coal as well as in the number of coal miners and overall coal use by the power sector. Coal burned by U.S. electricity generators is expected to fall slightly in 2022, to about 482 million metric tons, and a further decline for 2023 is forecast by EIA (Fig. 3). Employment in coal mines held steady at about 38,000, as mines and their customers rationalized the demand for and supply of thermal coal (Fig. 4).

Figure 4: Coal mining employment continues to drop.

The IRA and IIJA laws provide some federal dollars for carbon capture and sequestration (CCS), which could help existing coal-fired power plants stay open. But we think those credits, on their own, will not be enough to help make any proposed new-build coal plants move forward. Over the next five years, most of the project spending that will take place among coal-fired power generators is expected to be for: dismantlement & demolition (D&D); environmental remediation, such as closure and cleanup of coal ash ponds; and in-plant capital spending on maintenance and upgrades.


We estimate that about $2.85 billion will be spent on D&D activities at U.S. coal plants over the 2023-2027 period. An additional $4.4 billion is scheduled to be spent on environmental remediation over that time. A third category of coal plant project spending, in-plant capital spending, covering boiler revamps, fuel switching, generator rewinds and turbine refurbishments, will reach about $820 million over the next five years. And $600 million is expected to be invested in planned maintenance at coal-fired generators over the next 2023-2027 period.


Although Coal Country welcomed the Supreme Court decision in West Virginia v. EPA, and cheered Joe Manchin’s months-long resistance to the president’s climate legislation, there was scant possibility that either would reinvigorate coal-fired generation or lead to the construction of new coal-fired generation. Mid-summer analyses from Morgan Stanley and Glenrock Associated were even bleaker: the Supreme Court decision in West Virginia would not create an opportunity to extend the lives of existing coal-fired generators, much less build new plants, analysts said. The court decision may be a setback for the Biden administration, “but utilities aren’t changing their plans,” according to Paul Patterson, an equity analyst with Glenrock Associates. He added that most of the action on reducing greenhouse gas emissions (GHGs) from the power sector has been driven by state policies, federal tax incentives, and corporate green power purchasing decisions. In the absence of federal action, there were plenty of other drivers pushing coal to the margins.

Once a coal plant is deactivated and mothballed, it’s not economic to reverse course and bring it back online. Approximately 115 GW of U.S. coal-fired generation was closed between 2011 and 2021. Going forward, we expect another 44 GW of coal-fired generation to be closed by 2025 (Fig. 5).

Numerous asset owners announced the closure of coal-fired power plants in 2022 or moved up the closure dates. During the year, the PJM Interconnection deactivated about 3.2 GW of coal-fired generation, most of which was owned by Energy Harbor. AES announced plans to exit coal by 2025. Duke told investors it would be coal-free by 2035. Xcel Energy plans to stop using coal by 2032. Public Service Company of New Mexico announced plans to close two units of its San Juan complex in September. There were many other announcements along these lines.


Another driver working against new-build coal generation is the rise of Environmental, Social and Governance (ESG) investing. More than 3,400 institutional investors have signed the U.N. Principles for Responsible Investing (PRI), and their assets under management (AUM) exceeded $121 trillion as of March 30, 2021 (Fig. 6). That means developers seeking to build new coal-fired generation have fewer places to source their capital.

Figure 6: ESG investing continues to grow.

In a cruel irony, it may be that the most valuable assets owned by retired or retiring coal-fired power plants are their transmission lines and their land. Numerous coal-fired plant sites — including those in Illinois, Colorado, Nevada, New Mexico, North Dakota, Nebraska, Minnesota and Maryland — are slated to be transformed into renewable energy and/or battery energy storage projects in the next few years, according to an investigation by The New York Times. In addition, two retired coal-fired power plants in Massachusetts and New Jersey are scheduled to be converted to receive power generated by offshore wind farms. Further out, Bill Gates-backed TerraPower has plans to build a small nuclear power plant on the grounds of a Wyoming coal-fired power plant that is scheduled to be closed in the late 2020s.


The outlook for new-build natural gas generation in the U.S. has dimmed considerably in recent years. Looking forward to the 2023-2027 period, that erosion is expected to continue. Over the next five years, new-build natural gas generators are scheduled to account for only 5% of all new powerplants scheduled to be built. Last year, that percentage was about 11%, and five years ago it stood at about 41% (Fig. 7).

Figure 7: Proposed New-Build Generation, Renewables vs. Gas


What happened? One view is that gas became a victim of the “Carbon is Public Enemy #1” campaign undertaken by environmental organizations. A more nuanced perspective is that the hands of regulators have been tied by state laws and goals on renewable portfolio standards (RPS) and GHG reduction. Gas has a bleak future in states that are driving down their GHGs while increasing their RPSs.


On a percentage basis, the Mid-Atlantic region has the highest share of proposed new-build gas generators in the U.S., accounting for about 14% of all new power plants scheduled to be built over the 2023-2027 period. Following the Mid-Atlantic are the Great Lakes (12%), the Northeast (8%) and Southwest (7%). In terms of raw numbers, the Southwest has scheduled construction of the greatest amount of new-build gas-fired generation, at 5,456 MW, followed by the Great Lakes (5,376 MW) and the Mid-Atlantic (3,033 MW) regions.
Over two dozen proposed gas-fired generators that were scheduled to be built over the next five years have been cancelled. The aggregate value of those proposed projects exceeds $13 billion. The states with the largest number of project cancellations on a project-dollar basis are: Virginia ($1.8 billion); Texas, Pennsylvania and New Jersey ($1 billion each); and Florida, California and West Virginia (all slightly less than $1 billion each).


An additional 41 new-build gas-fired generation projects with aggregate value of $15.8 billion were scheduled to begin construction over the next five years but have been delayed. Texas is far and away the state with the largest dollar-value of project delays, at more than $8 billion, followed by Michigan ($2 billion) and Ohio ($1 billion). COVID-19 has been the cause of some of those project delays. The pandemic caused labor and materials shortfalls that have affected the entire power industry. Some of these delayed gas power projects could become reactivated over the next five years.


Organized wholesale regions like ERCOT (Electric Reliability Council of Texas) and MISO (Mid-Continent Independent System Operator) have sounded alarms of a potential generation shortfall in recent years, and the heat dome of Summer 2022 stretched those regions to the limit. Electric emergencies or rolling blackouts could focus the minds of regulators on the need for more dispatchable capacity. This bears watching, as events could cause regulators to relent and permit some new gas power development.


It is too soon to declare new-build gas plants a dead artifact of the 20th century. The thousands of MW of renewable energy that are operating, under construction or scheduled to be built will need to be backed up. That challenge outstrips the current capabilities of battery energy storage systems, even leaving aside the technological challenges of lithium ion battery systems, as well as concerns over the available supply of lithium. Pumped storage hydro facilities could be paired with intermittent generation, but the cost and timeline for building new pumped-storage facilities is daunting. In short, as much as policymakers and developers want to quickly move toward higher reliance on non-emitting generation, we see a continued need for new-build gas-fired generation.

In addition to new-build generation, IIR is tracking more than $13 billion in planned in-plant capital spending at U.S. gas plants over the next five years. Also, developers, engineers, and analysts are investigating the potential to co-fire gas plants with hydrogen.


Figure 8: A more granular view of renewables.


Even before Senator Manchin reversed course over the summer and supported the president’s slimmed down climate-change bill, plans to build renewable energy generating capacity over the next five years were exploding. They have risen to about 379 GW or 94% of all planned new-build capacity over the next five years. Last year, renewables were scheduled to account for 88% of all new-build construction over the 2022-2026 period. Five years ago, for the 2018-2022 period, that percentage was 55%.


In assessing the new-build generation market, we did not include renewable energy plants that could get built due to the Inflation Reduction Act of 2022, as the thinner version of “Build Back Better” was tabbed. That proposal, with an estimated $369 billion in clean electricity funding, includes Production Tax Credits (PTCs) for wind, solar and battery energy storage, among other things. The PTC for solar power would be new, as that industry has depended on Investment Tax Credits (ITCs) for years. If anything, our estimate for the new-build renewable generation market for the next five years could be conservative.


On a percentage basis, the U.S. regions with the greenest hues are: New England (where 100% of new-build generation is expected to be renewable); Rocky Mountains and West Coast (each 96%). On a MW-basis, the regions leading the green power parade are: Rocky Mountains (133 GW), Southwest (78 GW), Great Lakes (39 GW), and West Coast (36 GW). Again, we don’t expect all this planned renewable generation to be built as proposed. But the 2023-2027 period is starting off with an enormous number of renewable energy projects.


“Other” renewable energy projects, such as hydropower and geothermal, are expected to account for as much as 49 GW, or about 12% of all renewable capacity scheduled to be built over the next five years. Hydropower, in particular, is expected to benefit from some $754 million in incentives contained in the Infrastructure Investment and Jobs Act, signed into law in late 2021 by President Biden. New-build hydro could also benefit from the Inflation Reduction Act of 2022, depending on how the enabling legislation is written: Will hydro be defined as a “renewable” source of energy? Given that people define “renewable energy” differently, we thought it would be helpful to provide a more granular look at how plans to build renewable energy break down.


The “run to the sun” has accelerated in recent years. In a category once dominated by wind power, plans to build solar generation have taken a decisive lead, with 49% of planned renewable new-build capacity, or about 184 GW, set to begin construction over the next five years (Fig. 8). Areas with the greatest amount of planned solar generation construction include the Rocky Mountains (55 GW), Southwest (52 GW), Great Lakes (26 GW) and West Coast (13 GW). A huge countervailing factor that could limit the growth in new-build solar is the rise in prices that started to become evident in 2021. The supply-chain bottlenecks and soaring costs for materials have derailed or delayed some of these planned solar projects.


Among renewable projects, wind power has long been the hare to the solar industry’s tortoise. But for the next five years, wind power will fall into second place with about 22% of all new-build generation, or about 82 GW. The U.S. regions with the greatest amount of wind power project activity over the 2023-2027 period, measured on a GW basis, include the Rocky Mountains (about 23 GW), Midwest (17 GW), Southwest (10 GW), and New England and Great Lakes (9 GW each).

Figure 9: BESS operating capacity shoots up.

Figure 10: Actual and planned BESS capacity.


Plans to build battery energy storage systems (BESS) have skyrocketed in recent years. Developers have announced plans to build as much as 64 GW of BESS over the next five years. Data from the EIA shows that developers proposed to sharply increase large-scale BESS projects between 2022 and 2024. Operational BESS capacity more than tripled in 2021, to 4.6 GW from 1.4 GW in 2020, according to the EIA (Fig 9). Most of that capacity was being deployed by regional transmission organizations (RTOs). Going forward, construction of new BESS capacity is expected to surge. The EIA projects BESS capacity will shoot up from an estimated 4.6 GW in 2021 to about 22 GW by 2025 (Fig. 10). About 382 BESS projects are scheduled to be built over the next five years, valued collectively at about $81.1 billion. The regions with the greatest amount of BESS construction activity are the: Rocky Mountains, with 76 projects valued at $33.3 billion; Southwest, with 109 projects valued at $23 billion; and West Coast, with 76 projects valued at $12 billion.


The first iteration of the nuclear renaissance looks like it will be ending with a whimper, not a bang: the last new-build nuclear power project, the two-unit addition to the Alvin W. Vogtle Nuclear Power Station, is scheduled to finish construction in 2023. Years late and billions of dollars over budget, the Vogtle unit additions, totaling 2,234 MW, were expected to be the showcase of a revived nuclear industry when they were announced in 2008.


The two new units now have an estimated $32 billion price tag, nearly three times the original cost of $12 billion. If the units are brought online in 2023, it will be roughly seven years after the first unit was scheduled to begin commercial operations. The owners, led by project manager Georgia Power Company, are embroiled in litigation over who pays what for the project. And GPC can expect some tough questioning from the Georgia Public Service Commission when prudency hearings begin.


As difficult as the Vogtle experience has been, and for the Virgil C. Summer Nuclear Power Station before it, at least those plants succeeded in getting steel in the ground. Another nuclear plant announced at the same time as Vogtle, the Green River Blue Castle Nuclear Power Station in Utah, hasn’t made it out of the starting gate, and may never. That two-unit project, with total generating capacity of 2,000 MW, has been under development since 2008. It was designed to use two Westinghouse AP1000 reactors before Westinghouse exited the nuclear business with a 2017 Chapter 11 bankruptcy. Currently, the developer plans to begin construction in 2025. There are more questions than answers for that Utah project.


For a lot of reasons, utility leaders have been looking elsewhere for carbon-free generation that can be dispatched. The thinking now is the future is smaller — specifically, small modular reactors (SMR). One SMR design, from NuScale Power, received an approval from the U.S. Nuclear Regulatory Commission in August 2020. The Utah Associated Municipal Power Systems is trying to develop SMRs at Idaho Falls, Idaho. And Terra Power is eyeing construction of a different type of nuclear reactor, a sodium-cooled plant to be built at a soon-to-be retired coal-fired power plant in Wyoming. Both of those projects are scheduled to begin construction toward the end of the 2023-2027 timeframe. Also near the end of 2023-2027, the Tennessee Valley Authority and OPG (Ontario Power Generation) plan to begin construction of SMRs in Oak Ridge, Tennessee.


The Inflation Reduction Act law contained production tax credits for nuclear, recognizing its role in decarbonizing the electricity industry. IIR doesn’t think those tax credits will be enough, on their own, to lead to new-build nuclear power plants over the next five years, but they would help keep existing plants open. On that front, license-renewal applications for several plants are likely over the next few years, including Comanche Peak (Units 1 & 2) in late 2022, Perry in 2023 and Clinton in 2024. IIR also is tracking almost $1.5 billion in scheduled maintenance activity and more than $33 billion of in-plant nuclear capital spending over the next five years. These figures don't include new-build nuclear construction projects.


In another sign of a nuclear resurgence, some in California are advocating that Diablo Canyon remain open after its scheduled closure dates of 2024-25, to provide generation and grid support for the energy-hungry Golden State.


Project spending by commercial, industrial, and institutional (CI&I) customers to construct non-utility generation in the U.S. has increased in recent years, and  IIR expects that trend will continue over the 2023-2027 period. There are various drivers:

•	Renewable onsite generation is being constructed by CI&I customers for decarbonization or GHG-reduction goals.
•	Some large customers have been investing in onsite generation to ensure always-on power.
•	Some are building onsite generation to offset the rising cost of electricity from utilities.
•	Large energy-hungry operations like data centers and bit-coin-mining operations have built industrial energy producers (IEPs) to ensure predictably priced power.
•	Local environmental regulations are causing some to replace diesel-powered generators with natural gas or even renewable natural gas.
•	Some power-sensitive manufacturers have resorted to building generation when local power quality is low.
•	CI&I customers that are remotely sited are installing independent power generation to ensure 24/7 operations. 

Sometimes this non-utility generation powers a microgrid. Other times it is for standby or emergency uses. As more companies in the CI&I sector tabulate the true cost of power outages or low power quality, we expect a growing number will choose to install their own generation.


New opportunities for this generation are presenting themselves. Although the idea behind distributed generation is that it will be used to power a particular site, ISOs and RTOs increasingly are seeking to interconnect the non-utility generation with the grid in order to provide reserve power or voltage support when grid-connected generation is stressed or stretched. Several independent system operators (ISOs) and RTOs across the country count on these resources to be ready to operate when the grid needs them. ERCOT, the system operator that supports most of Texas, is counting on these generators. Several times during 2022, ERCOT has called upon these resources to help meet the state’s peak electric demand.


Other states, such as New York and California, are pushing to connect these independent energy generators to their respective grids. Some studies have shown that use of onsite generation assets can cut overall power generation spending by 20% or more. As the rising price of natural gas pushes up the price of power purchase agreements, the installation of onsite power assets is becoming more appealing. IIR is tracking plans to spend more than $10 billion on non-utility generation over the 2023-2027 period. That number does not include smaller generation assets, such as rooftop solar or generators that have less than 300 KW of capacity.


Non-utility generation, like all other segments of the power business, is working to repair its damaged supply chain. The current three-year wait for transformers, plus bottlenecks and rising costs for solar photovoltaic and battery energy-storage materials, are evidence that broken supply chains are nowhere near repaired.


Microgrids are becoming more popular among CI&I customers for the same reasons as independent energy production. When powered by renewable generation, microgrids sometimes are part of an organization’s decarbonization push. When powered by fossil fuels, microgrids may backstop utility-supplied power. Microgrids can be part of grid strengthening and hardening, as we see after each bout of extreme weather.


Spending on microgrids could reach several billion dollars annually during 2023-2027. CI&I customers and utilities are finding that microgrids can fill an important need. Some utilities deploy them as part of a multifaceted effort to prevent wildfires, or to support remote communities at risk of outages.


The industrial sector looks to microgrids for onsite power during times of need and for protection against cybercriminals. Microgrids also provide power to the grid during peak demand. Industrial Info is tracking plans to invest more than $2.4 billion in microgrids over the next five years, (not counting potential commercial or residential). Microgrid projects are experiencing supply chain shortages, and competition for required skilled workers and equipment.


In the same way that transmission organizations and local utilities sometimes call on independent energy generators to fire up and provide generation or capacity to the grid during times of high demand or resilience events, microgrid operators are receiving similar emergency requests for grid support.


Over the 2023-2027 period, we expect new-build power to be characterized by market disruptions including: Technologies that generate electricity or support transmission and distribution; economic assessments of options; environmental regulations and exigencies surrounding generation; the regulatory framework; inflow of federal funds to support generation technologies; and consumer expectations.


The predicted rise of electric transport will likely add new strain to electric distribution networks and generation. But now, the power industry faces another disruption from employee expectations. A growing number want greater work flexibility. If employers want to win the war for talent, they need to learn to flexible and responsive to this aspect of industry disruption. 

_____________________________________________

Britt Burt is Vice President of Global Power Industry Research for Industrial Info Resources (IIR), which is headquartered in Sugar Land, Texas, and has offices in North America and around the world.

Brock Ramey is a North American Power Specialist for IIR, which provides global market intelligence for companies in the power, heavy manufacturing and industrial process businesses. For more information see www.industrialinfo.com or email powergroup@industrialinfo.com

CAN ANYTHING REVERSE THE RUSH TO RENEWABLES?

U.S. POWER INDUSTRY OUTLOOK 2023

Courtesy of Texas A&M’s Turbomachinery Laboratory

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.

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).

The suitability of various energy storage technologies based on the amount of storage they provide and their capacity capabilities. Courtesy of Southwest Research Institute.

“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.” ■

Refrigeration Compression, Turbine Performance, Compressor Advances, Carbon Capture, and Energy Storage

TURBOMACHINERY SYMPOSIUM 2022

Federal regulation of interstate gas transmission in the United States is regulated by the Federal Energy Regulatory Commission (FERC). FERC’s main concern is assuring the maximum seasonal flow capacity of an interstate gas transmission system. Therefore, compressor stations must have sufficient available driver horsepower to meet compression horsepower requirements for each compressor installation regardless of whether full driver horsepower is needed or used. This criterion must be met for FERC to certify the interstate transmission system’s maximum seasonal capacities.

FERC does not directly address oper-ational flexibility and efficient operation to certify compliance and therefore pipe-line compressors rarely operate near their design point. Operational flexibility and efficient operations are left to individual interstate transmission companies since system throughput varies throughout the year due to daily and seasonal fluctua-tions of supply and demand. 


This article exposes shortcomings to traditional manufacturer centrifugal compressor performance maps. Yet it is also apparent that these performance maps are not utilized effectively for their gas turbine drivers. This analysis indicates that maximum gas turbine horsepower is not sufficient to utilize the complete compressor performance map because compressor manufacturers generally choose to provide maximum flow design conditions at operations around 80% turbine speed. Therefore, larger horsepower turbine drives are being specified and purchased to satisfy FERC certification. The maximum horsepower available of a large turbine drive may never be utilized since the compressor manufacturer intentionally chose the FERC certified capacity to occur at a reduced speed (80%).




A gas turbine’s available horsepower depends on atmospheric pressure and temperature. The required compression horsepower depends on pipeline flow conditions (i.e. gas composition, pressure, temperature, etc.).

Centrifugal compressor performance maps provided by vendors provide plenty of operational information (i.e. speed, head, flow, and efficiency); however, this is not necessarily sufficient to determine if the operation of the gas-turbine/compressor unit can satisfy the operational requirements dictated by ambient and pipeline conditions.

The traditional Head versus Flow performance map identifies the performance envelope to determine compression horsepower. These maps may not provide a clear picture of the possible operation available to the user in terms that are commonly used throughout the industry. For the past seventy years, there has been little improvement in user communication via the compressor map format.


Therefore, new methods for evaluating, designing, and optimizing centrifugal compressor maps used in natural gas transmission systems have been developed. Based on these methods, the most commonly used driver that powers many pipeline compressors lacks the flexibility to effectively and efficiently utilize the complete speed and efficiency ranges provided by the centrifugal compressor manufacturer.

 Compressor manufacturers develop performance maps after receiving information based on specified design conditions from pipeline design engineers. This includes the maximum capacity at inlet and outlet design conditions needed to meet FERC certification.

Compressor manufacturers commonly locate the design point (Figure 1) using the design conditions along the highest efficiency line (82.5%) and at or above 80% speed. Yet pipeline compressors rarely operate near their design point resulting in operations at reduced compressor and driver efficiencies, and gas recycling.



Figure 1: Typical manufacturer compressor map. This map has seven speed lines (50% - 105%) and six efficiency lines (70% -82.5%) with the resulting forty-two speed/efficiency intersection points to be used in the evaluation.



The forty-two intersection points within the boundaries of surge and stone-wall can be considered valid operating points from the compressor vendor’s standpoint. But they are not necessarily valid operating points unless the driver can provide the required compression horsepower.


A centrifugal compressor map provides the pipeline design engineer with information to determine where possible compression operations exist given head and flow coordinates. However, the map does not necessarily indicate if operation is possible since ambient conditions dictate if the gas turbine can provide the compression horsepower needed. It would be more useful to have a snapshot of all theoretical and physically possible operating points based on pipeline supply/demand conditions, daily or seasonal variations in pipeline operations, and changes in ambient conditions. These conditions could be substantially different from design condition. A clearer picture of what the compressor/driver can do under off-design conditions would be helpful.

Using the information in Figure 1, Figure 2 provides physically possible operations at the appropriate intersecting speed and efficiency lines. Fortunately, the operation at design conditions is possible at 80% speed as predicted by the compressor manufacturer.

Years of gas industry operating experience with gas turbine-driven centrifugal compressors has shown that operations should not be considered below the 80% speed due to increased maintenance and operational costs. As general rule-of-thumb, a 20% reduction in driver speed translates to a 50% horsepower reduction and an increasing gas turbine fuel rate.

Inspection of Figure 2 shows only the operations with sufficient driver horsepower while Figure 1 shows possible compressor operations without the driver information. Figure 2 is more useful as it identifies those operations that are physically possible due to sufficient available driver horsepower.




Figure 2: Available compressor map @120⁰F



Pipeline design engineers use terms like head, ACFM, efficiency, and speed when dealing with compressor performance maps. These terms do not clearly communicate the operation of a centrifugal compressor installation to other functional company groups. Figure 2 lacks the terminology commonly used between functional groups such as volumetric flow at standard conditions, Qstd (MMscfd), suction pressure, Ps (Psia), and discharge pressure, Pd (Psia). More informative compressor performance maps are presented in Figures 3 & 4 with terms commonly used throughout the natural gas industry.






Changes in ambient temperature can readily be presented in this format. Decreasing the ambient temperature from 120⁰F to 32⁰F provides additional operation at 90% speed and three additional operating points at 100% speed (Figures 3 and 4). These charts provide operating points on the compressor performance map where there is sufficient driver horsepower from 50% to 100% speed but without a horsepower amount.

Figure 5 provides additional information concerning available (BHPavail) and utilized (BHPutil) horsepower versus volumetric flow rate (Qstd). Many operating points utilize less than half of the available driver horsepower which limits efficient driver operations. There is a substantial difference in available and utilized driver horsepower at lower speeds. At 50% RPM, utilized horsepower is 17% of available driver horsepower; 99% of available horsepower is utilized at 90% speed.


In the 32℉ ambient temperature case (Figure 6), the utilized horsepower can be as low as 18% and as high as 97% of available horsepower at 50% and 100% speed, respectively. Figure 6 depicts an increase in speed range from 90% to 100% due to the lower ambient temperature with three out of six points on the 100% speed line having sufficient driver horsepower.




Figure 5: Available and utilized horsepower @ 120⁰F GT inlet temperature.

Figure 6: Available and utilized horsepower @ 32⁰F GT inlet temperature.


A season needs to be selected for optimizing the manufacture’s compressor map. To comply with FERC certification, the winter season (32℉) was selected. The summer season (120℉) was used to bracket optimization.

Maps were developed to show operation before and after optimizing the manufacturer’s compressor map. Three values were generated: 1) BHPreqd: The required compressor horsepower, 2) BHPutil: The utilized driver horsepower needed to physically satisfy compression needs, 3) BHPavail: Maximum available driver horsepower available at ambient conditions. These three values are plotted against Qmax (MMscfd) (Figures 7 and 8) for a 120⁰F ambient temperature.

The following conditions need to be satisfied at all 42 points for complete map operation to be physically possible: BHPreqd =BHPutil ≤ BHPavail. Figure 7 shows substantial levels of BHPreqd above 90% speed. Therefore, operations above 90% speed are not possible. Figure 8 shows after optimization of the initial manufacturer’s compression map additional operations are available at 90% speed.





Figure 7 –Before optimization @ 120⁰F

Figure 8 – After optimization @ 120⁰F



Prior to optimization, results show an operational improvement at 32℉ (Figure 9). After optimization, all of the required horsepower, BHPreqd, is equal to the utilized horsepower, BHPutil.




Figure 10: After optimization @ 32⁰F. 





As Figure 10 (32℉) indicates, the entire optimized compressor map can be utilized. Figure 10 supports the fact that sufficient driver horsepower is available to allow operations within the optimized compressor operating envelop. The final optimized compressor map with all possible operating points for Winter (32℉) is shown in Figure 11.



Figure 11: Optimized flow map @ 32⁰F GT inlet temperature



A sensitivity analysis was also performed by varying the design inlet pressure +/-50 Psia (Figures 12 to 15). The results indicated no problems in achieving the design flow rate at the design discharge pressure (Pd) with the available horsepower (BHPavial) at 32℉.




Figure 12 – Horsepower (@ -50 Psia & 32⁰F) Figure 13 - Flow Map (@ -50 Psia & 32⁰F)

Figure 13 - Flow Map(@ -50 Psia & 32⁰F)

Figure 14 – Horsepower (@ +50 Psia & 32⁰F)

Figure 15 - Flow Map (@ +50 Psia & 32⁰F)



As stated earlier, operations below 80% speed should be limited due to increased maintenance and operational driver costs. Even with compressor map optimization, there remains the problem that most possible physical operations exist below 80% gas turbine driver speed.

An alternate compressor driver capable of providing complete and efficient compressor map coverage would be needed to obtain operations on the complete, optimized compressor map. But years of operating experience with gas turbine-driven centrifugal compressors has shown that operations should not be considered below the 80% speed. Thus,


1. Optimization of existing and new compressor maps provides insight into limitations in operational flexibility of large ISO horsepower gas turbines (7,150-31,050hp) given driver constraints.


2. The replacement of a gas turbine driver with a driver that can perform efficiently and effectively at 50% to 100% compressor speed levels is needed to utilize the entire centrifugal compressor map based on the results provided. The complete compressor performance map will be made available at lower speeds in the event that such a driver becomes available.


3. Analysis indicates larger capital-intensive gas turbines are specified because compressor manufacturers chose to provide maximum flow design conditions at inefficient operations around 80% turbine speed. Therefore, users purchase larger horsepower turbine drives and never utilize their horsepower capabilities.




Reconfiguration of interstate natural gas compressor stations from gas-driven compression only to electrical power generation for gas compression and electrical power sales can benefit optimum full-load operation of the existing gas turbines. The excess electrical power produced could supplement renewable energy derived from wind, solar, geothermal or nuclear sources supplying electrical power in the absence of a conventional power station during events such as the 2021 Texas Electrical Reliability Council of Texas (ERCOT) rolling-blackout since the gas supply is available directly at the compressor station(s).

Additionally, if the variable speed electric motor drive becomes an option, replacement of the currently installed compressor(s) with new hermitically sealed electric motor driven compressors should be considered along with adding new electrical generator(s) coupled to the existing gas turbine(s). The existing gas turbine(s) could now operate at 100% load powering the electrical generator(s) to supply power for either gas compression or to the electrical grid. There would be times during seasonal demand for gas compression (Winter residential heating) or power generation (Summer – electrical power for cooling). And if a viable variable speed electric motor drive option becomes available in the 50% to 100% speed range then the electric motor driver’s power characteristics should be used to develop an optimum compressor/driver map. There will be no need to simulate seasonal horsepower changes due to ambient conditions since seasonal changes do not affect the horsepower rating of an electric drive. 



Evaluation, Design, and Optimization of Centrifugal Compressor Performance Maps

COMPRESSOR MAPS

Centrifugal pumps are used in many plants and facilities. Many are operated in parallel. There are risks, difficulties, and concerns to consider for parallel operation of pumps. There are factors and parameters which should be considered to mitigate these risks.


Many pumps, after all, have been damaged due to poor configuration, wrong selection, or operational carelessness in parallel operation. Further general knowledge on pump parallel operation is relatively low. There has been limited publication material available on this important topic.


Unfortunately, some engineers have been led to believe that pumps are like home appliances. They think they can put them in parallel operation and expect trouble-free operation. This is not true. The fact that pumps in parallel operation take suction from a common source and discharge into a common header is often overlooked. The fact that the pumps interact with each other is also poorly understood.


Different types of pump, of course, present different behaviours when in the parallel operation. As an example, so called “sensitive pumps”, which are more affected by operation far from BEP (best efficiency point), can be more troublesome when used in parallel operation.

There have been many reasons to put pumps in parallel operation. Sometimes, it is to cover a wide range of flow requirements. In other situations, they are installed in parallel for standby requirements or emergency backup. In an expansion or renovation program, a few new pumps may be added to an existing set to increase pumping capacity.

When pumps run in parallel, they would be expected to operate against the same discharge head. The combined pump “head-capacity” performance curve is, theoretically, determined by adding the respective flow rates of each pump at a series of specific head values. However, this is purely theoretical. There are many practical factors and parameters which should be considered.

If pumps are not properly selected for parallel operation, it can lead to inefficient operation, pump unreli ability, damage, and other problems.

If pumps are not properly selected for parallel operation and all required provisions for potentially complicated operation are not foreseen, it can lead to inefficient operation, pump unreliability, damage, and other operational problems. When wrongly selected pumps are operated in parallel, one of the pumps might be driven outside of its allowable operating range (far from BEP), even near shutoff point. This can result in overheating and pump damage.

Parallel operation of identical pumps is a better-known topic than operation of dissimilar pumps. There are established rules for the parallel operation of identical pumps. Performance curves should be matched within specified tolerances. In other words, although pumps are theoretically identical, because of differences in manufacturing and tolerances, their curves are slightly different. The differences between curves should be limited to 2% to avoid problems.


Dissimilar pumps operating in parallel introduce engineering complexity. The head should be matched at rated point of each pump (not at the same volumetric flow rate points). Parallel operation of dissimilar pumps is most often seen in revamp, renovation, or expansion projects.

For a revamp/renovation case, the head of new pump rated point should be matched with the head of the existing pump rated point (each has its own volumetric flow rate) considering the elevation head difference and frictional head difference (at downstream) for each pump. The surrounding area of rated points should offer a suitable operating condition for all pumps.

When dissimilar pumps are operated in parallel, however, there is risk if any pump is pushed to operate below its minimum allowable flow rate. As a practical measure, the pump manufacturer should be asked to simulate operation and explain all operational details and guarantee trouble-free operation for all combinations of parallel operation. In addition, operating points for all operating scenarios should be plotted and compared between the minimum continuous flow and the end of curve. A full simulation exercise and a study report for all possible parallel operation cases should be requested.


The shape of the “head–capacity” performance curve should be carefully considered when selecting pumps for parallel operation. If the pump curve droops (the head drops) as the flow is reduced towards shutoff point, there can be operational problems. In this case, when the first pump is started, a second pump may not be able to move from the shutoff point. This pump could run near shutoff, overheat, and possibly fail.

In other words, pumps in parallel operation work against the same discharge head. For a curve with more than one flow condition for a given head, a pump can be stuck near shutoff. This pump could fail over time. As a general rule, the performance curve should continuously rise to the shutoff point. In other words, pumps with head-capacity curves that droop towards shutoff point or have more than one flow condition for a given head, should not be operated in parallel. 

Amin Almasi is a Chartered Professional Engineer in Australia and U.K. (M.Sc. and B.Sc. in mechanical engineering). He is a senior consultant specializing in rotating equipment, condition monitoring and reliability

CHALLENGES AND DIFFICULTIES OF PARALLEL OPERATION 

TURBO TIPS: CENTRIFUGAL PUMPS

Oil & gas companies are under intense pressure to decarbonize and lead the energy transition while meeting production goals. For many assets including pipeline compression stations, gas and LNG plants, and production sites, generating the horsepower required for compression can be a significant contributor to both facility emissions and OPEX.


Selecting the type of machine to perform this duty has historically been a binary decision for operators – with most opting for either an electric motor or mechanical drive solution, such as a gas turbine or reciprocating engine. However, a strong business case can be made for combining one or more mechanical drive components with an electric motor (or motor-generator) into a single hybrid/dual drive train. These configurations can offer advantages over single-drive systems including flexibility, efficiency, lower costs, and a reduced carbon footprint.

Figure 1: Simplified layout for a hybrid/dual drive train.


Many facilities, particularly pipeline compression stations, already feature both electric motor and gas turbine-driven trains. By using different drivers, operators can avoid being locked into a singular energy supply. Operating two trains means at least partial station operation if or when one needs to be shut down for maintenance. However, having separate trains does not always constitute the most efficient equipment arrangement, as one train might be sitting idle for much of the year.

A hybrid/dual drive may be a better option in certain circumstances by affording operators the same flexibility to use available gas or grid electricity as their energy source but without the complexity of installing two trains. This lowers CAPEX as ancillary infrastructure is greatly reduced such as foundations, piping, wiring, cabling, electrical systems, and Balance of Plant (BoP).

Example: Electric motor-driven (EMD) compression is being viewed as one facet of decarbonization. On grids with a high percentage of wind and solar, an operator can use an EMD to run compressors during off-peak hours when prices are low and grid stability is high. The gas turbine would only be started up when electrical power is not available or prices were high.

As the motor can be designed to dually work as a generator, it also becomes possible to use any extra power from the turbine to produce electricity for site duty. The additional electricity can potentially be sold back to the grid. Grid connectivity, too, requires constant gas turbine speed. This can be achieved with advanced electronics. Similar flexibility is also provided by using variable inlet guide vanes (VIGVs).

Another scenario where a hybrid drive can be beneficial is at sites with gas turbine-driven compression trains that experience large temperature fluctuations due to seasonality. Available power from gas turbines decreases as the ambient temperature increases. As a result, units are often oversized to ensure sufficient power during the hot summer months. However, the same gas turbine may generate much more power during the winter than the compression train requires. This results in low-load operation of the gas turbine, reduced efficiency, and increased emissions.

Opting for a hybrid drive by installing an electric motor on the shaft end of the compressor opposite the gas turbine can solve this problem (assuming a grid connection is available). In such cases, a smaller turbine can be selected to operate fully loaded. The motor or motor-generator supplies any additional horse-power required when the temperature rises above design point. If the turbine produces more horsepower than is required for the compression duty in colder months, the motor-generator can be used to produce additional electricity, which can be used at the site or sold to the grid. By running the gas turbine at an optimal load, NO􀀁 and CO emissions are reduced. Fuel consumption and associated CO₂ emissions are also decreased.


Depending on the application and specific type of equipment used, multiple dual drive configurations are possible. In the case of centrifugal or integrally geared compressors with two shaft ends available, a typical arrangement would involve installing an electric motor or motor-generator on one side of the compressor shaft end and the gas turbine on the other. The need for clutches and gearboxes will be determined by the type of motor used and operation of the compression train.

THE CASE FOR HYBRID DRIVE COMPRESSION TRAINS

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