"Elections have consequences,” goes the political adage. That was particularly true for the electricity generation business during the first year of the new administration. On Day 1, President Biden issued a flurry of executive orders, including one to make the electric generation business carbon-free by 2035 as a step toward a net-zero carbon economy by 2050. 

All federal agencies were instructed to review, with an eye to reversing, all actions taken by the Trump administration that might conflict with or undermine the new president’s commitment to decarbonize the electricity business and the broader economy. 

“Confronting the carbon crisis” became a catchphrase. In some ways, this follows in the wake of the electricity business, which has been decarbonizing for years. That trend has been the product of federal and state tax incentives, state regulatory mandates, and technological gains that have improved the cost competitiveness of renewable energy. A growing preference for no- or low-carbon electricity also continued to gain traction among consumers and businesses during 2021.

A January 20, 2021, executive order revoked several executive orders from his predecessor on energy and electricity. Other Day 1 moves included returning the U.S. to the Paris Agreement and establishing an interagency working group to determine the social cost of greenhouse gases. Former EPA Administrator Gina McCarthy also became the first-ever White House national climate advisor. 

“The world must be put on a sustainable climate pathway to protect Americans and the domestic economy from harmful climate impacts, and to create well-paying union jobs as part of the climate solution,” the executive order stated.

The U.S. transformation from hydrocarbon-based electric generation to lesser or non-emitting generation accelerated during 2021, and most experts see further acceleration in the years to come. 

Although the COVID-19 pandemic cut overall electricity demand by 3.9% in 2020, the virus did not alter the existing trend to build fewer new power plants that burned coal or gas. For the 2022- 2026 period, Industrial Info Resources (IIR) expects renewables will continue to constitute the overwhelming majority of new-build U.S. electric generation projects, accounting for about 88% of all new electric generation capacity. Gas will account for about 11% over that five year period, with nuclear, fuel oil and coal sharing the remaining 1% of new generation construction (see map).

About 316,000 megawatts (MW) of new-build generation projects are being tracked with a scheduled construction start date between 2022 and 2026. Not all planned projects will be constructed according to their original schedules. Depending on the technologies involved, and developers’ ability to secure financing, offtake arrangements, and regulatory support, we typically see between one-quarter and one-half of all announced projects delayed or cancelled. But then again, new projects are announced on a near-daily basis. 

While all 316,000 MW of new generation are not expected to be built as announced, the trend for the 2022-2026 period is clear and consistent with longstanding projections: cleaner and greener new-build generation. 

And while coal has been out of favor in the new-build market for some time, the black rock certainly came to the rescue of existing electric generators and consumers in 2021. 

Once COVID-19 vaccines became readily available, U.S. consumers responded with a vengeance, driving up gross national product (GNP) and with it, electricity demand. For 2021, the U.S. economy is expected to grow 6.6%, and another 5% in 2022, according to mid-year 2021 projections from the U.S. Energy Information Administration (EIA). Based on projected strong economic growth (and assuming COVID is contained), the agency forecasts 2021 electric demand to grow about 2.7%.

Figure 1: Electric generators expected to increase use of coal in 2021, 2022 Source: Electric Power Monthly and Short-Term Energy Outlook reports, U.S. Energy Information Administration.

Rising electricity demand in 2021 came as natural gas prices were on the upswing, rising about 60% through the first seven months of 2021, to about $4 per million British thermal units (MMBtu). For 2021, the EIA projected gas will average $4.46 per MMBtu. 

Generators that could switch fuels increased their use of coal in 2021, driving up coal use about 17% compared with 2020 (Figure 1). The EIA’s preliminary estimate of coal use in 2022 by power generators shows a decline of about 9% in 2022, as asset owners switch back to what they assume will be lower-cost gas. But as wave after wave of summer heat drove up electric demand, gas prices similarly went upward while coal stayed relatively flat. Could coal hold onto some of its newfound gains in the electric fuels market in 2022? 

Figure 2: Coal inventories at U.S. generators forecast to fall below five-year average Source: U.S. EIA Short-Term Energy Outlook (July 2021).

Figure 3: Investors jump onto ESG train Source: United Nations Principles for Responsible Investment.

Electricity generators drew down on their coal inventories to meet rising demand, according to EIA estimates (Figure 2). Roughly 23% of U.S. electricity was generated by coal in 2021, up from 20% in 2020, the EIA said. In 2022, coal’s market share is expected to fall to 21%. Existing coal- and gas-fired generators continued their bare-knuckled fight in the electric fuels market, where a shift of a few pennies per MMBtu can cause generators to swing from one fuel to the other. 

New-build coal-fired generation, however, continued to struggle in 2021 and faces a bleak future over the 2022-2026 period. Another recent force increasing King Coal’s misery has been the rising influence of environmental, social and governance (ESG) investing, which effectively bans investment in the coal business. By some calculations, ESG assets under management (AUM) soared to more than $100 trillion by the end of 2020 (Figure 3). 

During 2021, generators across the U.S. announced plans to phase out coal in the pursuit of net-zero carbon emissions. That trend is expected to continue in 2022 and beyond. 

The Tennessee Valley Authority (TVA), for example, has retired or announced the retirement of about 8,600 MW of coal-fired generation. It is evaluating the impact of retiring the remaining 6,000 MW of its coal fleet by 2035. That retired generation has been replaced by adding nuclear, solar and gas-fired generation as well as upgrading its hydroelectric power stations. 

In a mid-year 2021 announcement, TVA said it planned to invest about $1 billion to build new gas-fired combustion turbine generators totaling approximately 1,500 MW. The new facilities will replace aging gas-fired combustion turbines. 

In announcing that decision, Jacinda Woodward, senior vice president of power operations at TVA, said, “As we continue to evolve our generation portfolio, natural gas is the right choice at this time because it provides the flexibility and reliability we need to add more solar energy. It’s important to remember that solar power is an intermittent generation source, but natural gas delivers reliable electricity even when the sun doesn’t shine.” TVA will continue to consider natural gas’ role in its fuel mix as it studies the closure of its remaining coal fleet by 2035 while adding about 10,000 MW of new solar generation. 

TVA’s announcement came during a year when asset owners from Oregon to Florida announced plans to accelerate their move away from coal. During 2021, coal plant closure announcements were made by numerous asset owners, including Consumers Energy, Alliant Energy, Vistra, GenOn, Xcel Energy, PPL, Minnesota Power, NRG, Mississippi Power, American Electric Power and Lakeland (Fla.) Electric. 

Figure 4: Planned new-build capacity additions jump sharply Source: Industrial Info Resources.

IIR expects a surge in renewable energy construction over the 2022-2026 period, which would push overall new-build generation for that period to nearly 316,000 MW, up nearly 50% from the five-year plans of only one year ago (Figure 4).

At mid-year 2021, roughly 42,000 people were working as coal miners, up slightly over the year-earlier number of about 39,700. But the ranks of coal miners have thinned by about 75% since 1985, according to data tracked by the St. Louis Federal Reserve (Figure 5). 

Figure 5: U.S. coal-mining employment rises a bit. Source: Federal Reserve Bank of St. Louis. 

In recent decades, employment in industry has been crippled by increased automation of mining, coupled with demand being crushed by ever-more stringent environment regulations, and the rising competitiveness of substitute fuels like gas and renewables. 

U.S. generators closed more than 100,000 MW of coal-fired generation between 2010 and 2020, and another 34,000 MW is expected to close during the next five years, according to data tracked by IIR (Figure 6). Though some states, like Wyoming, have tried to erect legal barriers to the closure of coal mines and coal-fired power plants, most observers don’t think those laws will be upheld by the courts. Economics more than laws will determine the future of coal and coal-fired generation in the U.S. 

Over the 2022-2026 period, construction is unlikely to begin on any new-build coal-fired power plants. Capital spending at coal generators will be for environmental remediation, particularly cleaning up coal ash ponds, and in-plant capital improvements like turbine upgrades.

Figure 6: U.S. coal-fired generating capacity retirements, actual and planned Source: Industrial Info Resources.

Construction on about 35,000 MW of new-build natural gas-fired generators is expected to start during the 2022-2026 period. That’s about 11% of the 316,000 MW of new generation that developers plan to begin building during that fiveyear timeframe (Figure 7). The areas with the greatest amount of planned new-build gas generation are the Great Lakes, the Mid-Atlantic, the Southwest, the Rocky Mountains, and the Northeast. Very little new gas generation is scheduled to be built in the Southeast, Midwest, or West Coast. 

Figure 7: U.S. planned new-build gas generation continues to decline Source: Industrial Info Resources.

Developers and asset owners who have delayed or cancelled gas-fired, newbuild generation typically cite “market forces” as the reason for their decision. That covers a wide range of factors, including an inability to obtain financing, reach offtake agreements, or secure transmission rights. As gas pipelines start to run into opposition, stymied gas pipeline projects like the Atlantic Coast Pipeline are another market force with which developers have to contend. Finally, another powerful market force is a state’s regulatory regime, and several have turned against gas in recent years.

Renewables will continue to constitute the overwhelming majority of new-build U.S. electric generation projects. 

That’s certainly the case in California, Arizona and New York, where state commitments to reduce greenhouse gas emissions in the electric sector or increase the percentage of renewable energy in the electric mix work against gas. In addition, methane emissions have emerged as another market force working against natural gas generation. Methane is a much more potent greenhouse gas than carbon dioxide, at least over the short term.

The cancellation or delay of approximately 48 new-build gas-fired power plants has been documented in 25 states that were scheduled to begin construction in 2021. The total investment value of those plants was about $12.6 billion. As more states, and possibly the federal government, enact measures that cut against gas-fired generation, the number of new-build generation projects should continue to decline over the 2022-2026 period. 

Figure 8: Planned new-build gas-fired generation, by region over five-year periods (GW) Source: IIR.

About 35,000 MW of new-build gas-fired generation is scheduled to begin construction between 2022 and 2026. That is down a little over 10% from last year’s five-year tally and about 60% less than what was planned to kick off construction during the 2019-2023 period.

It was not that long ago that the power industry was proclaiming a “dash to gas,” as coal plants closed and before sharp declines in renewable energy costs. But recent trends shows a dramatic slowdown in new-build gas generation. Though most U.S. regions show a decline in planned gas-fired project kickoffs, the most dramatic declines are in the West Coast and Southwest (Figure 8).

Figure 9: Proposed New-Build Generation, Renewables vs. Gas Source: IIR.

Gas’ loss has been renewables’ gain. Renewables are now projected to account for about 88% of all U.S. new-build generation capacity over the 2022- 2026 period, roughly eight times the amount of gas-fired generation scheduled to be built over that time (Figure 9). That gap has widened over time. In 2018 looking at a five-year construction cycle between 2019 and 2023, renewables were scheduled to account for about 57% of all new-build generation scheduled to be built in the U.S compared with 41% for gas. But renewables’ improving cost competitiveness stemming from efficiency gains, coupled with a growing embrace by regulators and Corporate America, has widened its lead in the new-build race.

Over the next five years, solar is expected to surpass wind for the first time in utility-scale renewable energy construction (Figure 10). The widespread popularity of rooftop solar, both for residential and commercial settings, is not reflected in Figure 10, so the growing popularity of rooftop solar likely would give that energy source an even larger slice of the renewables’ pie.

Fig. 10 Planned Renewables Construction, 2022-2026 Source: Industrial Info Resources.

About 1,450 renewable energy projects are scheduled to begin construction over the next five years. Those projects have a total investment value of about $390 billion. 

Again, all of those projects are unlikely to begin construction as scheduled. But over the next five years, the new-build renewable power business looks particularly green in the Rocky Mountains, the Southwest, the Great Lakes and the West Coast (Figure 11). 

Figure 11: Dollar value of planned new-build renewable energy generation Source: Industrial Info Resources.

Figure 12: Dollar value of planned new-build windpower, by region Source: Industrial Info Resources.

Nevada and Arizona are the states in the Rocky Mountain region with the largest dollar value of solar projects under development. In the Southwest, solar project activity is taking place almost exclusively in Texas. The Great Lakes region also has a robust pipeline of solar projects being developed, with Ohio and Indiana in the lead, followed by Kentucky and Illinois, according to project data being tracked. 

Although fewer wind projects are being developed than in prior years, mostly because the areas with the best quality wind resource already have been tapped, the Rockies, Midwest, Southwest and New England are the regions with the largest dollar-value of wind power projects scheduled to begin construction between January 2022 and December 2026 (Figure 12). The Rockies, Wyoming, New Mexico, and Arizona are the regions and states with the largest dollar value of wind projects under development, according to data tracked.

The $390 billion of renewable energy projects under development include 27 offshore wind projects valued at about $39 billion. The Atlantic Ocean is far and away the leading body of water for proposed offshore wind power projects. The Biden administration wants to see as much as 30 gigawatts (GW) of offshore wind power developed in the Atlantic Ocean by 2030.

When politicians try to fight against markets, markets often win. We saw that most clearly in the Trump administration, which unsuccessfully fought against market forces to try to restore coal in the electric fuel mix. But Biden is taking the opposite approach, working to accelerate market-driven changes already well underway.

While in years past renewable energy projects would have had to include the cost of a transmission line to bring the energy to a market hub, several renewable energy projects announced during 2021 plan to be built on or near large shuttered plants to take advantage of existing transmission infrastructure.

Examples are NextEra Energy’s plan to construct a 690 MW solar plant next to its closed Duane Arnold nuclear plant in Iowa, and Xcel Energy’s plan to build a 460 MW solar plant on the site of its soon-to-be-closed Sherco plant in Minnesota. There should be many more over the next five years. Use of existing transmission lines also enables a developer to fast-track their project around clogged queues in regional markets.

The outlook for new-build nuclear is as bleak as the outlook for renewables is upbeat. The only planned new-build nuclear project, the Blue Castle nuclear power station in Utah, continues to be developed, with a planned construction start date of spring 2025 and a projected start-up date of mid-2032. The Blue Castle project is expected to utilize two 1,100-MW advanced passive reactors from Westinghouse. This project has been on the books for more than a decade, and its projected costs have mounted as its commercial operation date has been pushed back. There is a very low probability of this project ever getting built.

At the other end of the spectrum, a small modular reactor (SMR) project called the Carbon-Free Power Project continues to be developed by the Utah Associated Municipal Power Systems (UAMPS), a group of community-owned electric utilities across the intermountain West. 

In 2020, the group received a ten-year, $1.4-billion grant from the U.S. Department of Energy to develop and deploy 720 MW of SMRs in 60-MW modules. Originally, 12 were planned to be built at the Idaho National Laboratory in Eastern Idaho, with construction starting in 2025. But plans for that project were scaled back in mid-2021, as some UAMPS utilities rethought their participation in the project. 

Now, the UAMPS project envisions constructing only six modules, but a spokesperson for the group said these modules will be more efficient than previously thought. Instead of 720 MW consisting of 12 60-MW modules, the project now consists of six modules of 77 MW each, for a total of 462 MW.

Across the country in Tennessee, the Tennessee Valley Authority (TVA) is also contemplating SMRs as part of its plan to decarbonize generation. The agency has big hopes for the smaller nuclear generators, but its long-term resource plan does not contemplate construction beginning until 2027 at the earliest. 

The only new-build nuclear project still being constructed in the U.S. is the two-unit addition to the Alvin W. Vogtle Nuclear Power Station in Waynesboro, Georgia. Helmed by Southern Company subsidiary Georgia Power, Unit 3 expected to begin operating sometime during 2022. Unit 4 is scheduled to begin operating about one year later. 

As the project missed milestone after milestone in recent years, a construction oversight panel filed ever-gloomier reports about the costs and in-service dates of the two new units. A mid-2021 report from that oversight panel cast serious doubt on Georgia Power’s projected in-service dates for Units 3 and 4, and said construction costs could be as much as $2.4 billion over the most recent agreed-upon amount. 

Whenever those units are finished and whatever their eventual cost, expect a pitched fight at the Georgia Public Service Commission (GPSC) over how much of its investment Georgia Power can recoup from its customers. The unit addition’s other three owners, all municipal agencies, are not jurisdictional at the GPSC. But whatever that panel decides about Georgia Power’s 45.7% stake in the two new units could cast a long shadow over the other three owners’ regulatory decisions about the prudence of that investment, the quality of construction, and the effectiveness of construction management.

The other owners of Vogtle units 3 and 4 are Oglethorpe Power Corporation, a 30% owner, the Municipal Electric Authority of Georgia, which has a 22.7% stake, and Dalton Utilities, a 1.6% owner. Most of the value of work scheduled to be performed on nuclear plants over the next five years exists at the other end of the product life cycle: dismantling and decommissioning shuttered nuclear plants. A dozen closed nuclear stations are awaiting D&D work totaling about $19 billion. 

Roughly two dozen in-plant capital projects for nuclear generators are being tracked, including steam generator replacements, control upgrades, and extended power uprates. The value of this work is about $1.8 billion.

The outlook continues to brighten for battery energy storage systems (BESS) to become a more significant part of today’s marketplace (Figure 13). Regulators are providing incentives and allowing it to enter regional markets as a stand-alone generation resource. BESS is utilized for many applications, including: stand-alone generation resource; grid stability; renewable energy utilization; and storage for thermal generation.

Figure 13. Sharp increase expected in deployment of battery energy storage systems Source: US EIA.

Demand for BESS is rising, particularly in areas prone to natural disasters. The fast-paced push in the West Coast and Southwest to integrate these systems into electric markets is another factor creating a boom in this sector. 

In ERCOT, there is over 40 GW of BESS in early-to late-stage development being proposed for 2021-2023. This number may decline as projects confront permitting challenges, financing hurdles, and regional transmission constraints. 

Another driver for BESS growth is the late-2020 extension of the federal Investment Tax Credit (ITC) for solar energy. The guidelines grant ITCs to BESS assets based on its proximity to solar generation, its ownership, and whether it was being charged at least 75% of the time. The extension of the Production Tax Credit (PTC) for wind energy did not include a BESS provision. 

Like many other projects, BESS suffered COVID-19 supply-chain issues. The strong demand growth for lithium may act as a limiting factor in the near term, as projected demand for that metal, used in electric vehicles, cell phones, smart devices as well as battery energy storage projects, far exceeds estimated supply. There have been calls to expand lithium processing facilities in the U.S., but any such project would be years away from commercial operations. 

About 3.5 GW of battery energy storage that will become operational in 2021 is being tracked, an 80% increase over the capacity that began operating in 2020. Another 4.3 GW of BESS capacity is slated to come online in the U.S. by the end of 2022. The West Coast and Southwest are the regions with the highest level of project activity for BESS.

Currently, the U.S. has 115 operational microgrids that include over 2 GW of generation, according to the EIA. The referenced microgrids range from a segment of 500 kW to more than 100 MW.

Right now, these microgrids are being installed at military bases, universities and colleges, hospitals, police, fire and first responder stations, industrial complexes, government centers, and other settings where a high value is placed on having uninterrupted power. The annual spend to install microgrids is expected to be just below $1 billion in 2021. 

The pandemic dramatically slowed the deployment of microgrids in 2020 and 2021, and may not see a rebound until the pandemic and all its variants is conclusively defeated. COVID created a near-term pause in deployments, but growth should resume, possibly by mid-2022. The regions with the highest interest in microgrids are the West Coast and Southwest.

Natural disasters and prolonged power interruptions tend to drive microgrid deployment decisions, and there has been no shortage of natural disasters and power outages in recent years. Years of wildfires in the West, flooding, hurricanes, and the Texas grid breakdown of February 2021 are likely to lead a wider appreciation of the benefits of microgrids that utilize distributed generation such as solar or wind plus BESS. 

The cost of a microgrid will not be irrelevant in a company’s or agency’s planning. But we expect more projects will achieve financial viability when entities sharpen their proverbial pencils and take a closer look at the cost of a microgrid compared to the cost of power interruptions or unreliable power. 

Utility-scale microgrid projects, on the other hand, have encountered a variety of headwinds — including regulatory, permitting and financing — in recent years. Those headwinds have caused many projects to stall or be shelved. Construction costs continue to be a high hurdle to overcome at an estimated $2.6 million to $4 million per installed MW of capacity. 

State and federal grants for research & development have supported microgrid deployment. Congress is scheduled to consider a clean energy bill that includes up to $1.5 billion for microgrid R&D grants. About $2 billion in planned microgrid spending for 2022 is being tracked, a doubling of planned spending for 2021.

Over the last several years, distributed energy resources (DER) have become a more important element of the power generation business. As a category, DER includes a wide range of assets in smaller-scale settings, typically less than 10 MW in size. Types of DER include: small combined heat and power (CHP) units; wind; solar; battery storage; flywheel; biomass; waste-to-energy incinerators; small hydropower; fuel cells; reciprocating internal combustion engines (RICE); and generation that is part of a microgrid. 

DER also includes onsite power generation located at industrial or institutional sites such as colleges, universities, chemical processing plants, refineries, medical centers, military bases, manufacturing plants, and more. 

More than 29 GW of DER generation currently under development across the country is being tracked, with an additional 1.4 GW of generation in the early planning stage, with possible deployment by 2022- 2023. The regions with the largest planned spend on DER are the Southwest, Northeast, and Rocky Mountains. 

Orders 828 and 842 from the Federal Energy Regulatory Commission (FERC) determined that DERs deserve to be compensated if they provide generation or frequency support. Utility generation owners continue to have some concerns about FERC Order 842. 

In September 2020, FERC issued Order 2222, which expanded the definition of DER to include rooftop solar, electric vehicle charging system (EVC), and other micro-generation sources when coupled together. FERC followed that order with 2222-A, issued in March 2021, which removed other barriers to aggregated DERs in wholesale markets.

It is unclear whether full decarbonization of the U.S. electricity business can be achieved by 2035. But in the current business climate, decarbonization doubters have largely gone underground. Those advocating cleaner and greener power are driving the narrative.

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The Biden Administration stresses new-build renewables, but rising gas prices gave new life to coal-fired generators. 

US Power Industry outlook 2022

Axial compressors are used in processes where a large amount of gas is required, providing high efficiency relative to their size. Industrial applications include first-stage mixed refrigerant compressors in LNG plants, main blowers in refineries using the catalytic cracking process, and blowers for blast furnaces in steel mills.

Figure 1: A set of hypothetical constant speed performance curves typical for axial compressors with A points as surge points; and B points as choke points. The operating point (OP) on the curve is located approximately halfway from the surge and choke points.

There are two restrictions on the operation of dynamic compressors caused by different phenomena: at relatively low flow rates - surge; and at relatively high flow rates, a choke or a stone wall. These conditions must be taken into account in design so they can be prevented.

Due to the severity of surge and the much higher likelihood that compressors will operate at relatively low flow rates, this issue has received more attention. The surge phenomenon can be described as erratic operation accompanied by strong mechanical vibration, rotational speed fluctuations, pressure fluctuations, gas velocity fluctuations, and rapid temperature rise with possible overheating and abnormal sound generation. The choke phenomenon can be defined as increased vibration, temperature rise, and a rapid drop in efficiency. If the choke is not as strong as the surge, prolonged operation in the choke zone may damage the compressor.

Both surge and choke are fluid mechanics phenomena that occur in compressors under certain circumstances. Dynamically unstable compressor operation due to surge or rapid efficiency drops due to choke can occur at different speeds, inlet pressure, inlet temperature, and different molecular weight of gases (in LNG applications). Therefore, the theory of experimental fluid mechanics must be applied.

The principles of similarity and dimensional analysis are used to generate modified dimensionless compressor maps with fixed surge and choke limiting lines for all inlet conditions, gas compositions, and rotational speeds, which can then be used in various surge and choke protecting algorithms. The most commonly used dimensionless coordinates of such maps are compression ratio and corrected mass flow rate.

Close-loop PID controllers are typically used to regulate anti-surge valves to protect compressors from surge, and to regulate inlet guide vanes (IGV) or outlet valves to prevent compressor choking by comparing the controlled variable (CV) to the desired SP setpoint. There are various compressor protection algorithms that calculate the CV that characterizes the position of the operating point relative to the choke line, represented in dimension-less rectangular coordinates.

The most commonly used choke protection algorithm in industrial control systems, or its derivative, defines the CV (%) as the distance from the operating point to a point on the choke line at the same compression ratio. Other algorithms define the CV (%) as the distance from the operating point to the point on the choke line at the same mass flow. In rectangular coordinate systems, the distance between points on a curve and the curve itself are projections onto a horizontal or vertical axis.

The first algorithm requires extrapolating the choke line so that the vertical coordinate passes through it. Compressors are selected to operate at points with maximum efficiency, somewhere between the surge point and the operating point OP (Figure 1) in a curve where the accuracy of calculating the controlled variable to protect compressor from choke is minimal, since the position of the point (B)Rc is an assumption. The accuracy of the operating point calculation increases as the choke point is approached, but may still be inaccurate within the safety threshold.

Figure 2: The constant speed performance curve has rays emanating from an imaginary center point, indicating possible movements of the operating point along the curve, from the surge point to the choke point in polar coordinates: from the polar angle to the polar angle. Position of the operating point OP is determined by the polar angle.

Algorithms of the second type seem preferable, since the projection of the operating point on the horizontal axis always intersects the choke line. In such algorithms, the displacement of the operating point is determined by the vertical coordinate of the compression ratio as a function of the horizontal coordinate of the corrected mass flow rate, then a small change in distance between the intersection point (B) on the choke line and the choke point can significantly change the distance, which makes it difficult to tune the PID controller for its fast response.

Setting the safety threshold in rectangular coordinate systems can only be made relative to the choke line, since the entire operating range is not available. The compressor performance curves on the plane are geometrically limited to perpendicularly oriented lines to reproduce the entire operating range from the surge point to the choke point, which is achievable in a polar coordinate system defining this range as a rotation from the polar angle to the polar angle. Therefore, the controlled variable CV (%) for the choke protection controller can be calculated as the choke point polar angle minus the operating point polar angle divided by the entire range, which is equal to the choke point polar angle minus the surge point polar angle. 

Polar coordinates provide the most accurate representation of the operating point in relation to surge and choke limits, reproducing the full range of operating points at which the safety threshold control setpoint can be set exactly as required. And the controlled variable calculated in the polar coordinate, is an almost linear variable, which makes it easier to tune the PID controllers.

Compressor choke

BY HASANUR JAMAL MOLLA, SAAD H. AL-DOSSARY, TARIQ NADEEM, AND MOHAMMAD F. AL-SHIHRI.

Varnish is an organic residue produced by irreversible chemical degradation of mineral oil lubricants. It can lead to filter plugging, restricted oil flow, poor heat transfer, valve sticking, fail-to-start conditions, and unit trips. 

During rotating equipment operation, heat generated due to friction degrades the oil and produces very small by-product particles that settle throughout the system as varnish. Spark discharges from static charge buildup in the lubricating oil filters play a key role in its formation. Over time, these particles attach themselves to surfaces throughout the turbine, producing a sticky film. As varnish builds up, performance of rotating equipment suffers. 

A variety of varnish removal systems are avail-able in the market. As the conversion between soluble and insoluble varnish is a physical equilibrium process dependent upon temperature, Varnish Removal Units (VRU) are equipped with a cooler to reduce the oil temperature and convert soluble into insoluble varnish. Special filter media inside the VRU capture dissolved and suspended soft contaminants from the oil.

Varnish is a sub-micron-sized soft contaminant that is polar in nature. Oxidation and thermal breakdown are among the causes of varnish formation. But the two major reasons are micro-dieseling and static electric discharge. 

In micro-dieseling, the implosion of entrained air bubbles as they migrate from low-pressure zones to high-pressure zones creates a local oil temperature in excess of 1,800ºF. This is enough to cause severe oxidation of oil molecules and generates carbonaceous byproducts. As system pressures increase, the potential for micro-dieseling rises.

The industry’s shift to synthetic and glass filter media has created unexpected side effects due to the combination of tighter filter pore sizes to remove fine sediment with very high filter flux rates to reduce capital cost. The result is significant static charge buildup within the oil system. These spontaneous discharges can generate sparks of static electricity with temperatures greater than 18,000ºF. This “cooks” the oil, creating molecule fragments that deplete antioxidant additives. The oil circuit where there is metal-on-metal contact can also generate a static charge.

The conversion between soluble and insoluble varnish is a physical equilibrium process dependent upon temperature.

Oil-degraded soft contaminants are dissolved in the oil at operation temperature which are polar in nature and get absorbed onto dipolar (colder) metallic surfaces. The varnish is formed by soft contaminants agglomerating and hardening into a lacquer-like coating on valve spools and sleeves, bearing surfaces, gears and other internal surfaces of the lubricant system. 

The sticky nature of varnish captures hard contaminants as they flow within the system, forming an abrasive finish that accelerates component wear. Furthermore, varnish is an efficient insulator that provokes bearing surfaces to run hotter, and heat exchangers to have lower efficiency.

In Saudi Aramco, all critical rotating machines are monitored by a lubricant condition monitoring (LCM) system. The scheduled samples are tested inhouse. Test slates are decided based on oil type and equipment. However, color and acid number are checked for all industrial lube oils. When color and acid number are high, the RULER (Remaining Useful Life Evaluation Routine)/ RPVOT (Rotating Pressure Vessel Oxidation Test), and UC (Ultracentrifuge)/ MPC (Membrane Patch Colorimetric Test) are checked to understand the condition of the oil and design the corrective action to prevent unscheduled equipment downtime.

The MPC test has been used for many years in oil analysis as a qualitative test to assess the condition of oil. Recently, several commercial laboratories have developed quantifiable scales to trend the varnish potential of oil. For example, on Analyst Inc.’s scale from 0 to 100, a varnish potential rating of 0 to 15 is considered normal. The range 15 to 30 means monitoring is required. Readings greater than 30 are considered action-able and should trigger rapid remediate.

Figure 1: Varnish was found in the compressor gearbox, bearing, and shaft. 

Delaval make a 5-stage centrifugal low-pressure (LP) gas compressor driven by a 3,500 hp electric motor. It is a critical asset, operating throughout the year with no standby equipment. The compressor takes gas from the LP suction drum and discharges it to the high-pressure (HP) gas compressor. The compressor runs at 10,295 RPM and delivers 19.27 - 21.55 MMSCFD of gas, with the amount varying from summer to winter. The set alarm and trip temperature of the compressor bearings are 235oF and 250oF respectively.

The compressor train is lubricated through a forced feed system to provide lubrication to the motor, gearbox and compressor bearings. The lube oil reservoir capacity is more than 3,000 gallons of ISO VG 46 turbine oil. 

The bearing temperature trend of the LP compressor showed a gradual increase at the inboard (I/B) bearing. It reached above the limit of 250oF and resulted in a trip. The bearing was dismantled, and varnish was found on the bearing. This lowered the oil flow rate because of reduced clearance and a reduced heat dissipation rate (Figure 1 and 2).

Figure 2: The lube oil sample testing revealed a very high level of varnish presence; the test result for new (left) and in-service lube oil (right).

An offline Varnish Removal Unit (VRU) was connected to the LP gas compressor lube oil system while the machine was running. The VRU suction is taken from the lube oil reservoir drain valve. The VRU discharge is returned back to reservoir through a one-inch socket welded on the reservoir inspection manway.

The VRU utilizes filter media optimized for varnish removal. The warm oil is drawn from the system tank to the VRU by means of the transfer pump. The oil first passes through a blast cooler, then a heat exchanger and finally a chiller system before reaching the filter housing. The oil temperature comes down to approximately 50°F before reaching the filter media that captures dissolved and suspended soft contaminants.

Varnish has traditionally been defined as an insoluble deposit. However, it also exists in soluble state. The conversion between soluble and insoluble varnish is a physical equilibrium process dependent upon temperature. The soluble varnish becomes insoluble by reducing the lube oil temperature and can then be removed easily from the lube oil system.

After extracting the varnish from the lube oil, it is returned to the main lube oil system. Varnish-free oil now starts to clean system components in contact with oil, resulting in a varnish-free system for up to a few months depending on system condition.

After utilizing the VRU for a few weeks on the LP gas compressor, bearing temperatures and the condition of the lube/seal oil were improved. Oil samples subjected to MPC tests showed a drop from 39.1 to 1.4 within 19 days of operation. Bearing temperatures dropped from 249.4oF to 186oF within 19 days due to the removal of varnish and better heat dissipation as well as increased oil flow.

The varnish removal unit utilized by Saudi Aramco. Courtesy: CJC.

The usage of the VRU in combination with MPC testing of the lube oil system reduced the bearing temperature by detecting and cleaning varnish deposits. This improved heat dissipation and prevented any equipment trips due to high bearing temperatures. It also eliminated the immediate need for oil replacement, system flushing, and chemical cleaning.

Varnish removal technology in turbine oil. 

Resolving varnish challenges

BY BENJAMIN HELLMIG AND GUILLAUME DE FOMBELLE

Methane accounts for the largest share of greenhouse gases after carbon dioxide. It is many times more potent but has a shorter lifespan in the atmosphere. Methane emissions are usually not entirely avoidable. Compressors in gas pipeline compressor stations leak due to their design as the mechanical dry gas seals currently used do not seal completely. 

Pipeline operator GRTgaz from Western Europe decided to tackle the problem. Its infrastructure consists of several thousand kilometers of pipeline network with around 10,000 delivery, regulating, or sectioning stations as well as numerous compressor stations. Dry gas seals have been installed at new compressor stations for 25 years, and pipeline venting emissions (mainly for maintenance needs) are fed back into the pipeline with mobile gas compressors. Based on 2016 figures, the company has achieved a two-thirds reduction in methane emissions. The next target is to divide that number by five by 2024.

The CobaDGS from EagleBurgmann is a gas-lubricated mechanical seal that eliminates leakage even under high pressures. It has been implemented by European pipeline operator GRTgaz to reduce methane emissions from turbocompressors.

Conventional dry gas seals reduce emissions by up to 90% compared with oil-lubricated mechanical seals. Their tandem design meets safety requirements. If the main or primary seal fails, a secondary seal withstands full pressure. Other advantages include lower friction, longer service life, and efficiency.

If compressors do not remain in continuous operation, this can lead to seal contamination. There are several strategies to avoid this: A common practice is to depressurize the compressor housing, which results in methane escaping into the atmosphere. A better way is to keep the compressor housing pressurized during downtime. GRTgaz has implemented this strategy at several compressor stations using a rotating seal gas booster. 

Another way to minimize leakage is to use dry gas seals in a double arrangement. They are supplied with nitrogen, which then enters between the seal surfaces as a sealing gas. This means that no impurities are created, and only small amounts of nitrogen enter the compressor. However, the reliability of the supply is crucial. Without nitrogen, double seals are damaged. In addition, their safety level is only sufficient for lower pressures. 

Coaxial dry gas seals designs are similar to double seals. They can prevent leakage, are supplied with nitrogen, and are used at low pressures. The main advantages over double seals: their small footprint (comparable to a single seal) and resilience to nitrogen failure arising from a problem with the nitrogen generator. 

This coaxial design has been adapted for use at higher pressures. This gives components more stability as well as additional secondary seal faces behind the coaxial seal to provide a safety level like that of tandem seals. If the nitrogen supply fails, the system can continue to operate with process gas. In such a case, only small amounts escape into the vent line. 

The CobaDGS from EagleBurgmann has been implemented by European pipeline operator GRTgaz to reduce methane emissions from turbocompressors.

This seal eliminates leakage during operation and shutdown. As it is permanently pressurized with nitrogen (N2), venting is no longer necessary. This also prevents contamination. The system operates at up to 160 bar operating pressure, even in the event of an N2 failure. Modifications to the compressor housing are unnecessary. It is suitable for new compressors and retrofits. 

Although it can operate without nitrogen, an uninterrupted supply is important for environmental protection and to ensure clean gas. Instead of transporting it to the compressor station, the nitrogen had been successfully generated on site in the GRTgaz pilot project through pressure swing absorption. The nitrogen accumulator that secures the supply operates at 330 bar. Pressure is reduced downstream to the required seal supply level. It is estimated that this new seal design saves on average 230,000 cubic meters of process gas per year while reducing overall operating costs.

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Compressor seal addresses methane leakage. 

Methane emissions

Since its founding in 1965, Sullair offers a line of portable and industrial air compressors, including Class 0 certified oil-free compressed air solutions. From scroll to rotary screw to centrifugal, the Sullair oil-free portfolio is available in powers from 2 – 30,000 hp and pressures from 15 – 725 psi. Sullair became a Hitachi Group company in 2017. The combination of two compressor OEMs brings more solutions to achieve their compressed air needs.

70% of all industries use some form of compressed air. In any industry it is used, compressed air directly or indirectly encounters the product being manufactured. In the food and beverage industry, for example, this means the packaging or containers holding the food or beverage, or the food or beverage itself. In pharmaceuticals, this means pills or bottles holding the pills, and so on. When using oil-flooded air compressors—especially if they are not well-maintained—there is a risk of oil passing through the compression chamber, making it downstream, and contacting the product. This jeopardizes the health and safety of the consumer. Therefore, an increasing number of industries—including food and beverage, pharmaceutical, automotive, medical, electronics, and power —are moving to oil-free compressed air systems.

WHAT ADVANTAGES DO OIL-FREE CENTRIFUGAL COMPRESSORS PROVIDE?

Centrifugal compressors provide superior energy efficiency for large volumes of air as advanced technology impellers are designed to match the required airflow and pressure. This means additional energy savings. They also provide low maintenance costs, as they’re designed with many non-contacting internal components. This ensures minimal maintenance needs. Additionally, all moving parts are easily inspected by removing the horizontally split gear cover. Centrifugal compressors provide Class 0 oil-free air for applications where air purity is essential.

Oil-free air compressors are cost-effective when looking at total lifecycle costs. They require minimal maintenance. A properly configured oil-free system lowers energy consumption. Further, many multi-national manufacturers are moving to oil-free compressed air systems to protect themselves against potentially damaging effects—such as contaminating end product, damaging production equipment, causing downtime or damaging their brand’s reputation due to the low quality of the end product and/or product rejections.

WHAT ARE YOUR T-SERIES COMPRESSORS USED FOR?

With T-Series compressors, Sullair offers six off-the-shelf integrated packages, all providing Class 0 oil-free air. Key features include titanium impellers as standard to extend the life of the compressor. An accessible horizontally split gearbox allows for quick inspection. A thrust collar design extends bearing life and increases impeller rotation stability. Additionally, an Allen-Bradley programmable logic controller (PLC) is standard on all models. Sullair T-Series compressors are primarily used in automotive, steel, glass, food and beverage, air separation, large industrial manufacturing, aircraft manufacturing, plant air for chemical, and petroleum processing.

A Sullair T-series centrifugal compressor. 

Sullair f-series compressors are designed to meet specific needs. They are custom engineered to meet high pressure and flow applications. They produce Class 0 oil-free air. There are also custom seal designs available for specialty gases. Our f-series compressors are primarily used for steel, air separation, glass, automotive, process gas for chemical, and petroleum processing.

IHI-Sullair Compression Technology is a joint venture between Ishikawajima-Harima Heavy Industries (IHI) and Sullair to design, produce, and sell advanced centrifugal compressors. We have been part of this joint venture since 2004. The line, branded Sullair powered by IHI, is supported by Sullair distributors throughout North, Central, and South America. The Sullair-IHI centrifugal line is complementary to the rest of our oil-free compressor offerings, engineered and manufactured by Sullair and Hitachi. These include the DSP Series oil-free rotary screw air compressors and SRL Series oil-free scroll air compressors. The DSP Series is supplies oil-free air reliably and efficiently. Features include an air end design optimized for efficiency, an oil mist remover that improves air quality while reducing top off requirements, and a motorized isolation valve that provides additional protection against downstream humidity (A big enemy of oil-free screw compressors).

WHAT TRENDS HAVE YOU NOTICED OVER THE PAST YEAR?

While there are currently few government regulations in place regarding the mandated use of oil-free air compressors, there is a growing push to change this in some industries. This is leading to an increase in multi-national corporations switching to an ISO 8573-1 certified class 0 oil-free compressed air system. Another trend is that as customers continue to emphasize sustainability, energy conservation lies at the forefront. The cost of energy can quickly surpass the upfront cost of an air compressor. Energy conservation favors larger centrifugal compressors.

Brian Tylisz, Senior Vice President of Sales, Americas at Sullair, discusses centrifugal 
compressor and air compressor technology.

Q&A: The need for oil-free compression

FS-Elliott is a manufacturer of oil-free air and gas compressors. In addition, it provides a line of lubricants and control systems. The company has been in business for over 50 years and operates in more than 90 countries. “Despite widespread cuts in spending from customers due to COVID-19, we are experiencing increased demand in some industries,” said Alex Curtin, Product Manager, Engineered and Air Separation at FS-Elliott. “The fact that the major oil indexes have steadily rebounded and major investments to address the global chip shortage are indicators of a strong air compressor market.” But the pandemic caused a shift in strategy for 2020. The company refocused its efforts on internal process and product management modifications to offer engineered products with improved prices and lead times. In addition, it revamped extended warranty programs, and released a new control panel to market.

FS-Elliott has two compressor product lines, the Polaris+ and the PAP Plus. Polaris+ air compressors serve customers in industries such as food and beverage, textiles, industrial manufacturing, plastics, and power generation. The PAP Plus line is mostly utilized in oil refining, petrochemical, and LNG production and transport. It offers compliance to API 672 and API 614 standards. The company is also active in the air separation industry, where both of its compressor lines are used. 

The PAP Plus A1 is FS-Elliott’s workhorse compressor for oil and gas. Primarily used as an instrument air compressor, the A1 is available in cost and short lead-time pre-engineered configurations to meet API 672/614 with critical reliability features. The A1 can be customized to meet specific requirements to ensure year-round reliability and operation. 

Curtin commented that compressor life-cycle costs are generally organized into three groups: capital investment or purchase price; maintenance; and energy usage. When purchasing a new compressor, the primary focus is generally on the purchase price. Over the life of the compressor, that is typically the lowest cost. Energy costs are the highest, followed by maintenance. The other impact to consider is the effect the air source can have on the finished product. 

“Oil-flooded compressor air sources use expensive separation systems and can leave trace amounts of oil that can transfer to the finished product,” said Curtin. “For those producing textiles, food products, or medicines, any potential for oil contamination is unacceptable.” 

He recommends that audits are performed on existing compressed air systems by a company certified by the Department of Energy AirMaster+ Program or that completed Compressed Air Challenge training courses for compressed air systems. The return on investment of an air system audit can be immediate based on what is uncovered during the process and the final recommendations. One example is an automotive component manufacturer in North Carolina that saved $100,000 per year on electrical usage and $25,000 per year on annual maintenance costs by converting three oil-flooded rotary screw compressors to a more efficient oil-free centrifugal compressor.

FS-Elliott offers a range of control systems, including both microprocessor-based and PLC solutions. Its control panels support needs ranging from a basic user wanting to turn the compressor on and let it run without worry to more complex solutions encompassing redundancy and monitoring of every characteristic of compressor operations. 

The new FS-Elliott R2000 control panel features improved energy efficiency and a better user experience while reducing downtime. On the energy savings front, an Energy Advisor makes suggestions to improve efficiency based on operating trends. Its maintenance notification system tracks compressor usage and provides predictive maintenance advice.

The FSE-TurboCool line of fluids feature extended fluid life, wear protection, and resistance to foaming. FSE-TurboCool and FSE-TurboCool HD are ISO 32- and ISO 46-grade lubricants selected based on coolant temperatures and environment. FSE-TurboCool FG is a food-grade version of a 32-grade lubricant created to meet H1 requirements for fluids with incidental food contact (FDA 21 CFR 178.3570). FSE-CentriMax is a 32-grade premium mineral oil and FSE-TurboCool CC cleans heavily varnished air compressors while the unit remains in operation.

FSE-TurboCool uses an ester-based lubricant suitable for use in all centrifugal compressors and offers advantages over glycol-based lubricants. “In most glycol-based lubricants, a secondary oxidative inhibitor must be added to capture water and aid in water separation, which deactivates over time,” said Curtin. “FSE-TurboCool’s oxidative resistance offers long-lasting protection against deposits and varnish, enables moisture buildup from condensate to drain, and improves the efficiency of the compressor’s mechanical components.”

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Vendor spotlight: FS Elliott

Hydrogen – the world’s lightest and most abundant element – has been touted as a solution to radically decarbonize industries and societies. Several countries have included it in their medium and long-term emissions reduction plans, with the likes of Canada, France, Germany, and Japan rolling out strategies specific to hydrogen. 

Equipped to support 30% hydrogen co-firing, Mitsubishi Power’s J-Series gas turbines can produce up to 700 MW of electricity while reducing CO2 emissions. (Photo Credit: Mitsubishi Power)

To spur mass adoption of this zero-carbon molecule, a more robust supply chain is necessary. However, cost is a major barrier. Certain methods of hydrogen production, storage, and transport are specialized and expensive, especially when compared to more carbon-intensive alternatives. 

One way to make hydrogen more economically viable is to significantly scale demand. The installation of a single 400 MW, 100% hydrogen-fired gas turbine combined cycle power plant, for example, would use the same amount of hydrogen as 2 million hydrogen fuel cell vehicles. Such a shift would generate enough impetus to expand the build-out of hydrogen-related infrastructure.

Energy sector players need not start from scratch to ramp up hydrogen utilization. They can use existing gas power infrastructure. For decades, the energy sector has already successfully used hydrogen in various proportions within small gas turbines. The next step is to develop larger machines that can safely deploy hydrogen for utility-scale power generation. To date, there has been success in converting large gas turbines with dry low-NOx combustors to run with a 30% hydrogen and 70% natural gas mix. Exclusive hydrogen-firing is projected for 2025. 

Conversion of legacy systems to accommodate hydrogen firing can be done with minor structural modifications. Piping and valving sizes must be increased given the greater volume of hydrogen needed. But the compressor, turbines, and other auxiliaries can remain largely the same. 

To ensure the safe deployment of hydrogen in large-scale power generation, the combustor design has been reimagined. Most existing large gas turbines can run with up to 20% H. But as its proportion increases, hydrogen’s explosive nature and wide range of flammability must be addressed. One notable effect of the significant rise in temperature with hydrogen combustion is the increase in formation of NOx. 

A higher incidence of NOx emission can be mitigated by premixing fuel and air before entering the combustor. However, doing so poses a new challenge. Adding hydrogen raises the combustion speed of the fuel mix. It accelerates flame propagation to the point where it may exceed the fluid velocity of the premixed gases. This increases the risk of flashback – where the flame moves upstream in the fluid and can ignite fuel outside the combustion chamber.

A dry low-NOx combustor with an improved swirler nozzle has been developed to mitigate this challenge. Air is injected from the tip of the nozzle, increasing the velocity at the center of the swirling flow. This design boosted flashback resistance while enabling low-NOx combustion.

The energy sector can help drive demand for hydrogen, but it cannot act alone. Leaders in both public and private sectors can take steps to stimulate hydrogen demand and supply, while striking a balance between economic feasibility and environmental performance. 

The existing hydrogen supply chain is not decarbonized. With the bulk of commercially available hydrogen derived from fossil fuels, the IEA estimates that hydrogen production generates 830 million tons of carbon dioxide annually. This is equivalent to the combined CO2 emissions of the UK and Indonesia. 

There are several ways to produce hydrogen that can drastically reduce or eliminate carbon from the process. This includes pyrolysis of hydrocarbons (forming solid carbon as byproduct) as well as using steam reforming systems with carbon capture capabilities. Another option is to generate green hydrogen using renewable power. The rapid growth of renewables in several places has led to oversupply, forcing power producers to curtail renewable power generation or sell excess power at a loss. In theory, this surplus electricity from renewables can be harnessed to power electrolyzers to produce carbon-free hydrogen. 

However, to make green hydrogen competitive at scale, capital expenditure and operating expenses need to go down. The European Commission estimates that hydrogen derived from fossil fuels costs about $1.80 per kg, whereas green hydrogen ranges between $3.00 and $6.55 per kg. 

To bring hydrogen further down the value chain, suitable transport and storage systems are also needed. Traditionally, hydrogen is stored in tanks at high pressures (350 to 700 bar) and low temperatures (below -252.8°C). These extreme conditions mean that tanks must be specially designed, with large compressors enabling such processes.

Salt caverns, such as those used by the Advanced Clean Energy Storage project in Utah, present a viable alternative for hydrogen storage. When operational, the system will be integrated with existing power grid infrastructure in the Western U.S. and provide up to 1 GW of renewable energy that can be tapped year-round. 

Ammonia, which is easier to transport at scale than hydrogen, is also advancing the development of a hydrogen ecosystem. Not only can it be used directly as a fuel in smaller power systems, but it has proven to be an effective hydrogen carrier. In Australia, the Eyre Peninsula Gateway project is set to generate up to 40,000 tons of green ammonia per year and will feature a 75 MW electrolyzer for green hydrogen production.

Mitsubishi Power teamed up with the Los Angeles Department of Water and Power and other partners to work towards at-scale green hydrogen procurement at $1.50 per kg in the Los Angeles Basin by 2030. (Photo Credit: Green Hydrogen Coalition)

Various parts of the world are at different stages of hydrogen adoption. In Europe, first-generation hydrogen projects are set to come online within the decade. These include the conversion of a 440 MW gas-fired power plant in the Netherlands to 100% hydrogen firing, as well as the development of a green hydrogen cluster in Hamburg. The U.S. has been leading the way in exploring hydrogen for energy storage, with ongoing projects and evaluations in Utah, New York, Virginia, Louisiana, and Texas. In Saudi Arabia, work is underway for a facility that will produce, among others, 650 tons of green hydrogen per day. 

In developing markets, limitations to infrastructure and access to capital are more acute. These countries can scale hydrogen adoption with blue or gray hydrogen and pair hydrogen production systems with carbon capture technologies. 

At the end of the day, the development of a global ecosystem for affordable hydrogen production, storage, transportation, and utilization will need partnerships across sectors and industries. One example is HyDeal Los Angeles where the local government is working with industry players to drive down the cost of green hydrogen to $1.50 per kg.

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How the energy sector can lead the hydrogen revolution. 

The economics of hydrogen

Now that coal plant emissions have been largely curtailed across much of Europe and North America, attention is swinging onto gas turbines. Such plants, by and large, do a good job at reducing emissions such as NOx and SOx.

"Power producers have already made great strides in lowering the carbon intensity of the power sector in the U.S., largely due to retiring coal and replacing it with a combination of natural gas and renewables,” said Evan Canady, Mitsubishi Power.

The solvent-based CO2 capture process. Source: IDTechEx.

The direct air capture process. Source: IDTechEx.

However, the current demand is that gas-fired plants greatly reduced their carbon emissions. This can be accomplished either by pre-combustion carbon separation (usually using methane steam reforming to syngas with subsequent water shift and CO2 removal) or post-combustion flue gas CO2 removal. 

The big hurdle, of course, is cost. Current technology is expensive and energy intensive. Not only is the carbon to be captured, it also needs to be stored somewhere and increasingly utilized in some process. Hence the term carbon capture utilization and storage (CCUS). (Note: It is also sometimes called CCS. 

Most attention, to date, has been lavished upon solvent-based capture i.e., the gas stream is exposed to a liquid medium to absorb CO2 via some kind of physical or chemical mechanism. Regeneration is also needed to break absor-bent-CO2 bonds.

Drawbacks include high energy consumption, corrosion, difficulties in scaling, and raw economics. Why spend money to develop and implement the technology in an environment that shows little love for fossil-based fuels. Nevertheless, advances have been made. Amine-based solvents from Mitsubishi have been used in the Petra Nova facility in Texas. Shell Global’s CanSolv is another solvent being used at the Boundary Dam project in Canada. Similarly, physical absorption solvent breakthroughs have been made such as Lurgi’s Rectisol process using chilled methanol as a solvent. Further areas of development include: solid sorbents are being developed by Svante in conjunction with Chevron and others; the Polaris membrane by Membrane Technology and Research in collaboration with the U.S. Department of Energy; SES Innovation’s cryogenic carbon capture; and FuellCell Energy’s fuel cell technology for carbon capture, using electrochemical membranes to separate CO2 from industrial waste gas streams. Further, Chart Industries (owner of LA Turbine) has developed Cryogenic Carbon Capture (CCC) technology. The cost to produce cement and capture CO2 using CCC technology is said to be 24% higher than producing cement with no capture.

Another approach is direct air capture (DAC) to strip CO2 from air using chemical and physical processes. Those working on this include Climeworks with a plant in Switzerland and Carbon Engineering from British Columbia, Canada, that plans to build a Permian Basin facility that to capture a million tonnes of CO2 per year by 2024 using a high-temperature aqueous method based on potassium hydroxide. Global Thermostat, too, has pioneered a porous, honeycomb ceramic approach to carbon capture. 

According to IDTechEx, capturing a tonne of CO2 directly from the atmosphere costs between $600 and $1,300 using current technology, compared with approximately $40 to $80 for capturing a tonne of CO2 from the flue gas stream of a coal-fired power plant. Despite that, the analyst firm forecasts that DAC is likely to gain a growing share of global CO2 capture capacity over the next few decades.

Lowering carbon emissions from gas turbines. 

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