Though the biggest currently-functioning offshore wind turbines top out below 10 MW, researchers lead by the University of Virginia are hoping to develop a 50-MW wind turbine with blades 200 meters in length.

The Segmented Ultralight Morphing Rotor Project was awarded a three-year grant of more than $3.5 million by the U.S. Department of Energy’s Advanced Research Projects Agency-Energy, CNBC reported.

Researchers hope such a large-scale project would reduce energy costs by 50 percent. While traditionally-designed wind blades become expensive and so heavy they strike their towers at extreme scales, the project uses a blade design that morphs and sways with the wind like a palm tree, which reduces structural requirements. Segmenting the blade design will also ease manufacturing and transportation constraints.

Though the finished product will use a tower roughly the size of the Eiffel Tower, the project will test the blades in Colorado on a 12-story tower.

Sandia National Labs will develop the project’s structural configuration, while the University of Colorado and the Colorado School of Mines are creating a control system that pitches and morphs the turbine’s blades.

Waste-to-energy plants perform a key role in reducing the amount of waste that goes to landfill and are critical in the generation of power for the local grid. However, when a generator fails it is essential that repairs are completed quickly to get the plant back online. Sulzer was contracted to rewind a damaged generator and managed to return it to operation within just 30 days, minimizing the costs associated with lost production.

For a mid-sized plant, processing over 200,000 tonnes of waste per year, keeping downtime to a minimum is essential to maintain efficiency. Operating a comprehensive, preventative maintenance program is crucial to operating a cost-effective plant. However, unforeseen maintenance issues will occur; in these situations, it is the speed of response and the quality of the repair that will determine the success of the repair project.

A waste-to-energy plant owner in the UK experienced an unexpected failure of the site’s sole generator, which meant that the heat generated by the incinerator could no longer produce energy. Keen to resolve the issue quickly, the maintenance manager called in Sulzer engineers, who arrived within two hours, to carry out an initial inspection to determine the cause of the failure.

The results showed that the stator had suffered from a coil shorting to earth on the turbine side of the winding, as well as suspected damage to the stator core. The plant operator had to move fast. The order was given to remove the generator from the site for further investigation of the core and rotor which were not accessible without a full dismantle.

Comprehensive investigations

The generator is central to the entire business, both financially and physically. The first task was to disconnect all of the ancillary equipment and remove a section of the building’s roof to allow a 400-tonne crane to lift the generator from its operating plinth onto a set of skates. This enabled its removal from the building and loading onto transport for immediate delivery to the local Sulzer Service Center in Birmingham.

With time such a critical factor in this project, the generator was dismantled overnight to allow the rotor, stator and coils to be tested. Apart from the need to rewind the stator, the tests also showed that the rotor required further investigation as the insulation resistance tests did not meet the acceptance criteria of 100 MΩ.

The refurbishment of the stator included replacement of the coil retaining blocks

Designing and manufacturing new stator coils is a complex task, one that the engineers at Sulzer have perfected over many years. Using the latest class F insulation materials allows for thinner layers that can withstand greater dielectric stress, higher temperatures and also creating more space for copper within the same slot area. This reduces the resistance of the stator winding, which runs cooler, allowing a small increase in output.

Meeting the tightest deadline

By using the latest CAD software, the new coils were precisely formed to ensure an exact fit in the stator slot, making the installation process more efficient. The new coils were manufactured in Sulzer’s coil winding shop in Birmingham, UK, which uses its in-house copper rolling mill to enable round-the-clock coil production to meet even the tightest deadline.

Once the stator had been stripped of the old coils, the stator core inspection revealed a damaged tooth that would need to be repaired before the new coils could be installed. The damaged slot section was machined out to allow the installation of an epoxy glass block G11, which was machined to restore the stator slot profile to the correct dimensions.

Keith Barbier, Head of International Contracts and Projects at Sulzer UK, comments: “The re-build process is a very skilled and time-consuming task because precision is essential to achieving a high-quality finish. The engineers worked round the clock to manufacture the new coils and install them into the stator.”

The engineers worked round the clock to complete the rebuild of the generator

Prior to the rebuild, the coils were stress tested to earth in accordance with EN60034-1, tan delta tested and interturn tested using EA Technical Specification 44-5 as the pass mark. At the same time, the rotor was refurbished and then reassembled with the completed stator before the final tests were completed.

After just 30 days the generator was back on site, being craned into position and reinstalled with all the ancillary equipment, before being put back into service.

Projects such as this have highlighted Sulzer as a leading provider of engineering solutions to the power generation sector, from on-going condition monitoring to complete turnkey projects. With a global network of repair centers capable of completing generator and turbine repairs, Sulzer ensures it employs experienced engineers, equipped to complete projects on site if necessary.

The Integral Molten Salt Reactor (IMSR) represents a clean energy alternative to fossil fuel combustion for industrial heat and provision, which is compact, efficient, and cost-competitive with fossil fuels. The IMSR is a Gen 4 reactor and a successor of the very effective Molten Salt Reactor Experiment work of Oak Ridge National Lab.

Terrestrial Energy USA is now working with Idaho National Laboratory to couple the IMSR to advanced industrial systems. Several systems have been designed and proposed. These can serve energy-intensive industries with stable heat and power for clean H2, O2 production, and by extension ammonia and methanol production.

Desalination is also a very significant market sector for IMSR heat and power.

IMSR has the potential to be a transformative technology. When coupled with advanced industrial systems, IMSR enables new, transformative clean industries.

An IMSR power plant can rapidly load follow grid power demand. Photo courtesy: Terrestrial Energy USA

How the Integral Molten Salt Reactor Works

• The term ‘Integral’ refers to the company’s proprietary design in which all the primary components (pumps, moderator and primary HX) of the reactor core are sealed in a compact and replaceable component, the IMSR Core-unit.
• A new Core-unit is exchanged every 7 years with the old Core-unit stored on site.
• The IMSR is a “pool-type” reactor with no penetrations into the reactor vessel.
• IMSR fuel, the Fuel Salt, is a liquid, high-temperature fluoride salt that operates at ~700C.
• These salts have high thermal stability and are excellent heat transfer liquids.
• IMSR Fuel salt can be produced today with current methods and within current regulations.
• The Fuel Salt, which contains the nuclear fuel, never leaves the reactor core vessel during operation.
• Fuel Salt is circulated in a closed loop up through the graphite core, where the fuel fissions in a thermal neutron spectrum creating heat within the fuel, which then circulates back down through heat exchangers giving up heat to a secondary salt in a primary heat exchanger and isolated loop. The Fuel Salt circulates back into the core.
• The reactor core contains a graphite moderator – outside of the moderated area, the salt is no longer active.
• A secondary heat exchanger exchanges heat via secondary salt to a third loop containing a 600C industrial salt that can be transported up to 5 kilometers.
• The IMSR has a low level of tritium production. Furthermore, the IMSR’s three successive isolation loops further ensures no tritium moves beyond the nuclear island.
• Uranium enriched to less than 5% is currently intended to fuel the IMSR; however, with future iterations of IMSR technology, the IMSR is very capable of using a diverse array of fuel forms, including thorium-based fuels and spent nuclear fuels from existing nuclear fleets.
• An IMSR power plant can rapidly load follow grid power demand.
• An IMSR power plant is anticipated to deliver power at less than $50 per MWh, which is highly competitive with fossil fuel combustion.

This type of high temperature reactor allows for much more than just electricity production. An IMSR power plant can deliver 600C heat by liquid salt up to 5 kilometers to an industrial energy park. This allows the IMSR baseload heat production of nuclear to be switched from electric power provision to the production of the most valuable high energy products in off-peak hours. This maximizes use of IMSR heat energy and allows the IMSR to run in the most capital efficient manner.

All of the primary components (pumps, moderator and primary HX) of the reactor core are sealed in a compact and replaceable component – the IMSR Core-unit. Photo courtesy: Terrestrial Energy USA

The following are examples of process heat applications for IMSR:

Thermal Storage/Desalination

Demands for safe, secure supplies of potable water globally are increasing faster than can be provided by natural, ever-depleting sources of fresh water. Simultaneously, global demand for electricity is also projected to grow significantly.

Desalination of seawater and brackish water is extremely energy intensive. The IMSR is uniquely suited to provide clean, heat energy and electric power on an industrial scale needed at cost-competitive prices to enable far greater deployment of desalination technologies today.

In addition to utilizing heat energy for desalination, hot industrial salts can be directed to a hot salt mass energy storage, a method that is already in use today. These hot salt thermal energy reservoirs supported by IMSR heat can be used as a grid sink for excess Wind and Solar electric power production. This system negates any need for grid-based electric power storage and is highly complementary to wind and solar power production. The cheap and effective salt-based thermal storage would act as an energy battery that will allow the demand curve to be supplied at the appropriate service levels without damaging surges taxing the grid system.

Studies conducted by Terrestrial Energy USA and Idaho National Laboratory (INL) have shown that the IMSR power plants would be an effective system, relative to all other systems under review, to provide a growing water supply and stable power to the grid. The expanding growth demands on power and water can be served by an IMSR — a low-cost, carbon-free source of inherently safe energy.

H2 from High Temperature Steam Electrolysis

Making H2 from natural gas is the dominant method today, but is highly sensitive to NG input prices. The (IMSR) is uniquely suited to provide a reliable and secure alternative method for H2 production that has negligible input price volatility. The IMSR’s can deliver the temperatures (600C+) and electric power that are needed for alternative methods for H2 and O2 production.

Terrestrial Energy USA and Idaho Nation Laboratory (INL) have shown that the IMSR would be the most effective system of those reviewed to date to enable the best method of clean cost-competitive H2 supply.

Analysis by INL and Terrestrial USA have shown that the IMSR is highly suited to be coupled to an industrial facility using High Temperature Steam Electrolysis for H₂ production. Findings of the studies show that there are many other H₂, O₂, NH₃ and heat power production combinations that can be tailored to a great number of industrial applications.

Synthesized Transport Fuels

Production of transport fuels, including gasoline, using the IMSR, processes heat and electricity at a cost-competitive positon with fossil fuels and represents a dramatic shift in economics of liquid fuel synthesis technology. This shift could have a profound effect on the industrial production methodologies of a broad range of valuable chemicals and fuels used in our industrial society. Demonstrating the production of synthetic gasoline at an industrial scale will certainly be followed closely by the production of other fuels such as aviation fuels, LPG, Diesel and others.

Gasoline is also a symbolic fuel the public is familiar with and would give a clear signal of the immense opportunities that synthetically-derived fuels from nuclear power-driven process heat would represent. Namely: stabilized cost of energy inputs, sequestration of atmospheric carbon, and economic alternatives to fossil fuels. All of these opportunities are symbolic of the potential of IMSR to be a transformative technology and enables many new innovations and competitive clean industrial technologies that combine to drive economic growth and deep decarbonization of primary energy systems.

Ammonia Production Coupled to IMSR:

During 2016, thirty plants produced 9.4 million metric tonnes of ammonia (NH3), principally based on the Haber-Bosch reaction processes. The principal feedstock to these plants is natural gas, which is reformed with steam to produce a target stoichiometric gas mixture of CO₂, N₂, and H₂. Sorbents are used to remove CO₂ and other contaminants prior to synthesizing NH₃. Ammonia is used to produce a wide variety of fertilizers, nitric acid, fuels, and amine-based chemicals used broadly in industrial agriculture.

The above opportunities are examples of how IMSR can benefit the large and growing ammonia industry. Hydrogen that can be produced by high temperature steam electrolysis (HTSE) can replace the fossil-fuel intensive steam methane reforming technique. This would eliminate CO₂ emissions associated with hydrogen production today. The economics of HTSE when compared with fossil fuel-based hydrogen production, are based on the value of Green House Gas (GHG) emissions avoidance, as well as the market value of oxygen production for industrial uses, which represents a valuable byproduct of the HTSE process. Another possible opportunity for IMSR is for a modified interface with either a conventional or a revised steam methane reforming plant – a similar system to one used for methanol production. The significant benefits of a novel and disruptive NH₃ economy can be brought rapidly to fruition with the hybrid coupling of IMSR process heat with large scale ammonia production.

Coupling IMSR Technology into Direct Reduction Steel with H₂

It has been estimated, in the studies conducted at INL, that hydrogen-based high performance steel making could be cost-competitive with traditional steel production when coupled to an IMSR hybrid energy H₂ production system. This could also reduce total CO₂ emissions from steel production by 80 percent (Fischedick et al. 2014b).

Author

John Kutsch is vice president of Business Development for Terrestrial Energy USA.

The power industry as well as oil & gas, chemical, petrochemicals, mining and other industries generate large volumes of waste water that must be managed. Commonly these wastewaters are discharged via a plant outfall to a surface water body, an evaporation pond, or in some cases deep well injected. However, there are growing environmental concerns regarding such discharge practices, which has resulted in the development of Zero Liquid Discharge (ZLD) processes.

ZLD can be defined broadly as a process for maximum recovery of water from a waste water source that would otherwise be discharged. This water is beneficially reused and the salts, and other solids contained in the waste water are produced and generally disposed in a landfill.

The drivers for ZLD include a growing concern by the public about the impact of such discharges on the environment, and in many areas of the world, water is a scarce resource. Such concern is resulting in increased regulation and limitation of waste water discharges. Even without regulatory push, many companies in various industries are mandating initiatives for reducing water discharge by recycle reuse, as well as ZLD, to reduce their environmental footprint and improve sustainability.

Zero liquid discharge can be achieved in various ways. There is no “one size fits all” solution, as the optimal system design is site specific. The waste water composition, various streams to be treated, site specific operating costs, foot print availability and other factors are determining factors for an optimal design. This article provides a brief primer on various typical ZLD configurations and focus on factors that are critical to the successful design and operation of a ZLD system.

The system objectives for a ZLD system are to eliminate a liquid waste water discharge, generate solids for landfill disposal or reuse, and to recycle a high-quality water that can be beneficially reused. The design objectives are to minimize the capital investment and system operating cost, while not significantly impacting the manpower required for operation. Further, the system must be designed with operational flexibility to meet the facility needs and be safe and reliable.

Waste Water Chemistry

Careful consideration of waste water chemistry is needed for the successful design and operation of a ZLD system. Sometimes prior experience with similar water chemistry is available to the ZLD designer. Where experience is lacking, proprietary water chemistry modeling software can be applied to understand the solubility limits of various species as the water is concentrated to a high TDS brine. Such software is also useful for estimating the chemical consumption of various chemicals that may be used in the ZLD process for conditioning and pH control. If water is available, bench top studies can also be useful to validate chemistry modeling; where water may not be available, synthetic analogues can sometimes be used. A sound water chemistry design basis is key to successful ZLD design.

In a ZLD system, the waste water being processed is concentrated to solubility limits of the dissolved salts. When the solubility limits are exceeded, salts crystallize and can then be harvested using an appropriate means. Brine chemistries in which monovalent cations such as sodium are balanced with sulfate and chloride, generally are limited to a maximum TDS of less than 30% and a chloride concentration (important factor in metallurgy selection) of less than 170,000 ppm.

Divalent cations such as calcium and magnesium are of primary concern for design of a ZLD system. High calcium and magnesium concentrations can lead to concentration of highly soluble species such as calcium chloride and magnesium chloride. High concentrations of these divalent cations can significantly contribute to the increase in boiling point elevation. As waste water brines concentrate the boiling temperature increases above that of pure water due to a physical property of the solution known as boiling point elevation (BPE). The design of an evaporator requires accurate knowledge of the boiling point elevation. Further, high concentrations of these divalent cations can result in high concentrations of chloride ions and lead to more costly metallurgy.

Calcium is generally sparingly soluble due to the presence of alkalinity and sulfate cations and must be properly considered to avoid scaling of a pre-concentrating membrane system, as well as brine concentration evaporators (Brine Concentrator). Membrane preconcentrators generally rely upon softening and antiscalants to control scaling. Brine concentrators are designed with seeded slurry scale control. By using seeded slurry scale control brine concentrators scaling is retarded by maintaining a proper concentration such that a high ratio of crystal surface area is maintained.

Generally forced circulation crystallizers receive the blowdown from upstream preconcentrating membrane systems or brine concentrators. Crystallizers are designed to manage precipitation of highly soluble species such as sodium chloride and sodium sulfate, as well as sparingly soluble salts such as calcium sulfate. High concentrations of sodium relative to divalent cations are beneficial in controlling the chloride concentration.

Silica is present in varying concentrations in natural water sources. The solubility is very limited at near neutral pH; however, solubility is greatly enhanced if the pH is increased. If allowed to precipitate without control, silica can scale preconcentrating membrane systems and the heat transfer surface of evaporators. Such scales are difficult to remove by chemical cleaning and therefore need to be avoided and considered in the design of the system.

Ammonia when present will volatilize in an evaporator system and partition between the distillate and atmospheric vent. As the ammonia volatilizes the pH of the system may decrease and caustic may be needed to control the system pH. If ammonia is present additional controls on the vent may be required depending on the concentration of the vent to avoid a health hazard, an air permit violation or a nuisance odor.

ZLD System Design

Evaporation systems generally are more capital and operating cost intensive than membrane systems, with crystallizers the most costly. For that reason, and when possible, membrane systems can be utilized to reduce the capital and operating cost of the evaporation system.

Conventional membrane systems can concentrate up to 2 to 3 percent TDS, specially designed high recovery systems can concentrate to as high as 6 percent to 8 percent in some applications. Depending on the waste water composition, preconcentrating using a membrane system can dramatically reduce the sizing requirement of the backend evaporations system and thus the system capital and operating cost. As an example, if a waste water with a feed TDS concentration of 5000 is concentrated using a high recovery membrane system, the duty requirement of the evaporation system may be reduced by 90 to 95 percent. Note that to reach high recoveries in a waste water membrane system, appropriate pretreatment such as softening and pH adjustment is often required.

Vertical tube falling film brine concentrators are generally used to concentrate lower total dissolved solids (TDS) brine solutions up to 12 percent to as high as 25 percent total solids and are used to minimize the design capacity of a downstream forced circulation crystallizer. Brine concentrators are specifically designed to manage the scaling of sparingly soluble divalent salts such as calcium sulfate and calcium carbonate, as well as silica that is also commonly present. Forced circulation crystallizers are generally used to concentrate brine blowdown from upstream concentration equipment, although small waste water flows are sometimes treated directly with a forced circulation crystallizer. Such applications generally involve waste water flows less than 20 to 30 gpm. Crystallizers are designed to manage crystallization of all salts, sparingly soluble as well as highly soluble sodium salts such as sodium chloride and sodium sulfate, without excessive scaling and cleaning frequencies. This robustness comes at the expense of higher specific energy consumption and higher specific capital cost.

The solids generated by a forced circulation crystallizer are generally harvested and dewatered by either an indexing belt filter or by centrifuge. In such case the solids are collected and typically landfilled in a conventional landfill as long as the waste passes Toxicity Characteristic Leaching Procedure (TCLP) testing. However, in some applications involving, ZLD equipment the highly concentrated brine is discharged to an evaporation pond. Such a configuration reduces the footprint of the evaporation pond, and the labor and expense of operating the dewatering equipment.

ZLD Success Factors

Relevant Experience of the ZLD Supplier. ZLD systems must be custom designed based on the waste water chemistry and flow of waste water to be treated. ZLD system design is the intellectual property of the system supplier and is generally not available from text books, journals or Wikipedia. A successful implementation of a ZLD system requires that the supplier can demonstrate relevant successful experience. Just as important in the supply of the equipment is the support that the supplier provides after the system is started up. The ZLD supplier should have a strong organization to provide such support and be able to demonstrate the same.

Waste Water Chemistry Design Basis. There are no “one size fits all solutions”. It is critical to establish a waste water chemistry design basis that is representative of the average conditions, as well as the minimum and more importantly the maximum conditions. Care should be taken to not be overly heavy handed in applying margin to design chemistries as such practice may not achieve the desired result. It is better to estimate the expected chemistry and discuss implications of deviations with the ZLD system supplier.

Metallurgy. Metallurgy plays a significant role in the capital cost of a ZLD system. Alloys that provide corrosion resistance to the highly concentrated brines are required. There are options available that allow for cost optimization without sacrificing plant service life.

Conservative Design Margin. The ZLD system is the “end of the pipe” in most plants; anything that has washed into a waste sump concentrates in the ZLD system. Experience shows that actual waste water chemistry will deviate from the design chemistry.

Once properly designed operating issues can be handled by the plant operating team working with a ZLD system supplier that has demonstrated experience in operating similar facilities.

Author:

Daniel Bjorklund is vice president of Aquatech International, a global leader in water purification technology for industrial and infrastructure markets.

With the latest advancement of F, G, H, and JClass combustion turbines, combined-cycle designs are affected when compared to the previous generation of FClass and smaller machines. This article provides an overview of some of the significant influences associated with advanced combustion turbine design for current combined-cycle installations.

With the obvious consideration being larger combustion turbines and the additional power generated, there are other power block and balance-of-plant (BOP) design impacts. These impacts include integration of the latest combustion turbine steam cooling or turbine air cooling, sizing of heat recovery steam generators (HRSGs) and steam turbines, complex designs related to the larger equipment, and material selection for higher-steam temperatures.

The current combined-cycle design incorporates a number of features to accommodate the requirements of today’s market. There are numerous demands on the designs, including fast startup, both base load and cycling operation, high ramp rates, high efficiency, high reliability, lower emissions, and lower life-cycle costs, to name just some of the expectations. With all of these market demands, the combined-cycle plants are also trending larger in an effort to obtain economies of scale with the installed cost of the facility. All of these factors influence the design of the power block equipment, along with the integrated BOP equipment.

Figure 1 shows a representative model cut developed by Sargent & Lundy for an advanced combustion turbine facility project.

Integration of Combustion Turbine(s) with the Steam Bottoming Cycle BOP

There is opportunity with advanced combustion turbines to increase combined-cycle efficiency by integrating heating and cooling systems between both thermodynamic cycles. These systems include: 1) fuel gas performance heating system, 2) steam cooling of combustor transitions; and, 3) energy recovery with the turbine cooling air (TCA) system. The advanced combustion turbines have an even greater design demand on the integrated systems providing these services. Figure 2 on page 19 illustrates how these schemes between combustion turbine and steam cycle are integrated.

Fuel Gas Performance Heating System

The fuel gas performance heater is not to be mistaken for a natural-gas dew point bathheater, which increases the incoming fuel gas temperature by several degrees above the hydrocarbon dew point so the fuel remains in the gaseous state and no liquid drops impinge on hot combustor and/or turbine blade components causing pitting. The fuel gas performance heater provides significant sensible heat to the fuel prior to combustion and increases the efficiency of the combustion turbine. One method of accomplishing this is by extracting feedwater from the HRSG and directing this feedwater to a tube-and-shell heat exchanger. With high-temperature feedwater on the tube side and natural gas on the shell side, the temperature of the natural gas is raised significantly to improve combustion turbine efficiency. The cooled feedwater is then recirculated back to the condensate line entering the HRSG preheater.

The following criteria are guidelines for design of a standard gas fuel heating system:

• Ensure water pressure is higher than gas pressure during gas turbine operation and shutdown.
• The heated fuel must meet the requirements of the combustion turbine manufacturer’s fuel specifications, including particulate coalescing filters and final-stage knockout vessels.
• Provide early indication of heat exchanger tube failure and prevent water from entering the gas turbine combustion system should a heat-exchanger tube leak.
• Prevent gas fuel from entering the feedwater system following a heat exchanger tube failure.
• Provide overpressure protection to the combustion turbine gas fuel heating system piping and components.

Depending on the combustion turbine model and steam cycle configuration, the fuel gas final temperature requirements have increased over the combustion turbine requirements of the past, and can be greater than 600°F. The source of heat for the natural gas heater is typically feedwater. While in the past, the feedwater could be sourced from intermediate pressure, the current advanced combustion turbines with ever-increasing pressure ratios require a high-pressure, high-temperature feedwater source. To satisfy these requirements, the source is usually from the outlet of the high-pressure economizer section of the HRSG.

Steam Cooling of Combustor Transitions

When introducing a new, advanced-class combustion turbine (GClass with turbine inlet temperature of 1,500°C, or JClass with turbine inlet temperature of 1,600°C), manufacturers will take a conservative approach, with extensive testing and validation programs. Third-party insurers also perform independent engineering reviews for the insurance market. This approach usually means some advanced combustion turbines are first introduced and tested with a steam-cooled combustor. The improved heat transfer effectiveness of steam cooling allows for better management of the initial unknowns associated with a new or advanced combustor technology.

The typical method of the integrated steam cooling is utilizing cold reheat directed to the combustor sections with the steam returned to the steam cycle as hot reheat steam.

As actual operating experience of the combustion turbine generator is obtained with testing and validation programs and/or commercial installations, cooling of the combustor has historically transitioned from steam-cooled to air-cooled. This is due to the design and operating complexity of integrating combustion turbine generator cooling requirements and matching temperatures with the steam cycle. Air cooling also improves operating flexibility with regard to quick start and load cycling.

It is worth noting that aside from the method of combustor cooling, the steam-cooled combustion turbine and the air-cooled versions are the same engines. There is no equipment difference between the two models.

Energy Recovery with the TCA System

The turbine cooling air system is designed to reduce temperature of the combustion turbine’s compressor discharge air (utilizing feedwater), which is then used for cooling of internal turbine components, including the combustor, rotor, and blades. Heat transfer between the feedwater and turbine compressor air occurs across the TCA cooler heat exchanger. Design of this TCA feedwater system is in collaboration with design criteria provided by the turbine manufacturer. The turbine cooling air cooler feedwater interface typically utilizes supply water from the HRSG low-pressure drum as a branch from feedwater pump supply line or directly from the boiler feed pump discharge at the appropriate design pressure.

This extension of the feedwater system features the following interfaces:

• TCA supply water from the boiler feed pump discharge or a dedicated TCA pump
• TCA cooler heat exchanger (water side)
• TCA pump minimum flow bypass (upstream of TCA cooler, to condenser)
• TCA cooler bypass (downstream of TCA cooler, to condenser)
• Supply return piping system to the HRSG at the appropriate location

Turbine cooling air systems are also referred to as once-through coolers (OTCs) or kettle boilers, depending on the turbine manufacturer’s nomenclature and function. Some TCA systems return the feedwater to the HRSG as high-temperature feedwater. Other designs return saturated steam to the HRSG, thus the name kettle boiler.

Due to the importance of maintaining the combustion turbine’s cooling air flow at design temperature, redundant components are required (i.e., 2×100% TCA pumps). Manufacturer recommendations should be strictly adhered to with regard to TCA pump startup sequences and operating procedures, especially during upset conditions.

Challenges of Designing Steam Cycles for Advanced Combustion Turbines

With the ever-increasing demands of the market and with the advanced combustion turbines being larger, design of the HRSGs and steam turbines must consider the higher combustion turbine exhaust gas flow volumes and temperatures, resulting in greater steam generating capabilities at higher temperatures and pressures. This presents the engineering team with many challenges when specifying equipment for design of the optimal combined-cycle configuration.

Heat Recovery Steam Generator

There are many factors that influence the design of today’s HRSGs. These factors include the ever-increasing exhaust gas flows and exhaust gas temperatures from the combustion turbines, along with previously mentioned market requirements (i.e., fast start, frequent cycling, increased ramp rates, higher efficiency, lower emissions, etc.). As such, the design demands on HRSGs are ever increasing, with some of the more significant modifications noted below.

Transition Inlet Duct Design

The conventional inlet duct design for smaller combustion turbine exhaust gas flow rates included a gradual sloping inlet duct with no greater than a 45degree slope. The inlet transition ducts of the past also included flow training components, such as turning vanes and distribution grids or flow-straightening devices. These earlier designs have proven to not work as well with the current advanced combustion turbines. The gradual inlet transition ducts tend to recirculate the exhaust gas flow within the duct area, causing additional turbulence and pressure drop, and thereby negatively affecting the combustion turbine and HRSG performance. Based on flow modeling and testing, the current transition duct design is much steeper and compact with minimal ductwork. This configuration has led to less turbulence, improved pressure recovery, and better flow distribution into the HRSG (as illustrated in Figure 3). This has helped improve not only the performance of the HRSG, but also the cost.

Thermal Design Considerations

With the fast start and high exhaust gas flows and temperatures, the HRSG’s thermal design associated with today’s advanced combustion turbines is impacted. Each HRSG manufacturer has determined its own strategies to accommodate the current demands. With the fatigue life of the high-pressure components (i.e., drums and superheaters), some manufacturers employ smaller-diameter longer high-pressure drums to reduce the metal wall thickness and minimize the thermal fatigue, while others have opted for once-through high-pressure designs to achieve the same or similar affect. However, the smaller-diameter drums reduce the retention time and the once-through designs require better water quality, and typically require the use of condensate polishers to achieve the water quality needed. Other thermal design strategies employed include single-row harp sections in the high-pressure sections and enhanced materials in the high-pressure sections to reduce tube wall thickness. Smaller-diameter tubes and headers are also used to minimize tube and wall thicknesses.

While these methods can have positive impacts on achieving the demands of additional steam flows, temperatures, and pressures while supporting fast startup, care needs to be taken not to sacrifice operability and maintainability of the equipment. As HRSG manufacturers are pressured to find cost-effective solutions for the current design requirements, minimizing the drum size and reducing the diameter of tubes and headers have helped achieve this goal. However, with smaller retention times in drums, the operability of the HRSG becomes more challenging. The smaller retention times leave less reaction time for upset conditions prior to potential high- or low-level trips, impacting overall facility reliability. Additionally, HRSG manufacturers desire to increase the tube depth within modules to even greater values to reduce cost. The increased tube depth impacts the ability to repair tubes located in the middle of the bundles.

HRSG manufacturers are also increasing the fin density and fin height, and lowering the fin thickness to reduce cost. These types of modifications significantly increase the risk of damage to the fins during maintenance. Additionally, these fin designs make it difficult to clean tubes/fins and restore HRSG performance.

Draft Loss Considerations

Due to the large exhaust flows from the advanced combustion turbines, HRSG manufacturers have incorporated designs utilizing three-wide module concepts. This is similar to the current designs for larger combustion turbines and is employed to reduce the overall HRSG pressure drop, improving the combustion turbine performance and, consequently, the combined-cycle facility performance.

Purge Credit and Stack Dampers

To support fast-start design, advanced combustion turbine designs have incorporated purge credit and stack damper designs. National Fire Protection Association (NFPA) purge credit is employed not only in the combustion turbine fuel gas supply, but also in the duct burner fuel gas supply. Purge credit is accomplished by purging the gas systems of gas during the previous plant shutdown and adding additional isolation valves in the gas supply system. This design allows the startup to occur without the volumetric purge required by NFPA 85, enhancing the fast-start capability of the facility.

Another means of achieving faster starts is the use of stack dampers. Stack dampers allow the HRSG to be bottled-up, conserving the heat built up in the HRSG. Traditional design without stack dampers provides for the air to flow through the combustion turbine and HRSG, allowing the equipment to cool quicker. By employing a stack damper, the equipment is not cooled by convection of the air flowing through the machine. By using stack dampers, the ability to potentially improve the overall plant startup times is improved with the potential for changing a cold start to a warm start and a warm start to a hot start.

HRSG Balance of quipment Design

The remaining HRSG components continue to be in use. These components include supplementary firing, post-combustion emissions control equipment (i.e., carbon monoxide [CO] and selective catalytic reduction [SCR] catalyst), gas baffles, drains, low-pressure condensate recirculation system, deaeration, etc. These systems continue to be used to improve the performance, operation, and maintenance of the HRSG.

Steam Turbine Generator

Steam turbine designs associated with advanced combustion turbines are similar to designs used for traditional Rankine cycles. These machines are capable of the increased steam pressures and temperatures associated with the latest combined cycles. The current combined-cycle steam turbine inlet main steam pressure is 2,400 psig and main steam and hot reheat temperatures are 1,112°F for both. The older combined-cycle designs with lower pressures and temperatures were able to use steam turbines without an inner shell. However, with the higher temperatures and pressures, steam turbine designs have to employ both an inner and outer shell design.

Traditional Rankine cycle steam turbine designs included steam chests with control stages. This allowed steam turbines to use partial-arc steam admission. However, combined-cycle units typically use full-arc admission, minimizing efficiency losses via throttling across the admission valves. This concept continues to be the preferred method for operating a combined-cycle facility.

Steam turbine designs are also incorporating multiple low-pressure turbine sections as the flow rates increase with multiple advanced combustion turbine/HRSG trains and incorporation of supplementary firing feeding a single steam turbine. These configurations require multiple condensers with the corresponding design challenges for large steam turbine pedestals and multiple-shell condenser design and operation. However, single-shaft combined-cycle configurations are also employed, allowing a smaller axial exhaust steam turbine configuration to be used.

Final-Stage Attemperation

One of the challenges with designs to reduce overall emissions is the matching of the HRSG steam production and the startup of the steam turbine. This is especially valid when trying to start the advanced combustion turbine and maintaining lower emissions. The traditional combustion turbine startup is to temperature-match the exhaust with the steam requirements for the steam turbine startup. This would require the combustion turbine to stay at very low loads, and not be able to control the CO and nitrogen oxides (NOX) emissions. The current designs employ final-stage attemperators to allow the combustion turbine to start up independently from the steam turbine. The final stage attemperators allow the steam conditions to be matched to the steam turbine startup requirements regardless of the combustion turbine load. Therefore, the combustion turbine can ramp up to its emissions control load or greater and not be impacted by the steam turbine startup.

Sargent & Lundy has incorporated final-stage attemperators in combined-cycle designs to allow the combustion turbine to be started independently from the steam turbine to minimize emissions during startup at least as far back as 1997. At that time, Sargent & Lundy received special permission from the steam turbine manufacturer during the design process, since the ASME Turbine Water Induction Prevention guidelines in 1997 did not recommend water be added to the steam in route to the steam turbine without a downstream heat exchanger being employed. As interstage attemperators within the HRSG were not capable of controlling the steam temperatures for this configuration, final-stage attemperators were used. Today, this is a common design feature and the ASME Turbine Water Induction Prevention guidelines have been modified to allow for this configuration.

Auxiliary Boiler to Reduce Combined-Cycle Startup Time

Auxiliary boilers are still being used to improve on combined-cycle cold startup times. Auxiliary boilers as used to generate steam for steam turbine seals and to establish condenser vacuum. Based on Sargent & Lundy’s investigation, auxiliary boilers improve the cold startup time by approximately 15 30 minutes. This startup time requires the auxiliary boiler to be capable of starting quickly.

An auxiliary boiler and stack damper may also be used during warm shutdowns to maintain steam seals and keep the HRSG drums warm. The stack damper system is closed to hold heat in the HRSG during shutdown. Both of these provisions limit thermal cycle fatigue on the HRSG and reduce the duration required for the HRSG to begin producing steam that can be utilized for steam turbine warming.

Therefore, depending on the operating profile of the plant, if the intent of the auxiliary boiler is to shorten cold startup time, the benefits of an auxiliary boiler are limited. If the intent is to operate the plant in cycling mode, extending the duration from shutdown and maintain the unit in hot or warm standby, the auxiliary boiler has an advantage.

Conclusions

The current advanced F, G, H, and J Class combustion turbines impact the combined-cycle power block and BOP designs. These machines, along with various market demands, result in challenges in overall facility design. These challenges include integration with the steam bottoming cycle and BOP equipment, including the HRSG and steam turbine generator design, combustion turbine cooling air system, and the natural-gas supply system. In addition, the steam cycle is impacted through design requirements for fast startup, base load and cycling operation, high unit ramp rates, high efficiency, high reliability, lower emissions, and lower life-cycle costs. These techniques and their successful implementation have proven highly beneficial in the use of advanced combustion turbines in combined-cycle applications.

According to the U.S. Department of Energy (DoE), the 2016 U.S. electricity markets included 81 gigawatts of installed combined heat and power (CHP) capacity in approximately 4,300 industrial and commercial facilities. This represents approximately 8 percent of the total electric generation portfolio in the U.S. While most media coverage is on solar photovoltaics, electric vehicles, microgrids and net metering debates, the role of CHP may in fact represent one of the most significant long-term trends that will affect electric distribution.

CHP represents a remarkably diverse set of technologies and possible configurations, including reciprocating engines, combustion gas turbines, steam boilers, microturbines, and fuel cells. CHP is further characterized by heat recovery systems, generators, emissions control systems, and electrical interconnection and metering systems. These elements are advancing in their design efficiencies and competitive price points, and most benefit from low and stable natural gas price forecasts.

This diversity presents a challenge for utilities since they must gain detailed familiarity with a wide range of facility operating profiles, interconnection and metering needs, and net energy export characteristics. Each factor’s effect on grid services must be anticipated, accommodated and forecasted. In brief, if diversity means complexity, then complexity will only grow with CHP energy.

CHP Benefits

At the core of CHP is the capture and reuse of the waste heat generated by the conversion of the fuel from the prime power generation technology required – such as a natural gas-fired turbine or liquid fuel reciprocating engine. To enable heat reuse, the facility must meet both its thermal load — steam, hot water, chilled water — and its electrical energy needs at a lower collective heat rate than when compared to rates from separate processes. This more economical heat rate equates to lower emissions and operating costs. Additionally, the on-site electrical capacity can reinforce reliability, mitigating damaging losses from compromised power quality or sustained power outages.

In exchange for these benefits, the CHP facility owner must divert its capital to build a potentially complex thermal and electrical system, which is sometimes tangential to its core business. It must operate and maintain this system over the long term, taking on new forms of risks, such as embedded fuel purchase contract arrangements, emissions abatement controls, and fuel quality considerations.

Furthering DER Deployment

Because CHP can deliver electrical services to the grid in the form of capacity, energy and/or ancillary services, it is gaining attention as a key building block in a distributed energy resource (DER)-dominated future. Regulators aiming to recast distribution utility market functions want to ensure that CHP is afforded the full benefit of the services that it can provide to the grid. For example, a well-placed CHP facility might alleviate a local distribution system power flow constraint, or alleviate the need for upstream incremental generation.

CHP is also gaining traction for its potential role in improving the resilience of critical infrastructure, particularly if part of a well-designed microgrid. The need to bolster resilience has grown due in part to major outages caused by natural disasters, such as those following Hurricane Sandy on the U.S. east coast in 2012. Those looking to expand DER opportunities,including CHP, are attempting to find ways to incorporate benefits such as resilience into the monetary benefit stream, further incentivizing these largely private investments.

Despite the promise of these benefits, CHP often represents challenges for the host interconnecting utility if not planned well. Most pressing is the fact that the CHP operation may reduce utility revenues. This, in turn, could reduce anticipated fixed cost recovery, and introduce the need to spread uncollected costs across the remaining distribution system customers. However, this change in cost recovery is not guaranteed, and under most recovery mechanisms and rate structures there is a time lapse before it can be conceivably achieved. Additionally, the utility may also incur unrecoverable costs to interconnect and accommodate the CHP facility.

Another aspect of the challenge is the reality of how the CHP operates as compared to forecasts and plans – there are no guarantees that once interconnected, the CHP will operate indefinitely, or as forecasted. It may not provide the net energy dispatch that was anticipated, and it may require additional service from the utility to serve additional load or support facility reliability. There could also be changes to voltage and power quality on the local circuit (if not served off the primary system).

In the case of the Reforming the Energy Vision (REV) initiative in New York, arguments have been raised regarding CHP’s market transformation impacts. REV’s multi-tiered framework is underway, which includes several orders intended to address resilience, long-term climate change impacts and investment risks. The market ideally should be sufficiently robust and resilient in order to accomodate CHP entry and exit without undue disruption, but this state of advanced market maturity will take time to realize.

For example, in 2012, Sacramento Municipal Utility District (SMUD) witnessed the possible termination of 160 MWs of its nearly 500 MW of CHP when a major food processing facility on its system risked shutting down. Another utility in the Midwest has recently seen nearly 8 percent of its daily load serving requirement defect when one of its largest industrial customers, a plastic manufacturer, decided to self-generate to meet its processing needs, despite efforts to retain this load.

It is also important to note that existing CHP owners face pressing challenges associated with process upgrades, equipment replacement and service life extensions. Additionally, the markets served by these manufacturers may abruptly change, causing fast breaking dislocations that are beyond the utility’s control.

Managing CHP Challenges

There are many market reform challenges that utilities, commissions and stakeholders across the country will need to investigate and pursue in order to take full advantage of the benefits that CHP can deliver to the system. At a minimum, CHP facility operators need to have reasonable certainty on current regulations so they can effectively evaluate options. Market dynamics also need to be constantly reevaluated, including the role of emission-related benefits, the costs and requirements of interconnection, and the role of demand, standby and nonbypassable utility charges. Many of these questions are intertwined with a larger set of questions around market reform.. In any event, utilities should find pathways towards accommodation, clarity and transparency in working with their CHP customers. Ultimately, if CHP customers are successful,the electric service region as a whole benefits through improved economic performance and output.

There are some immediate steps a utility should consider to address the challenges introduced by CHP. At a minimum, it should develop the capability to be responsive to the needs of private developers looking to explore CHP opportunities on a project-by-project basis. This collaboration should include discussion on understanding the full suite of optimization and configuration options with the facility owners. These options should include exploring ways to push system benefits, as they can become potential sources of value that can help address cost recovery challenges and debates.

Electric utilities should also consider CHP as an opportunity through different ownership models. When the utility is the owner/operator, potential revenue streams could be derived from the sale of market-based power and steam, and/or thermal energy to customers. Projects with adequate net present values of free cash flows can be identified as potential CHP sites that would then require detailed financial analysis for final selection. Increasingly, stakeholders are also interested in locational values provided by distributed resources that are often outside of current market pricing arrangements, although monetizing these additional sources of value is highly market-specific.

In the electric utility industry, there are successful examples of ratemaking approaches associated with CHP services centered around transactional arrangements whereby the utility owns and operates the facility (i.e., an energy center concept dedicated to providing electric service, steam and chilled water to the customer). Such services are provided to the customer either through a standard tariff offering or some type of special contract that establishes prices for service (reflecting capital and operations & maintenance components) .

As part of the CHP opportunity analysis, the above calculations allow the utility to evaluate the costs and net revenue impacts, as well as any effect on net margin requirements. If compensation for power is based on actual avoided costs, no margin impacts are expected. However, for a utility with excess capacity, the avoided costs are based on energy costs alone; a margin component depends on the heat rate differentials between system marginal heat rates and the CHP facility heat rate multiplied by any difference in fuel costs per MMBtu.

More broadly, it would be wise to proactively address CHP cost recovery concerns in a context of forward-looking and optimistic perspectives. This will not always be possible on a project-specific basis, but unless a utility actively finds unique project attributes, configurations and contracting arrangements, it will not always be able to develop a market prescence for the long term in this important area of market transformation.

Authors:

Ajay Kasarabada is a CHP Solutions Manager and Project Manager in the Distributed Generation Service Area within Black & Veatch’s Power Division. Andrew Trump is a Director in Black & Veatch’s management consulting business.

Natural gas generators are quickly becoming a focus of corporate strategy for many generator manufacturing companies. The market for natural gas is growing and will continue to grow. There are three driving factors behind this burgeoning industry switch diesel powered engines to natural gas. First and foremost, end users are looking to eliminate emissions independent of regulatory mandates, simply to prove they’re good stewards to their local environment. Secondly, according to recent reports and studies, natural gas has the ability to provide long-term price and supply stability. The American Gas Association anticipates a period of relative natural gas price stability and robust supply as demand increases to meet environmental requirements. Lastly, natural gas engine technologies have and will continue to advance, making this fuel source a more reliable solution than other options on the market.

The United States Environmental Protection Agency (EPA) sets guidelines for manufacturers in the commercial and industrial sector to comply with. As it stands now, traditionally-used fuels meet these standards, but natural gas provides companies who are specifying new gensets with a cleaner burning, lower emissions option, which is often well-suited for the community where they’re doing business.

According to the International Gas Union, natural gas is one of the cleanest fossil fuels when it burns, meaning it can greatly reduce a business’ carbon footprint. Compared to oil and coal, the emissions of sulfur, nitrogen and carbon dioxide (a greenhouse gas) are considerably lower. When burned, natural gas releases 50 percent less CO₂ than coal and 20 to 30 percent less than oil. This reduction in sulfur, nitrogen and especially carbon dioxide are what make natural gas a viable, cleaner fuel option above others.

This 50 percent reduction in CO₂ emissions decreases manufacturing “smokestacks,” meaning less air and water pollution. This is an immediate benefit for manufacturing plants and companies who are supported by a surrounding community who value a clean local environment.

Another reason behind the push towards natural gas lies in its stability. The United States has battled with a stable gas source for years, leading to costly price fluctuations that can hurt the bottom line for many companies. Natural gas is an abundant fuel source that can be found in the backyard of many American companies. The infrastructure has also improved tenfold. The natural gas pipeline structure is now advanced to deliver 99.9999% reliability and now reaches nearly every part of the U.S in the lower 48 states.

The three-part infrastructure allows natural gas to meet peak demand needs unlike other renewable resources. Natural gas is delivered by underground pipelines connected to the utility main supplies that connect to the end-user. Across the country, there are more than 2.4 million miles of natural gas distribution pipeline infrastructure that supplies 177 million Americans and about five million commercial enterprises with natural gas. For a simpler visual, these underground pipelines can be compared to the U.S. highway system. This vast underground interconnectedness creates a stable supply of natural gas for end users.

This stability and reliability also translates during times of power outages. If a pipelines fails, natural gas can be rerouted to continue to meet the end user. For facilities that deal with regular threats of power outages, this can be a game changer and a driving factor to switch to natural gas for power generation.

Together, the gas utilities and pipeline companies in America are investing billions of dollars annually to ensure that natural gas continues to be delivered in a safe and reliable manner. In conjunction with pipeline infrastructure improvements, natural gas engine technology has also improved. Today, natural gas-powered engines combine high efficiency, low emissions, advanced combustion, improved air systems, dedicated engine system controls, and reduced cost of ownership. This makes backup power generation as reliable as anything else on the market. These gensets are now equipped with features that allow for great power outputs that will result in longer run times.

These durable, more dependable gensets will only continue to improve as the nation’s drive for natural gas becomes greater.

New technology, abundant and reliable sourcing methods and a cleaner fuel option all add to the logical reasoning behind a surging shift to natural gas usage in North America. More companies today understand natural gas is a smart solution to powering equipment and operations. Continued technological progress is more than an expectation, it’s a certainty.

In September 2002, I was working onsite at a power plant construction project. It was just like every other Tuesday morning, only this Tuesday morning would change the beliefs I had about safety. I believed the most important part of a good safety program were the processes and “rules.” Supported by our extremely low injury rates, I believed our project was as safe as any I had ever worked on; why wouldn’t I? However, that belief ended on this morning when a subcontractor employee lost his life due to an incident on the project. To this day, I remember the look of fear and panic on the foreman’s face as I arrived on the scene of the accident.

We work in a dangerous industry.

Historically, the electric utility industry has one of the highest worker accident and fatality rates in the country and the world. Many utility headquarter lobbies or operations centers have memorials to those who have died in the course of their duties. Unnamed are the thousands more who are burned, disabled or dismembered by electricity and the dangerous work environment created to supply, operate and maintain “the most complex machine of the 20th century.”

Much has been accomplished over the last several years to improve the recognition and appreciation of safety. Since 2002, I have come to realize that although safety processes and rules are important they are just one part of a safety program designed to achieve an organization’s safety goals. My current employer has developed a strong safety culture over the last decade. We are consistently best of class in every measurable key performance indicator as it relates to safety, placing us in the top 5 percent of safety performance for all contractors nationwide. How did we achieve these numbers? And, more importantly, how to do we improve upon these numbers?

As with most successfully safe companies, leadership starts at the top. Our then CEO immediately made the company aware of his goals and initiatives. The goal, simply put, was to “make us one of the safest engineering and construction firms in the world.” The first step in this process was to define what “safe” looked like. He formed a team to look at the company’s risks, both from a corporate perspective as well as a project perspective.

The next step was to establish a successful safety program that would align with our strategy of achieving our goal. Over the past 13 years, we have implemented several different programs to strengthen not only our safety processes but also our culture. Some of the more notable programs are our Task Safety Observation Program (Behavioral Recognition Program), Employee Engagement program and a robust training initiative. We also realized that improving the culture at our firm would only get us so far; we had to also improve the culture of the entities that we choose to work with – our clients and in particularly our subcontractors. Without engagement and a desire from these groups, a continually improving culture of safety could not exist.

We started with investing and maintaining a safe workplace. It may sound simple, but when people see the effort and commitment demonstrated by management towards creating a culture where safety is a value they immediately want to be part of the solution. Another effort was to create a system to track and prevent safety concerns. An electronic employee concern notification system and an incident management system developed to give our employee-owners a way to voice their concerns and suggestions. These contributed to our folks being actively engaged in improving their safety climate.

The words “Behavioral Based Safety” are often met with hesitation, and I agree that BBS on its own is not as effective as other stand-alone programs. However, when incorporated into an overall safety program BBS can have several benefits. Used properly, BBS identifies at-risk behaviors, assists with evaluating the effectiveness of training programs and your current safety programs, and provides a way to promote engagement from all levels of an organization.

Training is another term that generally doesn’t promote excitement, mostly because safety related training is highly technical and a bit boring at times. That said, it in no way downgrades its importance. Training is vital to any successful safety program. Not only is it required by law for certain tasks, but good safety training helps people identify hazards, understand expectations, be able to accurately evaluate risk, and know what to do to ensure that hazards do not negatively affect themselves or others.

How do you improve your safety performance? Leadership, Commitment and Effort. It starts with what we are at our core. The very foundation of every company begins with its people. When you positively motivate employees to contribute to the safety success of the organization, you get an engaged employee. There is no “follow these requirements and everything will go as planned.” Safety isn’t about rules or requirements; it’s about the safe execution of those processes.

State-owned Santee Cooper could get a new owner – and that owner could revive the cancelled Summer nuclear expansion.

Both South Carolina Gov. Henry McMaster and Santee Cooper officials told the Post and Courier they’re undergoing separate searches for buyers. McMaster said interested parties could be Duke Energy, Dominion Energy and Southern Power.

Southern Power, through its subsidiary Georgia Power, is currently assessing whether to continue construction of its own nuclear expansion at the Vogtle plant. Both Vogtle and Summer are over-budget and behind schedule, and both lost their main contractor when Westinghouse Electric filed for bankruptcy.

Santee Cooper indicated it is only looking for a buyer for its 45 percent share of the two unfinished reactors at Summer, and has found two unidentified interested parties. South Carolina Electric & Gas owns the remainder.

Talen Will Keep Coal-Fired Colstrip Open

Though the end of the coal-fired Colstrip Power Plant was once rapidly approaching, the owners of the 2,100-MW plant have changed course and will keep it open, at least for now.

Spokesmen for some of the six utilities that co-own the plant have said they have accepted Talen’s offer to keep the plant open, the Billings Gazette reported. However, the final details have yet to be worked out.

The reversal comes after a 2016 decision that it was “not economically viable” to keep operating Colstrip, and January filings that indicated co-owner Talen Energy would cease operating Colstrip Units 3 and 4 by mid-2018.

Coal Generation to Surpass Gas in 2017

The latest short-term energy outlook from the Energy Information Administration indicated coal is still on track to surpass natural gas generation for 2017, with total shares of almost 32 percent and 31 percent, respectively.

That near-tie comes after natural gas generated 34 percent of the nation’s power in 2016, with coal finishing at 30 percent.

However, the projected generation shares for coal and natural gas for 2018 are now nearly identical, averaging between 31 percent and 32 percent.

Overall U.S. generation is expected to decline by 1.2 percent in 2017 as a result of milder than normal temperatures in the third quarter.

Rhode Island Establishes New Laws Supporting Renewables

Rhode Island Gov. Gina M. Raimondo signed into law a number of bills that would support the growth of renewable energy in the state.

The laws include:

• A 10-year extension of the renewable energy growth program
• A streamlined permitting application for solar
• A streamlined process for connecting renewable energy to the grid
• The ability for farmers to install renewable energy on up to 20 percent of their total acreage
• An expansion of virtual net metering for renewable project development

Goldwind Provides 60 MW to One Energy for DG

Goldwind Americas announced it will supply One Energy Enterprises with 60 MW of Goldwind turbines for distributed generation wind power projects in the U.S. as part of One Energy’s Wind for Industry model.

The first four turbines will be installed in Whirlpool Corp. facilities in Mario and Ottawa, Ohio.

“Manufacturers are taking control of their energy future,” said Jereme Kent, Chief Executive Officer of One Energy Enterprises. “They want clean energy, they want low fixed rates, and they want it now; and that is exactly what we give them.”

California Offers $44.7 Million in Grants for Microgrids

The California Energy Commission issued a $44.7 million RFP for microgrid programs.

The intent is to develop microgrid designs that can be put into continual service and drive down future development costs. The commission had previously offered $26.5 million in 2014, resulting in seven microgrid demonstration projects.

Of the $44.7 million, $22 million is allocated to military bases, ports and Native American tribes, $11.7 million will go to disadvantaged communities and $11 million for other locations, including rural areas, educational facilities and industrial complexes.

Individual grants will range from $2 million to $7 million, though winners will need to provide 20 to 25 percent of the funds for the project.

Falling Battery Prices to Accelerate Storage Installations

A new report by IHS Markit indicates prices for lithium-ion battery storage will fall below $200 per kilowatt hour by 2019.

That drop, a full 70 percent since 2012, will cause energy storage use to surge as applications become more economical.

The report indicated storage capacity will grow from 4 GW today to 52 GW by 2025.

Annual growth is expected to grow from 1.3 GW last year to 4.7 GW by 2020 and 8.8 GW by 2025. In turn, revenue will increase from $1.5 billion last year to $7 billion in 2025.

AES Begins Construction of California Gas Plant

AES Alamitos, a subsidiary of the AES Corporation, began construction the 640-MW gas-fired Alamitos Energy Center.

The plant, which will include a 100-MW battery energy storage system, will replace the existing AES Alamitos Generating Station in Long Beach, California.

“We’re excited to move forward to the construction phase of this important project and look forward to working with the community every step of the way,” said Stephen O’Kane, president of AES Alamitos Energy LLC.

Wind Power Represented 27 Percent of New Capacity in 2016

A new report from the Department of Energy indicated 8,200 MW of wind capacity was established nationwide in 2016, representing 27 percent of all new capacity added that year.

Last year, wind supplied six percent of all U.S. electricity, with 14 states now generating more than 10 percent of their electricity from wind. Iowa and South Dakota produce more than 30 percent from wind. Texas leads the nation in terms of total capacity with over 2 GW of wind.

Wind prices, established through power purchase agreements, are cost-competitive with traditional power sources in many parts of the nation.

The Energy Department said near-term growth is supported by production tax credits, state-level policies and improvements of both the cost and performance of wind power technology. Offshore wind has grown as well, with 20 projects totaling 24,135 MW are in development.

DTE Energy Proposes 1,100-MW Gas Plant in Michigan

DTE Energy proposed an 1,100-MW gas plant to be constructed in East China Township, Michigan.

The nearly $1 billion project is currently scheduled to break ground in 2019 and come online in 2022. DTE, which has filed a certificate of necessity with the Michigan Public Service Commission seeking approval, said the plant is part of the company’s goals to reduce carbon emissions by 30 percent in the early 2020s and 80 percent by 2050.

DTE said the proposed plant will be the most efficient plant in the state.

Judge: TVA Must Remove Coal Ash at Gallatin Plant

A federal judge ordered the nation’s largest public utility to dig up its coal ash at a Tennessee power plant and move it to a lined waste site where it doesn’t risk further polluting the Cumberland River.

U.S. District Judge Waverly Crenshaw ruled in favor of the Tennessee Scenic Rivers Association and the Tennessee Clean Water Network, saying coal ash storage at Tennessee Valley Authority’s Gallatin Plant has been letting pollutants seep into the river for decades in violation of the Clean Water Act.

As long as the coal ash remains at the plant about 40 miles from Nashville, dangers, uncertainties and conflicts will continue, Crenshaw wrote. However, he added that there’s scant evidence so far of concrete harm beyond the mere risk and presence of pollutants.

Texas Consumes 13 Percent of U.S. Energy

The latest State Energy Data System report from the Energy Information Administration indicated Texas recorded the greatest energy consumption in 2015 with 13 quadrillion Btu, or 13 percent of total U.S. energy consumption.

Texas has consumed the most energy in the nation every year since 1960, the earliest year for which EIA has data. California came in second with eight quadrillion Btu, or eight percent of total energy use. Louisiana, Florida and Illinois rounded out the top five, which together account for more than one-third of total energy use.

Additionally, total energy consumption by the top 10 exceeded the combined energy use of the other 40 states and the District of Columbia. Vermont, which has used less energy than any other state since 1961, came in at the lowest at 132 trillion Btu.