Figure 1. Double-effect absorption refrigeration cycle.

There’s a concept, eh? The author takes a comparative discussion of chiller technologies and options, and he places it squarely within the current events context of domestic energy sources, the utility rate landscape, and thermal efficiency. Read this and then look for Part 2 in the near future.

There is much to cheer about ASHRAE’s stated goal of “net zero” buildings in view of today’s operationally challenged building designers, owners, and managers. Property professionals are actively reducing building operating expenses to stay competitive in our challenging marketplace. A recent report from Building Owners and Managers Association (BOMA) International and Kingsley Associates concludes that reducing utility costs is a key strategy. In the last two years, general multi-tenant buildings have, in fact, been able to reduce their utility bills by $0.08/sq ft. These reductions are even greater in corporate sector buildings and government facilities. The report concludes that “a steadfast focus on energy efficiency has become a key element of ongoing operational practice” and will outlast the current economic downturn.”

The demand for new and existing renovated net energy zero buildings can be expected to grow. However, current net zero criteria may not be sustainable from a carbon neutral standpoint. For example, the coefficient of performance (COP) of any gas-fired or electric motor-driven chiller can be expressed as the ratio of a cubic foot of natural gas (NG) available as “internal” energy used by on-site (customer’s) equipment (Ea) vs. (Eu) representing the useful energy obtained as the resulting refrigeration effect.

In terms of carbon neutral criteria, how does one compare a two-stage lithium bromide (LiBr) absorption chiller having a COP (or Eu/Ea) of 1.20 with an equivalent Eu obtained from a comparable motorized water cooled rotary screw chiller having a COP of 3.9? One must first begin with the NG (Ea) supplied to the remote electric power generating station (EPGS) operating at a 33% thermal efficiency, with the resulting Eu (or refrigeration effect) at the customer’s rotary screw chiller, which corresponds to a carbon-neutral adjusted COP of 1.29.

Therefore, the subject rotary screw chiller is only 7.5% more efficient than the absorption chiller on a carbon neutral basis, while emitting approximately three times the amount of greenhouse gasses (GHG) into the atmosphere at the remote EPGS that supplies the power.

Because of growing concern regarding climate change, HVAC designers can no longer afford to turn a blind eye to this GHG disparity. Chiller design must consider the environmental effects of refrigerants - namely natural (water) vs. artificial refrigerants and their environmental consequences. Let’s now take a look at the remote EPGSs now being planned by our nation’s public utilities and see how the selection of chillers, which have a relatively long useful life, may need some rethinking.


DOE records and information provided by utilities and trade groups to the Associated Press indicate that more than 30 traditional coal plants have been built since 2008 or are now under construction. The construction wave stretches across the country despite growing public wariness over the high environmental and social costs of fossil fuels, demonstrated by mine disasters in West Virginia and the Gulf oil spill.

Hoping for a technological solution, the Obama administration devoted $3.4 billion in stimulus spending to foster clean-coal plants that can capture and store greenhouse gases. The electric utility industry seems to have ignored the DOE’s highly touted “clean coal” technology and proposals aimed to reduce carbon emissions amid its largest largest expansion in two decades. New investments in traditional coal plants total more than $35 billion, which represents approximately 10 times the amount spent by the Obama administration to date to foster clean coal plant construction. Not surprisingly, in July the Senate scrapped the leading bill to curb carbon emissions.

Utilities prefer coal since its abundance makes it less expensive than natural gas or nuclear power, and more reliable than intermittent power sources, such as wind and solar. Still, the price of coal plants is rising, and consumers in some areas served by the new facilities will see their electricity bills rise by up to 30%. Utility spokesman proclaim increases would be even steeper if utilities switched to NG or were forced to adopt the DOE’s proposed emission-reduction measures.

Approvals for building the less efficient, traditional coal-fired plants came from state and federal agencies that chose not to factor in future climate warming issues in spite of some successful legal challenges by scientific expert efforts to overturn agency decisions. As a result, the new wave of construction is more than enough to ensure coal’s continued dominance in the power industry for years to come.

Sixteen large, traditional coal-fired plants that have been operating since 2008 and 16 more believed to be under construction will not capture carbon dioxide despite ongoing governmental stimulus spending and additional millions spent by DOE clean-coal programs. Taken together, these 32 will produce an estimated 17.9 MW of electricity while generating an estimated 125 million tons of GHG annually (according to emissions estimated by the respective utilities and the Center for Global Development), thereby amounting to the equivalent of an approximately 22 million additional automobiles on our highways.

Clean coal power plants require adjacent geological formations. While some success has been achieved in separating carbon dioxide from plant effluent for storage underground in experimental trials, high costs and problems of isolating carbon dioxide from other effluent gases have stymied commercialization of the process. For example the 110-MW Wygen III coal plant that began operating in northeastern Wyoming earlier this year had “no way of capturing carbon” according to public statements by its operators. As each ton of coal rumbles off conveyor belts from a coal mine nearby, steel pulverizers crush the fuel to the consistency of baby powder. Thereafter, fans blow it into a giant furnace where the coal is combusted to a temperature of 1,700°F, producing steam to generate electricity. While Wygenn II requires approximately 20% less coal per delivered per unit output compared to earlier plants, the process has changed little since Thomas Edison built the first plant in 1882 in New York.

Today’s lackluster national economy presents the EPGS industry with a problematic future. To make matters more difficult for the industry , the EPA proposed a rule on July 6, 2010, that would require significant reductions in sulfur dioxide (SO2) and nitrogen oxide emissions (NOx) that cross state lines. The rule, known as the Transport Rule, would replace EPA’s 2005 Clean Air Interstate Rule and would require 31 states and the District of Columbia to improve air quality by reducing emissions from all EPGS, including  all the new coal-fired plants

In addition, the EPA released two draft rules on September 2, 2010, for implementing the agency’s new permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration (PSD) program. Meanwhile, Congress is expected to vote to block or delay EPA’s regulation of greenhouse gas emissions under existing Clean Air Act requirements, and litigation over EPA’s rules moves forward. But unless the courts or Congress intervene, limits on GHG emissions from stationary sources will begin to go into effect early next year.


One will no doubt find the data on the wide expansion of older design traditional coal-fired power plant construction by electric utilities in keeping with the disparity in the skewed rating COPs of electric motor-driven vs. gas absorption chillers .

Based on a estimated average thermal efficiency for NG gas-fired remote EPGSs of approximately the same 33% in converting prime NG gas (internal) energy into electricity at its terminus, one must recognize the environmental consequences of the remainder being discharged to ambient as thermal pollution and GHG, in addition to average power distribution losses averaging an additional 10%.

Figure 2. Operating cost savings obtained by employing the VRA unit in a reverse series flow double-effect absorption chiller.

Since it has been estimated that an additional 125 million tons of GHG will be generated by these EPSGs, we have to account for GHG differentials and deal with energy costs at the energy source or point of  “Ea prime energy conversion” as opposed to current  “Eu point of use.” rather than continue to operate at the so-called net zero comparable but with energy industry skewed gas and electric customer rates delivered at their respective meters.

LEED® certification is now required by 14 federal departments and agencies, 34 states, and more than 200 local governments. Some offer incentives for certification, while others mandate LEED as a kind of code to follow for best results. But where is the compliance procedure to ensure both positive energy savings and GHG emissions reduction? Is it enough to characterize a building with a guarantee for how much energy  it won’t consume? One of the reasons the program has proven so popular is that LEED certification is given before energy savings are proven, and, until recently, building owners have not needed to demonstrate actual energy savings. LEED certification has never depended on actual Ea source energy use, and it’s not going to until our industry addresses climate change issues. Consequently, a new building owner/manager/operator could use as much energy as it wished, including reporting it, and still keep a LEED plaque/certification.


The conventional gas-fired LiBr absorption chiller must be able to take advantage of higher temperature heat sources to achieve higher COP so as to be competitive with lower-first-cost electric chillers under current market pricing conditions. However, two-stage LiBr absorption chillers are limited by corrosion effects, which have been shown to accelerate significantly above 160°C.

Referring to Figure 1, notice the numbering of components and circuits [1-8] which define the key operational aspects that will be dealt subsequently to improve cycle thermal efficiency, and hybrid shifting of on-site NG energy use to and from purchased electricity to achieve “real time”  cost savings as can be seen, for example, in Figure 2. Other key components, namely the steam-fired (low temperature) stage generator [5], evaporator [3], combination high and low stage condenser [1], steam fired (high temperature) stage generator [8], refrigerant circuit [2], absorber [4] and related absorber/condenser series flow cooling tower circuit, and high and low concentration LiBr solution circuits [6] and [7].

If the LiBr chiller is of the indirect (steam) fired-type and it were able to simultaneously increase its refrigerant mass flow rate and LiBr concentration to the absorber shown in Figure 1 through appropriate integration with a vapor recompression absorber (VAR), it would consume approximately the same amount of prime NG Ea source energy as the comparable high-performance electric chiller, while still being more sustainable from an environmental impact (e.g., GHG emissions standpoint).

Consequently, research to further improve double-effect LiBr absorption chillers beyond the VRA benefits reported to date are now being extensively investigated. Former simulation studies of low differential pressure VRAs reported in 2001 indicated a 7% COP efficiency gain, while additional simulation studies reported in 2006 indicated a 38% COP efficiency gain, with the VRAs operating at elevated differential pressures at slightly above the upper-stage concentrator temperature previously considered but safely below the 160°C corrosion limit. In so doing, the electric motor-powered VRA component provides a unique “hybrid” benefit that can take advantage of the differential cost of real-time gas and electric rates to drive greater operating savings than either standalone direct gas-fired, indirect gas-fired (via steam or hot water media), or waste heat-fired two-stage absorption chillers as will be seen in Table 1 following and/or in Part 2 of this article found at

Figure 2 illustrates the effect of real-time gas and purchased electricity on VRA increased cost operational savings.


After examination of the environmental consequences of continuing to ignore the above facts, new research, and cognizant expert opinions, it can be concluded:
  • In spite of the general interest in improving electric utility plant efficiencies, recent permits for “older type” coal-fired plants are currently on the rise in the U.S. and are in the majority. Since 1967, little has been done to increase their thermal efficiencies beyond the current national average of 33%, which excludes local distribution losses from power plant to customer meter.
  • For NG-fired electric utility plants, the numbers are equally depressing, but VRA absorption chiller cycle options can dramatically affect that balance for both new and existing gas-fired and electric motor-driven chillers.
  • If one compares the use of NG in a remote electric utility plant (of the type referenced above) with the choice of electric motor vs. gas engine-driven (or absorption) chillers served from both electric and gas metering at the building point of use, in most cases the choice invariably goes in favor of electric motor-driven centrifugal, reciprocating, or screw compressors with a perceived higher COP, lower first cost, and/or footprint/size. That is, except in cases where increasing electric demand or service cost (e.g., in renovating an existing building) could prove prohibitive.
  • Comparing these choices from the standpoint of GHG emissions, however, gives a substantially different result. The reason being that we have ignored lost NG internal energy, which on a delivered kW basis at the customer’s electric meter amounts to approximately a 67% thermal efficiency loss or GHG emission gain. In the case of NG, the amount of C02 emitted per cubic foot of NG at the customer’s absorption chiller is 0.1182 lbs, whereas at remote coal-fired and gas-fired EPGS on average it is much higher, at approximately 2.1 lbs and 1.3 of CO2 per kWh, respectively. Coal-based production regions (e.g., North Dakota) are much higher.
  • In the case of NG delivered to the same customer’s gas meter, the equivalent lost NG internal energy may amount to anywhere from 0% to 35%, depending upon the type of gas engine efficiency (operating at 33% thermal efficiency), either a single-effect indirect fired LiBr absorption chiller (operating at 60% to 65% thermal efficiency) or a gas-fired double effect LiBr absorption chiller operating at a COP > 1.0 even after an adjustment for associated electric motor driven LiBr solution pumps. Assuming an efficient electric motor-driven centrifugal chiller with a reported COP of 6.0, on the basis of comparable GHG emissions to an equivalent gas fired LiBr double effect absorption chiller operating at a COP = 1.1, one would have to adjust its NG energy source COP to 1.8.
  • It has been demonstrated that self-contained VRA components physically integrated with either an existing or a new gas-fired two-stage effect absorption chiller can achieve an estimated 35 to 40% energy cost savings, depending upon prevailing building site comparative annual projected gas to electric utility rates.
  • After taking into account the reduction in net electrical building demand, to accommodate greater use for IT or other anticipated additional future building electrical usage, the electric motor driven chiller NG “energy source “COP” (or Ea/Eu) will often approach approximately the same value. ES


1. Sakraida, Vincent A. “Basics For Absorption Chillers.”Engineered Systems. March 2009, p.36.

2. Meckler, M. et al. “VRA Enhancement of Two Stage LIBR Chiller Performance Improves   Sustainability” Paper No. ES2007 – 36109, Proceedings:  1st ASME International Conference on Energy Sustainability, Track 4, Heat Pumps, Refrigeration, Climate Control, Advanced Energy Systems Division, ASME; Long Beach, CA, ISSN 0-7918-3798-X June 27-30, 2007.