Faced with rapidly rising power costs, chemical manufacturers are using a range of strategies to tackle the problem, starting at the corporate level and progressing all the way through to energy-saving activities at the plant level.
The scale of the problem — some even say crisis — was highlighted by the American Chemistry Council (ACC), Arlington, Va., in its recent presentation to the Senate subcommittee on energy and mineral resources. “Today, U.S. natural gas prices are the highest in the world,” the ACC noted, comparing the more than $7 per million BTU cost in the US to Europe’s $5.25, China and Japan’s $4.50 and the $1.25 or less in the Middle East and Russia. This obviously impacts on operating costs at existing plants within an industry that is the nation’s largest consumer of natural gas. Indeed, more respondents (almost one-third of the total) to a recent Chemical Processing survey on costs that most threaten the competitiveness of plants put energy first; feedstock/raw material costs came in a relatively close second, with other factors far behind (see CP, July, p. 13). This competitive disadvantage, of course, doesn’t just affect current plants. It also is now driving investment away from the U.S. chemical industry. “Of the 125 world-scale chemical plants now under construction around the world,” says the council, “50 are being built in China, but only one in the U.S.”
Although the chemical industry has no real sway over the actual price of natural gas, the ACC has welcomed the energy tax package put forward in June by the Senate finance committee. This package includes incentives for manufacturers to switch from natural-gas-fired operations to ones that make more use of synthetic gas produced from coal, biomass and waste materials — a move that has the potential, says the council, of replacing some 7% of total natural-gas demand with synthesis gas, at about two-thirds the current delivered price of natural gas.
The necessary gasification technology for that to happen is already available, of course, but it is hardly an overnight solution to today’s problems of high energy costs. What plants need right now are either cheaper energy prices or ways of reducing their power consumption by improving the energy efficiency of their operations.
The power of pooling
As the ACC recognizes, energy pricing policy is as much a political issue as it is a commercial one. However, one proven way for industry to drive down the price posted by its electricity suppliers is the practice of “power pooling.” Introduced not long after the deregulation of the power industry in the late 1990s, the concept of power pooling calls for like-minded manufacturers to act in concert and leverage their collective buying power to obtain lower energy rates.
One of the first examples of this in the chemical industry was the pool set up by the Chemistry Council of New Jersey (CCNJ) in 1999. Over 40 of its members formed what is still the nation’s largest industrial energy-aggregation group, with each company — including some of the largest chemical and pharmaceutical operators in the state — saving an average of 15-20% in charges. “New Jersey’s energy costs continue to be the fifth highest in the nation and our energy pooling program has worked to the advantage of our members,” says Hal Bozarth, CCNJ executive director. “By combining our buying power of nearly 260 MW of peak electricity load, participating member companies have saved nearly $20 million on energy costs and have a higher level of budget certainty.”
The New Jersey buying pool is renewing its contracts for a third time, while a similar pool is about to be set up in Texas through a partnership with the Texas Chemical Council, the Association of Chemical Industry in Texas, and Priority Power Management (PPM), a Texas-based energy management and consulting services firm.
Perry Ruthven, managing director of PPM’s Houston operation, explains the attraction of power pools: “As energy costs for chemical manufacturers have soared, company managers are seeking innovative ways to manage energy procurement and lower costs. While traditional aggregation is limited by a ‘one size fits all’ philosophy and rate cross-subsidization, our buying pools offer individual contracts and flexibility. The result is a multi-contract procurement which allows the retail providers to offer the discount of bulk purchasing, while eliminating cross subsidization through the use of customized rates for each contract.”
|Figure 1. DSM’s largest site, at Geleen, The Netherlands, has achieved significant savings by using software to optimize energy costs in real time.|
The Texas pool partnership was announced earlier this year and Ruthven says PPM has been gathering information on companies’ power loads since then, with the aim of proposing detailed pooling plans to the firms in the fall. “The potential is large,” he says. “We have received letters of intent so far for 120,000 MWh of conditional loads to pool, and we haven’t yet covered the whole range of possible participants.” This compares with PPM’s first pool of some 140,000 MWh, set up for another industry sector around the time of deregulation.
Sighting on the site
Energy procurement at this level might seem somewhat remote to the engineer at the plant, but what happens on-site can have a huge impact on the financial factors involved in negotiating power rates. The net result of deregulation may well have been greater choice and flexibility of supply, but plants need to have a better understanding and control of their true energy requirements. Or, to invoke the mantra of management consultants across the globe, “what you can’t measure, you can’t manage.”
One of the latest tools for helping plant energy managers in this way is a software program called the Plant Energy Profiler for the Chemical Industry (ChemPEP). Launched in May, ChemPEP was developed as part of the U.S. Dept. of Energy’s Industrial Technologies Program (ITP) by EPRI Solutions, the commercial arm of the Electric Power Research Institute, Palo Alto, Calif., in partnership with the American Institute of Chemical Engineers.
According to Ed Fouche, manager of EPRI’s Process Industries Program and a senior associate with EPRI Solution’s subsidiary Global Energy Partners, Raleigh, N.C., “ChemPEP was designed specifically for the chemical industry to help energy managers determine overall plant energy use, identify major energy-using equipment, review cost distributions and locate areas of improvement. You start with a site-wide energy balance, and then go through a number of steps to establish what improvements can be made to balance loads at the unit operation level.”
Along with two other new software tools for combined heat and power (CHP) applications and chilled water systems, ChemPEP is available as a free-of-charge download from the ITP’s Best Practices website (www.oit.doe.gov/best practices).
Fouche is finding the industry “generally receptive” to the energy efficiency measures promoted by the ITP. These include the application of advanced control and power technologies to improve electrical reliability and energy efficiency. The program’s current focus is on the petrochemicals sector, with companies such as ChevronTexaco, Shell, BP, ConocoPhilips and Valero involved. “Some companies are much more proactive than others with their energy programs,” Fouche says, “but all of them, to some degree, need valid information to make decisions.”
Eric Petela, director of energy optimization for Aspen Technology, Cambridge, Mass., makes the same point. “Companies typically don’t have the processes or systems in place to measure their current performance,” he says, “and in many cases responsibility is spread across multiple stakeholders — from the power plant manager, to the process engineer, to the energy purchasing manager.” Aspentech’s answer is its range of software solutions for “energy performance management.” In effect, these build on the company’s expertise in process simulation, using accurate models of a site’s key process units and utility systems to visualize exactly how changes in operating strategy or utility supply will impact the plant’s energy performance.
Petela maintains that “model-based software solutions are now enabling companies to both manage and optimize their energy systems, taking into account the specific operating constraints and cost drivers at individual sites.” The results can be seen at DSM’s largest chemicals complex at Geleen in the Netherlands. This huge site has implemented Aspentech’s “aspenONE energy management for chemicals” software to optimize its energy costs in real time.
“Since we are dealing with complex contracts that specify the amount of energy we can consume, we needed a solution that would allow us to forecast and optimize our energy consumption for the year to improve our utility rates and help us avoid millions of euros in fines,” explains Geert-Jan de Laat, DSM’s modeling competence manager. He quantifies the benefits to DSM as up to 3% reduction in energy consumption, 4% in operating costs, and — significantly in such a tightly regulated market — an insight into negotiating better rates with energy suppliers.
The energy-performance-management software solutions used by DSM are implemented at a site-wide level but significant energy savings also can be made at the individual unit-operation level by using advanced control and power management technologies. One good example of this has already been recognized in these pages with the honor of the first CP Plant Innovation Award going to Dow’s Seadrift, Texas, facility (see CP, May, p. 19). The award was made to the team involved with implementing Gensym’s G2 expert system software, coupled with a closed-loop optimizer, on one of the site’s three cogeneration units. By using the rules-based approach of G2 to better manage the complexities of the cogen unit’s heat-recovery steam generators and turbines, Dow saved $1.75 million in energy costs last year.
Cogen operations on the scale of that at Seadrift, which has a total rated capacity of 144 MW, are practically utility companies in their own right, of course. Internally, they provide the heat and power to run the plant while any excess power generated can be sold into the grid. That’s the theory, at least. In practice, as Seadrift was finding before switching its optimizer fully into closed-loop mode, engineers often tend to be fully occupied in generating reliable heat and power for their own plant and simply don’t have the time — or the expertise — to trade-off the cost and value of exported power at the most beneficial rates.
PPM’s Ruthven emphasizes the importance of that market knowledge. “Engineers have a responsibility to run their plants as efficiently as possible,” he says, “and consume electricity in as cost-efficient way as possible. But now, increasingly, a company’s finance department will be hedging the natural gas market to make the best possible power purchase on as long a term as possible.” One consequence of this can be the anomaly of a smaller plant paying much less for its imported power than a far larger neighbor, purely because it might have signed up for a longer-term supply contract a few years ago — or made what might be called a “prodigious procurement,” as Ruthven ruefully puts it. Nevertheless, he sees power pooling as a way of avoiding such anomalies, because both large and small operators will be taking their combined power requirements to the utility on much more of a level playing field.
As planning executive for ExxonMobil Refining and Supply for Europe, the Middle East and Africa, Brussels-based Paul Dillon is involved with cogeneration on the global scale. Across its refining and petrochemical operations, ExxonMobil now has an installed cogen base of 3700 MW across 85 units at 30 locations worldwide. Although Dillon acknowledges that total capital costs for cogeneration are higher than alternative power-generation systems, he believes these are more than offset by “cogeneration providing the highest overall efficiency, lowest cost per MWh and low CO2 emissions.” And to these advantages can be added the ability to sell excess power “to those markets with enabling rules to encourage cogen power sales.”
This last point is clearly the key to unlocking the full potential of cogeneration. If the local utility powering the grid does not have the mechanisms in place to import excess electricity, then a significant step towards reducing plants’ overall energy bills could be lost. “There are still issues to be overcome here,” says EPRI’s Fouche, “but we are seeing an increase in the amount of power being put back into the grid. In some cases this is ‘green power,’ generated from material such as biomass, which is something the power utilities can be interested in so they can take advantage of any tax credits for renewable energy resources.” Just in the last few months, for example, states such as Vermont, Iowa, Montana, Idaho and Washington have started introducing legislation that will encourage their utility companies to look more closely at renewables.
Natural gas prices will, like any commodity, probably always be prone to the vagaries of the marketplace but chemical companies now have more options to influence the power market.