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.