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1. The Rapids Energy Center (left) cogeneration plant
must provide highly reliable steam at 400, 150, and 50 psi to keep the adjacent paper mill operating profitably. New fieldbus technology aids in the effort |
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| 12. Mac Bonham mans the dual-screen DeltaV PC operator workstation (above) for the new gas boilers (left), while Ray Nellis monitors the existing Provox DCS operator console (right). The DCS console also can be used to operate the gas boilers because the Provox Application Server passes data between the two systems |
The cogeneration plant at a paper mill in Grand Rapids, Minn, recently was upgraded to provide a more reliable, rock-solid source of steam for the mill’s paper-manufacturing
processes (Fig 1). The project involved decommissioning two 65-yr-old natural-gas-fired boilers, installing two new gas-fired
package boilers automated with the latest field-based process automation, and then tightly integrating the new automation with an
11-yr-old distributed control system (DCS). The DCS runs the mill’s paper machines plus the cogeneration facility’s plant master and two
retained wood-fired boilers.
The upgrade allows better coordination among the four boilers, two steam turbine/generators, and three headers supplying steam to the mill at 400, 150, and 50 psi. The process steam serves various drives, thermo-compressors, dryers, and building heat. Benefits from
the upgrade include:
- More stable steam-header pressures.
- Reduced fuel costs through more efficient boiler loading.
- Faster response to mill steam loads multi-sourced from the
boilers and from downstream pressure-reducing valves (PRVs),
turbine extractions, and turbine exhaust.
Latest automation
The mill—owned by Blandin Paper Co, a subsidiary of UPM-Kymmene, Helsinki,
Finland—features a pressurized ground-wood mill and four paper machines, and is a major manufacturer of the lightweight coated paper used by such publications as national news magazines. Its largest paper machine boasts a 311-in. trim width and 4900-ft/min speed using an off-machine coater.
The mill’s 33-MW cogeneration plant, which houses the boilers and turbines, was owned by the paper company until 2000, when it was sold to Minnesota Power Co, Duluth, Minn, and renamed the Rapids Energy Center. The sale contract stipulated that the two aging gas boilers be decommissioned and that the two new automated boilers be installed within a powerhouse building expansion. The new boilers were to more closely supplement the two existing wood-fired traveling-grate boilers. Significantly, the upgrade had to be completed within 10 months.
Minnesota Power’s Engineering Dept was given three months to design the expansion and to specify and purchase equipment. Controls development was allotted only six to eight weeks—a time crunch that led the power company to retain assistance from systems integrator Novaspect Inc, Minneapolis, Minn. For controls architecture, Novaspect quickly settled on PlantWeb, a digital plant architecture featuring Foundation fieldbus technology from its business partner,
Emerson Process Management, Austin, Tex.
PlantWeb’s DeltaV digital automation system consists of:
- A single, modular, DIN rail-mounted controller in an
un-air-conditioned field cabinet adjacent to one boiler.
- PC-based operator, application, and engineering workstations
in the powerhouse control room.
- An Ethernet network tying the controller and workstations
together.
- Foundation fieldbus technology for networking of field
instrumentation.
- Intelligent motor protection relays.
- Graphical configuration of boiler control logic.
Fieldbus instruments selected for the Minnesota Power project include Fisher valves with Fisher Fieldvue digital valve controllers, Rosemount pressure and temperature transmitters, Micro Motion Coriolis flowmeters, and several non-Emerson devices. The PlantWeb architecture was integrated into an existing Emerson Provox DCS running the paper mill, turbines, and wood boilers.
The powerhouse operator uses a DeltaV dual-screen PC workstation for monitoring and controlling the gas-fired boilers (Fig 2). He also can monitor and control these boilers from the existing DCS console. For convenience, the DCS console is most often used.
Steam sources
Even a simplified one-line diagram of steam flows illustrates the complexity of the
control task (Fig 3). The four boilers each produce approximately 200,000 lb/hr of superheated steam—the high-pressure (h-p) wood-fired boilers at 1250 psi, 900F, the new low-pressure (l-p) gas-fired boilers at 400 psi, 670F. Total mill and cogeneration plant steam demand can be as high as 500,000 lb/hr.
The h-p boilers feed a 17-MW non-condensing turbine-generator. They also serve a turbine bypass PRV that supplies 400-psi steam to both a 16-MW l-p condensing turbine-generator and the 400-psi mill header. That header is additionally served by extraction steam from the h-p turbine.
The two new water-tube boilers directly feed the l-p turbine and the 400-psi mill header. The 150- and 50-psi headers are served by combinations of extraction steam, additional turbine bypass PRVs, and h-p turbine exhaust.
The mill is king
The plant-master control algorithm, which resides in the DCS and takes into account operating priorities and economics, was enhanced to select which on-line steam sources would be the most cost-efficient for particular combinations of mill and turbine loads and fuel costs.
Some of the factors considered by the algorithm’s strategy are:
- To maximize paper output (the site’s most valuable economic
activity), the mill has first priority on steam. Turbine/generator
production is sacrificed if necessary to support surges in mill
header demands. Under normal conditions, however, both turbines
operate at their maximum outputs to minimize purchased power costs
and maximize available extraction and exhaust steam. The
generators, whose only load is the mill, provide at full output
80% of the mill’s electrical needs. The shortfall is purchased
from the Minnesota Power grid.
- The h-p wood boilers are the base steam source and are loaded
to the maximum. The h-p turbine’s 1250-400-psi bypass PRV is
normally closed, with headers maintained by turbine extraction and
exhaust alone. Extraction is more efficient than a PRV.
- Because wood and bark waste trucked from local sawmills is the
least expensive energy source, it is the primary h-p boiler fuel.
Coal supplements these boilers if wood alone cannot maintain steam
pressure. The h-p boilers have been running a 90% wood/10% coal
mixture, with about 1000 tons of waste wood consumed per day.
- The new l-p gas boilers contribute steam only if the wood
boilers cannot meet mill and turbine loads, or if a wood boiler is
off-line. The algorithm states that if a wood boiler, the h-p
turbine, or the 1250-400-psi PRV reaches maximum output, a gas
boiler will be brought on-line as a peaking unit in swing service
to meet steam demand.
- Should natural gas become less expensive than coal,
supplementing the wood boilers with coal will cease, steam from
these boilers will be portioned to assure maximum h-p turbine
output, and the gas boilers will pick up unmet 400-psi header and
l-p turbine loads. With recent high gas prices, the gas boilers
were idle most of last summer, although one was occasionally
maintained at minimum steam flow for quick response should a wood
boiler fail. During the winter, one gas boiler was needed to help
meet building heating loads.
Efficient communications
To maintain rock-solid header pressures, the new boiler automation system must
communicate quickly and transparently with the plant master in the DCS. Communications are accomplished using a Provox Application Server (PAS)—a combination PC hardware/software solution for automatically configuring data flow in both directions and for enabling DCS screens to operate DeltaV control modules. The PAS resides on the new automation’s Ethernet network and taps into the DCS’s data highway.
The PAS has prolonged the life of Rapids Energy Center’s legacy DCS by permitting the DCS to be quickly and cost-effectively expanded by adding the fully scalable, field-based automation. The server-to-server PAS solution is faster to develop, less engineering-intensive, and more capable than serial links, hard
wiring, or an OPC bridge. Hundreds of points, including error messages and tuning parameters (the latter handled appropriately for the system they are viewed on) were configured in minutes. Because the PAS does not support commands, several hard-wired analog input/output (I/O) circuits were necessary for raising and lowering gas boiler output.
In the future, Minnesota Power expects to switch the plant master and h-p boiler control to the new automation, leaving the legacy DCS for mill control only, and splitting the ownership of the two control systems at a more natural point.
Company-wide historian. An additional advantage of the new
automation system is its built-in PI historian, supplied by OSI
Software Inc, San Leandro, Calif. PI is Minnesota Power’s standard
generation historian for assisting dispatchers and power marketers.
The legacy historian used by the DCS in the Blandin mill—and
formerly used in the cogeneration plant—is paper-industry-oriented
and not feasible for integration into Minnesota Power’s corporate
system.
The new PI historian captures data from the gas boilers, as well
as relevant data in the DCS. In fact, much of the data from the DCS
passing through the PAS is intended for the new historian. All
cogeneration plant historical data will soon be uploaded to a
Minnesota Power central PI server.
Fieldbus speeds installation. On the back-plane of the gas
boilers’ modular controller are dual-redundant CPU and power supply
cards, three Foundation fieldbus cards having two H1 segments each,
six 4-20-mA analog I/O cards, and a serial communications card. The
burner management system is separately hard-wired.
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3, 4 . Bonham checks an instrumentation stand for
Rosemount fieldbus transmitters adjacent to one of the package
boilers. The yellow fieldbus spur cables terminate in the H1
fieldbus segment brick (visible on the right side of
inset) |
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A total of 56 bus-powered fieldbus instruments are distributed
over the six H1 fieldbus segments (Figs 4, 5). One fieldbus card is
dedicated to each boiler, while the third card is common to both.
All PID and operating logic takes place in the controller; none is
distributed to field devices.
Fieldbus instrumentation was selected over conventional analog
versions primarily to save time, although overall costs later proved
to be lower. Less wiring and conduit were needed, and commissioning
and calibration proved to be approximately twice as fast. An ongoing
benefit to operators is the large amount of device status and
condition information available.
The controller’s analog cards serve several instruments not
available in fieldbus, as well as inputs from a continuous emissions
monitor, the commands from the DCS, and several on/off devices that
were later fitted with positioners. The latter include flue-gas
recirculation dampers that now permit percent-open settings to be
established from the control room, and startup vent valves whose
flows can now be adjusted to protect the superheaters.
Boiler
configuration
The systems
integrator, Novaspect, used an in-house-developed boiler control
package plus the boiler manufacturer’s P&IDs to quickly and
graphically configure the new gas units.
The package consists of standard and derived function blocks in
the IEC 61131.3 Function Block Diagram language that are assembled
to manage combustion, fuel/air ratio, excess air trim, three-element
drum level, feedwater pumps, steam pressure, forced-draft fans, etc.
The boilers have no induced-draft fans, and the only common
components between the gas- and wood-fired units are the condensate
pumps.
Minnesota Power plans to add a simple, automatic, feed-forward
notification system that will tell the cogeneration plant operator
when a surge in the mill’s steam demand is expected. The operator
will then be able to temporarily overstoke the boilers and raise
turbine backpressures to make more steam available for the mill
headers.
Notification will come from an alarm triggered by vacuum being
applied to a paper machine press, an indication that a sheet is
about to be pulled across the press and that demand for steam by the
dryer will soon soar. If two paper machines at the same time signal
that press vacuums are being pulled, the operator could call the
mill and ask that one machine be delayed for 20 minutes or so.
Currently, notification by the mill of impending steam loads is only
by phone, and is often forgotten by mill operators.
With typical boiler control systems, open/close commands to
relays operating 2400-V switchgear powering large motors are
transmitted over hard-wired connections. For the new boilers,
Minnesota Power chose intelligent electronic relays from Schweitzer
Engineering Laboratories, Pullman, Wash, that communicate with the
DeltaV controller via high-speed, full-duplex, RS-485 serial link
using the open Modbus data representation in a multi-drop
configuration. Modbus technology was supplied by the Automation
Business, Schneider Electric, North Andover, Mass.
The only hardwiring is for emergency-trip push buttons on the
face of the switchgear. The relay installation consists of six motor
protection relays (for three boiler feedwater pumps, two
forced-draft fans, and one spare) and one overcurrent relay for the
switchgear feed.
By going digital, wiring costs were drastically cut and operating
information from current transducers and nearly 30 other points plus
some 25 alarms are transmitted to the operator. This information
provides a very good picture of the status and health of these vital
motors and their power source.
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