The document discusses how United Water New Jersey uses its SCADA and process control systems at its Haworth Water Treatment Plant to both optimize plant operations and participate in demand response programs to reduce energy costs. By monitoring each treatment process, United Water has been able to identify less efficient processes and reduce its kilowatt-hours per million gallons of water by 1/2% to 1%. The SCADA system also allows United Water to reduce load by up to 6.1 MW during demand response events called by PJM, its regional grid operator, helping lower United Water's energy costs. Other water utilities discussed also use advanced process control and partnerships with demand response aggregators to optimize operations while earning payments for reducing load during peaks.

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M
anagement at United
Water New Jersey under-
stands that implementing
a robust supervisory con-
trol and data acquisition
(SCADA) system at a water treatment
plant can provide more than centralized
control of processes that ensures a reli-
able water supply for customers. United
Water operates SCADA systems for
water and backup and emergency power
at its recently upgraded Haworth Water
Treatment Plant in Haworth, NJ. The
utility depends heavily upon SCADA
when shedding load during demand
response events that are reducing the
plant’s energy costs.
The Haworth plant is one example
of the growing realization among water
utility managers that process control can
do more than conserve water or ensure
its delivery. The amount of power that
some plants consume is not insignificant
and process control can optimize opera-
tions as well as energy use. Utilities that
supply their own off-the-grid backup
power for plants also need process con-
trol for this mission-critical function.
The Haworth plant was constructed
in the mid-1960s with a 60-million-
Increasing process
control intelligence
can allow a utility
to conserve water
and energy.
BY DON TALEND
CENTRALIZED
MANAGEMENT,
CONTROLLED SAVINGS
@ISTOCKPHOTO.COM/ADVENTTR

3. MARCH/APRIL 2012 WATER EFFICIENCY 35
gallon-per-day (mgd) capacity and was
upgraded into a 200-mgd peaking facility
in the late 1980s. The water distribu-
tion network also includes 13 wells, a
113-square-mile watershed, nearly 15,000
fire hydrants, and more than 2,000 miles
of water mains. In spring 2009, the plant
underwent a $100 million renovation that
improved process efficiency and water
quality and exceeds all current regula-
tions. The renovation included high-rate
dissolved air flotation (DAF) for sedi-
mentation clarification, making the plant
the largest in the nation to use DAF. The
network serves about 350,000 billable
customers and nearly 1 million people in
Bergen, Hudson, and Sussex counties in
northern New Jersey. Production usually
peaks at about 188 mgd in midsummer.
PSE&G supplies the main power
supply to the plant. PPL Electric Utilities
operates a backup power system at the
plant for United Water that consists of
four, 2-MW Caterpillar natural gas-fired
generators. Emergency power is sup-
plied by Solar Turbines. United Water
buys electricity on the next-day, hourly
Locational Marginal Pricing (LMP) mar-
ket. United Water bids and contracts for
base level quantities of gas and electric
and purchases the balance of electric on
the LMP market. United Water runs the
backup power system when gas prices
are relatively low—especially during the
summer months.
Water treatment and distribution,
as well as Solar Turbines for emergency
power, utilize a GE Proficy HMI/SCADA
iFIX system that monitors plant process-
es. A Schneider Electric ClearSCADA
system is used for remote site HMI. The
systems control pumps, chemical feed
controls, an ozone generation system,
filter controls, and a residual handling
system in the plant, and will control
system components at remote sites such
as wells, booster stations, distribution
storage tanks, pressure-reducing valves,
and regulators.
United Water is also in the process of
improving radio communications at the
remote sites and obtaining new licenses
for backhaul frequencies. The plant,
which serves as the hub of United Water’s
northern New Jersey operations, is
equipped with an operator control room
staffed by three full-time employees. They
monitor integrated data points from the
plant and PPL Electric SCADA systems.
Process control of water produc-
tion is nothing new to United Water
New Jersey. When the plant capacity was
increased, a Westinghouse distributed
control system (DCS) was implemented.
Another DCS from HSQ later replaced
the original Westinghouse system. The
GE SCADA system was implemented
during the 2009 plant renovations.
PPL Electric has a dedicated SCADA
system equipped with Modicon PLCs for
the plant’s main power supply. Accord-
ing to Chris Brophy, the resident SCADA
expert for United Water, this SCADA sys-
tem pulls together 30–40 different electric
data for water production such as voltage
and frequency for the plant operators to
monitor.
“Years ago, you basically had incom-
ing power, and that’s what you knew,”
recalls Brophy. “You didn’t know where
it was going to be consumed in the plant,
and you didn’t know what was efficient
and what wasn’t efficient in the plant.”
The new equipment in the facility,
including motor control systems and
the DAF system, “has power monitor-
ing so we can literally monitor—besides
the gross numbers coming in—each
process, so you can see
which process is a little
off, how they’re compar-
ing to each other, and
where energy is being
consumed,” says Brophy.
“You can’t manage it
unless you have the
information.”
Data are transmitted
directly from the plant
via fiber-optic/Ethernet
and from field sites to the
control room, according
to Keith Kolkebeck, engi-
neering systems man-
ager for United Water. A
reporting program from
utility technology and
management consulting provider EMA,
Inc., compiles the data for analysis.
United Water New Jersey counts
on its SCADA system during occasional
load shedding that is deemed cost-effec-
tive when natural gas prices are favor-
able. Energy Curtailment Specialists
manages a demand response program
on the grid of PJM, a regional transmis-
sion organization that coordinates the
movement of wholesale electricity in
13 states and the District of Colum-
bia. United Water has committed to a
6.1-MW load reduction at the Haworth
plant during demand response events.
“We get a two-hour notice of an
emergency event, and it can run up to
six hours,” says Brophy. “It can happen
multiple times per year, and we have two
hours to reduce load as much as we can.
We’ve usually been performing about
100 to 150% of our commitment when
required.” Kolkebeck added that some
of the plant’s larger pumps consume
significant energy and that the facility
routinely pulls 12–14 MW.
“Our peak days generally coincide
with the electric operators’ peak days,”
says Brophy of the Haworth plant’s water
production. “When it’s hot and humid
and people are running air-conditioning,
they’re also using water—the peak days
coincide almost exactly.” Because the
plant “pumps to demand,” using water
stored in tanks with some pumps pow-
ered down is not an option, he adds.
Kolkebeck says that United Water
uses the GE SCADA data to continually
monitor and control processes in the
plant. Process changes
do not involve directly
changing PLC codes,
but, rather, changing
parameters, setpoints,
and control points.
“We do pump
efficiency testing and
testing on our systems
to make sure they’re
energy efficient, and if
they’re not, we have a
maintenance program
in place to take correc-
tive action,” he says.
Brophy says that
since the plant up-
grades took place a
couple of years ago, it
appears that United Water has reduced
its kilowatt-hours by roughly 1/2% to
1% per million gallons of water. This
might improve with greater monitoring
capabilities built into the remote sites.
INTELLIGENCE-ENABLED DEMAND RESPONSE
The more intelligent a water distribution
network becomes, the more challenging
“We can literally
monitor—besides
the gross numbers
coming in—each
process, so you can
see which process
is a little off, how
they’re comparing
to each other, and
where energy is
being consumed.”

4. 36 WATER EFFICIENCY WWW.WATEREFFICIENCY.NET
it can become to shed power during a demand response event
without losing water delivery reliability. This is where further
automation of process controls can be helpful.
That is the stage of process control implementation at the
Perris, CA-headquartered Eastern Municipal Water District
(EMWD), one of the largest water purveyors in southern
California and serving a population of about 755,000 across
542 square miles. The EMWD is a major consumer of electric-
ity, at $10 million in annual electricity costs. With this in mind,
the district enrolled in a demand response program managed
by energy management consultant EnerNOC and committed
to reduce electricity consumption by about 3 MW by shedding
load at its main treatment and distribution facilities.
For doing this, EMWD receives annual payments
from EnerNOC totaling about $120,000.
Dan Howell, director of purchasing and con-
tracts for EMWD, pointed out that working with
a third-party demand response manager such as
EnerNOC is advantageous. EMWD has participated
in utility interruptible programs for the past 15 to 20
years, but the regulatory environment has changed
recently, Howell reports.
“We’re located in the South Coast Air Quality
Management District, which is probably one of the
most heavily regulated air districts in the United
States,” he says. “So we were challenged with operat-
“Our EMS looks at the best
way to operate in terms of
both meeting our water
delivery obligations, and
from a financial perspective
with regard to energy use.”
Right: Mid-Dakota Rural Water Systems’ central SCADA control
operation facility. MDRWS’ SCADA system controls and monitors
57 sites for pump speeds, tank levels, discharge pressures, and
any operational malfunctions.
Below: View of Mid-Dakota Rural Water Systems’ water distribution
network via its SCADA system
MID-DAKOTARURALWATERSYSTEM

5. MARCH/APRIL 2012 WATER EFFICIENCY 37
ing generation assets in order to meet some of the interruptible
provisions that the utility has under their programs. If you fail
to interrupt when you’re on an uninterruptible tariff, you’re
assessed large penalties and fines associated with every kilowatt-
hour you use during that interruption period.
“Aggregators such as EnerNOC don’t have penalties per se
for failure to interrupt. The economic incentive is typically less
under the third-party aggregators as it would be under the util-
ity programs, but the penalty doesn’t exist. In order to meet our
delivery obligations, third-party aggregators such as EnerNOC
became a good alternative.”
California, the nation’s most populous state, faces greater
energy supply challenges than most. To deal with the challenge,
Southern California Edison (SCE) manages programs such as
a Base Interruptible Program (Schedule TOU-BIP). Customers
that select this program are required to choose a Firm Ser-
vice Level that reflects the amount of electricity the customer
determines is necessary to meet their operational requirements
during an interruptible event. They must also choose a partici-
pation option, which is the amount of time (15 or 30 minutes)
the customer requires in order to respond
to the event.
EMWD receives lower overall utility
rates for participating in the program.
The combined reduction efforts reduce
the overall demand for electricity in
California and potentially prevent power
interruptions. Penalties are assessed to
commercial customers that do not partici-
pate when an interruptible event occurs. Customers that have
agreements with third-party aggregators, such as EnerNOC, are
not assessed penalties but merely forgo payments received from
the aggregators for non-participation in a given interruptible
event. For many organizations
—public and private water utilities, for example—determining
how to shed load without compromising core operations poses
a challenge.
Demand response, and partnering with a third-party ag-
gregator, suits EMWD because it cannot participate at all of its
facilities in every interruptible event, according to Howell. The
utility has more than 250 accounts with SCE and, in addition
to over 8 MW’s enrolled in SCE programs, can shed another 3
MW of load during interruptible events among its Hemet Water
Filtration and Perris Water Filtration plants and five other facili-
ties. Facilities with higher energy demand include its Hemet
Water Filtration and Perris Water Filtration plants, which
account for about half of EMWD’s load shedding capabilities
under the third-party demand response events. None of the
facilities that are contracted with EnerNOC have backup power
systems.
“There are challenges in meeting air regulations for operat-
ing those standby emergency generation generators,” says How-
ell. “We believe that where we do have contracts with EnerNOC,
that we have adequate water storage, and we have redundant
facilities perhaps elsewhere that can help supplement during
those events.”
EMWD operates separate SCADA systems for its water
distribution system and for its four wastewater treatment
plants; each of the latter has a dedicated system. None of the
wastewater treatment plants is managed under the EnerNOC
program. The water distribution network is equipped with a
Telvent OASyS SCADA system and a Derceto energy manage-
ment system (EMS).
The water distribution network has a relatively high level of
automation, according to Howell. EMWD monitors tank levels
and pressure throughout the system, for example, and optimizes
network operation at any given time and level of water demand.
“Not many water utilities are using that level of sophistica-
tion,” says Howell. “Our EMS looks at the best way to operate in
terms of both meeting our water delivery obligations, and from
a financial perspective with regard to energy use. It’s a real-time
pump scheduler, not a reporting system. It’s literally looking at
projected water demands throughout our service area, and then
looking at available assets to meet those demands and what it
costs to run individual assets and then optimizing which should
run first. It takes into consideration the utility rates, the time of
day, the pumping capacities, the efficiency of one pump versus
another—it’s selecting that and the speed at which to operate.”
The water SCADA system also has a
high level of sophistication for demand
response events and may soon become
even more sophisticated. When informed
of a demand response event, EMWD
staff reviews SCADA information to both
determine whether the utility can partici-
for related articles:
www.waterefficiency.net/energy

6. 38 WATER EFFICIENCY WWW.WATEREFFICIENCY.NET
pate and, if so, how to operate the network in order to comply.
“What we’re now working on is the potential to automate
that—we’re looking at working with the utility, Honeywell, and
Derceto, and EnerNOC to automate the receipt of a demand
response event from [SCE] and EnerNOC through our SCADA
system in our Integrated Operations Center to allow the staff to
make a yes/no decision to participate or not, and then resolve
how the system will operate. So there’s a hu-
man interface there. That’s the sophistication
that’s coming into play.”
The EnerNOC-managed demand
response program benefits both EMWD and
the state, Howell notes.
“[The refunds] go to directly offsetting
our operating costs,” he
says. “So to the extent
that we reduce operat-
ing costs, it benefits
our ratepayers. We are
a municipal nonprofit
water district, so any opportunity to reduce
operating costs directly affects our ratepay-
ers—this is one example of that. The benefit
to the environment and the state is that [the
program] defers the cost and the impacts of
constructing additional power generation. It is a major under-
taking in this state to construct power generation facilities.”
More water utilities in California would be able to partici-
pate in interruptible events if they can increase their process
control sophistication, Howell concludes.
“Other utilities that may not have that level of sophistica-
tion may be reluctant to participate because they just don’t know
Security Risks and Cyber Attacks
As noted in the Water Efficiency editor’s blog (“Water
Insecurity”, www.waterefficiency.net/WE/Blogs/1145.aspx), last
November, an Illinois water utility was thought to be the victim
of a foreign cyber attack. On November 8, the water utility’s
pump system failed, and initial reports indicated that utility
mangers feared the utility had been attacked by cyber criminals
hacking into the utilities network via their unsecured SCADA
system. Ultimately, the FBI and the Department of Homeland
Security (DHS) determined that the utility had not been hacked
(www.pcmag.com/article2/0,2817,2396835,00.asp).
In a statement relating to the investigation, a DHS spokes-
man stated,“After detailed analysis, DHS and the FBI have found no
evidence of a cyber intrusion into the SCADA system of the Curran-
Gardner Public Water District in Springfield, Illinois.”
Although this particular SCADA hack was just a false alarm, cy-
ber security experts warn that similar tactics could be used success-
fully in the future across a wide variety of SCADA systems; including
those used for nuclear reactors and chemical plants.
Unfortunately, outdated SCADA systems litter much of the
country’s industrial and commercial landscape. In an interview
quoted in Daily Tech (www.dailytech.com/Cyber+Attack+on+Illino
is+Water+Utility+Sparks+DHSFBI+Investigation/article23331.htm),
Lani Kass, former senior cyber policy adviser to the US Joint Chiefs of
Staff and the US Air Force, says,“Many [SCADA systems] are old and
vulnerable. There are no financial incentives for the utility owners to
replace and secure these systems, and the costs would be high.”
When initial reports of the alleged cyber attacks surfaced,
it was suggested that the perpetrators had accessed the utilities
SCADA system using stolen credentials from the SCADA software
company—a methodology that is not too far fetched according to
Dave Marcus. Marcus, Director of Security for McAfee labs, warns
that SCADA networks lack some of the security protocols common
in standard computer networks, there’s no way to know whether or
not our systems have not already been compromised.
In an interview in PCWorld (www.pcworld.com/businesscen-
ter/article/244359/water_utility_hacked_are_critical_systems_at_
risk.html), Marcus outlines some of the biggest concerns regarding
SCADA systems and suggests some preliminary precautions that
can be taken in response to this new security threat. He also recom-
mends some of the following precautions:
• Include“cyber”in all risk management.
• Set up extensive penetration testing.
• Set up extensive counter-social engineering training.
• Put a SCADA-specific CERT plan and team in place.
• Network with law enforcement at all levels.
• Expect to get attacked and take appropriate countermeasures.
The question remains, if SCADA networks represent signifi-
cant targets for terrorists or other politically motivated attacks,
are we doing enough to defend our systems? It’s difficult to
determine whether or not a cyber attack has already taken place,
but if SCADA networks are“easy targets,”perhaps it’s time to start
implementation of other, additional, security measures.
This kind of map gives
a water utility a good
idea of what and where
everything is in its
distribution system.

7. MARCH/APRIL 2012 WATER EFFICIENCY 39
what’s going on,” he says. “In this industry, we tend to err on the
side of being overly conservative when it comes to being able to
meet water supply, so without that good SCADA background,
we just wouldn’t have the information in order to make these
kinds of decisions.”
MONITORING A VAST RURAL TERRITORY
Across the often-vast distances of a rural water utility, a SCADA
system really helps out the staff by identifying problems in the
water distribution network from a computer screen, rather than
onsite visual inspection. Scott Gross, operations manager at the
Miller, SD-based Mid-Dakota Rural Water System (MDRWS),
which serves about 30,000 rural customers in 16 communities
in all or parts of 14 counties in a territory covering about 7,000
square miles, can attest to that. He is responsible for overseeing
a network consisting of about 4,000 miles of distribution pipe-
line, 115 miles of mainline, and 16 storage tanks ranging in size
from 100,000 to 2.5 mg for a total storage of 7.8 mg. The system
keeps expanding, too: the capacity of a treatment plant located
near Pierre, SD, was recently increased from 9 to 13.5 mg, and a
2-mg storage tank and 6,000-gallon-per-minute booster station
was added as well.
Gross recalled that the expansive nature of the system
meant that it took a while for a SCADA system to be fully
implemented. The treatment plant went online in 1997, but it
took until 2006 for a Micro-Comm SCADA system to cover
the entire network. MDRWS uses a SCADAview CSX (Client/
Server/X-platform) central-based (CTU) telemetry system,
a cross-platform application that has versions for Windows,
Mac OS X, and Linux. Gross and MDRWS primarily use the
system to monitor tank levels and flow rates. One major reason
why this system was chosen is the vast distances comprising
MDRWS, according to Gross. The system uses telemetry sta-
tions that compile operating data by radio signals. The system is
equipped for signal transmission across the vast spaces. Rolling
terrain on the western half of the territory does not make signal
transmission any easier, according to Harvey Aberle, whom
Gross succeeded in fall 2011. As a result, the SCADA system
uses antennas mounted on 14 water towers located throughout
the territory.
The combination of the SCADA system and VFDs en-
ables MDRWS to achieve significant energy savings, although
MDRWS had not been able to quantify the savings as of fall
2011 with the ongoing expansion of the system.
“The number one savings is that we don’t have to have
manpower go out to each station twice a week—we do that off
of SCADA,” says Aberle. “Also, some of the biggest power sav-
ings result from the fact that everything runs on VFDs. We have
control of VFDs, so we don’t have that rush of power when we
start pumps up. We can also control the speed of the VFDs, so
we know that if we have a high demand coming in for the day—
say if it’s 100 degrees Fahrenheit, we will actually start pumps
up from the central
computer here in
Miller. Or, if we know
that it’s going to be a
cold week, we turn
the speed of the VFDs
down, because we don’t need to move all of that extra water
into the tanks and not use it. I know that, to start up a pump for
the initial surge of power, with a VFD you save three times the
demand charge versus a hard start on a regular pump.”
A SCADA system is a powerful tool, but human capital is
still needed for
maintenance.
“The biggest killer for MDRWS is ice storms,” says Aberle.
“They ice up the antennas, and then we can’t communicate. The
winters here are pretty tough, and we actually take a shotgun out
and shoot the antennas clear so that we can keep communica-
tions going.”
Gross adds that the odds of damaging the antennas from
180 feet away on the ground are minimal.
“You can’t get guys up there—the ladders are too iced up,”
he explains. “You’re shooting [small] number eight shot, so
there’s a pretty small chance of breaking anything.”
A SCADA system is a necessity for monitoring such a
spread-out water distribution network, Gross concludes.
“We couldn’t run this without SCADA,” he says. “We’d
be running guys ragged without this, and it would probably
double the workload—we only have 10 operators.” WE
Don Talend is a frequent contributor specializing in technology
and innovation.
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