Best Practices for Cogeneration System Operation

Jim Schettler1,

Nancy Andrews* 1

1Brown and Caldwell *Email: nandrews@brwncald.com

ABSTRACT

As more and more water resource recovery facilities (WRRFs) design and operate new biogas utilization systems it becomes crucial to share the best operating practices for the cogeneration and gas treatment systems. The intent of implementing best operating practices is to (1) maximize the electrical and natural gas energy cost savings via increased engine output per unit of gas and engine uptime, (2) minimize operations and maintenance expenses that erode net energy cost savings, and (3) reduce biogas flaring.

The objectives of this study are to:

• Identify key maintenance activities that maximize engine availability and electrical production

• Suggest operating strategies to maximize electrical savings

• Share plant operator’s perspective on key aspects of system design to help provide more operator-friendly designs

• Consider staffing and training practices that contribute to operating success

KEYWORDS: CHP, cogeneration, biogas, operations, maintenance

INTRODUCTION

Although CHP systems have substantial potential to recover valuable energy and reduce WRRF costs, plant operations and maintenance (O&M) procedures must be optimize to achieve these benefits. As one plant engineer that we spoke with for this study succinctly stated, CHP systems are “expensive to operate and hard to operate well”.

Operating data and standard maintenance procedures from 15 well-run cogeneration facilities of various age, types and sizes were compiled via survey in order to capture the industry’s best operating practices. The key features of the plants surveyed are summarized in Table 1. Survey topics included practices related to mechanical maintenance, design features to facilitate best operating practices, and overall management of the digester gas production and cogeneration systems. The intent of this survey was to increase implementation of operation and maintenance best practices and to disseminate design details that will reduce maintenance headaches in new systems.

The following concepts were considered by plant staff in our survey to be the most critical to system success. These concepts will be discussed in further detail in the following sections.

• Observation of critical operating parameters and constant attention to changes – “Watch Everything All the Time!”

• Biogas Treatment to remove hydrogen sulfide (H2S), moisture, and siloxanes

• Continuous and thorough drainage of condensate moisture from biogas piping and vessels to avoid freezing and other operational issues

• Appropriate frequency of meaningful maintenance, including oil changes, spark plugs, and overhauls

• Good controls, including a heavy emphasis on automatic operation of all components

• Support from utility staff with specialized training and qualified local equipment representatives

• Steady operation of system, from digester feed to biogas flow and engine loading

Table 1. Surveyed Plants

Utility and/or

Plant Name,

Location

Current

Average

Plant

Flow

(mgd)

Biogas Use Prime

Mover

Current

Installed

Generation Unit

Capacities, kW

Year of

Installation for

Current

Operating

Equipment

(Approximate)

Central Valley Water Reclamation, Salt Lake City

60 IC Engine-Generators (5) 1300

Waukesha 1986, 2003 1

Des Moines, IA 45 IC Engine-Generators (3) 600 Superior

(2) 1400 Jenbacher

1988, 2014

Encina WRF, Carlsbad CA

36 IC Engine-Generator (4) 750

Caterpillar 2008 1

Eugene Springfield MWMC, OR

35-45 IC Engine-Generator (1) 800

GE Jenbacher 1997

Gresham, OR 12 IC Engine-Generators (2) 395 Caterpillar

2005, 2014

Hampton Roads Sanitary District, Atlantic Plant, VA

25-30 IC Engine-Generators (2) 1100 Cummins

2013

LOTT Clean Water Alliance, Olympia, WA

12 IC Engine-Generators (1) 335

GE Jenbacher 2010

L.A. County Sanitary District, Carson Plant

300 Gas Turbine Generators (3) 9000

Solar Mars 90 2000

Madison Metropolitan Sewer District, WI

40 (2) IC Engines and (1) Engine-driven Blower

(2) 475 (1) 500 hp Waukesha

1990

North Davis Sanitary District, Syracuse, UT

23 IC Engine-Generators

(2) 550 (1) 923

Waukesha (2) 1100

Cummins 2

1986, 1996, 2015 2

Environmental Services, City of Portland, Columbia Blvd.

66 IC Engine-Generators (2) 750

Jenbacher 2008

Racine, WI 20 Engine-Driven Blowers (2) 426 hp (1) 675 hp Waukesha

1992, 1997

Laguna Treatment Plant, Santa Rosa, CA

18 IC Engine-Generators (4) 1100 Cummins

2013 1

Sheboygen, WI 18 Microturbines (10) 30 (2) 200

Capstone 2006, 2010

Steven’s Point, WI

3 IC Engine-Generator (1) 180 MAN

2012

1 These plants have replaced older cogeneration equipment and are now operating a newer system. 2 Currently being installed

BIOGAS TREATMENT

Due to changes in biogas contaminants and the use of more complex and demanding engines, over the last ten or fifteen years gas pretreatment systems to remove hydrogen sulfide, moisture and siloxanes have become almost standard components of cogeneration systems. This change was driven by the need to remove siloxanes which in turn mandated H2S removal to protect the siloxane removal systems. Both the Eugene/Springfield and Madison plants have added biogas treatment to their existing CHP systems, and note a dramatic improvement in engine reliability. As an example of the maintenance benefit of these systems, the Eugene/Springfield plant was able to reduce their head replacement frequency from one year to 20,000 hours and reduce the frequency of oil changes from around 700 hours to 2500 hours following the addition of gas treatment equipment.

In order to maintain the effectiveness of these systems, regular maintenance such as media replacement must be performed. The replacement frequency must be optimized to minimize media costs while maintaining adequate fuel quality to avoid engine damage. Effective monitoring techniques are required to support this optimization.

Newer, high efficiency lean burn engines have more stringent biogas quality requirements than older, rich-burn engines. Table 2 summarizes the gas quality requirements published by some of the major IC engine and gas turbine suppliers.

Table 2. Cogeneration System Manufacturer’s Fuel Gas Specifications

Sulfur

Content

H2S

Siloxanes Moisture Liquid

Condensate

(droplets)

Fuel Gas

Temperature

Cummins Class A 3

12.9 ppm 0.52

ppmv as Si

80% None 5-50°C (41-122°F)

Cummins Class C 3

600 mg/Nm3CH4

12 mg/Nm3 CH4

80% None 5-50°C (41-122°F)

GE Jenbacher 700 1 Based on Si detected in Engine Oil

<50% with carbon treatment

None <40°C

Caterpillar 60 mg H2S/Btu

0.60 mg Si/Btu

<80%, at minimum temperature

None -10 to 60°C (50 to 140°F)

Caterpillar/MWM 2200 mg/10kW

<20 mg per 10 kWh

<80% at lowest temperature in piping system

- 10-50°C

Solar Turbines 3,000 ppmw as H2s

5 2 to 10 mg of SI per Nm3

of CH4

Gas temperature 20°F greater than dewpoint

None Minimum set by dewpoint. Maximum 93°C (200°F)

Capstone Microturbine

5,000 ppm as H2S

10°C (18°F) greater than dewpoint, <5% by volume

None Minimum set by dewpoint. Maximum 50°C (122°F)

1 Fuel specification without exhaust gas catalytic reactor on exhaust 2 Mercury 50 turbines 3 Cummins biogas quality grades

Hydrogen Sulfide Removal

The benefits of good hydrogen sulfide removal include:

• Avoiding acidification of oil

• Avoiding oil lubricity reduction

• Minimizing piping and equipment corrosion and bearing damage

• Reducing corrosion and deposits in exhaust gas heat recovery units formed when temperature is below acid dew point (Figures 1 and 2)

Figure 1. Ceramic deposits formed on exhaust heat exchanger as exhaust gas temperature

falls below acid dewpoint (Farrand, 2011)

Figure 2. Sulfur-based corrosion and deposits (Farrand, 2011)

In surveyed plants, H2S system media replacement frequency varied from 3 months to one year. H2S media replacement tends to be much more labor-intensive than carbon media replacement. After a long service period, the media can become cemented together. The Madison plant has set a maximum media replacement interval (with regeneration) of 14 to 15 months because media in service longer than this period required jackhammering to remove.

Iron sponge media longevity is extended at plants that add ferric to their digesters. However, the iron sponge dose and chemical cost increase steeply for removal to low H2S levels required for optimum engine operation.

While H2S removal equipment plays a key roll in engine longevity and reliability, many plants expressed frustration with the reoccurring expense of iron sponge media replacement. The surveyed plants identified several strategies for reducing the cost of H2S removal:

• Regenerating Media. The Madison and Eugene/Springfield plants have found that their iron sponge air injection system works well to prolong media life, with 1.3% air added to the biogas stream.

• Alternate Media Sources. Some plants have tried procurement of media from alternative supply sources, some with mixed results.

• Bioscrubber Pretreatment. The HRSD Atlantic plant is pleased with the bioscrubber they use to pretreat the biogas flow. This system reduces the H2S concentration to near zero, essentially eliminating the need to replace the downstream iron sponge media.

• Ferric Chloride Addition. The CVWR plant adds 12 gallons per hour of ferric chloride to their digester and does not have further downstream biogas treatment of H2S.

Monitoring for Hydrogen Sulfide Media Replacement

Hydrogen sulfide concentrations will begin to drift up as the treatment media is depleted. Surveyed plants most often use grab samples on a weekly or monthly basis to detect this increase in H2S concentration and the need to replace hydrogen sulfide treatment media. Grab sampling is done with either hand-held mine safety devices or Draegger tubes. Two plants also used on-line H2S monitors, but tended to use grab samples to verify the validity of the on-line sensor data. As an example, the NDSD plant uses an increase in iron sponge outlet concentration to 100 ppm as the cut-off to trigger media replacement.

A few plants mentioned that they had experienced occasional episodes of very short iron sponge media life that they suspected were due to media quality issues, with high outlet H2S concentrations detected after only a few weeks. Frequent H2S monitoring is needed to detect these issues promptly.

Moisture Removal

Although H2S and siloxanes get most of the attention in biogas treatment, moisture removal is also important since digester gas is saturated with moisture. This moisture condenses profusely as it cools from digester temperature (37°C /98°F) in piping and biogas treatment vessels. As indicated in Table 2, all of the engine manufacturer’s gas specifications also require that no water droplets are present in the biogas to the engine and that the fuel gas is less than saturated.

Gas condensation can form at pipe walls and equipment dead zones during cold weather, even though the bulk gas temperature it higher than the dewpoint, as illustrated in Figure 3. In addition to potentially damaging the engine, moisture collects in any low spots and was mentioned repeatedly by plant staff as an operational problem, both for quantity of drainage and potential for freezing.

Figure 3. Cooling of gas temperature on pipe walls causes condensation in cold weather

Moisture removal via chilling improves siloxane removal carbon bed life since adsorption capacity on activated carbon decreases at excessive biogas humidity and with increasing biogas temperature. Dry biogas also minimizes moisture problems in downstream fuel piping and reduces engine corrosion.

Most plants, such as the Eugene/Springfield facility, have found monitoring the biogas temperature leaving the cold heat exchanger to be the most reliable way to monitor the effectiveness of their moisture removal systems and alarm system failures. The Madison plant also mentioned that they have chiller status alarms. The LOTT biogas treatment system was furnished with a relative humidity monitor, but this sensor has not been reliable.

Siloxane Removal and Particle Filtration

Few operational difficulties were mentioned in the survey related to carbon systems for siloxane removal.

Most biogas treatment systems include particle filters downstream of the siloxane removal vessels. The plants surveyed reported that they found over time that these filters were always clean and the cartridges did not need replacement. However, the Eugene/Springfield experienced an overflow of their carbon media, which was retained by the downstream particle

filter. They have addressed this issue by reducing the depth of the carbon media in the vessel slightly and installing a screen on the vessel discharge.

Monitoring for Siloxane Treatment Breakthrough

Clean activated carbon media will absorb siloxanes starting at the lowest contact layer. As the carbon is used, the active layer moves up the vessel until the top layer is used and breakthrough occurs. As such, it is important to watch for siloxane breakthrough, either via gas-phase siloxane sampling, frequent oil testing for silicon (Si), or both.

Gas-phase siloxane measurements require off-site analytical work, so plants typically monitor siloxanes much less frequently than H2S. Siloxane laboratory analysis is somewhat costly. For example, the Sheboygan plant samples for siloxanes on a quarterly basis and reports annual expenses of $3000 to $3600 for laboratory analysis. The siloxane sampling frequency reported by surveyed plants varied from monthly to annual. Quarterly sampling can help detect seasonal changes in siloxane concentrations.

Most surveyed plants also monitor siloxane removal by observing the Si values in their lube oil tests. Some plants, including the CVWR facility, use frequent oil sampling for silicon to detect the need for carbon replacement.

The Sheboygan microturbine facility has recently shifted from routine 80 day carbon replacement to a replacement cycle based on treated biogas volume. They have slowly ramped up their replacement cycle period, testing for siloxanes prior to each media change to detect whether the quantity of biogas treated was large enough to cause breakthrough. Thus far, they have extended the media change cycle to approximately 18 million cubic feet of treated biogas, significantly increasing the time between carbon replacements.

Design Features to Facilitate Siloxane Media Replacement

Most plants used vacuum trucks to remove spent carbon. For refilling the carbon, many plants used a fork truck to lift a pallet of 23 kg (50 pound) carbon bags or super sacks, and then transferred the contents of the bags by hand.

The Sheboygan plant conducts frequent carbon media changes due to the strict biogas quality required by the microturbines. The Sheboygan plant, as well as the Stevens Point plant, have purchased vacuum systems for $5500 as shown in Figure 4, eliminating the cost of hiring outside vacuum truck contractors for media changes. The vacuum system connects to the bottom of the siloxane vessel. A compressed air connection is under consideration to fluidize the media during the vacuum operation.

Figure 4. Plant-purchased vacuum system used for removing carbon media (Shebogan

Regional Wastewater Treatment Facility)

Annual Biogas Treatment Costs

Annual biogas treatment costs vary significantly from plant to plant. H2S media costs appear to be typically higher than carbon expenses. Based on limited data collected in this survey, biogas treatment costs can be 50-75% as high as engine maintenance costs.

ENGINE MECHANICAL MAINTENANCE

Lube Oil Management

The right type of engine oil must be used to suit the specific operating conditions found in WWRF CHP systems. Low ash oil was used by most of the surveyed plants. Low ash oil is particularly critical for engines with any exhaust catalysts.

The appropriate oil change frequency varies with biogas treatment and engine load. Similar to biogas treatment maintenance, oil change frequency must be scheduled to minimize engine component damage while controlling engine outages and maintenance expense. Usually oil change intervals are reduced if the biogas contains H2S, per the manufacturer’s guidelines.

Weekly or biweekly off-site lube oil laboratory analysis provides an inexpensive means of fine-tuning the oil change frequency based on actual conditions such as the quality of biogas

treatment and engine wear. Oil analysis will alert operators to changes in critical parameters that should be used to trigger oil changes and sometimes biogas treatment media replacement, including:

• Sulfur

• Silicon

• Total Base Number (TBN) and Total Acid Number (TAN)

Of the plants surveyed, reported oil sampling frequency varied considerably, from 250 hours to 2000 hours, with testing sometimes done coincident with oil changes.

Manufacturers often recommend 1000 hour oil change intervals, with the recommended frequency adjusted in accordance with oil sample laboratory results. Several plants now operate within the EPA requirements for 1440 hour oil changes. Of the plants surveyed, oil change frequently varied from 600 hours to as high as 4000 hours, with most plants in the 720 to 2000 hour range.

Best Practices for engine lubrication include:

• “Keep it hot”. Engine lube oil heat exchanger cooling water loops should also be kept above 77°C (170°F) since the engine works better with hot oil. An engine lube oil heater also helps minimize condensation in the oil, especially with oversized lube oil filters which allow the oil to cool off.

• Use a pre-lube pump on engine start-up to minimize friction on cool engine parts, and minimize wear associated with start-up.

• Follow manufacturers oil filtration guidelines

• Immediately repair oil leaks to avoid low oil pressure conditions

Spark Plugs

Many plants replace or maintain spark plugs during lube oil replacement shutdowns, with most plants reporting spark plug replacement at 1400-2400 hours.

Routine spark plug replacement is essential but costly, with survey respondents reporting spark plug costs ranging from $100 to $526 per plug, typically with 16 plugs per engine. A few plants have tried various strategies to reduce spark plug replacement costs:

• The Encina plant extends the life of their spark plugs by cleaning them in a commercial ultrasonic cleaner, followed by regapping.

• The Eugene/Springfield plant has found that their plugs last longer if they run at a lower voltage, so they run at 25,000 to 30,000 kW in lieu of the recommended range of 30,000 to 35,000.

Special Tools

There are several specialized tools used for overhauling and adjusting engines and other biogas utilization equipment. The Eugene/Springfield plant staff mentioned the following tools as “must-have” items that were purchased from the engine supplier following construction:

• T-handles for picking up heads

• Oil tube alignment tool

It is possible to purchase these tools with the initial cogeneration equipment purchase. Available tools should be reviewed during the development of design specifications. If the equipment is procured competitively, pre-purchase of these tools can save costs, as well as maintenance staff time.

Several plants have designed tools needed for overhauling the engines, adjusting fuel gas regulators, and other components. The lead engine person at the Des Moines plant has designed over 20 different tools to help operate, clean, adjust, replace, or fix various types of machinery in support of the engines, biogas system, and waste heat system. The CVWR lead indicated an even larger number of custom tools.

As an example, a tool was developed by the Eugene/Springfield plant for use with a vacuum system to clean their exhaust heat recovery units in order to minimize engine backpressure and maximize heat recovery, as well as another tool to disassemble the carburetor fuel gas mixer to avoid damaging the gear motor.

Other Maintenance

• Engine Coolant Water Treatment. Ongoing monitoring and control of engine coolant water treatment is necessary to minimize scaling and corrosion which can degrade engine cooling capacity.

• Parts Cost and Availability. CVWR staff have occasionally traded spare parts with another WWTP as a means of addressing parts availability. Other plants have been unable to pursue this avenue because they are not aware of similar operating engines.

• Head Replacement. Similar to other maintenance functions, head replacement frequency varies with gas quality. The Encina plant, with no siloxane removal, had the shortest interval for head replacement at 8,000 hours. Most plants replaced heads at intervals between 25,000 and 40,000 hours.

• Major and Minor In-Frame Overhauls. Many of the survey respondents rely on local manufacturer’s authorized service personnel for major and minor overhauls. The Encina plant staff mentioned that they worked with their service contractor to develop a detailed scope for the overhauls in order to ensure that the plant and service contractor have a mutual understanding of the work to be done. The Eugene/Springfield, NDSD, CVWR plants perform overhauls themselves.

Reported O&M Costs

Reported O&M costs for IC engine-generator installations were generally in line with conventional assumptions of $0.015 per kWh, with lower costs for older, less complex rich burn engines.

Madison plant staff also noted that operating costs due to parasitic electrical loads for hot water pumps, radiator fans, chillers, and gas blowers have been somewhat higher than expected. They also noted that engine efficiency was somewhat lower than expected at their 1990 start-up due to biogas higher heating value (HHV) used for electrical output efficiency projections in lieu of proper lower heating value (LHV).

Figure 5. Racine Engine Room

Gas Turbine Maintenance

Large gas turbine installations have very different maintenance concerns than IC engine-generator system, although the overall cost of maintenance reported by the LA County Sanitation District was approximately similar to the conventional cost reported for newer IC engines.

This plant reported an oil changes frequency of 5 years using synthetic oil. The LA turbines are overhauled every 35,000 to 45,000 hours of operation.

One of LA’s most significant operating difficulties is keeping their exhaust heat recovery unit from fouling with siloxanes, since the biogas system includes venturi scrubbers and cooling coils, but does not include carbon or other additional siloxane removal provisions.

OPERATING STRATEGIES

Several plants mentioned operating strategies that they have found to improve the reliability and cost-effectiveness of their CHP system.

• Steady and Nearly Continuous Engine Operation. A key challenge faced by WRRF cogeneration facilities is matching engine loading to fluctuating digester gas production rates. If properly operated, gas storage can dampen production fluctuations and stabilize engine operations, and steady codigestion feed can be used to keep digester gas production even. This operating strategy has been found by the Sheboygan facility to be particularly important with microturbines to avoid bearing wear and premature failure. LOTT staff also stated that shutdowns of their IC engines tended to result in issues when re-starting, which are minimized by keeping the engines running. Similarly, the Eugene/Springfield plant has also found that too frequent engine adjustments often lead to difficulties.

• Minimizing Wear due to Engine Start-ups and Shutdowns. Engine start-up, especially from cold conditions, stresses the engine and causes wear of major mechanical components. Some of this stress and wear can be minimized if engines are specified with prelube oil pumps and jacket water and oil heating systems.

• Natural Gas Blending for Peak Hours. The Encina plant maximizes their electrical savings by completely disconnecting from the grid during peak electrical demand hours. During this peak period the plant supplements their biogas supply with natural gas to increase power production as needed to meet the plant load. This operating mode was particularly valuable during a recent grid blackout, and generates $1 million dollars in electrical bill savings per year. During off-peak hours the engines run on biogas alone and the plant reconnects to the grid.

• Cogeneration Feed to Bias Electrical Production for On-Peak Hours. In some cases, FOG and high strength waste feeds can be increased during peak hours in order to produce more biogas and electricity. Other biogas storage strategies can also be used to bias cogeneration toward on-peak periods. The Madison plant formerly used this strategy with whey addition to their digesters.

• Minimizing Outages that Increase Demand Charges. The HRSD Atlantic plant has worked diligently to develop a procedure to restart engines following an outage with their 30

minute demand window. The NDSD and Sheboygan plants schedule maintenance outages during non-peak hours to minimize demand charge impacts. Other plants cluster maintenance activities so that only one outage is required for oil changes, spark plugs, and biogas treatment media replacements. The Stevens Point and HRSD plants run their emergency generator to keep their demand costs low during maintenance outages.

• Operating Oil Temperature. Keeping the engine oil temperature around 88 degrees C (190°F) is important to keep the lubricating system at its optimum performing condition. Some plants may consider operating at lower temperatures in order to recover heat at temperatures suitable for digester heating, e.g. 63-71°C (145-160°F), but this operating condition shortens engine life and increases engine servicing and maintenance. Lube oil heat exchanger cooling water should be kept above 77°C (170°F) in order to maintain the desired temperature.

• Lube Oil Heating during Shutdowns. Adding an engine lube oil heater also helps minimize condensation in the oil and speeds start-up. This is particularly true with oversized auxiliary lube oil filters.

• Operating Coolant Temperature. Keeping the engine jacket temperature as hot as possible is important to avoid corrosion due to hydrogen sulfide, primarily in the heat recovery exhaust silencer and bearings.

• Balancing Air Emissions Requirements with Engine Electrical Efficiency Trade-Offs. Depending on regulatory circumstances, some sacrifice in engine efficiency might be required to meet nitrogen oxide (NOx) permit limits. Cogeneration designers and plant staff must determine what engine tuning settings best meet their environmental and energy objectives. A couple of plants reported using their own portable NOx sensors to make occasional tuning adjustments to monitor emissions and tune engine efficiency.

• Engine Loading (100 vs. 80-Percent) to Optimize Engine Efficiency and Maintenance

Requirements. Older engines were often operated at 80 to 85-percent load because operators perceived that underloading the engines reduced maintenance issues, and because older natural aspirated rich-burn engine could not develop full output with low-Btu digester gas fuel. Newer engines are turbocharged and designed to operate continuously at 100-percent loading and they reach their highest efficiency at this operating point. If sufficient digester gas is available, operating at or near 100-percent load can increase electrical output and fuel efficiency. Alternatively, natural gas blending equipment can often be used to achieve consistent 100-percent loading while minimizing gas flaring.

CONTROLS AND AUTOMATION

Previous reliability studies (Brown, 1992) have found that controls are the leading cause of engine-generator outages for natural gas engines. Feedback from the CHP survey suggests good control systems are also essential for biogas systems. Several of the utilities surveyed, including the Racine plant indicated that reliable control systems were the most helpful aspect of their CHP design. The following specific control and automation features were mentioned by plant staff, either as items that were useful or could be improved in their installation:

• Flexibility for Future Operating Conditions. As and example, the HRSD biogas booster blowers were initially programmed to allow only one of the two installed gas blower to be selected. Additional programming was required to allow HRSD biogas blowers to be operated in alternating or parallel modes.

• Automatic Starting. The survey found variations between plants in the degree of engine generator starting sequence automation, including variations for starting cold engines vs. restarting warm engines. HRSD would have liked an automatic starting system sequence in order to ensure that engines could restarted and back on line after an outage within their 30-minute demand window.

• Ignition Monitoring. Ignition system performance can be monitored via ignition voltage or cylinder temperature, but these monitoring features are not always included on the engine skid. For example, the LOTT facility prolongs cycle time between spark plug changes by using ignition voltage monitoring, while the Gresham plant stated that they would like to have this capability.

• Paralleling Coordination with Plant Grid. The Des Moines plant installed new cogeneration engines for use in conjunction with their older engines. The two new engines apparently did not include sufficient communicating devices with the switchboard to allow starting engines to match the other operating engines.

• Remote Diagnostic Monitoring. The LOTT plant and other plants have found that having their control systems networked with their local engine suppliers for troubleshooting technical issues is one of the most helpful aspects of their system.

DESIGN FEATURES

During design and procurement, utilities and engineers have the opportunity to incorporate several features that will pay dividends in reduced staff time and increased run time over the life of the equipment. In addition to the important control features mentioned previously, CHP design teams should pay close attention to the following details and lessons learned from surveyed plant staff:

• Iron Sponge Vessel Access. Iron sponge media can be difficult to remove, especially with common 3-foot access hatches. The Eugene/Springfield plant has found that it can only access and remove part of the iron sponge media via their hatch, indicating the need to consider vessels that allow removal of the entire vessel cover. However, for large systems, such as the 12-foot diameter Sacramento installation, full cover removal is not practical due to the number of bolts and danger of warping during removal.

• Biogas Treatment Weatherization. Many, if not most, gas treatment systems are installed outdoors in order to minimize costs associated with new or adapted buildings, but this design was not well-liked by survey respondents (similar to Figure 6). In cold or inclement climates this can lead to a significant impairment in operations maintenance, including freezing of accumulated moisture or difficulty with explosion proof heat tracing. Several plants, including the Madison plant expressed frustration with operating outdoor systems, and has installed barriers to at least block some of the wind. Designers should carefully consider whether an indoor location is feasible, or at least provide some permanent shelter to mitigate wind and minimize snow accumulation.

•

Figure 6. Outdoor biogas treatment system components, Columbia Blvd plant, Portland,

OR

• Cold Weather Chiller Operation Chillers are generally designed for air conditioning applications that operate during warm weather. Since chillers used for moisture removal operate year-round, cold weather operation can negatively affect chillers. The Des Moines plant has addressed this issue by routing warm room air exhaust to the chiller’s condenser zone in the winter.

• Biogas Moisture Drainage Systems. Many plants mentioned difficulties with insufficient drainage of moisture from system components upstream of the moisture removal system. For example, the LOTT plant found that they had to add manual valves in parallel with their auto-dripper units because the auto-drippers would not keep up with the condensate formed in cold weather, and freezing had occurred. Temporary insulation is also added to the bottom of the tanks in winter months to avoid freezing. Similarly, the HRSD Atlantic Plant had to modify their bioscrubber system to handle the high flow of condensing biogas moisture. Even downstream of the moisture removal system, drains are important in the siloxane system since cold ambient temperatures will continue to cool the gas below its dewpoint, as noted by LOTT staff.

• Chiller Quality. Chillers for moisture removal systems fall in a size range that overlaps with commercial equipment. This equipment can be cost-effective, but will have a shorter life than other system components. The life can be extended by specifying the chiller with coating on all interior and exterior copper components. Un-named “Plant A” noted that they wished their chiller equipment was more robust, and the Sheboygan plant experienced corrosion in a location exposed to dewatering equipment atmosphere.

• Lube Oil Make-up System. Engine systems are designed to consume a certain amount of oil during operation. For example, the still new 1100 kW HRSD Atlantic Plant engine-generator consumes 1 gallon per day, while other plants can use 6 gallons per day or more. The CVWR plant, with much older engines, suggested that a larger oil storage tank size would be helpful to reduce their staff time for filling the tank. New systems should be designed with ample make-up oil and waste oil storage to allow for future expansions and reduced maintenance attention.

• Lube Oil Make-up System Automation. According to HRSD plant staff, their engine skid appears to have some features that could be used to automate the replenishment of this oil, but it lacks the high/low oil reservoir sensors that would be needed to remotely monitor or automate this function as they would like. Ren lube oil systems are available to perform this function.

• Waste Oil Handling and Storage. As noted previously, frequent oil changes are critical to reliable operation, so waste oil is generated approximately 6 to 12 times per year per engine. The waste oil handling components of the lube oil system are generally not furnished as part of the standard engine package and must be designed and specified by the engineer. Insufficient provisions can lead to time-consuming oil handling operations, such as the Eugene/Springfield plant’s need to transfer waste oil multiple times, from drain barrels, to transport totes, then to the plant oil storage area.

• Exhaust Condensate. Water vapor generated during the combustion process, as well as moisture in the biogas can create condensing moisture in the exhaust components. The Eugene/Springfield plant found that they were able to reduce the accumulation of hard deposits on their exhaust heat recovery systems by improving the condensate drainage from their exhaust.

• Building for Engines. The Columbia Blvd (Portland, OR) plant considers the building housing their engines to be their most helpful asset, and noted the importance of designing the building around the engine layout, rather than vice-versa.

• Engine Hoisting Provisions. The CVWR considers their 10-ton overhead crane to be one of the most helpful aspects of their facility. In contrast, the engines for the HRSD Atlantic plant were installed in place of old engines, so a fork lift must be used to lift and move overhaul components. Also, plant staff expressed concern regarding an inconvenient access door arrangement to remove the engine as needed for major overhauls. The NDSD also noted that engine exhaust systems must be configured to avoid interference with cranes and engine dismantling.

• Equipment Access: Engines The Sheboygan plant experienced difficulty with insufficient access space for major microturbine failures and subsequent turbine replacements, The equipment access issue can be especially critical for smaller systems, where plant staff noted that their units are packaged together in a very tight space, making it difficult to work on some parts for non-routine maintenance.

• Equipment Access: Biogas Treatment. The Shebogan plant wishes they had additional headroom above their siloxane vessels (Figure 7). The Portland plant had to add access platforms (similar to Figure 7) to their gas treatment equipment. The Madison plant recommended that biogas treatment equipment skids or systems should be configured to allow easier removal of major components like blowers, either via unobstructed lifting access, rails, or perimeter location. Likewise, the Columbia Blvd. plant had to modify their biogas treatment equipment for maintenance access.

• Engine Room Ventilation. The Madison plant noted that their engine room ventilation system is somewhat cramped, and that the ventilation systems do not adequately cool the space when one engine is being serviced and the adjacent engine is still running. Properly configured localized ventilation could greatly improve working conditions for maintenance.

• Spill Containment. Two plants reported failures of their coolant hoses and loss of coolant charge. If possible, designers should consider whether provisions to control spills can be incorporated into the design.

• Engine Oil Centrifuge. One plant operates with an oil centrifuge for recycling engine oil. This feature can be useful for larger, multi-engine facilities.

• Engine Terminations. NDSD has experienced failures of electrical terminations on engine skid and suggests that these terminations be located off the skid to avoid failures due to vibration.

Figure 7. Siloxane removal tanks with access platform for media changes, but limited

headroom, Sheboygan, WI

• Resolving Bottlenecks in Grid Load. Plant electrical distribution systems often subdivide plant electrical loads into separate bus systems. Several plants, including the LOTT facility, mentioned that they had experienced a need to limit the output of the generator due to insufficient electrical demand on the bus that the generator was connected to. It is important that the electrical designer for new generator systems includes any needed electrical distribution system modifications to avoid unnecessary generator limitations.

ORGANIZATIONAL STRATEGIES, TRAINING AND STAFFING

HRSD, Des Moines, NDSD and CVWR assign a team of select maintenance staff that have been specially trained in the cogeneration system components. Most plants used on-the-job training with senior staff mentoring new staff. A team approach is required to ensure that coverage is available during vacations and rotating shifts. This approach appears to lead to job satisfaction and an increased sense of ownership in the success of the operation.

Several plants made suggestions for training:

• One person from LOTT was sent to manufacturer’s technician training at the manufacturer’s facility.

• For new installations, the HRSD superintendent recommended that specifications include provisions for scheduling engine O&M training in more than one site visit in order to coordinate with shift schedules, since personnel can be off for five days.

• HRSD also lacked a manual start-up procedure, and developed their in-house, with helpful graphics as shown in Figure 8

Figure 8. Example of graphic SOP developed by HRSD to support manual restart

training.

Cogeneration system operations are also the subject of regular plant energy team meetings at the Gresham and Des Moines Plants. The Gresham facility uses these monthly meetings to review any operating issues and ensure that root causes of outages are addressed and operating hours are maximized.

Several plants have staff members with long careers in engine work. For example, the Des Moines and unnamed “Plant A” cogeneration staff have significant previous experience in large engine operation, such as Navy operations, merchant marines, or maintenance of ocean going vessels.

In several plants, management support for the CHP program and staff helps foster an environment where optimization ideas from experienced engine operators can be advanced and realized. For example, the Des Moines lead operator investigated their heat recovery system and uncovered control and heat exchanger bottlenecks. Revisions to the temperature control valve and additional heat exchanger plates have allowed a higher level of heat recovery and reduced plant natural gas consumption.

Surveyed utilities indicated that local manufacturer’s reps play an important role in maximizing engine up-time. Proximity of service staff was an issue for an Oregon plant that was being supported by service staff based in Southern California.

OPPORTUNITIES FOR INDUSTRY RESEARCH AND COLLABORATION

Industry quality standards or testing protocols for iron sponge media. Two plants reported issues with erratic iron sponge media performance, with some iron sponge batches lasting only a few weeks. One plant with low media consumption expressed a concern with media degradation during storage or light usage. Another plant expressed concern about the cost and unknown specifications of the proprietary media they have been using. No standard product specifications seem to be available, and no testing method has been identified to determine whether a load of media will be effective. Since excessive media changes are costly, reduce electrical output, and pose some inherent safety risks, the industry would be well served by adopting standards and testing methods for this product.

Better quality standardized carbon specifications. Few plants expressed dissatisfaction with carbon quality, but some plants were interested in a more standardized procurement process to allow them to specify carbon grades and obtain equivalent quotes from alternate sources.

CONCLUSION

A successful cogeneration system operation relies on optimal operation of the several systems: digestion, digester gas management, digester gas pretreatment, engine-generator equipment, and electrical distribution components. In particular, cogeneration systems with advanced lean burn engines must be properly maintained and operated in order to sustain their high efficiencies and to maximize availability and electrical production.

There is a wealth of knowledge and experience among utility staff operating cogeneration systems. By sharing this knowledge, we hope that operating staff and design engineers can learn from past experiences and continue to make CHP system operation more trouble-free and cost-effective, increasing their economic viability and environmental benefits.

ACKNOWLEDGMENTS

The authors are grateful for the thoughtful responses provided for this CHP survey by the following utilities and individuals:

Central Valley Water Reclamation, Brian Cannon Des Moines WRA, Mark Dauterive Eugene Springfield WMC, Todd Anderson and John Diller Encina Wastewater Authority, Octavio Navarrete Environmental Services, City of Portland, Jim Brown City of Gresham, OR, Jeff Maag HRSD Atlantic Plant, Richard Roberts and Sam Jones LA County Sanitary District, Jim LaRoche LOTT, Dale Ackley and Ken Butti Madison Metropolitan Sewerage District, Alan Grooms, Steve Reusser, Jeff Mike North Davis Sewer District, Myron Bachman, Scott Vineyard Racine Wastewater Utility, Rick Pace, Bruce Bartel Steven’s Point, Chris Lefebvre Sheboygan, Jeff Sargent and Sharon Thieszen One other plant that requested that their name not be disclosed

REFERENCES

Farrand, Fred, “The Impact of Digester Fuel Gas Treatment on Project Economics”, New Jersey Water Environment Association, Fall Technology Transfer Seminar, 2011

Brown, Harry W and Stuber, Samuel F, “Reliability of Natural Gas Cogeneration Systems: Final Report”, ARINC Research Corporation, Gas Research Institute, 1992