Reciprocating Technology Services is Acquired

Reciprocating Technology Services is acquired by the Cooper Machinery Services family of distinguished brands.

Cooper Machinery Services (“Cooper”), a portfolio company of Arcline Investment Management, recently completed the acquisition of RTS, a TTS Energy Services company. Previously, Arcline had acquired Cooper from BHGE. The combined companies were rolled out at the GMRC in San Antonio in October.

“It has been an absolute honor and pleasure to work with the RTS management team, mechanics, field technicians, and support personnel. We all worked hard to start this company and to build a successful brand. Our efforts were clearly recognized by others in the industry.” Said Frank Hoegler, Former President of RTS and Vice President at TTS Energy Services.

RTS operated as an entirely separate division of TTS Energy Services since 2014, and for the past five years, Frank has split his time and energies between RTS and Turbine Technology Services, the sister organization of RTS. “With the separation of RTS, my focus is now squarely on growth for TTS and a smooth transition for RTS.”

“It is high praise indeed that Frank and his team built, in a very short time, an organization chosen to join such an exciting new venture in the gas compression industry. TTS Energy Services management saw this as an opportunity for the RTS operation to grow dramatically and succeed at a scale that would otherwise have taken years to achieve,” said TTS Energy Services CEO, Tony Thornton.

~~~~~~~~~~~~~~~~~~~~~~

Since 1983, Turbine Technology Services has provided innovative technologies and engineering, high-value solutions and gas turbine expertise to over 400 clients worldwide. Our offerings to the global power generation and midstream industries include Controls and Control Panels, Gas Turbine Parts Supply, Conversions, Modifications and Upgrades, Asset Performance Technologies, Engineering, and OnSite Services, Power Plant Services, and DynaFlex Performance Services.

When It’s Hot Outside, Make More MW

Your Gas Turbine Can Increase Output and Revenue with Adjustable Peak Firing

The reports say that June was the hottest month ever in Texas, however, August may have blown that record away. As an example, ERCOT reported that on Tuesday, August 13, over 73,000 MWh were generated largely in support of every air conditioner in the state running full out. For a short period that day, Reuters reported real-time prices briefly soared to $9,000 per megawatt-hour as consumers cranked up air conditioners to escape the brutal heatwave.

Turbine Technology Services offers DynaFlex Performance™ tools that take advantage of this situation and help gas turbine operators produce more MWh and revenue.

Extra Power When You Need It

Depending on their power purchase agreement, gas turbine operators may receive payment based on their maximum generation capacity, or they may need to hold a certain amount of generation in reserve as a percentage of their maximum capacity. For these reasons, adding peak firing capability to both simple and combined cycle units can bring economic benefits without a substantial impact on maintenance costs when the peak fire capability is used strategically at times of high demand.

Traditional peak firing is commonly a fixed, incremental amount of firing temperature above the rated baseload firing temperature. This increase can equate to at least a 2.5 percent increase in the output above baseload for newer GE units and potentially more for vintage GE units.  Increasing firing temperature also increases NOx emissions – which means operators must take into account NOx emission limits as they incrementally increase firing.

Adjustable Peak Firing Keeps NOx Emissions in Check

Adjustable peak firing is a valuable tool in cases where emission values exceed allowable limits before the unit reaches its standard peak firing limit. It allows the operator to increase the load to take advantage of periods of high electricity prices while staying within the maximum allowable NOx emissions dictated by their emissions permit. This mode is especially useful for merchant plants with simple cycle units or with combined cycle units with SCRs.

With TTS’s adjustable peak option, operators slowly and incrementally increase output in steps of 0.1-0.2 MW, monitoring NOx emissions as load increases.

Operators continue increasing the load until they reach a NOx value that they decide provides an acceptable degree of margin in their situation. The adjustable peak option maintains an upper firing temperature limit equal to the standard unit peak firing temperature.

Implementation of adjustable peak firing requires control system logic modifications, HMI modifications (to select adjustable peak fire) and combustion tuning necessary to install peak firing capability.  Take advantage of this hot weather, keep your air conditioner running and make more MWh and revenue in the process.

How Can We Help You?

Contact TTS and speak with a gas turbine engineer for a custom-tailored solution that addresses your unit’s operating parameters, plant requirements, and business objectives explicitly.

Leave us a message or call (407) 677-0813 to speak with an expert today.

Modernizing Vintage Gas Turbines in the Natural Gas Pipeline

Efficiently manage your assets to improve the bottom line

Modernization involves more than migrating from an old vintage system to its modern equivalent. It requires rethinking applications and upgrading multiple technologies. But in the end, it can transform a compression station’s processes and help reposition its operations for the next 20 to 30 years.

To demonstrate, in 2012, TTS was involved in the conversion project of a legacy GE Frame 5001 gas turbine.  The PLC-based turbine control system had become obsolete due to mechanical wear and outdated manual calibrations in the field.  TTS simplified the gas turbine fuel control system by eliminating the unnecessary pre-control valve pressure regulation.  The upgrade allowed for a more efficient, innovative fuel control system by reducing preventative maintenance costs from $5,000 to $10,000 per year to under $1,000 per year.  Furthermore, updating critical gas turbine instrumentation allows production machines to adapt to modern demands and ensures a reliable, productive service life.

The full benefit of a system upgrade is achieved if you do the upgrade in conjunction with a rewire and some device upgrades to support the new control systems and optimize its available features.  The primary benefit of a system upgrade is the availability of information that can be gathered, logged, and stored.  This information is paramount for operations and maintenance performance trending, predictive maintenance programs and troubling shooting problems.

There are, essentially, two types of system upgrades – drop-in and retrofit.  Read on to find out more about these system upgrades and their benefits:

Drop-in Upgrade

In a drop-in upgrade, there is no need for wiring changes, drawing changes, or engineering beyond specifying the equipment.  Examples would be:

  • Battery Systems – Charger and Battery
  • Motor Control Centers – where the control circuits are maintained

Retrofits

Complete retrofits, on the other hand, require detailed design engineering and the provision of new design documentation – specifications/drawings/software, etc. These include those above and the following:

  • Turbine Control Systems
  • Station Control Panels
  • Emergency Shutdown Systems
  • Compressor Controls
  • Motor Control Centers: Intelligent centers with control over Ethernet or DeviceNet
  • Electronic Valves applied to Fuel systems or replacing hydraulic actuators of any sort – IGV, for example.

By restoring old or obsolete automation systems that make up only a fraction of plant capital costs, pipeline operators can more efficiently manage their assets to help improve their bottom line.  Furthermore, they can leverage advanced analytics to monitor and optimize multiple stations across their pipeline fleet.

Making Obsolete Systems Operational Again

Gas turbines have recently become the technology of choice for new U.S. compressor stations, but a lot of Frame 3 and Frame 5 gas turbine units have been in service for decades and are still in operation. Modernization presents an opportunity to mitigate the risks of vintage systems and help improve business performance long term.

The need for station and unit control reliability is critical in these decades-old facilities. But their aging or obsolete systems, combined with the lack of operational and diagnostic information available in those vintage systems, can make reliability elusive.

As a result, these compression stations experience a greater risk of production stoppages and downtime. They are more likely to face support challenges and difficulty with maintaining regulatory compliance. Likewise, they spend valuable time and resources performing manual data collection and reporting.

Modernizing to a contemporary balance of plant control systems can alleviate these challenges and facilitate tighter integration between unit control and associated subsystems.

TTS: We Know Gas Turbines

Turbine Technology Systems (TTS) is an alternative to the OEMs with 36 years of experience and gas turbine expertise. We currently serve six out of the top ten largest pipeline operators in North America with services including commissioning, fuel system upgrades, the balance of plant controls, control upgrades and control panels.

Learn more by visiting our website or contact Frank Hoegler, 407-902-1344

Turbine Technology Services Partners with Voith Establishing Actuator Test Stand

New Workshop at TTS Houston Facility Provides Greater Convenience to Voith’s Local Oil & Gas Clients

Houston, TX (09/04/2018) – Turbine Technology Services (TTS) and Voith recently joined forces to add an actuator, governor and turbomachinery (AGT) test stand at the TTS Houston facility. This development brings a support network of trained technicians to the Houston area, offering greater convenience for Voith’s local oil & gas clients.

TTS opened its facility in Houston in 2016 in conjunction with its sister company Reciprocating Technology Services (RTS). RTS has been working closely with Voith in a joint development effort to provide a new starting technology for large reciprocating engines that provide zero emissions and many other benefits.

“We loved the idea of bringing Voith into our shop,” said Frank Hoegler, TTS Vice President. “This partnership provides us the opportunity for a closer relationship with Voith and its Houston-area customers. What’s great is that TTS doesn’t compete with Voith, but we share a lot of mutual clients, so it’s a win-win situation for us and our customers.”

The AGT test stand has been up-and-running for over a month, explained Thad Berry, sales account manager at Voith Digital Solutions, Inc.

“We’ve had people knocking on our door since day one,” Berry said. “Having a local, certified team of trained technicians means a lot to our Houston customers. They want a local support network that understands the actuators and their applications with the proper equipment, tools, and expertise to perform critical maintenance and emergency repairs.”

Berry continued, “Actuators can be delivered directly from the field to Voith and its trained technicians – reducing the workload and time involved with shipping. That, in turn, means that repairs and maintenance can be completed faster, allowing for shorter outages.”

About TTS

TTS is an OEM alternative that offers agility, innovation and experience delivering industry leading aftermarket parts, modernization, optimization, upgrading and custom services for our power generation clients. With over 35 years of experience providing technical solutions in the power generation and gas compression industry, TTS has managed hundreds of gas turbine installations and modernization projects. Based in Orlando, Florida, our team of 40+ engineering professionals has traveled millions of miles to over 90 countries serving more than 400 clients.

About Voith

Voith is a global technology group. With its wide range of plants, products, services, and digital applications, Voith sets standards in the markets for energy, oil and gas, paper, raw materials, and transport & automotive. Founded in 1867, Voith today has more than 19,000 employees and earns $4.7 billion in sales. It has locations in over 60 countries and is one of the largest family-owned companies in Europe. For more information, visit www.voith.com.

Contact Information:

Scott Muster, Marketing Director, TTS Energy Services
9848 Windfern Rd Houston, TX 77064
TTSEnergyServices.com
832-341-9341
smuster@TTSEnergyServices.com

35 Years in the Gas Turbine Industry
Where our renowned history meets a promising future

March of 1983, Turbine Technology Services (TTS) was founded. Our first project was in Saudi Arabia and involved taking over the operations of a 7EA power plant. This was a high-pressure project; it was not wise to disappoint the Sheik. The project lasted 2 ½ years, it was a fabulous way to begin our journey.

But this announcement isn’t so much about our history and what we were, but more about what we have become and where we are going. Our team of 40+ engineering professionals has traveled millions of miles to over 90 countries serving more than 400 clients managing hundreds of gas turbine installations and modernization projects and providing innovative and integrated engineering solutions – our hallmark.

We are part of the TTS Energy Services portfolio of companies, and, with our sister company Reciprocating Technology Services, we are positioned for growth. As an alternative to the OEMs, both organizations offer agility, innovation and experience delivering industry leading aftermarket parts, modernization, optimization, upgrading and custom services for our power generation and gas compression and transmission clients.

“This is an exciting time to be connected to such a great team of engineers and professionals who live and breathe customer centric values, power generation and technology innovation.” George Gramatikas, Founder, TTS.

Today the power generation industry is experiencing disruption of unprecedented scope and speed. OEMs are laying off employees and struggling to restructure their organizations.

TTS Energy Services is not down-sizing, but rather up-sizing. We have focused our strengths on growing the business, meeting new challenges and exploring a future that is filled with opportunities and promise.

Black Start – The Driver is Reliability

The solution is TTS’ Operational Excellence



The United States would face severe economic consequences if there was a serious disruption to the electricity supply. The cost could easily run into billions of dollars. While the likelihood of such an outage is low, the concerns regarding the possibility and impact of electricity blackouts is increasing. The leading concerns? Weather, aging infrastructure and cyber-attacks.Regardless of the cause, there are no yardsticks available to compare the cost of infrastructure investment to the cost of power outages. Just know, that it is all expensive. Add the potential for physical harm and injury to people effected by the blackout and there is no calculation that applies.

What is a “Black Start”?

A “black start” is the process of restoring an electric power station or a part of an electric grid to operation without relying on the external electric power transmission network. Needless to say, it’s a very complicated process. The controls and instrumentation used during a black start must operate dependably and with the utmost precision and speed.

A black start unit is one that can start its own power without support from the grid in the event of a major system collapse or a system-wide blackout. In the U.S., every region within the North American Electric Reliability Corp. (NERC) has its own black start plan and procedures. Each region also designates certain plants as black start units.

TTS Answers the Call

One of these plants recently contracted Turbine Technology Services (TTS) to work with them and other contractors to upgrade the plant’s controls and systems to meet the current technology and reliability standards. Black start operations are conducted in compliance with NERC Critical Infrastructure Protection (CIP) standards. Black start resources are linked to the CIP EOP-005-2 standard, and any cyber asset that is essential to the operation of a black start resource is a “Critical Cyber Asset” by definition, according to NERC.

 

The Scope of the Project

TTS is very proud to be awarded this prestigious project based on TTS’ wide collection of skills and experience. The project’s gas turbine reliability improvement scope description included a detailed engineering design package for all materials to be provided for this project.

Those materials include:

  • Complete Control Building (PEECC) for two (2) units including installation of EPWS equipment and FAT testing.
  • Electrical Equipment
  • Air-Start Compressor Skid
  • Fuel Oil Forwarding Skid
  • Transmitter Panels
  • Cable Tray
  • Conduit and Cable
  • Installation engineering
  • Test packages
  • Connection drawings

In addition, the scope entails the following site installation and commissioning activities:

  • Demolition of Complete Control Room Equipment
  • Equipment Installation
  • Complete project installation and commissioning
  • PEECC
  • Fuel Skid
  • Compressors
  • Fuel Valves
  • Cable Tray
  • Conduit and Cable

TTS is excited to announce that the project is well under way. We’ll keep you up to date on what’s happening both here and on LinkedIn, so be sure to follow us online. You’ll be the first to hear all the latest details from TTS. To Be Continued…

Do you have a project that needs a TTS technical solution?
Contact us to see how we can help you meet your goals for operational excellence.

The State of Safety in Oil & Gas Industry – 2018

Abridged from DNV Report 05/07/2018

We work safer now than ever before, but: “You can’t take anything we do for granted… “

Recently, a horrible accident happened at a small welding shop behind our offices here in Houston. In this shop worked two or three welders, each one an experienced hand with 20-30 years of welding experience. While one of the welders was heating up a sealed pipe, something went terribly wrong: the pipe exploded.

When the pipe blew, we heard a loud bang and screaming. In the pipe’s sudden explosion, the welder tragically lost his arm just below the elbow. The EMTs arrived by emergency helicopter and took the injured man to the hospital to be treated. Fortunately, the man would live; unfortunately, he might not weld ever again.

Our safety lead at RTS, Tom Anderson, called an Emergency Safety Meeting. “You can’t take anything we do for granted—we work in a dangerous environment,” he said.

The oil and gas industry has become considerably safer over the past two decades according to data from several industry bodies, such as the International Association of Oil & Gas Producers (IOGP), as well as national associations, including those in the UK, Norway, US and Australia.

Despite this, any time you work in a high-risk environment, accidents like the one at the welding shop behind us can occur. So, is enough being done to further improve safety in the oil and gas industry? Have recent market dynamics negatively affected investments in enhancing safety performance? And how aware are industry leaders of safety risks and incidents?

You just can’t be too safe.

Key Issue – Increased Risk Due to Reduced Maintenance Investment

According to the results of DNV GL’s 2018 Industry Outlook research, close to half (46%) of the 813 senior oil and gas professionals surveyed believe that too little has been invested in maintenance and inspection of installations and equipment in recent years. Some 38% said that safety management in the oil and gas industry is effective and does not need to change – 26% disagree, while 31% are neutral. This clearly shows that the industry is divided on the need to change safety practices.

It is also interesting to note that safety performance and investment increased during the strong growth years to 2014, but only risk increased through the challenging years that followed. We have heard where some companies inadvertently increased safety risk because of incentive programs that rewarded maintenance managers for being under budget on maintenance.

Certainly, many in the industry don’t believe that their business has made any compromises on safety. “The risk that we’ve got now, in the recovering market, is that companies forget about the underinvestment that they made,” says Graham Bennett, vice president, DNV GL – Oil & Gas. “Ramping up operations to take new opportunities can result in a worrying picture if companies don’t recognize the underinvestment made in the last few years. There is always a lag between periods of underinvestment and any associated safety impact.”

Downstream Sector Set to Invest More in Safety

In our survey, respondents from the downstream sector currently expect the highest increase in safety spending (41%) this year, compared with other parts of the industry. We also find the downstream sector to be more concerned about safety than other areas of the value chain. For instance, only 12% of respondents overall say that cost cutting over the past three years has increased health and safety risk, but this figure is nearly double (23%) in the downstream sector.

Digital Safety Measures Increasing

Many new investments in safety will be aimed at digitalizing safety monitoring, processes and responses this year. A clear finding from our survey is a significant increase in the proportion of respondents (54%) who intend to boost spending on digitalization in 2018 – up from 39% expected for 2017. Looking further ahead, over the next five years, 76% of respondents say they will invest in digitalization.

Already, even where cutbacks have been widespread, 40% say digitalization has improved safety over the past three years. “The industry has been a quick adopter of new technology and digitalization,” says Mr. Lu Nianming. “Technology has helped us improve safety monitoring systems, data analytics helps us determine which processes, areas and equipment are more accident-prone, while we have wearable equipment to monitor workers in case they faint or fall.”

A key advantage of digitalization in the safety context is that it can allow for the integration and transparent communication of hundreds of key indicators from across an organization. For example, DNV GL’s MyQRA service draws on data from quantitative risk assessment (QRA) reports to create a single source of safety data that can help all stakeholders generate deeper safety insights, better understand important safety signals, make decisions and predict future outcomes.

Senior Executives are More Positive About Safety Than the Field Engineers

Encouragingly, most survey participants (85%) say that safety risks and incidents are reported to senior management, and this figure rises to 91% among those working for companies with an annual revenue over USD500m. But how do perspectives on safety differ between those closer to the boardroom and those closer to the hazards?

Our survey found:

  • Senior management (45%) are more likely than engineers and technical specialists (32%) to say safety management is effective and does not need to change.
  • Nearly twice as many engineers/technical specialists (28%) as business leaders (15%) say that a focus on profitability has had a negative impact on safety performance.
  • Most business leaders (65%) say that senior management understands the impact of cost cutting on safety, while just 50% of engineers and technical specialists say the same.

This indicates that those in the boardroom are, to some degree, more optimistic about safety than those in the field. While further research is needed to understand why this is the case, it suggests that senior leaders in the oil and gas industry could benefit from spending time better understanding the risks faced by those on the front line.

The Right Mindset: Perpetual Improvement

Overall, long-term trends indicate a strong improvement in the safety of oil and gas industry workers over time. The industry appears to be largely continuing this path, increasing investment and modernizing safety procedures and equipment. However, there are reasons to caution the optimism – from lower investment in safety in recent years, to the relatively higher concerns identified in the downstream sector, and by more junior and technical employees.

“Operators cannot afford not to maintain safety – they are aware, of course, that they can’t compromise in this area – I don’t really believe they are allowing maintenance or safety standards to slip,” says Frank Ketelaars, regional manager, Americas at DNV GL – Oil & Gas. “In fact, in many places the pressure to raise standards has increased.”

In Closing

While zero risk is not achievable, much more can be done to stop preventable incidents. “We are in an industry that involves risks,” says Tom Anderson, Operations Director, RTS. “Safety incidents will happen no matter how much we do, but we can work to get the rate of incidents as low as possible. And to do that we must constantly focus on the need for improvements. Safety Matters Most.”

Breaking News: GE Frame 5PA Upgrade Motivated by Forced Outage Also Works for 6B and 7B-EA

TTS Successfully Converts a Mark V Fuel Control to Electronic Valves

A paper products plant in the Southeast was planning for a major spring 2017 inspection for their Frame 5 with preparations were well underway in October 2016 when suddenly, the unit tripped on high vibration, just as day shift arrived at the facility.

An original Row 2 bucket failed, causing considerable downstream damage. Management decided to begin necessary repairs immediately and to conduct the machine’s third major inspection at the same time.

The Frame 5 cogen unit had accumulated nearly 115,000 total fired hours and 1,500 starts since its commission in 1997. The 24.5-MW (on gas) MS5001PA engine was equipped with a DLN-1 combustion system and capable of dual-fuel firing. It was one of the most advanced Frame 5s in the fleet when it was first installed.

Since its commissioning, the 12 combustion, six hot-gas-path (HGP) and three major inspections typically revealed little beyond normal wear and tear. In fact, few significant modifications had been made to the basic engine in its two decades of service and plant personnel told the editors that the bucket failure was the first major issue suffered by the gas turbine in its lifetime.

Chris Mancini of Mechanical Dynamics & Analysis Ltd was informed of the unit trip and its likely damage shortly after it occurred. He and a superintendent were onsite within two days to assist in damage assessment.

Field service personnel arrived one day after Mancini and the following day, the day shift completed its site and safety orientation, organized tools and work areas and ran power and compressed-air lines as needed. The night shift received its site orientation, set up lighting and began disassembling the unit. The project proceeded at an aggressive pace from that point forward given the black-start cogen unit’s importance to mill production.

MD&A was awarded a turnkey contract for repairs, the major inspections of the turbine and generator, as well as some additional projects including the removal of the liquid-fuel and trip-oil systems.

Because the mill never had success operating on liquid fuel, the most practical solution was to not burn liquid fuel. That decision, made years ago by plant management, was easy given the ready availability of quality gas.

However, oil infrastructure eventually ran afoul of the company’s goal for continuous improvement. It took three shifts to remove liquid-fuel components to conduct a combustion inspection and three to reinstall it before engine restart.

The facility has been performing CIs at 8000-hr intervals so the cost, in terms of labor and outage schedule impact, added up quickly.

The plant engineer was guardedly optimistic about doubling that interval, as promised by the more robust coating applied by ACT Independent Turbo Services Inc, on hot-section parts in its Texan LaPorte shop during the outage. However, this doubling required approval by the facility’s insurer and the coating’s merit would need to be considered.

MD&A was credited with developing a plan to eliminate oil capability, including the fuel-nozzle mods, at less than half the cost estimated by an alternative supplier. It should also be noted that by eliminating the parasitic power associated with the liquid-fuel system, unit output increases by 280 kW.

Issues with fuel valves equipped with hydraulic actuators motivated the mill to replace that equipment with electrically actuated valves when the change to gas-only firing was made. With this upgrade, less gas is burned to produce a given amount of power than with hydraulic valves in the circuit.

Replacing the mechanical overspeed bolt and trip-oil system with an electronic overspeed trip enables operators to now verify trip functionality at 500 rpm without stressing the unit.

 

Converting from Dual Fuel to Gas-Only

The liquid fuel system (LFS) for this Frame 5 included the following subsystems: primary and secondary liquid fuel and purge, atomizing air, and water injection and purge. LFS decommissioning, a first step in the conversion of the unit to gas-only operation included deactivation or removal of all hardware associated with oil supply as well as of equipment in the subsystems noted.

During the forced outage, key components of the LFS were removed, but because of schedule constraints and the physical location of some hardware, it was not feasible to remove everything at that time. Others who have performed similar conversions told the editors it’s important to disconnect/remove components that would consume power when inactive—such as the fuel pump and atomizing air compressor—and simply abandon in place piping that would have no adverse impact on gas-only operations.

The end covers and piping inside the turbine compartment were modified during the outage to reflect elimination of the LFS; Mark V controls software was reconfigured to accommodate the changes made.

 

Checklist of LFS Hardware Removed

  • Accessory-gearbox oil-vapor eductor; a desiccant breather cap was installed in its place.
  • Atomizing-air booster compressor driven by the starting diesel, along with related piping and valves.
  • Atomizing-air pre-cooler and its cooling-water supply piping. Source-air piping from the atomizing-air pre-cooler inside the turbine compartment also was removed.
  • Extraction piping from the compressor to the atomizing- and purge-air subsystems.
  • Gas-fuel purge system hardware.
  • Primary liquid-fuel lines from the flow divider to the fuel nozzles.
  • The accessory-gear-driven atomizing air compressor—together with its drive gear and associated bearings.
  • The accessory-gear-driven fuel pump—together with the electric clutch, coupling, bypass valve, and gear and its bearings.
  • Water-injection piping to the fuel nozzles.

 

Fuel Valve Upgrades

The mill’s Frame 5 was equipped with a combined, hydraulically actuated gas stop speed/ratio (SRV) and control valve (GCV) and gas fuel splitter valve. Recall that the SRV and GCV are independent valves. Gas flows through the SRV to the GCV, which regulates the amount of fuel flowing to the ring manifold serving the 10 combustion chambers. The splitter valve serving on DLN machines divides gas flow between the primary and secondary fuel systems.

Turbine Technology Services Corp was retained to remove the liquid fuel system, as described above, and to replace the existing hydraulically actuated, 3-in. SRV/GCV and splitter valves with new electronic valves from Young & Franklin Inc. Existing gas supply strainers and valves were retained inside the compartment. A 3-in. stop valve was required in addition to electronic primary- and secondary-fuel control valves.

 

The company’s Dave Simmons told the editors TTS has deep experience in this work, having removed liquid-fuel capability on about 50 GE Frame 5s through EAs over the years and retrofitted electronic valves from different suppliers on perhaps 20 machines.

Simmons said elimination of liquid-fuel capability on a non-DLN gas turbine is relatively easy, but experience counts when a DLN engine is involved. This project was unique: It was the first time that a Mark V-equipped DLN-1 machine was converted to electronic valves for fuel control—and it took only four weeks from initial request to startup.

TTS proved it could satisfy project goals by running tests on its reconfigured Mark V simulator. No empirical testing was involved. There were no surprises, Simmons said. The Y&F valves performed the way the company said they would.

He added that an increasing number of plants are investigating conversion to electronic valves and most projects can be justified based on opportunity costs. One of the first things to do, Simmons continued, is to determine the availability of physical space to accommodate the new equipment. This shouldn’t be challenging for non-DLN machines, he said.

Some demolition and installation of the new valves and electrical conduit and wiring are key elements of the physical project. The editors were told that most wiring generally can be reused, excepting old non-DLN units. Otherwise, shielded cable is strongly recommended for use with electronic valves.

Finally, if considering electronic fuel valves for your plant, don’t forget to audit the control system logic file to see if it can accommodate the switch from hydraulics to electric. There was no such issue on this project because of all the liquid-fuel infrastructure removed.

TTS modified the gas control software in the Mark V panel and HMI operator screens and then performed functional and operational tests of the new gas control system.

 

Other Activities Required to Complete the Project

  • Disable piping to the gas control valve for the existing hydraulic- and trip-oil systems. Note that the mechanical overspeed trip was disabled when trip-oil supply to the gas control valve was terminated.
  • Install an emergency-stop pushbutton inside the accessory compartment.
  • Install two magnetic speed pickups and independently connect to the Mark V overspeed “hardware” trip.

To convert the dual-fuel end covers to gas only, the liquid-fuel and water-injection distributors were removed. The tubing runs connecting the distributors to the corresponding five primary-fuel nozzles on each end cover also were removed and caps installed in their place at the openings created. Secondary-fuel nozzles attach to the center of each end cover—their liquid-fuel and water-injection connections were also removed and capped.

 

To learn more about TTS’ dual fuel experience and capabilities for fuel conversions or upgrades, visit our website.

TMOS Provides a Path to Compliance with the Recent GE Power Product Service Information Bulletin Regarding Mark V Communication Interface Overload

By Scott Muster, Turbine Technology Services

A recent article published on a popular online media site highlighted a catastrophic failure on a GE F-Class unit using Mark V controls and discussed the events leading up to the failure. While the root cause of this failure was not identified, it was associated with an apparent overloading of instructions to the Mark V system which then behaved abnormally precipitating the failure. The article suggested possible actions to protect against the failure but did not suggest steps to prevent the failure from occurring in the first place.

Subsequently GE Energy published a technical bulletin which referred to the article. The bulletin described the events surrounding the failure in detail and provided specific communication management criteria which if adhered to would likely preclude a failure of this type. It also recommended against implementing the protective measures suggested in the original article.

For many users, modifying their existing <HMI>, DCS and other interconnected systems to comply with these communication limitation requirements may represent a significant engineering exercise and may alter or limit the functionality of their overall DCS, SCADA and PLC systems. In addition, it may still be difficult to guarantee that a communication overload is not possible under every set of circumstances for each and every possible system configuration.

One solution to this problem is the Turbine Monitoring System (TMOS), available through Turbine Technology Services (TTS). The TMOS is a direct replacement for existing Mark V <I> and <HMI> systems and one of its main features is that it actively manages and regulates the transfer of instructions from all site devices (BOP, DCS, SCADA, Operator Stations) to the Mark V ensuring that the type of communication overload associated with the recent failure is not possible.

TMOS has been in the field since 2001 and has maintained an outstanding record for safety and reliability for more than 60 million operating hours. TMOS is typically a simple and quick “plug and play” replacement for single Mark V systems and can be used to dramatically simplify multi-unit systems. TMOS is an established product and there are already hundreds of machines around the globe that have been upgraded to this system.

We asked the TMOS’ developer Thomas Finstermann, CEO, of Industrial Turbine Services to comment on how TMOS addresses the recommendations in GE’s Bulletin Advisory. He highlighted the following points:

  • TMOS has a built-in traffic control algorithm that buffers the command traffic from all connected clients (operator stations, DCS systems, SCADA systems, etc.) and sends them to each MKV with a delay which ensures compliance with GE’s Advisory requirement. Operator Display command push buttons are given priority over Modbus, OPC, or other 3rd party clients.
  • The traffic control algorithm consolidates identical commands arriving simultaneously at TMOS from multiple devices into a single command which is then forwarded to the Mark V.
  • The TMOS communication architecture ensures that the number of TMOS (HMI) Servers on any Mark V ARCNET system does not exceed two (2) while providing full server and HMI system redundancy in a “hot backup” configuration.
  • TMOS Servers act as a historian and online site monitoring system. There are no additional read requests issued to the Mark V panel.
  • The TMOS traffic control will only allow a predefined number of sessions and it is safe to use them during unit operation.
  • The traffic control algorithm will not allow the same signal to be requested from the Mark V twice. If a signal is required for a fast trending operation, but the same signal is already used in a slow updating display, the signal will be moved from the slower to the faster task.
  • There is no screen cache limitation in TMOS. If two or more operator displays or other devices are requesting the same signal at the same time, the Mark V will receive only one request.

Neither the original article nor the GE bulletin discusses or identifies a root cause mechanism for the failure and while it is important to ensure that each Mark V system complies with the GE advisory recommendations, it remains possible that other factors could have contributed to this specific failure.

TMOS provides the most established, rigorous and predictable solution to the issue of managing traffic to a Mark V system and ensuring system compliance with the fundamental GE recommendations in the bulletin. TMOS will also simplify the overall Mark V system communication architecture while allowing users to maintain all their existing SCADA, DCS, PLC and other communication interfaces intact and without modification.

For additional information on the TMOS system and its capabilities please visit our website or contact Scott Muster at smuster@turbinetech.com.

Turbine Reliability is Often Driven by Fuel Quality and Availability

“No one wants to burn liquid fuel in their gas turbine – unless they have to.”

Reliability is always key.

Despite fuel resource limitations or fluctuations, despite increased demand and despite the pressures from environmental compliance, confidence needs to be high that the unit will start and operate well. With that in mind, many utilities will use dual fuel capability as a back-up just in case their primary fuel resource fails in quality or availability.

Some areas of the country face economic and reliability risks due to the weather. Forbes reported that “When it’s below 20°F, each time the temperature drops one degree another 400 MW of electricity is needed.” And, it’s not just about electrical demand – Winter 2014 saw a 20-fold increase in gas prices on isolated, cold days… ouch.

Because much of today’s gas supply comes from shale plays, many operators have seen an increase of liquids in the gas which can cause serious issues for the turbine’s operation (Primary Re-Ignition for example) and the environment. The quality of the supply needs to be monitored closely.

Switching to dual fuel, however, has its challenges:

  • Dual fuel is more complex as indicated by the following schematics.
  • More complexity equates to increases in maintenance.
  • Liquid fuel requires careful selection of the fuel filtration system. GE manual calls for a one micron filter.
  • Fuel quality from long term storage will naturally undergo chemical degradation due to Oxidation and Polymerization.
  • Coking can be an issue. 250oF often cited as threshold for coking, but coking severity is on a temperature / time continuum.

If these challenges didn’t dissuade you, reliable liquid fuel operation relies on the successful operation of numerous control components from multiple systems including: liquid fuel, atomizing air, water, liquid and gas purge and false start drain.

Your O&M program should incorporate:

  • Component inspection
  • Device calibration
  • Component testing
  • System testing
  • Robust startup, operating, and shutdown procedures

Some important takeaways:

  • Monitor and address fuel quality issues.
  • Reduce the potential for coking by reducing temperatures in key fuel system components: Water-cooled check valves, 3-way valves/distributor, and post-shut down purging of fuel from system.
  • Consider upgrading to corrosion-resistant flow dividers.
  • Inspect and test dual-fuel components and systems, particularly in the late fall.

To learn more about TTS’ dual fuel experience and capabilities for fuel conversions or upgrades, visit our website.