National Renewable Energy Laboratory 

Innovation for Our Energy Future 

A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 

Innovative Distributed Power 

Grid Interconnection and 

Control Systems 

Final Report 

December 11, 2000 – August 30, 2005 

K. DePodesta 

Gas Technology Institute 

Des Plaines, Illinois 

D. Birlingmair and R. West 

Encorp, Inc. 

Windsor, Colorado

Subcontract Report 

NREL/SR-560-38982 

March 2006 
Innovative Distributed Power 

Grid Interconnection and 

Control Systems 

Final Report 

December 11, 2000 – August 30, 2005 

K. DePodesta 

Gas Technology Institute 

Des Plaines, Illinois 

D. Birlingmair and R. West 

Encorp, Inc. 

Windsor, Colorado 

NREL Technical Monitor: T.S. Basso 

Prepared under Subcontract No. ACL-1-30605-04 

Subcontract Report 

NREL/SR-560-38982

March 2006 

National Renewable Energy Laboratory 

1617 Cole Boulevard, Golden, Colorado 80401-3393 

303-275-3000 • www.nrel.gov 

Operated for the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy 

by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337
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Acknowledgements 

The following personnel at GTI have contributed to the technical efforts covered in this report: 

• Karen DePodesta, William Liss, Michele Dybel 

The following personnel have contributed to the technical efforts covered by this report: 

• Doug Birlingmair, Randall West, Larry Adams, Kevin Sauer, Arie Willenbrecht, Joshua 

Meyer, Bruce Heath, Harry Hunter, Don Simmons, Rick Dohmen, Chris Whitham 

Trademarks 

Encorp, Encorp Intelligence, Encorp Power, enpower, entelligent, and Virtual Power Plant are 

trademarks of Encorp, Inc. LONWORKS, is a registered trademark of Echelon Corporation. 

Windows is a registered trademark of Microsoft Corporation in the United States and other 

countries. ISaGRAF is a registered trademark of ICS Triplex. All other brand or product names 

are trademarks of their respective holders.

iii
Executive Summary 

The objective of this contract was to continue the advancement of distributed generation in the 

marketplace by making installations more cost-effective and compatible across the electric 

power system and energy management systems. This advancement was achieved by developing 

innovative grid interconnection and control systems. 

Specifically, the overall goals were: 

• To develop and demonstrate cost-effective distributed power (DP) grid interconnection 

products, software, and communication solutions applicable to improving the economics of 

a broad range of DP systems, including existing, emerging, and other power generation 

technologies. 

• To enhance the features and capabilities of DP products to integrate with, interact with, and 

provide operational benefits to the electric power system and advanced energy management 

systems. This includes features and capabilities for participating in resource planning, the 

provision of ancillary services, and energy management.

These objectives are outlined with the following specific tasks: 

Contract Tasks 

Task 1: Develop Prototype Advanced Controller 

Task 2: Develop Prototype Power Sensing Board 

Task 3: Expanded Suite of Communication Capabilities 

Task 4: Interface for Revenue-Grade Meter 

Task 5: Demonstrate Interconnect DP Device 

Task 6: Type Testing 

Task 7: System Command and Control 

Task 8: Demonstration of Controlled DP Resources 

This final report provides the results of the work completed on the advanced grid interconnection 

controller, the command and control system, as well as two demonstration sites. This contract 

work achieved the following objectives: 

• Realized significant cost savings compared to current industrial switchgear options. 

• Reduced maintenance costs due to the benefits of integrated switchgear and controls systems 

and the power of remote monitoring, diagnostics, and communications, as well as the design 

of the Advanced Controller for field service and field support capabilities. 

• Demonstrated compatibility with major electric power system communication protocols and 

building energy management communication protocols. 

• Created the ability to integrate with a broad cross-section of energy generation technologies 

and energy load management technologies. 

The following is a list of specific technical accomplishments that have been achieved under this 

contract: 

• Designed, developed, and tested a prototype. 

• Demonstrated the prototype design’s functionality in the Chowchilla case study. 

iv
• Researched and published the Communication Study. This study identified the various 

types of communication used and the control features that would be desirable for remote 

monitoring and control of DP assets. 

• Addressed Internet related security features that would be needed in the Advanced 

Controller. 

• Developed the prototype design into a commercial product and released it for commercial 

use. 

• Created a design in which most simple systems do not need a CPM because remote 

communications can be performed directly with the Advanced Controller. This 

eliminates an expensive component (and associated wiring and system complexity) that 

was prone to failing in the field.

• Designed the system so that it reduces the time required to initially load or upgrade an 

application. Large systems will take only a few minutes per control and single control 

download capability within a multiple control system is provided (more than a 100 times 

improvement in speed over the previous controller, especially in larger systems). 

• Provided for a single user interface. Older controllers required designing the control with 

both LONWORKS tools and the ISaGRAF workbench tool, which complicated the 

designs and increased errors that were debugged late in system assembly. 

• Utilized International Programming Languages to improve marketability and ease of use 

training for the control. 

• Provided Application Simulation during the system design process to minimize design 

errors and correct these errors early, reducing manufacturing and site set-up times. 

• Gave the application the ability to self-document during the design process. This saves 

many hours during the design process and ensures that the documentation is the same as 

the design. 

• Provided a design with serviceability improvements. The current controller design 

requires the cover to be removed for access to wiring, LEDs, connectors, and the reset 

button. The Advanced Controller design provides cover-on accessibility for functions. 

• Designed the Advanced Controller to allow field replacement and project archival. It 

provides an easier method to perform a field replacement and store or re-store the 

application project on the Advanced Controller. This is achieved with a Removable 

MultiMedia Flash Card interface, which will allow field replacement by on-site 

technicians, eliminating the need for an engineer to travel to the site to perform the field 

replacement. 

• Designed the Advanced Controller to extensively document the firmware design, 

implementation logic, and control algorithms that were not available on the previous 

controller. This will greatly aid training new users and engineers, and aid debugging of 

issues that occur when using the new controller. 

• Designed a system that provides a 20-fold performance improvement through the use of a 

high-speed controller central processing unit, along with a high-speed digital signal 

processing chip. 

• Designed a system that reduces manufacturing costs (estimated reduction to be greater 

than 15%). 

• Designed a system that increases control capabilities with the design of a patented active 

anti-islanding control scheme. 

v
• Designed a system to further increased control capabilities with the design of a loss-of 

synchronization control scheme. 

• Designed a system that reduces overall grid interconnect system capital and installation 

costs with the elimination of additional system hardware now intrinsic to the Advanced 

Controller (i.e., improved firmware and communications capabilities). 

• Designed a system that includes compliance with current and projected industry 

standards for switchgear and interconnection devices. 

• Designed a system that increases functionality for the DP customer. 

• Designed a system that includes supporting software that encompasses the ISaGRAF 

Workbench Extension Tool and the Advanced Controller Commissioning Tool. 

• Provided a design that is software configurable, eliminating separate hardware 

configurations for UPC, KWS, and PTC applications. This is a big cost savings-- it 

increases production volumes thereby lowering, inventory, support, and documentation 

costs, as well as simplifying marketing and sales efforts. 

• Included an RTU (Remote Terminal Unit), which is focused on connecting and 

communicating with distributed resource subsystems. The RTU allows interface with 

utility-grade energy meters, engine controllers, fuel meters, etc. and feeds this 

information to higher-level systems. The Advanced Controller includes the following 

RTU capabilities: 

o Modbus devices (Server and Client) 

o LONWORKS devices (more standard implementation) 

o TCP/IP (Ethernet) 

o Additional RS232 and RS485 serial interfaces. 

• Provided a standard Web browser interface for simple monitoring and operation. 

• Provided a Web trending capability. 

• Performed an extensive series of qualification and compliance tests on the Advanced 

Controller. The following actions were performed on prototype and production units, 

ensuring that a quality system was in place to maintain the quality of the controllers that 

would be manufactured. 

o Unit testing of each individual software unit that was developed 

o Bench-level testing of the controller system 

o Type testing as specified in IEEE 1547 and other applicable standards (temperature, 

mechanical shock/vibration, EMI, RFI, etc.) 

o Live on-generator system tests in a laboratory environment 

o Production and on-going reliability tests 

o Tracking and monitoring of field deployment issues 

o Corrective action and verification of all issues that were identified during the 

development and deployment of the Advanced Controller. 

• Created the Remote Energy Management Command and Control (EMC), located in 

Windsor, Colorado. The EMC is capable of remotely monitoring and controlling 

distributed generation assets. 

• Demonstrated the combined system at two demonstration sites: 

o Single generator application located in Colorado 

o Multi-generator, combined heat and power application in California

o Both systems are supported by the EMC remote monitoring and control capabilities.

vi
Table of Contents

1. Introduction............................................................................................................................. 1 

1.1 Background..................................................................................................................... 1 

1.2 Distributed Power Problem Statement............................................................................ 3 

1.3 Interconnection Controller Problem Statement .............................................................. 3 

2. Contract................................................................................................................................... 6 

2.1. Contract Overview.......................................................................................................... 6 

2.2. Product Development Methodology............................................................................... 6 

2.3. System Architecture Technical Approach ...................................................................... 7 

3. Summary of Tasks and Results............................................................................................... 9 

3.1. Task 1 - Develop Prototype Advanced Controller.......................................................... 9 

3.2. Task 2 - Develop Prototype Power Sensing Board....................................................... 11 

3.3. Task 3 - Expanded Suite of Communication Capabilities............................................ 12 

3.4. Task 4 - Interface for Revenue-Grade Meter................................................................ 13 

3.5. Task 5 - Demonstrate Interconnect DP Device............................................................. 14 

3.6. Task 6 - Qualification and Testing of the Advanced Controller................................... 17 

3.7. Task 7 - Develop System Command and Control ........................................................ 19 

3.8. Task 8 - Demonstration of Controlled DP Resources................................................... 21 

4. Conclusions........................................................................................................................... 24 

5. Appendix A: Product Development Methodology .............................................................. 29 

6. Appendix B: System Architecture Technical Approach...................................................... 32 

6.1 Control Layer................................................................................................................ 33 

6.2 Data Acquisition Layer................................................................................................. 34 

7. Appendix C: Advanced Controller Design.......................................................................... 36 

7.1 Hardware....................................................................................................................... 37 

7.1.1 Communications................................................................................................... 39 

7.2 Firmware ....................................................................................................................... 41 

7.2.1 ISaGRAF Embedded PLC.................................................................................... 42 

7.2.2 Function Blocks.................................................................................................... 43 

7.3 Advanced Controller Support Software........................................................................ 46 

7.3.1 GWE ..................................................................................................................... 46 

7.3.2 Advanced Controller Commissioning Tool.......................................................... 46 

8. Appendix D: Prototype Power Sensing Board..................................................................... 47 

9. Appendix E: Communications.............................................................................................. 52 

9.1 Evolution of Communications Standards ..................................................................... 52 

9.2 Implications of Communication Standards Situation ................................................... 53 

10. Appendix F: Task 5 Prototype Demonstration ................................................................... 54 

10.1 System Overview.......................................................................................................... 54 

10.2 System Topology .......................................................................................................... 56 

10.3 Software ........................................................................................................................ 58 

11. Appendix G: Qualification / Type Testing .......................................................................... 61 

11.1 Definition of Testing / Overall Quality Strategy .......................................................... 61 

11.2 Unit Testing (Lowest Level – Developer Level).......................................................... 61 

11.3 System Bench Testing................................................................................................... 62 

11.4 Compliance Testing/ Type Testing............................................................................... 63 

11.4.1 Temperature/Humidity (Operating and Storage).................................................. 63 

vii
11.4.2 Mechanical Shock and Vibration.......................................................................... 63 

11.4.3 UL ......................................................................................................................... 65 

11.5 Live System Testing ..................................................................................................... 65 

11.6 Production / Manufacturing Testing ............................................................................. 67 

12. Appendix H: System Command and Control ..................................................................... 69 

12.1 Communications Study................................................................................................. 69 

12.2 Internet Security Design Considerations ...................................................................... 69 

12.3 Market Analysis............................................................................................................ 71 

12.4 Product Development Methodology and Results ......................................................... 73 

12.4.1 Design Details – Data Transport........................................................................... 74 

12.4.2 Design Details – Data Processing......................................................................... 75 

12.4.3 EMC Data Examples............................................................................................. 76 

12.4.4 EMC Summary ..................................................................................................... 77 

13. Appendix I: Demonstration of Controlled DP.................................................................... 78 

13.1 Implementation Process................................................................................................ 79 

13.2 Demonstration Site One - Encorp Headquarters........................................................... 82 

13.2.1 Site Description..................................................................................................... 82 

13.2.2 Advanced Controller Design of Site..................................................................... 83 

13.2.3 Results of Testing ................................................................................................. 85 

13.3 Demonstration Site Two - The Aquarium of the Pacific .............................................. 87 

13.3.1 Advanced Controller Design at Site ..................................................................... 88 

13.3.2 Results of Implementation / Testing..................................................................... 91 

14. Appendix J: IEEE Standards Activities.............................................................................. 93 

List of Figures

Figure 1: Typical Interconnection of Distributed Power Device................................................... 5 

Figure 2: Moving to a Digital Platform .......................................................................................... 8 

Figure 3: Moving to a Digital Based Platform................................................................................ 9 

Figure 4: PSM without Cover....................................................................................................... 12 

Figure 5: Chowchilla 48-MW Power Plant ................................................................................. 15 

Figure 6: Advanced Controller for Qualification Testing............................................................. 17 

Figure 7: Systems Test Facility at Encorp .................................................................................... 18 

Figure 8: Advanced Controller Production Tester....................................................................... 18 

Figure 9: EMC System Architecture............................................................................................. 20 

Figure 10: Demonstration Site One - Encorp Headquarters......................................................... 22 

Figure 11: Demonstration Site Two - Aquarium of the Pacific.................................................... 23 

Figure 12: Base Year Product Life Cycle Development Activity ................................................ 30 

Figure 13: Option Year 1 Product Life Cycle Development Activity.......................................... 31 

Figure 14: Moving to a Digital Platform ...................................................................................... 32 

Figure 15: Moving to a Digital-Based Platform ........................................................................... 33 

Figure 16: Control System Architecture....................................................................................... 34 

Figure 17: The Data Acquisition System...................................................................................... 35 

Figure 18: Advanced Controller Hardware................................................................................... 36 

Figure 19: Digital Upgrade PCA Board........................................................................................ 37 

Figure 20: Improved Accessibility of Advanced Controller......................................................... 38 

Figure 21: Communications Ports Layout .................................................................................... 39 

viii
Figure 22: Relative Complexity and Capability of Communication Standards (Burns, et al.) .... 52 

Figure 23: Typical Chowchilla II Two-Engine Configuration ..................................................... 54 

Figure 24: Chowchilla II Protective Relaying Scheme................................................................. 55 

Figure 25: VMM User Interface ................................................................................................... 58 

Figure 26: Example One-Line Diagram ...................................................................................... 59 

Figure 27: Generator Room Display............................................................................................ 59 

Figure 28: Generator Annunciator Display.................................................................................. 60 

Figure 29: Generator Metering Screen ......................................................................................... 60 

Figure 30: Market Analysis ........................................................................................................ 72 

Figure 31: EMC System Architecture.......................................................................................... 73 

Figure 32: Standard EMC Reports............................................................................................... 76 

Figure 33: Demonstration Site One - Encorp Headquarters........................................................ 83 

Figure 34: Demonstration Site One - Graphical Representation ................................................. 84 

Figure 35: Demonstration Site Two - Aquarium of the Pacific.................................................... 87 

Figure 36: System Layout............................................................................................................. 88 

Figure 37: One-Line Diagram....................................................................................................... 89 

Figure 38: Communications Diagram........................................................................................... 90 

List of Tables

Table 1: PSM Measured Parameters............................................................................................ 48 

Table 2: PSM Three Phase Parameters........................................................................................ 49 

Table 3: Unit Testing Results ...................................................................................................... 62 

Table 4: System Bench Testing Results....................................................................................... 63 

Table 5: Dielectric Strength Tests................................................................................................ 64 

Table 6: Typical EMC Parameters............................................................................................... 75 

Table 7: Demonstration Checklist ............................................................................................... 79 

Table 8: System Performance Data.............................................................................................. 91

ix
x
1. Introduction

1.1 Background 

Various industries, companies, and organizations have worked for decades to develop 

technologies and products to facilitate the growth of the distributed power (DP), or distributed 

generation (DG),1

 industry. Interest in the use of DG and storage has increased substantially over 

the past 5 years because of its potential to increase reliability and lower the cost of power 

delivery to the customer, particularly with customer-sited generation. The advent of competition 

and customer choice in the electric power industry has, in part, been the stimuli for this increased 

interest. These technologies can offer additional environmental benefits by utilizing renewable 

resources, such as biomass, and by employing combined heat and power systems that increase 

the overall efficiencies of the energy system. Also contributing to this trend has been the 

development of small, modular generation technologies, such as photovoltaics, microturbines, 

and fuel cells. 

 

DP will be a key ingredient in the reliability, power quality, security, and environmental 

friendliness of the electric power system. By supporting customer choice, distributed power may 

be the long-term foundation for competition in the electric power industry. 

The application of distributed generation technologies can bring many benefits. To realize these 

benefits and avoid negative impacts on system reliability and safety, the operational concepts to 

properly integrate them into the power system must be developed. The current power 

distribution system was not designed to accommodate active generation at the distribution level, 

particularly exporting power to other distribution customers. The technical issues of allowing 

this type of operation are significant. For example, control architectures that ensure safe and 

reliable DP operation, and that exploit the potential of DP to provide grid support, will require 

modernized system-protection design enhancements. This may require large amounts of 

information to be fed to advanced, intelligent local controllers that act quickly and operate local 

distribution areas for both local- and distribution-level benefits. New system architectures and 

enabling hardware and software will need to be developed.

Electricity regulation, zoning and permitting processes, and business practices that were 

developed under the old framework — an industry based on central-station generation and the 

ownership of generation facilities by regulated monopolies — can be barriers to the orderly 

development of market opportunities for DP in a restructured electric power industry. 

The system integration issues related to DP are national issues that cut across a number of 

industries. By bringing together these various parties — hardware manufacturers (of 

photovoltaics, wind turbines, fuel cells, gas turbines, batteries, etc.), utilities, energy service 

companies, codes and standards organizations, state regulators and legislators, and others — 

there is a significant opportunity to address the technical, institutional, and regulatory barriers to 

distributed power. In fact, these very groups are working together on the technology and 

infrastructure issues. 

 

1

 Although no uniform definition applies, distributed power and distributed generation generally refer to small 

power facilities of 10 MW or smaller. 

1
This contract pursues technology development that will alleviate infrastructure barriers to DP. 

Under this contract, enabling hardware, control logic, and communications capabilities were 

developed, demonstrated, and validated in conventional and emerging DP technologies and 

products. The contract’s success is the result of focusing on key enabling technologies and 

features built into system-level integrated solutions that work for customers and other 

stakeholders and participants in the DP market. These technologies and features have facilitated 

market participants to more fully capture and realize the benefits of DP products. 

GTI's efforts to develop advanced grid interconnection products began in 1985 with 

benchmarking, surveying electric utilities for technical requirements, and performing 

distribution-level power system simulation studies. That effort yielded the first commercial 

multifunction solid-state protective-relaying package using digital signal processing (DSP) 

technology. Those efforts included joint testing with electric utilities to address new technology 

adoption challenges (e.g., the reluctance to shift from "tried and true" conventional 

electromechanical protection devices to integrated solid-state electronic equipment). Since being 

introduced, thousands of these multifunction protective-relaying systems have been used in DP 

system applications. Many companies followed suit with similar products, and electric utility 

acceptance increased tremendously for the new technology. That effort resulted in millions of 

dollars of capital, engineering, and maintenance cost savings and helped enable small DP and 

cogeneration projects to move from concept to reality. 

As we head into the next decade, there is a critical need to support enabling technology that 

benefits increasingly smaller and more diverse DP products and that allows for interoperability 

between the DP source or sink and the grid. Because of the increased competition brought on by 

utility restructuring, the market will increasingly demand lower costs and more features (i.e., 

more value) from DP projects. Meeting these demands is essential to increasing the appeal and 

market acceptance of these systems. 

The integration of a host of discrete DP generators into state-of-the-art Virtual Power Plants will 

be a major market achievement. Transparent solutions that can be employed with a diverse array 

of DP technologies and products will lead this movement. That application space includes: 

• Conventional technologies (engines and turbines) using conventional fuels (natural gas and 

diesel) and unconventional fuels (waste fuels such as landfill gas) 

• Emerging technologies (microturbines and fuel cells) operating on conventional and 

unconventional fuels 

• Renewable technologies such as wind, solar, and small hydropower systems 

• Small-scale cogeneration or combined heat and power (CHP) applications such as backpressure turbines (BPT) that can be affordably connected 

• Enabling the aggregation of DP capacity and energy to provide valuable ancillary services at 

the distribution and transmission level 

• Enabling command and control strategies essential for the integration of DP into grid 

operations 

• Energy management systems. 

2
1.2 Distributed Power Problem Statement 

During the course of the past two decades, the independent power industry has thrived in the 

United States — at least for larger systems. Multi-megawatt simple-cycle and combined-cycle 

gas turbine power systems are the dominant technology choice for new power generation 

investments because of their favorable attributes of low cost, high efficiency, low emissions, and 

speed of project construction. In contrast, the market for small-scale power generation has not 

developed very substantially over this period. 

There are many causes for the lagging nature of the DP market, including negative scaling 

effects for small power systems (i.e., higher cost per kilowatt with decreasing size), legitimate 

technical issues, inadequate product choices, and competitive responses from electric utilities. 

Examples of electric utility efforts to limit small DP market growth include long approval times 

and high costs for electric power system interconnection, special incentive rates to prevent 

customer loss, and high fees for standby power. More examples are contained in “Making 

Connections: Case Studies of Interconnection Barriers and their Impact on Distributed Power 

Projects” (NREL/SR-200-28053). 

This National Renewable Energy Laboratory (NREL)/Department of Energy (DOE) report 

identified a 10-point action plan for addressing barriers to expanded DP use: 

1. Adopt uniform technical standards for interconnection of distributed power to the grid. 

2. Adopt testing and certification procedures for interconnection equipment. 

3. Accelerate development of distributed power control technology and systems. 

4. Adopt standard commercial practices for any required utility review of interconnection. 

5. Establish standard business terms for interconnection agreements. 

6. Develop tools for utilities to assess the value and impact of distributed power at any point on 

the grid. 

7. Develop new regulatory principles compatible with distributed power choices in both 

competitive and utility markets. 

8. Adopt regulatory tariffs and utility incentives to fit the new distributed generation model. 

9. Establish expedited dispute resolution processes for distributed generation project proposals. 

10. Define the conditions necessary for a right to interconnect. 

Through NREL, DOE took steps to address these and other barriers to DP market growth 

through research, design, and development (RD&D) initiatives. An NREL 3-year competitive 

solicitation requiring cost sharing was won by GTI and Encorp to address technical development 

activities directly in support of action items 1 through 3 above. The result of the Base Year and 

Option Year One of contract work toward these objectives is the subject of this report. Other 

parallel DOE/NREL efforts are under way to address these and other action items. These efforts 

hold significant promise for reducing the barriers to DG and CHP system use in the United 

States. 

1.3 Interconnection Controller Problem Statement 

As noted, many existing and emerging DP technologies suffer from relatively high total installed 

costs (in dollars per kilowatt). This is due in part to physical costs for interconnection equipment 

(e.g., switchgear, protective relays, and controls) as well as high “transaction costs” of working 

3
with utilities and other parties to permit equipment for grid interconnection. These costs can 

escalate as the functionality of a DP installation strives to meet higher-level objectives, such as 

integrating and interacting with the electric power system (and its supervisory control systems) 

or with building energy management systems. In many instances, the small size of DP systems 

makes it difficult to justify the added cost for networking and customizing a product to a 

particular application. In addition, the small scale of many DP projects places them below de 

minimis size limits that distribution or transmission operators deem worthy of consideration. 

These factors make it difficult for small DP systems to provide value-added benefits to the 

electric power system (at least benefits that are monetized). This situation negatively affects the 

economic value of DP technologies — even though their aggregate capabilities have the 

potential to offer real benefits to the grid. 

The DP industry also faces loss in value because of the inability of various products to work 

together. Lack of cross-platform compatibility exists among products ranging from turbines to 

engines, steam turbines, microturbines, fuel cells, wind turbines, photovoltaic systems, power 

quality systems (batteries and flywheels), and heat-recovery devices. This means that system 

integrators miss the potential for pooling resources in a manner similar to the Virtual Power 

Plant concept (where a number of smaller generators can be networked together and controlled to 

provide the equivalent of a multi-megawatt power plant or load center). A system integrator that 

can pool resources will be better positioned to provide valued services that will earn an economic 

return. 

Encorp Power control systems and Virtual Power PlantTM software greatly simplified the task of 

managing and controlling a large number and wide variety of distributed resources — including 

engine generator sets, microturbines, fuel cells, wind turbines, and energy storage devices. 

 

The current Encorp generator power control (GPC), with the power transfer control-enabled 

configuration, provides safe, reliable transfer of power between a single generator and the utility 

grid. Standard options include a wide variety of traditional control modules and opencommunication protocols integrated into a single unit. The Encorp GPC with the kilowatt 

sharing-enabled configuration provides reliable paralleling of multiple generators. Combined 

with the Encorp utility power control (UPC), the kilowatt sharing-enabled GPC provides 

synchronizing and paralleling of multiple generators to the utility grid. 

Although these products provide satisfactory features and value to customers today, a number of 

additional desirable features and functionalities are not resident in the existing GPC or 

competitor products. Research and design efforts are needed to provide greater functional 

integration, switchgear design simplicity, and cost reduction for the customer. Example needs 

include features to meet advanced communications, diagnostics, monitoring, and relay function 

expectations of customers as well as to ensure compliance with anticipated future 

interconnection standards within IEEE 1547. 

A primary motivation for the IEEE 1547 standard is the desire of many market participants to 

rationalize and simplify the process for interconnecting a DP device with the electric power 

system. The following figure illustrates a typical interconnection scheme for a DP device with a 

generation source (labeled GS in Figure 1) supplying power at a customer site. In many 

4
instances, the generation source is sized to meet a portion of the customer’s peak power needs. 

Electricity is often not exported in this type of arrangement, but it could be in some instances. 

The generation source may also be used to provide emergency power in the event of loss of 

electric service. 

Substation

Utility Distribution Line

Transformer

Visible

Disconnect

Switch

Circuit

Breaker

CT

PT

GS

32

VAR

Controller

PT

25

27/

59

81

O/U

Legend

Required Interconnection 

E i *

25 Synchronizing 

27/59 Under/Over Voltage 

81O/U Over/Under Frequency 

 -- Visible disconnect 

 -- Potential, Current 

(as needed).

Suggested Operational Items:

(not required)

32 Directional Power 

 -- VAR Controller. Adjustable 

for synchronous generators.

* List will vary by site.

Shaded Region:

Basic Requirements for

Interconnection

Site

Load

Figure 1: Typical Interconnection of Distributed Power Device 

The IEEE 1547 standard is intended to be a performance-based document rather than a 

prescriptive document that lays out specific relay functions that must be incorporated into a 

device. This approach is in line with the evolution of the market during the past decade from 

discrete electromechanical relay devices toward integrated multifunctional, microprocessorbased interconnection and control systems that can perform a number of operations through 

control algorithms. 

With the move toward performance-based standards, however, there is a desire to enable DP 

controller devices with higher-level functionality and safety features. For example, a concern 

among utilities is what happens to a DP generation source when a fault occurs on the utility 

distribution line (or electric power system). If a utility line breaker is open because of a 

temporary fault and subsequently reclosed, the DP device may inadvertently continue operating 

and be out of phase when the primary source is restored. In a worst-case scenario, a DP 

generation source may inadvertently supply power to a line that a service person thought was not 

energized. 

5
These types of scenarios are raising expectations that DP products will provide higher levels of 

processing performance and control sophistication to address a range of issues that goes beyond 

conventional over and under voltage and frequency detection. A key element of this contract is 

the development of a high-performance computing platform that will allow high-speed 

monitoring and detection of system fault conditions and use of sophisticated algorithms that can 

address the host of potential application requirements for interconnecting a DP source into 

electric power systems. 

2. Contract

2.1. Contract Overview 

To address the technical and market needs of the evolving DP market, GTI and Encorp identified 

a multiyear plan. This effort began with the development of a new and significantly enhanced 

core controller technology and evolved into the development and demonstration of higher-level 

controls, software, communications capability, and functionality that captures the objective of 

improving the DP value proposition. In parallel, Encorp supported the development of the DG 

interconnection standards development — notably, the IEEE 1547 series of standards. 

 

The specific tasks that were performed as part of this contract are as follows: 

Contract Tasks 

Task 1: Develop Prototype Advanced Controller 

Task 2: Develop Prototype Power Sensing Board 

Task 3: Expanded Suite of Communication Capabilities 

Task 4: Interface for Revenue-Grade Meter 

Task 5: Demonstrate Interconnect DP Device 

Task 6: Type Testing 

Task 7: System Command and Control 

Task 8: Demonstration of Controlled DP Resources 

This report provides a brief summary of each task Statement of Work (SOW) and technical 

results achieved on this contract. It references appendices that include additional details. This 

approach allows the reader to get a good overview of the contract and to allow in-depth coverage 

if the reader chooses to read more on a particular topic. Also included is a brief overview of the 

technical topics covered to orient the reader prior to covering the specific tasks. 

2.2. Product Development Methodology 

Today’s business environment can be characterized by complexity, and the acceleration of 

everything from customer demands to production methods to the rate of change itself. In the 

face of these demands, organizations must continue to develop and deploy high-quality products 

that meet the customers’ needs. Organizations use development and business processes to help 

6
achieve success. However, if the organization and management of people and processes breaks 

down, the net effect is reduced product quality. 

Encorp analyzed numerous successful products that were being used throughout the electrical 

power industry and one key attribute was always evident: quality. The power industry demands 

even more quality from products than do several other industries. Products are expected to 

operate as anticipated in harsh environments, to be self-sufficient and reliable without 

maintenance for long periods of time and to work flawlessly when needed. 

Refer to Appendix A for additional details on the product development methodology. 

2.3.System Architecture Technical Approach 

Traditionally, when deploying power systems, several discrete analog devices would serve 

singular functions in the power system and would need to be integrated together for the system to 

function properly. This equipment is sometimes referred to as “custom” paralleling switch gear. 

Making all the different devices work together in a coordinated fashion is very difficult, 

cumbersome, prone to errors, and labor intensive. Each system deployed in this manner will be 

slightly different because of varying site, customer, and regulatory requirements. This adds to 

the complexity of the systems and increases the cost of deployment and maintenance by 

increasing the labor effort associated with each system’s design, manufacturing, and deployment. 

In addition, the collection and reporting of data from the numerous devices, (often analog 

devices) in the traditional switchgear breaks the chain of information. And breaking the 

information path impairs implementation of an intelligent DP system. 

Encorp’s new Advanced Controller approach, developed as part of this contract, is to take the 

functionality that the analog devices provided and build them into software on a digital controller 

platform. This allows the “customization” of this equipment to be largely a configuration effort 

performed in software. The software reduces costs considerably during the design, assembly, and 

support phases of a project. This approach also provides additional user benefits in a simple user 

interface, greater built-in functionality, additional communications capabilities and remote 

monitoring as well as remote command and control functionality (Figure 2 and Figure 3 further 

highlight this philosophy). 

7
Traditional Method (Analog) Digital Solution 

Figure 2: Moving to a Digital Platform

8
Figure 3: Moving to a Digital Based Platform 

Refer to Appendix B for additional details on the system architecture. 

3. Summary of Tasks and Results

3.1. Task 1 - Develop Prototype Advanced Controller 

Task 1 - SOW Summary 

The SOW description follows. 

This task is to develop a prototype controller by redesign of existing GPC product 

hardware to achieve even greater functional integration, cost reduction, and switchgear 

design simplicity than conventional products. This shall be achieved by incorporating an 

enhanced microprocessor, input/output (I/O) and communications features and 

capabilities; reallocating the circuit board functionality to incorporate basic monitoring, 

protection, and control features for the distributed power resource; as well as built-in 

Internet communications (rather than using a separate "gateway" as in the current 

architecture). 

9
All necessary paralleling functions shall be further integrated into a single hardware 

device with extremely flexible object-oriented software for customizing the particular 

power system application (instead of customizing the switchgear cabinet hardware for 

every different site through many hours of engineering and custom manufacturing, 

assembly, and wiring). 

 

Task 1 - Summary of Accomplishments 

The prototype controller module is the repository for firmware that coordinates the logic, 

features, functions, programmability, adaptability, and versatility of the Encorp GPCs. To 

provide price point and feature flexibility, the controller is designed to be flexible and 

expandable to meet the needs of both small and large DP equipment. 

The CPU is the main processing element and communications hub. It incorporates a highperformance but cost-effective processor operating at sufficiently high processing speed to 

support the growing processing demands of DP applications and increased communications 

capabilities. It includes extensive memory support — including the capability to expand storage 

to support features such as data logging and trending. 

The processor section of the prototype controller has extensive communications capabilities 

required by current and future applications. These capabilities include supporting LONWORKS, 

100 Base-TX Ethernet, Controller Area Networks (CAN) interfaces, RS-232/485, and Modbus 

communications. The controller is designed to be flexible enough to handle a variety of other 

communications capabilities. The flexible memory design will allow the controller to expand or 

extend to meet a variety of future product features and applications. The controller has a 

watchdog timer and real-time clock. 

With respect to interconnection, the prototype Advanced Controller design incorporates (among 

other features) the following functions2

: 

• Sync check (25) 

• Autosynchronizer (25 A) with voltage matching, two modes available: frequency and phase 

matching and slip frequency. 

• High-speed (160 millisecond) over/under voltage for generator and utility tie (27/59) 

• High-speed (160 millisecond) over/under (O/U) frequency for generator and utility tie (81 

O/U) 

• Directional power (32) 

• Directional reactive power (32 VAR) 

• Reverse-phase/phase-balance current (46) 

• Phase sequence voltage (47) 

• Voltage-restrained over current (51V) 

• AC time over current (51N) 

• Anti-islanding relay 

 

2

 IEEE Std C37.2 – 1996 (Reaff 2001), IEEE Standard Electrical Power System Device Function Numbers and 

Contact Designations 

10
• Loss of synchronization relay (required for applications with stiffness ratio of 20 or less) 

• Over-current relay (required for over 2megavolt-ampere [MVA] units) 

• Form-C contact outputs 

Refer to Appendix B for additional details on the product system architecture. 

Refer to Appendix C for additional details on the Advanced Controller design. 

3.2. Task 2 - Develop Prototype Power Sensing Board 

Task 2 - SOW Summary 

The SOW description follows. 

This task includes determining the functional requirements for a prototype power sensing 

capability, and designing, developing, and testing this prototype power sensing 

functionality. This prototype power sensing board will significantly enhance the ability 

of the controller to fully comply with all interconnection requirements. Primary 

attributes of the new power sensing board will be a simpler design (for lower cost and 

end-user price) and ease of installation. It needs to be capable of supporting three phases. 

The design approach of the power sensing board shall provide the necessary 

computational support and high-data bus structure that enables interconnections 

compliant with existing standards. 

Task 2 - Summary of Accomplishments 

The power sensor module (PSM) design is a stand-alone intelligent module powered by highpower DSP technology (Figure 4). The primary purpose of this module is to interface with 

multiphase voltage (potential) and current transformer inputs. This module will perform 

extensive signal processing, manage the input information, and transfer the resulting values to 

the controller module. This encompasses various electric power issues related to real and reactive 

power as well as harmonics. 

11
Figure 4: PSM without Cover 

In addition, this module contains relay outputs for circuit breaker close/open control, digital 

inputs for auxiliary contact feedback, and solid-state digital outputs for relay targets or secondary 

circuit breaker control. 

The prototype PSM module design has sufficient memory to allow up to 64 cycles of waveform 

information to be buffered to support an event-reporting application. In addition, the power 

sensor module software performs several high-speed protective relay functions (e.g., over/under 

voltage [27/59], over/under frequency [81 O/U], sync check [25], and loss of synchronism relay 

[78]). 

Refer to Appendix D for additional details on the Prototype Power Sensor Module. 

3.3. Task 3 - Expanded Suite of Communication Capabilities 

Task 3 - SOW Summary 

The SOW description follows. 

A key element of the Advanced Controller design is developing an enhanced set of 

communications capabilities. This includes multi-directional communications to: other 

DP units at the local site; facility energy management systems; monitoring, display and 

analysis programs at the local site; remote dispatch, metering, billing, and alarming 

systems; and service providers. 

Task 3 - Summary of Accomplishments 

A critically important element of this development effort is the incorporation of an expanded set 

of communication capabilities into the Advanced Controller. These capabilities include 

communication pathways to tie into existing and future energy management systems, electric 

utility command and control centers, independent system operator (ISO) and regional 

12
transmission operator (RTO) organizations, and other participants. Communication technology is 

seen as an essential element of the long-term DG value proposition. 

With regulatory and legislative changes transforming the electric power industry from a 

monopolistic to a deregulated and competitive industry, there is increasing need for information 

and data exchange among open systems and interoperability across multivendors’ hardware. An 

example of this type of information exchange is contained in a key American Society of Heating, 

Refrigerating, and Air-Conditioning Engineers Inc. (ASHRAE) report produced by Martin Burns 

and Michael Kintner-Meyer. They identified the following as key communication information 

services: 

1. Revenue meter reading (electricity, gas, water, steam) 

2. Quality of service monitoring 

3. Real-time-pricing transmission 

4. Load management service 

5. On-site generation supervisory control 

6. Energy-efficiency monitoring 

7. Weather reporting and forecasting services 

8. Indoor air-quality monitoring 

9. Dynamic demand bidding into a power exchange. 

What is significant about these findings is that nearly all these services, with the exception of 

Item 8, can be provided by Advanced Controllers for DG. 

Refer to Appendix E for additional details on communications. 

3.4. Task 4 - Interface for Revenue-Grade Meter 

Task 4 - SOW Summary 

The SOW description follows. 

The Advanced Controller needs an interface for revenue-grade meters. This interface 

shall accommodate the numerous legacy meters in use as well as new bus-enabled 

metering devices. In addition to being able to perform all of the metering calculations to 

the requisite accuracy, the interface should also affordably access the revenue-grade 

meter information most DP deployments will require. The necessary interfaces shall be 

built into the hardware platform and software architecture. 

Task 4 - Summary of Accomplishments 

The specification of the controller includes the ability to interface with existing (or “legacy”) 

electricity meter devices as well as the ability to provide stand-alone revenue-grade meter 

information. 

13
With respect to interfacing with existing meters, the intent is initially to incorporate features 

common to the most widely used electric demand meters. Electric demand meters can include, or 

be modified to include, a pulse output. This is often done using what is referred to as a Form C 

relay, also known as a KYZ relay. In this nomenclature, the K is usually the common of a singlepole, double-throw (SPDT) relay, the Y contact is normally open, and the Z contact is normally 

closed. The relay device changes state between open and closed with each rotation (or partial 

rotation) of the meter disk. The KYZ output is also referred to as a pulse meter. With input on 

various factors associated with the meter device, the KYZ output can be used to provide revenuegrade information on power and energy usage. The meter design specification incorporates the 

ability to interface with KYZ-based meter signals. 

In addition, the prototype PSM design of the new controller has revenue-grade metering 

capabilities. The controller is designed and will be tested to the power and energy accuracy 

requirements of ANSI C12.20-1998, Accuracy Class 0.5. 

3.5.Task 5 - Demonstrate Interconnect DP Device 

Task 5 - SOW Summary 

The SOW description follows. 

This technology is seen as having application in large commercial, institutional, and 

industrial facilities as well as in small-scale biomass energy plants. Verify the 

functionality of the Advanced Controller, including the communications capabilities 

developed in tasks 1-4 in an operational setting. This task will demonstrate the benefits 

that will be derived from deploying the prototype Advanced Controller in a real world 

setting. 

GRI will work with EPRI to leverage efforts on addressing advanced communication 

needs for DP systems. 

Task 5 - Summary of Accomplishments 

To document the first-hand market issues with the interconnection and communications of DP 

systems, a system case study was done on the Chowchilla II power generation station in 

Chowchilla, California. Encorp Inc. designed the controls and switchgear system for this 

complicated plant. The Chowchilla II system is a prototype version with some of the features and 

functions that would be implemented on the production version of the Advanced Controller 

being developed. This prototype hardware is not integrated in the same manner as planned on the 

Advanced Controller but serves as a model for the capabilities that would be integrated into the 

Advanced Controller. 

The Chowchilla II power plant (Figure 5) is a 48-MW facility powered by 16 Duetz natural gasfueled generator sets operating in parallel with the local utility. The plant is owned by NRG 

Energy and operated by NEO, a subsidiary of NRG Energy. The power facility, although located 

in California, is dispatched by NRG from offices in Minneapolis, Minnesota. The plant is 

14
dispatched based on receiving a call from PG&E or in response to area energy pricing signals. 

The California ISO monitors the facility to determine capacity effect and demand scheduling. 

Figure 5: Chowchilla 48-MW Power Plant 

Individual generator power measurements are made by the Encorp controllers in the system. The 

power data is gathered and ultimately passed up to the communications processing modules 

(CPMs) in each system and sent to NRG and the California ISO for their use. 

The Encorp communications system at the Chowchilla power generation facility brings together 

various software, system, and network topologies. As a result of this effort, the following results 

are realized. 

• On-Site Generation Supervisory Control

Supervisory control of the on-site generation is provided by the Encorp UPC/GPC controls 

and the local or remote desktop workstation (DWS). Supervisory control includes 

remote/local system dispatch, alarm monitoring and trending, event trending, dial out alarm 

notification, local/remote generator power level settings, and system power-level monitoring. 

• Generator Status/System Status Monitoring 

The Encorp controls allow local and remote monitoring of a multitude of generator and 

system data points. These points include: 

o Inlet/Exhaust temperature 

o Coolant temperature 

o Crank case pressure 

o Starting air pressure 

o Lube oil pressure (before and after filter) 

o Lube oil level 

o Supply voltage 

15
o Throttle position 

o Engine speed (revolutions per minute [RPM]) 

o Generator bearing temps 

o Generator winding temps 

o Generator inlet/outlet air temps 

o Combustion chamber temperatures 

o Gas valve positions. 

• Load Management Service

Because this site is used exclusively for supplementing the existing distribution capacity, 

load management is limited to the ability to adjust the base load reference of the individual 

generators from a local or remote location via the DWS. Generator power limits and active 

demand levels are also available at the local or remote DWS. 

• Indoor Air Quality Monitoring

Indoor air temperatures are measured and ventilation fans are operated automatically from 

the Encorp UPCs based on the air temperature of the facility. 

• Revenue Meter Reading

This site did not incorporate revenue meter reading in the Encorp system. Revenue meter 

reading was integrated into the ISO distributed power generation hardware. However, the 

Encorp system is fully capable of receiving either real or pulse (KYZ) meter information and 

displaying the resultant demand information from those sources. 

• Energy-Efficiency Monitoring

The Chowchilla power station did not require energy-efficiency monitoring. If at some point 

in the future there is a need for efficiency monitoring (heat rate versus kilowatt-hours), the 

Encorp software could be easily modified to provide such information. 

• Weather Reporting and Forecasting Services

There were no requirements for weather reporting or forecasting services data or I/O for the 

operation of the Chowchilla project. 

California ISO Data

Numerous monitoring and control points are sent from the Encorp communications system to the 

California ISO via the DPG. A listing of all these points can be found in the California ISO DPG 

Technical Specifications via their Web site at www.caiso.com. 

Refer to Appendix F for additional details on the prototype Advanced Controller in the 

Chowchilla, California power plant. 

16
3.6. Task 6 - Qualification and Testing of the Advanced Controller 

Task 6 - SOW Summary 

The SOW description follows. 

This task aims to ensure the overall quality of the Advanced Controller. Because of the 

critical nature of the DP systems the Advanced Controller will be managing, and the 

danger involved in having failures, a great deal of time and effort was devoted to 

ensuring the overall quality, reliability, and stability of the Advanced Controller. A test 

plan shall be drafted and then finalized that addresses the necessary environmental and 

functional test requirements. The type testing shall include complete written reports 

documenting the technical and environmental conditions and performance, test evaluation 

criteria, and, analysis of, and recommendations concerning, the adequacy of the test plan. 

Task 6 - Summary of Accomplishments 

Type testing of a new product is really a subset of the main area of concern, which is the overall 

quality of the product being developed. Encorp went beyond the original scope of the contract in 

ensuring quality through an exhaustive regiment of testing in all phases of the product lifecycle. 

Quality really starts during the design phase and involves manufacturing, suppliers, customers, 

engineering, type testing, bench testing, system testing, on-going reliability, and an approach to 

handle any field failures. The product should be engineered to meet or exceed the identified 

quality requirements in all of these areas. Figure 6 depicts the Advanced Controller used for 

qualification testing.

Figure 6: Advanced Controller for Qualification Testing 

The quality of a product requires a systems approach over the life cycle of the product, from 

development through field reliability. This starts during the engineering phase using tools such as 

good requirements documents that are agreed to by the entire organization. The requirements are 

implemented utilizing a structured design methodology and simulation of the design where 

possible. During the design stage the overall goal is to perform an evaluation of critical signals, 

stack up tolerances, and create a product with some design margin in it. An early transition of 

firmware to the target system allows continuous board and code testing during development that 

improves the overall product stability. These tests are followed with further critical tests that are 

17
performed on the engineering units, correcting issues that are identified prior to initiating the 

certification testing. Finally, performing the certification tests on products that have been 

produced from the planned production line can ensure a product that meets the requirements 

identified and that meets the market demands for a high quality, reliable product. (Figure 7 

shows the test facility at Encorp) 

Figure 7: Systems Test Facility at Encorp 

The overall test approach has been summarized as follows: 

• Engineering development tests (critical path analysis, design margin, firmware 

verification, etc.) 

• Bench tests (subsystems/functions, systems single/multiple controllers, etc.) 

• Production tests (ICT, Functional – board/module, calibration, burn-in, FGA, on-going 

reliability; Figure 8 shows the Advanced Controller Production Tester) 

• Systems tests (subsystems/functions, on-generator, multiple generators, various control 

modes and applications) 

• Certification Testing on production units “Type Tests” (IEEE, UL, ANSI, IEC). 

Figure 8: Advanced Controller Production Tester 

The key is to develop a strategy to address each of these areas to ensure the highest quality 

during each phase of the product’s lifecycle. For each test performed, testers wrote a detailed 

test procedure and test report. 

18
Refer to Appendix G for additional details on testing and qualification of the Advanced 

Controller. 

3.7. Task 7 - Develop System Command and Control 

Task 7 - SOW Summary 

The SOW description follows. 

Develop and deploy the software and communications systems that surround the 

Advanced Controller and allow remote monitoring as well as command and control of the 

DR unit. These software systems need to remotely interact with the Advanced Controller 

to enable the transfer of critical information for monitoring and to enable the controls to 

remotely dispatch the DP systems. 

Task 7 - Summary of Accomplishments

Encorp developed the Energy Management Center (EMC), a fully functional command and 

control system that allows customers to monitor, analyze, and control DG assets via a secure 

Web-based interface. 

When approaching this task, Encorp completed several design-related activities to obtain the 

most complete understanding of what software and communications subsystems were to 

surround the Advanced Controller to further enhance its functionality and overall quality. These 

activities included a detailed communications study, research and testing surrounding IT related 

security, and a comprehensive market analysis to enable a better understanding of the industry 

climate. This included detailed analysis of the broad range of DG projects that Encorp had 

implemented to date. 

The knowledge gained while completing these activities was used to design, develop, and deploy 

the command and control system (EMC). Figure 9 portrays the EMC communications 

architecture. The EMC has been released into production as a commercial product and is being 

utilized by several customers, including the demonstration sites discussed later in this report.

19
Figure 9: EMC System Architecture 

Additionally, Encorp spent a considerable amount of time and resources to gather information 

regarding communications, security, and market conditions to ensure the overall quality of the 

EMC and the Advanced Controller. This information and the EMC system description are 

summarized in this report as well as a more detailed report that was completed earlier as part of 

this contract entitled “Distributed Generation Advanced Communications Study (ACL-1-30605-

04)”. 

Refer to Appendix H for additional details on System Command and Control architecture. 

20
3.8. Task 8 - Demonstration of Controlled DP Resources 

Task 8 - SOW Summary 

The SOW description follows. 

Deploy and demonstrate the Advanced Controller in two diverse commercial 

demonstration sites. The demonstration shall use several physically separate, gridconnected DP resources to demonstrate the ability to provide autonomous site control, 

scheduled control from a dispatch center, and real time data monitoring and asset control 

from a network operations center that is representative of DP operations in a commercial 

environment. The DP resources shall be operated in accordance with commercially 

useful practices and the necessary monitoring of distribution operations shall be 

coordinated to determine the nature of any operational impacts. 

Task 8 - Summary of Accomplishments

The final task to be completed was the demonstration of the Advanced Controller and EMC 

outside of the lab environment in an “uncontrolled” commercial deployment. To be sure that the 

Advanced Controller was adequately tested in this manner, the evaluation and selection of an 

appropriate demonstration site was essential. It was decided to utilize two demonstration sites to 

ensure broad coverage of commercially representative conditions. 

Establishing the two ideal demonstration sites was based on the following selection criteria. 

• Location of site 

o The site needed to be easily accessible by the development staff and the 

operations engineering staff to ensure a fast response to any problems. 

Locations that had enhanced security with restricted hours were not 

considered. 

o Testers targeted sites that represented a geographical marketplace where DG 

is prevalent to ensure a demonstration site that would be representative of the 

customers of the Advanced Controller. 

• Customer selection 

o It was important to select appropriate customers who would allow testers to 

utilize their sites and in some cases their customer’s sites. 

o The customers needed to understand the benefits of the Advanced Controller 

and be willing to accept the risk if the demonstration did not go smoothly. 

• Retrofit 

o It was decided to do the demonstration at two DG sites in which earlier 

generation Encorp controls were already deployed. This would allow a 

comparison of the existing structure with the Advanced Controller. 

21
o Sites that were using the EMC prior to deploying the Advanced Controller 

were selected to have a “before” and “after” site profile based on the 

information that was being gathered through the EMC. 

• Compliance with National Environmental Policy Act (NEPA) 

These commercial sites were carefully selected to be representative of the current market place. 

Once the Advanced Controller was installed at these sites, testing and remote performance 

monitoring and analysis were performed. 

Based on these criteria, the first site was Encorp’s Headquarters in Windsor, Colorado, and the 

second demonstration site was the Aquarium of the Pacific in Long Beach, California, in 

partnership with City Light and Power in Long Beach. 

Demonstration Site One - Encorp Headquarters 

Encorp’s headquarters in Windsor, Colorado, was built and opened in 2001. The facility has 

80,000 square feet that includes manufacturing facilities, office space, and a small data center. 

The facility utilizes power that is being distributed by Xcel Energy. The facility uses one Detroit 

Diesel Generator with a nameplate capacity of 535 KW to provide backup power in case of a 

utility outage. Due to the need for reliable power for the small data center, the site is 

representative of a critical power application that would be analogous to a telecommunications 

center or a hospital. 

Figure 10: Demonstration Site One - Encorp Headquarters 

Demonstration Site Two - The Aquarium of the Pacific 

The second demonstration site was the Aquarium of the Pacific (AOP) in Long Beach, 

California. AOP is one of the largest aquariums in the United States. It is home to more than 

12,000 ocean animals that represent more than 1,000 different species. The beautifully 

architected 156,735-square-foot building is right next to the Pacific Ocean on the west side of 

downtown Long Beach. AOP was visited by over 1.1 million people in 2003, making it the third 

most attended cultural institution in the greater Los Angeles area. It is a strong asset to the 

22
community, bringing in more than $20 million in economic benefits to Long Beach and $100 

million to Los Angeles County annually. 

Figure 11: Demonstration Site Two - Aquarium of the Pacific 

emonstration Observations 

he implementation results for the first demonstration sites were very positive. Transitioning the 

bench and 

nd 

s 

provements in speed and reliability surrounding data collection were also evident due to the 

nical 

l 

, so the 

onstruction and spring thunderstorms were the primary cause of most interruptions in utility 

D

T

Advanced Controller into the hands of the engineering and operations team from the 

development team was eased tremendously because of the use of the ISaGRAF Work

standard IEC 61131 programming languages. The function blocks that provide the control 

algorithms were implemented along with the IEC standard functions, such as multiplexers a

gates. This sped the implementation and facilitated easier customization needed to meet the 

particular nuances of the site’s sequence of operation. These standard programming language

are another major benefit of the Advanced Controller, allowing industry engineers to quickly 

understand and use the Advanced Controller with minimal specialized training. 

Im

Advanced Controller’s data acquisition enhancements. This was very useful for remote 

monitoring, database storage, and generation of system health and status pages to the tech

support cellular telephones and e-mails. The system was configured to generate an informationa

e-mail to the cellular phone of selected employees to indicate when the site was being powered 

solely by generation during the monthly load test, or if the site was down because of an 

emergency. During testing, the facility was seamlessly transferred to backup generation

e-mail messages provided the only indication to other plant personnel that the test was 

happening. 

 

C

electrical power. The event recording of the power conditions at the time of interruption was 

performed at a much faster frequency (1 second) to the standard database programs than by the

previous communication channels. This enabled site personnel to know the cause and type of 

interruption more precisely than before. 

23
Noticeable improvements were evident in the overall system maintenance as well. Having a 

single hardware and software platform lessened the site’s complexity. This enabled the site to 

receive several firmware upgrades and feature enhancements with less overall testing than was 

previously possible. These features provided operational efficiencies that reduce the overall cost 

of system implantation and reduced the overall operational maintenance costs. 

Having TCP/IP Ethernet on the Advanced Controller allowed the controls to be placed on the 

facility network. Although the Advanced Controller might have a dedicated network at many 

sites, the TCP/IP Ethernet interface allowed the controller to be tested with all of the 

communication traffic of the facility and not just the site. It also gave users the ability to monitor 

or demonstrate remote connections into the site. 

In performance testing, the Advanced Controller exhibited a high degree of stability and 

“smoothness” as it was taken through the loading, unloading, base load control, and import 

control algorithms. In particular, the import control was able to control to within a +/- 10 kW 

level, where previously only +/- 20 kW was obtainable. In the base load mode, the export 

control limiter function transitioned from base load to export limiting function without any 

issues. The export limiting function comes into play when a base load level is set on the 

generator, but the site load decreases to the point where the export limiter decreases the generator 

load to maintain the desired export of power from the utility to the facility. 

All software programming for the control, including communication settings and tunable 

configurations for the site, were backed up on the multimedia card (MMC). In the unlikely event 

of an Advanced Controller failure, the MMC card could be inserted into a replacement control 

and all software programming, custom settings, and performance tunings could be restored in a 

single step. This feature will greatly reduce field maintenance costs of deployed Advanced 

Controllers, allowing a control to be shipped and installed by on-site personnel, circumventing 

the need for an engineer to travel to the facility to replace the controller. 

Refer to Appendix I for additional details on the two demonstration sites. 

4. Conclusions

This final report provides a summary of the successful results of the work completed on the 

advanced grid interconnection controller and the command and control system, as well as two 

demonstration sites. 

This contract work achieved the following objectives: 

• Significant cost savings compared to current industrial switchgear options. 

• Reduced maintenance costs due to the benefits of integrated switchgear and controls systems 

and the power of remote monitoring, diagnostics, and communications, as well as the design 

of the Advanced Controller for field service and field support capabilities. 

• Demonstrated compatibility with major electric power system communication protocols and 

building energy management communication protocols. 

24
• Created the ability to integrate with a broad cross-section of energy generation technologies 

and energy load management technologies. 

The following is a list of specific technical accomplishments that have been achieved under this 

contract. 

• Designed, developed, and tested a prototype. 

• Demonstrated the prototype design’s functionality in the Chowchilla case study. 

• Researched and published the Communication Study. This study identified the various 

types of communication used and the control features that would be desirable for remote 

monitoring and control of DP assets. 

• Addressed Internet related security features that would be needed in the Advanced 

Controller. 

• Developed the prototype design into a commercial product and released it for commercial 

use. 

• Created a design in which most simple systems do not need a CPM because remote 

communications can be performed directly with the Advanced Controller. This 

eliminates an expensive component (and associated wiring and system complexity) that 

was prone to failing in the field.

• Designed the system so that it reduces the time required to initially load or upgrade an 

application. Large systems will take only a few minutes per control and single control 

download capability within a multiple control system is provided (more than a 100 times 

improvement in speed over the previous controller, especially in larger systems). 

• Provided for a single user interface. Older controllers required designing the control with 

both LONWORKS tools and the ISaGRAF workbench tool, which complicated the 

designs and increased errors that were debugged late in system assembly. 

• Utilized International Programming Languages to improve marketability and ease of use 

training for the control. 

• Provided Application Simulation during the system design process to minimize design 

errors and correct these errors early, reducing manufacturing and site set-up times. 

• Gave the application the ability to self-document during the design process. This saves 

many hours during the design process and ensures that the documentation is the same as 

the design. 

• Provided serviceability improvements. The current controller design requires the cover 

to be removed for access to wiring, LEDs, connectors, and the reset button. The 

Advanced Controller design provides cover-on accessibility for functions. 

• Designed the Advanced Controller to allow field replacement and project archival. It 

provides an easier method to perform a field replacement and store or re-store the 

application project on the Advanced Controller. This is achieved with a Removable 

multimedia flash card interface, which will allow field replacement by on-site 

technicians, eliminating the need for an engineer to travel to the site to perform the field 

replacement. 

• Designed the system to extensively document the firmware design, implementation logic, 

and control algorithms that were not available on the previous controller. This will 

greatly aid training new users and engineers, and aid debugging of issues that occur when 

using the new controller. 

25
• Designed a system that provides a 20-fold performance improvement through the use of a 

high-speed controller central processing unit, along with a high-speed digital signalprocessing chip. 

• Designed a system that reduces manufacturing costs (estimated reduction to be greater 

than 15%). 

• Designed a system that increases control capabilities with the design of a patented active 

anti-islanding control scheme. 

• Designed a system to further increased control capabilities with the design of a loss-of 

synchronization control scheme. 

• Designed a system that reduces overall grid interconnect system capital and installation 

costs with the elimination of additional system hardware now intrinsic to the Advanced 

Controller (i.e., improved firmware and communications capabilities). 

• Designed a system that includes compliance with current and projected industry 

standards for switchgear and interconnection devices. 

• Designed a system that increases functionality for the DP customer. 

• Designed a system that includes supporting software that encompasses the ISaGRAF 

Workbench Extension Tool and the Advanced Controller Commissioning Tool. 

• Provided a design that is software configurable, eliminating separate hardware 

configurations for UPC, KWS, and PTC applications. This is a big cost savings-- it 

increases production volumes thereby lowering, inventory, support, and documentation 

costs, as well as simplifying marketing and sales efforts. 

• Included an RTU (Remote Terminal Unit), which is focused on connecting and 

communicating with distributed resource subsystems. The RTU allows interface with 

utility-grade energy meters, engine controllers, fuel meters, etc. and feeds this 

information to higher-level systems. The Advanced Controller includes the following 

RTU capabilities: 

o Modbus devices (Server and Client) 

o Lon Work devices (more standard implementation) 

o TCP/IP (Ethernet) 

o Additional RS232 and RS485 serial interfaces. 

• Provided a standard Web browser interface for simple monitoring and operation. 

• Provided a Web trending capability. 

• Performed an extensive series of qualification and compliance tests on the Advanced 

Controller. The following actions were performed on prototype and production units, 

ensuring that a quality system was in place to maintain the quality of the controllers that 

would be manufactured. 

o Unit testing of each individual software unit that was developed 

o Bench-level testing of the controller system 

o Type testing as specified in IEEE 1547 and other applicable standards (temperature, 

mechanical shock/vibration, EMI, RFI, etc.) 

o Live on-generator system tests in a laboratory environment 

o Production and on-going reliability tests 

o Tracking and monitoring of field deployment issues 

o Corrective action and verification of all issues that were identified during the 

development and deployment of the Advanced Controller. 

26
• Created the Remote Energy Management Command and Control (EMC), located in 

Windsor, Colorado. The EMC is capable of remotely monitoring and controlling 

distributed generation assets. 

• Demonstrated the combined system at two demonstration sites: 

o Single generator application located in Colorado 

o Multi-generator, combined heat and power application in California

o Both systems are supported by the EMC remote monitoring and control capabilities.

27
28
5. Appendix A: Product Development Methodology 

Today’s business environment can be characterized by complexity, and the acceleration of 

everything from customer demands, to production methods, to the rate of change itself. In the 

face of these demands, organizations must continue to develop and deploy high quality products 

that meet the needs of their customers. Organizations use development and business processes to 

help achieve success. However, if the organization and management of people and processes 

breaks down, the net effect is reduced quality of the products that are being developed. 

Encorp analyzed numerous successful products that were being used throughout the electrical 

power industry and one key attribute was always evident: quality. The power industry demands 

quality from products even more than what is found in several other industries. Products are 

expected to operate as anticipated in harsh environments, to be self sufficient and reliable 

without maintenance for long periods of time, and to work flawlessly when needed. 

Understanding these demands from business in general and the enhanced demands of the power 

industry, Encorp employed a proven product development process that ensures meeting the 

industry’s high standards of quality. This development process is fairly simple but requires 

discipline at all levels of the organization. 

This process is broken down into various sections in the life cycle of a product: concept, design, 

development, product validation, ramp to production, production, and end of life. Figure 12: 

Base Year Product Life Cycle Development Activity and Figure 13: Option Year 1 Product Life 

Cycle Development Activity; outline the relevant phases employed for the Advanced Controller 

development in the Base Year and in Option Year 1 of this contract work. 

29
Figure 12: Base Year Product Life Cycle Development Activity 

(DFM – Design for Manufacturing) 

30
Figure 13: Option Year 1 Product Life Cycle Development Activity 

31
6. Appendix B: System Architecture Technical Approach 

Traditionally, when deploying power systems, several discrete analog devices would serve 

singular functions in the power system and would need to be integrated together for the system to 

function properly. This equipment is sometimes referred to as “custom” paralleling switchgear. 

Making all the different devices work together in a coordinated fashion is very difficult, 

cumbersome, prone to errors, and labor intensive. Each system deployed in this manner will be 

slightly different because of varying site, customer, and regulatory requirements. This adds to 

the complexity of the systems and increases the cost of deployment and maintenance by 

increasing the labor effort associated in each system’s design, manufacturing, and deployment. 

The new Advanced Controller approach, developed as part of this contract, is to take the 

functionality that the analog devices provided and build them into software on a digital controller 

platform. This allows the “customization” of the equipment to be largely a configuration effort 

performed in software, allowing for cost savings during the design, assembly, and support phases 

of a project to be considerably less expensive. This approach also provides additional user 

benefits in a simple user interface, greater built-in functionality, additional communications 

capabilities, and remote monitoring, as well as remote command and control functionality. 

(Figure 14 and Figure 15 further highlight this philosophy.) 

Traditional Method (Analog) Digital Solution 

Figure 14: Moving to a Digital Platform 

32
Figure 15: Moving to a Digital-Based Platform 

Based on this approach, the overall system architecture has two major subsystems: the control 

layer and the data acquisition layer. 

6.1 Control Layer 

The control system uses the Advanced Controller developed under this contract to take in critical 

system information points, such as voltage, kW, and current, and make command decisions 

across the entire system. In the control system, the utility power control (UPC) is deployed at 

each utility entrance point in a facility. 

In Figure 16 there are two UPCs deployed at each of the facility’s two utility feeds. A generator 

power control (GPC) is deployed at each separate DG unit. Three GPCs are also deployed, one 

on each of the facility’s reciprocating engines. Please note that the UPC and GPC are physically 

the same device and only the software configuration used in each device is different, providing 

the UPC and GPC functionality. This illustrates just one of the cost savings of the Advanced 

Controller approach. The savings are many, including those achieved by spreading direct and 

indirect costs over a higher volume of manufactured components, and the lower manufacturing 

costs that are realized with higher volumes. When these controls are deployed, they use the 

LONWORKS communications protocol to pass information amongst each other and make 

coordinated system-level decisions. This allows the control system to execute in various 

application modes, such as peak shaving and standby. 

One of the major advantages of the Advanced Controller design is to minimize the 

communications traffic on the LONWORKS bus by just allowing critical generator control 

functions to occupy that bus. This improves system reliability and performance. 

33
Figure 16: Control System Architecture 

6.2 Data Acquisition Layer 

The controls are also a critical part of the data acquisition layer. The primary purpose of this 

layer is to gather data from the controls and other sources of important data quickly. This data 

can then be consumed by applications and other systems. The most common system that is used 

in conjunction with data monitoring is traditional supervisory control and data acquisition 

(SCADA) packages. 

These SCADA systems usually include: 

• Historical trending servers to store larger amounts of data for later historical analysis and 

regulatory compliance (i.e., AQMD [Air Quality Management District], Joint 

Commission on Accreditation of Healthcare Organizations [JCAHO]) 

• Alarming servers to facilitate the immediate response to the systems’ alert conditions 

• Graphical display packages that represent the system in a logical, easy-to-use visual 

format via Web screens, on-site touch screens, or graphical applications on a workstation 

computer. 

Building management systems (BMS) are another example of a downstream system that 

consumes data from the data acquisition system to make decisions about managing the building, 

based on what is going on with the power systems. This interaction is a very important feature 

of the Advanced Controller because it enables a building to coordinate demand response 

programs, which can greatly reduce a facility’s overall cost of electricity (by removing peak 

loads from the electric power grid). 

34
Figure 17: The Data Acquisition System 

The data acquisition system must be very robust to ensure that operators can monitor equipment 

during times of critical operations. Also, because the data acquisition system is feeding other 

applications and downstream systems, speed and stability are always design considerations. 

Figure 17 is a system-wide example of the data acquisition system. 

One of the challenges that were successfully overcome while developing the Advanced 

Controller was improving the performance and reliability of the data acquisition layer. This was 

successfully achieved by two major improvements to the Advanced Controller. The first 

improvement was separating the control layer communications from the data acquisition layer 

communications. Prior to this contract work, both layers utilized the LONWORKS network for 

messaging, which could lead to major slow downs on large systems. The Advanced Controller 

continues to use LONWORKS for inter-controller (inter-generator) communications, but has 

offloaded the data acquisition traffic to one of several different communications busses, the most 

common being high-speed Ethernet. The other improvement is the addition of the other 

communications busses, including four high-speed serial ports (with Modbus remote terminal 

unit (RTU) support and master/slave capabilities), two CAN bus ports and the aforementioned 

Ethernet port. 

35
7. Appendix C: Advanced Controller Design 

The purpose of this section is to explain in detail all the features and assets of the Advanced 

Controller developed as part of this contract. Throughout this section, design considerations and 

challenges that were successfully overcome will be highlighted. The Advanced Controller can 

be best explained in three separate parts: 

• Hardware 

• Firmware 

• Support systems and software. 

Though the Advanced Controller is divided into these three separate parts, be assured that the 

interaction between these different tiers is seamless and goes well beyond the necessary system 

speed requirements. 

Figure 18: Advanced Controller Hardware 

36
7.1 Hardware 

The Advanced Controller hardware is 

composed of five major components, t

digital upgrade PCA, the analog I/O 

PCA, the light emitting diode (LED) 

PCA, the power supplies PCA and the 

electronics packaging. Refer to Figure 

18 for a diagram of these parts. Except 

for the Analog I/O PCA, these major 

components are either new designs or 

modified versions of the original 

controller platform. 

he 

The digital upgrade PCA is a new 

design that increases computation 

performance, adds increased 

communications connectivity, and 

provides enhanced field upgrade, mass 

storage, and data logging capabilities. 

Figure 19: Digital Upgrade PCA Board 

The computational performance was increased over the original control by adding a higher 

performance main processor, the MPC555 running at 40 megahertz (MHz) and a higher 

performance Neuron processor, the FT3150P-20 running at 20 MHz. The communications 

connectivity was increased by the addition of three serial ports (for a total of four), two CAN 

ports and a 10/100 Base-TX Ethernet port. The four serial ports are two each of RS-232 and RS485 (2-wire or 4-wire). Field upgrade, mass storage, and data logging capabilities are facilitated 

using a removable Secure Data Multi-Media flash card. Refer to Figure 19 for a picture of the 

top of the Digital Upgrade PCA board. 

Analog and I/O functionality is maintained by connecting the digital upgrade PCA to the current 

analog I/O PCA through the same connector used on the original control. The Advanced 

Controller has no additional analog or I/O functionality beyond that of the original GPC. 

The LED PCA indicates the status of several electronic subsystems within the analog I/O and 

digital upgrade PCAs. It is mounted to the digital upgrade PCA via a 26-pin dual row connector. 

The LEDs are visible with the enclosure top cover installed. The RESET and LON Service 

switches are accessible with the enclosure top cover installed, improving the field maintenance 

of the Advanced Controller. 

The electronics packaging is similar to that of the original controller, except that all terminal 

blocks, I/O connections, LED indicators, and the memory card are accessible with the enclosure 

37
top cover installed. This also improves the field maintenance capabilities of the Advanced 

Controller. Figure 20 shows an example of the improved accessibility of the Advanced 

Controller. These hardware changes are major improvements for overall maintenance and onsite monitoring of the controller. 

Figure 20: Improved Accessibility of Advanced Controller 

38
7.1.1 Communications 

For the Advanced Controller communications ports layout, refer to Figure 21. 

MultiMedia Card

CAN

LON ETHERNET

2X RS232

2X RS485

Figure 21: Communications Ports Layout 

Serial Communications 

The GPC has four serial interfaces located on the digital board: 

• Two optically isolated RS–232 ports, which are designated COM1 and COM3. These two 

ports are isolated from the core electronics, as well as from each other. The physical 

connector for each RS–232 port is a standard DB-9 male. 

• Two optically isolated RS–485 ports, which are designated COM2 and COM4. These two 

ports are isolated from the core electronics, as well as from each other. The physical 

connector for each RS–485 port is a standard DB-9 male. 

The serial interfaces are used for local user interfaces, programmable logic controller (PLC) 

monitoring, I/O expansion, remote monitoring, SCADA connection, bus-enabled revenue grade 

metering, and GPS receivers. The serial interfaces do not share a common ground for isolation 

purposes. The serial interfaces support the following features: 

• Serial transmit and receive data only 

• Two dedicated RS-232 and two dedicated RS-485, configurable for RS-485 2-wire or 4-

wire operation 

• 8 bit character size 

• 1 or 2 software-programmable stop bits 

• Baud rates of 4800; 9600; 19200; 28800; 38400; 57600; and 115,200 

• Activity LED indicating that the controller is sending or receiving messages 

• Self-powered 

• 1000 volts root mean squared (VRMS) isolation to ground 

• 700VRMS isolation between channels 

• On-board jumper-selectable termination 

• Jumper-selectable bias resistors for RS–485 multi-drop mode. 

39
Ethernet 

The GPC has one Ethernet local area network (LAN) port located on the digital board PCA. The 

Ethernet interface operates at either 10 (megabits per second) Mbps or 100 Mbps, and supports the 

following features:

• Full Modbus TCP support 

• Full or half duplex capability at 10 Mbps or 100Mbps 

• 100BASE-TX physical interface that complies with IEEE 802.3 

• Activity LED status indicator for transmit or receive activity 

• Link OK LED status indicator for valid link connection 

• RJ–45 connector physical interface (transformer isolated with a minimum 1500 VRMS 

isolation to meet IEEE 802.3) 

• Communication error detection and indication built into the ISaGRAF workbench 

network communications setup 

• Dynamic security to prevent damage in the event of a denial of service attack. 

Echelon LONWORKS Port 

The LONWORKS network is used for communication between advanced controls and other 

devices. The LONWORKS implementation is also compatible with third-party products and 

network management tools. The Advanced Controller has one LONWORKS port located on the 

digital board. LONWORKS support includes software to provide automatic binding of system 

control object (SCO) variables for digital load sharing and communications without the need for 

a LONWORKS binding tool. The LONWORKS interface includes the following features: 

• Activity LED that will turn on whenever the controller sends or receives messages 

• Service Indicator LED 

• Service pin switch used to trigger the control to broadcast a service message 

• High-performance neuron processor running at 20 MHz 

• Ability to withstand 1000 VRMS dielectric strength test for 1 minute 

• LONWORKS software subsystem. 

Controller Area Network (CAN) Ports 

The CAN ports were added to the Advanced Controller for future expandability. One port that 

has already been tested with a prototype version is dedicated to Encorp’s Power Sensor Module 

(PSM). The other port was added in anticipation that it can be used to communicate with various 

engines in the future because CAN is a very popular communications medium on engines. 

40
7.2 Firmware 

The Advanced Controller can be deployed as a generator power control (GPC), which would 

control various DG types or a utility power control (UPC), which would coordinate system 

activity based on parameters being monitored from a facility’s utility power entrance. The 

Advanced Controller utilizes a real time operating system (RTOS) to ensure reliability, stability, 

and enhanced security. 

The same firmware is installed on all GPC and UPC controls. Functionality is determined 

entirely by the application program that is installed in the control. 

The firmware includes the following features and functionality: 

• ISaGRAF Embedded PLC software module, IEC 61131-3 Programming Languages 

• Programmable, separately isolated switch inputs and solid-state relay driver outputs 

• Setup and configuration with standard PC (no handheld programmer required) 

• Embedded Web server 

• Support for both Modbus client and server, allowing Modbus I/O expansion 

• Manage and upgrade applications from offsite locations 

• Upgradeable firmware 

• Single point communications connection for application tools 

• Single tool for application installation, configuration and test 

• High-speed download of ISaGRAF applications 

• High-speed data access and control through the ISaGRAF OPC server. 

One of the main functions of the GPC embedded firmware is to support the ISaGRAF PRO 

Virtual Machine software environment. ISaGRAF PRO is a third party embedded software 

technology that supports open distributed control applications in a networked environment. The 

runtime target or Virtual Machine is an execution engine that runs on the Encorp platform and 

provides the application framework for the system. The Virtual Machine is downloaded and 

debugged from a PC application called the ISaGRAF PRO Workbench. The Workbench 

supports the five IEC 61131-3 programming languages (Structured Text, Sequential Function 

Chart, Flow Diagram, Ladder Logic, Instruction List), which provide the required flexibility for 

the application space. 

 

The embedded firmware provides hardware drivers to interface the local hardware to the 

ISaGRAF PRO Virtual Machine. Local hardware support includes discrete inputs, discrete 

outputs, frequency bias output, voltage bias output, load share, potential transformer inputs, and 

current transformer inputs. Advanced digital signal processing is implemented for the potential 

transformer and current transformer inputs to provide true RMS power information, including 

harmonics. 

ISaGRAF application function blocks support synchronizer, automatic transfer switch and 

import/export control, kW and kVAR load-sharing control with soft loading and unloading, baseload control and reactive power/power factor (VAR/PF) control. 

41
7.2.1 ISaGRAF Embedded PLC 

The Advanced Controller utilizes the ISaGRAF software environment from ICS Triplex. This 

environment includes two main components: 

• Virtual Machine – a software engine that executes control algorithms on the Advanced 

Controller 

• Workbench - a powerful application development environment for configuring all the 

elements of the Advanced Controller 

Virtual Machine 

When the Advanced Controller is built, a Virtual Machine (VM) is loaded into the embedded 

RTOS. This VM acts as an embedded PLC that runs target independent code (TIC) that has been 

generated by the Workbench. 

Workbench 

The ISaGRAF Workbench is the environment that allows development of multi-process control 

applications that run on the VMs of the Advanced Controller. The development process consists 

of creating projects made up of configurations that represent individual target nodes, on which 

one or more resources are downloaded. At runtime, the resources run on these target nodes. 

Resources can be programmed using any of the five languages of the IEC 1131-3 standard: 

• Sequential Function Chart (SFC)- a graphic language used to describe sequential 

operations. The process is represented as a set of well-defined steps, linked by transitions. 

A Boolean condition is attached to each transition. A set of actions is attached to each 

step. Conditions and actions are detailed by using other languages (ST, IL or LD). From 

conditions and actions, any function or function block in any language can be called. 

• Function Block Diagram (FBD) - a graphic language that allows the programmer to 

build complex procedures by taking existing functions from the standard library or from 

the function or function block section. 

• Ladder Diagram (LD) - a graphic representation of Boolean equations, combining 

contacts (input arguments) with coils (output results). The LD language enables the 

description of tests and modifications of Boolean data by placing graphic symbols into 

the program chart. LD graphic symbols are organized within the chart exactly as an 

electric contact diagram. LD diagrams are connected on the left side and on the right side 

to vertical power rails. These are basic graphic components of an LD diagram: 

o Left vertical power rail 

o Right vertical power rail 

o Horizontal connection line 

o Vertical connection line 

o Multiple connection lines (all connected together) 

o Contact associated with a variable 

o Coil associated to an output or to an internal variable 

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• Structured Text (ST) - is a high-level structured language designed for automation 

processes. This language is mainly used to implement complex procedures that cannot be 

easily expressed with graphic languages. ST language can be used to describe the actions 

within the steps and conditions attached to the transitions of the SFC or the actions and 

tests of the FC Language. 

• Instruction List (IL) – is a low level language. Instructions always relate to the current 

result (or IL register). The operator indicates the operation that must be made between the 

current value and the operand. The result of the operation is stored again in the current 

result. 

• Flow Chart (FC)(language) – a graphic language used to describe sequential operations. 

An FC diagram is composed of actions and tests. Between actions and tests are oriented 

links representing data flow. Actions and tests can be described with ST, LD, or IL 

languages. Functions and function blocks of any language (except SFC) can be called 

from actions and tests. An FC program can call another FC program for more complex 

operations. The called FC program is a subprogram of the calling FC program. 

Resources are compiled to produce the TIC that the VMs will execute. Within the resources, 

variables are declared using simple types (Boolean, integer, real, string, and timer) or userdefined types such as arrays or structures, for defined variables, set up alarms, events, and 

trending. Furthermore, field communications connect variables to field equipment. Resources 

can share variables using a binding mechanism, develop projects on a Windows operating system 

development platform, using the project manager and language editors. Individual resources, 

from the configurations making up a project, are downloaded, using the ETCP network, onto 

target nodes running real-time operating systems. Communication between configurations can 

be implemented using the TCP\IP or any other network. 

This tool also supports the ability to simulate running a project, using high-level debugging tools, 

before actually downloading configurations to the target nodes. This feature saves an abundance 

of time and money by allowing engineers to do simulated test runs of their control algorithms 

before going into the field. 

The Workbench has powerful self-documenting capability. This feature allows the engineer to 

configure what elements of the project to be included in the final documentation and then the 

Workbench automatically builds a complete, coherently grouped document with all the selected 

information and a history of all the project modifications. This self-documenting feature saves 

time and money in the design and maintenance phases of projects. 

7.2.2 Function Blocks 

The Advanced Controller replaces the large number of external analog devices found in 

traditional switchgear cabinets with a single control that implements the same functions in 

software. The Advanced Controller retains the familiar distinction between devices by replacing 

each physical device with a corresponding software function block. The function blocks are 

wired together in software using the IEC 61131-3 programming languages. 

43
The following is a list of some of the major function blocks that were designed as part of this 

contract and are built into the Advanced Controller. 

• Automatic Transfer Switch (ATS) – This function block provides full ATS 

functionality. The ATS object can be operated as a soft transfer closed transition or an 

open transition transfer switch. It also has inputs to test the system (to simulate a utility 

outage) and to override the retransfer time delay and switch back to utility. 

• KW Control – The KW control is used to control generator load in a multi-unit load 

sharing system. Several control options are available, including droop, load sharing, and 

baseload. The KW Controller in the KWS can also be used in client mode to a server 

UPC controller for import/export and baseload control when in parallel with the utility.

The KWS Real Power Control provides closed loop proportional control of a generator’s 

real power when it is paralleled to the utility. 

• KVAR/PF Control - PF sharing, KVAR/PF control and voltage droop control modes 

will be supported in this block. Power control (QPC) provides closed loop control of 

generator reactive power in both bus and generator parallel operation. In bus parallel 

operation, either VAR or power factor control may be selected. In generator parallel 

operation it provides proportional VAR sharing and all units will cooperate in 

maintaining bus voltage at the specified level. In the generator parallel state, the QPC 

will share load with other GPC controls. In client mode, the KVAR/PF control will 

accept a VAR or PF reference signal from a UPC. The client control mode will be 

proportional and will not control bus voltage. The QPC is also available to accept remote 

voltage bias signals from a UPC for synchronizing the bus to the utility. Additionally, the 

voltage trim function may be used in this mode. In power factor control mode, the QPC 

tries to maintain a constant power factor, which means that the reactive power flow 

(VARs) will change proportionally with the amount of load on the generator. 

• Utility Real Power Control - provides control of the utility power when the generators 

are paralleled to the utility by providing control signals to its other GPC controls. The 

UPC can send this master control signal to the GPC controls in several ways, depending 

on the desired KWS control operation. Baseload control, import/export control, process 

control, and ramp functions are also provided. 

• Utility KVAR/PF Control - The Utility VAR/PF Controller provides closed loop control 

of utility reactive power. Either VAR or Power Factor control may be selected. The UPC 

reactive power control provides closed loop proportional, integral and derivative (PID) 

control of generator’s reactive power when they are paralleled to the utility by providing 

signals to the GPCs. The GPC causes a change in the Voltage Regulator setpoint that will 

ultimately change the amount of excitation in the generator. When the generator is 

paralleled to the utility, the generator voltage is set by the utility. So, a change in 

generator excitation results in a change in the reactive power load on the generator. A 

reactive power GPC control will not attempt to regulate bus voltage. 

44
• Circuit Breaker Controller - The circuit breaker control (CBC) object is a generic 

object designed to control a circuit breaker or a contactor. The CBC has momentary 

outputs to close and open the circuit breaker. The CBC also has a maintained output for 

control of a contactor for those applications containing a contactor instead of a circuit 

breaker. The CBC controls how long to hold the close output and open outputs on, to 

allow the breaker to close or to open. The CBC limits the number of close attempts as 

well as the minimum amount of time between close attempts. The CBC senses generator 

current and provides a fault output if the CBC sees generator current when the 

breaker/contactor is open. This indicates a breaker problem or that the auxiliary contact 

on the breaker/contactor has failed. The close input typically comes from the 

synchronizing relay and/or ATS blocks. 

• Auto Synchronizer Relay (25A) - The synchronizer will provide synchronization 

control of either the generator or system. The Sync-Check Relay tests for proper voltage 

and phase conditions and initiates circuit breaker closure. Synchronizing functions are 

provided to ensure closure to the grid only when frequency, phase, and voltage are 

matched. The parameters for allowable frequency, phase, phase slip rate, and voltage are 

configurable within certain ranges to allow for adjusting the closure tolerances. 

• Engine Sequence Control - The engine sequence control will provide basic start and 

stop control for a typical diesel or gas engine. The engine sequence control shall provide 

inputs for engine alarm and shutdown conditions, as well as lube pump cycle timing and 

purge cycle and cool down timing. 

• Energy Meter - The E Meter will be designed to provide demand, power, and runtime 

information based upon ASHRAE standards documentation. 

• 51V Voltage Restrained Overcurrent Curves - A set of voltage restrained overcurrent 

curves will utilize three phase voltage and current inputs to calculate the time to 

overcurrent trip, based upon the selected curve. Curve selection will be through a 

configurable integer input to the object. Standard inverse time curves that comply with 

IEEE c.37-112 1996 will be supported in this object. 

• LONWORKS - The product will support the use of LONWORKS to transmit messages 

between controllers. 

• Modbus I/O - The Advanced Controller is capable of supporting multiple Modbus I/O 

devices with mixed address types using Modbus RTU protocol. 

• Calibration Function Block – Provides offset and gain adjustments, which can be 

manipulated at run time by the user to actively adjust the operating range of analog inputs 

and outputs as needed. 

45
7.3 Advanced Controller Support Software 

The purpose behind the applications that are included in the Advanced Controller’s Support 

Software was to make the design, testing, deployment, and maintenance of DG projects that 

utilize the Advanced Controller as simple and intuitive as possible. Two applications are 

included in this category: the GWE and the Advanced Controller Commissioning Tool. 

7.3.1 GWE 

The GWE is a software tool that extends the functionality of the ISaGRAF Workbench to better 

meet the needs of the engineers that will be deploying the Advanced Controller. It provides 

additional support for some internal business processes and operations workflow processes. 

Some of the additional functionality that it includes is archiving project files, tracking project file 

versions, and adding security for the Advanced Controller’s FTP server. 

7.3.2 Advanced Controller Commissioning Tool 

The Advanced Controller Commissioning Tool is a software application that was designed to 

provide assistance with the tasks surrounding the commissioning of a DG site using the 

Advanced Controller. The main functionality that this application delivers includes: 

• Present aggregate real-time display data from the GPC. 

• Allowing easy entry and display of most setup parameters 

• Providing descriptive text for each control variable, and a comprehensive context 

sensitive help system 

• Real-time trending for debugging system dynamics, including basic mathematical 

operations. 

46
8. Appendix D: Prototype Power Sensing Board 

The power sensor module (PSM) design is a stand-alone intelligent module powered by highpower DSP technology. The primary purpose of this module is to interface with multiphase 

voltage (potential) and current transformer (PT and CT) inputs. This module will perform 

extensive signal processing and management of the input information and transfer the resulting 

values to the controller module. This encompasses various electric power issues related to real 

and reactive power as well as harmonics. 

In addition, this module contains relay outputs for circuit breaker close/open control, digital 

inputs for auxiliary contact feedback, and solid-state digital outputs for relay targets or secondary 

circuit breaker control. 

The prototype PSM module design has sufficient memory to allow up to 64 cycles of waveform 

information to be buffered to support an event-reporting application. In addition, the power 

sensor module software will perform several high-speed protective relay functions (e.g., 

over/under voltage [27/59], over/under frequency [81 O/U], sync check [25], and loss of 

synchronism relay [78]). 

The following parameters will be measured and provided by the PSM design on all four phases. 

47
Table 1: PSM Measured Parameters 

Voltage RMS V, selectable L-N or L-L 

Current RMS A 

Watts RMS P 

True Power Factor PF 

VA RMS S = V * A 

VAR RMS Q 

Displacement PF DPF 

Fundamental W P1 

Fundamental VA S1 

Fundamental VAR Q1 

Voltage phase angle Radians, relative to DFT window 

Voltage harmonics 32nd, on demand 

Current harmonics 32nd, on demand 

Voltage total harmonic distortion V THD 

Voltage total odd harmonic distortion V TOD 

Voltage total even harmonic distortion V TED 

Current total harmonic distortion I THD 

Current total odd harmonic distortion I TOD 

Current total even harmonic distortion I TED 

48
The following parameters are provided by the PSM design on three phases: 

Table 2: PSM Three Phase Parameters 

Equivalent system voltage Ve = √ (Va2 + Vb2 + Vc2) / 3 

Equivalent system current Ie = √ (Ia2 + Ib2 + Ic2) / 3 

Total W Pt = Pa + Pb + Pc 

System VA Se = 3 * Ve * Ie 

Total VAR Qt = Qa + Qb + Qc 

Total true PF PFt = Pt / Se 

Total fundamental W P1t = P1a + P1b + P1c 

Total fundamental VA S1t = S1a + S1b + S1c 

Total fundamental VAR Qt1 = Q1a + Q1b + Q1c 

Total displacement PF dPFt = P1t / S1t 

Negative sequence voltage V2a = 1/3 (Va + a*Vb + a2*Vc), where a* is 

the 120 degree vector operator and a2* is the 

240 degree vector operator. 

Positive sequence voltage V1a = 1/3 (Va + a2*Vb + a*Vc) 

Zero sequence voltage V0a = 1/3 (Va + Vb + Vc) 

Voltage sequence imbalance V2a / V1a

Negative sequence current I2a = 1/3 (Ia + a*Ib +a2*Ic) 

Positive sequence current I1a = 1/3 (Ia + a2*Ib +a*Ic) 

Zero sequence current I0a = 1/3 (Ia + Ib + Ic) 

Current sequence imbalance I2a / I1a

The PSM design has several digital and relay outputs. These will enable control of external 

lamps and relays — including the ability to actuate high-current relays. This will be done while 

ensuring compliance with industry-recognized high-voltage isolation capability. 

49
The PSM board design contains various PT inputs with the following properties: 

• Nominal 120 V AC with a range of 40 V AC to 150 V AC 

• Accuracy of ±0.25% over temperature and time 

• Maximum 0.2 VA burden at 120 V. 

The PSM board design contains CT inputs with the following properties: 

• Nominal 5 A with a maximum of 7 A 

• Withstand 20-A continuous current 

• Withstand 300-A transient current for 1 second 

• Accuracy of ±0.25% over temperature and time 

• Maximum 0.2 VA burden at 5 A. 

The IEEE 1547 draft standard establishes criteria and requirements for interconnecting 

distributed resources with electric power systems (EPSs). Protective relay functions are planned 

to comply with all requirements of this standard. The PSM design performs a minimum set of 

critical high-speed protective relay functions including: 

• Under voltage/over voltage relay (three phase/one phase) (27/59) 

• Frequency relay (81 O/U) 

• Out-of-step protective relay (78) 

• Synchronism check device (25). 

Other functions can be incorporated, as needed, within the PSM or controller module. 

The specification for each function follows: 

Under Voltage/Over Voltage Relay (Three Phase/One Phase) (27/59) 

The U/O voltage protection function will measure the effective (RMS) or fundamental voltage 

value of each phase-to-neutral or, alternatively, each phase-to-phase voltage. When the measured 

voltage is less than a minimum percentage set point or greater than a maximum percentage set 

point of base voltage (nominally 120 V), the PSM will issue a breaker open command through 

one of the high-speed relay outputs. These set points shall be adjustable to a minimum range of 

50% to 120% of base voltage. The maximum time from the start of the abnormal condition to the 

relay contact output will be 48 milliseconds (ms). 

Clearing time is the time between the start of the abnormal condition and the DP ceasing to 

energize the area EPS. Note that this time includes any delay in the circuit breaker or other 

interconnect device, so clearing-time adjustments must account for this delay — placing further 

emphasis on the need for high-speed detection and recognition. The voltage and clearing time set 

points will be field adjustable so an operator can specify different voltage settings or trip times to 

accommodate system requirements. Field-adjustable settings will be protected against 

unauthorized adjustment.

50
Frequency Relay (81 O/U) 

The PSM will follow the interconnected area EPS frequency within the range 59.3 hertz (Hz) to 

60.5 Hz (on a 60-Hz base). At a minimum, the over/under frequency (81 O/U) protective relay 

will be adjustable between 57 Hz and 60.5 Hz. The maximum time from the start of the 

abnormal condition to the relay contact output will be 48 ms. 

Clearing time is the time between the start of the abnormal condition and the DP ceasing to 

energize the area EPS. Note that this time includes any delay in the circuit breaker or other 

interconnect device, so clearing time adjustments must account for this delay. The frequency and 

clearing time set points will be field adjustable so an operator can specify different frequency 

settings or trip times to accommodate system requirements. Field-adjustable settings will be 

protected against unauthorized adjustment. 

Out-Of-Step Protective Relay (78) 

Synchronous generators in applications with a stiffness ratio of 20 or less will be equipped with 

loss of synchronism (out-of-step) protective functions to isolate the DP from the area EPS 

without any intentional time delay. The solution to be implemented is described in “A Study Into 

a New Solution for the Problems Experienced With Pole Slipping Protection” by M.A. Redfern 

and M.J. Checksfield (IEEE Transactions on Power Delivery, Vol. 13, No. 2, April 1998). 

. 

Synchronism Check Device (25) 

The sync check device shall be adjustable to the following: 

• Frequency difference (∆f, Hz), maximum of 0.1 Hz [Target +/- 0.01 Hz] 

• Voltage difference (∆V, %), maximum of 3% of the base voltage [Target +/- 0.25%] 

• Phase angle difference (∆∅,°), maximum of 10% [Target +/- 1 degree]. 

Additional functions and protective relays that are implemented in the Power Sensor Module 

include: 

• Anti-islanding relay (passive, or in conjunction with the Advanced Controller active antiislanding signals) 

• Directional Power (32) Relays 

• Negative Sequence Current (46) Relays 

• Negative Sequence Voltage (47) Relays 

• Instantaneous Over Current (50P, N) Relays 

• Over Current Relays (51P, N) 

• Protective Relay Programmable Logic 

• Circuit Breaker Controllers 

51
9. Appendix E: Communications 

9.1 Evolution of Communications Standards 

The primary goal of communications standards is interoperability. Communications standards 

evolved primarily in the 1970s and 1980s. Because of the topology of various communication 

methods, many specialized communications protocols were developed for different application 

domains. In fact, in the 1990s, virtually every technical domain was represented by its own 

communications standards effort. The result was a cornucopia of standards that were domain 

specific. That is, the communications standards, besides providing for the generic goal of 

exchanging information, contained semantics and architectural elements that recognized specific 

industry requirements. An example of this is distributed network protocol (DNP), which 

recognized the “freezing” of data measurements in its communications services model. The 

advent of wide area network (WAN) connections to local area networks (LANs) introduced a 

new obstacle to interoperability. That is, the scope of applications evolved to overlap domains. 

The following figure illustrates the relative complexity (and implicitly, relative cost) versus the 

capability of several application layers in communications protocols. The protocols shown in the 

figure are all suitable for interoperable exchange of measurement and control information such 

as a switch position (i.e., on/off).

Figure 22: Relative Complexity and Capability of Communication Standards (Burns, et al.) 

52
Key: 

BACnet ANSI/ASHRAE 135 protocol for Building Automation and Control Networks 

CAN Control Automation Network 

CEBus Electronic Industry Associations Consumer Electronic Bus, EIA 600 

COM+ Microsoft Distributed Object Model 

CORBA Object Management Group Distributed Object Model 

DNP Distributed Network Protocol 

Fieldbus/Profibus Industrial control network 

LONWORKS Echelon’s Local Operating Node communications protocol 

PEEK/POKE Metaphor for Basic programming language memory manipulation instructions 

PSEM Protocol for Electric Meters, ANSI C12.18, ANSI C12.19 

SNMP Internet Engineering Task Force’s Simple Network Management Protocol 

RFC 1156/ RFC1157 

UCA/CASM EPRI Utilities Communication Architecture Common Application Services

9.2 Implications of Communication Standards Situation 

Given the complexity of the communications landscape, it is imperative for the new controller 

design to incorporate sufficient capability and flexibility to accommodate historic 

communication protocols and practices as well as evolving developments (in terms of standards, 

devices, and methods). 

A number of communications capabilities have been identified that would allow the controller to 

interface with higher-level systems for uses such as monitoring, display and analysis, remote 

dispatch, metering, billing, and alarming. Expanded communication capabilities are also desired 

for interface with other low-level devices for low-cost I/O, displays, and other original 

equipment manufacturer (OEM) controllers. Features included in the controller to support 

communications include: 

• 100 Base-TX Ethernet with TCP/IP stack for high-level, high-speed communications 

• CAN/DeviceNet (2 channels) for low-level, high-speed communications 

• LONWORKS for low-level, long distance communication 

• RS-232/485 (2 channels) for serial communications (Modbus will use one of these channels). 

TCP/IP networking support will be provided with the RTCXnet network communication suite. 

The network communication suite is fully integrated with the RTXC kernel. The networking 

support will include TCP/IP, UDP, Address Resolution Protocol (ARP), Internet Control 

Message Protocol (ICMP), Domain Naming System (DNS) client, Dynamic Host Configuration 

Protocol (DHCP) client, Telnet, and Point-to-Point Protocol (PPP). 

53
10. Appendix F: Task 5 Prototype Demonstration 

To document the first-hand market issues with the interconnection and communications of DP 

systems, a system case study was done on the Chowchilla II power generation station in 

Chowchilla, California. Encorp Inc. designed the controls and switchgear system for this 

complicated plant. The implementation of Chowchilla II is a prototype version of some of the 

features and functions that would be implemented on the production version of the Advanced 

Controller being developed. This prototype hardware is not integrated in the same manner as 

planned on the Advanced Controller but serves as a model for the capabilities that would be 

integrated into the Advanced Controller. 

10.1 System Overview 

The Chowchilla II power plant is a 48-MW facility powered by 16 Duetz natural gas-fueled 

generator sets operating in parallel with the local utility. 

The plant is owned by NRG Energy. The power facility, although located in California, is 

dispatched by from offices in Minneapolis, Minnesota. The plant is dispatched based on 

receiving a call from PG&E or in response to area energy pricing signals. The California ISO 

monitors the facility to determine capacity effect and demand scheduling. 

Individual generator power measurements are made by the Encorp GPCs in the system. The 

power data is gathered and ultimately passed up to the communications processing modules 

(CPMs) in each system and sent to NRG and the California ISO for their use. Figure 23 

illustrates a typical two-engine pair located in the plant. In total, the facility has 16 natural-gas 

engines. 

Figure 23: Typical Chowchilla II Two-Engine Configuration 

54
As noted previously, the interconnection requirements for DP vary widely and typically entail 

more sophisticated and extensive protective relaying strategies for larger systems. Figure 24 

illustrates the protective relaying scheme used in this application. 

Figure 24: Chowchilla II Protective Relaying Scheme 

The Encorp communications system at the Chowchilla power generation facility brings together 

various software, system, and network topologies. As a result of this effort, the following results 

are realized. 

• On-Site Generation Supervisory Control

Supervisory control of the on-site generation is provided by the Encorp UPC/GPC controls 

and the local or remote desktop workstation (DWS). Supervisory control includes 

remote/local system dispatch, alarm monitoring and trending, event trending, dial out alarm 

notification, local/remote generator power level settings, and system power-level monitoring. 

• Generator Status/System Status Monitoring 

The Encorp controls allow local and remote monitoring of a multitude of generator and 

system data points. These points include: 

o Inlet/Exhaust temperature 

o Coolant temperature 

o Crank case pressure 

o Starting air pressure 

o Lube oil pressure (before and after filter) 

o Lube oil level 

55
o Supply voltage 

o Throttle position 

o Engine speed (RPM) 

o Generator bearing temps 

o Generator winding temps 

o Generator inlet/outlet air temps 

o Combustion chamber temperatures 

o Gas valve positions. 

• Load Management Service

Because this site is used exclusively for supplementing the existing distribution capacity, 

load management is limited to the ability to adjust the base load reference of the individual 

generators from a local or remote location via the DWS. Generator power limits and active 

demand levels are also available at the local or remote DWS. 

• Indoor Air Quality Monitoring

Indoor air temperatures are measured and ventilation fans are operated automatically from 

the Encorp UPCs, based on the facility’s air temperature. 

• Revenue Meter Reading

This site did not incorporate revenue meter reading in the Encorp system. Revenue meter 

reading was integrated into the ISO DPG hardware. However, the Encorp system is fully 

capable of receiving either real or pulse (KYZ) meter information and displaying the 

resultant demand information from those sources. 

• Energy-Efficiency Monitoring

The Chowchilla power station did not require energy-efficiency monitoring. If, at some point 

in the future, the need for efficiency monitoring (heat rate versus kWh) is needed, the Encorp 

software could be easily modified to provide such information. 

• Weather Reporting and Forecasting Services

There were no requirements for weather reporting or forecasting services data or I/O for the 

operation of the Chowchilla project. 

• California ISO Data

Numerous monitoring and control points are sent from the Encorp communications system to 

the California ISO via the DPG. A listing of all these points can be found in the California 

ISO DPG Technical Specifications via the Web site at www.caiso.com.

10.2 System Topology 

The SCADA system at the Chowchilla power generation station is representative of Encorp’s 

ability to design, configure, and implement complex communications schemes with distributed 

controls from numerous vendors. The Advanced Controller will enable work with a broader 

array of communication systems.

56
Each engine generator set has two points of data acquisition: (1) the Duetz TEM control, which 

monitors and controls engine parameters, and (2) the Encorp GPC-KWS control, which monitors 

and controls generator parameters. The GPC also provides protective relay functions for the 

generators. The overall system power is monitored and controlled by two Encorp Utility Power 

Controllers (UPCs). System operating parameters are monitored and controlled by two PLC 

Direct (Koyo) PLCs. House power is monitored and the house power breaker is controlled by an 

Encorp MMC. 

Because of RS232 data loading concerns at the serial hubs, the data acquisition system is divided 

in half. Eight engine generator sets are served by each PLC, CPM, and DWS. The data is then 

gathered by each CPM and distributed via Ethernet to the Frame Relay and DPG for access by 

NEO and ISO. Hewlett Packard ProCurve network switches are used to switch Ethernet 

communications between the Koyo PLCs, DWSs, Frame Relay, and the CPMs. 

The TEM controls communicate via Teletypewriter (TTY) current loop into a RS232 serial 

converter. The engine information is fed into a Rocket Port serial hub, which can handle up to 

eight RS232 serial inputs simultaneously. The serial hub interfaces with the native Windows 

operating system COM ports via Ethernet TCP/IP connection. 

The Encorp GPC-KWS and UPC controls communicate via Echelon LONWORKS network to 

the Lon SLTA PCI card located in the CPM. They also communicate via RS232 port at 19.2 

kilobytes per second (Kbps) with a local four-line variable frequency drive (VFD) display. 

The Encorp MMC controls the house power breaker. The MMC provides house power metering 

information. Communications to the MMC will be through the LONWORKS OPC Server that 

resides on the CPM. 

The CPM is an industrial PC operating on a Windows NT operating system platform. Its purpose 

is to serve as the communications collection point for the various distributed devices in the 

system. Dial-in capabilities are possible to the CPM via analog line into a 56-K modem. 

Hewlett Packard ProCurve network switches are used to switch Ethernet communications 

between the Koyo PLCs, DWSs, Frame Relay, and the CPMs. 

Local DWSs running Windows NT operating system are used to provide an HMI point for the 

operators of the system. They communicate with the CPM via Ethernet TCP/IP connection. Dialout capabilities for the purposes of alarm annunciation via pager are possible through the 56-K 

modem on the DWS and an analog landline. 

A SYSCO frame relay is used to provide SCADA to communicate plant information to NRG. 

The CPM provides data to the frame relay via Ethernet. The frame relay communicates with 

NRG via leased line provided by MCI Telecommunications. 

57
A DPG module, serving as the Modbus master, polls the CPMs via RS485 serial 

communications, MODBUS protocol. Data points are sent from the DPG to the California ISO 

via DNP3.0 protocol over a 56-Kbps modem connection on the DPG. 

10.3 Software 

The Encorp Virtual Maintenance Monitor (VMM) software is a graphical user interface (GUI) 

run on a Delphi application layer. The VMM software usually resides in the CPM but may also 

be installed in remote terminals that require their own GUI. The VMM uses Distributed 

Component Object Module (DCOM) clients to access the data provided by the LONWORKS 

network. Custom pages for the VMM are designed by Encorp applications engineers to provide 

the end-user with useful information regarding the power generation system. Figure 25 shows the 

generator overview screen that is standard in the Encorp Intelligence VMM GUI. 

Figure 25: VMM User Interface 

The Encorp Virtual Power Plant (VPP) server resides in the CPM and is used to provide access 

to the power generation system configuration and operating information. The number of units, 

capacity, status, and aggregate load information is available through the VPP server. A remote 

DWS running the VPP dispatch application is then used to poll the VPP server and issue dispatch 

commands to the site. A software interface is used to design graphic displays for various 

discrete, integer, and real data. The following — Figures 26, 27, 28, and 29 — illustrate various 

user interfaces for this application. 

58
Figure 26: Example One-Line Diagram 

Figure 27: Generator Room Display 

59
Figure 28: Generator Annunciator Display 

Figure 29: Generator Metering Screen 

60
11. Appendix G: Qualification / Type Testing 

11.1 Definition of Testing / Overall Quality Strategy 

Type testing of a new product is really a subset of the main area of concern, which is the overall 

quality of the product being developed. Quality really starts during the design phase and involves 

manufacturing, suppliers, customers, engineering, type testing, bench testing, system testing, 

ongoing reliability, and an approach to handle any field failures. The product should be 

engineered to meet or exceed the identified quality requirements in all of these areas. 

To build high quality into a product, the creators must use a systems approach over the life cycle 

of the product, from development through field reliability. This starts during the engineering 

phase, using tools such as good requirements documents that are agreed to by the entire 

organization. The requirements are implemented utilizing a structured design methodology and 

simulation of the design where possible. During the design stage, the overall goal is to perform 

an evaluation of critical signals, stack up tolerances, and create a product with some design 

margin in it. An early transition of firmware to the target system allows continuous board and 

code testing during development that improves the overall stability of the product. These tests 

are followed with more critical tests that are performed on the engineering units, correcting 

issues that are identified prior to initiating the certification testing. Finally, performing the 

certification tests on products that have been produced from the planned production line can 

ensure a product that meets the requirements identified and meets the market demands for a high 

quality, reliable product. 

The overall test approach has been summarized as follows: 

• Engineering development tests (critical path analysis, design margin, firmware 

verification, etc.) 

• Bench Tests (subsystems/functions, systems single/multiple controllers, etc.) 

• Production tests (ICT, Functional – board/module, calibration, burn-in, FGA, on-going 

reliability) 

• Systems Tests (subsystems/functions, on-generator, multiple generators, various control 

modes and applications) 

• Certification Testing on production units Type Tests (IEEE, UL, ANSI, IEC) 

The key is to develop a strategy to address each of these areas to ensure the highest quality 

during each phase of the product’s lifecycle. Each test performed had a detailed test procedure 

and test report written as part of this process. 

 

11.2 Unit Testing (Lowest Level – Developer Level) 

Unit Tests verify that each of the Advanced Controller’s individual subsystems, functions, and 

function blocks work as specified in the requirements document. Each piece of the Advanced 

Controller was tested individually and the results follow. 

61
Table 3: Unit Testing Results 

Test Type Test Name Test Procedure Report 

Resource/Subsystems Boot Loader Pass Complete Complete 

 File system Pass Complete Complete 

 ISaGRAF Port Pass Complete Complete 

 RTC – Real Time Clock Pass Complete Complete 

 Configuration Management Pass Complete Complete 

 

I/O CAN ports Pass Complete Complete 

 FFT Pass Complete Complete 

 ISaGRAF I/O Pass Complete Complete 

 LONWORKS Pass Complete Complete 

 Ethernet Pass Complete Complete 

 Local I/O Driver Pass Complete Complete 

 Modbus Pass Complete Complete 

 Serial Ports Pass Complete Complete 

 

Function Blocks ATS - ATS Control Pass Complete Complete 

 CBCont – Circuit Breaker Control Pass Complete Complete 

 DTR – Definite Time Relay Pass Complete Complete 

 Energy and Demand Meters Pass Complete Complete 

 KWSCont – KW Sharing Control Pass Complete Complete 

 QPS – VAR Sharing Control Pass Complete Complete 

 PTC – PTC KW control Pass Complete Complete 

 QPC – PTC VAR/PF control Pass Complete Complete 

 SYNC – Synchronizer Control Pass Complete Complete 

 UPC – UPC KW Master Control Pass Complete Complete 

 UPCQ – UPC VAR/PF Control Pass Complete Complete 

 SCO – System Control Pass Complete Complete 

11.3 System Bench Testing 

Bench testing focused on testing the Advanced Controller with two distinct methodologies. The 

first methodology put the control in simulated real life situations in which most of the 

controller’s functionality was tested in conjunction with other controllers, I/O devices, and 

monitoring equipment. These tests are designed to reveal what the realistic maximums are for 

the number of controls in a system, ISaGRAF program limitations, and communications 

bandwidth capabilities. The second testing methodology was designed to evaluate the control as 

a system in itself. This phase of testing included resource monitoring for controller CPU and 

memory space. It also tested all the individual function blocks to verify that they interacted 

correctly with other function blocks within the system. 

62
The following is a summary of this testing activity. 

Table 4: System Bench Testing Results 

Test Name Test Procedure Report 

Baseline Control Passed Complete Complete 

Load Typical Application Passed Complete Complete 

Max Number of GDU controls Passed Complete Complete 

Replace GDU Passed Complete Complete 

Modbus Passed Complete Complete 

LONWORKS Passed Complete Complete 

CAN Bus Passed Complete Complete 

Ethernet Passed Complete Complete 

CPU loading Passed Complete Complete 

DTR (Definite Time Relay) Passed Complete Complete 

Synchronizer Passed Complete Complete 

Energy and Demand Meters Passed Complete Complete 

Function block interaction tests Passed Complete Complete 

11.4 Compliance Testing/ Type Testing 

11.4.1 Temperature/Humidity (Operating and Storage) 

The Advanced Controller will operate over a temperature range of –20 °C to 70 °C, to operate at 

95 percent humidity noncondensing at 38 °C, and will survive at a storage temperature range 

from minus 55 °C to plus 105 °C. 

The Advanced Controller passed the following IEC tests: 

• IEC 60068-2-1, Environmental Testing - Part 2: Tests -Tests A: Cold, -20°C for 96 hours. 

• IEC 60068-2-2, Basic Environmental Testing Procedures - Part 2: Tests-Test B: Dry Heat. 

+70°C for 96 hours. 

• IEC 60068-2-30, Environmental Testing-Part 2: Tests -Test DB and Guidance: Damp Heat. 

Cyclic. +40°C at 93% humidity for 96 hours. 

11.4.2 Mechanical Shock and Vibration 

The Advanced Controller passed the following IEC tests: 

• IEC 60255-21-1, Electrical Relays – Part 21: Vibration, Shock, Bump and Seismic Test on 

Measuring Relays and Protection Equipment- Section One: Vibration Tests (Sinusoidal), 

Vibration Response Class 1 0.5G, Vibration Endurance Class 1, and 1.0G. 

• IEC 60255-21-2 Electrical Relays – Part 21: Vibration, Shock, Bump and Seismic Tests on 

Measuring Relays and Protection Equipment- Section Two: Shock and Bump Tests. 

• IEC 60255-21-3, Electrical Relays – Part 21: Vibration, Shock, Bump and Seismic Tests on 

Measuring Relays and Protection Equipment- Section Three: Seismic, Class 2. 

63
11.4.2.1 Electrical Testing 

11.4.2.2 Dielectric Strength 

The Advanced Controller passed the following tests: 

(Applied for 1 minute to each independent circuit to earth and applied for 1 minute between each independent 

circuit.) 

Table 5: Dielectric Strength Tests 

Isolation Minimum (Volts alternating current) 

Analog Inputs 1500 V ac 

Analog Outputs 1500 V ac 

Analog Load Sharing Lines, from power 

input 

1500 V ac 

Digital Inputs 2500 V ac 

High Current Digital Outputs 2500 V ac 

Solid State Digital Outputs 2500 V ac 

Power Supply, AC 3000 V ac 

Power Supply, DC 1500 V ac 

Potential Transformer Input 2500 V ac 

Current Transformer Input 2500 V ac 

LONWORKS 1000 V ac 

Serial Ports 1000 V ac 

CAN 1500 V ac 

11.4.2.3 Surge Withstand/ Fast Transient 

The Advanced Controller passed the following tests on the digital inputs, digital outputs, analog 

inputs, PT and CT inputs, analog outputs, and power supply: 

• IEEE C37.90.1-1989, IEEE Standard Surge Withstand Capability (SWC) Tests for Protective 

Relays and Relay Systems. 

• Oscillatory 1.0 MHz, 3.0 kilovolts (kV). 

• 50 ps burst, 5.0 kV. 

• IEC 61000-4-4, Electromagnetic Compatibility (EMC) 

• Part 4: Testing and Measurement Techniques 

• Section 4: Electrical Fast Transient Burst Immunity Test Basic EMC Publication. 

• Power supply, Level 4, 2.5 kilohertz (kHz), 4.0 kV. 

• I/O, Level 4, 5 kHz, 2.0 kV. 

• IEC 61000-4-5, Electromagnetic Compatibility (EMC) 

• Part 4: Testing and Measurement Techniques 

• Section 5: Surge Immunity Test. 

• Power supply, Level 4, 4.0 kV. 

• I/O, Level 2, 1.0 kV. 

• IEC 60255-5, Electrical Relays 

64
• Part 5: Insulation Tests for Electrical Relays. 

• Impulse voltage test: 0.5 Joule, 5000V. 

• IEC 60255-22-1, Electrical Relays 

• Part 22: Electrical Disturbance Tests for Measuring Relays and Protection Equipment. 

• Part 1: 1 MHz Burst Disturbance Tests. 

11.4.2.4 Electrostatic Discharge 

The Advanced Controller passed the following IEC tests: 

• IEC 61000-4-2, Electromagnetic Compatibility (EMC) 

• Part 4-2: Testing and Measurement Techniques – Electrostatic Discharge Immunity Test. 

• Level 4, Contact discharge 8 kV. 

• Air discharge 15 kV. 

11.4.2.5 Radiated Immunity 

The Advanced Controller passed the following IEC and IEEE tests: 

• IEC 61000-4-3, Electromagnetic Compatibility (EMC) 

• Part 4-3: Testing and Measurement Techniques – Radiated, Radio Frequency, 

Electromagnetic Field Immunity Test. 

• Level 3, 80 to 1000 MHz, 10V/m. 

• IEEE C37.90.2-1995, Standard for Withstand Capability of Relay Systems to Radiated 

Electromagnetic Interference from Transceivers 

• 10 V/m. 

11.4.2.6 Conducted Immunity 

The Advanced Controller passed the following IEC test: 

• IEC 61000-4-6, Electromagnetic Compatibility (EMC) 

• Part 4: Testing and Measurement Techniques 

• Section 6: Immunity to Conducted Disturbances, Induced by Radio-Frequency Fields. 

• Class 3, 150 kHz to 80 MHz, 10 V maximum. 

11.4.3 UL 

11.4.3.1 UL Recognized Component 

The Advanced Controller will be UL Recognized as defined in Sections 29A and 30 of UL 508 

and under Category Control Number (CCN) NMTR2.E188578 for the US and NMTR8.E188578 

for Canada. 

11.5 Live System Testing 

Live System testing is intended to provide as many different operating and product application 

scenarios as possible while maintaining an in-house controlled testing environment. This testing 

was performed in a live environment utilizing three generators. 

These generators were wired and set up in the following system configurations: 

• Single Unit No Utility Paralleling (standby operation) 

• Single Unit Utility Paralleling 

65
• Multiple Unit No Utility Paralleling 

• Multiple Unit Utility Paralleling 

• Multiple Unit with generator tie breaker 

• Multiple Unit with interposing tie breaker 

• Multiple Utility Feed (multiple System Controllers) 

In these configurations, the Advanced Controller was tested running the following applications / 

test plans: 

• Time of day start/stop 

• Run time/demand metering 

• KW Droop Control 

• KW control 

• I/E control 

• VAR Control 

• PF control 

• KW Sharing 

• PF Sharing 

• Circuit breaker control 

• Engine Protection 

• Engine start / stop sequencing 

• Generator Protection 

• Synchronizing (slip and phase match) 

• Voltage Matching 

• Export Limiting 

• Generator Sequencing 

• Load Sequencing 

• Manual Frequency and Voltage Adjust 

• System Controller Synchronization 

• System Controller KW Control 

• System Controller KVAR/PF Control 

• System Control Object (SCO) 

• Power Transfer Control KW controller 

• Power Transfer Control KVAR/PF controller 

Each of these scenarios was documented with an engineering test plan. Once the plan was 

executed, the results and observations of that plan were documented in a test plan report. The 

Advanced Controller passed each of these tests successfully. 

66
11.6 Production / Manufacturing Testing 

Production / Manufacturing Tests 

To ensure the Advanced Controller maintains a high level of quality that was established during 

the design phase, production / manufacturing tests are performed as well as ongoing reliability 

testing to continually validate the product quality on production units. In the event any issues are 

discovered by these tests, root-cause analysis and corrective action are executed as part of a 

continuous improvement process. 

The following are the tests that are necessary for production / manufacturing: 

• Manufacturing In Circuit Test - The manufacturing in circuit test is utilized by 

manufacturers to verify the placement of the components, solder connections, and trace 

routing on the board. A “bed of nails” in circuit tester is programmed by the manufacturer 

to verify each board is built in the same manner as those that went through the design 

type tests. Failure on the in circuit tester is typically due to misplaced components, 

wrong valued components, shorts and opens from the board stuff, and solder processes 

used in producing the PCA. 

• Manufacturing Functional Test (Finished Goods Audit) – Utilizing a functional test 

device, all digital board functions are verified for basic functional capabilities. This test 

also verifies the interaction of the various components used on each PCA that is 

produced. 

• Manufacturing Reliability Test – This test is part of the initial qualification of the 

product. After the initial phase, these tests are reduced to a sample frequency. This 

sampling is what verifies that the product maintains the design qualities over time. It is 

intended to produce accelerated stress to hardware components that will then manifest 

themselves as a failure in the functional test of the device. A complete control is inserted 

into the thermal chamber, and cycled from minimum to maximum storage temperature 

with time allowed for thermal soaking at each end. The control is then brought to ambient 

level, stabilized, and then powered up and run through a functional test using the external 

functional tester. If this test is passed, the unit is ramped to maximum operating 

temperature and functionally tested there, after a suitable thermal soaking period. If this 

functional test is passed, the unit is lowered to its minimum operating temperature and 

functionally tested there, again after a suitable period for the board to stabilize at the 

minimum temperature. If this test is passed, the board is once again brought to ambient 

temperature, stabilized, and functionally tested for a final time. Operational test data is 

collected at the various temperatures and compared to each other for shifts in 

performance at the temperature extremes. 

In addition to production / manufacturing tests, procedures are in place to test the system in a 

customer’s facility for which that the Advanced Controller is being designed, built and deployed. 

These procedures include: 

• Design Computer Simulation –The project simulation feature built into ISaGRAF 

projects can be tested prior to the project configurations being loaded into the Advanced 

Controller. Catching errors early in the design process improves the quality of the 

project being implemented and lowers the overall project cost. 

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• Engineering Review - The engineering team reviews all the designs before going into a 

systems manufacturing process. 

• Lab Systems Testing – After the system is built, the engineering team tests the full 

system on the manufacturing floor. If the system passes, it is shipped to the customer’s 

facility. 

• Commissioning Testing – Once the system has been deployed into the customer’s 

facility, the field service team completes testing for all modes and deployed 

applications. This is usually done in the customer’s presence and is a form of training. 

Once this is completed, the EMC (see section 7) is utilized to monitor key system 

parameters to be evaluated on an ongoing basis. 

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12. Appendix H: System Command and Control 

When approaching this task, Encorp completed several design-related activities to have the most 

complete understanding of what software and communications subsystems were to surround the 

Advanced Controller to further enhance its functionality and overall quality. These activities 

included a detailed communications study, research and testing surrounding IT related security, 

and a comprehensive market analysis to enable a better understanding of the industry climate. 

The market analysis included detailed examination of the broad range of DG projects that Encorp 

had implemented to date. 

The knowledge gained while completing these tasks was used to design, develop, and deploy the 

Command and Control system (EMC). This product is being produced commercially and is used 

by several customers, including the demonstration sites discussed in Appendix I. Details of the 

EMC architecture and subsystems are outlined in the following subsections 

12.1 Communications Study 

Encorp completed a communications study in September of 2004. The study results presented a 

comprehensive overview of current and future communication architecture options used in 

Distributed Generation/Combined Heat & Power (DG/CHP) systems and facility energy 

management systems. 

The systems and subsystems represented have evolved over the years as product offerings 

engineered for various clients that needed certain capabilities. As the product and service 

offerings have strengthened, customers have demanded a more vertically integrated solution. 

The study covers the technology in function-level detail. It also covered several of the different 

types of standard communications protocols and company device manufacturers used when 

implementing solutions for DG power systems customers. 

12.2 Internet Security Design Considerations 

Critical facilities such as data centers use power equipment to protect their facility and 

equipment in the event of a power failure. There are other very important considerations for 

these same facilities to ensure their safety and security. One very important concern is the 

security of all the IT systems surrounding the power and building management systems. 

Suppliers need to understand such issues and provide powerful products to ensure IT security as 

well as power reliability. 

In the United States alone, network security breaches cost businesses an estimated $10 billion 

per year. With the proliferation of the Internet, and the resulting growth of intranets and 

extranets, we are witnessing a remarkable shift toward more open computing and networking 

environments. While these new networked environments offer incredible opportunities for 

business improvements, it also dramatically increases the security challenge by introducing new 

"insiders" to enterprise networks. 

As facility systems increase capabilities to include local area networks (LAN), browser-based 

accessibility, and more, the computing enterprise becomes extended beyond the corporate LAN. 

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Devices that access the corporate LAN increase internal security threats, vulnerabilities, and 

risks. The greatest threat from unauthorized users is their ability to circumvent security controls 

and use energy management systems to shut down power systems, creating power outages within 

the facility. 

Facility systems now need IT standards. Any Web server can be hacked. Uses of Web servers 

in nontraditional IT environments are increasing and pose a whole new set of risks. Facility 

managers need to ensure that advanced security features are available within the hardware 

devices connecting to their facility equipment, systems, and devices. The computing industry has 

done a fairly good job of responding to market priorities by developing technologies to address 

corporate networks and information assets from the Internet and to unambiguously authenticate 

users. These same technologies can be used to solve the network security problem of facility 

systems and devices. What is needed now is not new technology, but an information technology 

approach to creating an internal security solution for the facility and power-related operations. 

Breaches are common and often result from a lack of security awareness on the part of a wellintentioned IT security staff. 

Network Security Fundamentals: 

There are several basic elements in network security: 

• Access Control – Businesses must make sure that information is available to users in a 

secure way. Once a person or system has been authenticated, their ability to access data 

and use systems is determined by access control. 

• Private Secure Communications - A number of methods exist to secure the connections 

between systems. Internet Protocol Security (IPSec) has emerged as the most important 

protocol for establishing a secure connection. Using Internet standard IPSec protocols, 

the system should offer full end-to-end protection, including encrypted tunnels, for all 

communications. You should be able to easily create and control secure connections 

within your network infrastructure. 

• Network Intrusion Tools - Security audit tools and techniques are designed to diagnose 

the vulnerability of a system, and the potential risks if the system is attacked. Intrusion 

detection systems are predicated on the assumption that an intruder can be detected by 

examining various parameters such as network traffic, user locations, and various file 

activities. Called “audit trials”, these records are analyzed for unusual and suspicious 

behavior. 

• Firewalling - A firewall is a gateway that restricts and controls the flow of traffic 

between networks, typically between corporate networks and the Internet. Firewalls may 

also provide secure gateway services between internal networks. Firewalls monitor 

incoming and outgoing traffic and filter, redirect, repackage, and/or discard packets. 

• Authentication - Authentication is the process of verifying an identity claimed by or for 

a system entity. Authentication can provide assurance that users (or systems) are who 

they say they are. 

• Encryption -Encryption transforms some input into an output that is impossible to read 

without the proper key. 

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These design philosophies were employed in the design and implementation of both the 

Advanced Controller and the EMC. The Advanced Controller was rigorously tested using 

advanced network security tools to ensure it will withstand the threat of an attack. One tool that 

provided an especially complete set of tests was the Nessus tool. The Nessus runs more than 

1200 tests to assess vulnerabilities of devices that are part of a local area network (LAN) 

environment. In deployments, it is strongly suggested to put the controls behind an industrial 

grade firewall. Considering the risk of not having adequate security, designing and testing the 

Advanced Controls to this standard was a “must have” requirement. 

12.3 Market Analysis 

A large number of firms specialize in developing and deploying technologies for the 

communication and control for DG/CHP. In general, these firms can be classified into three 

industry segments: grid interface component providers, system integrators, and software service 

providers. The following text and Figure 30 describe these segments and leading companies 

relative to their position in the marketplace: 

Grid Interface Component Providers 

Equipment providers are often focused on grid interface and protective devices. These devices 

are the fundamental control elements of any DG/CHP interacting with the grid, generation, or 

energy storage devices. Firms such as Woodward Governor and Basler provide engine controls 

and protective relays that are frequently used in the DG market. Other firms such as ASCO or 

GE/Zenith provide grid interconnection equipment that lack many of the advanced 

functionalities implemented in the Advanced Controller developed on this contract. 

Systems Integrators 

Systems Integrators are divided into two categories. The first category is sophisticated OEMs, 

such as Wartsila that provide engines, generators, controls, automation software, and remote 

monitoring inside a single package. However, many of these OEMs use proprietary technologies 

that, by design, do not easily integrate with generators or software platforms provided by third 

parties. An open system, such as that used on the Advanced Controller, provides customers with 

greater flexibility, scalability, and long-term value. 

The second category of Systems Integrators comprises a limited number of companies that act as 

engineering consultants or switchgear providers that offer integrated solutions. Firms such as 

Enercon do not manufacture engines or generators but package on-site power systems, which 

include grid-interface hardware, communications modules, and application software. The lack of 

affiliation with a generator OEM allows these rivals to adopt an open systems interface with a 

multitude of hardware and software platforms. As these systems designers have not developed 

integrated communication and control technologies, they tend to use disparate components and 

charge their customers on a time and materials basis. The core technologies for this contract 

work reduce engineering labor for system integration and are cost-competitive with current 

product offerings in the market place. 

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Figure 30: Market Analysis 

Software Services 

A number of firms have established a beachhead by remotely monitoring, and in some cases 

dispatching, distributed generation assets. As the market for managed services is immature, none 

of these firms has a large pool of customers and many lack an understanding of generation and 

grid interface technologies. Few competitors have experience with operations and maintenance 

issues, and generally do not convert data into meaningful software applications to reduce 

operational costs and increase generator utilization. The ability to optimize generator 

performance, increase capacity factor, and reduce maintenance costs are unique skills in the 

managed services market. 

As the energy market continues to liberalize, new entrants will emerge. However, similar to 

today’s rivals, few entrants will be able to offer end-to-end solutions that integrate DG/CHP with 

the grid, other dispersed energy devices, intelligent electronic devices at the site, building 

automation systems, remote software applications, and the various energy markets. 

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12.4 Product Development Methodology and Results 

Figure 31: EMC System Architecture 

The EMC (Figure 31) is a technologically advanced data collection and aggregation service, 

which continually provides updated reporting on detailed site parameters, overall operational 

efficiencies, and economic performance of DG/CHP resources. The EMC leverages modern 

communications infrastructure (i.e., the Internet / FTP / XML and supporting technologies) to 

effectively and securely deliver high-level summary data to end-users anywhere, anytime. The 

EMC uses a combination of proprietary and commercially available technologies to retrieve, 

aggregate, normalize, analyze, and then report on data from diverse DG/CHP systems. This 

ability to aggregate raw data into meaningful intelligence based on a site's engineering design 

and utility tariff helps customers maximize the value of their DG/CHP systems. 

When a facility considers making significant capital expenditures for a distributed energy 

system, their decision is typically supported by detailed pro forma analyses. For certain types of 

facilities, the potential benefits for deploying CHP systems are highly attractive. They include: 

• Reduced energy costs 

• Reduced life-cycle costs 

• Attractive return on investment 

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• Improved power reliability 

• Improved economics for enhancing air quality. 

A reliable means of tracking the performance of a complex DG/CHP system is a “must have” for 

site operators in order to receive the feedback necessary to adjust and optimize system 

parameters. As operational efficiency reaches its peak potential, site managers remain focused on 

the costs incurred in producing power versus buying it from utilities. Without effective tools, 

these costs (and savings) can remain hidden, leaving management in the dark regarding their 

equipment’s return on investment. 

The EMC makes it possible to track cost savings from operating on-site power plants. Viewing 

summary data from a historical perspective allows usage patterns to emerge that facilitate 

intelligent operational decision making. The effort to effectively deploy and manage DG/CHP 

resources can seem daunting with the myriad of technical, maintenance, and financial issues. 

12.4.1 Design Details – Data Transport 

The EMC leverages the existing infrastructure typically seen at a DG site. Data coming off the 

data acquisition system is collected into an SQL server database every minute. Once every 15 

minutes the EMC Transmitter performs an SQL query on the database for the last 15 records. 

The results of the query are stored in a Net Dataset. Once in the dataset, the transmitter executes 

a built in .Net method to convert the data into an XML file. As the XML file is generated, the 

EMC Transmitter logs on to the Encorp EMC external FTP site. The EMC Transmitter then 

transfers the XML file containing the last 15 minutes of data into a preconfigured folder. Once 

the file is on the FTP server, the EMC Receiver, which is running on the Encorp EMC network 

at Encorp’s headquarters, opens the XML file into a Microsoft.Net Dataset. Once the dataset is 

populated, the EMC Receiver then connects to the EMC production SQL Server and inserts the 

data into the corresponding customer table. 

This architecture and the processes surrounding it have had multiple iterations of software 

releases to improve reliability and prevent any data loss. Some of the most challenging lessons 

that were learned from this architecture drove development on the EMC receiver. Device failure 

or lost communications would result in data loss. Encorp developed alarms at the EMC Receiver 

that alerts the proper support personnel to prompt immediate resolution. One other feature that 

was added was a 1-hour maintenance window in the early morning to provide time for backups 

of the databases both at the site level and the EMC level. 

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12.4.2 Design Details – Data Processing 

Once the data has been entered into the 

customer specific database it will be accessible 

via the EMC website. The customer can log 

on using a secure password to see a custom 

view of all the sites that are entered under his 

or her profile. Reports that are available for 

the customer’s viewing are listed in a selection 

box. Also next to that selection box is a 

selection box that allows users to specify the 

“from” date and the “to” date. Once the 

customer selects the site, the report, and the 

timing parameters, he or she would then click 

the “view report” button. 

Typical parameters for EMC based 

site 

Generator related Generator related Utility related 

Alarm Status Start Output Status Amps 

Fault Status Hz Amps A 

Coolant Temp kVA Amps B 

Fuel Flow Rate kVAR Amps C 

Oil Pressure kW Power Factor 

Amps kWh Volts A 

Amps A kWSP Volts B 

Amps B Receiver Temp Volts C 

Amps C Runtime Hz 

Demand Oil Temp kVA 

Peak Demand Oil Level kVAR 

Power Factor Operating State kW 

Volts A Exhaust Temp Volts 

Volts B Air Inlet Temp kWh 

Volts C Demand 

Breaker Status Peak Demand 

Running Status Breaker Status 

A Web request is sent to a software class that 

handles all the database connections for the 

Web site. This class triggers a database-stored 

procedure that processes large amounts of data 

into usable information. A Crystal Report file 

then transforms the database-stored procedure 

results into an easy-to-read report. 

Table 6: Typical EMC Parameters 

There were several difficult design and process challenges that were overcome on the data 

processing system for the EMC. The biggest challenges included providing adequate security for 

customer data, ensuring acceptable speeds when processing reports via the SQL stored 

procedures, and finally, standardizing the methodology that the development team used to 

implement code that stressed long-term maintainability. 

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12.4.3 EMC Data Examples 

 Table 6 shows some of the typical parameters that are monitored on a “base” level EMC system. 

Figure 32 shows two of the reports typically included in the same “base” level EMC package. 

Figure 32: Standard EMC Reports

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12.4.4 EMC Summary 

By utilizing a rigorous design process, the EMC has had success in the market place. Customers 

can read their Web reports on a daily basis to ensure the cost savings that they initially expected 

have actually materialized. The EMC was built to meet the challenges in the present, as well as 

into the future. One key design decision was to pass XML files via FTP to the datacenter from 

the DG sites. By utilizing XML, the EMC can easily be integrated into several other systems 

with minimal effort. 

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13. Appendix I: Demonstration of Controlled DP 

The final task to be completed was the demonstration of the Advanced Controller and EMC 

outside of the lab environment in an “uncontrolled” commercial deployment. This is the most 

critical step in the product development process. To be sure the Advanced Controller was 

adequately tested in this manner, the evaluation and selection of a demonstration site was 

essential. It was decided to utilize two demonstration sites to ensure broad coverage of 

commercially representative conditions. 

Establishing the two ideal demonstration sites was based on the following selection criteria. 

• Location of site 

o The site needed to be easily accessible by the development staff and the 

operations engineering staff to ensure a fast response to any problems. 

Locations that had enhanced security with restricted hours were not 

considered. 

o Testers targeted sites that represented a geographical marketplace where DG 

is prevalent to ensure a demonstration site that would be representative of the 

customers of the Advanced Controller. 

• Customer selection 

o It was important to select appropriate customers who would allow testers to 

utilize their sites and in some cases their customer’s sites. 

o The customers needed to understand the benefits of the Advanced Controller 

and be willing to accept the risk if the demonstration did not go smoothly. 

• Retrofit 

o It was decided to do the demonstration at two DG sites in which earlier 

generation Encorp controls were already deployed. This would allow a 

comparison of the existing structure with the Advanced Controller. 

o Sites that were using the EMC prior to deploying the Advanced Controller 

were selected to have a “before” and “after” site profile based on the 

information that was being gathered through the EMC. 

• Compliance with National Environmental Policy Act (NEPA) 

Based on these criteria, the first site was Encorp’s Headquarters in Windsor, Colorado, and the 

second demonstration site was the Aquarium of the Pacific in Long Beach, California, in 

partnership with City Light and Power in Long Beach. 

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13.1 Implementation Process 

Table 7 illustrates the process used to implement both demonstration systems. 

Table 7: Demonstration Checklist 

System Checklist 

Phase Details / Comments 

Customer kickoff meeting 

Site survey 

Preliminary design review w/ customer Review preliminary design: 

 Sequence of operations 

 Control scheme 

 Protection scheme 

 Communications architecture 

 Schedule of system implementation 

 Customer / Engineer preliminary signoff 

 

Sequence of operations Black start / Standby 

 Open or closed transition to generators 

 Open or closed transition back to utility 

 

Determine hardware design 

Identify parts needed to meet requirements for 

control and communications 

 Inventory the system's existing parts 

 

Change I/O modules from LONWORKS to 

Modbus I/O 

 Modify the system bill of materials 

 

Design system to capitalize improved control 

and communications capability 

 

Update wiring drawings 

Update drawings to include the Advanced 

Controller behaving as a GPC/UPC/MMC 

 

Add wiring and Modbus I/O (remove Acromag 

DI, DO and AO on generators and replace 

with Modbus I/O) 

 

Add wiring and Modbus I/O (remove 

LONWORKS analog output remote I/O 

modules and replace with Modbus I/O) 

 Update communications connections. 

 

Control software 

Create ISaGRAF for Advanced Controller 

based on existing bindings, ISaGRAF PLC 

code, and add new functionality. 

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System Checklist 

Phase Details / Comments 

 

Setup each of the needed function blocks 

using application defaults (settings optimally 

tuned at site). 

 

Implement engine interactions (load sharing, 

voltage bias, etc.) 

 

Review CHP PLC code and verify that there 

are no changes required. 

 Update sequence of operations. 

 

Protection scheme Determine the existing protection relays. 

 

Review relay settings with sequence of 

operations. 

 Determine relay interactions with controls. 

 Verify logic with utility protection relays. 

 Verify logic with generator protection relays. 

 

System bench test application 

Simulate the application and all I/O logic using 

ISaGRAF software. 

 

SCADA / Communications 

Configure the Ethernet OPC server for 

Modbus TCP interface. 

 

Load the address list from the ISaGRAF 

Workbench into the OPC server. 

 Update the addresses on the HMI screens. 

 

Update the addresses for the EMC data 

logger. 

 Update the SCADA documentation. 

 Bench test the application in simulation mode. 

 

Equipment inspection Inspect all hardware to be used at site. 

 Power up test. 

 Upload firmware to controls. 

 

System simulation testing 

Wire system up in lab as it would appear in 

the field. 

 

Execute system simulation tests from 

ISaGRAF Workbench. 

 Test all I/O and SCADA screen interactions. 

 All hardware packaged and shipped to site. 

 

Preliminary site commissioning Receive equipment. 

 Inspect all equipment that was received. 

 Implement wiring based on wiring diagrams. 

 

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System Checklist 

Phase Details / Comments 

Site commissioning Install equipment. 

 Equipment power up. 

 Wire all controls and communications nodes. 

 Power all equipment up into the system. 

 

Set protection and engine systems into test 

mode. 

 Test interactions with engine / engine control. 

 

Verify control outputs to engine are properly 

scaled. 

 Ensure output timing is adequate. 

 

Monitor and adjust both engine and control 

based on interaction. 

 

 Test interactions with protective relays. 

 

Verify control outputs to protective relays are 

properly scaled and being received. 

 

Verify control inputs from protective relays are 

properly scaled and being received. 

 

Ensure timing for interactions are adequate 

between controls and protective relays. 

 

Monitor and adjust controls based on 

interaction. 

 

 Commission the SCADA system. 

 Set up network addresses. 

 Set up OPC servers. 

 

Ensure variables from controls are updating in 

OPC server properly 

 Setup EMC logging through OPC server. 

 Setup HMI screens through OPC server. 

 

Setup panel HMIs directly to control Modbus 

port. 

 Commission alarm and trending servers. 

 

Ensure user settings are correct for network 

security. 

 

Ensure the OS and all server software is 

properly updated. 

 

Set EMC up to begin updates. Verify files are 

being properly created and sent. 

 

Final commissioning 

Put system into "Run" mode. Monitor and 

adjust base on system interactions. 

 

Record all control and relay data at 1-minute 

samples and review data for irregularities. 

 

Review site design and implementation with 

customer. 

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System Checklist 

Phase Details / Comments 

 

Train customer on SCADA system, system 

interaction. 

 

Customer and engineer sign off 

commissioning. 

 

Final site acceptance 

All documentation to be reviewed and 

updated as result of implementation. 

 

System alarms and data reviewed with 

customer at regular interval. 

 

Any irregular behavior reviewed with 

customer. System updated remotely as 

needed. 

 Final documentation sent to customer. 

 Final documentation archived. 

 

Final acceptance signed by engineer / 

customer. 

 

Ongoing monitoring and tech support 

provided as agreed to in initial contract. 

13.2 Demonstration Site One - Encorp Headquarters 

13.2.1 Site Description 

Encorp’s headquarters in Windsor, Colorado, was built and opened in 2001. The facility has 

80,000 square feet that includes manufacturing facilities, office space, and a small data center. 

The facility utilizes power that is being distributed by Xcel Energy. The facility uses one Detroit 

Diesel Generator with a nameplate capacity of 535KW to provide backup power in case of a 

utility outage. Due to the need for reliable power for the small data center, the site is 

representative of a critical power application that would be analogous to a telecommunications 

center or a hospital. 

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Figure 33: Demonstration Site One - Encorp Headquarters 

13.2.2 Advanced Controller Design of Site 

The system utilizes one Advanced Controller as both a GPC and a UPC. This mode of operation 

is referred to as a Power Transfer Control (PTC). In this mode, the Advanced Controller 

monitors all the incoming utility power and turns on the generator during any utility failures. 

The following is a high-level graphics representation of the site. 

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Figure 34: Demonstration Site One - Graphical Representation 

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13.2.3 Results of Testing 

The implementation results for this first demonstration site were very positive. Transitioning the 

Advanced Controller into the hands of the engineering and operations team from the 

development team was eased tremendously because of the use of the ISaGRAF Workbench and 

standard IEC 61131 programming languages. The function blocks that provide the control 

algorithms were implemented along with the IEC standard functions such as muxes and gates. 

This sped the implementation and facilitated easier customization needed to meet the particular 

nuances of the site’s sequence of operation. These standard programming languages are another 

major benefit of the Advanced Controller, allowing industry engineers to quickly understand and 

use the Advanced Controller with minimal specialized training. 

Improvements in speed and reliability surrounding data collection were also evident because of 

the Advanced Controller’s data acquisition enhancements. This was very useful for remote 

monitoring, database storage, and generation of system health and status pages to the technical 

support cellular telephones and emails. The system was configured to generate an informational 

email to the cellular phone of selected employees to indicate when the site was being powered 

solely by generation during the monthly load test or if the site was down because of an 

emergency. During testing, the facility was seamlessly transferred to backup generation, so the 

e-mail messages provided the only indication to other plant personnel that the test was 

happening. 

 

Construction and spring thunderstorms were the primary cause of most interruptions in utility 

electrical power. The event recording of the power conditions at the time of interruption was 

performed at a much faster frequency (1 second) to the standard database programs than by the 

previous communication channels. This enabled site personnel to know the cause and type of 

interruption more precisely than before. 

Noticeable improvements were evident in the overall system maintenance as well. Having a 

single hardware and software platform lessened the site’s complexity. This enabled the site to 

receive several firmware upgrades and feature enhancements with less overall testing than was 

previously possible. These features provided operational efficiencies that reduce the overall cost 

of system implantation and reduced the overall operational maintenance costs. 

Having TCP/IP Ethernet on the Advanced Controller allowed the controls to be placed on the 

facility network. Although the Advanced Controller might have a dedicated network at many 

sites, this allowed the controller to be tested with all of the communication traffic of the facility 

and not just the site. It also gave users the ability to monitor or demonstrate remote connections 

into the site. 

In performance testing, the Advanced Controller exhibited a high degree of stability and 

“smoothness” as it was taken through the loading, unloading, base load control, and import 

control algorithms. In particular, the import control was able to control to within a +/- 10 kW 

level, where previously only +/- 20 kW was obtainable. In the base load mode, the export 

control limiter function transitioned from base load to export limiting function without any 

issues. The export limiting function comes into play when a base load level is set on the 

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generator, but the site load decreases to the point where the export limiter decreases the generator 

load to maintain the desired export of power from the utility to the facility. 

All software programming for the control, including communication settings and tunable 

configurations for the site, were backed up on the MMC card. In the unlikely event of an 

Advanced Controller failure, the MMC card could be inserted into a replacement control and all 

software programming, custom settings, and performance tunings could be restored in a single 

step. This feature will greatly reduce field maintenance costs of deployed Advanced Controllers 

allowing a control to be shipped and installed by on-site personnel, circumventing the need for 

an engineer to travel to the facility to replace the controller. And finally, the team successfully 

executed all the tests identified in the aforementioned system checklist. This site will continue to 

provide critical power protection for the site and will act as a production test environment as new 

features are released. 

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13.3 Demonstration Site Two - The Aquarium of the Pacific 

The second demonstration site was the Aquarium of the Pacific (AOP) in Long Beach, 

California. AOP is one of the largest aquariums in the United States. It is home to more than 

12,000 ocean animals that represent 1,000 different species. The beautifully architected 156,735 

square foot building is right next to the Pacific Ocean on the west side of downtown Long Beach. 

AOP was visited by over 1.1 million people in 2003 making it the third most attended cultural 

institution in the greater Los Angeles area. It is a strong asset to the community, bringing in 

more than $20 million in economic benefits to Long Beach and $100 million to Los Angeles 

County annually. 

Figure 35: Demonstration Site Two - Aquarium of the Pacific 

AOP has a very high-tech water filtration process that filters more than 900,000 gallons of salt 

water per hour. In that system there are 10 miles of piping, 79 life support circulating and 

exchanger pumps, 44 sand filters, 14 ozone chambers, and 14 de-gas chambers. AOP worked 

with City Light and Power of Long Beach to design a CHP system to offset the demand for 

utility power and utilize the heat coming off the twin 675kw Duetz natural gas generators 

throughout several critical processes in the facility. Figure 36 shows the layout of the generators 

and some of the CHP systems at the site. 

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Figure 36: System Layout 

13.3.1 Advanced Controller Design at Site 

The design consisted of four different controls: 2 GPCs, 1 UPC, and 1 Meter Monitoring Control 

(MMC). An Advanced Controller was used for each of these devices. Figure 37 and Figure 38 

are the one-line diagram and the communications overview of the contract work. 

 

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Figure 37: One-Line Diagram 

89
Figure 38: Communications Diagram 

The functional description of the site with the deployed controls follows. 

• UPC – The utility power control watches the incoming utility. It is configured for three 

phase monitoring on the utility power side of the utility tie breaker and 1 phase of 

monitoring after the breaker. Based on the information it receives, it coordinates the rest 

of the controls through the LONWORKS connection. 

• GPC1, GPC2 – These GPCs are used to monitor and control the two Gensets and a pair 

of generator tie breakers. The method for control on these Duetz engines is to send a KW 

setpoint for the engine to run against. 

• MMC – this control is metering the facility load after it passes through a feeder breaker to 

provide the AOP with the load. 

• CHP PLC – This is a PLC that gathers all the information about the facility’s CHP 

system. 

• Communications gateway– This is the main computer at the site. It collects all the 

information from each control and the CHP PLC. Once the information is collected, it is 

stored in a database, displayed on a screen on site and remotely, and sent back to the 

EMC for archival and reports for data analysis. Some alarms generate e-mails to notify 

Encorp or site personnel. 

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13.3.2 Results of Implementation / Testing 

The final signoff from the customer was received on June 1, 2005. The EMC continues to 

receive data from the site to be monitored and reviewed by the engineering team in conjunction 

with the customer. The following is a view of the system’s performance over the month since 

the data recorded after the commissioning was complete. 

Table 8: System Performance Data 

Engine 1 Engine 2 KWH Produced 

Date 

Run 

Hrs % 

Run 

Hrs % Total Peak Mid Off 

Gas Flow 

(CF) 

6/1/2005 23.72 98.82 23.72 98.82 26,808 0 14,890 11,918 312,200

6/2/2005 23.78 99.1 23.78 99.1 26,904 0 14,904 12,000 315,600

6/3/2005 23.77 99.03 23.77 99.03 26,602 0 14,710 11,892 313,600

6/4/2005 23.38 97.43 23.38 97.43 26,430 0 0 26,430 309,400

6/5/2005 23.55 98.13 23.55 98.13 26,070 0 0 26,070 307,900

6/6/2005 24 100 24 100 25,546 6,792 10,066 8,688 302,600

6/7/2005 23.98 99.93 23.98 99.93 24,872 6,742 10,136 7,994 297,900

6/8/2005 22.58 94.1 22.03 91.81 24,268 6,752 9,854 7,662 286,700

6/9/2005 23.85 99.38 23.85 99.38 26,048 6,709 10,176 9,163 308,400

6/10/2005 23.63 98.47 23.63 98.47 26,310 6,688 10,160 9,462 311,700

6/11/2005 23.72 98.82 23.72 98.82 26,117 0 0 26,117 309,300

6/12/2005 23.75 98.96 23.75 98.96 26,008 0 0 26,008 309,500

6/13/2005 23.52 97.99 23.52 97.99 26,031 6,618 10,101 9,312 311,600

6/14/2005 24 100 24 100 25,902 6,686 10,111 9,105 309,400

6/15/2005 24 100 24 100 25,795 6,686 10,127 8,982 306,900

6/16/2005 24 100 24 100 26,063 6,703 10,163 9,197 308,000

6/17/2005 21.97 91.53 24 100 25,062 6,746 9,691 8,625 294,600

6/18/2005 24 100 24 100 26,211 0 0 26,211 307,000

6/19/2005 24 100 24 100 26,039 0 0 26,039 306,700

6/20/2005 24 100 21.97 91.53 24,444 5,802 9,615 9,027 290,800

6/21/2005 24 100 21.93 91.39 24,592 6,336 9,276 8,980 291,200

6/22/2005 24 100 12.52 52.15 19,850 6,530 6,404 6,916 238,500

6/23/2005 24 100 24 100 26,122 6,746 10,251 9,125 308,100

6/24/2005 24 100 24 100 26,068 6,708 10,202 9,158 310,400

6/25/2005 23.4 97.5 23.78 99.1 25,988 0 0 25,988 306,700

6/26/2005 24 100 24 100 26,448 0 0 26,448 313,600

6/27/2005 24 100 21.52 89.65 24,378 6,238 9,152 8,988 291,400

6/28/2005 24 100 22.45 93.54 25,070 6,774 9,616 8,680 297,300

6/29/2005 22.27 92.78 24 100 25,236 6,746 9,808 8,682 302,300

6/30/2005 19.68 82.01 17.47 72.78 20,048 6,776 5,620 7,652 239,800

7/1/2005 23.32 97.15 22.38 93.26 20,820 4,238 8,276 8,306 258,800

7/2/2005 24 100 12.57 52.36 15,914 0 0 15,914 204,000

7/3/2005 24 100 7.3 30.42 17,716 0 0 17,716 214,600

Totals: 777.87 98.2% 730.57 92.2% 815,780 130,016 233,309 452,455 9,696,500

91
The system’s runtime percentage is especially worth noting; there have been no long periods of 

downtime due to problems with the Advanced Controller. 

The Advanced Controller has helped with time-based event analysis. The controls are 

configured to record important data to the database on the CPM at 1-second intervals. 

Previously, due to the amount of data, communication constraints, and graphically displayed 

data, only 10-second intervals were possible. The 1-second interval data allowed operators to 

pinpoint an on-engine condition as the source of a generator shutdown, allowing a quick 

resolution to the problem. 

Improvements made to the functionality of the export limiter of the utility base load controller 

function block improved the generation efficiency at the site by providing a much smoother 

transition between the base load operation that the customer desires and the export limiting that 

the utility requires. 

92
14. Appendix J: IEEE Standards Activities 

In addition to conducting the technical tasks identified in Phase II during option year 1, there 

were concurrent support efforts in the development of interconnection standards through the 

IEEE 1547.1 - 1547.5 working groups and participation in several DOE Distributed Power 

Program (DPP) review meetings. Encorp has supported interconnection standards and has 

served on various IEEE 1547 committees. 

The IEEE 1547 standards efforts were led by DOE through NREL, and have been 

instrumental in reducing the barriers to implementing and interconnecting DG with the electric 

power system. 

The IEEE 1547 standards effort consists of the following: 

− IEEE STD 1547 (2003) (Interconnection Standard) -- Chair: R. DeBlasio, NREL; > 500 

volunteers developed or balloted standard. 

− IEEE STD 1547.1 (2005) (Test Standard) -- Chair: J. Daley, ASCO Power Technologies, 

Inc., 82 members; ballot Fall 2004. 

− P1547.2 (Guide to STD 1547) -- Chair: N. R. Friedman, Resource Dynamics Corporation, 96 

members. 

− P1547.3 (Guide for Monitoring, Information Exchange, and Control) -- Chair: F. Goodman, 

EPRI, 95 members. 

− P1547.4 (DR Islanding Systems) – start Dec. 2003; Chair: B. Kroposki, NREL, 25 members. 

− P1547.5 (Interconnection >10 MVA to Transmission Grid) – start Sept. 2004; Chair: M. N. 

Satyanarayan, Xcel Energy (membership). 

− P1547.6 (DR on Secondary Networks) – start Mar 2005; Chair: J. L. Koepfinger, IEEE 

Standards Board Emeritus (establishing membership). 

The benefits of the IEEE 1547 standards efforts include: 

− Safeguards against hazards 

− Fostering quality design and manufacture 

− Increasing competitiveness in industry 

− Creating and expanding markets 

− Facilitating trade and commerce 

− Ensuring that products meet quality standards so that users need not be concerned with 

further testing or evaluation of the product 

− Accelerating engineering advances and implementation, interoperability, and installation 

− Assisting increased quality and reliability achievement 

− Simplifying compliance to needs, permitting, and rules 

− Promoting advanced communications; software platforms interchangeability 

− Enabling enhanced DR systems and grid intelligence 

− Lowering cost and deploying projects more quickly. 

93
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1. REPORT DATE (DD-MM-YYYY)

March 2006 

2. REPORT TYPE

Subcontract Report 

3. DATES COVERED (From - To)

12/11/00 – 08/30/05 

5a. CONTRACT NUMBER

DE-AC36-99-GO10337 

5b. GRANT NUMBER

4. TITLE AND SUBTITLE

Innovative Distributed Power Grid Interconnection and Control 

Systems: Final Report, December 11, 2000 - August 30, 2005 

5c. PROGRAM ELEMENT NUMBER

5d. PROJECT NUMBER

NREL/SR-560-38982 

5e. TASK NUMBER

DP05.1001 

6. AUTHOR(S)

K. DePodesta, D. Birlingmair, and R. West 

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

Gas Technology Institute Encorp, Inc. 

1700 South Mount Prospect Road 9351 Eastman Park Drive 

Des Plaines, IL 60018-1804 Windsor, CO 80550 

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ACL-1-30605-04 

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NREL 

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National Renewable Energy Laboratory 

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NREL/SR-560-38982 

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14. ABSTRACT (Maximum 200 Words)

The contract goal was to further advance distributed generation in the marketplace by making installations more costeffective and compatible with existing systems. This was achieved by developing innovative grid interconnection and 

control systems. 

15. SUBJECT TERMS

distributed generation; distributed power; interconnection; advanced controller; DG; DP; distributed energy resources; 

DER; grid; remote monitoring; diagnostics; grid communication 

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