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Conference Paper

NREL/CP-5D00-73848

May 2019

Interconnection Requirements for 

Renewable Generation and Energy 

Storage in Island Systems: 

Puerto Rico Example

Preprint

Vahan Gevorgian,

1 Murali Baggu,1 and Dan Ton2

1 National Renewable Energy Laboratory 

2 U.S. Department of Energy 

Presented at the 4th International Hybrid Power Systems Workshop

Crete, Greece

May 22–23, 2019 
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Conference Paper

NREL/CP-5D00-73848

May 2019

Interconnection Requirements for 

Renewable Generation and Energy 

Storage in Island Systems: 

Puerto Rico Example

Preprint

Vahan Gevorgian,

1 Murali Baggu,1 and Dan Ton2

1 National Renewable Energy Laboratory 

2 U.S. Department of Energy 

Suggested Citation 

Gevorgian, Vahan, Murali Baggu, and Dan Ton. 2019. Interconnection Requirements for 

Renewable Generation and Energy Storage: Puerto Rico Example: Preprint. Golden, CO: 

National Renewable Energy Laboratory. NREL/CP-5D00-73848.

https://www.nrel.gov/docs/fy19osti/73848.pdf.
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Interconnection Requirements for Renewable 

Generation and Energy Storage in Island Systems:

Puerto Rico Example

Vahan Gevorgian, Murali Baggu

National Renewable Energy Laboratory

Golden, Colorado, USA

vahan.gevorgian@nrel.gov, murali.baggu@nrel.gov

Dan Ton

U.S. Department of Energy

Washington DC, USA

dan.ton@hq.doe.gov

Abstract— On September 20, 2017, Hurricane Maria made 

landfall in Puerto Rico, incapacitating the central power system 

and leaving the entire island without power. To ensure the longterm recovery of Puerto Rico’s electric power grid in the most 

secure and resilient way, the U.S. Department of Energy funded 

research to develop recommendations for a cohesive new 

framework of interconnection standards for utility-scale 

renewable electrical generation and energy storage that ensure 

cross-technology compatibility and enable high deployment 

levels without compromising grid reliably, safety, or security. 

This paper provides a summary of work conducted by the 

National Renewable Energy Laboratory to analyze and address 

many shortcomings and areas of improvement to help the

Puerto Rico Electric Power Authority (PREPA) establish

minimum technical requirements for interconnecting singletechnology and hybrid renewable generation because of their 

importance for PREPA system security and impacts on future 

integrated resource planning scenarios. Results and findings 

presented in this paper are important for any island power 

system.

Keywords-component; renewable power plants, energy 

storage systems, grid services, interconnection requirements

I. INTRODUCTION

The future of Puerto Rico’s still-recovering electricity 

system does not rely only on repairing the island’s grid but 

also on rebuilding and modernizing it to make it resilient, 

low-carbon, and less dependent on imported fuels. The new 

“post-Hurricane Maria” integrated resource plan (IRP) is 

under development by the Puerto Rico Electric Power 

Authority (PREPA) to identify potential strategies to meet the 

island’s electricity needs through 2035, including new 

renewable generation, new or modernized conventional 

generation, retirements of existing units, transmission 

buildup and reinforcement, and large-scale deployment of 

other enabling technologies such as energy storage [1]. The 

main goal of the IRP is to achieve a least-cost, reliable, 

resilient, renewable-dominated power system for Puerto Rico 

[2]. On October 2018, a regulatory framework and energy 

policy bill was introduced in the Puerto Rico Senate. This 

new legislation calls for generating 100% of the Puerto Rico’s

power using only renewable energy by 2050. The traditional 

approach to renewables as a provider of bulk variable power 

to the grid might no longer be sufficient to meet the evolving 

expectations for enhanced resilience in the island. Advanced 

power electronics-coupled renewable generation and energy 

storage technologies can be controlled to contribute to 

system-wide reliability. The deployment of utility-scale, gridfriendly solar photovoltaic (PV) and wind power plants as 

well as energy storage systems that incorporate advanced 

capabilities to support grid stability and reliability is essential 

for the large-scale integration of variable renewable 

generation into PREPA’s power grid.

 Modern PV and wind power plants as well as energy 

storage systems can be used to mitigate the impact of 

variability on the grid, a role reserved by PREPA for 

conventional generators. For example, it was demonstrated in 

[3] how very large PV power plants can provide essential 

reliability services to the grid, enabling PV to become a 

provider of a wide range of grid services, including spinning 

reserves, load-following, ramping, frequency response, 

variability-smoothing, frequency regulation, and voltage 

support. It was also demonstrated in [4] how a utility-scale 

20-MW PV plant can provide reliability services to the 

PREPA transmission grid in the form of PV plant 

participation in automatic generation control (AGC), the 

provision of programmable frequency droop, and fast 

frequency response (FFR).

To ensure the long-term recovery of Puerto Rico’s power 

grid in the most secure and resilient way, the U.S. Department 

of Energy (DOE) convened experts from many national 

laboratories to develop a cohesive set of recommendations 

based on the expert opinions of the varied stakeholders to

ensure a strong technical rational for Puerto Rico’s energy 

investment decisions. A resilient electric grid is vital to Puerto 

Rico’s security, economy, and way of life and will provide 

the foundation for essential services upon which people and 

businesses on the island rely every day. The goal of work 

described in this paper was to develop recommendations for 

a new framework of interconnection standards for utilityscale renewable electrical generation and energy storage that 

ensure cross-technology compatibility and enable high 

deployment levels without compromising grid reliably, 

safety, or security. Modification of the existing and 

development of new valid interconnection requirements for 

grid-level variable renewable generation and energy storage 

are important tasks in this process because all reliability 

evaluation efforts for future planning assessments for the

Puerto Rico grid must rely on them. This consideration is one 

important motivation behind the National Renewable Energy 

Laboratory’s (NREL’s) research effort described in this 

paper. 
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II. INCREASING NEEDS IN RALIABILITY SERVICES IN 

ISLAND SYSTEMS

Many island utilities, such as Hawaiian Electric 

Companies, are considering renewable resources and 

enhancing technologies such as energy storage and demand 

response to play an integral role in the grid of the future; 

meanwhile, the role of fossil fuels is expected to diminish 

from the energy mix in the islands [5]. Energy storage is also 

one potential resource for flexibility and reliability services 

within a diverse resource portfolio. Many island utilities are 

evaluating energy storage technologies and roles they can 

play to increase the operational flexibility of the existing (but 

often aging and slow) generating units. The deployment plans 

for energy storage must be developed in concert with other 

operating practices, such as generating unit dispatch, loadshedding schemes, load management, and customer-focused 

solutions [5]. In addition, advanced reliability services by 

energy storage systems such as synthetic inertia and FFR 

stacked on top of more common applications—such as 

frequency regulation, renewables ramp limiting, and voltage 

support—should be considered when defining the role of 

storage in island systems for enhanced security and resilience.

On international power sector scenes for islands and 

isolated power systems, there is widescale adaptation and 

increasing experience, especially in frequency control 

measures of any variable generation and energy storage [6]. 

Most international experiences in frequency control for 

power systems with very high shares of variable generation 

revolve around key areas of managing power systems with 

low inertia (and therefore a high rate of change of frequency 

[ROCOF]), using faster frequency control characteristics 

offered by inverter-coupled variable generation and energy 

storage. A few large international jurisdictions (500 MW or 

more) are experiencing issues related to high ROCOF [6], 

such as EirGrid/ System Operator for Northern Ireland 

(SONI), National Grid in Great Britain, and Cyprus [7]. The 

Australian Energy Market Operator (AEMO), EirGrid, and 

SONI have performed significant research work on 

challenges related to the operation of low-inertia grids [8]. 

SONI proposed interim grid code standards of 1 Hz/s over

500 ms for the Ireland system and 2 Hz/s for the Northern 

Ireland system. A high ROCOF was experienced in the 

South Australia system during the blackout event on 

September 28, 2016, [9] and issues related to ROCOF are 

investigated in the Future Power System Security Program 

at AEMO. Simulations are performed to demonstrate the 

behavior of the system for different fast frequency responses 

from wind turbines [10]. WEB Aruba is using flywheel 

energy storage for frequency regulation in their power 

system, which has high levels of wind and solar generation. 

PREPA’s system will be trending toward lower levels of 

synchronous inertia, meaning that there are significant 

advantages to targeting a future system for the island capable 

of withstanding extreme ROCOF scenarios. This process 

needs to commence early to ensure that generation installed 

during various stages of IRP deployment has the capabilities 

to operate in the future high-ROCOF environment and can 

demonstrate functionality to mitigate ROCOF. The process 

of retrofitting plants to ensure compliance for existing plants 

would be much more complicated and costlier. In 

combination with other active power control (APC) features

such as FFR, primary frequency response (PFR), and AGC 

participation by variable generation and energy storage, the 

acceptable levels of frequency response can be achieved in 

the future PREPA system. 

The effects of the widespread electricity loss in Puerto 

Rico triggered discussions on possible pathways for 

improving island electric system reliability and system 

resilience. The challenges in achieving both goals are 

different because system reliability and system resilience are 

related but depend on different scopes and regulatory 

environments. Reliability is often referred to as the ability of 

a system or its components to withstand transient and 

dynamic instability, uncontrolled events, cascading failures, 

or unanticipated loss of system components [11]. On the 

other hand, reliability is also referred to as the ability of a 

system or its components to adapt to changing conditions and 

withstand and rapidly recover from disruptions. The 

reliability metrics, standards, and indices have historically 

been well defined and enforced by the Federal Energy 

Regulatory Commission (FERC) for the bulk power system 

through several orders, and they have been less formalized 

but still well studied for many island communities. From this 

perspective, the evolving development of interconnection 

requirements for island systems—and PREPA, in 

particular—although still challenging, can be considered 

more or less a straightforward process; however, 

incorporating resilience-related controls for variable 

generation and energy storage is more challenging, 

especially considering the fact that there are no commonly 

used metrics for measuring grid resilience. As of today, 

electric system resilience for any jurisdiction is not mandated 

by federal, state, or territorial legislations. A 2016 report 

from several DOE national laboratories focused on this 

changing environment and the need to maintain a resilient 

power system [12]. This report provided recommendations 

“to guide future decision-making to enhance resilience of the 

U.S. electricity system,” including a recommendation on the 

development of a robust and scalable system of resilience 

metrics for the electricity system. This report provides some 

initial recommendations for interconnection requirements 

for variable generation and energy storage technologies 

related to resilience, such as grid-forming and black-start 

capabilities. More on this topic will be covered in the Phase 

II activities along with progress on the IRP development and 

work on better defining the resilience metrics for PREPA. 

III. RENEWABLES INTEGRATION CHALLENGES IN PUERTO 

RICO

PREPA has a modern electric power system that serves 

the entire main island of Puerto Rico and its two adjacent 

islands of Vieques and Culebra. The subsea cable to Vieques 

was damaged during the hurricane, so both Vieques and 

Culebra are now disconnected from the PREPA grid. 

Currently, the total installed generation capacity in Puerto 

Rico is close to 6 GW, which includes almost 200 MW of 

wind and solar PV generation (Figure 1).

Puerto Rico’s power system exhibits an interesting cycle 

of a daytime peak, followed by a solar and wind power rampdown, followed by an evening system load ramp-up that 

reaches a nighttime peak that is higher than the daytime. This 
3

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cycle is extremely important to the challenges of integrating 

wind and solar into Puerto Rico’s power system. 

Figure 1. Installed generation capacity in Puerto Rico (2016 data)

Some hypothetical scenarios for PREPA net load at 

different installed PV capacities calculated by NREL are 

shown in Figure 2 (similar to the California Independent 

System Operator “duck” curve). High levels of PV 

generation will cause sharp changes in the real-time ramping 

needs, so more resources with faster ramping capacity will 

be needed to meet these stiff evening and morning net load 

ramps. At very high PV penetration levels, the “belly of the 

duck” could actually go negative, requiring either 

curtailment or energy storage capacity to shift it. As 

described earlier, energy storage can be a potential resource 

for flexibility and the provision of reliability services within 

such PV resource portfolios.

Figure 2. Hypothetical net load profiles at different PV capacities

IV. PREPA’S EXISITING MTRS

In 2012, PREPA developed its own set of interconnection 

requirements, or minimum technical requirements (MTRs), 

with which all transmission-level utility-scale wind and solar 

PV generators shall comply [13]. A 2014 Siemens Power 

Technologies International (PTI) study [14] confirmed the 

importance of 100% compliance with PREPA’s MTRs for 

the planned target of 579.4 MW of renewable generation 

(419.4 MW of PV and 160 MW of wind). In addition, the 

same study stressed the importance of existing and future 

renewable generation to provide frequency regulation. The 

new, post-Hurricane Maria IRP, also being developed with 

help by Siemens, will define new feasible levels of variable 

generation and required levels of energy storage in the 

PREPA grid to ensure an affordable, reliable, and secure gird 

of the future in Puerto Rico. From this perspective, it is 

anticipated that PREPA’s MTRs will constantly evolve as 

the level of renewable penetration increases, modeling tools 

are improved, and experience with system performance is 

gained. 

PREPA’s existing MTRs for PV generation already required 

that utility-scale PV projects should have many reliability 

controls available, including: 

• Low-voltage ride-through (LVRT) and high-voltage 

ride-through (HVRT) controls 

• Voltage regulation controls 

• Steady-state and dynamic reactive power controls 

• Frequency fault ride-through (FRT) controls 

• Frequency response and frequency regulation controls

• Ramp-rate controls 

• Active power management.

In addition, requirements such as transient FRT, power 

quality compliance, and resource forecast have been listed in 

the 2012 MTRs. 

A 2015 project funded by DOE’s Solar Energy Technologies 

Office was designed to provide PREPA with an opportunity 

to spur the adoption of and contribute to improving advanced 

grid-friendly controls of utility-scale PV generation [4]. 

These goals were achieved by conducting such tests and 

demonstrations on a 20-MW grid-connected PV power plant 

located along the south coast of Puerto Rico (AES Ilumina 

PV power plant). This NREL-led demonstration project laid

the foundation for understanding what types of benefits can 

be provided to PREPA’s reliability by using advanced 

reliability service controls of modern utility-scale PV power 

plants. A joint NREL, AES, PREPA, and GPTech team 

modified the AES plant controls to provide new types of 

reliability services, including plant participation in AGC and 

the provision of PFR and FFR. In fact, at the time, it was the 

first and largest project of its kind ever conducted using a 

utility-scale PV power plant. For AGC tests, it is remarkable 

to notice that during certain periods of testing the AES 

Ilumina PV power plant was the only resource in PREPA 

participating in AGC. The results of one AGC test from 

August 14, 2015, are shown in Figure 3, where 40% 

curtailment from available solar power was used to provide 

headroom for following the AGC signal provided by

PREPA. 

The results of the 2015 NREL project showed clearly that 

it is mainly a matter of implementing controls and/or 

communications upgrades to provide a full suite of gridfriendly controls from hardware components that are already 

in existence in many utility-scale PV plants. Carefully 

designed new or modified existing interconnection 

requirements should help PREPA unleash these capabilities 

from renewable resources and use them as one of many tools 

in PREPA’s tool set for achieving the broader objective of a 

resilient, reliable, low-carbon grid for Puerto Rico. 
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Figure 3. Example of AGC test conducted in 20-MW AES Ilumina 

PV plant in Puerto Rico

V. RECOMMENDATIONS ON MTR MODIFICATIONS

A. Inertial Reponse

Inertial response is the important characteristic of any 

power system that impacts the initial ROCOF during 

contingency events, similar to the one shown in Figure 4. 

This event was recorded in August 2017. 

Figure 4. Frequency event recorded in Puerto Rico

PREPA’s existing MTRs for wind power require the

provision of inertial response; however, it does not specify 

characteristics of such response such as magnitude of the 

response and frequency/ROCOF deadbands.

Figure 5. Aggregate inertial response of 100-MW wind power plant

Based on these considerations, NREL recommended 

including requirements on ranges for inertial control 

deadbands for frequency and ROCOF and also including

requirements on the magnitude of inertia response as a 

percentage of prefault power level or total plant capacity. For 

example, the programmable frequency deadland for inertial 

response can be within a range of 0.025–0.3 Hz. The 

programmable ROCOF deadland can be within a range of 

0.1–2 Hz/s. The magnitude of inertial response can also be 

programmable within a range of 0–0.15 p.u. The exact values 

for deadbands need to be verified during integration studies. 

PREPA can request plant operators to change these values at 

later times if changes in the system occur and retuning 

inertial parameters is needed. 

B. Primary Frequency Response

The primary frequency response (PFR) requirement is 

very well defined in the existing MTRs for both wind and 

solar generation; however, it is important to point out that 

both wind and PV power plants can reduce their power 

outputs very fast during frequency events, so nonsymmetric 

droop characteristics are possible. This way, more 

aggressive down-regulation droop settings can be used to 

arrest fast overgeneration events. 

Figure 6 shows test results for a 1.5-MW wind turbine 

generator (WTG) exposed to real step changes in frequency 

emulated by NREL’s medium-voltage grid simulator. As 

shown, the turbine first provides inertial response 

immediately after the frequency drops, then it deploys and 

maintains its primary reserve in accordance with the 3% 

droop setting until the frequency returns to nominal, and it

can provide these services at any wind speed conditions. 

Figure 6. Utility-scale 1.5-MW WTG providing inertial response 

followed by droop response

C. Automatic Genmeration Control

The existing PREPA MTRs for wind and solar do not 

have a clause for AGC participation by wind and solar 

generation, so renewable plants in Puerto Rico are not AGC 

capable. The purpose of the AGC functionality for renewable 

generation is to enable a wind or solar PV power plant to 

follow the active power set points sent by PREPA’s AGC 

system. When in AGC mode, the power plant controller 

(PPC) of renewable plants initially sets them to operate at 

power levels that are lower than the estimated available peak 

power to have headroom for following the up-regulation 

AGC signal. The lower boundary of AGC operation can be 

set at any level below the available peak power, including 

full curtailment, if necessary. PREPA’s AGC is normally set 

to send a direct MW set-point signal to all participating units 

every 2 s. For more efficient participation in an AGC 

scheme, all ramp-rate settings in the PV and wind power 

plant’s PPC should be set at a very high level.

PREPA’s area control error (ACE) is expected to have 

strong correlation with grid frequency because it is an 

islanded system. Figure 7 shows 2-s ACE data plotted 

against PREPA’s frequency. It can be observed from the plot 

that ACE correlates very well with frequency (correlation 

factor 0.87), and it essentially represents the “sensitivity” (or 

bias) of PREPA’s frequency to load-generation imbalances. 

During this day, PREPA system exhibited B≈9.1 MW/0.1

Hz. Of course, the distribution of the frequency bias B needs 

to be analyzed for the whole year; however, even this 
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preliminary value allows estimating the amount of frequency 

regulation reserves for different renewable penetration levels 

to maintain PREPA’s frequency within predefined limits.

The ability of utility-scale PV generation and WTGs to 

follow AGC set points was tested by NREL in collaboration 

with industry partners [3], [15]. Note that PV plants should 

be able to maintain the desired regulation range, so the plant 

PPC must be able to estimate the available aggregate peak 

power that all the plant’s inverters can produce at any point 

in time. A similar requirement is true for wind power plants 

as well. Many utility-scale PV power plants in Puerto Rico 

are already capable of receiving curtailment signals from 

grid operators; each plant is different, but it is expected that 

the transition to AGC operation mode will be relatively 

simple with modifications made only to the PPC and 

interface software. 

Figure 7. Typical 2-s ACE

NREL recommended including AGC functionality in the 

modified MTRs for both wind and solar PV generation. New 

renewable plants should be able to have two-way 

communications with compatible protocols and hardware as 

well as proper scaling for set-point signals. The plants should 

be able to maintain their predetermined headroom and follow 

the AGC signal from RPEPA with a high level of accuracy. 

The plants should always be able to accurately determine 

their available reserves and communicate that information to 

PREPA’s SCADA. 

D. Ramp Limiting

PREPA’s 10% of nameplate capacity per minute ramprate limitation for renewable plants has been a topic of 

industry-wide discussion for several years now. The purpose 

of PREPA’s 10% limitation was to protect the system from 

significant changes in power from wind and PV power 

plants. Because of the added costs imposed by complying

with this limit, it makes sense to put effort into reassessing 

this rule criticality based on improved analysis methods. 

Large energy storage systems or other ramp mitigation 

equipment (even diesel generators) have been used by 

several plant developers in Puerto Rico to comply with the

10% limitations.

The combined distribution of all wind and solar PV 

ramps from all plants in PREPA is shown in Figure 8 for a

typical summer month. As shown, the aggregate wind and 

solar ramp distribution as a percentage of combined capacity 

is much smaller than for individual plants. This fact provides 

enough reason to reevaluate the blanket 10% capacity/min 

ramp-limiting requirement for all renewable plants in Puerto 

Rico imposed by the existing MTRs. It is obvious that 

geographical smoothing of ramps can reduce the aggregate 

renewable ramps across the whole system, thusrequiring less 

per-unit energy storage capacity for the same benefit. 

Figure 8. Aggregate wind and solar 1-min ramps

Figure 9. Comparison of total PV and PV+BESS ramps for a 

typical summer month

A comparison of total PV-only and PV+battery energy 

storage system (BESS) ramp rate distributions are shown in 

Figure 9 for the same month. As shown, the BESS provides 

only marginal improvements in the tails of the distributions 

(orange trace vs. blue trace in Figure 9). A similar analysis 

conducted by NREL using other historic data from Puerto 

Rico demonstrating that using a BESS coupled with 

individual PV plants for ramp-limiting purposes provides no 

or marginal benefits to the system in terms of PV ramp 

limiting. Even if PV plants are equipped with energy storage, 

the storage can be controlled to provide the most benefits on 

an aggregate system level rather than responding to resource 

variability within only the plant footprint.

E. Acitve Power Reserves by PV plants 

Establishing a headroom for up-regulation is not a 

problem for the conventional generation fleet, but the 

varying nature of solar and wind generation makes it 

challenging to set and maintain adequate headroom for these 

varying resources. To provide active power reserves (or a 

headroom margin) for up-regulation that can be 

automatically dispatched as needed, a PV plant needs to 

operate below its maximum power point (MPP); however, 
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evaluating that MPP in curtailed mode is not a trivial task, 

especially for large PV power plants during various types of 

variable conditions caused by clouds. One example of such 

uncertainty is shown in Figure 10 during operation when the 

PV plant was responding to an AGC signal sent from system 

operator. The AGC system assumed that there was still some 

available headroom for up-regulation because its evaluation 

was based on the available plant power value that was 

communicated by the PPC; however, the calculated available 

power is overly optimistic, and inverters are not able to 

produce as much power because they are already operating 

at their peak power point. 

Figure 10. Example of inaccurate maximum potential power

estimation (NREL test conducted in Puerto Rico)

A different method for estimating the maximum power 

was used during a demonstration testing a 300-MW PV 

power plant in California [3]. In this case, a single 4-MVA 

inverter was taken from the AGC scheme and set to operate 

at the power level determined by its maximum power point 

tracking (MPPT) algorithm. The measured AC power of this 

inverter was used as an indicator of available power for the 

other 79 inverters (80 inverters total), so the plant was able 

to operate with a fixed 30 MW of headroom. In recent years,

NREL developed a more advanced method based on the use 

of multiple reference inverters to achieve high levels of realtime maximum peak power estimation under conditions of

extreme variability [16]. 

Calculations performed for different variability cases

(moderate, intense, and extreme) demonstrated continuous 

improvements in the accuracy of the estimated maximum PV 

plant power with increasing numbers of reference inverters 

(N=1 .. 48). This can be observed from both 1-s time-series 

graphs for the extreme variability case (Figure 11). 

Figure 11. Improving accuracy of potential power estimation for 

48-MW PV plant under conditions of extreme variability 

Based on these considerations, NREL recommend that

PREPA include a requirement for new solar PV and wind 

power plants to have the capability for accurate real-time 

active power reserve estimation. Such capability is important 

for the provision of plant controls for both AGC and 

frequency response. Different vendors can use different 

methods for such estimation. It should be demonstrated 

during the plant commissioning stage that the reserve 

estimation error stays within tolerance bands under

conditions of extreme various resource variability. We also 

recommend that RPEPA conduct a study determining the 

minimum tolerance bands for reserve estimation by variable 

generation. 

F. Reactive Power and Voltage Control

Reactive power capabilities defined in current MTRs 

require a wide range for MVAR support. NREL has 

conducted testing and demonstrated that many modern PV 

and BESS inverters and some wind turbine topologies can 

meet and exceed PREPA’s reactive power requirements 

[17], [18]. For example, a per-unit comparison of PREPA’s 

requirements with reactive power capability of BESS 

measured by NREL is shown in Figure 12.

Figure 12. Comparison of BESS reactive power capability with 

existing PREPA MTR

PREPA’s current reactive power capability requirement 

listed in the existing MTRs seem to be adequate; however, 

NREL’s advice is to reevaluate it based on two scenarios: (1) 

all renewable plants are coupled with energy storage to meet 

the existing PREPA MTRs, and (2) there are centralized 

energy storage plants providing system-level services for 

both active and reactive power controls. A comparison 

between two scenarios might indicate that less reactive 

power capability from individual renewable plants might be 

needed for scenario (2). 

VI. RECOMMENDATIONS FOR ESTABLISHING NEW MTR

FOR ENERGY STORAGE SYSTEMS

A. Active Power Controls by BESS

The current PREPA MTRs are applicable for solar PV and 

wind power plants only, and they do not include standalone energy storage plants that can be located elsewhere in 

PREPA’s power system and provide centralized active and 

reactive power services to PREPA’s grid. Such services can 

include:

• Provision of dispatchability for variable generation 

in Puerto Rico

• Aggregate ramp limiting, variability smoothing,

and cloud-impact mitigation on system levels
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• Provision of spinning reserves

• AGC functionality

• Renewables forecast error correction services

• PFR with programmable droop

• FFR

• Inertial response—programmable synthetic inertia 

for a wide range of H constants emulated by BESS

• Reactive power/voltage/power factor control

• Advanced controls: ability of the plant to modulate 

its output for the provision of power system 

oscillation damping services 

• Stacked services (ability to provide several services 

at the same time).

FFR is an evolving method to use the BESS to 

compensate for sudden generation or load losses. This can 

become a very efficient frequency response tool for system 

operators but requires precise knowledge of loss magnitude, 

so the BESS can be commanded to change its power output 

accordingly. This method is dependent on the ability of the 

control system to rapidly determine the magnitude of the loss 

and communicate the set point to BESS control. The speed 

of response (or how fast the BESS deploys all available 

reserves) will depend on power system stability impacts: the 

BESS can deploy all available reserves very fast, which can 

cause unwanted oscillations in the system. In some cases, 

FFR activation by the BESS can be based on frequency 

thresholds such as underfrequency load-shedding schemes or

based on the ROCOF. This will require determination of 

precise FFR magnitudes based on system frequency or 

frequency ROCOF by conducting system-level modeling 

studies. NREL measured approximately 20–30 ms consistent 

response times by a commercial 1-MW/1-MWh Lithium-ion 

(Li-ion) BESS with an inverter demonstrating that battery 

storage can be an efficient provider of FFR service. 

NREL explored the question of what frequency 

response services by a BESS are most impactful in terms of 

improving power system performance during and after large 

contingencies. For this purpose, we used a power system 

model for a system such as PREPA consisting of 

synchronous generators with steam, gas, and hydro 

governors; static loads; inertia-less wind and solar 

generation; and a BESS. In this hypothetical case, there was

a 20% share of combined wind and PV generation, and the

combined rated power of the BESS is 3.5% of the total load. 

We simulated a large contingency by tripping off a generator 

that supplies 3% of the load. The combined inertia constant 

for all conventional generators H=5 s. In this modeling 

exercise system, both wind and solar generation were 

providing only bulk power with no reliability service. The 

BESS operated at zero power, so it had ability to operate at 

full power in both charge or discharge modes. At t=50 s, a

generator tripped, causing the system frequency to decline,

as shown in Figure 13. The base case (black trace) is when 

inertia and droop response by only conventional generators 

are available, causing a frequency nadir at about 59.6 Hz.

The results of the simulations for this hypothetical case are 

explained in Figure 13a and b.

The following services by BESS are activated to demonstrate 

the impacts on system frequency:

• Case 1: BESS providing inertial response (200-ms 

delay)

• Case 2: BESS providing droop response (200-ms delay)

• Case 3: BESS providing inertial response and droop 

(200-ms delay)

• Case 4: BESS providing FFR (2-s delay)

• Case 5: BESS providing inertia (200-ms delay) and FFR 

(2-s delay).

Figure 13. System frequency (a) and BESS response (b)

B. Reactive Power Controls by BESS

The P-Q capability of NREL’s 1-MW/1-MWh BESS 

consisting of LG Li-ion batteries and SMA 2.2-MVA, 400-

VAC inverter/charger with 1.1-MVA 13.2-kV/400-V 

transformer was verified using an experimental grid 

simulator setup. The inverter was commanded by various 

combinations of active and reactive power set points to cover 

the whole range of P-Q operation, as shown in Figure 14.

Figure 14. Results of BESS P-Q characterization test

a.

b.
8

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

The reactive power capability of a colocated hybrid 

renewable power plant is larger than the reactive power 

capability of individual components of the plant. One 

measured example of such expanded reactive power 

capability of a hybrid plant consisting of a 1.5-MW doublyfed induction generator WTG, 500-kW PV power plant, and 

1-MW BESS is shown in Figure 15. 

Figure 15. P-Q characteristics of hybrid power plant

C. Grid-Forming Controls by BESS

Grid-forming- and black-start-capable BESS can 

effectively replace the on-site diesel generators that have 

traditionally provided this service. Black-start capability will 

increase the value proposition of battery resources in Puerto 

Rico while avoiding some of the costs associated with 

retrofitting existing generators for black-start service. It will 

also help increase the level of power supply security, 

resilience, and fact recovery of the PREPA system during 

and after natural disasters. We recommend that PREPA 

include black-start capability by BESS in studies related to

the IRP process to better understand the imitations of battery 

chemistries and impacts on inverter power capabilities for 

black-start service.

The grid-forming capability of 1-MW BESS inverters 

tested by NREL are demonstrated in Figure 16. In this case 

it was demonstrated that the inverter operating as a voltage 

source in isochronous mode (constant 60-Hz operation) can 

provide fast active and reactive power control based on both

external set-point and droop operation. Figure 16 shows that 

inverter active power is ramped up and down in a controlled 

way while maintaining stable voltage amplitude frequency 

with acceptable power quality. 

D. Recommendations on New NTRs for Energy Storage 

Systems

NREL recommend that PREPA to develop a new dedicated 

MTR document for utility-scale energy storage systems. 

Such a new MTR should cover:

• All aspects related to active and reactive power grid 

services by energy storage systems 

• Black-start and grid-forming capability

• Transient FRT capabilities of storage inverters

• Power quality requirements

• Protection issues

• Provision of validated energy storage plant models

• All new grid-scale BESS in Puerto Rico need to operate 

under direct control by PREPA for participation in AGC 

with enabled local frequency-responsive controls.

• In case of Power Purchase Agreements (PPA) 

renegotiations with the existing PV plants equipped 

with energy storage take place in the future, this could 

be a good chance to upgrade the controls and 

communications and use the existing energy storage 

assets to provide system-level benefits to PREPA.

Figure 16. Active power control of 1-MW BESS inverter operating 

in grid-forming mode

A list of required services by BESS and related parameters 

that need to be specified in MTR should include:

• Inertial response capability with programmable inertia

constant H

• Fast frequency response capability with response time 

and maximum possible power up- and down-ramp rates

• Frequency droop control capability with programmable 

droop setting and deadbands

• Ability to follow 2-s active power set-point commands 

from PREPA’s AGC system

• Voltage droop control capability with programmable 

droop setting and deadbands

• Steady-state and dynamic reactive power injection or 

absorption capability 

• Short-circuit current control capability (including 

control over positive-, negative-, and zero-sequence 

components) under balanced and unbalanced fault 

conditions

• Voltage and frequency FRT capability

• Grid-forming capability:

o The concept of a virtual synchronous machine 

(VSM) is emerging in the industry as a flexible 

option to allow operation under a wide range of 
9

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

system conditions, including seamless transition 

between grid-connected and stand-alone operation.

o Control of short-circuit current in grid-forming 

mode under various fault scenarios.

VII. CONCLUSIONS

The NREL team conducted activities to analyze and 

address some shortcomings or areas of improvement in 

PREPA’s MTRs because of their importance for PREPA’s

system security and impacts on future IRP scenarios. The 

review presented in this paper is largely based on NREL and 

industry experience in conducting large-scale demonstration 

projects featuring multi-megawatt variable generation plants 

with the provision of many types of reliability services to the 

grid.

ACKNOWLEDGMENT

The authors acknowledge the substantial support of this 

work provided by staff at the Puerto Rico Electric Power 

Authority (PREPA). The National Renewable Energy 

Laboratory worked closely with staff from PREPA 

throughout the technical review of PREPA’s existing 

minimum technical requirements to ensure an accurate 

understanding of Puerto Rico’s electric grid and the status of 

renewable energy integration. The authors also thank 

Michael Pesin, U.S. Department of Energy Deputy Assistant 

Secretary for Advanced Grid Research and Development,

and his team, who sponsored this work. This effort could not 

have been completed without their support and involvement.

Results and findings presented in this paper are of 

importance for any island power systems.

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