Generation Assessment and Loss Justification

The generation was estimated considering 315Wp modules of a reputed make and 1MW solar inverter of a reputed make as initial design inputs for conducting the simulations. The project uses a seasonal tilt system for with 7.5m pitch. The DC to AC overloading that has been decided as a design parameter is 25%.

The typical loss breakdown is as shown below with relevant justifications

Table 1: Justification of PVSyst Losses

S.No. Parameter Measure Justification

1. PV Syst Version 6.41 Latest version of PVSyst simulation tool has been used

2. Tilt Angle/Tracking Angle 5 o and 30 o For seasonal tilt, the aforementioned tilt angles

for summer and winter have been assumed.

3. Pitch(m) 7.5

Considering the overloading of 25%, and

corresponding land usage and generation optimization, the pitch values given here came

out to be optimal

4. Shading

-0.2% (5 o)

Near shading is caused by inter row distance and due to tall objects like control rooms and

lightening arrestors. For shading from tall objects, sufficient spaces are left by conducting a

shadow estimation study so as to keep the PV array shadow free during generation hours. The

near shading loss due to inter row spacing is

however determined by PVSyst as per the design pitch considered. In the case of seasonal

tilt, the shading losses are low for summer tilt and is higher for winter tilt. However, the

average shading loss will fall somewhere in between the two values.

-3.7% (30 o)

5. Incidence Angle Modifier

-2.2% (5 o) IAM loss accounts for losses in radiation

penetrating the front glass of the PV modules due to angles of incidence other than

perpendicular. The loss figures is a module dependent parameter and is calculated by the

PVSyst as per the module chosen.

-3.3% (30 o)

6. Soiling Loss -1.5%

This is the loss due to dust and bird droppings

on the PV modules depending on the environmental conditions, rainfall frequency

and on the plant’s O&M module cleaning strategy.

To assure the maintenance of soiling losses below 1.5%, a novel soiling estimation setup will

be setup at plant during O&M consisting of two

PV strings. One of the PV strings will be cleaned on a daily basis, while the other one will not be

cleaned. Once, the difference between performance of the two strings will start

touching 1.25%, a module cleaning cycle of the entire plant will be initiated, thus ensuring

soiling loss in line with the design assumption.

7. Module Temperature Loss -9.5% (Seasonal)

The characteristics of a PV module are

determined at standard temperature conditions of 25˚C. Considering the temperature coefficient

of the 315Wp modules selected, the module performance decreases by -0.40% for every oC

rise in cell temperature.

Module temperature loss is computed by the PVSyst by considering the temperature profile

of the location as per the meteo database. Since, the site is located in Rajasthan, a desert region

with high temperatures, and the high temperature losses calculated are representative

of the high temperature profile.

8. Module Quality Loss +0.4%

PV modules generally deviate from the

manufacturer’s technical specifications. The 315W modules considered here are supplied

with a positive Power tolerance of 0 to 3%. The

developer has thus considered a quality gain of 0.4%, although on a conservative side so as to

account for other contingencies in generation estimation.

9.

First Year Module

Degradation (under Light Induced Degradation(LID))

-1.5%

The performance of PV modules degrades over

the time. The degradation is most significant

during few hours of first exposure of PV modules to light. This phenomenon is known as

Light Induced Degradation (LID). Factors affecting the degree of degradation include the

quality of materials used in manufacture, the manufacturing process and the quality of

assembly and packaging of cells into the

modules. The first year degradation considering LID and

annual degradation is guaranteed to be less than 2.5% in the datasheet. However, as per the

general industry experience, the first year degradation for Tier-1 modules has typically

been observed between 0.8% to 1.5%. Hence, the

first year module performance degradation has been considered as 1.5% here.

10. Module Array Mismatch Loss

-0.8%

Mismatch losses represent the mismatch in

current/voltage of modules in a string due to statistical variations. Typically, the mismatch

losses are considered as 1%. However, the loss

can be reduced by sorting the modules as per current before factory dispatch. The modules

supplied at site with a 3-bin current sorting will effectively reduce the mismatch losses. Hence,

we have considered the module mismatch losses as 0.8%.

11. DC Ohmic Wiring Loss -1.5% (STC)

Electrical resistance in the wires between the power available at the modules and at the

terminals of the array gives rise to ohmic losses (I²R).

For well-designed plants, DC cabling losses at STC vary from 1.2% to 1.5% at STC. We have

considered 1.5% as the DC Ohmic losses at STC.

The losses are at full load, and the PVsyst computed the overall losses considering the

solar plant operates at partial loads most of the times. The final loss then computed by PVSyst

corresponding to 1.5% loss at STC considering the partial load profile of plant is 1.1%

12. Inverter Loss during

Operation (Efficiency) -1.7%

Inverters convert power from DC into AC at a certain efficiency. This results in a loss of power

during conversion from AC to DC. The efficiency curves are inverter dependent. In our

case, the inverters considered are 1000kW of a

reputed make. The efficiency loss has been calculated by the PVSyst as per the

manufacturer provided efficiency curves of the inverter and stands at around 1.7%.

13. Auxiliary Losses -0.6%

Various components of plants like inverters,

PLC, module cleaning system, plant lighting, security systems etc and amenities like Air

conditioning, plumbing and others consume electricity for their operation. This is known as

auxiliary loss. The auxiliary losses vary from 0.5% to 1% depending upon the size, design and

structure of the plant. Typically, small plants

require a higher percentage of auxiliary consumption than bigger plants on relative

terms. Various measures such as night disconnect, self-powered trackers, LED lighting,

have been considered in the design for reducing auxiliary consumption. The auxiliary losses

have thus been reasonably considered at 0.6%

with sufficient margin.

14. AC Ohmic Losses -0.5% (Full Load)

This includes ohmic losses in the cable from

inverter leading to the substation, and depends

on the sizing of cables during the design. During the design of the plants, the AC cable sizing has

been done in such a way that the losses do not exceed 0.5% in the AC side. Full load AC ohmic

losses of 0.5% have been considered, corresponding to which PVsyst computes the

overall losses considering the solar plant operates at partial loads most of the times. The

final loss then computed by PVSyst

corresponding to 0.5% loss at STC considering the partial load profile of plant is 0.3%.

15. System Unavailability -0.5%

Downtime depends on the diagnostic response

time and stock of spare equipment. Further, loss

in generation due to unavailability of plant and grid are also accounted for in downtime losses.

Typically, the unavailability is higher for smaller plants, as compared to larger plants due to

relative impact of failure of a single component on the entire plant availability. The O&M

scheme thought out also considers stocking of

inverter transformer, breaker, inverter IGBT stacks, and modules, cables of all sizes,

consumables and on site deployment of service persons of critical components like

transformers, inverters on site along with regular manufacturer training of O&M

personnel. Large solar plants in solar parks are

now connected at 132kV to the grid which is ultimately connected at 400kV to green corridor

grid network, which will be extremely stable with very less downtime. Considering the

above, the system unavailability has been considered as 0.5%

16. External Transformer Loss -1.6%

Large losses may rise in the transformer but are

generally less than 1% for each transformation level. Given the fact that the plant will be

evacuating at 132kV, two levels of losses have been considered; 1.0% for the intermediate

transformation at 33/11kV, and 0.6% (following

the GTP of the transformer to be used on-site) for the second level of transformation at 132kV

in line with standard design practices.