Download Load Model Issues for RAS, LFWG, LOLEWG discussion

Draft revised 01/19/10
Load Model Issues for Loss-of-Load Calculations
Introduction
The NERC Planning Committee’s G&T Reliability Planning Models Task Force
(GTRPMTF) is to “develop a common composite generation and transmission reliability
modeling methodology for the purpose of assessing system resource adequacy, which
considers the ability of load to receive power supplied by aggregate resources.”1
Preliminary Recommendations
The task force has not finalized its recommendations on the details of the methodology.
However, these are some preliminary recommendations:
1. A probabilistic analysis that will cover all hours of the year; e.g., an 8,760-hour
model. The analysis should be able to include the extra 24 hours for leap year. The
calculation of probabilistic indices (such as loss of load hours - LOLH) across all
hours will:
a. Include the random outages of supply side resources,
b. Allow the modeling to reflect transmission limitations, thereby preventing the
inclusion of unavailable/undeliverable capacity as supplying demand.
c. Accommodate modeling of energy-limited/variable resources ;
d. Be able to address load shifts to near-peak hours as a result of demand
response energy payback.
2. Develop reliability models for each year of the next ten years covered by the LTRA
reporting period.
3. A common modeling methodology needs to be used within an Interconnection. The
reason is that calculation of probabilistic indices for a “system” will include the
explicit consideration of assistance from neighboring systems. Therefore, all systems
need a common modeling methodology within an Interconnection to achieve that
goal.2 [The biggest issue is the amount of capacity assistance to be assumed to be
available and deliverable from external sources.] It is envisioned that a Monte Carlo
model would be used. There are two ways generally used to include transmission
system characteristics in the Monte Carlo simulation. They differ in their
representation of the transmission system.
1
See the GTRMPF scope at
http://www.nerc.com/docs/pc/gtrpmtf/GT%20Reliability_Planning_Models_Task_Force_Scope_06-1009.pdf.
2
Practically speaking, we will not likely model the entire Interconnection in one model, but large parts will
be modeled so that the impacts of capacity assistance from neighbors can be properly accounted for.
Capacity assistance from neighbors depends not only on their generation availability, but also on their
loads. Neighbors are assumed to make non-firm generation available to a system that would otherwise
lose load if the assistance was not provided. This assumption is a fundamental one for all resource
planners. A large amount of load diversity between neighbors (e.g., one is summer peaking while the other
is winter peaking) can significantly reduce both of their capacity needs if this characteristic is incorporated
into capacity planning. Therefore, load diversity should be properly represented in reliability assessments.
1
Draft revised 01/19/10
a. A transportation model represents zones of generation and load, which for
modeling purposes, have no internal transmission constraints. All generation and
load in a zone can be modeled as connected to one electrical bus. Zones are
connected by a single line representing the equivalent transfer limit, with
constraints modeled with various levels of detail. Power flow on these
representative lines does not follow electrical laws of physics but instead are
modeled as “transportation” e.g., roads, water, etc.
b. A dc power flow model represents the transmission network at the bus level –
loads are defined at individual busses and generators are connected to individual
buses. Power flows across the transmission system according to the electrical
laws of physics. The thermal impact of transmission outages must be considered
explicitly in the reliability calculations because the flows over any element
cannot exceed N-1 even though an all-lines-in-service (N-0) calculation would
remain within satisfactory thermal limits during pre-contingency conditions.
Constraints on the transmission network may also be enforced to limit the
electrical impact of voltage and stability concerns resulting from contingencies.
However, because the power flow uses a “dc” model and not “ac” model, actual
power flow restrictions due to limited var capacity and therefore voltage based
constraints are not modeled.
Load Model Issues
Two load modeling issues have been formulated by the task force.
1. Load models need to be developed in a coordinated manner within each
Interconnection so that the results of the individual system load models “make
sense” when they are aggregated at three different levels:
a. The Interconnection level. The aggregated subregional load shapes
should be sensible at the Interconnection level.
b. The subregion level. For example, WECC has four U.S. subregions, each
of which includes many systems. Each subregion’s load shape should
maintain a sensible chronological relationship with those of its
neighboring subregions.
c. The transmission constrained level. For transportation models, there
needs to be a process to allocate the hourly loads at a system level to
transmission constrained areas that may encompass one, two or more
reporting entities as well as portions of a reporting entity. This could be
alleviated by a granular, bus level, forecast that could then be “rolled-up”
into a transmission constrained area. However, the bus-level forecasts
would need to sensible when summed at the subregion and
Interconnection level.
It has been observed that the system loads are driven by common weather
patterns that impact multiple electric power systems across large geographic
regions simultaneously. Without coordination of the load models, the peak days
selected by adjacent systems may not reflect the historic diversity/correlation
experienced between the systems when all systems are numerically combined.
2
Draft revised 01/19/10
Hourly aggregated load models need to be able to assign forecasted hourly loads
to zones (for transportation models) or to busses (for dc power flow models).
2. The second issue is the representation of load forecast uncertainty. While the
determination of what uncertainties to model has not been confirmed by the
GTRPMTF, its present thinking is:
a. Weather uncertainty is considered over the entire calculation period, since
that is always present.
b. Economic uncertainty is considered for the five years only. After that, it
is not allowed to increase. The rationale is that generation adequacy
computations should consider economic uncertainty in the short-term
(five years) when most resource plans cannot be easily adjusted for
deficiencies due to generation or demand-side resources. After that time,
resource plans can be adjusted to account for divergent economic paths.
An approach to represent uncertainty in generation hourly adequacy models is to
adjust the 8760 hour load profile “up” and “down” to reflect uncertainty in load
levels.3 These adjustments, however, leave the order of relative values of
chronological hourly loads unchanged. Additionally, such a process assumes that
weather affects all geographic areas equally across the entire interconnection
simultaneously. We believe that much uncertainty in the final result can not be
captured by this approach because there is no variation (uncertainty) in the shape
of the demand model.4 A “family” of 8760 hourly load profiles, each reflecting
different weather scenarios at distinct probabilities, may be an answer. But this
family of 8760 load profiles would need the consistency among all neighboring
systems described in the previous section.5
The illustration below shows the impact in load shape variability on loss-of load
probability calculations. 6 The same weather and economic forecast error were
incorporated into each load shape but there was still a significant difference in
results. Each load shape was scaled to the same peak and energy so the difference
between the load shapes stems from the contributions to LOLH from the second
highest peak load, the third highest peak load, the fourth highest peak load and so
forth.
3
While this is a present constraint, if other methods were developed, those would likely be incorporated by
vendors.
4
For example, maintenance scheduled for generation that is based upon a single load profile will not
capture the reliability impacts of higher loads during those scheduled maintenance periods.
5
Software vendors differ in their ability to address load forecast uncertainty. However, any solutions that
developed should not be constrained by current software limitations – if a solution makes sense, vendors
can adapt their models to that solution.
6
This figure was provided courtesy of Kevin Carden of Astrape Consulting.
3
Draft revised 01/19/10
1.00
0.90
0.80
Loadshape 1
0.70
Loadshape 2
0.60
Loadshape 3
Days/Year
.1 = 1 day in 10 0.50
years
0.40
Loadshape 4
Loadshape 5
0.30
0.20
0.10
0.00
4%
6%
8%
10%
12%
14%
16%
18%
20%
Reserve Margin
Assistance Requested from the Load Forecasting Working Group (LFWG) and the Lossof Load Expectation Working Group (LOLEWG)
The GTRPMTF requests that the LFWG and the LOLEWG consider how the load
modeling issues described herein could be addressed in an Interconnection-wide
modeling approach.
1. Since the LFWG’s purpose (from its scope) is “to assess the degree of uncertainty
inherent in [the NERC aggregations of regional/subregional load forecasts], and
increase consistency of forecast reporting” (emphasis added) we believe they would
have the lead role in recommending approaches to address these issues, including
recommending methods for aggregating independently forecasted hourly load data.
This may require benchmarking to historical relationships. In the U.S., the reporting
of historical hourly load data has been required by FERC Form 714. See
http://www.ferc.gov/docs-filing/forms/form-714/overview.asp.
a. While the development of a family of load shapes may be desirable, the
GTRPMTF understands that that may require additional work. The LFWG’s
focus should first be on developing forecasted load shapes that can be
aggregated in each Interconnection and each subregion in the LTRA. If
forecasted load shapes are changing, that would also need to be addressed, but
again, that is a lower priority at this point.
2. We would look to the LOLEWG to draw upon its members’ experience – have they
recognized these issues, and, if so, how have they addressed them?
4