My most recent post on substations
has drawn a lot of interest. It points to a couple problems in the
CIP-002-5.1 Attachment 1 criteria for which there aren’t clear answers. I invited people to send me other examples of
problems with the criteria, and Stacy Bresler of EnergySec immediately brought
one up.
His is quite simple: The words “Transmission
Facilities” (both capitalized) are used several times in the criteria. Since they are capitalized, this means these
are defined terms – either together or separately. There is no NERC definition for “Transmission
Facility”, but there are definitions for both “Transmission” and
“Facility”. However, Stacy points out
that combining the two definitions really doesn’t produce much enlightenment
about what really is a transmission facility.
I think the problem is mainly with the
“Transmission” definition:
An
interconnected group of lines and associated equipment for the movement or
transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers or is delivered to other electric
systems.
I believe Stacy’s concern is that many
substations combine elements that would normally be called “transmission” and
“distribution”. Where exactly do you
draw the line between them? This is no
idle concern, since an entity that doesn’t properly draw that line will end up
either spending much more money and time than they need to protecting systems
associated with purely distribution elements (lines, transformers, breakers,
etc), or else they’ll end up not properly protecting their transmission
elements – which can result in big fines.
Stacy does point out there is a workable
definition of “Transmission Facility” that does provide the specificity that’s
required. That’s the good news. The bad news is that this definition only
applies to entities in the province of Alberta, since it is found in the
glossary of the Alberta Electric System Operator (AESO) – which can be thought
of as a combination of NERC and PJM for that province.
Stacy provided a link
to the glossary, but here is the definition, in all its glorious specificity:
an
arrangement of conductors and transformation equipment that transmits
electricity from the high voltage terminal of the generation transformer to the
low voltage terminal of the step down transformer operating phase to phase at a
nominal high voltage level of more than 25 000 volts to a nominal low voltage
level of 25000 volts or less, and includes
(i)
transmission lines energized in excess of 25000 volts,
(ii)
insulating and supporting structures,
(iii)
substations, transformers and switchgear,
(iv)
operational, telecommunication and control devices,
(v) all
property of any kind used for the purpose of, or in connection with, the
operation
of the transmission facility, including all equipment in a substation
used to
transmit electric energy from (A) the low voltage terminal, to (B) electric distribution
system lines that exit the substation and are energized at 25 000 volts or
less, and
(vi)
connections with electric systems in jurisdictions bordering Alberta, but does
not include a generating unit or an electric distribution system.
My guess is this definition will get entities
a lot closer to what they need than the anemic NERC definition of Transmission
does.[i] Does that mean everybody should start using
Alberta’s definition in order to “slice and dice” the elements in their
substations between Transmission and Distribution? Well, I think this at least gives you a
template for working out your own definition (or maybe NATF or some other
organization can write one).
As one of my next posts will discuss, when
NERC doesn’t define a term or only vaguely defines it (and when no guidance is
put out to remedy this problem, which of course is the rule with CIP v5, not
the exception), I think the door is open for the entity to find something that works
and use that to guide their efforts.
Just be sure to document it, and inform your Regional Entity you’re
doing this…unless they have some better definition for you to use.
Of course, the best solution to this problem
is for NERC to provide guidance on this question, as well as many others. My next post will discuss a new initiative
NERC is undertaking to try to provide some guidance, and the challenges
involved with that effort. But don’t
start thinking miracles are on the way.
The views and opinions expressed here are my
own and don’t necessarily represent the views or opinions of Honeywell.
[i]
In the Guidance and Technical Basis section of CIP-002-5.1 (page 23), the SDT
did mention that entities should separate Transmission (called “BES
Operations”) from Distribution Facilities in a substation:
However,
in a substation that includes equipment that supports BES operations along with
equipment that only supports Distribution operations, the Responsible Entity
may be better served to consider only the group of Facilities that supports BES
operation.
This statement seems to assume one of two things:
1. The NERC definition of Transmission is
sufficiently clear that everyone will be able to distinguish these Facilities
with no problem; or
2. There isn’t any clear line between Transmission
and Distribution Facilities, meaning that whatever the entity thinks is appropriate
will be fine with the auditors. This is
implied in the sentence that begins the paragraph from which the above sentence
is taken: “When the drafting team uses the term ‘Facilities’, there is some
latitude to Responsible Entities to determine included Facilities.” Of course, just because the SDT said there
is “some latitude” doesn’t mean you’ll be given any latitude at all when audit
time comes.
This is simply another example of the bright-line
criteria requiring a lot of interpretation.
And I don’t see anybody – other than the regions on an individual basis,
and even then it’s quite spotty – to do this.
http://blogs.scientificamerican.com/plugged-in/wellinghoff-extend-electricity-market-visibility-to-the-distribution-grid/?nocache=1#postcomment
ReplyDelete