Increased weight makes reconductoring much more difficult as the structures are designed to carry specific weight. Increased size can also impact structure loading from ice or wind. So, generally, reconductoring does not materially increase weight.
The primary difference between the traditional conductors and advanced conductors is temperature tolerance. Most transmission lines are aluminum conductors with a steel core for strength (ASCR). As current increases, so does temperature, causing lines to sag (or the steel anneal if too hot).
Advanced conductors use a different composition to operate at higher temperatures, or otherwise carry more current (one example: aluminum conductor, composite reinforced, or ACCR) so as to have similar weight (and profile) to the original, traditional conductor.
Anywhere that icing is possible during the winter, the static weight of the conductors is not generally the dominant design constraint; it is the diameter of the cable and the resulting additional load when icing occurs. Weight really only increases sag, which constrains attachment height, but wind gusts with increased wind resistance increase horizontal load. In areas that don't get ice, diameter drives wind loading, again making wind gusts the dominant failure mode for pole lines. This comes about as most poles and/or other support structures for overhead conductors have far greater strength vertically than horizontally.
I've spent far too much time over the last couple of years learning pole line design using QuickPole. The other factor that keeps cropping up in my designs are grading and/or positioning issues. Putting a pole even 50cm out of line with other poles can result in it failing loading due to the added horizontal load on the pole. On a recent design I had to add downguys and anchors to 2 poles because they were out of line, a mistake during installation that nobody paid attention to. The same thing happens when a pole that is too tall is installed in an existing pole line. The wires to adjacent poles add horizontal force to the top of the pole. On one design I had a pole failing because of that, but it was fine if all the conductors were lowered 5 feet.
All I wanted to do was put fibre optic cables on poles to serve my home...
You may be referring to either 1) the real-time line ratings (directionally required by FERC order 881, or 2) technology like the "SmartValve" from Smart Wires which dynamically adjusts impedance to keep conductors within their operating envelope.
Among risks that are managed is ground faults caused by sage (as the line heats, it expands, getting closer to the ground), or 2) annealing which is a permanent expansion of the conductor due to operating too hot for too long. The advanced conductors use composite cores allowing the conductor to carry more current at a higher temperature with reduced risk for annealing.
As the new conductors will have lower impedance, some breakers may need to be replaced to interrupt higher fault current. Otherwise, it's likely the only substation equipment needing to upgrade would be series compensation stations which may have lower normal and emergency ratings than the upgraded conductors.
More likely is that lower impedance on the reconductored circuit will cause increased flows on other, non-upgraded circuits, either requiring those to be reconductored, or installing phase-shifting tranformers or reactors to limit current.
Have you seen a lot of phase-shifting transformers in the U.S.? In my experience they've mostly been in Europe with a few specialized applications in the States.
I would think a utility would want to reconductor the other circuits otherwise they're leaving benefits on the table right?
I only know the western US. And my experience is consistant with your own -- specialized applications.
They would love to reconductor the other circuits. In the US, the utilities make a guaranteed rate of return on investments in the transmission system. So, anything they regulators will let them do, they'll do -- not necessarily because it has technical benefits, but because it has economic benefits.
This is one reason why reconductoring isn't that popular with utilities -- it allows the utility to get more capacity with less spend, so less profit.
Fair enough. I had a conversation with one utility that was fine with transformers popping (even if preventable) because a popped transformer becomes a capitalizable expense.
The algae, forest, and other capture projects do not appear to sequester, on a geologic time scale, the atmospheric carbon. Even the sequestering of carbon through enhanced oil recovery is of uncertain time scale.
I do not believe that this is accurate. California Investor Owned Utilities (IOUs) have had their profit decoupled from revenue since 1981. [0]
The Federal Energy Regulatory Commission (FERC) allows for an equity rate of return on assets of approx 10% (9.3). [1]
As a result, California IOUs don't have an incentive to sell more power, but do have an economic incentive to build more assets. Asset construction is driven by growing peak demand. Or under-investment in O&M.
I believe there is a distinction between profits for "transmission" specifically and for electric utilities more broadly. The FERC ruling that you reference is for PG&E's transmission assets, i.e. high voltage lines and transformers and such. I assume that their retail electric business is regulated by CPUC and has a different profit/revenue/whatever arrangement.
You did not understand what I wrote. I didn't say the eight foot slice was severed, I said control of the right to build on it was severed. That right is an abstract thing, but it has value, and the value is now not owned by anyone.
The electrical grid has many different resources that can be constrained. For example, the entire grid may not have adequate supply to meet demand, a transmission line may not have adequate capacity to deliver electricity from generation to load, or a substation may not have enough transformation capacity to delivery electricity from the transmission grid to the distribution grid.
As a society (natural monopoly), we pay to meet peak demand. In fact, most of the cost of electricity (in the US, in most markets...) is not the marginal cost of generation, but the amortization of fixed costs.
My reducing the peak demand, we reduce the need to build new infrastructure that is unnecessary for all but 8755 hours a year.
PG&E is an investor-owned regulated monopoly. Other utilities in California are publicly owned (either government, or non-profit. For example, LADWP, SMUD, Palo Alto, Turlock and many, many more). Those publicly owned utilities have much lower rates.
PG&E has a "revenue requirement" which is the amount it needs to bring in to cover operating, energy procurement, construction, and profit. At the most simplistic level, rates ($/kWh) are set by dividing the revenue requirement by the anticipated quantity of electricity sold.
The amount of profit it is allowed to make it determined primarily by how much it has invested to safely and reliably deliver electricity. Some of that is regulated by the Federal Energy Regulatory Commission (FERC). Something like a 9% return on equity for investment.
This creates a misalignment of incentives: PG&E would rather spend CapEx than OpEx. This is the market failure (of the natural monopoly) that the regulator is supposed to address.
However, PG&E's lack of maintainence on a metal hook (over > 80 years) which eventually failed caused the Camp Fire. Instead of replacing all of the hooks (a relatively inexpensive OpEx), PG&E proposed, and the CPUC blessed, an incredibly expensive effort to underground transmission lines. [0] This is a windfall for PG&E's investors and organized labor in California. But a huge headwind to the economy of California, and California's efforts to electrify. As others have noted, PG&E's rates are now so expensive that driving an EV doesn't save materially (or at all) over gasoline (even with California's relatively high gasoline prices).
Here in Ontario we are similarly bent over the barrel by Hydro One. The key to operating a regulated monopoly is to inflate your expenses so that the regulator has no choice but to approve the increase the rate you charge. Hydro One accomplishes this by sending out 6 people to do a job that only requires 2 or 3. Works great -- our delivery rates have never been higher!
The electrical grid is designed to cover the highest load (typically the hottest hour of the year; A/C drives peak load).
Most of the grid is a fixed cost. The transmission lines, distribution lines and the power plants recover enormous investments whether they are used or not.
The marginal costs are surprisingly low. Marginal costs of fueled (fossil or nuclear) power plants are typically < $0.05/kWh.
Peak load is what drives capacity expansion -- both in wires (transmission and distribution) but also generation. Building all of this capacity to only run for < 1% of the year incurs tremendous cost.
By flattening the (demand) curve (through either generation or load reduction) there are tremendous savings for society.
However, electric utilities are natural monopolies, so investor owned utilities (contrasted with munis or coops) must substantiate investment to their regulators who in turn allow them to make a rate of return on their investments. So, these utilities only increase profit by increasing investment.
There are some other interesting use cases for smarter energy consuming devices, what they call Cold Load Pickup, where a section of the grid loses power during a blackout, and power comes back. that initial spike kills equipmenton the transmission side, if you are able to delay start some equipment, you spread the load and reduce strain on the grid.
It's a horrible naming choice and it shows the industry preconception that a power plant is a large, transmission-interconnected facility.
It also, IMHO holds on to an outdated concept that all generation must be centrally dispatched. There are plenty of concepts that allow distributed dispatch including voltage (which in turn can be controlled based on local conditions).
Finally (and perhaps most importantly), it implies that only devices that export generation are part of the solution. The supply and demand must be balanced in real-time. And the demand side of the equation is often much less expensive than the supply side.
But if the industry is the one naming it, why are they going against their own "preconceptions?"
I feel like GGP is the one with the preconception about the name "power plant," while the industry (as shown here) is starting to use it to be this broader term encompassing distributed generation and price-influenced demand, etc etc.
As an industry, the term "power plant" is something that generates power (electric energy). However, much of the DER opportunity is not generation, but load. Which is why the term "Virtual Power Plant" is a misnomer and predisposes people to only be thinking about the generation side of the supply/demand equation.
Right, but it's precisely that shift that the term is supposed to induce. From a fungible energy perspective, there really isn't that much difference between increasing the supply by an additional MW and decreasing the demand by an additional MW. Moreover, that additional MW that's now in the grid is the greenest possible energy, provided without producing a single atom of CO2.
When people thinking about generation they think about something different than reducing demand, but it's critical to start seeing that those can be the same thing, in certain circumstances.
But "PP"s, that is, normal power plants that aren't compromised of DERs, are not going to partake in this shift of the term from meaning "generation" to meaning "generation or load shedding". So you end up with "power plants" that everyone understands are suppliers of power and "virtual power plants" that are, confusingly, a mix of demand reduction and maybe some supply.
So I agree that the VPP terminology leaves a lot to be desired. I prefer the more generic "DER" terminology, because it is more descriptive; either a generator or a load is an "energy resource", and "distributed" is a good description of what is unique about these particular energy resources.
Virtual Power Plants, both in general (see first sentence on wikipedia: https://en.wikipedia.org/wiki/Virtual_power_plant), and specifically in the definition given in the comment you replied to, include "demand flexibility" so your comment is confusing.
because you're right, the people that own this stuff (and work on these companies) are used to thinking in terms of large transmission-interconnected facilities.
so my take this move has most to do with how to bill people, and how to collect payments and pay taxes on said payments and so on. I expect that the actual electrical engineering is treated as an implementation detail
The primary difference between the traditional conductors and advanced conductors is temperature tolerance. Most transmission lines are aluminum conductors with a steel core for strength (ASCR). As current increases, so does temperature, causing lines to sag (or the steel anneal if too hot).
Advanced conductors use a different composition to operate at higher temperatures, or otherwise carry more current (one example: aluminum conductor, composite reinforced, or ACCR) so as to have similar weight (and profile) to the original, traditional conductor.