"The simple step of a courageous individual is not to take part in the lie." - Aleksandr I. Solzhenitsyn
Warning: Long Blog Post.
Decades ago, I worked as an operator at the Coso Geothermal Power Plant.
Below: Coso. A portion of the Navy 1 Wellfield, and Navy 1 Power Block - Units 1,2 and 3. (click on images to improve resolution and clarity)
Below are a few Google Earth images, showing the remote location of this place. Below is the western US. The red arrow indicates the location of the Coso Geothermal Project.
Below: Closer in. Southern California. Los Angeles is at the bottom, and Las Vegas is at the top right in this image.
Below: The Sierra Nevada mountains are on the left, and the Panamint Valley, very close to Death Valley, is at the right. Coso sits inside the western edge of the Mojave Desert.
The Coso Geothermal project wellfield and power blocks are spread out over several square miles of harsh wind-swept desert, at an average elevation of about 4200ft (~1300m), on property that is owned by the Navy, and administered by the Bureau of Land Management (BLM). There are three seasons there: Hot and windy, Cold and windy, and windy. The seasons overlap somewhat.
The site consists of nine steam turbine generating units that (as built) use a dual-flash steam system - meaning that the steam is flashed in high pressure separators from hot brine after it comes out of the ground, then the brine is pumped to low pressure separators for a second low pressure steam flash.
I made a generic post about geothermal power several years ago, and re-titled it recently to go along with the career autobiography theme. That post explained the basics of the process. This post will go into greater detail of the operating issues that arise when you don't have very much control over the incoming steam resource, and how those issues were resolved over the years that I was there. It will also discuss some interesting idiosyncrasies of these units that I've not seen elsewhere.
There were a number of things that made that job different, and in many ways more interesting, than the other places that I've worked. Keep in mind that I haven't been in touch in a professional sense with anyone from there for decades, so nothing here will be current or up to date - just noting a few things that made that particular power plant an interesting one to operate at the time.
The high desert is an odd place for a Navy base, isn't it? The Navy conducts training for aviators, and the civilian portion of the base is dedicated to missile development and testing. There were occasions when, for safety reasons, the Navy had a "range closure", and at that point we had to leave the plants running and go offsite while they tested a missile.
The missiles being tested would have no warheads on them - I'm pretty sure that the purpose was to test the navigation systems of cruise missiles, test how a missile would perform against countermeasures, and to see how well an air-to-air missile would respond to evasive maneuvers. The Navy didn't want anyone harmed in the event something went wrong with a missile test, so off site we would go for the duration of the test - which were sometimes lengthy.
The company had (in the late 1980's) set up a remote control station where we could remotely monitor and control the units via a dedicated phone line and low speed dial-up modems. It was pretty early in the days of such technology, and when you switched pages on the screen to monitor other equipment, it would often lock up the remote work station. It got better over time as modem speed improved.I should probably begin with the production wells - those wells that were drilled to provide steam for the turbines. The depths of the wells involved in production was between 1300ft (400m) to 11,000ft (3350m). Very few, if any, of these wells went straight down. They were directionally drilled so that the slotted liners would be inside where it was guessed the production zone was.
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Below: Diagram of a directionally drilled well. This is the only kind of well drilled these days.
It's important to bear in mind that these wells didn't just produce steam. Many of the wells produced significant amounts of very hot water (brine) - which made them much more powerful than the dry wells, because a large quantity of boiling hot water can create a lot of steam, once the pressure is reduced in a suitable steam separator. Because this power plant was a dual flash arrangement, water also increased Low Pressure steam production - whereas a drier well would not provide liquid for a secondary flash.
Below: Geothermal steam separators. The steam/water mixture from several wells enters on the left side. Hot brine swirls and some of it flashes to steam inside the vessel, allowing water to fall to the bottom, meanwhile the steam rises and exits the steam outlet pipes at the top of the vessel.
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Most of the wells - particularly the older ones - delivered dry steam, and very little water. They were steady producers, if not very powerful. Other wells might have a periodic "heartbeat" where they would cough up more or less water at regular intervals. No two wells behaved the same, and they all changed over time.
Newer wells were a lot more quirky and unpredictable. Wells that had recently been "worked over" also tended to be unstable. When a well was re-drilled,
mechanically cleaned of scale, or chemically de-scaled by pumping in a solution of
high molarity hydrochloric/hydrofluoric acid - they tended to flow erratically. New and freshly worked-over wells might might run in a stable pattern for hours, then taper off and die. They might also taper off, and then come surging back with a mighty flow that could knock the power plants offline.
How could an erratically flowing well knock three units offline at once? In addition to coughing up steam and water, the underground reservoir contained carbon dioxide gas. The underground gas had a lot to do with how the wells surged. If you think of the reservoir as a shaken up bottle of soda that you have released through several different straws, you have an idea why things might be so erratic. There is continuous percolation of gas, steam and water underground through porous rock, and inside the production wells.
Sometimes a production well would suddenly puke up a huge volume of non-condensible gas, which would trip the steam turbines on high condenser back-pressure. Sometimes they would puke up a huge volume of water, which would flood the high pressure separator, and trip the steam turbines on high separator level. When I was a new control room operator at the geothermal plant, I found this situation to be nerve-wracking.
Wells would get shut in sometimes. They were shut in during a workover, following a plant outage, or when they had died (stopped flowing) and they needed a little recovery time. To bring a well back online was more complex than just opening it up into the gathering system - the system of pipes and separators that bring the steam into the power block..
Before a well was ready to bring back in service, it had to be "unloaded". The gas in the underground reservoir has a tendency to rise to the surface inside the well. This gas has to be vented off (unloaded) or the gas will overwhelm the vacuum in the main condenser and trip the units offline on high back-pressure. Unloading was also important to getting watery wells flowing. As the gas cap was vented off, it allowed water to flow upwards into the well, getting the well to flow. Each well was different. Some might need to unload for a few minutes, while others might require hours.
Putting a production well into the silencer was always interesting. The gas would come screeching out the flow line into the silencer - no steam, just the odor of fire and brimstone. Sometimes you could see some density waves off the top of the silencer. Then it would go dead silent as the gas pressure died off. After 10-30 seconds, the steam/water would arrive and then it would absolutely roar with a chest-rattling rumble. The ground would start popping as the well expanded with the heat. Once the well's flow and temperature had stabilized, the vent valve could be brought shut, while also opening the valve going into the system - to keep the well flowing. Dead-heading a well could kill it again.
Sometimes unloading gas was not enough to get a well flowing. This was often true of watery wells - wells that produced mostly brine - particularly after they had been shut in for quite a while. The reason that watery wells would sometimes not flow during unloading is that a
static head of water would build up inside the well, and press downwards
with force equal to the pressure underground pressing upwards. Even
venting the gas cap off into the silencer was not enough to do more than
shift the static level of the water. In these cases it was necessary to contract a wellfield services company such as Halliburton or Schlumbarger to get it flowing again.
When unloading failed, the well could sometimes be kick-started by putting an "air cap" on it. High pressure air from diesel-driven compressors on trailers would be forced into the well, pushing all the cold, static water back down into the hot underground formation. After an hour or two, that liquid would have re-heated to hot brine, and the air pressure could be vented off and the well would come back to life. This process could be repeated several times if necessary
When the "air cap" technique failed, it would be necessary to have a well "lifted". This was pretty expensive process, and used only when the air cap technique failed. A tube would be insterted down to the bottom of the well, and then liquid nitrogen would be rapidly pumped down the tube. Once it was down-hole in the hot zone, this liquid nitrogen would quickly turn to gaseous nitrogen. The nitrogen gas, expanding a thousand-fold, would make its way to the surface, lifting the cold water inside the well up with it.
Below: A well flowing into a test cell. Unloading is a similar process.
Below: The far silencer has a well unloading into it. The near silencer looks to have a minor amount of leak-by coming from a well valve. You will notice that the water doesn't look quite right. There's a reason for that.
Produced geothermal water has a great deal of mineral content. It has been underground in a hot environment, leaching minerals from the rocks. When "produced" (brought up out of the ground), the static chemical balance is upset. Steam is flashed from the brine, concentrating the minerals above the saturation point, and the minerals come out of solution. You end up with scale in pipes, and weird colored pond water.
When I was employed at the geothermal power plant, the company had an ongoing development program to locate new geothermal resources and tap into them. New wells were constantly being drilled. If a well looked promising, it would be run to a specially equipped silencer called a test cell, monitored for a month or two for flow, temperature and pressure. If the well or wells were adequate, then the gathering system would be expanded to that well pad. This was all very expensive of course. Drilling wells isn't cheap - and you don't always hit resources after pouring millions into drilling. Neither is it cheap to install and insulate miles of pipeline, nor instrumenting a remote wellhead and adding remote shut off valves.
Below: What you get sometimes when you spend millions of dollars, and then drill into solid granite instead of a productive geothermal zone. This is all you have to show for it - An "observation well". If you are too cheap to fill it with cement and properly abandon it, operators take readings on a dead-end wellhead once per day.
Occasionally the company would drill a powerful new production well that theoretically should have been good for 5-10 megawatts. In practice, these powerful wells would raise the steam system pressure, and kill several weaker wells. The weaker wells could not flow against the new higher system pressure. So in reality, your killer new 10 megawatt well would give you maybe 2-3 megawatts, because it killed several older, weaker wells off :) Once the new well settled down after a few weeks or months of high production, its pressure and mass flow would fall off. At that point, you could then bring the older weak wells back into service.
The gathering system had several iterations over the years, as new swells were developed, and new sections of the geothermal wellfield were brought online. Power and pipelines had to be run for miles, to operate pumps and valves. As the reservoir pressures declined, stages were added to the turbines, and pipelines that once held High Pressure steam, were re-routed and used to transport low pressure steam.
All the pipelines have expansion loops in them. What look like haphazard zig-zag pipelines welded by freaks on methamphetamine (true), actually has a reason. The thermal expansion of the pipelines would tend to stretch them out and push them off their pipe stands.
I mentioned non-condensible gas earlier. This was a huge ongoing issue at the two unit BLM-East site. The gas fraction in the high pressure steam was so high that it was difficult to maintain vacuum under steady-state conditions, and both units would frequently be blown offline due to loss of main condenser vacuum by gas surges coming from a few of the more erratic and gassy wells.
The air removal systems on the main condensers of these two units were massive. On each unit, there were two complete dual-stage air ejectors trains. The primary air ejectors were really enormous. Each was fed by a three inch steam line, and the primary steam nozzles were maybe 6 inches across - I saw them apart a couple of times, and the primary nozzles looked like the rocket nozzle for a large hobby rocket.
The first stage ejector venturi sections were each about 10 feet long. These air ejectors used about 50,000 lbs/hr of steam - about 10% of what each unit used to make full power. A huge waste of steam.
The shells of the inter and after condensers were drained of condensate via loop seals that went deep underground. Theoretically, this arrangement would allow the condensate to drain back to the main condenser without the pressure differential also allowing the gas to also circulate back into the main condenser. In practice, loop seals would constantly blow out due to the massive quantities of gas overpressurizing the air removal system - and the inter and after condensers frequently blew their rupture disks.
The air ejectors would surge until the outside operator could isolate the loop seals, hoping to re-establish the the water seal. There were four loop seals - two intercondenser drains and two aftercondenser drains - and it was difficult to tell which one had lost its water seal. The air ejectors surged all the time - it was a rare day when they did not. There was just that much non-condensible gas to deal with - if memory serves correctly, each unit had 27-30k lb/hr of non-condensible gas to remove at all times. Condenser vacuum ran at 4-5 inches absolute, and the turbine trip was at 7 inches. The megawatt meters would swing up and down in synch with the noise of the air ejectors surging. Fascinatingly weird.
Below: A generic two-stage air ejector.
As built, all of the sites re-injected the non-condensible gas underground. It was the simplest and most inexpensive way to deal with the gas. The gas would be compressed by large, expensive and high-maintenance compressors - three per unit - and sent to several different wellheads. The gas was forced into those wells and carried underground by the weight of expended brine. The 200 degree F brine was pumped out of the Low Pressure separators by high pressure, high volume pumps.
The injection wells frequently backed up, and then stopped taking flow. There would be so much gas flow that the wells would build up pressure, and then they would stop taking brine or gas. At that point the non-condensible gas compressors on the units would trip on high back pressure, and the plant would vent raw gas. The gas contained hydrogen sulfide, so it was always necessary to file an emissions report with the air quality board. This would happen several times in a 12 hour shift. A full shift without venting was a rarity.
To unlock a gas-locked injection well required that someone go to the wellhead, isolate the gas, and vent the gas pressure off the injection well - not a quiet or safe operation. Once the wellhead pressure was low enough, brine would begin flowing into the well again. Once brine flow was re-established, the operator could begin slowly cutting in gas again, and the gas compressor could be re-started. Each well was different, and each operator was mostly guessing how much gas each well could take before it would lock up again. Meanwhile the units would be either venting (and being fined by air regulators), at reduced power, or both.
Later on, in an attempt to minimize injection well lock-ups, the gas was blended with the brine in a mixing tee. This made the brine behave like fizzy soda water. On sites where the brine had to travel a long way to the injection wells, the gas would come out of solution and often gas-lock the entire injection line, and trip the gas compressors on all of the units at once, as well as backing up the flow of brine, to where it would dump into ponds, threatening to overflow them.
There were other issues. At some of the generating sites, the re-injected water and gas disappeared forever, going to places unknown to mankind. That might sound good - at least from the standpoint of the gas - but loss of water leads to resource depletion. Eventually the reservoir will run out of hot water and steam. Geothermal power plants need most of that water returned to the reservoir to be re-heated.
A worse scenario than loss of all the water - as was the case at BLM-East - the injection wells
communicated underground with the production wells rapidly, and
so as the steam temperature and pressure rapidly declined, the gas fraction increased. BLM-East, during my tenure there, became the testing ground for
all sorts of schemes for dealing with massive quantities of non-condensible gas, and dwindling brine to flush it back underground.
Water was a huge issue too. The company rented agricultural diesel-fueled pumps to move water. These pumps were 500-800 gallon/minute units, with 6 inch diameter discharge lines. They used 20 foot sticks of aluminum pipes with victaulic couplings to "temporarily" move water from one place to another. I grew much too familiar with these.
These pumps moved water all over the wellfield. There was a constant scramble to move water out of ponds that were in imminent danger of overflowing to other ponds that were in slightly less danger of overflowing. I learned more than I ever wanted to know about getting one of these pumps to run - usually in awful weather. The water was a bit acidic due to carbonic acid (carbon dioxide dissolved in water), so the aluminum pipes were constantly corroding and springing leaks - requiring replacement.
Re-injection of the non-condensible gas eventually caused so many issues with water and emissions that the company finally had to spend money to engineer a way for gas to be vented to atmosphere. During most of this period, I was stuck at the worst site, BLM-East, or as we called it, the Island of Misfit Toys. It was not unusual to come to work and find both units offline due to loss of vacuum, and struggle (and fail) to keep them online throughout a 12 hour shift, then turn over with the next crew with the units both offline - all due to gas in the steam.
In order to be vented to atmosphere, this geothermal non-condensible gas had to be treated. It was mostly carbon dioxide, with minor fractions of nitrogen and hydrogen sulfide. If you have ever been near a volcano, sewage, or a hot spring, you know hydrogen sulfide. It smells nasty, but that's not its worst characteristic. It's exceedingly toxic. It's slightly less toxic than hydrogen cyanide, which has been used to execute prisoners.
And that was one of the other fun bits of this job once the company decided to start treating and releasing the gas - it morphed from a geothermal power plant into a chemical processing facility that had nine generators and a wellfield.
The first, inexpensive scheme for gas processing was a home-spun rig with in-house "engineering". This first process used a huge propane storage vessel, which was modified by dividing it into three sections internally, with gas spargers between each section.
With this triple-baffle internal arrangement, one section could be drained and refilled of the hydrogen sulfide scrubbing solution, while the other two sections continued to scrub hydrogen sulfide from the gas. I will give them a little credit - it scrubbed the gas and vented it. It was also so troublesome and poorly thought-out that it had to be abandoned.
The chemical process used a sodium nitrite solution to react with the hydrogen sulfide, and this occurred at a tank pressure of about 100 psig. The high operating pressure of this system meant that the gas compressors remained in use, and those machines were tedious from an operation and maintenance perspective.
This in-house project was done so cheaply that the outlet pressure control valve for the vessel was operated by a guy on overtime - whose only job was to turn the valve as requested. As alluded to earlier, gas flow from the wellfield wasn't consistent. Wells were constantly burping, taking a breather, or coming back to life with the ferocity of a dragon. I made a lot of overtime sitting in a lawn chair that summer, opening and closing that valve 1/4 turn at a time.
The scrubbed carbon dioxide gas was routed to the nearest cooling tower, with no muffler or diffusing device. It was pretty loud, and really hot - I won't lie that the overtime had some hardship involved. If you were operating the scrubber/propane tank, you would hourly monitor the hydrogen sulfide from each of the three cells using a Draeger tube, and measure the concentration of the sodium nitrite solution, and take pressure drop readings across each cell of the vessel. I'm sure most of those hourly readings were required by the air board.
Once the sodium nitrite in one cell was exhausted, the slurry product had to be blown out into a waste tank, and then that cell of the propane tank would be refilled with fresh solution. The slurry in the waste tank would eventually harden into a cement-like sulfur smelling block in the bottom. Once the waste tank lost enough capacity due to build-up in the bottom, operators would have to enter the tank with forced air breathing apparatus and jack hammers to remove the material. This was also true to a lesser extent of the propane tank.
The process was expensive, because it consumed several tanker trucks' worth of sodium nitrite weekly, and the slurry had to be removed and disposed of. In addition, there were unanticipated corrosion issues that cropped up.
It turned out that the product of the reacted hydrogen sulfide and sodium nitrite was highly acidic, and it was soon discovered that this acidic solution ate holes in our giant propane tank. This was concerning, because the process operated at pretty high pressure for a tank with such a large internal surface area. The first few times a hole developed, a patch was welded over it, and then pressure vessel code required a hydrostatic pressure test. The hydrostatic pressure test was for an hour at 150% of the rated pressure, and it usually created/revealed several other leaks, which had to also be patched. Then the tank would have to undergo another hydro-test - etc, etc, etc.
Eventually they started adding "hand holes", instead of patching the leaks. Apparently adding a maintenance port doesn't require a hydro, so the tank ended up having a bunch of randomly placed access ports added where holes had popped up. The holes tended to occur where the spargers from one cell discharged into the next cell - jets of acidic liquid seemed to be corroding and eroding the untreated carbon steel walls of the propane tank.
The acidic vapors generated in the process and were vented into the nearby cooling tower also caused problems. Eventually all that acid reduced the pH in the cooling tower and started corroding the internal fire system piping. We figured out that issue when the fire system supervisory system lost air pressure. The cooling tower was found to be at a pH of 2.2. We started by adding an entire pallet of 50lb bags of sodium bicarbonate, which didn't do much about the pH. After that, we switched to bags of granulated sodium hydroxide dumped straight into the circ water pump suction bay. It only took a few bags of that to get the pH back again. Thereafter, we had to check it daily, and dump 1-2 bags in.
And of course the vent line to the cooling tower eventually started developing leaks along the bottom where the acid mist condensed. A smarter man probably would have found another job at this point.
Eventually the company opened up their wallet, and hired an engineering firm that specialized in sour gas treatment in the petroleum and natural gas industry. The eventual resolution of the non-condensible gas problem involved replacing the steam air ejectors with massive industrial vacuum pumps. The vacuum pumps ended the steam losses caused by air removal, saving that steam for generation.
Below: A large vacuum pump, similar in size to those installed later at the Coso plants.
The non-condensible gas would no longer re-injected underground. Going forward, it would be treated to remove the hydrogen sulfide gas and released to the atmosphere.
At BLM-East and West, the non condensible gas was pumped over to a regenerative catalytic system called a SulferOx. The process circulated a chelated iron solution, through which the gas was sparged in a huge tower. This process was less expensive, because the iron solution could be regenerated by blowing air through it. So there was a constant depletion and regeneration of the solution going on.
Below: A SulferOx hydrogen sulfide scrubbing unit.
Tiny sulfur particles would accumulate in the solution, and these had to be filtered out in a side stream of the overall process. At the back end was a rotating drum of fine screen, half-submerged in the solution, that had a vacuum applied to the center of the drum. The solid sulfur particles would end up on the drum and a knife would scrape the sulfur off as the drum rotated. The sulfur would drop into a huge bin.
Below: A rotary drum filter for removing solids from a process. Solids are scraped off the drum by the brass-colored knife, and fall out the chute at the front.
Navy 1 and 2 were in less dire straits than the BLM units - from the perspective of curtailing operations due to non-condensible gas, so those two were the last to stop injecting gas. After a bit of operating experience with the SulferOx units at each BLM site, a less expensive and less maintenance intensive scrubbing system was installed at the Navy units, called a Lo-Cat. The Lo-Cat was a big box that operated at 15 psig gas pressure instead of 100 psig. Installation was quite a bit less expensive, and high pressure gas compressors weren't required to feed it. It also wasn't a tower, so it didn't require as much foundation work for a high seismicity zone.
It turned out that all of the gas scrubbing units had a few issues, although nothing as severe as the previous issues. The non-condensible gas contained trace quantities of vaporous mercury. The mercury accumulated in the scrubber solution, and eventually the bins of sulfur reached the point where they were hazardous waste. This issue was resolved by the addition of a vessel upstream of the scrubber that was filled with bags of activated charcoal.
Another issue these units had was a tendency to foam and spray chelated iron solution out of the vent stack from time to time. This is not too surprising, as they were circulating a fizzy carbon dioxide saturated solution, after all. Unfortunately, wind, iron mist, and high voltage switchyards don't go well together. There were a few high-voltage insulator flashovers until the company realized that it would have to make a habit of cleaning the insulators frequently.
The scrubbing units were complex enough that they required a dedicated operator to monitor the process. It was important to adjust the chemistry and ensure the sulfur removal end was working correctly. Operators also had to rake down, cover, and replace bins full of sulfur.
As one of the drones trying to earn a living, it was less than thrilling going from a power plant operator to a chemical process operator who smelled like a burnt match at the end of shift.
Geothermal power plants have a couple of other issues that fossil power plants don't have. I've touched on one of them: Resource Depletion. It's very important to recover as much brine as possible, and to re-inject that water into the underground reservoir to replenish it. It's just as important to be careful when doing this. If too much of this cooler water is injected in one place, it's possible to quench nearby wells. Injection wells that were placed within the middle of the wellfield were tightly controlled regarding flow rates, and fluorescent trace chemicals were frequently added, to monitor how quickly they would be seen in nearby production wells. The tracers were both volatile and non volatile, to better understand the underground water and steam movements. The reservoir modeling was complex.
Regardless of how well you conserve your wellfield, the enthalpy of the steam will fall over time. The pressures are low to begin with, and go down from there. High pressure steam was 100-110 psig when I first got there, low pressure was 7-10. By the time I left, these numbers had fallen to 90 psig and 4-5 psig. When I was there, the company set a record of 270 Megawatts. More recently, capacity has fallen to about 145 Megwatts. That's resource depletion.
Long after I left, the company was looking for additional water sources to replenish the steam reservoir. It seems they found one, after a huge fight. It's really tough to accomplish a water re-allocation project in the desert where water is scarce to begin with.
I mentioned the low pressures of the incoming steam from the wellfield. Because the steam is low-quality, low enthalpy saturated steam, you have to use enormous quantities of it. Each 33 Megawatt unit required 500,000 lbs/hr of HP steam, and maybe 30,000 lbs/hr of LP steam. In a high pressure superheated fossil-fueled power plant, you could make 250 Megawatts with that quantity of steam.
Because a high efficiency, high enthalpy fossil plant and the geothermal plant are condensing the same quantity of spent steam, each little 33 Megawatt unit has a cooling tower and main condenser the size of a much larger power plant. Have a look at the cooling tower for a small 120 Megawatt geothermal power plant in the Geysers, in Northern California.
There were a number of interesting design choices made on the units. The steam turbines exhausted upwards into crossover ducts, which routed the spent steam into the top of the main condenser. This was done to avoid expensive excavation for support structures, and building expensive reinforced concrete structures to place the steam turbine above the main condenser.
Below: BLM-East unit 7 at the left, and unit 8 on the right. The unit 7 steam turbine exhaust crossover is the large cylinder at the upper left. The dual air ejector train for unit 8 is above and right of the guy's hard hat. The inter and after condensers are directly above his hard hat. That system is no longer in use due to the vacuum pump installation (not shown in the photo)
The condensate from all condensed steam was pumped by single-stage condensate pumps into the circ water system. That's right - the cooling tower make-up was distilled water from the condenser hotwell. The cooling tower basins were fed plenty of make up water - 500,000 lb/hr of condensed steam. The cooling tower basins received much more make-up water flow than they could evaporate. The cooling tower basins were equipped with overflow pipes that drained into a fire-water pond. That pond was equipped with a diesel fire pump - and that pond overflowed to a different pond that was re-injected underground. Inexpensive and clever. The only chemistry control I recall on the cooling towers was a weekly dose of biocide. Any chemical would quickly be diluted and removed along with the overflow water, so there wasn't much point of adding anything. Same for the geothermal steam.
The last couple of stages on the steam turbines had Stellite strips on the leading edge of each blade. The turbines were designed to extract every BTU of energy, so the steam would be starting to form water droplets before it even left the turbine. The result was erosion, which was countered by using super tough alloy strips. You could see the difference in wear between the hard strips and the softer blade material after a few years of operation.
Below: One of the steam turbines out on a stand for annual de-scaling - sandblasting. The large cylinder on the right side of the rotor is a "dummy piston", to help counter the thrust of the steam flowing through the blading on the left.
With the exception of Unit 1 - a Mitsubishi - all the generating units were identical Fuji units, and they had a very interesting turning gear. They used a small oil turbine for turning. It used a nozzle that squirted oil from the main lube oil pump discharge at about 110 psig onto a Pelton wheel in one of the bearing housings. So instead of turning gear, these units had a "turning oil valve" that opened or shut to slow roll the turbine.
The main condensers came with an online Ball Cleaning System. This system would inject mildly abrasive balls into the circ water system just before the circ water entered the main condenser. They would enter the condenser tubes and scrape gunk off the inside, then be captured in a screen on the outlet side of the main condenser. It was weird, and it's difficult to know if these had much effect, considering how clean the water was. The Ball Cleaning System definitely made the service tech wealthy.
The first unit built at the site was at the very end of a 50 mile long 115KV transmission line. Due to capacitance in such a long line, there was the potential that the unloaded line voltage would be too high to synchronize the generator to it. This unit's main transformer was equipped with an on-load tap changer to be able to vary the line side voltage quite a bit more than the exciter would be able to do by itself. Only Navy 1 used the 115 KV line, so once Unit 1 was synched, the line voltage could be controlled, allowing Units 2 and 3 to synch.
The remaining units, 4-9 used a 230 KV transmission line that stretched even further - 90 miles or so. The unloaded line open-ended voltage control issue for these units was handled by an "inductive reactor bank" at Navy II - huge three phase high impedance coils - that could be cut in with 230 KV breakers to reduce line voltage low enough to synch the units. Units 4-6 used the standard step-up main transformers, 13.8kv to 115Kv, then had a larger 2:1 transformer to raise the output of the three 115 KV transformers up to 230 KV.
Below: Navy II switchyard with three main (13.8/115KV) transformers on the upper right, one larger 115/230KV transformer at the left, and the two inductive reactor banks inside square cinder block walls.
Each site initially had its own control room, with a wellfield control room operator and a power plant control room operator. There would be 1-2 outside power plant operators to deal with the problematic gas compressors, and loop seal upsets on the inter and after condensers. There would be 3-5 wellfield operators as well. At the peak, each crew was 17 people, and most of them were pretty busy with the troubles caused by non condensible gas.
After the non-condensible gas issue was more or less resolved and the IT technology had matured enough to allow remote operation, the control rooms of each site were consolidated into one central room at the Navy 2 site.
Immediately after the place began using vacuum pumps, and started treating and releasing the non-condensible gas, the really big issues mostly went away. Injection wells stopped locking up, the troublesome gas compressor skids were no longer needed.
There still were occasional upsets, usually caused by loss of the 115 or 230 KV line. All the units would trip on over-frequency, and the entire wellfield would begin venting. Shutting in a wellfield that has over 100 production wells doesn't happen very quickly.
The wellfield guys invented a device called the Yoyo to quickly close the scaled-up wellhead valves. you would bolt a spool onto the wellhead valve, wrap a tow strap around it several times, and connect the loose end to a truck and slowly drive off. That would close some very sticky valves in a reasonable amount of time.
The area near the power plant was interesting in that Native Americans had been there long before we ever got there, leaving behind gorgeous petroglyphs. We were told in no uncertain terms to leave all of this stuff alone. The fact that it's on highly restricted Navy property probably has a lot to do with why it these amazing archeological sites haven't been destroyed by off-roading idiots.
Below: Climate change is real! Nothing but rattlesnakes and coyotes live there now.
There wasn't much opportunity for advancement beyond control room operator, unless you played politics and had a solid back-stabbing game. When I left and went to work at the coal-burning power plant, my pay increased by about 50%. I worked at that place for 8 years - although it seemed much longer than that.
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