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Workover Equipment
Posted by Heading Out on November 29, 2009 - 10:55am
When we began this series of tech talks, a drilling rig was anything that punched a hole through the ground, to get at the oil or natural gas underneath. Once a hole is drilled, however, there is often other work that needs to be done on the well, but now the infrastructure that helped when we drilled the well starts to get in the way when we need to do other things. And so the tool will change to what is known as a workover rig. (Though these could be the old rigs left in place on a platform after the production wells are drilled - just to keep life clear).
See there you are, having sunk your kid's inheritance into this oilwell, and it just isn't producing the way you were promised. Sure it's making oil, but the supply seems to be dropping faster than it should, or perhaps there is too much sand coming out with the oil, or the could be any one of a variety of reasons.
And suddenly the partnership is talking about hiring an oilwell service company to bring out a workover unit to come out and fix the problem. You might have heard of one of the two of the small companies that carry out this sort of work, the two more prominent are Halliburton and Schlumberger, although the latter came into the business first as a company that helped log or survey the hole to determine the types of rock that the drill had gone through. (And in true MSM tradition I should admit that I have consulted for both these companies, and that “small” was meant as a joke).
Work-overs can deal with a wide variety of problems, but they come at the situation from a different perspective than the original well drilling. To begin with, there is a cased hole that often goes all the way down to the original pay. Further the tools that will be used are not going, in large measure, to be used to drill new segments of holes, but rather to treat the original well, replace parts that have failed, or change the layer of rock that the well is getting the oil from.
Now there is a word of caution here. To work on the well, the first thing that you are likely to do is stop it pumping oil. That is known as shutting the well in or killing the well. Then you bring in the work-over rig, and do what needs to be done. The workover rig leaves, and you start the well producing again. Here is the caution. Because you stopped the well producing for a while, when it restarts, in most cases, and regardless of whether the action or treatment that the company applied really worked, the well will begin by producing more oil than it did just before it was shut in.
Because the oil well owner may have paid quite a bit of money for a treatment, it is sometimes amazing to me how well educated folk will see that immediate gain and believe that a treatment that in other circumstances they would find incredible, has created an improvement in production. Techniques, for example, that promise the ability to drill lateral wells out from the main bore at high rates of speed – without discussion of where the cuttings that were so miraculously removed went to – may, at some time, be the subject of another post. The well behavior has also to be monitored over a period of time to validate the improvement (`nuff said).
Some of the treatments that need to be carried out are not very complicated. Perhaps when the well was first drilled it was not effectively acidized or perhaps the oil might have precipitated out some of its contents into the drill pipe as it moved from the completion zone up to the surface. Remember that the oil starts out usually more than a mile or two deep in the ground, where the temperatures can be quite hot. Then as it flows up though the pipe the oil can, for example, suddenly enter a section of the pipe that is being cooled by the North Sea that lies all around it and is a great heat sink. Suddenly any dissolved minerals in the oil might reach saturation and then drop below the saturation temperature, and start to crystallize out. (I have seen pipe sections where the hole diameter has been cut by more than half by crystals that grew in from the wall and were more than an inch long.) Paraffin or similar waxes that were in the oil might similarly, for example, have started to clog the pipe, or some of the carbonate and sulphates in the oil might form a precipitate or scale on the pipeline wall as the oil flows upwards.
These deposits can be removed by putting a scraper onto either the drilling rod of the workover unit, or from a wireline (a wire line) that is run from the surface, generally from a winch. A wireline can be either a slickline or single strand cable, or a braided line which has a number of strands and is capable of carrying a higher payload. These lines can be run into the well very quickly (and in smaller cases do not need to have the well killed to be used).
In a slightly more complicated case an electrical control cable or power cable can be added to the wire to power down-hole operations, particularly when packers or plugs are being used. Depending on purpose these might also be fielded using a more conventional drill string, or through coiled tubing, which I am going to talk about in a different post.
Packers are devices that are lowered into the well to isolate the well zone in which the work is to be carried out. For example, if one were going to seal off the old production zone and move to another one, one might pack off the old zone, first before pumping cement into the sealed-off segment to fill it with cement.
You can imagine that almost every type of repair must be carried out in this fashion. If something goes wrong down hole, then because of the limits of access it is going to take some imagination to deal with the problem, and the oilwell service companies have now provided that for a number of years.
The more simple jobs, such as sealing off a zone that has stopped being productive, or lowering a new perforating system down the well to stimulate production from the layer of rock, to cleaning the screens at the bottom of the well that keep the rock in place, while allowing the oil to flow into the well, are all somewhat obvious once named, though perhaps not so obviously needed until you see the effect of the problem on well production.
The more common other workover uses, for stimulating production, will be in another post. And once again this has been but a short summary of what can go on, just to describe some of the basic ideas. Comments and questions are welcome.
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After doing some postings of my own, I really can appreciate the time and effort you all put into keeping this site running. The quality of the postings has always brought me back. You are very much appreciated.
I remember reading in your posts about drilling a deep well to the point where the area temperature would be around 140 degrees Fahrenheit (e.g. 9,000 feet) or so with a cost of roughly $3 million to dig just the one well. I've looked on line to try to find where such a venture has been tried to heat a number of homes through something called district heating. Such a venture seems possible with an area of a 1,000 homes which would lead to a shared cost of $3,000 each with a pay back of a couple of years. This does not include the cost of running of insulated pipe and hookup.
To me this seems plausible but 140 degrees is probably too low and the amount of fluid needed would need a bigger pipe. Most large geothermal projects are along fault zones but I'm thinking internal tectonic plate areas. I guess my question is have you run into anything like this before and what did you find out?
I also assume that mineral accretions would also build up and the pipe would have to be eventually augered out.
I did a short technical post on Bit Tooth some time ago, and will probably return to that theme for a couple or three posts here, later in the year. The biggest sources for geothermal heat are where magma has come close to the surface. In California, for example, at The Geysers and in Iceland there is enough heat, closer to the surface, that it can be used to generate power. But you are right about the amount of dissolved solids that have to be dealt with.
Oh, and thanks, we appreciate the kind words.
Peter -- Not something I know much details about but a deep well probably won't be cost effective. One of the difficulties would be lifting and disposing the hot water. Most well that deep will be in a salt water environment. Salt water is a definate liabiity: maintenance and disposal costs would be much higher then you might suspect.
But the good news is that depending upon where you live a 50' to 100' well might work better. I saw a special where a series of shallow wells were drilled for thermal recovery. Near Atlanta, Georgia I think. Obviously the water temp wouldn't be too high but you can extract a lot of heat out of 75 degree water if you can move enough volume. The thermal recovery was going to suppliment the heating of a modest sized nursing home. I'm not sure but they may not have been producing water but using a closed loop system. The fact the application was for a commercial enterprise could mean that it wouldn't be cost effective for an individual home. But your thought regading some sort of a communal effort might make it viable. A "low temeperature geothermal" search might yield some info. I think I've also heard of heat pumps designed specifically for recovery from water.
In Sweden this is a very common technology to extract heat from holes drilled in ordinary rock for house heating. The rock or soil is cold maybe just a few degrees above zero but the the heat pump will still recover a lot of heat and use a lot less energy than heating direct with electricity.
If the electricity is generated with any kind of boiling fuel I guess the saving will be very small since the losses for electricity generation are a lot higher than for heat generation. There is however one exception and that is if the waste heat is used for heating via district heating and this is actually also common in Sweden.
Here in Halifax is a very big fan of air source heat pumps, even for replacing oil/gas heat. And your geothermal based variety will be much more efficient that an air source version. I think the only real downside is the high capital cost.
When we see counts of rotary drilling rigs in service, do these include workover rigs? Or are workover rigs by definition the opposite of rotary rigs?
Also, it seems like workover rigs are smaller. Wouldn't the big companies, say drilling natural gas wells, keep their own workover rig on hand to do maintenance, or is the technology such that it is better to hire Halliburton or Slumberger?
Gail -- typically most reporting agencies don't include w/o rigs. Many operations done with w/o rigs don't require a state permit so no one other then the parties involved are aware such activities are undertaken. Just like drilling rigs most operators don't own their w/o rigs....just not utilized enough. But if an operator owns a big field with lots of old wells they may keep some different types of units in the field called pulling units that don't even have all the capabilities of a w/o rig. There's even a fairly wide range in th world of w/o rigs. Some have rotating equipment which allows some minimal drilling capabilities.
The world of w/o rigs is populated by companies typically smaller then the drilling contractors. Halliburton and Schlumberger don't even come to mind when I think of w/o rigs.
As usual Gail, you are spot on!! Workover rigs are smaller. Where the drilling rig might be required to lift, set, reciprocate, and cement a string of casing weighing a BUNCH OF LBS, the workover rig largely works with tubing at 4.7 lbs/ft or sucker rods weighing a lot less. On average, drill pipe weighs @ 14.7 lbs/ft.
The workover rig costs less because of less horspower, it moves faster to location, and the traveling block runs up and down the derrick faster (shorter trip time).
Know that I am older than dirt, and I remember when workover rigs did not exist. The workover rig was brought about to achieve greater efficiency in doing the light lifting after the drilling rig had drilled and cased the well.
Until the early part of the 50's, the drilling rig completed the well it had drilled. It was a product of the "standard derrick" which was built before the drilling unit appeared on location. The "standard derrick" stayed over the well until the well was finally plugged and abanoned. Ergo, somebody decided the rig should use one derrick over and over, and thus the jacknife derrick of today was employed.
Clear as mud???
Deeper
A treatment of geothermal power generation costs can found found at the following address for those who may be interested:
http://www.nzgeothermal.org.nz/Publications/Whats%20New/SKM%20Cost%20of%...
Please note that the author(s) are discussing 'wet' systems, not hot dry rock.
Apologies for being somewhat off-topic
Always look forward to the tech talk posts, here is a fairly traditional style workover rig operation up north
weather is a bit of a consideration on the slope
Dang Luke...maybe everything in Texas isn't bigger (excluding egos, of course). Your w/o rig would make a fair sized drilling rig down here. To reiterate what the Dirtman pointed out above w/o rigs cost a good bit less than a drilling rig. It can take 1 to 2 weeks to complete a well. Real life example: last Tuesday we logged a keeper down on the Texas coast. By Thursday the casing was run and cemented (took a day to stabilize the hole. By Friday morning the drill was "released" (we stopped paying the day rate). Today, subject to just how bad the weather is, we'll move the w/o rig onto location. We'll run a log to make sure the casing is cemented properly. If not we'll shoot holes in the casing and pump more cement in. We ran 5" casing. The next step is to run smaller pipe in (2.5" tubing) to the 5" casing. This tubing will be secured by a series of packers (think of a straw stuck thru a cork which is then stuck into a bottle). Then we'll send perforating guns down to shoot thru the tubing and casing at the same time. Sometimes this is done separately. There is a heavy water in the tubing to keep the well from coming in wild. Then we'll release the w/o rig, flow the water back out the tubing and then run a number of tests to make sure we have a good completion. After that we'll need to lay a 1 mile flow line to connect to the main transport line. This could take a couple of months (low land that gets really nasty when it rains...had to run my SUV through the carwash twice last week). While we're waiting for the p/l we'll install the surface equipment the production will flow through. It might be a surprise to many but one important piece of the system is a line heater. As the pressure of the NG is reduced when it flows through the separation equipment it gets very cold. Cold enough to freeze the flow line. The heater treater pulls a little NG out of the flow line to feed itself. The last step is to install a meter to measure NG sales. Then we'll drill at least one development well.
BTW: this well made a very good holiday for us. We found about 25% more NG then we had modeled. The prospect was drilled on 3d seismic data which showed an HCI (hydrocarbon indicator) or "bright spot". Sometimes you can see a direct indication of NG on the seismic data. Now that we know the HCI is real the Ps of the development is excellent. Not foolproof but still probably an 80% chance of success.
Thanks for the extra insights Rock, always appreciate them. Hope you don't take the little needling I gave you on another post today the wrong way, I was just trying to do a little redirectional drilling so to speak. Good to hear you are having a good run of it :-)
Interesting on the heater. I hadn't thought of that but I'm only just starting to visualize the NG process. Locally the used ATCO magnate (made his first millions double stacking some surplus ATCO bunk houses he picked up for a song, or maybe just the hauling costs, on barges that were then leased to the Exxon cleanup operation in '89) is trying to get in with the outfits working the interior's gas play. He has developed the nearest hot springs thermal capabilities substantially and is looking to see if he can harvest whatever is available out of the NG wells. This is pretty much conceptual right now as I believe only one exploratory was drilled out Nenana way last summer. Much depends on whether a bullet line gets built south from the slope or interior (if the big line gets built). The Cook Inlet fields are playing out so pressure is building for something to happen. Things will pop eventually.
I followed a rig similar to the one posted above for about 1/2 hour one morning last fall. My phone pictures are weak and I don't have a 'photo bucket' type account so posting them would be a pain. The tires were about twice as tall as the guy walking behind them and were placed in pairs a little better than a tire's width apart centered front and back on the rig. A little later in the morning a caravan of three story buildings rolled down the road. The guys I worked with told me the rig was just a little one and the that when the big ones rolled down the roads it was quite the event. The big ones look big from a mile off when you are driving by.
The same post I clipped the above pic from had a shot of this smaller coiled tubing w/o rig as well.
Dang Luke…I didn’t even notice…honest. If you’re gonna tease a geologist you have to be pretty blunt. We’re use to being a target. And sometimes even rightfully so.
That’s a very different type mobilization process we have down here. In Texas you have to be road legal to move on any public roadway. On a leasehold you can drag (skid) a rig anyway that makes sense though.
Coiled tubing units have a big advantage in certain ops but the conventional drilling companies in the lower 48 have resisted expanding that way. One Canadian outfit has gone that way big time. Wonder if HO plans to discuss CT units.
Roadways aren't public once you are little out of Deadhorse, the haul road (Dalton Hwy) to Deadhorse only openned to the public a decade or so back. The real big stuff gets barged up and landed when the ice opens up.
The rig I saw moved may not have been quite as large as the one pictured but scaling it from close ups and distance shots make it 120 ft tall anyway, maybe more. It could roll on the gravel, I think it had four tires in front, but I only have a shot of the two in back.
The big rigs are much heavier and have to travel over smooth plates of some sort placed over the roadway in front of the rig then they must be passed through (I believe) the rig to the front of it after the rig passes over them. The operation has been described to me, but its been a bit. Can't skid stuff around over the tundra until ice roads are built in the winter, the busy season. Some huge modules are sealifted in as well. To move them from the beach they have covered the road with plywood in days past, but they may have advanced their tech some since then.
On a warmer note: those sealifts used to have a fairly narrow window in which they had to occur---these last few years the ice has been a couple hundred miles off shore, it used to average only fifty mile out, and its out for months longer than it was a mere fifteen years ago, something is certainly changing.
Speaking of roads couldn't help but notice you are all pickuped up again, what did you get?
Those steel plates used to drive/skid equipment over are called mud boats down here....lots more mud then ice in Texas.
No personal p/u. Have a Kia Sorento. Nice inexpensive 23 mpg vehicle. Very good ground clearence but not 4W drive. Most locations are boarded so 4WD not usually needed. But when I do have the need I rent one. Happy but still long for that p/u.
Never think of mud when thinking of Texas, always picture the scenes in 'Giant' but that is west Texas, big place. I imagine it gets darned wet near the gulf. Tundra is really weird stuff, the foot print even with ice roads ice kept to a minimum. It is so dry up here that that having enough snow to make the ice roads can be and issue. The thawing ground is starting to pull the plug some of the millions of pot hole lakes too. Its been noticeable even flying into Fairbanks summertime.
Back a little more on point: Is the heat produced from gas wells abundant enough to use some of it for electrical generation, or do you end up needing most of it to move the processed gas? The guy talking that game up here has a fairly cool temp hot spring he has harnessed for power and refrigeration at his end of the road off grid resort. He actually keeps an ice castle frozen year round (inside an insulated building) using low temp binary geothermal power.
Luke -- No real excess heat from a line heater for the NG flow. usually just sized large enough to keep the line from freezing.
My current boss did a neat trick years ago. Had a field producing very heavy oil...almost tar. A little NG too. Once a month he had to run turbine heaters for 3 days to warm the oil enough to get it to flow down to a barge. And had to spend a good bit on chemicals to prevent parafin build ups. So he took the little NG production and fueled an electrical generator. Took the hot water off of the generator jacket and continously cycled it thru the oil tanks (your basic co-gen set up). Oil stayed warm so didn't need the parafin chemicals. Used the elctricity to power the pump jacks in the field. Didn't know it when they bought the field but there was a pretty pond filled with this sludge that had spilled over the years. Dredged it out and paved the lease roads with it. In the end he had a very nice, clean and profitable project.
Thanks, little dense here, the line heater burns gas. I was picturing some heat exchanger system but if the processes already cool the gas to freezing having cooler gas to start with (because of a heat exchanger in line ahead of the pressure reduction phases) would just make the problem worse.
Luke -- Let me back up a little. Maybe my explanation wasn't clear enough or I'm not hearing you correctly. When the NG reaches the surface equipment the pressure is reduced...often significantly. This pressure reduction can produce a great cooling effect. Enough to freeze the NG flow line. The line heater actually heats the NG back up in order to keep the flow line open.
Did I misread you?
No I just was making things too complicated. As I understand you n/gas is pulled out of the line burned in a heater and the heat is added to the most effective place in the surface equipment/line arrangement to keep the expanded (I'm guessing if it loses heat) n/gas from freezing.
I envisioned some sort of heat exchanger installed ahead of all other equipment drawing heat from the raw n/gas and which was later piped back in to to heat the cooled n/gas back up some.
I'm guessing the surface equipment is to remove condensates and free water from the gas, but I'm not certain about whether that actually happens at individual well heads or not. The pictures and diagrams I have been able to pull up just give the me vaguest idea of what happens when the pipe exits the earth.
This is all a little off point from the rework topic of this post, but as the thread is rather quiet I was just trying to get a better visual filed in my head. Thanks for the help.
Sorry for the late reply. I see now what you're getting at. Even after the NG goes thru the heater treater there's no surplus heat to pull off of it. The water is removed with a "dehy": dehydration equipment. Water is the NG stream is a big no-no from the pipeline companies (as is CO2 and nitrogen). They have max allowable...exceed that and you not allowed to pipe the NG into their system. If there's condensate it's also removed. Can't get it all out but the condensate increase the btu of the NG. Folks price NG based on btu: 900 is pretty lean and 1300 is pretty rich.
ROCKMAN:
Thanks again for the helpful comments, and yes I do plan on adding CT to the list, fairly soon.
You're welcome HO. Since you do all the heavy lifting here I figure the least I can do is toss in a tidbit now and then.