A workover is not the same as a sleep-over
Posted by Heading Out on October 23, 2005 - 12:25am
As we move through this explanation things do start to get a bit more complex. When we began a drilling rig was anything that punched a hole through the ground, to get at the oil underneath. And then we divided these structures into rigs and platforms. Well the new term for this week is workover rigs. (And these may 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 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).
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, do what needed to be done, and it 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 almost every case, 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 they 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. The well behavior has 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. Paraffin or similar waxes might, 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 (I have seen some of these crystals be well over an inch long). These deposits can be removed by putting a scraper onto either the drilling rod of the workover unit, or from a wireline that is run from the surface. 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.
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. There is a more technical article available.
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 saved until next time.
This is part of an ongoing weekend series on technical aspects of oilwell (and natural gas) drilling. Previous posts can be found at::
the drill
using mud
the derrick
the casing
pressure control
completing the well
flow to the well
working with carbonates
spacing your well
directional drilling 1
directional drilling 2
types of offshore drilling rigs
coalbed methane
As ever, if this is not clear, or if there is disagreement then please feel free to post, and I will try and respond.
Contact
- Content: editors at theoildrum dot com
- Tech support: support at theoildrum dot com
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This work is licensed under a Creative Commons Attribution-Share Alike 3.0 United States License.
It would be very nice if this problem could be resolved, as I am rather keen to read that article.
Normally on Saturdays I post a technical topic on some of the basics of drilling for, and producing, oil. This week it has been delayed a day. Readers are asked to remember that it tries to convey the technology in a relatively simple, and thus easily understood, manner. For those in the oil patch who wince on occasion, feel free to chip with comments, and help convey the ideas. The series is starting to get fairly long, and so the list of earlier posts is attached at the end, and below the fold.
Does the phrase "gunboat diplomacy" ring a bell ? It was an old-fashioned term from the days of the British Empire. And now, apparently, it is making a reappearance in the Far East.
In a post a couple of weeks ago I had mentioned the problem of the "Rule of Capture" wherein the first person to draw oil/gas from a formation was entitled to as much as they could get from their wells, until their neighbors, in turn, sank their own wells.
Well this is not just a historical note - it is now one of the issues between China and Japan. Since the Chinese are tapping into a formation ahead of the Japanese, and thus, potentially "acquiring" some of the Japanese resource.
It was the same concerns that led Iraq into Kuwait back in the term of the first President Bush. Except here there was a concern that the wells in Kuwait had sort of "meandered" into Iraqi territory.
So what is with this meandering business?
Well to develop the idea of directional drilling, we need to return to the Volga-Ural basin in the Soviet Union, back in the 1950's. And I quote from John Grace's "Russian Oil Supply"
In the Volga-Ural basin, however, particularly after recognition of the enormous potential of the deeper Devonian strata, drilling targets were further below the Earth's surface. Moreover, the older, more lithified rock of the Volga-Ural basin was harder. This required higher drilling torque, which in turn demanded superior strength drill-string steel. The Soviet steel industry was basically unable to provide high-strength drill string in volumes necessary to develop the basin.
Engineers responded with turbo-drilling, which does not depend on rotating the drill string. Instead, immediately above the bit, they placed a turbo drilling motor, which itself did the work of turning the bit. This obviated the necessity of twisting the pipe and thereby reduced the required quality of steel.
Turbo drilling radically increased the productivity, Combined with the growing number of rigs available, the total number of feet of development drilling conducted per year nationwide jumped from 1.9 million feet in 1949 to 7.1 million feet by 1950 and 12.1 million feet by 1960."
(We'll come onto their second innovation - that of waterflood - in a few weeks.).
Putting the motor at the bottom end of the drill string had a couple of other advantages. One is that it allows the hole to make angle, i.e. to turn in a tighter radius than if the whole pipe were rotating.
Motors can accomplish 13º-15º per 100 ft doglegs, while turn radii of rotary steerables are 10º or less.
The Russian idea took a while to catch on in the West and to his credit, a guy in Houston called Bill Maurer , had a fair bit to do with that. (And due to Rita the link is currently down).
Suddenly we did not have to have the complexity of joining 30-ft lengths of drill pipe together to deliver power to the end of the bit. This had always been constrained by the steel strength and joint limitations, now that could be designed out, and the power could be delivered to the bit hydraulically through the mud, since this could be used to drive the motor. Unfortunately because the drilled holes are small, the motors have to be small also, and this means that they started out being quite long. (A case history or two can be found on the web.)
Turbo motors work best at higher speeds, but to create the chips and achieve effective drilling with conventional tri-cones, rotation speeds had, historically been slow. And the problem remained of creating the high thrusts across the bit that were required for this type of drilling, when the motor turned faster.
One answer came in response to a second problem. As the rocks that have to be drilled become harder, so the forces used to cut through them also up, causing a materials problem. The materials used to make the drill bits were breaking under the higher forces. But until now we had tried to break the rock in compression by pushing the tooth into the rock (remember that old miner).
If, instead we dragged the bit across the rock without trying to chip it, in the same way as a metal-cutting bit on a lathe peels off a layer of metal, maybe we could lower the forces on the bit. And if we used a diamond tool to do this, then while each diamond insert would only remove a very small amount of rock, we could impregnate a whole bit face with small diamonds ( much cheaper than the single stone you buy for the intended, since they are much smaller, and more common). These diamonds can be dragged over the rock face and slice off very thin layers, but can do so when moved at a very fast speed. Putting the two together meant that a new drilling concept could be developed, and a new drilling bit.
Some pictures of the development of these tools have been given by Schlumberger.
They also show the next development. This came about with the development of larger polycrystalline diamond compacts (PDC's or PCD's depending on your level of technical correctness). By making these larger diamond coated discs and setting them on the drill bit it was easier to circulate the mud so that it kept the diamonds cool. This is important since, if you get the temperature of the inserts above about 3-400 degrees, the diamond starts to soften a bit and wears faster. In this regard the design of these bits is still not perfect, but it has become better. Some of the earlier work on this was helped along by Sandia Labs, but unfortunately most of the early work was in the days before they posted their work to the internet.
So now we have a tool that can make all sorts of bends and that can drill rock that is harder, and relatively quickly. DoE still considers this an area for further work and is continuing to fund further development. We'll talk about some of those new ideas more in future posts.
Sorry - HO
The link to the article points to
http://www.theoildrum.com/admin/story/2005/9/25/18419/9524,
but the actual story is at
http://www.theoildrum.com/story/2005/9/25/18419/9524.
I don't have permission to enter the admin part of the site—for obvious reasons—but the story is still alive and well. Thank you for all your work.