6.
Chapter
Figure 26 - Liner packers can be run in conjunction with the liner hanger and set before cementing or after cementing. A pol-ished bore receptacle may be run above the packer to provide tie-back capabilities. (Courtesy of Texas Iron Works.)
w w w . l i n e r t o o l s . c o m Reprinted from World Oil magazine, May 1988 with permission from the authors.
C a s i n g
are not recommended on drilling liners for these reasons.
Another alternative when running a liner through known high-pressure gas sands is to run external casing packers.3,5 These too cause circulating restrictions and are very expensive. They can be run in the open hole (preferably an inguage part of the hole) or in the liner overlap. They should be considered more reliable than packers run in conjunction with liner hangers.
Lastly, concerning prevention of gas leaks in the liner top, two more techniques will be discussed. Stewart and Schouten51report that gas migration, resulting from casing contraction, is a com-mon problem. They recommend that mechanical seal ring devices be used to prevent this even though casing contraction is not ex-pected under initial production conditions (Fig. 27 shows a type of seal ring device of deformable rubber used for this purpose).
We agree with this precautionary installation for wells in which the internal pressure in the casing will be reduced substantially later while drilling or during production. As reported by Suman and Ellis,5thermal expansion of the casing while cement sets and sub-sequent temperature reduction, mill varnish, etc., can all cause a micro-annulus. This situation is also created by water base drilling
uids exerting less hydrostatic pressure as they are heated up. A micro-annulus also affects cement bond log evaluations. This will be discussed later in more detail.
A nal, more radical technique to consider is the use of a very short overlap of, say, 50 to 75 ft. If the liner leaks gas and it can-not be broken down, than an extremely high breakdown pressure may be tried. If this does not break down the liner top, a tailpipe below the packer could be used to spot acid on top of the liner.
The squeeze packer would be reset and an attempt made to break down the liner top once again with an extremely high breakdown pressure. (Note: Aluminum or PVC pipe should be used as tail pipe in the event, while squeezing, the annulus uid around the tailpipe compresses enough to allow cement to “creep” up around it. This pipe is easily drilled or pulled in two.) The authors know of one lin-er top successfully broken down with 5,000 psi surface pressure.
If a breakdown is not achieved, the work string could be jetted, or swabbed in for cleaning out restricted ow channels in the cement. Acid could then be respotted and an attempt made to breakdown the liner top again. If the top can be broken down, it should be squeezed with an anti-gas migration cement.
Caution should be used with certain anti-gas migration cements. If the proprietary slurry relies on a cement that devel-ops high thixotropic properties to control gas ow, it should not be circulated on top of the liner. Its quick forming gel strengths may make reversing out or circulating excess cement out the long way impossible. Also, the cement may not fall out of the drillstring. On one job, we could not reverse excess cement with 2,500 psi and could no circulate out the long way with 3,500 psi. We ranfrom the cement. After pulling out of the hole, we had 1,961 ft. of drill pipe cemented on the inside. These type cements also can cause severe swabbing difculties when pull -ing the liner runn-ing tool through the cement if is on top of the liner because of low clearance between the liner running tool an intermediate casing.
If the liner top is squeezed with thixotropic cement, then ce-ment should be displaced below a squeeze packer and into the overlap before attempting to obtain a squeeze pressure. Cement should also be batch mixed since any pumping problems that may occur will make it unpumpable. This will also help prevent high thixotropic cement from gelling up inside the drillstring as it develops high gel strengths and cannot be pumped. Squeeze techniques will be discussed in more detail in future articles.
One last comment should be made about predicting annular gas ow. The authors feel that there must be a certain gas-oil ratio at certain temperatures and pressures at which annular gas ow is not a problem. It appears that the higher the yield of a potential pay zone, the less likelihood there is for annular gas ow problems or, conversely, the “dryer” the gas, the more likely there will be annular gas ow. More research needs to be done to better predict this problem. The bubble point of the reservoir probably has a bearing on annular gas ow potentials, for instance.
MECHANICAL T ECHNIQ UES
If, despite the best efforts, the liner top still leaks, there are several options available. One is to set a production packer above the liner top and produce the liner top gas with the completed interval. However, gas ow through the channel could get worse as pressure on the top of the liner is reduced to the owing BHP of the producing zone. This could eventually allow movement of
uids behind the liner and through the liner top. A second op -tion is to run a liner tie-back packer. The packer is landed and set in a receptacle at the top of the liner. When set, the packer seals in the liner receptacle and packs off in the casing to isolate the liner top against pressures from above or below. These type packers are also available to be set hydraulically in high angle holes where drag causes difculties in applying weight to them.
The most expensive option is isolating a liner top leak is to run a tie-back string or scab liner.6 Even then, the same design problem of controlling gas migration still exists with the scab liner as when the rst liner was run. A tie-back string has a bet -ter chance of success than the scab liner because the cement column can be located much higher above the top of the leaking liner than a scab liner can. The amount of cement is limited with a scab liner to whatever the operator wishes to impose as the maximum amount to be circulated around the workstring on top of the liner. Thus, limited cement volumes mean more channels, less chance for isolation bonding and a shorter distance for the gas to migrate and honeycomb the entire cement column. The tie-back string can be cemented as high as the operator desires.
By varying cement thickening time, the operator should be able to contain gas migration to the lower part of the tie-back string before gas can channel the whole cement column. The only hope for success with the scab liner remedial approach is to use an anti-gas migration cement since the short cement column pro-vides no latitude for varying thickening times.
Packers can be run in conjunction with the tie-back string or scab liner. Circulating restrictions through the packer are Back-up ring Figure 27 - Seal ring device consists of two opposing deform-able cup-type sealing elements. As pressure develops at the casing-cement interface, it causes the inner seal to expand and seal against the casing. This can help guard against micro-an-nulus communication. (Courtesy Gemoco.)
Top of Cement
4 Piggyback
packer (set position)
Drillable packoff Liner top Liner setting tool
3 Piggyback
packer (unset)
Cement
2 Drill
String
Piggyback packer (unset)
Liner top
Liner
1
Intermediate Casing
Figure 28 - Sequence used to squeeze a liner using a piggyback backer. 1) Piggyback backer is run with drillstring, liner hanger and liner. 2) The rst stage is cemented around the bottom and the wiper plug is bumped. 3) Setting tool is pulled out of liner, packer is set and the liner top is squeezed. Cement is held in the overlap and on top of the liner. 4) Piggyback packer is unset and the drillstring is pulled out of the hole. (Courtesy of Texas Iron Works, Inc.)
w w w . l i n e r t o o l s . c o m Reprinted from World Oil magazine, May 1988 with permission from the authors.
not a design problem since the leaking micro annulus of the liner top will not accept uids. Thus, there is no danger of creating a lost circulation problem resulting from a higher equivalent circulating density or the bridging off of cuttings. (Note:
the intermediate casing should have been circulated cl ea n o f cuttings before cementing). The packer also can be expected to achieve a high rate of success because it will be set in the intermediate casing and not in an irregular open hole. Another advantage of the packer is that if it is successfully set after the cement is in place and can trap gas pressure long enough to let the cement column above it solidify, then the cement above the packer will not transmit gas should the packer fail later. Since the operator cannot
6.4
know for sure that the packer will set ahead of time, it would still be prudent to run an anti-gas migration cement slurry to guard against this eventuality. High pump rates to put cement in turbulent ow should also be possible in this “closed” system to ensure no channeling
One last point should be made on liner top repairs. Polished bore receptacles (PBR’s) leave open the option of running a scab liner or tie-back string to cover up a hole in the intermediate string or a loner top leak. Since it cannot be assured the there will never be a liner top leak or that a problem will not develop with the intermediate casing later in the life of the well, PBRs should be run on all liners.
LIT ERAT URE CIT ED FOR CHAPT ER 6:
LIT ERAT URE CIT ED FOR CHAPT ER 6:
For the references cited in this chapter, please refer to the back page, (all references for the entire document).
x Spotting cement around the drill pipe, pulling the pipe out of the cement and then squeezing the top of the liner would prob-ably result in a squeeze in which the cement was contaminated with mud.
Another alternative to consider is running a packer on the top of the liner to seal the annulus between liner and casing. As men-tioned previously, these packers can be run in conjunction with the liner hanger and set before cementing or can be set after after cementing is complete (see Fig. 26 of last months installment).
However, the authors do not consider the use of liner packers as the best alternative to choose for a well with lost circulation. Run with the liner, they impose a circulating restriction causing higher equivalent circulating densities and surge pressures.1 And should returns be regained there will be an increase in the likelihood that drill cuttings ahead of the cement will bridge in the annulus and squeeze off circulation. A positive pressure test would not be indicative of an isolating cement job in the overlap with a packer.
It is possible that the packer could give way at a later time,1 com-municating zones behind the liner with the uncemented liner top.
This could present serious problems while drilling is underway or later during the production phase of the well.1
For wells in which the mud in the hole can be circulated but cannot be weighted up without losing returns, some operators design cement slurries to precisely control the height of the ce-ment column. The idea is to keep the hydros tatic pressure of the heavier cement below the hydrostatic pressure required to break down the lost circulation zone. This is a difcult task because of the problem of cement channeling on the vast majority of liner jobs. Cement tops, and consequently cement heights, almost invariably end up higher than expected. One way to improve the chances for success with this type procedure is to reduce mud weight by something close to the trip margin being carried with the mud density and mixing spacer cement at the same density as the drilling mud.
Other considerations must be borne in mind if the opera-tor wishes to use a packer run piggyback in conjunction with the liner hanger (see Fig. 28). This enables precise placing of the cement in the overlap during squeezing and means that the well can be controlled downhole should a kick occur while ce-menting. Although the piggyback packer causes some circulation restrictions, and therefore surging, this surging is minimized by packers that have large circulating bypasses, which are left open while the liner is being run. Some precaution should be taken when piggyback packers are used, including:
x Liner should not be reciprocated or rotated.
x Hydraulic set, right-hand release liners should be run and the packer should have a left-hand set mechanism.
x There are tension limits to these packer that will preclude their use on long liners.
x It is recommended that cement or mud ushes be prevented from getting on top of the packer because of the potential of sticking or cementing the packer. This means limited cement volumes and mud spacers, which means lower contact times and lower degrees of cementing success.
x Unlike a liner packer, a piggyback packer can be used to squeeze the top of the liner.
x When the top has been squeezed, the possibility exists that there may be an uncemented interval left between the top of cement from the primary cementing and the bottom of cement from the squeeze on the liner top.
Glenn R. Bowman, Regional Drilling Superintendent, Ashland Exploration, Houston, and Bill Sherer, Operati ons Manager, Liner Tools LC and formerly Alexander Oil Tools, Houston
MANY LINERS are run in environments in which the drilling uid cannot be circulated, or in which the increased hydrostatic pres-sure of the cement column could cause lost circulation. This situ-ation makes primary cementing difcult, but there are some mea -sures that can be taken to enhance the chance success.
Every effort should be made, if practical, to cure the lost circulation problem. If returns are lost while cementing, the liner top will have to be squeezed. If it is a production liner and the lost circulation problem is below the potential producing zone, additional squeezing may be needed to isolate the productive in-tervals. If it is a drilling liner, it could buckle later due to higher temperatures and higher internal mud weights in washouts that were inadequately lled with cement.1,20,21,23
The biggest danger is that circulating surges could aggravate the lost circulation problem to the point that the mud’s hydrostatic pressure is lowered enough to allow the well to kick. If lost circu-lation cannot be cured, then every attempt should be made to at least minimize the problem (i.e., cutting mud weight, spotting LCM (lost circulation material) pills, open hole squeezes, etc.). Having to kill a well while running a liner can pose serious problems.
Due to complications in cementing liners with lost circula-tion problems, it is very important that good intermediate casing points be selected. The fracture gradient at an intermediated cas-ing point may be sufcient to allow safe drillcas-ing, but insufcient to allow cement to be circulated around the liner. Thus a later liner cement job should be kept in mind when picking intermediate casing points.
ALT ERNAT IV ES FOR HANDLING LOST CIRCULAT ION If well conditions mechanically or economically dictate that the lost circulation cannot be cured, the authors consider four alterna-tives. One is to run a piggyback packer above the liner hanger (see Fig. 28) and to cement the liner around the bottom conventionally.
The piggyback packer then is set in intermediate casing and the top of the liner is squeezed. This allows running the liner, cement-ing it and squeezcement-ing the top all in one trip. Another technique is to run the liner, cement conventionally around the bottom and then make a trip to pick up a packer for squeezing the top.
A similar technique (that the authors have not tried to date) is to bradenhead squeeze the liner top after completing the bottom after the liner top after completing the bottom stage, rather than make an extra trip to pick up a squeeze packer. Three disadvan-tages of this method are:
x Squeeze pressure is imposed on the entire intermediate string and if it has been worn by previous drilling, it could rupture below the calculated burst rating.
x Breaking down the intermediate casing shoe for squeezing could momentarily drop the mud level, and consequently, the hydrostatic pressure of the mud column, letting the well come in with no control of the well on bottom. If a gas kick occurs, excessive casing pres-sures could occur while killing the well.