Part
6
How to Run and Cement Liners
S pe c ia l c em e nt s a re a va il a b le t o pr e v en t
annular gas flow, but if a leak still occurs, there are other methods for controlling the problem.
Glenn R. Bowman , Regional Drilling Superintendent, Ashland Exploration, Houston, and Bill Sherer , Operations Manager, Liner Tools LC and formerly Alexander Oil Tools, Houston SINCE THE AUTHORS admittedly have limited experience with fighting annular gas flow problems, this article will deal mainly with design considerations extracted from current literature on the subject. It seems rather obvious obvious to assume assume that to achieve both anti-gas migration success and zonal isolation that the appropriate special cement has to be used and effective mud displacement has to be achieved .51 Again, this comes back to the necessity of good cementing practices talked about in earlier installments.
Receptacle
LEAK PREVENTION METHODS
Liner Packer
If a production liner is to be run, and the pay zone near the bottom is known to have annular gas ow potential, then considconsideration could be given to cementing around the bottom of the liner while rotating or reciprocating. The liner top could then be squeezed with an anti-gas migration cement if gas shows up in the mud when circulating circulating bottoms up. If there is no gas feeding in, then the top could be squeezed with regular low water loss cement. (Gas migration could be determined by monitoring gas in the mud with a gas detector while waiting on cement. As discussed in an earlier article, the drill pipe should not be pulled out of the hole for six to eight hours after the primary job in the event that gas gets through the cement and the well kicks.)
Gas trapped under packer
Liner hanger
The above technique may not be a good idea on a drilling liner with gas pay behind it. If accurate prediction of the cement top can be made (i.e., liner was cemented while achieving all known good cementing criteria discussed earlier), then it could be tried. There are two risks involved in doing a drilling liner this way. First, if the special cement does not work properly (due to channeling, etc.) and cement is accidentally accidentally circulated circulated on top of the the liner, the liner overlap may end up containing honeycombed cement that leaks gas and cannot be squeezed off. If the volume of gas is too high, the liner top may have to be isolated with a liner tie-back packer or a tie-back string before proceeding. Secondly, if the cement volume estimated is too low (or returns are lost) and the top of the cement ends up lower than expected, the result could be a large uncemented interval that could buckle and create wear spots after the liner tope is squeezed and drilling proceeds.1,21,23.
High-pressure gas
Another way to attempt control of annular gas ow is to run a packer on the top of the liner to seal the annulus between liner and casing,1 (Fig. 26). These packers can be run in conjunction with the liner hanger and can be set before cementing or after cementing is complete. Any gas present is therefore trapped below the packer if the overlap has no cement. These type packers are set by weight and held down by internal and external slips. This would be a viable method of lost circulation is not a concern (the packer is a circulating restriction that causes higher equivalent circulating densities and surge pressures) and the operator was certain that he could achieve a good cement job in the liner overlap. Otherwise, a serious problem could develop during completion of the well or later in the life of the well if the packer failed. Also the main sealing element could be damaged by mud and cutting circulating past the packer. packer.1 These type packers Reprinted from World Oil magazine May 1988 with permission from the authors. ,
Figure 26 - Liner packers can be run in conjunction with the liner hanger and set before cementing cementing or after cementing. A polished bore receptacle may be run above the packer to provide tie-back capabilitie s. (Courtes (Courtesy y of Texas Iron Works.)
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Caution should be used with certain anti-gas migration cements. If the proprietary slurry relies on a cement that develops 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 ran from 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 pulling the liner running tool through the cement if is on top of the liner because of low clearance between the liner running tool an intermediate casing.
are not recommended on drilling liners for these reasons. Another alternative when running a liner through known highpressure 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.
Back-up ring
If the liner top is squeezed with thixotropic cement, then cement 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.
Sealing elements g n i s a C
Cement in annulus
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.
Back-up ring
Figure 27 - Seal ring device consists of two opposing deformable 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-annulus communication. (Courtesy Gemoco.)
MECHANICAL TECHNIQUES 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 t hrough 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 option 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.
Lastly, concerning prevention of gas leaks in the liner top, two more techniques will be discussed. Stewart and Schouten51 report that gas migration, resulting from casing contraction, is a common problem. They recommend that mechanical seal ring devices be used to prevent this even though casing contraction is not expected 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,5 thermal expansion of the casing while cement sets and subsequent 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.
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 provides no latitude for varying thickening times.
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 cannot 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 atte mpt 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 liner 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. Reprinted from World Oil magazine May 1988 with permission from the authors. ,
Packers can be run in conjunction with the tie-back string or scab liner. Circulating restrictions through the packer are not
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Intermediate Casing Piggyback packer (set position) Drill String
Piggyback packer (unset)
Piggyback packer (unset) Liner setting tool
Top of Cement Liner top
Liner top
Drillable packoff
Liner
1
Cement
2
3
4
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.)
Reprinted from World Oil magazine May 1988 with permission from the authors. ,
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3
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 clean of 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 th at 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 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 pos sible in this “closed” system to ensure no channeling.
West, E.R. and Lindsey, H.E. “How to run and cement liners in ultra-deep wells.” World Oil. June 1966. 5
Suman, G.O., and Ellis, R.C. “Cementing Handbook.” World Oil. 1977. 6
Lindsey, H.E. “How deep Anadarko wells are designed and equipped.” World Oil. February 1, 1979. 21
Durham, Kenneth S. “How to prevent deep well liner failure,” Parts 1 & 2. World Oil. October and November 1987. 23
Goins, W.C., “Better understanding prevents tubular buckling problems.” World Oil. February 1980. 51
Stewart, R. B., and Schouten, F. C., “Gas invasion and migration in cemented annulus: Causes and cures” IADC/SPE 14779. Dallas, Texas. February 1986
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.
ACKNOWLEDGEMENT The authors thank their respective managements for permission and encouragement to publish this article and for their progressive management philosophy that encourages maximized engineering efforts on all eld operations. The authors also thank drilling foreman Leon Pate and Ray Guidry, and Tim Alexander Jr. for sharing their expertise and Judy BenSreti for typing the manuscript.
Liner Tools LC Specializing in Liner Primary Cementing
The authors would also like to state that they have read so much literature and talked to so many people concerning the subject matter that they realize that the manuscript does not completely constitute original thinking. Any credit not given to previous authors where credit is due is regretted and unintentional.
Showcase: The Mechanical Rotating Liner Hanger Optimal for medium to long length liners with severe down-hole conditions requiring high burst and collapse.
AUTHORS Glenn R. Bowman is the regional drilling superintendent for Ashland Exploration’s Houston Region. He graduated from Marietta College with a BS degree in petroleum engineering and has held various drilling engineering positions before joining Ashland in 1984. He was most recently drilling manag er for Wainoco Oil and Gas in Houston. Mr. Bowman is a member of SPE and has authored several other papers for World Oil on liners and bottomhole drilling semblies.
Applications: Used to run, cement, and rotate a liner at high RPM. Can be drilled into the hole. Optimum for all wells including deviated and S curved wells.
Bill Sherer is the operations manager for Liner Tools LC in Houston, and worked for Alexander Oil Tools from 1984-2001 concentrating on the B&W liner hanger line. Mr. Sherer worked for B&W from 1965 to 1979 and later as a consultant for running liners from 1979 until 1984. Mr. Sherer specializes in optimization techniques for cementing liners and has personally supervised the running of over 300 liners.
Features: Recessed, tongue and groove slips are protected. Unique design allows rotation and reciprocation while cementing. High burst and collapse provided by a casing barrel. Resists hostile down-hole environments with optimum material selection. Controlled and evenly timed slips load t he casing uniformly, eliminating casing failures due to point loading. Optimum slip angle maximizes the hanging capacity of the liner hanger. Simple to operate, requiring multiple right hand rotations to set the hanger.
ADDITIONAL INFORMATION For more information regarding high rpm liner rotation, centralization, and primary cementation please visit our web-site at the bottom of this page.
LITERATURE CITED 1
Lindsey, H.E. and Bateman, S.J. “Improve cementing of drilling liners in deep wells.” World Oil. October 1973.
Reprinted from World Oil magazine May 1988 with permission from the authors. ,
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