8.
Chapter
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.
This may need to be done more than once. A hesitation squeeze with low-water-loss anti-gas-migration cement should be used to help ensure pumping into all the microchannels.
One more recommended precaution if a hesitation squ eez e is deemed necessary: Use a cement retainer set within 50 to 75 ft of the top of the liner for reasons shown in Fig. 30. This means squeezing with cement in the workstring above the retainer, which some operators are reluctant to do. But the main objective is to avoid getting mud below the squeeze tool, which can allow a mud core to be pumped through the cement. This is less likely to occur inside the workstring above the squeeze tool. The retainer has the disadvantage that it must be drilled out. Nevertheless, ce-ment has to be drilled out in either event, and the retainer allows the workstring to be pulled out of the hole immediately.
The worst scenario would be for the cement to set up pre-maturely in the workstring while squeezing. This would mean having to clean out the cement from inside the workstring, which is not very expensive when compared to the cost of redo-ing a squeeze. The time saved from waitredo-ing on cement with a retrievable packer is about the same time required to drill the retainer. There is also always the danger of cementing a retriev-able squeeze packer in the hole. As discussed earlier, if the anti-gas-migration cement depends on quick thixotropic properties to prevent gas ow and a retrievable squeeze packer is used, the cement should be displaced below the packer before doing a hesitation squeeze. Otherwise the quick-forming gel strengths of the cement could cause it to become unpumpable.
One nal eld practice needs to be mentioned: It is common practice to bleed off squeeze pressure after a certain amount of time to check for backow. If the pressure will not bleed off, pressure is reapplied to the same shut-in pressure, and wait-ing on cement is continued. An effort is made to pump back in precisely the same volume of uid that was bled off. It is felt that this process can also ruin a squeeze job on a liner top. If the cement has not set, bleeding off the workstring presents the potential of allowing mud, cement ltrate or saltwater to ow back into the overlap from the open hole. In the example shown earlier, 1bbl of owback is en ough to displace all of the cement out of the channel from the rst squeeze. Repressuring back up to shut-in pressure may not necessarily displace all the foreign
Casing
fluid back out of the channel. When pressuring back up on the cement, the operator may pump back in 1 bbl less than was bled off, in which case there could still be mud, ce-ment ltrate or saltwater in the channel. Although often de -cried by efciency experts, it is cheap insurance to take extra rig time to wait on cement until it is certain there will be no
owback. The cement must not be “disturbed,” so to speak.
Remember also that the larger the water cushion, and con-sequently the differential pressure, the longer the operator should wait on cement
EVALUAT ING CEMENT JOB BEHIND LINER Once primary liner cementing has been completed and the liner top has been tested and cement has cured, the next step is to determine if the zone of zones of interest have been isolated.
A bond log is normally run to determine this. Proper precautions should be taken to run a bond log. Any pressure decrease inside the liner after the cement has cured allows the casing to contract and can break the cement/casing bond, creating a annu-lus. A cement bond recorded under these conditions of a micro-annulus will not represent the annular cement ll accurately. A micro-annulus cannot be distinguished from a channel with a high degree of certainty.
According to Fitzgerald, McGhee and McGuire,57 unless a cement bond log (CBL) is recorded with the correct uid pres -sure of the interval to be logged, the log has little chance of correctly dening the amount of annu lar cement ll. According to the authors, any increase in pressure applied to the casing, such as pressure testing or squeezing the liner top, can create a micro-annulus. They go on to explain that casing will return to its original conguration after a pressure increase/decrease cycle. Cured cement does not. They recommend that well his-tory be researched to ascertain the maximum pressure exerted on the casing after the annular cement cured, and then run-ning the CBL under that same pressure. For instance, if nal bottomhole squeeze pressure while squeezing the ling top was 2,000 psi over mud hydrostatic pressure, then the CBL should be run under 2,000 psi with the original mud weight. Some log
“scholars” say they can factor out a micro-annulus when ev al-uating a bond log, but this is less reliable. The referenced authors claim 90% accuracy in zone isolation decisions when applying the appropriate pressure to the casing.
Pressuring up to run a CBL can present a problem if bottomhole squeeze pressures are high and the burst rating of the intermedi-ate casing is unknown. There are two solutions to this problem.
The rst and best way is to run the CBL before testing or squeezing the liner top. If this is not palatable to the operator, and the zone of interest is near the bottom of the liner, then consideration could be given to leaving the top oat collar above the zone of interest to isolate it from squeeze of surge pressures during trips. The liner top could then be squeezed and tested and then the oat equip -ment drilled out and the CBL run. Another option would be to set a retrievable bridge plug inside the liner while squeeze work or testing of the liner top is going on.
The authors believe that all CBLs should be run in liners with 500 psi over the maximum hydrostatic pressure that the cement was cured under, if well conditions permit. This should remove any doubt about a micro-annulus and compensate for any surge pres-sures created while tripping in the hole and hydrostatic pressure reduction caused by mud heating and expanding. Two words of caution should be noted if the decision is made not to squeeze the linger top before running the CBL and if the zone of interests be-low the oat or landing collar. First, if the plug is drilled up before squeezing the liner top (to enable running the CBL across the pay zone), there is a possibility that when testing the liner top, the operator could pump through the oat equipment if the cement has not set up, due to contamination, and the plug was not bumped, or if it leaks. This could result in all of the squeeze cement going inside the liner. Second, drilling crews tend to Figure 30 - Packer location is important. In this example, packer
is set too high, allowing cement slurry to be contaminated as it channels through mud to reach perforations or holes (after Shy-rock and Slagle,55graphic after Suman and Ellis5).
relax lling up the hole on trips once cementing operations are completed. They should be reminded that zones behind the liner could still come in through the overlap. As always, the hole llup should be monitored on trips and the hole kept full of mud.
REMEDIAL CEMENT WORK BEHIND LINERS Once the decision has been made that a squeeze is necessary inside the liner, the breakdown pressure should be such that perfo-rations will take uid without fracturing the rock.55As pointed out by Murphy58 though, in almost all instances a fracturing pressure must be reached to get the perforations to take uid. The high-permeability, low-pressure or least mud-lled perforations will take
uid while other, more severely plugged, perforations may never be broken down. This can occur even if low-water-loss cement, and good hesitation squeeze procedures, are applied. According to Rike,58 most squeeze failures can be attributed to subsequent cleanup of previously plugged perforations (see Fig. 31). He goes on to say that mud lter cake has demonstrated it is capable of withstanding pressure differentials up to 5,000 psi, especially in the direction from wellbore to formation. A solids-free uid is nec -essary for squeezing off all the perforation channels, not just some of them. The authors have seen operators attempt to break down squeeze perforations with 4,000 to 5,000-psi surface pressure in heavy muds and then complain that the CBL is unreliable, the pri-mary cement job declared good, and the squeeze called off. They are consequently surprised when the well is tested and produces extraneous gas, oil or water.
The following case history will be used to show how barite and gel can plug perforations or channels when positive pressure (wellbore to formation) is applied. On a well on which Ashland was a partner in Cameron Parish, La., the operator had set 9⅝-in casing at 8,838 ft.
The shoe had a leakoff test of 16.2 ppg. An 8½-in hole was drilled to 12,225 ft. Lost return problems were occurring with 16.3-ppg mud.
Therefore, the decision was made to run a 7⅝-in liner. The liner was run to 12,225 ft. The hole took mud while the liner was being run.
The liner hanger was set with the liner top at 8,665 ft. The liner was cemented with full returns with 360 sacks (540 ft3) of 16.8-ppg low-water-loss cement.
The operator then made a trip for an 8½-in. bit. No cement was found on top of the liner. A 9⅝-in. squeeze packer was run and the liner top was broken down with 400 psi pump pressure and 16.8-ppg, and then squeezed with 250 sacks of 16.4-ppg low-water-loss cement. The nal shut-in squeeze pressure was 280 psi with 16.8-ppg mud. A hesitation squeeze method was utilized.
The rst squeeze job did not hold, and the liner top was resqueezed with 450 sacks of 16.4-ppg low-water-loss cement.
(Note that the liner overlap volume was less than 2½ bbl. The ce-ment volume used was over 120 bbl for the second squeeze.) The hesitation squeeze technique was used again with maximum pump rates of two barrels per minute. The nal shut-in squeeze pressure was 800 psi. Firm cement was drilled to the liner top at 8,665 ft.
The operator then made a prudent decision to test the liner top with a squeeze packer to enable both a positive and negative dif-ferential test with a 16.7-ppg mud. The liner top was tested to an equivalent mud weight (EMW) of 19 ppg, and it held. (Remember, the leakoff test on the 9⅝-in casing shoe held an EMW of 16.2ppg.) The drill pipe was displaced with water for a negative test to an EMW of 14.7 ppg. The packer was set and an attempt was made to bleed off the drill pipe pressure. The well began to ow. The well was shutin and drill pipe pressure built up to 300 psi. The liner top was resqueezed a third time with 76 bbl of cement.
The preceding case history shows how a solids-laden mud can plug a channel of perforations with positive pressure differen-tials. It also goes without saying that negative differential pres-sure tests should always be done on liner tops, especially when solids-laden muds are used.
If the operator has to work with heavy mud weights, and does not want to change to a brine system to squeeze, consideration should be given to spotting a heavy brine or viscous polymer (to stop barite settling between the solids-laden mud and spotting agent interface) across the interval to be squeezed in the fol-lowing manner:58
xLower retrievable packer to the bottom of existing of pro-posed perforations. Spot a solids-free uid or acid (acid density can be increased to approximately 12 ppg).
xPull packer back up to the packer seat and set.
xPump into formation and ow back a coup le of times to allow mud to be back-ushed if casing is already perforated.
Use a 90° phased perforating gun, since a channel may only be on one side of the casing and the chances of perforating into such a channel with a single-phase gun are minimal5(see Fig. 32). Ideally, the solids-free uid should be spotted before perforating and then the perforations shot under balanced through tubing. (This would preclude using a cement retainer because of its restrictive ID.) Oth-erwise, if the liner is perforated with a casing gun, the hydrostatic of the mud will necessarily be overbalanced. With a solids-free u -id, the perforations could break down at reservoir or slightly higher pressure and create a well-control problem as the uid level drops below reservoir pressure due to momentum. Or the perforations could “drink” the solids-free uid until mud gets to the perfora -tions and plugs them with wall cake. In this event, the operator has gained nothing for his trouble.
If the operator insists on working with mud, then the only vi-able option is the “high-pressure” squeeze operation. The rst requirement is to break down the perforations. As pointed out by Rike,59 the volume of cement required is a function of the width and depth of the fracture generated. It can be kept low by easing up to the breakdown pressure. To help ensure break down of all perforations, the authors recommend running acid or chemical washes ahead of the cement. Once cement arrives at the perforations, a high squeeze pressure is essential to Mud
or Debris
Figure 31 - When perforating with mud in the hole, the more severely plugged perforations may never be broken down. They have demostrated the ability to withstand differential pressures from the wellbore to formation of up to 5,000 psi.59 Squeeze failures can probably be attributed to subsequent cleanup of previously plugged perforations (after Rike59).
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.
getting a successful squeeze job in a single stage. Beach, O ’ B r i e n a n d G o i n s p o i n t o u t t h a t o n l y b y f o l l o w i n g the process of hesitation can enough pressure be built to force cement into mud-plugged holes.60 As discussed earlier, squeezing with heavy muds may mean that the final bottomhole squeeze pressure may need to be 5,000 psi higher than the bottomhole breakdown pressure.
Casing
90° Phased Gun
Mud Channel Cement
Entrance Hole
Entrance Hole
Entrance Hole
8.4
Final bottomhole squeeze pressures should be as high as possible. Conversely, if the perforations had been clean, a squeeze could most probably be attained with a bottomhole squeeze pressure above the pump in pressure of 500 to 1,000 psi with no bleedoff or flowback for 10 to 15 minutes.58Again, in the authors’ opinion, the cement should still be in the wor k-string while squeezing to avoid pumping a mud core through the cement during a high-pressure hesitation squeeze.
Also, according to Murphy, the job should be designed so that the hydrostatic head of cement slurry at any time during the job will not exceed wellhead equipment or maximum casing pressure limitations. This is a minimum pressure limitation since some pressure will be required to start the slurry mov-ing dependmov-ing on the delay and gel strength of the slurry.58 This is another good reason to go with a partial water cushion.
It lowers the reversing pressure required if reversing out is deemed necessary.
One final recommendation: If squeeze packers are used, only those that have concentric bypasses through the tool that ensure that reversing is accomplished around the bottom of the tool should be used. This helps guard against leaving ce-ment around a squeeze packer that may have gotten there during squeezing.
Figure 32 - Chances of shooting into a channel are much im-proved when using a 90º phased gun to perforate (after Suman and Ellis5).
LIT ERAT URE CIT ED FOR CHAPT ER 8:
LIT ERAT URE CIT ED FOR CHAPT ER 8:
For the references cited in this chapter, please refer to the back page, (all references for the entire document).
cement started filling the annulus. Rotation was increased to 40 rpm until the end of the job. Cement was pumped a 3 bpm to minimize the equivalent circulating density.
No cement was circulated on top of the liner because hole volume was underestimated, probably due to pressured shale sections washing out while circulating. The liner top had to be squeezed. Three zones were tested below 13,800 ft with no squeez-ing required. The bond log showed 95 to 100% bondsqueez-ing across test zones an estimated displacement efciency to top of cement was 87%.
Case 2 :
Production Liner, Cameron Parish, Louisiana.
Ashland Exploration drilled Sweetlake Land and Oil Co, No. 4 to a TD of 12,500 ft; 9 5/8-in. casing was set at 8,900 ft. An 8 ½-in. hole was drilled to TD with 17.0-ppg mud and frequent lost returns. Even with 17.0-ppg mud, mud showed a gradual chloride increase and high background and connection gas.
A 4,007-ft 5 ½-in., LT&C liner was run with one slim-hole centralizer per joint. Centralizers were allowed to float to facilitate reciprocation or rotation. The liner was run successfully to bottom. Mud was conditioned two complete rounds. Mud weight was not reduced because of gas and a slow high pressure saltwater sand feed-in. The liner was reciprocated while conditioning.
The liner was cemented with 30 bbl of 17.0-ppg spacer followed by 630 sacks of anti-gas-migration cement mixed at 17.5 ppg. The liner was rotated at 50 rpm after the cement be-gan lling the annulus. Cement was pumped at a high rate of 6 bpm because of the large annulus.
Since the zone of interest was a gas sand, no effort was made to get cement on top of the liner in the event the anti-gas-mi-gration cement did not work. This would facilitate a liner top squeeze with anti-gas-migration cement, if needed. There was no annular gas ow, and the liner top was squeezed with 30 bbl of water followed by 300 sacks of low-water-loss cement pumped in place below the squeeze packer at 8 bpm. Cement was displaced to 8,393 ft, or 100 ft above liner top.
Breakdown pressure before squeezing the overlap was only 50 psi with 17.0 ppg mud. Final SI squeeze pressure was 1,300 psi as a 2.500 partial water cushion was utilized to assure that ce-ment would stay in p lace when pumping stopped. The liner top was successfully tested both positively to an EMW of 19.0 ppg and negatively to an EMW of 9.0 ppg. The bond log conrmed a satisfactory job. Estimated displacement efciency to the t op of
Breakdown pressure before squeezing the overlap was only 50 psi with 17.0 ppg mud. Final SI squeeze pressure was 1,300 psi as a 2.500 partial water cushion was utilized to assure that ce-ment would stay in p lace when pumping stopped. The liner top was successfully tested both positively to an EMW of 19.0 ppg and negatively to an EMW of 9.0 ppg. The bond log conrmed a satisfactory job. Estimated displacement efciency to the t op of