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8/10/2019 Cement Stinger Balanced Plug
1/13
IADC/SPE 168005
Don't Get Stung Setting Balanced Cement Plugs: A Look at CurrentIndustry Practices for Placing Cement Plugs in a Wellbore Using a Stingeror Tail PipeJustin Roye, Schlumberger, and Sam Pickett, Chesapeake
Copyright 2014, IADC/SPE Drilling Conference and Exhibition
This paper was prepared for presentation at the 2014 IADC/SPE Drilling Conference and Exhibition held in Fort Worth, Texas, USA, 46 March 2014.
This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have notbeen reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarilyreflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of anypart of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is
restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright.
AbstractCement plugs have been used for decades within the oil and gas industry. Some of the applications include zonal isolation,curing lost circulation, abandonment, and serving as a base for kicking-off or sidetracking. The most common method used
for the placement of cement plugs is the balanced plug method using drillpipe, tubing, or a combination of both. The pipe is
run in the wellbore to the desired depth of the bottom of the plug. A calculated volume of cement is placed in the well.
Usually a volume of spacer is pumped ahead and behind the cement. When the plug is in place, the height of the cement and
spacer left inside the pipe is the same as the height of the cement and spacer placed outside the pipe. With equalized columnheights and fluid densities inside and outside the drillpipe, the hydrostatic pressure is balanced.
Tubing with a smaller diameter than the drillpipe is commonly run on the bottom of the drillpipe for setting a balanced
plug; this smaller diameter tubing is commonly known as the stinger. Using a stinger lowers the height of the cement plug
with the pipe in place, prior to pulling out of hole (POOH). The stinger also provides a larger annular cross-sectional areaduring cement placement. Some operators use a stinger with the assumption that it will minimize the disturbance of the plug
while POOH, decreasing the chance of cement contamination.
If a stinger is used, the assumption that all fluids both inside and outside the drillpipe will remain in equilibrium is false.
A mathematical analysis of what occurs once dynamic conditions begin by POOH with a small diameter stinger shows thatthe initially balanced system quickly becomes unbalanced. This analysis of placement technique can be valuable for any
situation in which a balanced plug would normally be used for plug placement.
Perhaps the most critical component of most cement plugs, especially kickoff and sidetrack plugs, is compressive strength
(CS) development. A cement kickoff plug with a final strength greater than the adjacent formation provides better support tosidetrack in the neighboring formation. Surfactant-laden spacers and drilling mud contamination have a drastic effect on
cement CS development. The contamination of the cement plug with these fluids can result in failed strength development,
which can result in failure to kick off the plug. The end result is lost time and money for the operator.
IntroductionThe balanced plug method of calculating plug placement volumes has long been a standard industry practice for setting
plugs in the wellbore. Volumes are calculated in such a way that all fluids both inside and outside of the pipe are at the same
height, thus resulting in a hydrostatically balanced system.
The basic assumption behind the balanced plug calculation method is that the fluid is going to remain in place while thedrillpipe is simply pulled through the fluids with minimal falling of the fluid level to fill the void left behind by the metal
displacement of the drillpipe. This assumption is correct, neglecting the frictional drag forces on the fluid, when the drillpipe
outer diameter (OD) and inner diameter (ID) are the same from top to bottom. However, when the drillpipe includes a stingerat the bottom, there is a disruption in the hydrostatic equilibrium between the column of fluid inside and outside the drillpipe
resulting in flow at the bottom of the stinger between the two regions.
As soon as this dynamic situation is imposed on the fluids in the wellbore, the fluids down hole begin to experience a
continual shifting in hydrostatic conditions. When a stinger is used at the bottom of a larger diameter drillpipe, the difference
in volumetric capacities per annular length can be substantial. The difference in the volumetric capacities inside the pipe per
8/10/2019 Cement Stinger Balanced Plug
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2 IADC/SPE 168005-MS
length can also be substantial. As a given length of larger diameter drillpipe is pulled out at surface, all the fluid that was
contained within that drillpipe, and the fluid in the annulus that was surrounding it, will attempt to stay in place. As noted
earlier there will be some drop in the fluid level due to the removal of the volume of steel in the drillpipe. However, a muchlonger length or column height of fluid per unit volume is displaced within the smaller diameter stinger due to its smaller
capacity. After pulling out several hundred lineal feet of drillpipe at the surface, a substantial difference in lineal footage of
fluid has passed through the stinger. If these fluid column height changes are not taken into account in the placement
calculations, as they are not in the balanced plug method, the result will be a plug that has had other displacement fluids
dumped into the middle of the cement as the drillpipe is POOH.
Post-Job Placement of the Balanced Plug CalculationA Look at Dynamic Conditions When Using aStingerIn this section, we discuss key changes in fluid movement after placement of the balanced plug. Graphic representations of
fluid movements are shown in Appendix A (Figs. 1A8A).
In this example of dynamic conditions when using a stinger, we assume a very simple open system (i.e., fluid levels can
never rise above the surface at 0 ft) in a vertical wellbore with the parameters shown in Table 1and volumetric capacities
shown in Table 2.
TABLE 1WELL PARAMETERSTD/TVD: 8,000 ft (vertical well)Openhole size: 8 -in. (from surface to 8,000 ft)Bottom of plug: 8,000 ft
Plug length: 500 ft (0% excess)Top of plug: 7,500 ftTubulars: 7,000 ft of 5-in. 19.5-lbm drillpipe
1,000 ft of 2 7/8-in. 6.4-lbm stingerFluid in hole: 12.5 ppg mudSpacer: 14.0 ppg weighted spacer = 30 bbl total volumeCement slurry: 17.5 ppg plug slurry = 37.19 bbl total volume
TABLE 2CAPACITIES
SECTIONBBL / FTCAPACITY
5-in. 19.5-lbm drillpipe (4.276-in. ID) 0.01776 bbl/ft2.875-in. 6.4-lbm stinger (2.441-in. ID) 0.00579 bbl/ft5-in. x 8.75-in. openhole annulus 0.05009 bbl/ft2.875-in. x 8.75-in. openhole annulus 0.06635 bbl/ft5-in. x 4.276-in. drillpipe 0.00652 bbl/ft
2.875-in. x 2.441-in. stinger 0.00224 bbl/ft8.75-in. open hole 0.07438 bbl/ft
Note that this scenario places all of the spacer and cement in the stinger by openhole annulus (Fig. 1A). Having fluids ofdifferent densities above the drillpipe/stinger interface would only further complicate the balancing of the system while
POOH. The assumption is made that fluid within the drillpipe has only two possible places to godown and out the bottom
or spilled out on the rig floor at surface.The balanced plug method (no underdisplacement) would yield the following conditions (Fig. 1):
Top of cement with drillpipe in place: 7,484.46 ft
Top of spacer with drillpipe in place: 7,068.57 ft
The capacities within the system are shown in Table 3.
TABLE 3INITIAL SYSTEM CAPACITIESVolumeInside7000 ft of 5-in. drillpipe 124.33 bbl1000 ft of 2.875-in. stinger 5.79 bbl
Outside7000 ft of 5-in. x8.75-in. annulus 350.63 bbl1000 ft of 2.875-in. x8.75-in. annulus 66.35 bbl
Work Steel7000 ft of 5-in. x4.276-in. drillpipe 45.67 bbl1000 ft of 2.875-in. x 2.441-in. stinger 2.24 bbl
The individual fluid volumes within the system are as shown in Table 4.
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IADC/SPE 168005-MS 3
TABLE 4INITIAL FLUID VOLUMES
VolumeMud7000 ft of 5-in. drillpipe 124.33 bbl68.57 ft of 2.875-in. stinger 0.40 bbl
Total mud inside 124.73 bbl
7000 ft of 5-in. x8.75-in. annulus 350.63 bbl
68.57 ft of 2.875-in. x8.75-in. annulus 4.55 bblTotal mud outside 355.18 bbl
Spacer415.89 ft of 2.875-in. stinger 2.41 bbl415.89 ft of 2.875-in. x 8.75-in. annulus 27.59 bbl
Cement515.54 ft of 2.875-in. stinger 2.98 bbl515.54 ft of 2.875-in. x 8.75-in. annulus 34.21 bbl
Next, we look at the well conditions after pulling out 100 ft. Using the common industry misconception, it will be
assumed that all fluids will remain effectively in place, while the drillpipe and stinger simply pull through the fluids. Theonly change made to the volumes within the system will be the loss of 100 ft of 5-in. 4.276-in. steel that was pulled out of
the well. This results in a loss of 0.65 bbl of volume (100 ft 0.00652 bbl/ft). In a balanced system, the level of fluid
remains the same inside and outside of the drillpipe. The volume of steel removed from the wellbore would cause the fluidlevel to drop 9.61 ft below the surface, both inside and outside the drillpipe.
Working from the inside of the drillpipe, top to bottom and referencing the fluid volumes of the original placementconditions above, the shift toward hydrostatic imbalance is shown mathematically in the calculations shown below of the new
fluid volumes within the system after POOH 100 ft.
For the mud, the 124.73 bbl of mud inside the system is the same as the initial volume (Table 4). The fluid level hasfallen down 9.61 ft due to the removal of the drillpipe. By starting at the top and working down through the tubulars, we can
mathematically calculate where the fluid interfaces have transitioned to after the POOH 100 ft. Starting at 9.61 ft and
working down, the base of mud/top of spacer can be found.
Length of 5-in. drillpipe filled with mud: 6,900 ft 9.61 ft = 6,890.39 ft
Volume of 6890.39 ft of 5-in. drillpipe: 6,890.39 ft 0.01776 bbl/ft = 122.37 bblThe remaining volume must push down into the 2.875-in. stinger:
Remaining volume: 124.73 bbl 122.37 bbl = 2.36 bbl
Length inside 2.875-in. stinger: 2.36 bbl / 0.00579 bbl/ft = 407.60 ftThe base of mud/top of spacer has moved from initially being 69 ft below the drillpipe/stinger interface, to now being
407.60 ft below the drillpipe/stinger interface, at 7,307.60 ft.The volume and length of spacer inside the drillpipe remains unchanged, with 2.41 bbl continuing to occupy 415.89 ft of
2.875-in. stinger. However, since the mud/spacer interface has pushed farther down the drillpipe, the spacer/cement interface
has also pushed further down. The new spacer/cement interface is 415.89 ft below the mud/spacer interface at 7,307.60 ft:
7307.60 ft + 415.89 ft = 7,723.49 ft.This leaves the bottom 176.51 ft of stinger that is filled with cement, with the volume of cement being 176.51 ft
0.00579 bbl/ft = 1.02 bbl.
With all fluid volumes and levels inside the pipe accounted for, the lengths of fluids outside the pipe can now be
determined, starting from the bottom of the stinger and working back up to surface.The volume of cement in the system is 37.19 bbl, of which 1.02 bbl was determined to still be inside the 2.875-in. stinger.
The remaining 36.17 bbl of volume will occupy the 100 ft of 8.75-in. open hole that is now free of any type of tubulars, and
the rest will fill the 2.875-in. 8.75-in. annulus: Volume of 100 ft of 8.75-in. open hole: 100 ft 0.07438 bbl/ft = 7.44 bbl
Volume in 2.875-in. 8.75-in. annulus: 36.17 bbl 7.44 bbl = 28.73 bbl
Length of 28.73 bbl: 28.73 bbl / 0.06635 bbl/ft = 433.01 ft
Top of cement in annulus: 7900 ft 433.01 ft = 7466.99 ftThe volume and length of spacer outside the drillpipe remains unchanged, with 27.59 bbl continuing to occupy 415.89 ft
of 2.875-in. 8.75-in. annular length. However, since the cement/spacer interface has pushed up the annulus because of the
fluids that have exited the drillpipe and stinger, the spacer/mud interface has also pushed up. The new spacer/mud interfaceis 415.89 ft above the cement/spacer interface at 7469.56 ft, and the top of the spacer in the annulus is 7051.10 ft (7466.99 ft415.89 ft = 7051.10 ft).
The remaining annulus from 7051.10 ft to 9.61 ft from surface will be filled with mud. Table 5summarizes the new fluidlevels:
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4 IADC/SPE 168005-MS
By simply comparing the heights of each fluid in Table 5, it becomes very clear that the system is not balanced. A quick
calculation of the hydrostatics yields:
Inside: [(7297.99 ft 12.5ppg) + (415.89ft 14.0ppg) + (176.51 ft 17.5ppg)] 0.052 = 5207 psi Outside: [(7041.49 ft 12.5ppg) + (415.89 ft 14.0ppg) + (433.01 ft 17.5ppg)] 0.052 = 5274 psi
The system is now 67 psi underbalanced inside the drillpipe. To balance, the fluids in the annulus must fall, pushing
heavier cement back into the stinger, spacer farther up the stinger, and mud up and out of the drillpipe until equilibrium isreached. For balance to be achieved, the fluid in the annulus would have to fall to ~ 29 ft below surface. Table 6
summarizes the fluid levels that would result in hydrostatic equilibrium (Fig. 2A).
TABLE 6HYDROSTATIC BALANCE HEIGHT OF FLUIDS AFTER POOH 100 FT
FLUID Top of fluidinside Top of fluidoutside
Mud 0 ft 29 ft
Spacer 7138.69 ft 7065.94 ft
Cement 7554.58 ft 7481.83 ft
Hydrostatic calculations are now:
Inside: [(7138.69 ft 12.5 ppg) + (415.89 ft 14.0 ppg) + (345.42 ft 17.5 ppg)] 0.052 = 5257 psi Outside: [(7036.94 ft 12.5 ppg) + (415.89 ft 14.0 ppg) + (418.17 ft 17.5 ppg)] 0.052 = 5257 psi
Balanced PlugYou Do the Math. Or NotNote that the above calculations only look at a single iteration after POOH 100 ft. Whereas in this example, only a single
iteration snapshot is viewed, in reality the fluids will be in a constant state of flux while attempts are made to continuallymaintain hydrostatic equilibrium as the drillpipe is removed from the wellbore. These calculations show how quickly such a
drastic change is imposed on the system and how the drillpipe is not simply pulling straight through the fluids, leaving them
undisturbed. By continuing on with these same analytical assumptions farther up the hole, the system will soon reach a pointat which all cement has exited the inside of the stinger while several hundred annular feet of cement remains outside of the
stinger (Fig. 4A). At this point, spacer will begin to exit the stinger and dump into the middle of the cement plug. Once all
of the spacer has exited, mud will begin to dump into the middle of the cement plug (Fig. 6A). Both fluids contribute to the
contamination of the top portion of the pluga detrimental effect when a solid cement base is needed for kicking off of or
sidetracking into the surrounding formation. In this example, 50% of the cement plug volume was contaminated.Simulations of other common cement plug scenarios using a stinger indicate that the top 40% to 50% of plugs can be
contaminated using the balanced plug method with a stinger.
To more accurately assess the conditions of the wellbore while POOH, more iterations need to be calculated. The
accuracy of the analysis will increase as the number of iterations calculated approaches infinity. Any attempt to calculatethese by hand becomes increasingly time consuming and tedious as the POOH process progresses. As mentioned previously,
after continuing to POOH, all of the cement will eventually have exited the stinger, adding a level of complexity to the
calculations. At some points, a severe change in underbalance inside of the drillpipe can occur, resulting in the flowback of
fluid through the stinger and out the top of the drillpipe, spilling onto the rig floor. Hand calculating these conditions willlikely not be practical, especially from the perspective of the field supervisor and company representative reviewing numbers
prior to starting a cement job. Therefore, the use of computer software designed to calculate multiple iterations and predict
fluid activity while POOH is an excellent option to avoid tedious or complicated hand calculations. As with all simulations,
care should be taken to input as much detailed and accurate data as is possible, since a simulation is only as good as the data
given. When used properly, the aid of such software can provide a much more in-depth look at the dynamic well conditionswhile POOH.
Using such software, a pictorial simulation of this particular well scenario can be found in the figures in Appendix A that
show conditions after POOH approximately every 100 ft or at points of special interest (such as when fluid interfaces beginto exit the stinger or when a simulated U-tubing occurs in the system). These snapshots of the simulation carry on with the
calculations outlined above. The images help to show the activity that is going on down hole between the time the pump
shuts down and the time the stinger is completely pulled out of the plug. They also point to the fact that calculating a simple
balanced plug is anything but simple when a stinger is used.
Alternatives and OptionsAs the industry has grown and developed, new tools and applications have been developed to aid the operator in setting
successful cement plugs. One such tool is the computer-aided simulation software alluded to previously. Such software canhelp tailor a custom solution to given well parameters, especially where a stinger is used. By allowing the computer to do the
TABLE 5FLUID LEVELS AFTER POOH 100 FT
Fluid Top of fluidinside Top of fluidoutsideMud 9.61 ft 9.61 ftSpacer 7307.60 ft 7051.10 ftCement 7723.49 ft 7466.99 ft
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IADC/SPE 168005-MS 5
cumbersome calculations, the spacer volumes ahead and behind the cement plug and the amount of necessary under
displacement can be optimized so that the mud, spacer, and cement interfaces are balanced after POOH instead of before.
Eliminating the stinger altogether and using a single size of drillpipe from top to bottom should be another option toconsider. The balanced plug method would then be applicable for calculating fluid placement, which simplifies calculations.
This method eliminates the continual fluid movement that occurs while using a stinger, which should lead to a more stable
plug while extracting the drillpipe from the cement. These advantages would need to be weighed against the increased
column height of the cement with the pipe in place and any potential issues caused by smaller annular clearances.
There are also mechanical devices available that can be placed in the drillpipe just above the stinger. These devices allowthe cement plug to be balanced using the basic balanced plug calculations. In addition, an indicator sub can be used to give a
pressure indication that the plug has been spotted on depth. After spotting the plug, the stinger is released from the drillpipe
before POOH. This eliminates the instability associated with extracting the stinger from the cement plug. In this case, thestinger is abandoned in the well. If it is necessary to drill out the plug, then the stinger would need to be made out of drillable
material.
Conclusions
Many factors will influence what placement calculations should be used on a given plug job (hole sizes, drillpipesize and length, tubing stinger size and length, length of plug, densities and volumes of the fluids in the hole, etc.).Since each job has different parameters, a cookie-cutter solution is not always possible. However, by incorporating a
few new best practices, operators should be able to better their chances at placing successful cement plugs more
consistently.
When using a small-diameter stinger on the end of drillpipe:o The balanced plug calculation method for spotting the cement plug will result in contamination of the top
section of the plug while extracting the stinger. The contamination can be up to 40% to 50% of the cement
volume. In addition, there is a much higher likelihood of fluid U-tubing out of the drillpipe, resulting in
spills on the rig floor.
o The calculation method to avoid contaminating the top part of the cement plug and avoid spills on the rigfloor is complicated and requires the use of a computer application. This type of computer application iscurrently available to the industry and allows the use of a stinger without sacrificing plug quality.
The balanced plug calculation method can be used in cases where a stinger is not used or in cases where a device isrun above the stinger to separate it from the drillpipe before POOH.
A careful look at each wells situation and a comparison of the different options now available to the industry willdetermine what placement technique is the best choice. By working together to educate colleagues and field
personnel, hopefully a new way of how weve always done it can begin to take shape.
AcknowledgementsThe authors would like to thank the management of Chesapeake Energy and Schlumberger for their permission to publish
this paper. We would also like to thank the many people who invested their time and energy into reviewing the content of the
text.
Appendix A
Figs. 1A8Aprovide a pictorial simulation of the fluid movements as the drillpipe is pulled out of the wellbore. The figures
show conditions after POOH approximately every 100 ft or at points of special interest (such as when fluid interfaces begin
to exit the stinger or when a simulated U-tubing occurs in the system). Tables 1A8Asummarize the fluid levels for each
point.
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6
F
T
F
Fig. 1A sho
op of Wellbore
ig. 1AInitiall
Table 1A s
ABLE 1AFL
luid Topud 0 ftpacer 7069ement 7484
Hydrostatic
In
O
ws the initiall
balanced syst
ows fluid lev
ID LEVELS AF
of fluidinside
ftft
calculations a
ide: [(7069 ft
tside: [(7069
balanced sys
em immediatel
ls for the initi
ER PLUG PLA
Top of0 ft7069 ft7484 ft
re as follows:
12.5 ppg) +
t 12.5 ppg)
em after place
Bottom of Well
after placeme
lly balanced s
CEMENT
fluidoutside
(416 ft 14.0
(416 ft 14.
ment.
bore
t.
ystem immedi
ppg) + (516 f
0 ppg) + (516
ately after plu
17.5 ppg)]
ft 17.5 ppg)]
g placement.
0.052 = 5
0.052 = 5
IADC/SPE
67 psi
67 psi
168005-MS
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I
F
T
F
DC/SPE 1680
Fig. 2A sho
op of Wellbore
ig. 2APOOH
able 2A sho
ABLE 2AFL
luid Topud 0 ftpacer 7145
ement 7561
ydrostatic cal
In
O
5-MS
ws the fluids i
to 7900 ft.
s fluid levels
ID LEVELS AF
of fluidinside
ft
ft
culations are a
ide: [(7145 ft
tside: [(7037
n the wellbore
fter POOH to
ER POOH TO
Top of28 ft7065 ft
7481 ft
s follows:
12.5 ppg) +
ft 12.5 ppg)
after POOH t
Bottom of Well
7900 ft.
900 FT
fluidoutside
(416 ft 14.0
+ (416 ft 14
7900 ft.
bore
ppg) + (339 f
.0 ppg) + (419
17.5 ppg)]
ft 17.5 ppg)
0.052 = 5
] 0.052 = 5
56 psi
58 psi
7
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8
F
T
F
Fig. 3A sho
op of Wellbore
ig. 3APOOH
Table 3A s
ABLE 3AFL
luid Topud 0 ftpacer 7207ement 7623
ydrostatic cal
In
O
ws the system
to 7800 ft.
ows the fluid
ID LEVELS AF
of fluidinside
ftft
culations are a
ide: [(7207 ft
tside: [(7006
after POOH t
levels after P
ER POOH to 7
Top of57 ft7063 ft7479 ft
s follows:
12.5 ppg) +
t 12.5 ppg)
7800 ft.
Bottom of Well
OH to 7800 f
800 FT
fluidoutside
(416 ft 14.0
(416 ft 14.
bore
.
ppg) + (177 f
0 ppg) + (321
17.5 ppg)]
ft 17.5 ppg)]
0.052 = 5
0.052 = 5
IADC/SPE
48 psi
49 psi
168005-MS
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I
F
T
F
DC/SPE 1680
Fig. 4A sho
op of Wellbore
ig. 4APOOH
Table 4A s
ABLE 4AFL
luid Topud 0 ftpacer 7291ement N/A
Hydrostatic
In
O
5-MS
ws fluid level
to 7700 ft; spac
ows the fluid
ID LEVELS AF
of fluidinside
ft
calculations a
ide: [(7291 ft
tside: [(6972
after POOH t
er begins to ex
levels after P
ER POOH to 7
Top of87 ft7059 ft7475 ft
re as follows:
12.5 ppg) +
t 12.5 ppg)
o 7700 ft. The
Bottom of Well
it the stinger at
OH to 7900 f
700 FT
fluidoutside
(409 ft 14.0
(416 ft 14.
space begins
bore
~7750 ft.
.
ppg) + (0 ft
0 ppg) + (225
o ext the stin
17.5 ppg)] 0
ft 17.5 ppg)]
er at approxi
.052 = 5
0.052 = 5
ately 7750 ft.
37 psi
39 psi
9
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1
F
T
F
0
Fig. 5A sho
op of Wellbore
ig. 5APOOH
Table 1A s
ABLE 5AFL
luid Topud 0 ftpacer 7491ement N/A
Hydrostatic
In
O
ws fluid level
to 7600 ft.
ows fluid lev
ID LEVELS AF
of fluidinside
ft
calculations a
ide: [(7491 ft
tside: [(6947
after POOH t
ls after POO
ER POOH TO
Top of98 ft7045 ft7461 ft
re as follows:
12.5 ppg) +
t 12.5 ppg)
o 7600 ft.
Bottom of Well
to 7600 ft.
600 FT
fluidoutside
(109 ft 14.0
(416 ft 14.
bore
ppg) + (0 ft
0 ppg) + (139
17.5 ppg)] 0
ft 17.5 ppg)]
.052 = 4
0.052 = 4
IADC/SPE
49 psi
45 psi
168005-MS
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11/13
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1
F
T
F
2
Fig. 7A sho
op of Wellbore
ig. 7APOOH
Table 3A s
ABLE 7AFL
luid Top
ud 28 ftpacer N/Aement N/A
Hydrostatic
IN
O
ws fluid level
to 7500 ft.
ows fluid lev
ID LEVELS AF
of fluidinside
calculations a
SIDE: [(7472
TSIDE: [(69
after POOH t
ls after POO
ER POOH TO
Top of
103 ft7024 ft7440 ft
re as follows:
ft 12.5 ppg)
1 ft 12.5 pp
o 7500 ft.
Bottom of Well
to 7500 ft.
500 FT
fluidoutside
+ (0 ft 14.0
g) + (416 ft
bore
ppg) + (0 ft
14.0 ppg) + (ft
17.5 ppg)] 0
17.5 ppg)]
.052 = 4
0.052 = 4
IADC/SPE
57 psi
56 psi
168005-MS
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I
c
T
F
F
DC/SPE 1680
ig. 8A showsolumn.
op of Wellbore
Table 4A s
ABLE 8AFL
luid Top
ud 55 ftpacer N/Aement N/A
ydrostatic cal
In
O
ig. 8APOOH
5-MS
fluid levels af
ows the fluid
ID LEVELS AF
of fluidinside
culations are a
ide: [(7360 ft
tside: [(6900
to 7415 ft; stin
er POOH to 7
levels after P
ER POOH TO
Top of
104 ft7004 ftN/A
s follows:
12.5 ppg) +
t 12.5 ppg)
er has pulled o
415 ft. At app
Bottom of Well
OH to 7415 f
415 FT
fluidoutside
(0 ft 14.0 pp
(411 ft 14.
ut of annular c
roximately 74
bore
.
g) + (0 ft 17
0 ppg) + (60 ft
ment column
21 ft, the sting
.5 ppg)] 0.0
17.5 ppg)]
t ~7421 ft
er has pulled
2 = 4
0.052 = 4
ut of the ann
84 psi
84 psi
13
lar cement