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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

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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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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