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SPE 60725

Bridge-Plug Millout With Coiled Tubing—Case HistoriesDaniel A. Durey and Dennis L. Degner, SPE, Halliburton Energy Services, Inc.

Copyright 2000, Society of Petroleum Engineers, Inc.

This paper was prepared for presentation at the 2000 SPE/ICoTA Coiled Tubing Roundtable held inHouston, Texas, April 5-6.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, as presented,have not been reviewed by the Society of Petroleum Engineers and are subject to correction by theauthor(s). The material, as presented, does not necessarily reflect any position of the Society ofPetroleum Engineers, its officers, or members . Papers presented at SPE meetings are subject topublication review by Editorial Committees of the Society of Petroleum Engineers. Permission tocopy is restricted to an abstract of not more than 300 words. Il lustrations may not be copied. Theabstract should contain conspicuous acknowledgment of where and by whom the paper is presented.Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A, fax 01-972-952-9435.

References at the end of the paper.

AbstractDownhole plugs are now commonly used for isolating multistagestimulation jobs. These plugs allow for more timely completion,yet they must also be removed in a timely fashion. This paper discusses how coiled tubing (CT) can efficiently mill out these

plugs.The three case histories in this paper demonstrate the suc-

cessful use of coiled tubing to mill out bridge plugs set inmultistage stimulation jobs. Specifically, each case history pro-vides a brief history of the well, a description of the equipmentused to meet downhole and surface needs, and the operating

procedure used for the job. The paper concludes with proceduresto improve CT millout efficiency.

IntroductionAs oil companies search for ways to lower costs, the completionsarea has become a prime target for change. CT services havehelped reduce costs by eliminating the need for workover rigs incertain applications. When coiled tubing units (CTU’s), are used,operators can arrive on location, rig up the CTU, perform theservice, and be off location more quickly and economically thanthey can when they use a workover rig. Bridge-plug milling isdefinitely an application where a CTU can save revenue.

Milling plugs can be a cost-effective operation if the proper planning occurs before the job. When planning a milling opera-tion, operators must consider equipment and treatment options(type of CTU, workstring, bottomhole tool assembly, and millingfluid) on the basis of plug information, bottomhole pressures,

bottomhole static temperatures (BHST’s), hydraulic fracturinginformation, and other data. When an operator reviews andadheres to the best practices for all parameters, a successfulmilling operation is possible.

Well HistoryBefore performing a CT milling operation, operators must under-stand the well’s history. In addition to knowing informationregarding well tubulars, depth, location, and other data, operatorsshould consider other key factors. For example, if the well has

been stimulated, it may be energized as a result. If the well has been produced for a long period, it may be depleted. If fluid has beeninjected into the well for a prolonged period, deposits may have

built up in the well.Another key factor is the well’s bottomhole pressure (BHP).

By knowing the BHP, operators can determine the proper equip-ment and the proper fluid for transporting cuttings to the surface.If the BHP is low enough that the formation cannot support acolumn of fluid, nitrogen must be added to the milling fluid to helpincrease annular velocity and transport cuttings to the surface.

Another important factor is “fish,” or debris left in the wellfrom previous operations. For example, ball sealers used on anacid ball-out or tools lost from wireline operations can greatlyincrease the milling time and often increase the chance of theassembly becoming stuck in the hole.

Equipment Considerations

CT/Pumping Equipment. When performing a millout, operatorsmust review equipment selection. Selecting the appropriate CTU,CT string size and length, as well as the needed pumpingequipment will aid in milling efficiency ( Fig. 1 , Page 5). If a high-

pressure well environment is present, special equipment such asadditional flow crosses and external blowout preventers (BOP’s)may be needed.

Surface Equipment. Proper surface equipment is also importantfor any millout. Before the job, the operator and the customer mustunderstand which types of surface equipment each party should

provide. The surface equipment should include a flowback



2 SPE 60725BRIDGE-PLUG MILLOUT WITH COILED TUBING—CASE HISTORIES

manifold with multiple chokes, flowback iron to a pit/tank, and anoptional cuttings catcher. The cuttings catcher acts as an opera-tional aid and a safety device; specifically, it removes cuttingsfrom flowback before they reach the chokes, and also limits theamount of exposure time to open chokes.

Bottomhole Assembly. The bottomhole assembly (BHA) used onthe three wells consisted of a tubing connector, backpressurevalve, hydraulic disconnect, mud/air motor and mill/bit.

In the case histories discussed, all three wells had composite plugs. Therefore, mud motors were used with bladed mills(Fig. 2 , Page 6). Air motors can be used in conjunction with rock

bits to prevent cone damage resulting from the higher rates produced by mud motors. Air motors are also preferred for situations where pure nitrogen will be pumped. (Some mudmotors’ internal components can be sensitive to cryogenicfluids.) A recommended practice of having a 92 to 95% drift inner diameter (ID) for the bit size will help improve the rate of penetra-tion (ROP) and fluid movement around the mill, resulting in

improved cuttings removal during milling operations.

Cuttings RemovalWhen performing any type of milling job, operators must alwaysconsider cuttings removal. The effectiveness of cuttings removalfrom a well is directly affected by the type of fluid used, theannular velocity maintained, and the type of material milled. Inmost cases, gelled fluid with annular velocities greater than 100ft/min will adequately remove cuttings from a wellbore; however,when this velocity cannot be achieved, a foamed fluid withnitrogen will help increase the annular velocity and the ability of the fluid to transport cuttings. For horizontal wells, the annular velocity required can be orders of magnitude greater than thevelocity required for vertical wells. The size of cuttings can vary,depending on the plug material and size and type of mill used (Fig. 3 , Page 6).

Case HistoriesThe case-history wells were treated with multiple stimulation

jobs, and composite bridge plugs were used for zonal isolation inthe Cotton Valley Sand and Hosston formations. Each well wasdrilled with a completion and millout period of approximately amonth. The plugs were set in the wells, and were exposed to

pumping, flowback, and shut-in conditions. Each job was per-formed with a flowback manifold, a cuttings catcher for safelymonitoring well returns, and similar bottomhole tool assemblies.All three wells are in different fields, but demonstrate similar depths and responses.

Case History 1. The first well, treated in August 1998, has 4.5-in. (11.6-lb/ft) casing with a drift ID of 3.875 in. ( Fig. 4 , Page 6). Thiswell in Cotton Valley Sand has a BHP of approximately 5,000 psi,with perforations from 8,508 to 8,760 ft. The top plug is set at 8,900ft. Below the top plug are perforations from 9,260 to 9,262 ft, withthe bottom plug set at 9,366 ft. A set of perforations is below the

bottom plug from 9,608 to 9,781 ft, with plugback total depth(PBTD) at 9,835 ft. Each plug was set, and 10 ft of cement was

placed on top of each. Job Procedure. Operators rigged up the 1 ¾-in., 60K CTU,

the pumping equipment, and the flowback surface equipment.The bottomhole assembly (BHA) consisted of a 2 7/8-in. tubing

connector, a backpressure valve, a hydraulic disconnect, a mudmotor, and a 3 5/8-in., five-bladed mill. Location water with frictionreducer was used as a milling fluid for the scheduled job.

The BOPs were pressure-tested, and the tubing was run inthe hole at 75 to 100 ft/min, while fluid was circulated through thetubing at 0.25 bbl/min. The first plug/cement was tagged, and theslurry rate was increased to 2.0 bbl/min (159-ft/min annular velocity). The average weight on bit (WOB) was 2,000 lb. After 20 minutes, the top plug was milled out and the tubing was runto the bottom obstruction. The bottom plug/cement was taggedand milled out after 15 minutes, at a slurry rate of 2.0 bbl/min witha 2,000-lb WOB. The tubing was then used to wash down toPBTD, and a wellbore volume was circulated. After a wellbore

displacement was pumped, operators pulled the tubing out of thehole while continuing to circulate the well.

Case History 2. The second well was treated similarly to the first,with multiple stimulation jobs in August 1998. This well in CottonValley Sand has about a 4,800-psi BHP, and perforations from9,030 to 9,200 ft, with the top plug set at 9,240 ft. Below the top plugare perforations from 9,250 to 9,530 ft, with the bottom plug set at9,630 ft. A set of perforations is below the bottom plug at 9,651to 10,430 ft, with PBTD at 10,520 ft. Each plug was set, and 10 in.of cement was placed on top of each. The well has 4.5-in. (11.6-lb/ft) casing, with a drift ID of 3.875 in. ( Fig. 5 , Page 7).

Job Procedure . Operators rigged up the 1 ¾-in. 60K CTU, the pumping equipment, and the flowback surface equipment. TheBHA consisted of a 2 7/8-in. tubing connector, a backpressurevalve, a hydraulic disconnect, a mud motor, and a 3 5/8-in., five-

bladed mill. Location water with friction reducer was used as amilling fluid for the scheduled job.

The BOPs were pressure-tested, and the tubing was run inthe hole at 75 to 100 ft/min, while fluid was circulated through thetubing at 0.25 bbl/min. The first plug/cement was tagged, and theslurry rate was increased to 2.0 bbl/min (159-ft/min annular velocity). The average WOB was 2,000 lb. After 18 minutes, thetop plug was milled out and the tubing was run to the bottomobstruction. The bottom plug/cement was tagged and milled outafter 22 minutes, at a slurry rate of 2.0 bbl/min with a 2,000-lb WOB.The tubing was then used to wash down to PBTD, and a wellborevolume was circulated. After a wellbore displacement was

pumped, operators pulled the tubing out of the hole whilecontinuing to circulate the well.

Case History 3. The third well was treated with multiple stimu-lation jobs in August 1999. This well has about a 4,000 psi BHP,which is lower than the previous two cases. The well in theHosston formation has perforations from 6,408 to 6,782 ft, with the



SPE 60725 3D.A. DUREY, D.L. DEGNER

top plug set at 6,830 ft. Below the top plug are perforations from7,160 to 7,362 ft, with the bottom plug set at 7,385 ft. A set of

perforations is below the bottom plug at 7,406 to 7,747 ft, withPBTD at 7,800 ft. Each plug was set; however, this well did nothave 10 ft of cement on top of each plug like the previous twowells. The well has 5.5-in. (17.0 lb/ft) casing, with a drift ID of 4.767

in. ( Fig. 6 , Page 7). Job Procedure. Operators rigged up the 1 ¾-in. 60K CTU, the pumping equipment, and the flowback surface equipment. TheBHA consisted of a 2 7/8-in. tubing connector, backpressurevalve, hydraulic disconnect, mud motor, and a 4 ½-in., five-bladedmill. Location water with friction reducer was used as a millingfluid for the scheduled job.

The BOPs were pressure-tested, and the tubing was run inthe hole at 75 to 100 ft/min, while fluid was circulated through thetubing at 0.25 bbl/min. The first plug/cement was tagged, and theslurry rate was increased to 2.0 bbl/min (99-ft/min annular veloc-ity). The average WOB was 2,000 lb. After 25 minutes, the top plugwas milled out and the tubing was run to the bottom obstruction.

The bottom plug/cement was tagged and milled out after 20minutes, at a slurry rate of 2.0 bbl/min with a 2,000-lb WOB. Thetubing was then used to wash down to PBTD, and a wellborevolume was circulated with a reduced fluid rate of 1 bbl/min whilenitrogen was started at 300 to 500 scf/min. Nitrogen was used inthis case because the BHP was somewhat lower than the others.It also helped increase the annular velocity for improved cuttingsremoval. After a wellbore displacement was pumped, operators

pulled the tubing out of the hole while continuing to circulate thewell ( Fig. 7 , Page 8).

ConclusionsUsing downhole plugs for isolating multistage stimulation jobsis becoming a common industry practice. The discussed casehistories describe the procedures followed to demonstrate aquick removal of these plugs. Though each environment wasdifferent, the milling efficiency was very good, allowing the plugsto be milled up at an average of 20 minutes each ( Table 1 , Page 4).Through proper planning, the milling efficiency of a CT milloutoperation can be greatly increased. The following guidelines canimprove this efficiency:• Select the proper surface equipment, such as a flowback

manifold and a cuttings catcher, to allow continuous milling.• Select a mill that is within 92 to 95% of the tubular drift

diameter. This will ensure that a good rate of penetration is

obtained and that the plug is adequately removed.• Select the proper downhole tools for the job, such as the

tubing connector, backpressure valve, hydraulic discon-nect, and mud or air motor. A circulating sub can be usedwhen higher rates are needed for circulating, or when nitro-gen circulation is not recommended through some of thetools that make up the BHA.

• Select a fluid that reduces friction in addition to transportingcuttings.

• When nitrogen is used in a milling fluid, it may be difficult toidentify motor stalling, resulting in reduced milling effi-ciency.

• Select the CT equipment that will maximize the slurry rate toobtain the annular velocity required.

• Make multiple weight checks while milling to ensure that thetools and/or the tubing are not becoming stuck.

• When preparing for any milling operation, ensure that accu-rate, current information about the CT string’s fatigue life isavailable.

• Log and review all of the well particulars such as depth, BHP,BHST, and previous operations performed on the well. Thisinformation will help operators plan the milling procedureand anticipate possible problems.

These guidelines will not always prevent milling ineffi-ciency; however, proper planning and the items discussed willgreatly increase the chances for efficient milling.

Although the case histories in this paper all involved composite plugs, some cases have been reviewed in which cast-iron bridge plugs were successfully removed with CT milling. In mostcases, if one plug is in the hole, a milling time of 40 minutes toseveral hours could result. In cases where multiple cast-iron

plugs have been set, the milling operation can take days. This can be attributed to the material being milled and the behavior of the plug when it is partially milled out. In most cases, if multiple cast-iron plugs must be milled, a hydraulic workover rig can performthe milling operation more quickly than a CTU.

References1. Sorgard, E. et al .: “Coiled Tubing Milling and Temporary Plug and

Abandonment Operations,” paper SPE 54472 presented at the1999 SPE/ICoTA, Houston, May 25-26.

2. Brown, A.D.F., Merrett, S.J., and Putman, T.S.: “Coiled-TubingMilling/Underreaming of Barium Sulphate Scale and Scale Controlin the Forties Field,” paper SPE 23106 presented at the 1991Offshore Europe Conference, Aberdeen, Scotland, Sept. 3-6.




Well Plug DescriptionPlug Size

(in.)Time to Mill

(min)Cement Above Plug

(ft)

Avg. SlurryRate

(bbl/min)

N2 Rate(scf/min)

No. 1 top plug 4.5 20 10 2 0bottom plug 4.5 15 10 2 0



Table 1—Milling Summary Table




Fig. 1—Coiled tubing rigup similar to the ones used in the three case histories outlined in this paper.




Fig. 2—Example of drill bit used in drilling wells in the CottonValley Sand and Hosston formations.

Fig. 3—Cuttings removed from wellbore vary, depending on theplug material and type of mill used.

Fig. 4—Well 1 schematic.




Fig. 7—Well 3, drilled Aug. 21, 1999. It had two composite plugs, at 6,830 and 7,385 ft, and used 5.5-in. (17-lb/ft) casing.

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