Cementing a Long Horizontal Wellbore Using CT Squeeze Technology

8/17/2019 Cementing a Long Horizontal Wellbore Using CT Squeeze Technology

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Copyright 2005, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 2005 SPE/ICoTA Coiled Tubing Conferenceand Exhibition held in The Woodlands, Texas, U.S.A., 12 – 13 April 2005.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in a proposal submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper

for commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to a proposal of not more than 300words; illustrations may not be copied. The proposal must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractCoiled Tubing (CT) cementing has been widely used and

highly successful for remedial squeeze and plug back

operations for over 20 year’s1,2,3. However, the vast majority

of these wells were at deviations less than 90 degrees.

A long horizontal well in the Alpine field on the North

Slope of Alaska was drilled early in the development phase

and was out of pattern (Fig. 1). The well required a plug back

and sidetracking to maintain desired off-take strategy (Fig. 2).

The well was drilled to a total depth of 11,984 feet and

completed with approximately 2,050 feet of 4-1/2” slottedliner inside the 2,210’ of 6-1/8” hole. Near the middle of the

horizontal section, the well’s deviation climbed to a maximum

of 96 degrees.

Cementing operations have long been recognized as a

problem in horizontal wells. However, a search of the SPE

online library identified only 5 papers that mentioned the

challenge we faced while a search of “horizontal” yielded

5,534 hits. Although the 5 papers did discuss the problem and

gave some general guidance to cement design consideration,

there was little specific information on the “best practice”

approach to Plug and Abandon (P&A) long horizontal

wellbores.

Based on the successful CT squeeze program in Alaska, a

team of engineers and field supervisors decided to use CT

cement squeeze technology to seal the lateral portion of the

wellbore and leave a cement base for subsequent sidetracking

operations. This paper will discuss the details of this job

including:

1. Job Planning2. Cement design and testing3. Tools and Equipment4. Wellbore geometry and Placement details5. Onsite Job Execution details6. Results7. Lessons learned

Field OverviewThe operator, ConocoPhillips Alaska Inc., and partners in

1994 discovered the Alpine field. The Alpine field is located

in the Colville River Delta a few miles south of the Arctic

Ocean and approximately 70 miles west of the Trans Alaska

Pipeline. The facilities are connected to the North Slope road

system via ice road for approximately three months of the

year. Aircraft provide the only mode of transportation at othe

times. Produced crude is transported to the Trans Alaska

Pipeline via the East-West running Alpine and Kuparuk

common carrier pipelines.

The reservoir was under-saturated at discovery with a gas

oil ratio of about 850 SCF/Bbl. The produced oil gravity

currently averages 39° API. As a result of the depositiona

environment and minor fault offset, excellent vertica

permeability is observed and the productive sands are pressure

connected across large distances. A “water alternating

miscible gas” flood is being conducted in the Alpine reservoir

The field is developed with line drive patterns, utilizing

horizontal producers and injectors in a one to one ratio (Fig

2).

Given the high mechanical strength of the clean fine-

grained Alpine sandstones, the operator elected to leave thehorizontal sections on the wellbore uncased, to minimize the

chance of formation damage. A 7.0” intermediate casing shoe

is set just below the top of the producing formations at high

angle. The uncased horizontal production hole typically

extends 3000-4000 feet beyond the intermediate casing shoe

Production and injection tubing is primarily 4.5” although

some lower rate wells are completed with 3.5” tubing. A

production or injection packer is located a few hundred

measured feet above the casing shoe. A typical Alpine wel

completion is shown in Figure 3.

While performing above expectations, this completion

practice has proven to be a difficult environment to access

Early attempts at logging these wells using CT memory toolsand conductor line tractors provided less than ideal results in

reaching the TD in the extended horizontal open-hole sections

Drilling and formation debris and abrasive formations in

combination with wellbore geometry limited our ability to

reach the full measured depth of the lateral sections. Portions

of open-hole lateral sections with fill or debris is not the only

potential challenge to successfully cementing these wells

recent caliper logs suggest that the wells may also have

sections that are washed-out or significantly out of gauge.

Although the final field development plan called for long

open-hole lateral wellbores with injection and producing wells

in a line drive configuration, there were a few early

SPE 94039

Cementing a Long Horizontal Wellbore Using CT Squeeze TechnologyW. Rauchenstein and C.G. Blount, SPE, ConocoPhillips Alaska Inc.


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2 SPE 94039

development wells drilled that did not fit the final offtake line-

drive strategy. The subject of this paper is the P&A of Well B

in preparation for a sidetrack to put the well in pattern.

Wellbore Completion and Geometry DetailsWell B was drilled early in the development of the Alpine

development. This well did not conform to the final line drive

production strategy for Alpine field. A P&A proposal wasconsidered to allow sidetracking of Well B to put this well in

conformance with the rest of the Alpine development (Fig. 4).

The original completion of Well B included:

• 16” Conductor set at 109’ TVD/MD and cemented tosurface

• 9-5/8” 40# L-80 Surface Casing set to 3,326’MD/3120’ TVD and cemented to surface

• 7” 26# L-80 Production Casing set to 9,775’MD/7,200’ TVD

• 6-1/8” Open Hole from 9,775’ MD to 11,984’ MDLined with a 4-1/2” 12.6# L-80 Production Slotted

Liner from 9,590 to 11, 643’ MD/+-7,133’ TVD, no

cement.• 4-1/2” 12.6# L-80 Production Tubing from surface to

8,777’ MD/7,031’ TVD with SSSV nipple, side-

pocket GLM’s, landing nipples, production packer,

and tailpipe with entry guide.

The schematic of the subject Well B is shown in Figure 5.

The geometry getting down to the horizontal completion is

shown in Figure 6.

Pre-Job PlanningPreparations for this program started with a meeting to

compare options to P&A the well in preparation for a

sidetrack to normalize the well to field pattern. P&A options

included:

1. Full-bore cementing the entire wellbore2. Cementing through a retainer in the top of the liner3. Setting a mechanical whipstock at the desired

sidetrack location and down-squeezing cement

4. Performing a CT placed liner-top cement down-squeeze

5. Performing a bottom up cement squeeze using the CTsqueeze procedure commonly performed in more

conventional wells in Alaska.

During the meeting, the participants determined that one

important goal of the job was to ensure that the original

wellbore was not left as an underground conduit for injected

or produced fluids that could affect sweep pattern efficiency.

A literature search to help offer additional guidance provedof little use providing only 5 papers generally addressing

horizontal cementing operations. The majority of these papers

discussed the cement properties for horizontal wells and

primary cement job considerations; none specifically

addressing the operational challenges of this horizontal P&A

squeeze job.

Review of various other jobs performed in Alaska yielded

some useful data points including a high angle CT squeeze on

a 21,100’ well, and some work on performing a “chemical

packer” job in another horizontal well4. This “chemical

packer” refers to a thixotropic cement system designed to form

discrete plugs of cement when pumped into horizontal

wellbores.

The more conventional approach of laying the cement

from the deepest measured depth attainable in the wellbore

was chosen for this well. The most compelling reason for this

approach was due to the need to do the best job possible in

hydraulically isolating the original wellbore to help assure

conformance with the injection and offtake pattern strategyThe chance of leaving a 2,200’ high permeability channel was

not tenable in this particular circumstance. One comforting

aspect of using a more conventional approach was the sheer

number of CT squeeze jobs performed on the North Slope

numbering well over 1,000 operations over the last 20 years.

The plan involved:

1. Running the cement nozzle to 11,570’ CTMD(staying in the slotted liner that was 341’ MD from

the end of the openhole section, and above the pack

off bushing near the bottom of the liner)

2. Liquid packing the wellbore, bottoms up3. Laying in the cement while pulling up hole at abou

a 1-1 volumetric ratio following spotting of 15 Bbls

of cement near TD

4. Pulling up hole to a depth where the deviation wasless than 45 degrees so the cement top area would be

more manageable

5. Hesitate squeezing by pumping fluid above thecement top to help displace any wellbore fluid

pockets in the horizontal section back into the

formation and filling the voids with cement

6. Running in hole and washing excess cement abovethe desired sidetrack depth

7. Pulling out of the hole washing all nipples and jewelry

This bottoms-up approach brought with it numerous

challenges. Reaching TD was not certain based on previousopen-hole experience in other Alpine wells. However, CT

forces modeling suggested that since the well was lined, we

should be able to reach the shoe of the liner at 11,643’ (341

shallow of the open hole TD) using a tubing straightener 5 on

the 1.75” OD tapered CT string.

Another concern was the possibility of becoming stuck

while spotting the dense cement. Numerous open hole and

even conventional cement squeeze jobs have proven how

effective the viscous and dense cement can be in moving

wellbore debris and occasionally bridging and sticking the CT

Early field operations by Arco and BP in cementing other

high-angle wells experienced problems in the heel area where

the low viscous fluids mixed with the cement and droppeddebris that had been carried up in the cement. To furthe

exacerbate the concern, historical trends have shown tha

formation spalling and cuttings are not uncommon in Alpine

wellbores6. The fact that this wellbore contained a slotted

liner (1/4” slots) helped alleviate some of these concerns.

In addition to determining the type of P&A, the nature of

the isolated Alpine field and the time of year –no ice road at

the time- precluded bringing in additional equipmen

commonly used in Prudhoe Bay and Kuparuk CT squeeze

operations. Alpine does not have a year-round road

connection to the well-established oilfield infrastructure

available to other North Slope fields. The only time large


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SPE 94039 3

equipment can be brought-in is during the three winter months

when the ice roads are available. Any large items that cannot

be transported by medium sized DC-6 or “Herc” aircraft,

including CT and cementing equipment, must be staged in the

field during the ice season.

The only equipment available to mix and pump the cement

was an Arctic Drilling Rig –located at the extreme distal end

of the pad from the well to be P&A’d- some 600’ away (Fig7). The available onsite equipment options did not include a

conventional batch mixer, commonly preferred to help ensure

cement quality for CT cementing jobs in Alaska.

Cement DesignA slow setting, low fluid-loss latex blend cement system was

chosen given the wellbore geometry and condition, required

placement and squeeze techniques, and necessity of attaining

the best hydraulic seal possible. The class G cement was

designed to 15.8 ppg in fresh water with .4% BWOC TIC

dispersant D065, .2% BWOC mid temperature retarder D800,

.2 gal/sk antifoam D047, and 2.0 gal/sk liquid latex D600G.

The Pv was measured at 32.2 cP at 81 deg F and 68.2 cP at

140 deg F. The Ty was 4.2 lbf/100ft2 at 81 deg F and 7.0 at

140 deg F. The Fann 35 rehology numbers of the cement

system are shown in Table 1.

The thickening time of the cement system was increased

from the traditional 3-8 hours to 8-10 hours at static bottom

hole temperature of 160° F (beginning with 80° F mix

temperature raised to 160° F BHCT in 44 minutes) to allow

trouble time should problems develop when laying in the

cement through approximately 4,500’ of the wellbore

including the horizontal section. The chance of rubble and

debris sticking the CT was still of concern while pumping the

cement job.

A low fluid loss cement blend was selected to minimize

the chance of prematurely bridging off localized areas thatmay take more fluid. The squeeze design called for an API

fluid loss of approximately 15 mL in 30 minutes (blend tested

at 14 mL). Since there was no plan to washout excess cement

through the liner and considering the fact that the liner was

slotted and uncemented, the normal requirement of developing

adequate node height was not a concern.

The cement’s API free water tested as close to 0% as

measurable.

The high latex content provided for the best possible

cement bond, helped lower the fluid loss, and provided for a

robust and resilient kick-off plug7.

All needed cement additives were flown in from the

service company base. The cement additives were mixed intothe mix-water and stored in a Vac truck the night before the

job to allow ample time for hydration.

Tools, Equipment, and ProcedureThe CT unit for this job was an Arctic Mast CT Unit with

15,210’ of tapered 1-3/4” coiled tubing. A pipe straighter was

previously installed on the CT unit to extend the attainable

reach into the extensive horizontal sections of Alpine

completions. Other equipment for the job included 3 Fluid

supply tanks, 4 returns tanks including a 200 Bbl trip tank, 1

HP cementing pump unit on the nearby drilling rig, 1 HP

pump on the CT unit, a re-circulating cement mixer, 640’ of

2” 1502 hard line, a HP dual choke manifold, a HP cementing

manifold, and 1 HP downstream tank manifold.

The simple Bottom Hole Assembly (BHA) for Well B

consisted of a 1 ¾” cold roll connector for 1 ¾” by .109” wall

coiled tubing, 1 ¾” dual check valves, 5’ of 1 ¾” extension

pipe, along with a 1 ¾” combination cement/jet-swirl nozzle

(Fig. 8). The BHA size was selected to be slick to the CT

diameter to minimize the chance of debris stacking on a BHAshoulder and sticking the CT. The combination cement/je

swirl nozzle has been used extensively for CT squeeze work

on the slope. The ball coverts the nozzle from a large bore

low differential pressure cement nozzle to a high differentia

pressure, up-down nozzle shown to effectively wash solids

and produce a turbulent vortex of fluid above the nozzle to

help “sweep” solids up-hole (Figs. 9 and 10).

The cement slurry was mixed “on-the-fly” using the

drilling rig’s re-circulating cement mixer. The drilling rig’s

cement pump was used to pump the spacers and cement to the

CT unit’s high-pressure surface manifold. The CT unit also

had a pump tied into the surface manifold and was used to

displace the cement and tail spacer from the CT and for al

subsequent pumping operations.

General Procedure and Job DocumentationWith the limited resources available, it was necessary to begin

the job setup several days in advance. As common with the

beginning of all new programs, the first several hours were

set-aside for Sim Ops and safety meetings.

Following pre-job meetings, two 380 Bbl seawater, and

one 380 Bbl diesel upright supply tanks were spotted inside a

secondary containment system -which holds a minimum o

110% of the capacity of the largest tank. Inspection of the

tank farm, and approval by the on site supervisor completed

filling the seawater uprights commenced by tapping into the

seawater injection header available on the drill site. An onsite tanker then loaded the diesel upright tank with preheated

diesel (80º F) for freeze-protect fluid.

While the fluid transfers continued in the background, the

CT crew, 3 roustabouts, and two cementers commenced

hammering up the 640’ of 2” 1502 hardline.

The returns tank farm downstream of the dual choke

manifold consisted of three 400 Bbl open tops, one 400 Bb

tiger tank, and one 200 Bbl gauge or “Trip tank”.

Once the basic equipment was in place, the coiled tubing

unit was spotted in front of the well and rigged up. After

raising the derrick, the BOP’s were flanged up to the

wellhead. The injector head and lubricator was then hoisted

and the BHA was installed. The BHA consisted of a simple 1¾” cold roll, 1 ¾” dual check valves, 5’ of 1 ¾” spacer pipe

and a 1 ¾” combination cement/jet swirl nozzle (Fig. 8).

Following nipple-up completion, all employees

participated in a safety and environmental walk thru of the

location. All well control equipment and hardlines were

pressure tested after the walk thru was completed.

Radios were the primary communication tool due to the

extensive distance between the cementing equipment, the

choke manifold, the tank farms and the CT unit. All radio

contact was performed with complete voice communication

rather than abbreviated acknowledgement such as “radio

clicking” for acknowledgement.


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The cement pumps were brought on line at minimum rate

to fill all hardline and coiled tubing while taking returns to the

returns tank farm through the choke manifold. Once fluid was

observed through all flow paths and at all return tanks, the

pumps were shut down and individual components were

pressure tested following standard operating procedures.

After successful pressure testing, current wellhead valve

conditions and all relevant pressures were recorded along withthe number of turns to open the swab valve.

Preparations for mixing the cement slurry began as the

coiled tubing operator ran in hole with the pipe straightener

on. All cement additives were previously premixed into the

mix water in a Vac truck and allowed to hydrate for about 12

hours to achieve desired properties in the continuously mixed

cement slurry.

Weight checks were performed every 2.500’ Coiled

Tubing Measured Depth (CTMD), while running in hole. The

pipe straightener was turned off during weight checks to

minimize coil life reduction.

Due to the fact that this particular wellbore had an open

guide shoe with a 2” pack-off bushing seal bore and 341’ of

open 6 1/8” hole, the onsite CPAI supervisor chose to not exit

the liner, and planned on down-squeezing cement to the toe.

A depth correlation flag was painted on the coiled tubing

11,570’ CTMD. Once on depth, the bottom up loading

procedure was started to displace any gas and other wellbore

fluids from the well. A wellbore liquid packed with known

fluids would provide a means to monitor the bottom-hole

pressure by using the CT by production tubing annulus

pressure. The bottoms-up load job was selected due to the

long horizontal section and concerns of effectively displacing

the gas with the more common bullhead loading of

conventional vertical cement jobs. The CT nozzle was moved

up and down across the liner noting any weight anomalies,

while the hole was loaded. Choke backpressure wasmaintained on the wellhead to assure slight overbalance to the

formation and prevent any gas or oil influx. The cement

supervisor began weighting up the blend toward the end of the

loading process.

Once a full wellbore plus 10% was circulated, cement

pumping operations were initiated through the long hardline

section, a Micro Motion meter and into the coiled tubing. Five

barrels of fresh water spacer was pumped in front of the

cement to minimize cement seawater mixing. The barrel

counter was zeroed when the CT Micro Motion meter density

indicated 11.5 PPG cement @ 68° F just before the full weight

of 15.7 ppg cement. All subsequent pump volumes were

based on this zero.The CT unit’s Micro Motion meter indicated the cement

was a constant 15.7 ppg. The cement mixer’s density

indicator showed the cement to be closer to 16 ppg. Samples

were weighed which showed the density running within this

range. The onsite supervisor elected to keep pumping at that

blend ratio rather than try adjustment, which may have caused

density fluctuations in the pumped slurry.

Pump rates averaged 1.1-1.3 BPM at 1,545 psi coiled

tubing pressure while holding 367 psi backpressure at the

choke system when cement pumping began. All returns were

taken into gauge tanks with 10 Bbl markers for tracking total

volumes returned. The coiled tubing pressure climbed to

3,568 psi at 1.3 Bbls/Min while filling the coil volume of 34

Bbls. The pump rate was lowered to 1 BPM @ 2,328 ps

coiled tubing pressure as the cement exited the nozzle and

began to fill the liner from 11,527’ CTMD. From barrel count

34 to 43, the well head pressure was slowly increased to assist

in pushing the cement out the bottom of the liner through the

2” seal bore located at approximately 11,630’ and into the

openhole toe. At barrel count 44, the wellhead pressure wasslowly lowered back to 500 psi. Pump rate was maintained

between 1 and 1.3 as constant as possible so minor changes in

pressure could be seen that may have indicated potentia

problems. At 50 Bbls pumped, the nozzle was slowly pulled

up hole at 27 fpm laying in the 15.8 PPG latex cement 1 for 1.

Proper laying-in cement procedure requires complete

accountability of returns verses barrels pumped in order to

ensure the nozzle remains below the cement top. Pulling the

nozzle out of the top of the cement will contaminate squeeze

cement. While this horizontal well posed a significantly

different geometry than normal, the “keep the nozzle in the

cement” logic was based on expected mixing, and a presumed

more viscous cement “wave”. The large holes in the nozzle

should have helped minimize in-situ mixing of cement and

wellbore fluids. In reality, the nozzle depth may have had

little effect on the efficiency of displacement while filling the

horizontal section.

As the 120 Bbls of 15.8 ppg latex cement count

approached, the cement crew prepared to displace the cemen

into the CT with 10 Bbls of fresh water followed by seawater

The cement tail and CT nozzle depths were closely monitored

and minor adjustments were made to assure that as the last o

the cement exited the nozzle as the nozzle depth neared the

calculated top of cement based on wellbore void volume. The

pull out of hole rate was increased when approaching the pre-

calculated worst-case top of cement timing the nozzle

breakout of cement to the same time as the fresh water spaceexited the nozzle. The top of cement was over 1,000’ MD

above the top of the formation in a 45° deviation section of the

wellbore providing a small-area cement top. An illustration o

the wellbore and relative depths is shown in Figure 11.

The nozzle was pulled up to ‘safety depth” of

7,200’CTMD for the duration of the hesitation squeeze period

Circulation was broken occasionally to prevent freezing pump

lines and coiled tubing given the negative 34° F ambien

temperatures during the job. The CT was also occasionally

moved to assure that it remained free.

Wellhead pressure and pumped volumes were closely

monitored and used to estimate the volume of additiona

cement that displaced any pockets of wellbore fluid into theformation during the hesitation squeeze. Eight hesitations

steps were used to increase the final squeeze pressure up to

1,040 psi shut in wellhead pressure, or about 800 ps

overbalanced pressure for 40 minutes:Step SIW HP SICTP Vol ume pumped Post WHP Post CTP T ime/mi n Pressure Los

1 81 113 0.2 200 230 12 130

2 102 125 0.3 190 272 11 110

3 70 120 0.3 200 250 10 100

4 96 146 0.4 300 300 10 130

5 370 480 0.4 500 500 13 180

6 262 264 0.8 750 750 15 200

7 460 560 1 1000 1000 10 310

8 715 717 1 1040 1068 11 314

30 min. circulation stage to warm up surface lines maintain 430# WHP. NO LOSSES

One hour circulation stage to warm all surface lines and allow cement temp to rise. Maintain 70# WH

Begin contamination proceedures with 2 PPG Biozan holding 500# W HP. NO LOSSES


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SPE 94039 5

The cleanout procedure to remove the excess cement

began immediately following the final squeeze step (Fig. 12).

The excess cement from estimated depths 8,300’ to 8,880’

CTMD (7,096 TVD) was diluted with 2 ppg welan polymer

followed by seawater to circulate the diluted cement out of the

well and leave the top of cement at the desired depth for the

planned sidetrack. 8,880 ‘MD was 100’ MD deeper than the

production tubing tail to assure that the 4-1/2” tubing tail wasnot cemented in place, which would have complicated the

workover. This cement top TVD at this measured depth was

also at least 26’ TVD higher than any depth to the measured

TD of the well. The wellhead pressure was maintained at 500

psi to assure overbalance and minimize the possibility of

formation fluids contaminating the cement.

All jewelry was washed with the swirl nozzle while pulling

out of the hole to ensure wireline access to GLM’s and

nipples. Cement returns were seen at close to the expected

barrel count indicating the cement top was as designed.

Pumped fluids were managed to leave a diesel freeze protect

volume from 2,500’, approximate permafrost zone, to surface.

Wellhead backpressure was adjusted to compensate for the

reduced hydrostatic head of the diesel. Figure 13 shows a

graph of various parameters during the job.

Squeeze ResultsThe target depth for the Top of Cement (TOC) was 8,880’

corrected depth. Following waiting on cement to cure, the

conductor line tagged the TOC at 8,885’ corrected depth. This

measured depth kept the TVD height of cement at least 26’

higher than the highest point further down the lateral section.

The combination of TVD height of cement and applied

wellhead pressure on the wellbore assured that cement did not

U tube; solid cement should have remained in the entire lateral

section following the down squeeze.

Washing the cement slurry down to 8,880’ MD allowedadequate distance below the production tubing to assure that it

was not cemented into the casing. This depth also provided

the drilling rig adequate distance to dress off the TOC to

9,078’ MD in preparation to set the sidetrack whipstock at

9,078’ MD. A pressure test verified a competent hydraulic

seal. During the workover, the drilling rig encountered good

hard cement drilling, set a whipstock, kicked off 30 degrees

right of high side and recompleted the well in line with the rest

of the field.

Conclusions and Lessons LearnedEven with the challenges and departures from conventional

CT squeeze techniques, the cement job was performed withoutsignificant problems. Available information suggests that all

program goals were met.

Factors that contributed to the success of this work

include:

1. Extensive pre job planning and contingencyidentification

2. Workforce familiar with CT squeeze procedures3. Knowledge and familiarity of cement slurry designs4. On site and laboratory cement testing5. A thorough record of the wellbore geometry to

understand critical depths and hydraulics forces

6. Good CT depth correlation to assure leaving adequatevertical column of the cement while keeping below the

top of 4-1/2” production tubing

Lessons learned –or more accurately stated, relearned-

during this job include:

1. Ensure all tanks and lines are thawed and clean. A potentially serious problem developed when the warm

diesel was stored in an available upright tank that previously held water based drilling mud. The warm

diesel melted a thin sheet of frozen mud lining the

inside of the tank. This resulted in higher than norma

CT pump pressures when a small volume of 11 ppg

“diesel” was pumped down the CT during the freeze

protect while coming out of the hole. This could have

plugged a suction hose or caused triplex pump

problems.

2. On larger programs such as this, 2 full sets of crewswould have allowed for fresh crews had lengthy

problems developed during the squeeze.

3. A smaller trip tank with smaller volume barrelmarkers would have improved the accuracy of the

fluids in and out management. The normal 40 Bb

cement trip tank was not available at Alpine.

4. Continuous mixing operations are a convenienmethod to mix large volume jobs. However, there are

fewer contingencies available during these “on-the

fly” operations. Batch mixing allows a greater degree

of quality control verification of all cement pumped

into the well.

The procedures and methods discussed in this paper appear

to represent a viable technique for P&A or remedial squeeze

work in long horizontal wells.

Acknowledgements

The authors thank the management of ConocoPhillips AlaskaInc., BP Alaska, and other Unit Owners for permission to

publish this paper. This paper reflects the views of the

authors, and does not necessarily reflect the views of the

Colville River Unit, Greater Kuparuk Area, Prudhoe Bay Area

or other Working Interests. The dedication of the on-site

personnel to implement these procedures cannot be overstated

and is greatly appreciated. The authors wish to specifically

acknowledge the contributions of Perry Cline, Steve

Doughten, Mike Burnett, Howard Gober, Cliff Crabtree, Chris

Pierson, and Aras Worthington. A special thanks is given to

Jack Kralick and Doug Cismoski for persevering in editing

this paper and their technical input. The authors also

acknowledge the contributions of the ConocoPhillips AlaskaWells Group, BP Alaska Wells Group, and Dowel

Schlumberger.

NomenclatureBbl = Barrel

HP = High Pressure

ppg = pounds per gallon

psi = pounds (f) per square inch

Pv = Plastic Viscosity in cP

TD = Total Depth

TVD = True Vertical Depth

Ty = Yield Point in Pounds Force per 100 square feet


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6 SPE 94039

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Antonio, Texas, 5-6 October, 1997.5. Bhalla, J., “Coiled Tubing Extended Reach Technology,” paper

SPE 30404 presented at the SPE Offshore Europe Conference,

Aberdeen, Scotland, 5-8 September, 1995.6. Blount, C., Crabtree, C., Kralick, J., Pierson, C., Rennie,

S., Diller, G., and Mackenzie, G., “Inflatable CT

Conveyed Selective Well Testing System for Logging

Open Hole and Horizontal Wellbores: Development and

Use,” paper SPE 81718 presented at the 2003 SPE/ICoTA

Coiled Tubing Conference, Houston, Texas, 8-9 April,

2003.

7. Blount, C. G., Brady, J. L., Fife, D. M., Gantt, L. L.,

Huesser, J.M., and Hightower, C. M., “HCL/HF Acid-

Resistant Cement Blend: Model Testing and Field

Application,” paper SPE 19541 presented at the 1989 SPE

Annual Technical Conference and Exhibition, San

Antonio, Texas, 8-11 October, 1989. JPT February 1991, pages 226-248

SI Metric Conversion Factors Bbl x 1.590 E - 01 = m3

Ft x 3.048 E - 01 = m

in. x 2.54 E + 00 = cm

Lbf x 4.448 222 E + 00 = N

Psi x 6.894 757 E - 03 = Mpa

Tables

Fann Readings

(rpm)

81 deg F 140 deg F

300 36.0 74.0

200. 26.0 53.0

100 15.0 32.0

60 11.0 21.030 7.0 12.0

6 4.0 4.0

3 3.0 3.0

Cement Fann 35 reading (Bob 1 Spring 1)

Figures

laska North Slope

Figure 1: Map of Alpine development andsurrounding area on the North Slope of Alaska.


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SPE 94039 7

Figure 2: Drillsite 2 in-line pattern configuration. Subject Well B area is circled.

Figure 3: Typical Alpine horizontal openhole completion.

1 8

3 1

5

3 6

3 0

4 3

4 0

3 7

5 5

1 6

2 3

1 2

2 0

9 1 0

8

1 3

2 8

2 2

2 9

1 9

4 6

4 8

4 1

3 8

3 5 a

4 5

4 4

5 3

5 7

5 8

5 2

5 1

5 6

8

Alpine 3

Alpine 1B

Alpine 1

42PB

33A

Neve 1

23PB

34PB

50PB

39PB

35

24PB

32PB

13PB

Alpine 1A

1 4

1 5

1 7

2 4

2 5

2 6

3 3 B

3 4

3 9

4 2

4 7

4 9 5 0

3 2

9-5/8" Casing at 2,727' MD / 2,377' TVD

Cemented to surface

7" Production Casing at 9,444'MD / 6,824' SS

4-1/2" SSSV at 1,796' MD / 1,697' TVD,

16" Conductor to 114'

GLM at 4,176' MD / 3,388' TVD

GLM at 6,759' MD / 5,203' TVD

GLM at 8,878' MD / 6,670' TVD

Calculated

TOC +/- 9,286' MD

6,803' SS

SSSV

6-1/8" to TD at 13,977' MD / 6,841' SS

4,533' openhole

X N

X

4-1/2" Tubing w/ Thermal Centralizers

Between 3,250' - 6,250' MD

X Nipple at 8,940' MD / 6,708' TVD

4-½" x 7" Packer at 8,994' MD / 6,739' TVD

XN Nipple at 9,070' MD / 6,780' TVD


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8 SPE 94039

Figure 4: Close-up of subject Well B between offset wells A and C; before P&A and after sidetrack


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SPE 94039 9

Figure 5: Completion diagram of Well B prior to P&A and sidetrack.

Figure 6: Plan view and section view of Well B prior to sidetrack.


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10 SPE 94039

Figure 7: Layout of major equipment. Due to seasonal road access, the drilling rig’s cement equipment had tobe used to perform the CT P&A. The rig-up required use of over 800’ of hardline.

Tool Description Sketch Tool O/D Tool I/D Length

Inches Inches Feet

1.75" 1" 0.35

1.75" Cold Roll Connector

1.75" 1" 1

1.75" Dual Check Valve

1.75" Spacer Pipe

1.75" 1" 5

1.75" Ball Drop Nozzle 1.75" 1" 0.5

6.85 Figure 8: CT Bottom Hole Assembly. The BHA OD was the same as the CT OD to minimize the chance ofwellbore debris sticking the CT during the cement job.


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SPE 94039 11

Figure 9: Example of a combination cement/jet swirl ball-drop nozzle. The ball is pumped following cemendisplacement to land on seat blocking larger holes in nozzle and converts the nozzle to a jet swirl cleanoutnozzle. Note up/down swirl configurations in the nozzle to enhance cleanout efficiency.

Figure 10: CT with combination Cement/Jet Swirl nozzle with ball on seat. Picture is downward toward top of CTin 7” casing showing swirl vortex while pumping biopolymer gel.


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12 SPE 94039

Figure 11: Vertical section of wellbore illustrating various positions of equipment, fluid interfaces, andcompletion overlaid on a graphically accurate representation of the inclination survey.


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SPE 94039 13

Hesitation Squeeze

0

500

1000

1500

2000

2500

3000

3500

1 6 : 4 2 : 3 9

1 6 : 5 2 : 3 9

1 7 : 0 2 : 3 9

1 7 : 1 2 : 3 9

1 7 : 2 2 : 3 9

1 7 : 3 2 : 3 9

1 7 : 4 2 : 3 9

1 7 : 5 2 : 3 9

1 8 : 0 2 : 3 9

1 8 : 1 2 : 3 8

1 8 : 2 2 : 3 8

1 8 : 3 2 : 3 8

1 8 : 4 2 : 3 8

1 8 : 5 2 : 3 8

1 9 : 0 2 : 3 8

1 9 : 1 2 : 3 8

1 9 : 2 2 : 3 8

1 9 : 3 2 : 3 8

1 9 : 4 2 : 3 8

1 9 : 5 2 : 3 7

2 0 : 0 2 : 3 7

2 0 : 1 2 : 3 7

2 0 : 2 2 : 3 7

2 0 : 3 2 : 3 7

2 0 : 4 2 : 3 7

2 0 : 5 2 : 3 7

2 1 : 0 2 : 3 7

2 1 : 1 2 : 3 7

2 1 : 2 2 : 3 7

2 1 : 3 2 : 3 7

2 1 : 4 2 : 3 6

2 1 : 5 2 : 3 6

2 2 : 0 2 : 3 6

2 2 : 1 2 : 3 6

2 2 : 2 2 : 3 6

2 2 : 3 2 : 3 6

Time

P r e s s u r e ( P S I G )

010

20

30

40

50

60

70

80

90

100

110

120

130

140

150160

170

180

190

200

210

220

230

P u m p e d V o l u m e ( B b l s )

WH Pressure psig

CT Pressure

Total Volume (Bbls)

Squeeze Circulate Squeeze

SqueezeSqueeze

Reset

MM Tot.

RIH to Cleanout

Figure 12: Graph of Well B hesitation squeeze. Areas marked where wellhead pressure was squeezed.Circulation took place between squeeze intervals: fluids were circulated to the choke to prevent freezing surfacelines. Fluids in and fluids out were carefully checked during circulation periods.

Figure 13: Graph of various parameters during the execution of the P&A of Well B. Weight is on the right Y-axis.Density was adjusted to #/100 gallons for resolution. Hesitation squeeze interval is between 500 and 840 min.

Cementing a Long Horizontal Wellbore Using CT Squeeze Technology

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