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The hardware used in casing-while-drilling operations has proved to be robustand reliable. Several directional wells havebeen drilled successfully with casing usingpositive-displacement motors (PDMs), butthe drilling efficiency was low. A rotarysteerable system (RSS) improved drillingefficiency when drilling with casing.

IntroductionConocoPhillips began a field-developmentprogram in 1997 in the Lobo trend of southTexas. More than 900 wells have been drilledthrough the Wilcox (Lobo) section ranging indepth from 7,500 to 13,000 ft. In 2001, afterdrilling approximately 600 wells, a programwas undertaken to find ways to reduce drillingcosts sufficiently to extend the developmentpotential for several years. Any major reduc-tion in drilling time had to address the flattime more than the making-hole time. A cas-ing-while-drilling system was chosen for thePhase 1 five-well pilot project. Sufficientprogress was made in drilling these first wellsto justify moving to a second phase of drilling.

The second phase proved that casing whiledrilling could eliminate the formation-relatedtrouble time experienced with conventionaldrilling. Lost circulation was almost com-pletely eliminated, allowing the drilling ofadditional wells formerly considered uneco-nomical. The wells were not drilled trouble-free, but the trouble was associated with themechanical-equipment limitations, whichwere overcome on the Phase 2 wells.

Retrievable Casing-While-DrillingProcessCasing can be used as all or part of the drill-string in several ways. Systems are eitherretrievable or nonretrievable. Nonretrievablesystems include both liner-drilling applica-tions and applications with full strings of cas-ing with which a fixed bit is used for drilling.The bit may be drillable (i.e., drilled out to drill

the next hole section), or it may be a conven-tional bit that is left in the hole at total depth.

Retrievable systems allow the bit and bot-tomhole assembly (BHA) to be changedwithout tripping the casing. Use of a retriev-able system is the practical choice for direc-tional wells because of the need to recoverthe directional-drilling and guidance tools,the need to replace failed equipment beforereaching casing point, and the need forquick and cost-effective access to formationsbeyond the casing shoe.

A retrievable casing-while-drilling systemhas downhole and surface components thatenable standard oilfield casing to be used as thedrillstring so that the well is simultaneouslydrilled and cased with the wireline-retrievabledrilling BHA suspended in a profile nipplenear the bottom of the casing. The top com-ponent of the BHA that facilitates attachmentto the profile nipple is the drill lock assembly(DLA). The casing is rotated from the surface,and the drilling fluid is circulated down insidethe casing and back up the annulus.

The drilling assembly terminates in a pilotbit, but it may include other conventionaldrillstring components such as an under-reamer, mud motor, stabilizers, drill collars,or measurement-while-drilling (MWD) orlogging-while-drilling tools. A top driverotates the casing for drilling and is used to

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE92195, “Casing Directional Drilling Using a Rotary Steerable System,” byRobert Strickler, SPE, and Todd Mushovic, SPE, ConocoPhillips; Tommy Warren, SPE,Tesco; and Bill Lesso, SPE, Schlumberger, prepared for the 2005 SPE/IADC DrillingConference, Amsterdam, 23–25 February.

Casing Directional Drilling With a Rotary Steerable System

Horizontal and Complex Trajectory Wells

Underreamer

(61/4 to 87/8 in.)

Bent-housing motor

43/4 in. then 51/2 in.

(1.5º bend)

Casing

shoe

Tandem

casing

stabilizer

DLA

7-in.,

23-lbm/ft

casing

to surface

61/4-in. PDC bit

(3×15 nozzles)

Nonmagnetic

drill collar

MWD

Float subassembly

Vibration-

monitoring

subassembly

Fig. 1—The BHA used to casing directionally drill Well 83.

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torque up the connections. The casing stringis rotated for all operations except slidedrilling, and it uses a motor and bent-hous-ing assembly for oriented directional work.

Directional Drilling With Steerable MotorsThe intermediate hole section (7-in. casing)of Well 83 in the Lobo casing-while-drillingsequence included an interval drilled direc-tionally with steerable motors. The direc-tional work was required to avoid a surfaceobstruction and provides a good example tohighlight the issues involved with usingsteerable motors in a retrievable drillingassembly. The well was kicked off, and incli-nation built to 15°, where the inclinationthen was dropped back to near vertical aftersufficient lateral displacement was obtained.

The well required 18.2 days to drill to theintermediate-casing point. A comparable,trouble-free vertical well would have taken81/2 days to drill to the same depth. Most of theincreased time required to drill the well wasthe result of inexperience with directionalwork with casing and inefficiencies of the cas-ing directional-drilling process with steerablemotors. The only lost time recorded for theinterval was 10.5 hours lost because of a miss-run when installing the first motor assemblyand 6.5 hours required to free the casing,which became stuck while sliding at 5,642 ft.

The well was drilled vertically to the kick-off point at a true vertical depth (TVD) of4,434 ft, where the vertical drilling assemblywas retrieved with wireline. A steerablemotor assembly with a polycrystalline-dia-mond-compact (PDC) bit, shown in Fig. 1,was run on wireline and landed in the cas-ing. The assembly was positioned in theshoe joint of casing so that all componentsbelow the tandem stabilizer extended intoopen hole below the casing.

The directional performance of the rotaryassembly was encouraging because it con-firmed that the well inclination could becontrolled in the pilot hole, with the holebeing opened to accept the casing far abovethe active portion of the assembly. This crit-ical step helped develop confidence that anRSS could be used when drilling with casingbecause there are no RSS tools that can workabove an underreamer.

Two Emerging TechnologiesCombining an RSS with casing-while-drillingoperations should eliminate major weaknessesin motor BHA designs. RSSs had not previous-ly been used with casing while drilling. Casingwhile drilling was developed for land opera-tions, while RSSs were popular offshore.Successes in reducing losses in historically

problematic formations have sparked interestin applying casing while drilling to similar sit-uations offshore. Directional operations withPDMs in smaller hole sizes were not effective.Therefore, RSSs were investigated. The diffi-culty was little overlap in logistics and method-ologies for merging these two technologies.

Two-Well TestA two-well test program was proposed. First,an RSS would be used in a vertical well. An RSShas a verticality mode in which the tool sensesdeviation away from vertical and then thruststhe bit back to vertical. This process takes placein a closed-loop fashion. The tool is added tothe BHA. No MWD system is needed, and thetool operates automatically, virtually transpar-ent to drilling operations. This well tested theBHA configuration, operational functionality,and directional performance of the RSS in theretrievable drilling assembly. Downhole-record-ed data confirmed tool operations. The stan-dard single-shot surveys confirmed the direc-tional performance of the system.

The BHA for the second well was morecomplex. An MWD system and full direc-tional-drilling operations were needed tofollow a planned trajectory. The inability todrill directionally would have requiredchanging rig operations to conventional-drillpipe drilling, a significant expense.

RSS Verticality Test. The verticality test tookplace in Well 89. The 95/8-in. casing wascemented in place at 588 ft. A 43/4-in. RSS and

a 43/4-in. drill collar were added to the standardverticality BHA. This configuration was runfrom 614 to 4,821 ft in 105 hours. Single-shotsurveys taken 500 ft apart showed that the wellwas nearly vertical. Higher-than-expected cas-ing vibrations were attributed to the long BHAstick-out. The run was terminated at a plannedreplacement of the underreamer. The operationcontinued to the 7-in. section TVD of 7,620 ft.

Operational data showed that the RSSdirectional-control unit did not stabilize on agravity reference for 3 days, when the bit wasat 3,710 ft. Because of verticality or a toolproblem, the tool had been unable to deter-mine which way was up and, as a result, hadbeen ineffective. The well had drifted out to2.25° of inclination at 3,600 ft. At 3,800 ft,the well snapped back to a nearly vertical0.25°. The RSS problem resolved itself at3,710 ft, the tool became directionally func-tional, it sensed the inclination, and itbrought the well back to vertical. Verticalitycontinued for the remainder of the test.

RSS Full Directional Test. Most of the wells inthe Lobo trend development are vertical. TheWell 91 target was 1,200 ft south of Well 79.The team proposed to use the old Well 79 loca-tion and drill an S-shaped trajectory to the tar-get location. The basic plan called for a build to29° and then a drop into the target 1,200 ftaway. As Fig. 2 shows, the trajectory wouldhave to be routed around Well 79 to avoid col-liding with the producing well. Well 91 wouldkick off along an azimuth that was 40° east of

-1200

-1000

-800

-600

-400

-200

0

200

-600 -400 -200 0 200

Easting (E/-W), ft

No

rth

ing

(N

/-S

), f

t

0

1000

2000

3000

4000

5000

6000

7000

0 1000 2000

Displacement, ft

TV

D, ft

Horizontal PlotVertical Plot

target

Well 91Well 91

Well 79

Well 79

Surface

location

Surface

locationTD

Fig. 2—The trajectories of Wells 79 and 91, as drilled. Well 91 had to circum-vent Well 79 to avoid collision risks.

54 NOVEMBER 2005

the target azimuth, build to 29°, and start a 100°turn to the right. During the later stages of theturn, the drop would be initiated, bringing thewell into the target. This profile resembledthose used on large multiwell offshore plat-forms. Experience showed that the deeper-cas-ing-point wells had more problems with vibra-tions and casing whirl when drilling the 7-in.section. Adding a straight PDM to the BHAabove the underreamer addressed this prob-lem. This addition was a significant operationalchange from the test in the vertical Well 89;therefore, the dynamics of the BHA were differ-ent and the MWD assembly was run below themotor. The MWD system was designed to takea survey when pressure dropped to zero(hydrostatic), and before the connection, whilethe BHA was still.

The BHA design for the 7-in. section ofWell 91 was 112 ft long with 85 ft of stick-outbelow the shoe of the 7-in. casing. Below theDLA, a tandem casing stabilizer with two sta-bilizer-blade sections was installed that wasgauged to the internal drift diameter of the7-in., 23-lbm/ft casing. This stabilizerabsorbed most of the vibrations of drilling.Placing the mud motor below the tandem cas-ing stabilizer allowed drillstring rotation to bereduced when dealing with vibration issues.

The underreamer was placed directlybelow the mud motor and opened the pilothole to 87/8 in. When the pumps were off,the arms of the underreamer collapsed sothat the maximum diameter of the tool wasslightly less than the internal diameter of thecasing. An external tandem stabilizer wasdesigned to reduce vibrations and wear onthe underreamer. Below these sections was aslim MWD system. A push-the-bit-type RSSwas installed below the MWD assembly. Thebit was a four-blade PDC bit.

Drilling operations started in the 7-in. sec-tion at 1,278 ft. The proposed kickoff point was2,100 ft. The RSS was programmed for verti-cality mode as in the previous well. The MWDtelemetry was strong. There were problemsholding the correct azimuth and then stabiliz-ing the turn. Drilling passed around the nearbywell and turned toward the target location.Twenty-six sets of telemetry data sent to theRSS in the drilling of this section had sufficientdrilling footage to evaluate. Twenty-four ofthese were judged to be directionally effective.

The kickoff run continued to 4,067 ft,where pressure spikes indicated BHA prob-lems. The BHA was retrieved by wireline.The motor was locked up, and a washoutwas found in the body of the RSS, though itwas judged operational before the trip out.The motor was removed from the BHA andnot replaced. The bias unit of the RSS wasreplaced, and drilling continued. Drillingwas slower, and it was difficult to keep sur-face turns above 60 RPM. The run was ter-minated when a replacement motor arrived.

The motor was added back for the thirdrun, restoring the BHA to the design configu-ration. Drilling proceeded normally for 200 ftbefore the rate of penetration dropped signifi-cantly. The BHA was pulled, and it was deter-mined that the wrong size underreamer hadbeen run. The underreamer was replaced, anddrilling continued normally to 5,420 ft, wherethe casing became differentially stuck. Thisevent caused 50 hours of lost time. Direction-ally, the build and turn had been finished, andthe drop was under way. Drilling then contin-ued to 6,360 ft. The well was at 4° of inclina-tion. A pressure drop indicated a washout inthe BHA. Surface inspection showed thewashout in the connection between the jetsubassembly and external tandem stabilizer.

The jet subassembly was dropped from theBHA, and drilling continued to section TD of6,950 ft.

Conclusions1. Directional wells can be drilled with

casing using steerable motors, but success isdifficult to achieve in holes smaller than81/2-in. diameter. The smaller sizes of BHAcomponents required to fit through smallholes give less-than-optimal power to steerthe underreamer and bit.

2. RSSs can be effective in 81/2-in. casing-drilled holes. Directional control in the pilothole is sufficient to guide the larger casing toa directional target.

3. In casing-drilled wells, pressure andflow operational requirements of RSSs re-quire consideration when selecting nozzlesize and BHA design.

4. The casing-string design for casing-drilled directional wells is different fromthat in vertical wells. Directional wells havemore side forces and are more susceptible todifferential sticking.

5. MWD systems run below mud motorscan maintain reliable data transmission, andthe signal attenuation was less than expected.The MWD survey should be taken in the quiettime when the pumps are down instead ofwhen the pumps first come back up after theconnection, as is the common practice.

For a limited time, the full-length paper isavailable free to SPE members atwww.spe.org/jpt. The paper has not beenpeer reviewed.

JPT