00084173

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Copyright 2003, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the SPE Annual Technical Conference andExhibition held in Denver, Colorado, U.S.A., 5 – 8 October 2003.

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, 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 paperfor commercial purposes without the written consent of the Society of Petroleum Engineers is

prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract 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.

AbstractDrilling with production casing while underbalanced isimproving the drilling performance dramatically in SouthTexas fields. This approach allows drilling of depleted andhigh pressure sands intermingled within one hole section,resulting in significantly less expensive well plans. Drillingcost reductions of 30% have been realized. Smaller reservetargets are viable, a key advantage in the mature South TexasVicksburg play.

IntroductionShell has developed and operated gas fields in South Texas forthe past 50 years. These 10,000 ft - 16,000 ft high pressure,high temperature (HPHT) wells normally have initial shut intubing pressures approaching 10,000 psi when virgin pressuresands are completed. The bottom hole temperatures rangefrom 280-400oF. Most wells have multiple low permeability pay sands, which require massive hydraulic fracturetreatments to produce economically. Each pay interval isfracture treated in a separate stage and the production from allthe sands is commingled.

Most current drilling activity is in and around maturefields where large volumes of gas have been produced. Severereservoir pressure depletion intermingled with high pressuresands is often encountered. The presence and level of pressuredepletion is difficult to predict due to complex geology, low permeability and production commingling.

The underbalanced drilling with casing approach was firstapplied to a slim-hole reentry program that began in 1995.These reentries were either sidetracks to replace wells thatfailed due to casing damage or wells that were deepened tonew objectives. The reentries normally cost half what a newwell would allowing smaller reserve targets to be drilled

economically. They were sidetracked out of the existing 5”o5-½” casing and a new string of 2-7/8” casing was run andcemented. By 2000, remaining reentry candidates weredifficult to drill with lost circulation and well control problemsmore common. The program was becoming uneconomic dueto the inability to set liners in the small hole size. Drillingwith casing1,2 while underbalanced was applied to resolvethese problems and ten reentries have been drilled this waysince 2001. The low permeability Vicksburg sands allowoperations with a higher underbalance than would be possiblein most other applications.

The learnings from the reentry program have beentransferred to the drilling of new South Texas wells. Drillingnew wells with casing while underbalanced enables the casingsize programs to be reduced, eliminates liners and reducestrouble cost resulting in cost savings of up to 30%. Themajority of Shell’s new South Texas wells utilize drilling withcasing while underbalanced.

Vicksburg Well Design Evolution

A typical South Texas well plan prior to 1990 (figure 1a)required 13-3/8” surface casing and 9-5/8” protective casingwith the option for a 7-5/8” liner when needed. Wells werecompleted with 5” or 5-½” production casing, 2-7/8” tubingand a permanent packer. The sands were produced one at atime from bottom to top. A workover rig was used to plug back and recomplete to the next zone. Well lives needed to be30 years or longer which was beyond what a typicaVicksburg well would last before failure.

In 1990, the new completion philosophy was tocommingle production from all sands (figure 1b)Commingling accelerated production and reduced the

necessary well life, providing an opportunity to improvedrilling economics. In 1994, a change to a 3-1/2” tubingles(or “cemented completion”) design (figure 1c) was made. The9-5/8” protective casing was designed to withstand loadsunder producing conditions in addition to being designed as protective casing. This design change resulted in a 15%decrease in well cost and the resulting monobore made multi-stage completion operations much simpler.

During the same time, drilling problems due to reservoirdepletion became more common. Severe lost circulation indepleted zones intermingled with high-pressure zones led tocostly well control problems. Poor reservoir pressure

SPE 84173

Underbalanced Drilling with Casing Evolution in the South Texas VicksburgDoug Gordon, SPE, Rich Billa, SPE, Mike Weissman, SPE, Shell Exploration and Production Company, Fu Hou, SPE,Shell International Exploration and Production Inc.

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prediction due to the complex geology required well plans to become more conservative. The standard 13-3/8” x 9-5/8” x7-5/8” program often became 16” x 11-¾” x 9-5/8” with a7-5/8” contingent liner to set before drilling into a potentiallydepleted zone. Although trouble costs were reduced total wellcosts increase.

Through the late 90’s, drilling mud lost circulationmaterial (LCM) pretreatments and “squeeze through the bit” procedures to combat lost circulation were developed. Withthese improvements, it became common to drill with a 5,000-6,000 psi overbalance without a drilling liner. In cases wherelost circulation could not be controlled, the thief zone wassqueezed and a 7-5/8” liner was run above it so drilling could proceed with a reduced mud weight.

By 2000, the overbalances were beyond the capabilities ofthe LCM pretreatment techniques and casing programs fornew wells began to get larger in order to set an additionalliner. On the reentry wells, liners could not be run in the slimholes. To continue drilling and reentering wells economicallythe mud weight had to be reduced so that the overbalance wasmanageable which caused much of the wellbore to beunderbalanced. Most of the wells could be drilled successfullyto TD but this underbalanced condition made it impractical totrip in order to run production casing. Drilling with casingwas identified as a possible solution.

A drawback to drilling with casing while underbalanced isthat open hole logs are not obtained and the completion must be done based on cased hole logs. Open hole log informationis generally not critical in the reentries since the open holelogs from the original hole are available. This made thereentries ideal candidates for the first underbalanced drilling

with casing attempts.

Re-entry ProgramThe reentries usually targeted partially depleted reservoirswith anticipated shut-in tubing pressures (SITP’s) of less than7,000 psi. These wells had 5” or 5-½” production casing witha premium connection which provided a second barrier if the2-7/8” casing leaked after completion. The drill with casingconnection selected for the reentries was 2-7/8”, RTS-6. Thisconnection has been used successfully as both work string and production tubing in South Texas wells.

In a typical reentry (figure 2), the existing production

equipment is recovered as deeply as possible above the pointof casing failure. A whipstock is set and a window is cut inthe 5” or 5-½” casing. A modified drilling assembly is used(figure 3) to drill with casing and work underbalanced. A3-7/8” or 4-1/8” PDC bit is able to drill the entire interval, 500ft-1800 ft without tripping. A back pressure valve is installedin the bit sub and a landing nipple is run above the bottomhole assembly (BHA) so an additional back pressure valve can be run on wireline as back up. Watermelon mills are usedrather than stabilizers so the window can be elongated asrequired. A profile for a latch-down cement wiper plug is runabove the drill collars. The drill string is not centralized andthe string is rotated during cementing to aid displacement.

The BHA is shortened to 100’, which minimizes the rat holeneeded below the objectives sands. Drill string modeling othe short BHA indicated minimal buckling problems becauseof the small annular clearances. Short flag joints were spacedout in the casing string for subsequent correlation purposes. Asurface stripper was used to divert the well returns and holdwell pressure so influx from underbalanced zones could be

managed. A remotely operated valve on the flow line wasadded so that pressure on the backside could be held whilemaking connections to keep the bottom hole pressure constant

The first three reentries drilled with casing wererepresentative of the entire program and demonstrate theadvantages of drilling with casing while workingunderbalanced. Drilling started in the Well A sidetrack with14.6 ppg oil based mud at 10,038 ft. After drilling to 10,056ft, a high pressure (17.0 ppg) wet zone was encountered whichresulted in a steady water flow of approximately 2 bbls/hourDrilling continued at 3 fph while pumping 1-2 bpm, rotating110 rpm, and maintaining 2000#-3000# WOB. The workoverig had a small mud system (300 bbls) so the oil based mudwas discarded several times during the job due to watercontamination. As drilling continued through several depletedzones the mud weight was adjusted between 14.6 and 17 ppgin an attempt to balance the water flows and mud lossesWater influx was minimized by ECD and by holding 300-500 psi on the annulus while making connections. Drillingcontinued until complete returns were lost at 11,449 ft. Themud weight could not be reduced any further due to the waterflow so a LCM cement squeeze was pumped and the 2-7/8”casing string was cemented in place in the 4-1/8” hole. Thefinal mud weight was 15.8 ppg. The 2-7/8” casing wacemented with lighter cement, 15.3 ppg, to guard against lostreturns. The casing was not rotated but the cement bond

looked adequate on cased hole logs. Although the desired TDand one of the reserve targets was not reached on this first drilwith casing well, the equipment all functioned well and therewere no directional problems with the shortened BHA. Thishole section was drilled with a mud weight 1.5 ppg lighterthan when originally drilled and could probably have not beendrilled using conventional drilling techniques without setting aliner across the water sand.

Well B was sidetracked at 7,850 ft and drilled with 14.2 ppg oil based mud at 10-15 fph to 8,801 ft, just above theknown depleted sands. The mud weight was reduced to 12.7 ppg before drilling ahead. High background gas readings and

water influx were managed by holding 250 psi was held on theannulus while making connections. The penetration ratedropped to 1-2 fph in the depleted sands. Both seepage and pigains were observed from the intermingled zones. At 8,994 ftthe mud weight was reduced to 12.2 ppg and the penetrationrate immediately increased back to 10-15 fph. At 9,625 ft, the2-7/8” string was cemented in place with a 12.7 ppg slurrywhile rotating. Subsequent cased hole logging indicated anexcellent cement bond. This section of hole was drilled with amud weight 2.5 ppg less than in the original hole.

Well C was sidetracked at 9,450 ft with 13.6 ppg oil based mud. High background gas readings were observed. A

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9,515 ft the drill string started packing off and sticking in asuspected fault zone. Mud weight was raised to 13.8 ppg andthe hole stabilized (normally the mud weight can be reducedto 12 ppg before hole stability problems occur). Drillingcontinued with high background gas readings and as each ofthe four depleted sands were drilled the penetration rateslowed to approximately 1 fph and the well started losing

mud. Full returns were lost several times. An LCM pill was pumped to slow the losses and drilling continued. The waterinflux continued to affect the mud properties so the mudweight was raised to 14 ppg and additional pressure was heldon the stripper while making connections. In an attempt tocontrol losses, three LCM cement squeezes were pumped at10,559 ft. They were not successful. An extremely difficultinterval was drilled with 3 ppg lighter mud than whenoriginally drilled. This interval could not have been drilledwith a conventional drilling operation.

The drilling with casing while underbalanced approachwas also used to deepen several existing wells. During 2001

and 2002, ten reentries were drilled with casingunderbalanced. Only one had a poor cement job (returns lostwhile cementing) requiring remedial work. In most cases thehole sections were drilled with considerably lighter mudweight than previously possible, which allowed the intervalsto be drilled and improved the drilling performance throughthe depleted sands. The reentry program is continuing in 2003and the underbalanced drilling with casing approach is beingutilized in nearly all open hole operations.

First Application on New WellWell D was the first new well which utilized underbalanceddrilling with casing techniques. A 7-5/8” liner was set abovefive separate, depleted sands. The mud weight was cut from17 ppg to 15 ppg to reduce the overbalance across the sands.Drilling continued until the last zone was reached, wherehigher than expected pressures were encountered and background gas and connection gas readings increased. AtTD, the mud weight was increased to 15.8 ppg, but short tripsindicated the drill string could not be safely tripped. Whileraising the weight to 16.0 ppg, complete returns were lost inone of the upper zones, and the fluid level dropped 2600 ft.The drill string was quickly tripped back into the 7-5/8” casingshoe, at which point the lowermost, high-pressured sand beganto flow. The open hole was squeezed with LCM cement,leaving 500 ft of cement inside the 7-5/8” shoe (figure 4a).

Normally at this point, an attempt would have been madeto clean out to above the high pressured sands so that a 5-1/2”drilling liner could be run across the depleted zones. Instead,the decision was made to attempt to ream out the cementsqueeze with the production casing to TD and cement thestring similar to the successful reentry work. A 6-½” PDC bitand a conventional double-valve float collar was run on the bottom of 3-½”, 12.7 #/ft, L80, VAM. The string was trippedto the top of cement, a rotating head was installed and the mudweight was reduced to 15.0 ppg. The cement reaming torquewas limited to 2,000 ft-lbs since the make-up torque on theVAM was 4,420 ft-lbs.

Gas was handled by a rotating head and a large gasseparator. The cement reaming was accomplished with lowtorque due to the low compressive strength design of the LCMcement. The cement was drilled out in 24 hours. At thi point, the mandrel hanger was positioned above the casing bowl and the string was rotated at 20 rpm’s while cementingThe tubing string was cemented with full returns and the

mandrel hanger landed and tested (figure 4b).

The underbalanced reaming with casing operation on theWell D eliminated the need for a 5-½” liner saving $300,000This along with the reentry success indicated that drilling with3-½” casing was feasible.

Drilling Casing Connection TestingMost of the new wells in South Texas target some high pressure reservoirs. The 3-½” production casing is designedto handle both the high SITP’s and stimulation pressures. A3-½” casing connection was needed that could be used to drilformation and then remain gas tight during high-pressure

production operations. Although reaming the casing string onWell D had been successful, a casing connection with a hightorque yield rating and compression rating was necessary fordrilling new hole. The maximum drilling torque recorded athe surface in most Vicksburg drilling operations is low (2,500ft-lbs for 4-¾” hole, 3,500 ft-lbs for 6-½” hole). To verifyload conditions a down hole memory tool was run to recordvibrations and shock loads while drilling 6-½” hole. Nosevere vibrations or shock loads were recorded.

After reviewing the available connection capabilities, 3-½”, 12.95 #/ft, L-80, Hydril 533 was chosen for testing because of the high yield torque (9,900 ft-lbs) and the 100%rating in compression. This connection has a smooth externa profile that would minimize wear in a rotating head. A fieldtest on a South Texas well was designed to test the connectionfor gas sealing ability after being used as a drill string. Threesets of four test connections were manufactured to the extremetolerances and tapers. The test connections were made up inthe worst case combinations and then run in the top, middleand bottom of the string along with a down hole memory toolso the effect of various loading conditions on the connectionscould be tested (figure 5). The test string was used to drilfrom 9,063 ft-11,900 ft (2,837 ft) in 200 rotating hours with2,000-3,000 ft-lbs surface torque, 3,000-7,000 lbs WOB and110-150 rpm’s. A drill string vibration analysis had been runforecast and the predicted excitation RPM’s were avoided

The bit was tripped once so that multiple field make and breaks could be done on the test samples.

The recorded bottom hole vibration loads were minimalalthough some slip-stick could be observed. The tesconnections were sent to the lab for testing. On breakout, themaximum torque seen was 7,900 ft-lbs, even though themaximum torque recorded at surface was only 3,000 ft-lbsSix samples, two from each section, were selected for a gassealing capability test, and two more were used for multiplemake and break galling tests. The gas sealing capability tesenvelope test is shown in figure 6. The test parameters weredesigned to apply the maximum expected loads while

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producing as follows: maximum internal pressure - 11,000 psi,tension - 90% of pipe body yield, maximum compression - 90Kips. Bending loads (20 degrees DLS) were applied with thecombined axial and pressure loads. Ten thermal cycles were performed between 125 and 350 degrees F. Bending loads of20 degrees DLS were also applied. All six samples passed thegas sealing capability test without a leak.

Four samples were tested to failure – all failed outside theEquivalent Von Mises (VME) envelope. The connection wasdeemed suitable for South Texas well conditions.

First New Well Drilled with Casing UnderbalancedWell E was the first new well designed to includeunderbalanced drilling with casing. A smaller casing programwas possible than what was typically used in offset wells(figure 7a). The smaller design eliminated a drilling liner bydrilling in a tapered string of production casing (3-½ x 2-7/8”)through depleted sands intermingled with high-pressure sands(figure 7b).

While drilling Well E, the 7-5/8” shoe at 9,000 ft brokedown at 16.8 ppg rather than the expected 17.7 ppg and couldnot be repaired. Drilling continued with a 16.3 ppg oil basemud to 10,862 ft, with high background gas and lost returns.Offset wells had required a 17.0 ppg mud to drill to the nextcasing point (11,300 ft) but the mud could not be raised above16.3 ppg without losses. The decision was made to “drill-in” aliner to the next casing point and then sidetrack out of the linerto TD.

The original design for the Well E had a 5-1/2” flush jointliner not suitable for drilling operations. A 5”, 18#/ft, P110,Hydril 513 liner was selected for drilling. A conventional

PDC bit was run on bottom, and crossed back to the casingwith a bit sub containing a back pressure valve. A fullopening auto fill (ball activated) float collar was run two jointsoff bottom. A setting sleeve without a hanger or packer wasused to rotate the liner on 3-½” drill pipe. After tripping to the7-5/8” shoe, the mud weight was reduced from 16.3 ppg to15.8 ppg. The liner was drilled 468 ft in 26 hrs (4000#-5000#WOB and 90-100 rpm) through a “fault zone” that hadrequired 3-4 LCM cement squeezes on offset wells. Drillingthe liner in allowed the mud weight to be reduced 1.7 ppglower than on offset wells, resulting in less lost circulation problems. Penetration rates were similar to conventionaldrilling results in offset wells.

At TD, a ball was dropped to release from the hanger, butthe steel ball seat had been eroded and the ball failed to seat.A standing valve was run but the tool would still not release.The 5” liner shoe was tack-cemented in place, the linerrunning tool backed off in the casing, and the top of the linersqueezed with cement. A whipstock was run just above theliner float collar and a window was milled in the 5” liner. Atthis point, a BHA similar to that of the reentry program was picked up and run on a tapered 3-½”, 12.95#/ft, L80, Hydril533 x 2-7/8”, 7.9#/ft, L80, RTS-6 casing string. The oil basemud was reduced to 12.6 ppg to minimize overbalance in thedepleted sands.

A rotating head, with remotely operated valves off theflow line, was used to divert gas to a large separator orthrough the choke manifold. Prior to picking up the BHA, asufficient number of 90 ft stands to drill to TD were made upand stood back in the derrick. Casing tongs and torque turnequipment was used to make up each stand. A crossover backto the top drive connection was made up on each stand. The

bit, BHA, 2-7/8” and 3-½” were tripped to the window. Todrill ahead, a stand of 3-½” with a crossover was picked upand made up into the string with tongs. The crossover wasthen made up to the top drive and drilling commenced. Thewell was drilled from 11,313 ft to 12,431 ft through sevensands of varying pressure in 91 hrs for an average of 11.3 fphThe deepest and highest pressured sand which had normallyrequired a liner was actually 400 psi higher than the mudweight at TD. High background gas and a constant 5 ft to 30ft flare were observed. At TD, 100 bbls of 12.0 ppg mud wa pumped ahead of 14.5 ppg cement. The cement was displacedwith 11 ppg CaCl2 and the rate was varied from 1-3 bpmthroughout the cement job to maintain constant bottom hole pressure. The string was rotated at 20 rpm, and the mandrehanger was landed after the plug was bumped. Subsequencased hole logging indicated excellent cement bond.

Eliminating the liner and downsizing the program saved$750,000 (25% cost reduction). Well E was completedsuccessfully utilizing cased hole logs. This well demonstratedthat severely depleted sands and high pressure sands could bedrilled together as long as there was no need to trip once TDwas reached.

Drilling with Casing Underbalanced Examples

Well F. A conventional well design (figure 8a) would nothave been economic to drill. By drilling with casing

underbalanced, a smaller less expensive casing program(figure 8b) made the replacement well an economic project. Atapered 3-½” Hydril 533 x 2-7/8” RTS-6 casing string wasused to drill 1,610 ft of 4-¾” hole to 15,860 ft (1,000-3,000#WOB, 70-80 rpm’s, 145 gpm). Five sands with varying pressures were drilled with 13.5 ppg oil based mud. One othe sands was high pressure (17.5 ppg ). It was drilled with1,000-2,000 units of gas (measured downstream of the gas buster) with a constant 5 ft to 30 ft flare. While picking up themandrel hanger to cement, the casing became stuck at TDThe well was cemented with full returns and a conventionalslip and seal assembly was used to land the casing stringHaving the production casing assembly in the hole allowed a

sound completion to be made despite being stuck. Over$1,800M (30%) was saved compared to the conventionawell plan.

Well G. A smaller casing program was also used in Well G by drilling underbalanced with casing (figure 9a, 9b). Inoffset wells, lost circulation problems were common becauseof the weak fracture gradient at the protective shoe (17.5 ppg)and the “T” sand which normally required a 17.5 ppg mud todrill. The “S” shaped well (maximum angle 11 degrees) wasdrilled to 11,800 ft with 16.5 ppg oil based mud and open holelogs were run. A full string of 3-½” Hydril 533 casing wasthen picked up to finish drilling the 6-½” hole interval to TD

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The “T” sand was drilled with 1,000-2,000 units downstreamof the gas buster with a constant 6-10 ft flare. The maximummud weight used was 16.8 ppg, which was 500 psiunderbalanced to the “T” sand. The casing was rotated duringcementing with full returns. Downsizing the program reducedthe drilling cost by $400,000 and another $350,000 was saved by eliminating the liner (30% drilling cost reduction).

Well H. A 5-½” liner was eliminated in Well H by drilling ina 3-½” full string of Hydril 533 casing, saving $400,000compared to offset wells (figure 10). Like the McAllen 116,the well was drilled halfway through the shallower, depletedsands conventionally to allow for open hole logs. The drillingwith casing string was then picked up and used to drill from13,320 ft to 14,770 ft with 13.5 ppg, oil base mud. Theinterval was drilled in 103.5 hrs, at an average of 14 fph. Aconstant 20 ft-30 ft flare was observed while drilling thedeeper, high-pressured sands. The casing was successfullycemented at 14,770 ft while being rotated. The deepest high- pressured zone had a bottom hole pressure of 11,500 psi –

2,000 psi higher than the static mud weight at TD.

ConclusionsDrilling with casing while underbalanced makes it possible todrill depleted sands intermingled with high pressure sands inone hole section. Smaller casing programs are possible andliners can be eliminated. Well costs in mature South Texasfields have been reduced by 30% through utilization of drillingwith casing and underbalanced drilling techniques. Lowerdrilling costs makes smaller reserve targets viable, a keyadvantage in a mature play like the South Texas Vicksburg.

Drilling with casing while underbalanced is now used as acontingent plan in case of unanticipated problems rather thanincreasing the casing program size. This allows conventionalwell plans to be more aggressive and results in reduced costseven when drilling with casing is not needed.

No significant rig modifications were necessary to drillwith casing while underbalanced and nearly all the equipmentneeded was standard and readily available.

A 3-½” casing connection capable of handling high pressure gas production after being used in a drill string has been tested and utilized successfully in new well applications.

Drilling with a liner while underbalanced was done

successfully on one well but several problems wereexperienced. Drilling with liners has many of the potential benefits of drilling with casing, however, the current linerrunning systems need to be modified for drilling.

A limitation of drilling with casing while underbalancedis the inability to obtain open hole logs. In most cases inShell’s South Texas fields there is enough offset data to makean effective completion based on cased hole logging. In step-out or exploration drilling this is a significant limitation.

Before attempting drilling with casing underbalanced inother areas, note that the low permeability Vicksburg sands

allow a higher underbalance than would be possible in mosother applications.

AcknowledgementWe would like to express our appreciation to SEPCOmanagement for allowing this paper to be published.

References1. Tessari, R.M., SPE and Madell, Garret, SPE: “Casing

Drilling – A Revolutionary Approach to ReducingWell Costs” SPE 52789, presented at SPE/IADCDrilling Conference held in Amsterdam, Holland 911 March 1999.

2. de Leon Mojarro, Jose C., SPE, TerrazasMartin,SPE, Eljure, Abraham Julian, SPE: “Breakinga Paradigm: Drilling with Tubing Gas Wells” SPE40051, presented at SPE International PetroleumConference and Exhibition held in VillahermosaMexico 3-5 March, 1988.

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Figure 1 - a) Pre-1990 – Conventional tubing –packer completion,b) 1990-1994 - Commingled tubing –packer completion,c) 1994 – Present tubingless commingled completion

Figure 2 - (a) Failed well due to casing damage, (b) Well reentered and sidetracked

a) b)

5 ½”

3 ½”

13 3/8”

9 5/8”

7 5/8”

5”

c)

CasingDamage

CasingDamage

high pressure

high pressure

depleted

depleted

5” or 5-1/2”

2-7/8” casingin 3 7/8” or4 1/8” hole

a) b)

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SPE 84173 7

Figure 3 - (a) Reentry BHA prior to drilling with casing,(b) Reentry BHA used for drilling with casing while underbalanced

high pressure

depleted

9-5/8”

13-3/8”

7-5/8”

LCMsqueeze

Figure 4 – Well D. (a) Depleted sand with lost circulation problems squeezed off,(b) 3-½” casing string drilled into place while underbalanced and cemented

a) b) 3-1/2”

PDC Bit

Pony Drill CollarStabilizer

Drill Collar

Stabilizer

Ten Drill Collars

3 7/8” or 4 1/8” PDC Bit

Watermelon MillDrill Collar

Watermelon MillDrill Collar

340’

Bit sub w/ back pressure valve

Cement Plug Landing Collar

Drilling Landing Nipple

2 7/8”, 7.9#, RTS-6 Casing

2 7/8”, 8.7#, RTS-6Work String

100’

Flag Joints

Tubing stripperRemotely Operated

Flowline Valve

Rotate pipe during cementing,no centralization

a) b)

Pony Drill Collar

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Test samples @ 5400’

Test samples @ 500’

6-½” PDC

IBS Stabilizer1 – 4-¾” Drill Collar

IBS Stabilizer

5 - 4-¾” Drill Collars

200’

BHA

Test samples @ 10,800’

Figure 5 3- ”, 12.95#/ft, L-80, Hydril 533 Test Assembly

0

5000

10000

15000

20000

-300 -200 -100 0 100 200 300 400

Axial Load (Kips)

100% Pipe Body VME

95% Pipe Body VME

TensionCompression

Connection Test Envelopew/ 20 degree bending

Figure 6 – 3-½” Hydril 533 Connection Test

Pressure (PSI)

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SPE 84173 9

20

13-3/8”

11-¾”

7-5/8”

9-5/8”

5-½”

2-7/8”

3 depleted sands

high pressure

depleted

13-3/8”

9-5/8”

3-½” x 2-7/8”casing drilled in

high pressure

7-5/8”Fault Zone

5-½”

a b

Figure 8 – Well F. (a) Conventional well plan,b Drill with casin underbalanced well lan

13-3/8”

9-5/8”

7- 5/8”

3-½” X 2-7/8”

depleted

high pressure

10-¾”

7-5/8”

5” Liner Drilled in

3-½” x 2 -7/8”Drilled in

high pressure

shoeproblems

fault zone

a) b)

Fig. 7 – Well E. (a) Conventional well design in offset well,(b) New design - drilling with liner and drilling with casing while underbalanced

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10 SPE 84173

13-3/8”

9-5/8”

depleted

10- ¾”

7-5/8”

3-½”Tbg drilled in

highpressure

High pressure (T Sand)

a) b)

Fig. 9 – Well G. (a) Conventional well plan in offset well,(b) Drill with casing underbalanced well plan

Open hole logsrun to 11,800

prior to pickingup DWC Assy

13-3/8”

9-5/8”

7-5/8”

5-½”

3-½” x2-7/8” Casing

Depleted

High pressure

High

pressure

3-½”Casingdrilled in

Open hole logsrun to 13,320’

prior to pickingup DWC Assy

a) b)

Fig. 10 – Well H. (a) Conventional well plan in offset well,(b) Drill with casing underbalanced well plan

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