Formation Damage and Reservoir Considerations for Overbalanced andUnderbalanced CT OperationsD. Brant Bennion, F. Brent Thomas, A.K.M. Jamaluddin, T. Ma, and C. Agnew, Hycal Energy ResearchLaboratories Ltd.

Prepared for presentation at the 6th International Conference onCoiled Tubing Technologies to be held in Houston, Texas, Oct. 27-29, 1997

effects. This paper reviews why fonnation damage effects may bemore significant in horizontal versus vertical well applications. Italso reviews current technology levels to reduce fonnation damagein horizontal well applications as well as applications of CTdrilling technology to improve the perfonnance of underbalanced

drilling (UBD) operations.

Abstract

Horizontal drilling using coiled tubing is gaining widespreadfrequency throughout the world. Production results from manyhorizontal wells have been disappointing, and it is believed thatwhen this has occurred in situations where viable reservoir qualityhas been present, near wellbore fonnation damage effects havebeen a major contributor to the marginal flow perfonnance. Dueto the fact that most horizontal wells are completed in an open holefashion, even relatively shallow invasive near-wellbore damage(that would be penetrated by conventional perforation practices incased and cemented vertical completions) may substantiallyimpede flow. Drilling induced damage may include finesmobilization, invasion of mud solids, mechanical glazing, phasetrapping or chemical reactivity between invading fluids and thefonnation matrix or in-situ fluids. Underbalanced drilling isdiscussed as a solution to some horizontal well fonnation damageproblems, and the importance of maintaining a continuousunderbalance pressure condition during the entire drillingoperation to obtain optimum results is emphasized.

Mechanisms of Formation Damage During Drilling ofHorizontal and Vertical Wells

Mechanisms of fonnation damage which may be operative inreducing the productivity of horizontal and vertical wells havebeen discussed in the literature by various authors\).

These damage mechanisms can be grouped into several majorcategories, these being:

Fines Migration. Fines migration is the motion of naturally pre-existing particulate matter in the pore system. This may be inducedduring the drilling process by high fluid leakoff rates of water oroil-based mud filtrate into the near wellbore region caused byelevated hydrostatic overbalance pressures or excessively highunderbalance pressures3.

Introduction

Horizontal wells are in use throughout the world in an everincreasing fashion to attempt to increase production rates bymaximizing reservoir exposure, targeting multiple zones, reducingdrawdowns to minimize premature water or gas coning problems,exploit thin pay zones and, more recently, in such processes assteam-assisted gravity drainage and as injectors and producers insecondary and tertiary enhanced oil recovery processes.Underbalanced drilling using horizontal well technology has alsoincreased in frequency as a means of attempting to increaseproductivity from horizontal wells by reducing formation damage,improve ROP and reduce drilling and stuck pipe problems insevere lost circulation zones.

External DriJlingiMud Solids Invasion. The invasion of artificialmud solids (weighting agents, fluid loss agents or bridging agents),or naturally generated mud solids produced by bit-rock interactionsand not removed by surface solids control equipment into theformation during overbalanced drilling conditions2.

Phase Trapping. The loss of both water or oil based drilling mudfiltrate to the formation in the near wellbore region due to leakoffduring overbalanced drilling operations, or due to spontaneousimbibition in some situations during underbalanced drillingoperations4, can result in permanent entrapment of a portion or allof the invading fluid resulting in adverse relative permeabilityeffects which can reduce oil or gas permeability in the nearwellbore region5.

The use of conventional technology to drill and completehorizontal wells has resulted in disappointing results in manyapplications, due to what is believed to be formation damage

2; FORMATION DAMAGE AND RESERVOIR CONSmERATIONS FOR OVER/UNDERBALANCED cr OPERATIONS 57005

Chemical IncompatibUity of Invading Fluids with the In-situRock Matrix. Many fonnations contain potentially reactivematerial in-situ in the matrix, including reactive swelling clayssuch as smectite or mixed layer clays, and detlocculatablematerials such as kaolinite or other loosely attached fmes.Expansion or motion of these materials within the pore system,which may be induced by the invasion of non-equilibrium waterbased mud filtrates into the near wellbore region, can causeconsiderable reductions in permeability6.1...9.

Factors Which Will Tend to Increase the Severity of NearWellbore Damage

The overriding factor which will increase the severity of nearwellbore damage will be the extent of incursion of fluids and solidsinto the reservoir and how these materials will react with theformation once they come into contact with the rock matrix.

Factors which will tend to increase the fluid/solid lossperforDlance of a drilling mud in a horizontal drilling applicationmay include:Fluid-Fluid Incompatibility Effects Between Invadbrg Fluids and

In-Situ Fluids:. Oil or water based mud filtrates invading into thenear wellbore region during overbalanced drilling processes canreact adversely with in-situ hydrocarbons or waters present in thematrix with detrimental results which may reduce permeability.Problems would include the formation of insoluble precipitates orscales between incompatible waters, de-asphalting of the in-situcrude or hydrocarbon based drilling fluid caused by blending ofincompatible oils, or the formation of highly viscous stable waterin oil emulsions due to turbulent blending of invaded filtrates witheither in-situ water or oil.

Overbalance Pressure. The greater the density of the hydrostaticfluid column and resulting downhole pressure generated incomparison to the net effective reservoir pore pressure, the greaterthe tendency for losses of both fluids and mud solids to theformation. Highly weighted mud systems (due to either deliberatehigh concentrations of weighting agents for well control or poorsurface solids control resulting in a undesirable build-up of a highconcentration of dense natural silicate or carbonate basedformation drill solids in the fluid system), high backpressures ordrilling operations in significantly pressure depleted formations(particularly in deep zones) may a11 contribute to high overbalancepressures. Overbalance pressures in excess of about 7000 kPa(1000 psi) are generally considered to be severe and may causeserious losses of fIltrate and associated solids to the formation,particularly in zones of high reservoir quality.

Near WeUbore Wettobility Alteration and Surface AdsorptionEffects. Many drilling fluid additives used for mud rheology,stability, emulsion control, corrosion inhibition, torque reductionor lubricity contain polar surfactants or compounds which can bepreferentially adsorbed on the surface of the rock. The physicaladsorption of these compounds can cause reductions inpermeability by the physical occlusion of the pore system, in thecase of high molecular weight long chain polymers, particularly inlow permeability porous media where the small pore throats maybe easily bridged by long chain polymer molecules. Polarcompound adsorption may alter the wetting characteristics of thematrix in the near wellbore region, generally in most cases to apreferentially more oil-wet state. This causes a potentiallysignificant increase in water phase relative permeability in thisregion, which may adversely elevate producing water oil ratio forthe well if the completion is in a zone where a mobile watersaturation is present.

High Solids Content A high concenb"ation of artificial or naturalsolids in the mud system, which are inappropriately sized to fonDa low penneability filter cake, can either invade into the rockmatrix (if the solids are too small, that is, less than approximately300/0 of the median pore throat aperture), or may screen off on theformation face forming porous, high penneability, thick filtercakes which may result in long-tenD filtrate seepage and stuck pipeproblems if the solids are too large. For an open hole completionscenario, an appropriate size distribution of particulate matter inthe mud is essential to establish a sealing, low permeability filtercake rapidly on the face of the fonnation. This will minimizesolids invasion directly at the wellbore-fonnation interface whereit can be readily removed, either by direct mechanical backflow orsome type of very localized chemical or mechanical stimulationtreatment.

Mechanical Near WeUbore Damage E/fectJ. Mechanical actionof the bit, combined with fme cuttings, poor hole cleaning and apoorly centralized drill string may result in the formation of a thin"glaze" of low penneability surrounding the wellbore. Thisproblem is believed to be aggravated by straight gas drillingoperations, where a large amount of heat is generated at the rock-bit interface due to the poor heat transfer capacity of the gas baseddrilling fluid system in comparison to a conventional drilling fluid.Open hole completions in low permeability clastic formations tendto be the most probable candidates for this type of damage.Glazing will not generally occlude large penneability features,such as fractures or vugs, and the glaze is usually readilyremovable in carbonate based formations with a light acid washdue to its highly soluble nature.

Poor Fluid Rheology. The use of high API fluid loss, lowviscosity fluids will generally increase the potential for filtratelosses to the fonnation. Consideration is often given to the use ofso called "clear" fluids with no added solids in the hope that, if thebase fluid is compatible with the fonnation, no damage will occur,even if significant fluid losses occur during the drilling process.Unfortunately, the presence of naturally generated drill solids inclear fluid systems often results in near wellbore mechanicaldamage as large volumes of the base fluid, along with the ofteninappropriately sized naturally generated fmes from the drillingprocess, are carried off into the fonnation. The use of appropriate

viscosifiers/polymers can assist in the reduction of uncontrolledfluid losses to the fonnation in some cases, and should beevaluated for each specific situation under consideration.

damage, which may be insignificant in a cased and perforatedcompletion, can be very substantial in an open hole scenario.Other reasons contributing to increased severity of damage inhorizontal versus vertical wells could include:

Poor Base Fluid Compatibility. Even in the best designedoverbalanced drilling operation, and often in many so called"underbalanced" drilling operations, some unavoidable losses ofmud ftItrate to the formation occur. Shallow invasion may not besignificant for cased/perforated completions, but may be quiteproblematic for open hole situations. This being the case, it isusually prudent to design the base mud filtrate with fullcompatibility with the formation matrix in mind. This wouldinclude anticipating problems with reactive clays, in-situ fluids(emulsion potential and precipitation ability) and phase trapping(possibility of including 1FT reducing agents such as surfactants oralcohols to lessen the impact of phase trapping if fluid losses do

occur).

Greater Depth of Invasion. Drilling times for horizontal wells areusually greater than conventional vertical wells. Fluid exposuretime at the heel of the well may be significant if poor mudrheology is present in an overbalanced condition, or if the mudfilter cake is continuously disturbed by a poorly centralized drillstring or multiple tripping operations, invasion depth of damagingmud filtrate and solids into the near wellbore region may besubstantially greater than in a conventional vertical well

application.

Selective Cleanup/Damage. The large exposed length of ahorizontal well often results in zones of highly variable reservoirquality being penetrated. High peTDleability streaks maypreferentially clean up upon drawdown resulting in minimaldrawdown pressure being applied to more heavily damaged andinvaded portions of the well, making it difficult to obtain aneffectual cleanup. Production logs on horizontal wells oftenindicate the majority of the produced fluid is being sourced fromonly a very small section of the total length of the well.

Presence of Zones of Extreme Permeability. Fluid losses andpotential dantage will generally be more significant in zones ofhigh permeability, such as high perm intercrystalline streaks,fractures or interconnected vugular porosity which may bepenetrated by the horizontal well. Conversely, if invasion depth isnot too significant, these zones may be the most forgiving and easyto clean up in some respects due to more favourable capillarypressure relations and larger pore sizes. DiffICulty of Stimulation. Damaged vertical wells may often be

effectively stimulated economically using a variety of penetrativetechniques such as hydraulic or acid fracturing, acid or other typesof chemical squeezes, heat treatments, etc. These types ofprocesses are not readily economically applied to horizontal wellsdue to cost and technical considerations associated with attemptingto stimulate a section hundreds of meters in lengili (instead of onlya few meters in length as often is the case in a vertical well).Therefore, most horizontal well stimulation treatments tend to berelatively non-invasive in nature, such as acid washes, and mayonly be effective in penetrating shallow near wellbore damage.

Why is Damage More of a Concern in Horizontal VersusVertical Wells?

There are a number of reasons why horizontal wells appear tobe more susceptible to formation damage than their vertical wellcounterparts. One of the major reasons is related to the completionpractices used for most horizontal wells. The fact is that themajority of horizontal wells are completed in either a direct openhole fashion, or with some type of slotted or prepacked liner,which, as far as produced fluids are concerned, is equivalent to anopen hole completion. This is in comparison to vertical wellswhere most of the wells are cased, cemented and perforated. Onecan thus see that a degree of relatively small invasive formationdamage, several centimetres in depth about a vertical wellbore maybe insignificant, as a nonnal perforation charge will penetratebeyond the damaged wne and access undamaged reservoir matrixto facilitate reasonable production rates if a permeable formationis present. Many types of damage, such as solids invasion, do, infact, tend to be very localized about the wellbore in this limitedtype of radius, particularly in the absence of wnes of extremepermeability (such has highly fractured or vugular porosity

systems).

Anisotropic Flow- The flow patterns into a horizontal well arecompletely different than a vertical well, this is schematicallyillustrated as Figure I. It can be seen that a vertical well in auniform strata of cross bedded planes which it penetrates in anorthogonal fashion will drain the reservoir in a uniform planarradial fashion. Conversely, a horizontal well sources fluids fromboth the vertical and horizontal planar direction and hence is muchmore radically affected by variations in the vertical permeability ofthe reservoir. This shall be described in greater detail in thefollowing sections of the paper.

In a similar fashion, invasion occun-ing during an overbalanceddrilling operation is governed by directional permeability whichexists in the reservoir. This is illustrated for a vertical andhorizontal well as Figure 2. It can be seen that invasive damageabout a vertical well in a situation of uniform non directionalhorizontal permeability will be in a cylindrical pattern, with thedepth of invasion in an unimpeded fluid loss situation being

governed by the variable permeability of the strata underconsideration. In a horizontal well, due to the frequent anisotropy

It can be observed in an open hole horizontal completion,however, that the produced reservoir fluids must pass completelythrough the zone of damage which may have been created aboutdie wellbore during the drilling process. Aldiough shallow in somecases, the penneability of this affected zone may be extremely low,

creating a very high zone of what is referred to as "skin" damageabout the wellbore. Thus, even relatively shallow invasive

4 !ORMAnON DAMAGE AND_RESERVOIR CONSmERA~ONS FOR OVER/UNDERBALANCED CT OPE~nONS 57005

of horizontal versus vertical penneability in many reservoirsystems, the invasion pattern will be elliptical in nature, with thedirection of the primary axis of the invasion ellipsoid beingoriented in the direction of highest penneability.

technology for drilling reduces problems associated withinexperienced crews implementing the relatively new technologyof coiled tubing drilling. In addition, coiled tubing drillingtechnology is currently limited at approximately 2500 ft. ofhorizontal outreach and relatively small hole sizes in order tomaintain sufficiently high annular velocity for adequate holecleaning purposes. High frictional losses, associated with thenecessity of injecting fluid through the entire length of the coiledtubing string at all times, may also be problematic.

Underbalanced Drilling

The previous discussion illustrated that near wellbore skindamage in a horizontal well can significantly reduce productivityto the point where, in some situations, the wells are uneconomic.Much of this damage is associated with invasion of fluids andsolids during the conventional overbalanced drilling process.Underbalanced drilling has been used in recent years as a means toattempt to reduce invasive formation damage and improve theproductivity of wells in high damage/high fluid loss pronescenarios. Success with underbalanced drilling operations hasbeen mixed, primarily due to misapplication of the technology inmany situations and a failure to maintain a continuouslyunderbalanced condition at all times during the drilling operation.Since no protective filter cake is formed during a properlyexecuted underbalanced operation, due to a net outflow of fluidsfrom the formation, even relatively short periods of periodicoverbalance pressure can result in significant invasion of fluids andsolids into the formation and severe damage, sometimes of greatermagnitude than would have occurred if a well designed andconceived overbalanced system with good fluid loss control hadbeen used in the same situation (Figure 3). In certain conditions,damage may occur due to countercurrent imbibition, gravitydrainage, mechanical glazing or drawdown effects, even if acontinuously underbalanced condition is maintained during thedrilling operation. A detailed discussion of problems associatedwith many underbalanced drilling operations and suggestedscreening criteria for the proper design of an underbalanceddrilling program is contained in the literature 4.12.13.

Jointed Pipe vs Coiled Tubing For Underbalanced Drilling

The vast majority of wells drilled using underbalancedtechnology have utilized conventional jointed pipe technology androtary rigs. More than 85% of the wells drilled using the "artificial"underbalanced type technology in Canada have been drilled usingconventional jointed pipe. The fraction is even greater if low headand flow drill applications are considered on a worldwide basis.Major advantages and disadvantages with respect to coiled tubingvs jointed pipe applications can be summarized into the following

categories:

2.3.4.5.6.7.8.9.

10.11.12.13.14.15.16.17.18.19.20.21.22.23.24.

The Use of CT in UBD Operations

Coiled tubing has been used with increasing frequency in someunderbalanced drilling (UBD) situations because of perceivedsuperiority to conventional jointed pipe drilling technology. Muchof the success of an underbalanced drilling operation centres on theability to maintain an underbalanced condition on a continuousbasis, transmit effective survey and pressure data back to thesurface in a unremitting fashion during the underbalanced drillingoperation, clean the hole effectively and operate in a safe fashionwith potentially high flow pressures at surface. Coiled tubing hasdistinct advantages in these areas over conventional jointed pipedue to the lack of requirements for connections, use of an internalwireline and capillaries for survey and geosteering purposes, andmuch higher operating surface pressure limitations thanconventional jointed pipe.

Safety and surface pressure control issuesContinuous BHP maintenance issuesRate of penetration issuesHole cleaning issuesTotal drilling time issuesContinuous circulation issuesMud spillage and environmental issuesMWD capabilities

Rig/site considerations, footprintSurface hole/casing considerationsHole size limitationsDepth limitationsRotation issuesTorque, drag and weight on bit issuesDownhole motor issuesTubing life limitationsTorque limitationsFlow hydraulics limitationsOrientation and steering difficultiesBRA considerationsAvailability issuesExperience issuesEconomics

Hybrid rig applicatjons

Some of the more significant of these areas with respect tofonnation damage issues will now be discussed in detail.

Continuous Maintenance of an Underbalanced BottomholePressure Condition

Jointed pipe, however, is much less expensive to utilize and isreadily available. Also, increasing experience and modificationsin technology (such as EMT surveying tools) have reduced or

eliminated many of the problems initially associated widt its usefor UBD applications. The common application of jointed pipe

One of the main motivations for underbalanced drilling, inmany situations, is the elimination or minimization of invasiveformation damage caused by fluid and solids losses to theformation under conventional overbalanced conditions. Much of

this benefit is negated if the underbalance pressure condition isperiodically compromised IS. This phenomena is schematicallyillustrated as Figure 3. Coiled tubing has a major advantage overjointed pipe in dtis case, due to the fact that there is no necessity tobreak for connections. If standpipe injection of the non-condensible gas being used to generate an artificially generatedunderbalance pressure condition is occurring, this may result inbottomhole pressure fluctuations which may, if improperlyhandled, result in conditions of periodic hydrostatic overbalancepressure being encountered downhole. This may negate much ofthe benefit of the UBD operation (with respect to formation

damage minimization). Damage may actually be worse in somecases in comparison to the same situation than if a well-designedoverbalanced drilling fluid (which has the capability to form astable and bridging and, hopefully, readily removable filter cake)had been utilized.

Hole Cleaning Issues

Hole cleaning presents a major problem in many UBDoperations. Hole cleaning is affected by fluid rheology, cuttingssize and concentration (which is in turn a function of bit type andROP) and annular fluid velocity. The majority of CT operations areconducted using 2" or smaller CT strings, whereas hole size can be6.25" or larger. This may result in high pump rates and frictionallosses in the CT string being required in order to maintainsufficient annular velocity to maintain effective hole cleaning.Inability to rotate coiled tubing may further exacerbate theproblems with hole cleaning. The use of larger CT strings (toreduce frictional drop in the string and increase correspondingannular velocity due to a reduction in annular size) may be useful.Increased use of aggressive bits (such as POC's) to reduce cuttingssize may also be useful, but may be offset by problems with torquegeneration and high amplitude torque variation.

Bottomhole pressure fluctuations using jointed pipe can beminimized by making fewer connections (drilling with double ortriple pipe stands - triples are becoming more common with the

increasing use of top drive rigs for UBD jointed pipe applications),faster connections, circulating to pure gas to attempt to unload asmuch fluid from the horizontal and annular section as possibleprior to making a connection, and leaving the annulus open duringconnections to allow bleedoffto prevent rapid fluid fallback in thevertical annular section of the wellbore. Bottomhole pressurefluctuations, however, in situations where significant volumes ofliquid are being produced from the formation, can be minimizedthrough application of these techniques but not totally avoided.

The ability to continually or periodically rotate conventionaljointed pipe may result in superior hole cleaning ability due tokeeping a competent cuttings bed from forming. Working the CTstring may also assist in hole cleaning ability in certain situations.Many CT applications for UBD are drilled slim hole which reducesthe problems associated with low annular fluid velocities in thehorizontal section, although problems may still be apparent inlarger diameter uphole sections. The concentration of largeamounts of drill solids in the hole, if the UBD condition iscompromised, may increase near-wellbore invasive damagecharacteristics.

Alternate injection configurations, such a parasite tubing stringor microannular injection techniques (see Figures 4 and 5) canprovide stable and unjfonn bottomhole pressure profiles for jointedpipe operations similar to those seen during CT operations. Thesemodified UBD operations increase expense of the well, however,both from an equipment perspective and also operationally due tothe fact that more non-condensible gas is required to maintain thesame bottomhole pressure in a concentric or parasite stringapplication in comparison to a standpipe jnjection mode in thesame situation.

Total Drilling Time

Drilling times may be reduced using CT due to the fact thattime for connections may account for up to 25% of the totaldrilling time (in soft fonnation applications) when drilling withconventional jointed pipe. Since connections are not required fora CT application, this represents direct reduced drilling time andcost savings for the drilling operation. CT can also be tripped muchfaster than conventional jointed pipe, which may also reduce on-site time if multiple trips are required in a particular job. Areduction in exposure time limits potential for invasivedamage/imbibition to occur.Rate of Penetration (ROP) Issues

Generally, ROP is significantly increased by UBD operations.All factors being equal, ROP increases in CT vs jointed pipeoperations are comparable, but this assumes that equivalent holesize, weight on bit, torque and drag considerations, etc. are presentwhich is often not the case as will be discussed shortly. ROP maybe compromised in some CT applications, particularly in extendedreach applications, due to the fact that limited weight can beapplied to the bit by the action of the CT injector at surface, andmuch of this force may be expended in drag effects as the CTstring is forced around the horizontal bend and down the helicalwell path that is typically generated when attempting to drillhorizontally with CT.

Continuous Circulation Issues

Due to the nature of coiled tubing, continuous circulation ispossible both while drilling ahead, and also while tripping. Theadvantages of continuous circulation in maintaining a uniformBHP while drilling have been discussed previously. The ability tocontinuously circulate with CT while tripping, in general, reducesreaming requirements, allows for backreaming, while tripping out(if required) and allows the hole to be cleaned and maintained ina better condition.

Depth Limitations and limited life of CT strings may often adversely affect theeconomics of a CT drilling application in comparison toconventional drilling with jointed pipe. The large number ofdepreciated and readily available land rigs which can be used forUBD operations may often make CT an uneconomic alternative inmany UBD cases. An increased number of CT units will foster amore competitive market with more depreciated equipment whichmay aid in reducing costs and improving the economics of CTdrilling in comparison to jointed pipe in some situations.

Coiled tubing, due to the inherent helical bucklingcharacteristics and limited power of the surface injector heads, iscwrently limited by both depth and horizontal outreach. Maximumhorizontal outreach with current levels of technology is in therange of2500 ft., which severely limits the use ofCT applicationsin many horizontal situations where extended reach wells arerequired due to reservoir or surface location considerations orconstraints.

Hybrid RigsCurrent research into the use of CT tractor units, which can be

used to apply weight on bit in CT drilling applications, and the useof larger CT strings, may extend the reach capability of CT in thefuture, but this currently remains one area in which conventionaldrill pipe exhibits considerable advantages over CT.

There has been interest in the development of hybrid drillingrigs which incorporate the desirable features of both jointed pipeand CT drilling applications into a single unit. This is particularlyappealing in some offshore applications where very limitedfootprint size is available for a given drilling operation. Onceagain, the cost of development and construction of these hybridrigs may make their initial use prohibitively expensive except incertain special applications.

Rotation Issues

A major disadvantage of CT over jointed pipe is that CTcannot be rotated. This means than a CT drilling operation isoperated in a continuous sliding mode which results inconsiderable associated frictional drag effects and a reducedeffective weight on bit, reduction in ROP and reduced outreach forhorizontal applications. There may also be the need to add frictionreducers to the drilling fluid to aid in the smooth operation of theCT drilling program. This increases the cost of the program, andmany friction reducers can adversely affect the formation if theunderbalance pressure condition is comprised and fluids are lost tothe reservoir matrix.

Conclusions

The use of coiled tubing for overbalanced or underbalanceddrilling of vertical and horizontal wells may result in a reductionoffonnation damage in specific situations. Particular applicationfor coiled tubing drilling occurs in situations where underbalanceddrilling is under consideration, as coiled tubing has specificadvantages with respect to the continuous maintenance of a moreunifonn, underbalanced bottomhole pressure condition as well asthe ability to continuously circulate the hole while faster trippingtimes and the ability to run an internal water line for lessproblematic MWD problems during horizontal underbalanced

applications.

Availability Issues

In many cases, CT drilling for an underbalanced drillingapplication is desirable, but a shortage of suitable CT units for theparticular application under consideration, in comparison toconventional jointed pipe rigs, occurs. This results in manyapplications of jointed pipe technology where CT may have beensuperior, due to simple availability constraints. As more CTdrilling units become available, this issue may become less

problematic.

Potential disadvantages associated with CT, particular forunderbalanced drilling, may be related to poorer hole cleaningability with limited diameter CT strings and a greater propensityfor potential damage and limited horizontal outreach associatedwith current CT technology.

AcknowledgementsExperience Issues

The authors express appreciation to Vivian Whiting andRosemary Everett for their assistance in the preparation of themanuscript and the figures, and to Hycal Energy ResearchLaboratories for the funding of this work and permission to presentthe data.

Although there are many experienced coiled tubing operators,there are few highly experienced coiled tubing drilling operators,especially for UBD applications. This results in problems in manyapplications with undertrained crews attempting to operateequipment in a highly non-standard situation which can result inless than optimal perfonnance and results. Once again, as more CTdrilling units come into the market and the number of CT drillingoperations increases, the mean expertise level ofCT drilling crewswill increase.

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