lADC/SPE 35102

Advanced Torque and Drag Considerations in Extended-Reach WellsM.L. Payne,* ARCO E&P Technology, and F. Abbassian,*** BP Exploration

‘SPE Members““IADC Member

Copyr,ght 1996, IADCISPE Dr,llmg ConferenceThis papel was prepared 10, pmsenlal(on al the 1996 IADCE3PE Dr,llmg Conference held nNew Orleans, Lo. wa.a 12-15 March 1996

This paper was selec!ed for presenta!,on by the IAOCISPE Prog(am Comrmrtee lollow,ngreview 01 mfmmatlon contafned m an abslracl submmed by the a.lhor[s) Ccmtems of Ihepaper as presenled have not been re.lewed by Ihe SocIeIy of Petroleum EogIneers or IheIntematonal Assoc,a[,on of DrWng Contractors and are subject to correcwm by the author(s)The matertal as pmse”!ed dces not necessarily rellecl any Wst,on of lhe IAOC or SPE, lhe,rolf,cers o, members Papers p,esented at IADCISPE meOt,ngs are sublect to p. blmat,onrevxew by Ed, tor, al Commd!ee 01 the IADC and SPE Perm(ss, on 10 cop N resmcled m anabslract of not more than 300 words Illuslral, ons may not be coped {he abstract shouldconla,n conspicuous acknowledgement of where and by whom !he paper was pressnledWr,te L,branan, SPE, P O Box 633386, I%chardsm TX 75083.3836 U S A

AbstractExcessive torque and drag can be critical limitations inExtended-Reach Drilling (ERD). This paper details issues

related to torque and drag prediction, monitoring, and

management in ERD wells, Results are presented from

sensitivity analyses of extreme ERD trajectories such as 7 to 8

km departures at 1600 m TVD. Several such wells have now

been successfully drilled at BP’s Wytch Farm oil-field using

results from these studies. [n such high-angle ERD wells,compression generated in the drillpipe during tripping and

sliding operations can exceed the critical buckling load and

cause the drillpipe to buckle, As a result, buckling initiation

and post-buckling analyses are used to quanti@ the extent andseverity of buckling and the associated increases in drag forces

and pipe stresses. The paper addresses the importance ofdrilling data in calibrating torque/drag models in order to

capture the continual changes in drilling parameters andoperating conditions. The paper presents a number of field

case studies where analyses have been conducted to directly

assist drilling operations, This paper should be of high interestto engineers executing, planning, or evaluating ERD

operations.

IntroductionTorque and upward drag must be projected for ERD

operations to ensure the rig’s rotary and hoisting equipment

are adequately sized and the drillstring is properly designed.Downward drag must be projected to evaluate the limits for

sliding oriemed drilling motors and running tubulars. A key

aspect of these projections is to ensure good accuracy with

some level of conservatism, without incurring excessiveoverdesign. Various components can contribute to the buildupof both torque and drag in ERD operations. Identifying and

quantifying these distinct components is an important part of

properly projecting torque and drag. The acquisition and

analysis of field data is critical in this process. When careful

analysis and forecasting has identified torque or drag as alimiting factor, effective measures must be available to

alleviate the specific operational constraint. These measures

include both torque/drag reduction and alternative means to

achieve the desired operation.

Torque/drag has been addressed in various industry

publications over the years. This paper provides additional

understanding and observations on torque/drag issues as aresult of theoretical and empirical analyses of extreme ERD

operations. These analyses were performed in support of BP’s

Wytch Farm ERD development [ I -2], which has set a number

of world-record achievements. This paper presents both field

data and modeling predictions to convey key torque/drag

issues. Topics covered include torque/drag projection,

analysis, variability, control and management, In addition to

drilling torque/drag issues, the paper covers other important

operations such as liner rotation while cementing and

completion operations. The purpose of the paper is tohighlight key lessons and observations on torque and drag asthey impact world-class ERD operations.

General Torque and Drag Considerations for ERDFrictional and Mechanical Torques. The theory behindthe “soft-string” model for basic torque/drag prediction is well

known in the industry [3]. Proper application of the model

requires a full understanding of the factors influencing torque

and drag in the field. Total surface torque is comprised offrictional string torque, bit torque, mechanical torques, and

dynamic torques, Separating these components allows more

accurate definition of friction for torque projections and

allows proper prioritization for torque reduction measures.

Frictional torque is generated by contact loads between thedrillstring and casing or open-hole. The magnitude of contact

loads is determined by drillstring tension/compression, dogleg

severities, DP and hole size, drillstring weight, and inclination,

Profile optimisation and tortuosity control are therefore

important measures to minimize contact loads. Lubricity is a

major factor controlling friction, and is itself largely controlledby mud and formation types. With means of predicting bit

torque, tbe implications of using different bit types can beassessed. Dynamic torques can also significantly impact

operations and should be minimized [4]. Mechanical torquesources, such as cutting beds, borehole ledges, and stabilizer

effects can be very significant and must also be minimized.

References and illustrations at end of paper 503

2 ADVANCED TORQIJF AND DRAG CONSIDERATIONS IN FXTENDED-RFACH WFI LS IADCLSPF35 021

Drag and Buckling. Prediction ofupward drag poses issues

similar to torque prediction interms oftrajecto~ design, mudlubricity, wellbore condition, tortuosity, and mechanical

influences. Downward drag prediction in ERD wells

introduces a further level of complexity as a result of potential

buckling of the string under excessive axial compression.Buckling is an important consideration in ERD wells because

while tripping in or sliding, the drillstring and other tubulars

(e.g. liners, workstrings, tubing, perforating guns, Coil-tubing)are subjected to large compressive forces. Consequently,

many operations in ERD wells may result in buckling.

Buckling must be properly addressed to account for its impact

on drag and its elevation of drillstring stresses.

Fig. 1 illustrates string behavior under increasing compressive

loads. When compression is below the critical buckling load

[5-6], the string will sustain this compression without

buckling. Above the critical buckling load, the string bucklesinto sinusoidal or “snaky” buckling. This buckling condition

results in the string deforming into a snaky configuration

along the low-side of the well. For compression loads abovethe critical helical buckling load [7], the string can no longermaintain its snaky configuration and it coils up against thewellbore and helically buckles. String lock-up immediately

follows the onset of helical buckling due to a dramatic

increase in wall forces. Helical buckling should therefore be

avoided. In high inclination wells, the magnitude of thehelical buckling load (for a conventional drillstring) is very

high and hence its occurance is not common. It is thus thegrowth of the snaky buckling and the associated increase inwall forces which predominantly need to be quantified.

The severity of snaky buckling is quantified by how far fromlow-side (in degrees) the string is displaced. If the snaky

buckling amplitude remains below about 40°, the buckling is

generally tolerable and does not cause significant increases indrag. However, more severe sinusoidal buckling should be

avoided as it can cause large increases in wall forces which

can also lead to string lock-up or loss of surface string weight,Both sinusoidal and helical buckling impose additional

stresses in the string. However due to wellbore confinement,the string remains elastic and is not damaged (i.e. yield or

“corkscrew”) unless the hole section is heavily washed out.When rotating, string-wellbore axial friction is considerably

reduced and string buckling becomes less likely, although still

possible.

Fig. 2 illustrates typical buckling behavior in an ERD-typewell profile. Only the upper portion of the 80° tangent section

is shown where compression exceeds the critical bucklingload. Buckling extends from the 80° tangent, where

compression is a maximum up into the near-vertical section.

In the 80° section, stabilization forces due to high inclination

provide adequate support to restrain the buckling to the snakymode. In the build section, wellbore curvature provides

additional support restraining the buckling in that section to

the snaky mode and of less severity than the 80° tangentsection. Full helical buckling develops in the near-vertical

section where the string receives little support from the

wellbore. This helical buckling gradually disappears as the

neutral point is approached where compression in the string is

less than the critical buckling load.

Buckling in ERD wells cannot be avoided, so torque/drag

simulators must account for these behavior. ERD engineers

should become familiar with buckling and drag issues since

they must be properly analysed to assess whether problems

will result in terms of drag or string integrity.

Torque ProjectionDrilling Torques. For initial torque/drag simulations,

default friction factors can be used which have been derived

from analysis of historical well data within BP Exploration:

Cased-Hole Open-Hole

Mud Type Frlctlon Factor. .

Frlc~. .

WBM 0.24 0.29

OBM 0.17 0.21

Brine 0.30 0.30

In conventional wells, torque/drag predictions are typicallywithin 200/0 using the default friction factors, however torques

can vary substantially more in specific ERD operations.Deviations occur due to variations in lubricity, hole cleaning

efficiency, drillstring dynamics, surge/swab effects, and use of

torque reduction tools. Consequently in ERD wells, torque

projections should be based on an integrated approach which

utilizes field data to calibrate the predictive model. Drillingtorques should be measured, monitored, recorded, and, to theextent possible, compared with predictive models all in real-

time. Even in the absence of real-time model comparison,

torque trend deviations provide valuable early-warnings to

hole cleaning, bit/BHA, or wellbore stability problems.

Service companies provide surface torque monitoring with

comprehensive mud-logging systems. Enhancement of this

service by integrating surface measurements with downhole

torque-on-bit (DTOB) MWD measurements should be

considered. DTOB can provide key information on thecondition of the bit and motor and more accurate assessment

of string torque [8].

Lubricity should be distinctly defined for cased and open-hole

intervals of each section. Cased-hole friction should be based

on correlating torque measured at the shoe prior to drilling outand during subsequent bit runs. Open-hole friction factors

should be independently assessed based on the rate of torqueincrease with measured depth in the open-hole section,Distinct friction may also be imposed by different formations

and significant torque changes can be seen when abrasiveformations are encountered. During drilling the cased-holefriction factor may increase when cuttings are brought backinto the casing.

Fig. 3 shows a comparison of predicted and measured

drillstring torque in a 12. 1/4” section of an early Wytch Farm

ERD well. The modeled drillstring torque is based on actualwell parameters and the above default friction factors for

OBM. The measured data is based on surface torque

measurements corrected for DTOB. This “measured” string

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IADCISPF 35107 M, L. PAYNE, F. ABBASSIAN 3

torque is subject to some error since the surface torque

measurement occurs several times a second while DTOB is

only updated every MWD communication cycle, i.e. once per

30-45 seconds. Surface torques are averaged over the MWD

communication cycles, however because the surface andDTOB measurements are not synchronous, the string torque

cannot be measured exactly. The derived approximation,however, is the best available measurement and believed to be

reasonably accurate. In this figure, good agreement isobserved between the modeled drillstring torque and the

average measured data although there is data scatter above and

below the predicted trend line. Fig. 4 shows the same data

from the next ERD well drilled. In this figure, the field data

shows a substantial decrease in torque levels with the field

data falling well below the trend line established using thesame OBM default friction factors. Various improvements in

mud rheology and lubricity, hole cleaning, and drillingprocedures are responsible for the reduced drillstring torque

levels. This significant change over the course of only two

wells underscores the need for active and timely integration of

field data acquisition and analysis in an effective torque

prediction and reduction program.

Bit Torque Contribution, Bit torque models have been

developed for various bit types, predominantly based on lab

measurements. Actual bit torques vary dynamically and

substantially during drilling and are influenced by manyfactors. These include WOB, RPM, formation characteristics(shear and compressive strengths), PDC bit design variations,

bit wear, and hydraulics. Bit torque models can show

substantial inaccuracies in non-ductile formations such as

sandstones and carbonates since the ratio of shear to

penetration strength varies dramatically from those in ductile

shales which are used for most laboratory tests. PDC bits,which come in a wide variety of designs (i.e. cutter size and

orientation, body profile and hydraulic design) generally havehigher torques and higher torque/weight ratios and have notbeen studied as thoroughly as tri-cone bits. Finally, most bittorque models do not currently account for the effects of bitwear or bit cleaning hydraulics.

The implication of these issues for torque forecasting is that

bit torque models should be used carefully. A more empirical

approach is to use a conservative upper bound for bit torque,preferably from field data. Bit torque should be monitored in

ERD wells using a drilling mechanics sub in the MWD toprovide DTOB. Alternately, crude TOB measurements can be

taken by monitoring off-bottom and on-bottom surface

torques, although this is only approximate since WOB causesvariations in the drillstring tension/compression profile

affecting wall forces and hence string torque magnitude. Use

of an upper bound for TOB is conservative and appropriate for

torque forecasting. However, since the majority of surfacetorques from the field will be taken when DTOB is below this

upper bound, projections can appear inaccurate unless this

“safety margin” is recognized.

As an example of the impact of bit type on torque projection,Fig. 5 shows 12.1/4” surface torques from a recent North

Slope well. All bit runs in this section were tri-cone with the

exception of the bit run over the interval from about 13,100’-

14,050’. As clearly shown, the PDC bit run exhibits an offset

of about 5,000 ft-lbs relative to the tri-cone torque trends.

This torque increase is substantial, particularly for an ERD

operation approaching rotary or drillstring torsional limits.Also of interest in this figure is the erratic torques seen with

the tri-cone bit over the interval from about 1 I, 150’-12,100.This interval was accompanied by significant torsional

dynamics which as mentioned above elevate the normal torquetrend.

Variability of Friction Factors. Frictional torque is the

lowest torque associated with the drillstring rotating in a clean

wellbore with a specific mud. Analogously, frictional drag is

the lowest drag associated with drillstring pickup or slackoff.

Various mechanical effects can aggravate these optimal

situations and cause increases in torque/drag. These includecutting beds, sloughing formations, swelling clays, unstable

formations, and excessive drillstring-wellbore interaction (e.g.

stabilizer blades digging into formations, undergage bits

causing working of stabilizers, bit/BHA whirl). Measures can

be taken to minimize these mechanical effects, but they first

must be recognized. For this reason, approaches imvolving

the “lumping” of mechanical and frictional effects into singlefactors is discouraged. Higher flow rates, careful rheology

control, and drillstring rotation can improve hole cleaning tominimize cutting beds. Mechanical and chemical wellbore

stability analysis can result in mud weight/chemistry

recommendations to minimize instabilities. Identification of

excessive stabilizer torque can lead to better equipment

selection such as under-gauge stabilizers, reamers, etc.

As an example of mechanically-induced torque variations,

Fig. 6 shows maximum 8.1 /2” surface torques from severalrecent Wytch Farm wells. A fairly well defined 8.1/2” torque

trend is established by wells F19, F20, and F21. That torquetrend, however indicated a maximum drillable depth of about

6500m due to the top-drive limit of 45,000 ft-lbs. On WellM2, lost-circulation problems in the 8. 1/2” reservoir section

led to substantial additions of fibrous lost-circulation material(LCM). The LCM formed a low-side bed which in

combination with the OBM produced a much lower frictional

interface with the drillstring/BHA than the previous steel-

sandstone contact. The M2 torque “trend” is thus very

complex. The “trend” involves a cyclic process of drilling

open-hole reservoir (with the associated steep torque trend)followed by the conditioning of that open-hole section by first

cleaning the fine sand grain cuttings from the well while

simultaneously adding LCM (with an associated torquereduction). These behaviors underscore the variations in

torque that occur as a result of wellbore condition and the

dominant role that mechanical factors can play in torqueprojection over fi-ictional considerations.

Liner Torques During Cementing. A special torque

projection problem is posed for the rotation of production

liners during cementing. In many ERD wells, the trajectoryinc Iudes a high-angle or horizontal reservoir section. Rotation

of the liner during cementing is an effective mechanicalmeasure to promote good fluid displacements and enhance

505

4 VA T~ AN RA E-RAHW 1A 1

cement bonding. Rotation of the liner, however, requires an

accurate projection of torques that will be experienced in theliner, as well as the hanger, the running tool and the drillstring.

Fig. 7 shows surface torque measurements during the liner

cement job on Well F21. The projected torque schedule starts

at about 13 kfl-lbs and increases to a maximum of 20 kft-lbs

before ultimately falling to a surface torque of 10 kft-lbs. This

projection is based on a constant set of friction factors during

the cement job with torque variations caused by buoyancychanges from the various fluids being pumped. The predictedtorque increase from 13 to 20 kfl-lbs is caused by the liner

being filled with cement heavier than the OBM, while the

subsequent reduction is caused by the additional buoyancy as

that cement is displaced into the liner annuhss. After some

calibration, agreement was achieved between actual and

projected torques until the cement enters the annulus. A

discrepancy is then observed which is attributed to cement

effects in the annulus. This includes a general increase in

friction between the liner and centralizers as those oil-wet

interfaces are infiltrated by cement slurry. As shown in the

figure, the “cement torque” generates up to 8 kft-lbs ofadditional torque which was previously unrecognized. In

addition, a significant transient torque event is seen late in thecement displacement process. This torque spike is associatedwith the leading edge of the cement slurry passing by the liner

hanger area. The leading edge of the slurry has undoubtedly

picked up various solids as it passed along the annulus. In

addition, that interface could have been theologically affected

by mixing with the spacer and residual OBM. This torque

spike was evident for about 6 minutes during the displacementand it created a torque increase of 6-7 kft-lbs. On Well F21,

these two effects combined to produce torques 15 kft-lbs

above those projected.

As a result of these observations and a longer2,000-2,400 m

reservoir section planned for later wells, an upgrade program

was initiated with regard to the liner connections, liner hanger,

and liner running tools such that the entire system was rated to

20-24 kfl-lbs. in addition, work was undertaken to modifythe cement to a low-rheology blend and calibration analyses

were conducted for proper friction coefficients to account for

the cement torques. Fig. 8 shows the result of these efforts on

the Well M3 liner cement job. As shown, the torque

projection closely matches actual torques due to the updating

of the annulus friction coefficient from 0.13 (with OBM in the

annulus) to 0,40 as the cement is displaced. The benefit of

improved hole cleaning and the modified cement rheology is

also seen as only a small (1,800 ft-lb), transient (2 minute)

torque spike was seen during this cement job.

Drag ProjectionSome conventional toque/drag simulators assume thedrillstring remains unbuckled and are therefore Iimi ted to

modeling situations where there is no buckling. When critical

buckling loads are exceeded, the drag model must have more

sophisticated capabilities. These include buckling and post-

buckling analysis capability taking account of the 3-Dwellbore geometry, curvature and wellbore friction effects. A

drillstring buckling simulator has been developed by BP

Exploration specifically for ERD application which is capable

of predicting:

● The onset of sinusoidal/snaky buckling,● The transition from sinusoidal to helical buckling,● The extent of buckling, i.e. specific intervals where the

drillstring has buckled,● The severity of buckiing, i.e. sinusoidal or helical and

degrees of magnitude,● The associated wall forces and drag,● The onset of string lock-up or loss of surface string

weight, and● The resultant forces and stresses in the string

Fig. 9 shows results from a drag analysis of oriented drilling

in the 8. 1/2” reservoir section of one of the record-breaking

Wytch Farm ERD wells. Because of the extent of frictional

drag and the very challenging nature of providing WOB for

sliding, the specific operation analysed includes several stands

of drillcollars (DC) which were picked-up and run at surface.Irr addition, 30 klbs of traveling equipment weight,

specifically from the top-drive and swivel, is being applied tothe drillstring to assist sliding. This weight application wasconducted only after careful stress analysis of the involved

loading scenarios and various components’ capacities. As

shown, the applied surface compressive loads resulted in

substantial buckling in the drillstring. The DC at surface do

not buckle due to their substantial thickness and bending

stiffness. Immediately below the DC section, the 5.1/2” DPpartially buckles. The buckling mode in the 5. 1/2” section is

sinusoidal and varies in magnitude from 43° to 57°. A short

section of the 5. 1/2” DP does not buckle due to the additional

wellbore support provided by the curvature in the buildinterval. The 5” DP section buckles completely inside the

9,5/8” casing with a peak buckling magnitude of 74° in the

sinusoidal mode. The buckling of the 5“ DP ceases only

within the 8, 1/2” open-hole due to the higher inclination and

hence wellbore support in that section. Overall, about 75V0 ofthe drillstring is buckled according to this analysis. Despitethis significant buckling and associated increase in drag,

analysis indicated that sufficient compressive weight would beavailable to the bit, and oriented drilling was successfully

achieved in this extreme ERD profile.

Fig. 10 shows a composite buckling plot for the clean-out

string following the running and cementing of the 5.1 /2” liner

in the 8. I /2” reservoir section. The buckling magnitude is

plotted for a series of running depths from the initiation of

buckling in the drillstring until reaching TD. Buckling islimited to the 2.7/8” DP inside the 9.5/8” production casing.

The magnitude of the 2.7/8” buckling which is sinusoidalgrows up to a maximum of 70°. The maximum buckling

occurs when nearly all of the 2.7/8” DP is inside the horizontal

5. I /2” liner generating drag which must be sustained by thetop of the 2.7/8” DP in the 9.5/8” casing above the 5.1/2” liner,

Inside the 5.1 /2” liner, buckling is suppressed due to smaller

clearances and higher inclination.

Fig. 11 shows a buckling analysis for the perforating string.

Buckling is predicted to occur in both the 2.7/8” DP above the

506

lA13C/SPF 35102 M. L. PAYNE. F, ABBASSIAN 5

guns andintheupper portion of the gun string. The buckling

is sinusoidal andhasa maxim umampiitude ofabout70°. For

added assurance in this operation, the 2.7/8” DP section wasnot run and 3.1/2” DC were used instead to stiffen the section

above the guns and eliminate buckling. In addition, the

perforating gun connections were modified and torqued-up toincrease their bending rigidity as well as enable the

contingency action of rotating the perforating string ifrequired, Theperforating string was successfully run to the

target depth without rotation and no damage was incurred in

any of the string sections.

The cases described here involve buckling while sliding

strings. Buckling of rotated strings has also been reported in

extreme ERD wells [9]. Specifically, in some ERD wells with

deep 17. I /2” sections, drillstring buckling has been detectedwhile rotary drilling with a tri-cone bit under high WOB. The

buckling was detected due to higher than normal torques. In

order to complete the section while avoiding further buckling,

a PDC bit (which can drill with a lower WOB) was picked up

and thereby buckling was avoided. [n case of bucklingrotation should not be initiated until the buckling is relieved

by picking up and then reaming back to bottom. Rotating a

buckled string is not recommended as it can lead to high

bending stresses, severe dynamics, and twistoffs,

As a final drag example, Fig. 12 shows running weight for the

9.5/8” production casing. Running of the 9.5/8” does notintroduce any buckling due to the substantial bending stiffness

of the casing. However, the 9,5/8” casing running is a criticaloperation in these ERD wells and warrants discussion, As

shown in the figure, the casing down-weights were

significantly below and up-weights significantly above the

projected weights. As with drilling torques, mechanical

effects during casing running can dominate frictional effects,

[n this case, mechanically-induced weight losses due to

cuttings and wellbore sloughing reduce available runningweight by about 70 klbs near 2000m MD. At that point, a

casing circulating tool was used to circulate the casing whileworking the string. As shown, running weight was partially

regained, although it remained about 40 klbs below levels

projected from frictional considerations. Casing circulation

was used on several occasions during the casing running and

eventually casing running weight recovered to projected levels

below about 2700m MD, Because of the potential for seriousmechanically-induced weight losses, ERD casing runningprocedures should include contingency measures. This may

include circulation, utilization of top-drive weight, full orpartial flotation, and casing rotation. With proper engineering,

casing running systems can be designed to improve running

capabilities and achieve successful casing runs into extremeERD well profiles. At Wytch Farm, 9.518” casing has been

successfully run to 6,006 m MD (19,700’), which involved

5,164m ( 16,940’) of 12.1/4” open-hole section at 80-82° ofinclination.

Torque Control and Management MeasuresTorque reduction should not necessarily be pursued if theoperation has adequate drillstring and rotary capacity to

handle high torques. R here limits are being approached,

various measures may be pursued to reduce torque or to

improve the capacity of the limiting equipment. Cased-hole

torque reduction can be achieved with non-rotating DPprotectors (DPP). These DPP are ideally run over long

intervals where drillstring-casing contact loads are high.

Likewise, open-hole torque reduction can be achieved with

subs which involve a non-rotating metal sleeve mounted onbearings, Optimization of the well trajectory in terms of both

general design and execution can be critical to torque

reduction. This will be discussed in the last section of this

paper, increased mud lubricity and use of lubricants is another

torque reduction option. Effective lubricants are very limitedwhen OBM is already being used, however increasing the oil-

water ratio (OWR) can improve OBM lubricity, Lubricating

beads can reduce torques, but generally have to be continually

added due to difficulty in recovering the beads at surface. Asmentioned above, dramatic torque reductions of up to 30°/0

have been observed through the use of high concentrations of

fibrous lost-circulation materials (LCM) which appear to form

a low-side bed with much reduced fi-iction.

[n assessing torque reduction measures, the potential for

torsional dynamics in ERD wells must be recognized, [t is

recommended that measurements be taken to examine the

presence and magnitude of dynamic torques. If torsional

dynamics are present, a rotary feedback system should be

considered to dampen and reduce the dynamics. Rotaryfeedback systems have been shown to be successful inreducing torsional dynamics and thereby increasing available

drilling torque [4]. Alternately, some operations have reportedthat significant decoupling of bit and drillstring dynamics has

been provided by double or extended power-section drilling

motors. Bit selection and BHA design (particularly

stabilization) also affects the propensity for torsional

dynamics. The key is to be aware of the impact of torsional

dynamics, examine their presence via measurements and take

appropriate remedial actions [IO]. Drilling limits will be

determined by both mean and dynamic torque behaviors.

If the torsional drilling limitation is related to the drillstring as

opposed to the rig (i.e. top-drive), various means exist to

optimize the strength of an existing drillstring or to design an

enhanced drillstring [ 1 I]. Substantial increases in nominal

torsional capacity of existing drillstrings can be obtained

through tooljoint stress-balancing and use of high-frictionthread compounds. Where options exist for specific drillstring

design, consideration should be given to the use of high-torque

(double-shoulder) tooljoints and high-strength (higher than S-135) material grades. Aside from strength, proprietary

drillpipe is also available with integral blades to enhance hole

cleaning and thereby reduce mechanically induced torquesfrom cuttings.

Drag Control and Management MeasuresMeasures exist to both reduce drag and to develop improved

or alternative means of achieving the desired operation. Aswith torque reduction, optimization of mud lubricity , the use

of an optimized well profile, and the use of low-frictiondrillpipe protectors can reduce drag. If drag is beingexacerbated by drillstring buckling, consideration should be

507

given to optimizing the drillstring design to minimize buckling

severity. This can include the use of a tapered drillstringconfiguration.

Distinct from drag reduction, techniques are also available to

simply overcome existing drag. To allow oriented drilling,

running DC and/or HWDP in the near vertical well section can

provide increased string weight, Extensive hole-cleaning and

pipe working can temporarily improve the ability to slide in

extreme ERD profiles. In some operating areas, thrusters or

bumper ~ubs are used to improve WOB delivery while sliding.

The use of extended or double power section motors to

increase stalling resistance has also been reported as a

successful measure to improve the ability to drill oriented.

Traveling equipment weight can be used to push the drillstring

down and enable sliding. This action should be pursued only

after careful analysis of the operation and proper safetymeasures.

To increase feasable ERD drilling depth and efficiency,

consideration should be given to the use of rotary drilling

systems which enable inclination control without orienteddrilling. The high-variable gauge stabilizer is a major advancein this area [ 12, 13] and full rotary steerable drilling systemsare also being advanced in the industry [ 14, 15]. In terms of

general drag reduction, rotation is a virtual “cure-all” and

consideration should be given to qualifying any string forrotation which may impose a critical drag limitation. This will

clearly include liners, but can also include perforating, testing,

and completion strings. As mentioned previously, casing dragcan also be a critical limiting factor in ERD. Optimized float

shoes, casing circulating tools, casing flotation, and casingrotation schemes should be considered.

Wellbore Trajectory DesignWith a background established on the various operational

constraints associated with torque and drag, the issue of an

optimum wellbore trajectory can be considered. The impact

of trajectory design on torque and drag has been discussed

previously [16, 17]. There are various profile types that can bedrilled to an ERD target including build and hold, double

build, etc. The selection of a specific profile type and its

detailed design must consider many possible limitations andconstraints in addition to just torque and drag. Examples

include wellbore stability at specific inclinations and

azimuths, hole cleaning, geological sensitivities (problemshales, underpressured sands, salt sections, etc.), and anti-

collision requirements with respect to existing and futurewells, For all ERD well profiles, it is important for thetrajectory to be as smooth as possible with minimum doglegs.

Thus, the ability to achieve directional control in the specific

geology involved must be an integral part of the designprocess. To the fullest extent possible, BHAs should beplanned to achieve the desired buiM/tum tendencies with themaximum amount of rotary drilling. This tends to minimize

doglegs as well as promote better hole cleaning and ROP.

Intermittent sliding as a means of ongoing course correction is

still recommended over more dramatic single course

corrections. As a result, oriented BHAs remain preferred overrotary BHAs for ERD, but their optimum use is in rotary

drilling to the fullest extent possible. Rotary steerable drilling

systems, which remain under development, will have a major

impact on future ERD wells since they will provide idealdrilling systems in term of smooth wellbore curvatures via

continuous reaction to changes in directional tendency

changes while drilling.

With regard to torque and drag, the optimum profile is

dependent on both local friction factors and the specific

operation being considered. Because of variations in friction

factors between operating areas and even between different

sections in a single well, there is no single “optimum” profile

for a given ERD Reach-TVD objective. For example, the

optimum profile for running 9.5/8” casing and for oriented

drilling in 8.1 /2” reservoir hole (both critical to the ERD

objective) are probably different. To resolve these issues, well

operations need to be distinctly identified and prioritized withregard to how critical torque and drag may be for their

execution. An operational review list might include 12, 1/4”

drilling (rotary and oriented), 9.5/8” casing running (down-

weights and up-weights), 8.1 /2” drilling (rotary and oriented),

7“ or 5. 1/2” liner running (with and without rotation), coiled-

tubing operations (CBL, completion running, and productionlogging), and perforation, testing, and completion stringrunning (down-weights and up-weights). With operations

identified, prioritization and weighting of constraints can be

pursued. For example, if 12. 1/4” directional drilling behavior

can be correlated with BHA/formation data so that oriented

drilling requirements are minimized in that section, 12. I /4”

sliding may become a lower priority constraint. Similarly, ifthe production liner can be upgraded for rotation, drag issuesassociated with sliding the liner are of little consequence.

As an example profile study, Fig. 13 shows alternative well

trajectories which were studied in order to achieve 8km

departure at 1600m TVD at Wytch Farm. The trajectories are

categorized into three classes, namely high kick-off point

(KOP), 1ow-KOP, and inverted. All the trajectories involve

horizontal reservoir sections. Because of the extreme

departure objective, the inclination range between the high and

low KOP profiles is only from 79.5 to 82.7”. The inverted

profiles had inclination as low as 7f’ but were discounted dueto directional drilling concerns of getting back into thereservoir efficiently to start the horizontal. Optimization

among these ERD profiles was investigated throughtorque/drag sensitivity analyses of involved operations. A

central issue to the optimization is the inter-relationships

between inclination, drag and buckling at inclinations above

the critical angle. The critical angle is the angleabove which

pipe requires force to be pushed into the hole. In this region, alower inclination angle produces less drag, but allows more

severe buckling due to lower wellbore support. A higherinclination angle generates relatively higher drag, butrelatively lower buckling severity. The optimization is thus

dependent on quantifying these sensitivities. The resultsconfirm that the effect of the well trajectory is significant,

especially on drag levels while tripping/sliding. Furthermore,

the optimum profile does depend on the operation, e.g. forrunning 9.5/8” casing or maximizing coiled-tubing reach,

profiles with a high kick-off point (KOP) are prefemed, while

508

tiDCE E 35102P M. L, PAYNF F. ABBASSANI 7

for tripping/drilling in 8.1/2” hole, low KOP profiles arepreferred as summarized below:

Ion Optimum

Tripping 12. I/4” Hole High KOP

Running 9.5/8” Casing High KOP

Tripping 8.1/2” Hole Low KOP

Running 5.1/2” Liner Low KOP

Running Completion High KOP

Coiled-Tubing Ops High KOP

As a result of these findings and the operational priorities

developed at Wytch Farm, a high KOP well profile was used

for well M5, the industry’s first 8km departure well, which

achieved 8,035m departure at 1605m TVD in September

1995.

Conclusions and Recommendations1.

2.

3.

4.

5.

6.

Drilling torque must be analyzed by careful examinationof its various components - frictional string torquq bit

torque, dynamic torques and mechanically-induced

torques. Accurate torque assessment enables better torque

projection and more focused torque reduction actions.

String torque/drag should be analyzed based on

examination of distinct friction factors for the cased-holeand open-hole, Torque/drag friction factors can vary

significantly from defaults and should be derived from

field data for each hole section.

Bit torque while drilling will vary substantially and

dynamically. Bit torque models should be used withcaution unless validated by field data. The preferred

measurement is via a drilling mechanics sub in the MWD.

A conservative upper bound on bit torque should be usedfor projections, and the impact of bit type on torque trends

should be recognized.

Both cased-hole and open-hole friction factors can varysubstantially between wells and even in single hole

sections of a given well as a result of wellbore conditionwith regard to cutting beds, etc. Collection and analysis

of field data is critical to being able to quantify thesevariations.

Projecting torques during liner rotation while cementing

requires specific calibration of a torque model againstfield data, Cement-induced effects can substantially alter

frictional behavior in the liner and produce significant

mechanical torques. A conservative philosophy is thus

recommended with regard to ERD liner and running

string torsional capacity.

Drag prediction is dependent on accurate diagnosis of

frictional drag in the well and the extent of buckling in the

string. Moderate sinusoidal buckling can be tolerated and

does not lead to severe increases in drag. Extensive

helical buckling of the string should be avoided and canlead to severe drag and lock-up. Washout sections canresult in large deformation of the drillstring under

7.

8.

compression and can lead to damaged drillpipe.Washouts should be avoided for this and other reasons in

ERD operations.

Various measures are available to reduce torsional and

drag friction factors and to overcome existing torque/dragto achieve desired operations. ERD engineers should be

prepared with contingency measures to both reduce

torque/drag and use alternative procedures on operationswhere substantial risk of torquekirag constraints exists.

ERD well profile design and torque/drag behaviors are

interdependent. “Optimum” trajectories are dependent on

local friction factors and the specific operational

constraints imposed by the given well design and riglimitations. As a result, ERD well profiles must be

optimized in a focused fashion for-

objectives and operating environments.

specific target

Nomenclature

BHA - Bottom-Hole AssemblyDC - Drillcollar(s)

DP - Drillpipe

DPP - Drillpipe Protectors

DTOB - Downhole-measured Torque-on-Bit

ERD - Extended-Reach Drilling

HWDP - Heavy-Weight Drillpipe

KOP - Kick-Off PointLCM - Lost-Circulation Material

MD - Measured Depth

MWD - Measurement (Survey) While DrillingOBM - Oil-Based MudOWR - Oil-Water RatioPDC - Poly-Crystalline Diamond Compact Bits

ROP - Rate of Penetration

RPM - Revolutions Per Minute

TD - Total or Target DepthTOB - Torque-on-BitTVD - True Vertical Depth

WBM - Water-Based MudWOB - Weight-on-Bit

AcknowledgementsThe authors thank the respective managements of BP

Exploration Technology Provision and ARCO Exploration

and Production Technology for permission to prepare and

present this paper. The work of Colin Mason in performing

the buckling simulations described in this paper is gratefullyacknowledged, as is the work of Chris Brown in performing

the analysis of the field drilling data,

References

1, Payne, M. L., Cocking, D, A,, and Hatch, A. J,, “CriticalTechnologies for Success in Extended Reach Drilling”, SPE28293, presented at the 69th Annual SPE Fall Conference, 25-28September, 1994, New Orleans. Reprinted as SPE 30140 Briefby editorial selection, J9urnal of Petroleum Technology,February 1995,

509

B ADVANCED ORQUFAND DRAG CON=TIONS IN FXTFNDED-REACH WEIIST IADCJSPF 351.Q2

2

3.

4.

5.

6.

7.

8.

9.

10.

Cocking, D. A., Payne, M. L. and Hatch, A. J., “Extended ReachDrilling Eliminates Need for Artificial Island”, &bX&UDI

Eng neer Ini tem , Febuary 1995, pp. 33-38.

Child, A. J. and Cocking, D. A., “Drillstring Simulator ImprovesDrilling Performance”, ~ Gas Jouco.al, 28 August 1989, pp.41-47.

Payne, M. L., Abbassian, F., and Hatch, A. J., “DrillingDynamic Problems and Solutions for Extended-ReachOperations”, 1995 ASME ETCE, 30 January - 1 February,Houston, Texas.

Paslay, P. R. and Bogy, D.B., “The Stability of a Circular RodLaterally Constrained to be in Contact with an Inclined CircularCylinder”, ASME Transactions, JQUUQIof Aocdied MechaniU,Volume 31, 1964.

Dawson, R. and PaSlay, P. R., “Drill Pipe Buckling in InclinedHoles”, SPE 1I67, presented at the SPE Annual TechnicalConference and Exhibition, New Orleans, September, 1982.

Mitchell, R. F., “Effects of Well Deviation on HelicalBuckling”) SPE 29462, presented at the Production OperationsSymposium, Oklahoma City, April 1995.

Belaskie, J. P., McCann, D. P. and Leshikar, 1, F., “A PracticalMethod to Minimise Stuck Pipe Integrating Surface and MWDMeasurements”, IADC/SPE 27494, 1994 IADC/SPE DrillingConference, 15-18 February, 1994, Dallas, Texas.

Justad, T., et. al., “Extending Barriers to Develop a MarginalSatellite Field from an Existing Platform”, SPE 28294,presented at the 69th SPE Amual Technical Conference andExhibition, New Orleans, LA., 25-28 September, 1994.

Fear, M,, and Abbassian, F., ‘rExperience in the Detection andSuppression of Torsional Vibration from Mud Logging Data”,SPE 28908, Europec Conference, 25-27 October, 1994, London,

11.

12.

13.

14.

15.

16.

17.

Payne, M. L., Duxbury, J. K., and Martin, J. W., “DrillstringDesign Options for Extended-Reach Drilling Operations”, 1995ASME ETCE, 30 January - I February, Houston, Texas,

Odell, A. C., Payne, M. L. and Cocking, D. A., “Application of aHighly Variable Gauge Stabilizer at Wytch Farm to Extend theERD Envelope”, SPE 30462, presented at the 70th Annual SPEFall Conference, 22-25 October, 1995, Dallas, Texas.

Payne, M. L. , Wilton, B. S., and Ramos, G. G., “RecentAdvances and Emerging Technologies for Extended-ReachDrilling”, SPE 29920, presented at the 1995 SPE InternationalMeeting on Petroleum Engineering and Oil & Gas Exhibitionheld in Be~ing, Chin< 14-17 November 1995.

Barr, J. D., Clegg, J. M., and Russel, M. K., “Steerable RotaryDrilling with an Experimental System”, SPE/IADC 29382,presented at the 1995 SPE/lADC Drilling Conference, 28February -2 March, 1995, Amsterdam.

Donati, F., Oppelt, J., Ragnit~ D., Ligrone, A., and Calderoni,A., “New Concept Steerable Drilling Tools for Horizontal andERD Applications”, to be presented at the 3rd AnnualInternational Conference on Emerging Technologies,31 May -2June, 1995, Aberdeen, Scotland.

Sheppard, M. C., Wick, C. and Burgess, T., “Designing We[lPaths to Reduce Torque and Drag”, SPE Drilling Engineering,December, 1987.

Banks, S.M., Hogg, T. W., and Thorogood, J.T., “IncreasingExtended-RTeach Capabilities Through Wellbore ProfileOptimisation”, IADC/SPE 23850, presented at the IADC/SPEDrilling Conference, New Orleans, LA., February, 1992.

WOB) CrlUcal WOE)Hellcal

WOB ~

Fig. 1 - Drillstring Buckling Behavior under Increasing Compressive Load

510

IADCISPF 35107 M, L. PAYNE. F. ABBASS IAN 9

rl Helical buckling

.Y

Fig. 2 - Example Drilling Buckling Behavior in ERD-type Well Profile

m

,5

?0E

5M !C.m 1

.

. I 1..1. iI I I -. l-t

D ?Wa Z& &l &

Measured Depth [m)

Fig. 3 - Correlation of Drillstring Torque Predictions with Field DataSection

L

for 12.1/4”

Fig. 4 -

12.1/4”

o ,COl m mm

Mea3ur,d Oepth (m)

Overprediction of Drillstring TorqueSection

511

m

due to

5mo KcO

Improved Drilling Practices in

10 ADVA~.~ ND DRAG CONSIDERATIONS IN EXTFNDED.REACH WFI ~~sl(u

Fig. 5

Fig. 6 -Cuttings

4s 00

4000

3500~

T 30.00

! 2s,00

j’

E20.00

z~ 15.00

310.00

S.oo

000

10000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000

Dep;h [ft)

- Trends from Field Data showing PDC vs. Tricone Bit Torque Offset

a-1 1 f

A FIOTC..W9 Id@w -!,,/ 1To(w* trend m dkly hok

n- — A fm r-

d’

=i--0 F28 1-

. H, Wllc,w?0- 4

Complex 8.1/2” Section Torque Trends due to Mechanical Torques fromBuildup and Torque Reductions from LCM Additions

: \

“-= .1COmm

8 WW9

!0

5I I I r , !I+=l_l

0

0 20 40 80 m Im lm ill mmm (ml”)

Fig. 7 - Predicted vs. Actual Torques while Rotating Liner duringshowing Discrepancy due to Cement effects on Liner CentralizerMechanical Effect of Slurry Lead

CementingLubricity and

512

MA M ASSI

nm9 (ml.]

Fig. 8 - Predicted vs. Actual Torques while Rotating Liner during Cementingshowing Good Agreement as a result of Calibrating and Updating LinerCentralizer Lubricity.

m- m MIA

m- . r

Fig. 9 - Drag Analysis showing Buckling Severity for Oriented Drilling in 8.1/2”Reservoir Section

lm 1

1m

I 1I

m8

*SM. Cnna1

.,,.,...’.,.,.. . ;,, , t.lir w5’1.? w

.

20

10

0 + Ilx.1 37m m 41ca w am 4793 4m Blca SxO S5m

Maswod D9PUI[m)

Fig. 10 - Drag Analysis showing Buckling Severity for Running of Liner Clean-out String

513

12 ADVANCEDTORQUF ANDDRAGCONS IDFRATIONS INFXTFNDFD -REACH WELLS IADCISPF 351 Q

,?01

Zinw 90d10n

3s

: ‘“ - $$’

..,,! ::-,,.”. :.,

%

Q

. . ! v.

3*,. . ..

~~~= ‘i,

o ....20-- i . .;,. , ,.:..’,...

,. , . .‘,, : ..’,. .;..,

0<

Um 4X4 m MaocmacKm 7RV mm mm

U*..UA C+h(m)

Fig. 11 - Drag Analysis showing Buckling Severity for Running of PerforatingString

Owlwolm 2m0Mc.3m2.5@ 4m4w*

htonsurod Dtpth (m)

Fig. 12 - Predicted vs. Actual 9.5/8” Casing Running Weights showingMechanical Weight Losses much larger than Frictional Weight Losses

o-

KO -

UO

g-’0:

mm

azm

... ,

I 4m

Itm.. . . . . . . . . . . .... . .. . .—. ..-

Iloo* mm 20W Xa ,Cca w w K@ e

Horizontal Dlsplammml (m)

Fig. 13 - Various ERD Well Profiles for Analysis of Optimum Trajectory toAchieve 8 km Departure at 1600 m TVD at Wytch Farm

514