MicroTortuosity Drilling Problem

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Copyright 2001, SPE/IADC Drilling Conference

This paper was prepared for presentation at the SPE/IADC Drilling Conference held inAmsterdam, The Netherlands, 27 February1 March 2001.

This paper was selected for presentation by an SPE/IADC Program Committee followingreview of information contained in an abstract submitted by the author(s). Contents of thepaper, as presented, have not been reviewed by the Society of Petroleum Engineers or theInternational Association of Drilling Contractors and are subject to correction by the author(s).The material, as presented, does not necessarily reflect any position of the SPE or IADC,their officers, or members. Papers presented at the SPE/IADC meetings are subject topublication review by Editorial Committees of the SPE and IADC. Electronic reproduction,distribution, or storage of any part of this paper for commercial purposes without the written

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AbstractTortuosity is commonly defined as the amount by which the

actual well bore deviates from the planned trajectory.

Elimination of excessive tortuosity has been regarded as a

critical success factor in extended reach drilling operations.

In this paper the authors will refer to micro-tortuosity, not

measurable by survey data, in which the hole axis is a helix

instead of a straight line. It is argued that this is Lubinskis

crooked hole described in the early 1950s. The paper

presents a study of micro-tortuosity using field data from

hundreds of wells. The paper details how and why micro-

tortuosity occurs and the negative impact micro-tortuosity

can have on the entire drilling operation. The paper also

presents a solution that eliminates or drastically reduces

micro-tortuosity.

Field results will be presented to demonstrate that micro-

tortuosity is in fact the dominant component of the total

tortuosity.

IntroductionTortuosity has been recognized recently as one of the critical

factors in extended-reach well operations1,2,3

. The effects

include high torque and drag, poor hole cleaning, drillstringbuckling and loss of available drilled depth, etc.

Conventional wisdom has always held that tortuosity is most

often generated by steerable motors while attempting to

correct the actual well trajectory back to the planned

trajectory. However, in the early days of drilling in the mid-

continent area of the United States, drillers observed a

problem with running tubulars into wells. A vertical well

drilled with a 12-1/4 bit would not drift 12-1/4. This led

Lubinski et al.4,5

to develop a formula for determining t

minimum drift size for a hole drilled with a given collar a

bit combination (or the reverse). This became known as

crooked hole country formula. Thus there was ea

recognition of the potential for problems due to the fact th

the wellbore was not straight. This recognition predated t

first use of steerable motors by some 30 years.

Today, several types of drilling tools are targeted

achieving reduced hole tortuosity as measured by surv

data, with a view to reducing torque and drag. Obvio

examples are adjustable gauge stabilizers and adjustab

gauge motors, and, more recently, rotary steerable system

In parallel, it is commonly suggested that bent-housi

steerable motors increase tortuosity as measured by surv

data by mixing high dogleg sliding footage and low dog

rotating footage. In brief, low dogleg equals low torq

equals good, high dogleg equals high torque equals bad

Recent evidence suggests that any torque and drag benef

derived from reducing dogleg as measured by survey d

(macro-tortuosity) are likely to be completely overwhelm

by the torque and drag generated by poor wellbore qual

(micro-tortuosity).

In the last two years, over 200 wellbore sections have be

drilled using long gauge bits, primarily in pursuit of drilli

improvements broadly encompassed by the term h

quality. Most of these bits have been run on steerab

motors; some, on rotary steerable systems. Modeli

measuring, and comparing torque and drag values

sections drilled with long gauge bits and with short gau

bits immediately showed two surprising results. First, there

no dramatic difference between the resulting torque and dr

values for steerable motors versus rotary steerables wh

both use similar bits. Secondly, there is a signific

difference between torque and drag values for long gauge runs versus short gauge bit runs regardless of the meth

used to drive them. The use of long gauge bits also give

clear improvement in activities that might be expected

benefit from improved hole quality or reduced mic

tortuosity. These include hole cleaning, logging operatio

resultant log quality, casing runs, and cementing operations

Quantifying these differences by back-calculating t

friction factors commonly used in the torque and drag mo

SPE/IADC 67818

Tortuosity versus Micro-Tortuosity - Why Little Things Mean a LotTom M. Gaynor, David C-K Chen, Darren Stuart, and Blaine Comeaux, Sperry-Sun Drilling Services, a HalliburtonCompany


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2 T. M. GAYNOR, D. C-K CHEN, D. STUART, AND B. COMEAUX SPE/IADC 678

shows a general trend. The friction factors that give accurate

results for long gauge bits are much lower than the values

necessary for obtaining accurate results when using short

gauge bits. Coupled with the observable field results, this

suggests that attention to hole quality is likely to have a far

greater effect on well design limits, particularly in extended

reach drilling, than will minute attention to matching

directional survey results to the ideal well proposal.

Thus, we believe that micro-tortuosity is far more important

than the commonly known tortuosity in determining the

resulting torque and drag and overall wellbore quality. In

addition, we will show that micro-tortuosity is highly

dependent on the bit and we will discuss field results that

support the contentions above.

Tortuosity vs. Micro-TortuosityTo explain the difference between tortuosity and micro-

tortuosity, we will first explain how tortuosities are defined

and measured.

Planned Tortuosity (Tp) is the summation of the total

curvature (inclination and azimuth change) in the planned

wellbore divided by the well depth. The result can be

expressed by either the radius of curvature or, as its

reciprocal, in degrees per 100 feet so as to be consistent with

measurements of dogleg severity. For example, in a well that

builds from vertical to 60 degrees with no change in azimuth,

the total curvature is equal to 60 degrees. If the total depth of

the well is 10,000 feet (3,048 meters) the Planned Tortuosity

is 60/(10,000/100) or 0.6 degree/100 ft.

Tortuosity (T) is computed from the final well survey by

summing all the increments of curvature along the well and

dividing by the well depth (total tortuosity), then subtractingthe planned tortuosity. In conventional wisdom, tortuosity is

approximately the same as macro-tortuosity created by the

local dogleg severity associated with the use of steerable

motors attempting to maintain or correct the actual well

trajectory on course with the well plan. The recent

development of rotary steerable drilling systems was to

provide smooth wellbore curvature that potentially could

minimize all the tortuosity. Thus conventionally, the

tortuosity (T) of the wellbore is equal to the total tortuosity

(TT) minus planned tortuosity (Tp) or

T Macro-Tortuosity = TT - Tp (Conventional Wisdom)

In their paper describing wellbore profile optimization,

Banks, et al.1 stated that wells drilled without regard to

smoothness could have tortuosity values as high as

0.7/100 ft while smoother wells could have values

approaching 0.3/100 ft. The smoothness to which Banks,

et al. were referring had to do with the kinks imposed in

the process of trying to steer the well back to the desired well

plan with a steerable assembly.

Micro-Tortuosity (Tm) is defined as the tortuosity that occ

on a much smaller scale as compared to macro-tortuosity. W

will demonstrate that the primary source of micro-tortuos

is borehole spiraling, where the hole axis is helix instead o

straight line. (Despite this the authors have stuck with

commonly used term spiralling.) Micro-tortuosity diff

from macro-tortuosity in that (i) it occurs on conventio

assemblies as well as motor assemblies (and rotasteerables, for that matter), and (ii) it creates a unifo

spiraled wellbore that can only be detected by advanc

wireline survey techniques or MWD caliper tools. Unl

more randomly occurring (and easily measured) localiz

washout, a spiraled borehole can last several thousand f

and can occur across a range of different formations. T

effect of washout is therefore considered minor

comparison to the impact of thousands of feet of spiral

borehole. The authors also suggest that what has historica

been classified as rugose, corrugated, or ledged hole

more likely spiraled hole.

Spiral hole was first mentioned by MacDonald and Lubin

in a paper in 19514. They reported that a spiral hole, though

has no objective rate of change in angle, could devel

serious key seating difficulties, drill pipe wear

intermediate casing, etc. Lubinski used the term ti

spiral to emphasize the high torque and drag associated w

the spiraled wellbore.

We believe that the tortuosity (T) of the wellbore shou

consist of the macro-tortuosity and the micro-tortuosity as

T = Macro-Tortuosity + Micro-Tortuosity

In the past, the micro-tortuosity associated with a spira

hole has been lumped into the crude friction factor valuetorque and drag models. As a result, even with t

introduction of new rotary steerable drilling systems wh

should have minimized all the local dogleg severity (mac

tortuosity), the observed field friction factors are still mu

higher than the coefficient of friction between steel and ro

measured in a laboratory. This suggests that a signific

portion of the torque and drag created by micro-tortuos

still exists downhole. We believe that micro-tortuosity occ

in most of the wellbore in the form of hole spiraling. On

by recognizing and removing micro-tortuosity can one dril

truly smooth wellbore. Based on the above hypothesis, t

torque and drag (and the associated friction factor) in

wellbore with little to no micro-tortuosity should approachlevel that is lower than has ever been seen before. We w

demonstrate that in the following sections.

Mathematical Model of a Spiral HoleThe geometry of a spiral wellbore as defined in a Cartes

coordinate system is:

X= r *cos ------- (1)


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SPE/IADC 67818 TORTUOSITY VERSUS MICRO-TORTUOSITY - WHY LITTLE THINGS MEAN A LOT

Y = r *sin ------- (2)

and

Z = P*/(2) ------- (3)

In which r and P are the radius and pitch of the spiral,

respectively. The wellbore depth S can be calculated as

S = [P2+4

2r

2]

* z/P ------- (4)

and the curvature of the spiral hole can be expressed as

K = 4 2r / (P

2+4

2r

2) ------- (5)

Thus, for a typical 5 pitch and 0.5 radius helix, using Eq.

(5) the wellbore curvature K is calculated to be 0.0656 1/ft or

a dogleg severity of 376 deg/100.

Because of this high equivalent dogleg value, the drill collars

and drill pipe cannot possibly conform to the spiral. If the

BHA is slick, the collars will lie on the crests but tool joints

will tend to hang up. If the collars are stabilised, either theBHA distorts to accommodate micro-tortuosity or the

stabilisers attempt to ream the hole straight. Either way

increased torque and drag is probable and this is not

accounted for in T & D models

The collars will act to limit the amount of lateral movement

of the bit off the centerline of the hole. Thus the spiral

amplitude will be determined by the relative size of the bit

and collars. This is exactly the function described by Woods

and Lubinski5in determining the maximum wellbore drift

of a crooked hole. Lubinski calculated the maximum drift

created in a crooked hole as

Drift = (Bit Diameter + Collar Diameter) /2 ------- (6)

Figure 1 shows the two-dimensional schematic of Eq. (6) and

the drill collars in a spiral hole.

Figures 2 and 3 show two spiral borehole images taken from

the wireline CAST (Circumferential Acoustic Scanning Tool)

tool in a well in South America. The evidence of hole

spiraling is presented in the strong diagonal response of the

CAST images running across the compressed and expanded

2-D images presented in tracks 1 and 2. The reverse 3-D

image presented in track 3 clearly indicates the wellbore

spiraling while it was being drilled. Note that the spiral

seemed to change its direction from time to time and had a

pitch length was about 2 feet.

Figure 4 shows a spiral hole detected by a differential caliper

tool on a wireline density measurement at a well in Gulf of

Mexico. The log indicates that the hole is under gauge

approximately by 1.5 every 4 feet and rarely over gauge.

This phenomenon is repeated over thousands of feet on this

log. This section was drilled by a 9-7/8 bit and 6-3/4

collars. Using Eq. (6) the drift (new wellbore) is calculated

be 8.31, a 1.56(16%) reduction in wellbore OD which

exactly the same magnitude measured by the wireline to

The reduction in the cross section area (drift vs hole size)

calculated to be 22.32 in2(29%). As a comparison, Figure

shows a perfectly gauge hole drilled with a new steera

system (a matched long gauge bit and positive displacem

mud motor). The entire 12,000 ft interval was drilled in on2.7 days with no short trips

Although a spiral hole creates higher torque and drag, t

extra wellbore length due to spiraling is usually negligib

For example, using the same parameters above in Eq. (4), S

1.014 z, representing a 1.4% increase of wellbore leng

drilled by the bit. Only for cases of very large rad

clearances (17-1/2 bits and 9-1/2 collars) can the additio

length increase to perhaps 3%, or an extra 30 feet drilled p

1000 feet of hole.

Solution for Micro-Tortuosity: Long Gauge BitsThe ability of any bit to move off the centerline of t

wellbore is determined by the gauge length on the bit, t

amount of side cutting structure on the bit, and t

stabilization of the bit and BHA. Other factors may play

role in reducing the tendency to move off center, such

anti-whirl feature, but these factors are addressing sympto

rather than causes.

The concept of preventing side-cutting to improve ho

quality is not new as machinists have taken advantage of

for years. A conventional twist drill for drilling through me

is furnished with a cutting structure that cuts only in t

direction of the tools long axis, and the spiral flutes ser

only to stabilize the cutting structure, and burnish the sid

of the hole. Until the flutes begin to stabilize the cuttistructure, the drill will tend to precess in the same directi

as drill rotation. This can readily be observed using

domestic electric drill, and explains why the hole bei

drilled is often triangular until the stabilizing flutes begin

control this movement. If they did not exist, the drill wou

continue to precess, and the resulting hole would

triangular in section, following a helical path.

Since the mechanics that governs machining metal

identical to that in rock, there is no reason to expect th

preventing fixed cutter bits contacting the side of a wellbo

will have any different result. Any tour of a machine sh

will immediately reveal that a drill press, designed only cutting tools that do not side cut (twist drills or reamers)

relatively slender. Milling machines, designed to cope w

side-cutting tools, are massive, with stiff, well-support

spindles to give them the stiffness to resist side-cutti

forces. This offers a possible explanation for the observati

that PDC bit tests carried out in laboratories (on rigs that

much more like milling machines than like drilling rig

produce results that have never been seen in the field. A dr

string can never approach the lateral and torsional stiffness


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a milling machine. However, a drill press, designed only to

drill holes which is what we want to do has no great

torsional, and often very little lateral stiffness. Instead, the

cutting tool provides the solution. The drilling equivalent of a

twist drill is a long gauge bit.

There is now abundant evidence that hole spiraling exists,

whether this evidence is anecdotal, visual (from imagingtools) or by inductive reasoning from logs with an otherwise

inexplicable periodic variation or tools with an otherwise

inexplicable wear pattern. There is also abundant evidence

that long gauge bits minimize or more often eliminate hole

spiraling. Since the drilling industry depends on steering, if

long gauge bits do not steer then this piece of information

is interesting, but has no practical application. Once it is

discovered that long gauge bits can be made to steer, initially

on specially designed motors, and subsequently on point-the-

bit rotary steerable tools, then the information is worth re-

examining.

This solution can be demonstrated by recourse to Lubinskis

crooked hole equation in Eq. (6). It demonstrates that the

drift of a hole is controlled by the diameter of the drill collar

directly above the bit. A non-spiraled, high quality hole will

have a drift diameter equal to its gauge, presumed to be the

nominal bit diameter. It is easy to demonstrate that if the

collar directly above the bit is in fact the same diameter as

the bit, then drift equals hole gauge, and the hole must

possess no spiraling. Running 12 collars in 12 hole

would pose problems. Running a bit with a 12 sleeve

directly above the cutting structure (a long gauge bit) does

not.

When this thinking has been applied to oil field bit design,

the results have been surprising. Straighter holes haveresulted in friction factors that defy conventional

expectations. Bit life has been extended greatly. Circulation

time as a percent of below-rotary hours has been reduced to

10-12% on average, demonstrating the efficiency with which

the cuttings are being circulated out of the well. Short trips

have been reduced or eliminated. Log quality and ease of

running logging tools has been improved. Cement job

success rate has been nearly 100%, with cement bond logs to

demonstrate the high quality of the job. MWD and LWD

failures have been reduced due to the drastic reduction in

downhole vibration. Lost-in-Hole risk has been reduced.

Entire hole intervals have been drilled in record times

repeatedly.

It is important to note that the drilling system employed

required changes to the bit design as well as changes to the

positive displacement mud motor design.

While these benefits apply to the vast majority of wells being

drilled today, the reduction in friction delivered by this new

system is of particular value for pushing the extended reach

envelope even further than previously thought possible.

Quantifying Tortuosity and Micro-Tortuosity by thFriction FactorThere are several ways to quantify tortuosity, such as usi

the surface torque1or using the friction factor in the torq

and drag modeling as proposed in this paper. More than o

hundred wells have been analyzed where the friction fact

were back-calculated, that is, the value of friction fac

necessary to generate model results that matched observfield data was calculated. All of the wells were drilled w

conventional BHAs, including motor and rotary assemblie

Table 1 shows the results from the study. As can be se

from the table, the friction factors can vary considerab

depending on mud type and whether the hole is open

cased. The friction factors are normally less in casing than

open hole. It has always been assumed that this was d

primarily to the lower relative coefficient of friction betwe

steel on steel (drill pipe on casing) compared to steel on ro

(open hole). We propose that a larger effect is

elimination of micro-tortuosity (spiraling) once the casi

has been run. Our reasons for believing this will becom

clear shortly.

These friction factors have been used for some time now

the purpose of predicting torque and drag on planned we

However, with the introduction of this new positi

displacement mud motor and long gauge PDC bit drilli

system6, it became apparent that the generic friction fact

used for everyday wells were no longer applicable to we

drilled using this new system. The pick-up, slack-off a

torque values predicted using the conventional fricti

factors were considerably higher than those observed in t

field, indicating that the friction factors were set too high

accurate torque and drag prediction for the new drilli

system.

In order to improve predictions when designing future we

that would utilize this new drilling system, we analyz

several North Sea runs that had been drilled with the syst

to determine an accurate friction factor. We found that

wells drilled with the new system and using pseudo oil bas

mud, the average friction factor value was 0.12. T

compares to 0.17 for conventional assemblies with the sam

mud type, a dramatic 30% reduction. As can be seen fro

Tables 1 and 2, the open hole friction factor value using th

new system is actually lower than the calculated casi

friction factor in conventional assemblies. This was

surprising revelation. The authors suggest that the drmeasurements on which the casing friction factor is based

normally recorded soon after the casing is run, perhaps on t

shoe drill-out run. This initially high drag value can

expected to drop with every rotating hour as the inside of t

casing becomes polished. Hence the friction will reduce w

time giving a lower friction factor value. We have fou

from further study that the open hole friction factor using t

new system is almost identical to cased hole friction fac

after polishing, further proof that the reduction must be do


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to micro-tortuosity. Figures 6 and 7 show typical calculated

friction factor analyses using this new drilling system at two

North Sea wells.

In order to simulate tortuosity on well plans, a tortuosity

scale factor is applied to the back-calculated actual friction

factors (See Table 2). Normally for conventional assemblies,

Halliburton has used a tortuosity scale factor value of 1.34.Using this new drilling system, it was noted that the

tortuosity scale factor was reduced to 1.14. This would mean

that in our example of Pseudo Oil Based Mud the planning

friction factor when using this new system will only be 0.14

(0.12 x 1.14) asopposed to the normal value of 0.23(0.17x 1.34) for conventional assemblies.

Field Examples of Micro-TortuosityMicro-tortuosity affects almost every aspect of drilling and

completing a well. Due to space limitations we have focused

on the most important areas, based on the significance of the

impact on drilling time and cost.

Bit Life and MWD/LWD Tool ReliabilityBits that designed to cut away the side of the hole as well as

the hole in front of it tends to drill a spiral hole. They include

short gauge length bits or bits with side-cutting structure7.

These types of bit are also prone to vibrations and whirl.

As most drillers are aware that impact damage is a primary

cause of PDC bit damage. Thus, spiral hole is often

associated with bit vibrations resulting in shorter bit life.

The same vibration that destroys the bit also travels up the

drill string and can lead to a premature MWD/LWD failure.

By stopping the vibration before it can initiate, the

MWD/LWD system reliability should improve. Data from

multiple incidents where vibration-related failures have

occurred, utilizing the new drilling system has had a dramatic

impact on eliminating or reducing the frequency of tool

failure.

Hole CleaningDue to the rugosity of the spiral wellbore, cuttings will travel

a tortuous path and will encounter a trough every 2 to 10 feet

(dependent on the actual pitch of the spiral). This will lead to

additional circulating time as well as extra time for

backreaming and short trips in an attempt to dislodge the

trapped cuttings. When using the new drilling system

(utilizing the long gauge bit), entire intervals have been

drilled without short trips and with greatly reducedcirculating hours. In one instance, a 12,000-foot open hole

interval in the Gulf of Mexico was drilled with no short trips.

The entire interval was drilled in only 2.7 days.

ROPStabilizers will tend to hang up in a spiral hole, especially in

a non-rotating (sliding) mode. This mechanism explains

the reduction in sliding rates of penetration (ROP) relative to

rotating ROP that is generally recognized as a univer

phenomenon. If spiraling could be eliminated, one wo

expect to see a resulting increase in sliding ROP relative

rotating ROP. In fact, this is exactly what has been se

when using the new drilling system that utilizing the lo

gauge bit. In some areas sliding ROP has been increase

within 80% or more of the rotating ROP. Thus, the pena

for sliding is reduced. This opens the door for the directiodriller to spend more time keeping the well closer to the w

plan while achieving a respectable ROP, thus reducing t

macro-tortuosity in the well also.

Stabilizer WearStabilizer hang up in spiral holes would also result in t

excessive wear on the leading and trailing edge of stabiliz

that has been observed on numerous wells. This is the ar

that would contact the spiral every pitch, and also would t

out the new formation when backreaming is done. The sh

gauge bit that originally allowed the spiraling to occur wou

not perform this function, because at any point in the ho

the bit will prefer to follow the relatively gauge holeoriginally cut, and so will follow the spiral in and out of t

hole. The job of backreaming is left to the stabilizers. A k

identifier for spiralled hole is that stabiliser wear advanc

alongthe hole axis, notperpendicularto it.

Torque and DragThe torque and drag in the wellbore often determine t

success of drilling extended reach or horizontal wells. Torq

and drag data gathered from the new drilling system show

40% reduction in the friction factor value required for t

modeling. This is a result of eliminating micro-tortuosity.

Logging Tool ResponseSpiraled boreholes have long plagued wireline and LW

service companies and have led to totally ambiguo

responses from resistivity, density, neutron, and oth

logging sensors. This is due to the fact that the logging t

will be supported on the low side of the hole by the peaks

the spiral. If the hole is in fact spiraled instead of corrugat

then the opposing side of the hole will be in phase rath

than out of phase as would be expected for a corrugat

hole. In simple language this means that opposite every pe

on the low side will be a peak on the high side, not a valle

See Figures 1 to 3.

Figure 4 illustrates a spiral hole detected by a different

wireline caliper tool. The borehole fluctuates between almperfectly gauge and 1.5 under-gauge. This is due to the f

that the caliper arm is regularly moving from a peak to

valley on the high side. When it measures the peak, the t

has its back against the wall at that point, so the distance

exactly the bit diameter. At all other times its back

spanning the valley between two peaks, and it is therefo

unable to conform to the borehole center, and thus measure


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an undergauge hole. As a comparison, Figure 5 shows a

perfectly gauge hole drilled with the new steerable system.

CementingThe spiral borehole described above is equivalent to a

continuous thread in the well. As previously described, a

spiraled wellbore will have a drift diameter substantially less

than the bit gauge diameter. Running casing into a wellborewill create an annular space with a varying annular clearance

at any given cross section. This might not create too many

problems as long as it is not continuous. Unfortunately, by

definition the spiraled borehole is continuous. The

consequences of this are that there could potentially be an

area of minimum cement thickness that wraps around the

casing in a continuous path from shoe to shoe. There are no

cased hole logging tools in existence today that can measure

this feature in a cement job, so it has escaped detection so far.

Gravel PackingIn gravel packing wells, and especially inclined wells, a good

distribution of gravel over the entire gravel pack interval isthe design goal. A gravel pack screen that has been run in a

spiral wellbore faces the same annular clearance issues

described above. The tortuous path the gravel is required to

travel may well be the root cause of many of the early sand-

out problems that have been experienced.

Conclusions1. Tortuosity has been redefined as having two

components, macro- and micro-tortuosity. Macro-

tortuosity can be detected by examination of survey

results. Micro-tortuosity is a smaller scale of dogleg that

will not show up in MWD survey data. It can only be

definitively detected by advanced wireline survey

techniques or MWD caliper tools.

2. Micro-tortuosity commonly exists in the form of holespiraling. The pitch of the spiral appears to range

between 2 and 10 feet. Analysis of hundreds of wells

indicates that micro-tortuosity exists in many of the

wells being drilled today

3. Friction factors back-calculated in the torque and dragmodel are used to quantify the micro-tortuosity. The data

indicate that Micro-tortuosity is a very important

component in total tortuosity, perhaps even the dominant

component.

4. Many factors contribute to hole spiraling or micro-tortuosity but the most significant issue is the bit design.

There is abundant evidence that long gauge bits

eliminate hole spiraling. To exploit the benefits of long

gauge bits, a new motor system has been designed to be

able to steer the long gauge bit. The same benefits are

available from point-the-bit rotary steerable tools.

5. Field data using the new drilling system have shownmuch lower friction factor compared to that from a

existing drilling system. This suggests that only

removing micro-tortuosity, can one drill a truly smoo

wellbore, regardless of the technology employed to ste

the well.

6. By eliminating or reducing spiraling, nearly every faof the drilling operation is quantifiably improved. No

of these improvements can be realized by a likew

reduction in steering-related macro-tortuosity

7. Micro-tortuosity should be routinely considered torque and drag modeling exercises. Until then t

industry will make decisions on field development th

are based on ERD limits susceptible to drama

improvement at little cost.

AcknowledgementsThe authors would like to thank members of sen

management from Sperry-Sun and Halliburton Ener

Services for supporting the team during the development

the new drilling system and for permission to prepare a

present this paper.

References1. Banks, S. M., Hogg, T. W., and Thorogood, J. L., Increas

Extended-Reach Capabilities Through Wellbore ProOptimization, IADC/SPE #23850. 1992 IADC/SPE DrillConference in New Orleans, Louisiana.

2. Payne, M. L., and Abbassian, F. Advanced Torque and DConsiderations in Extended-Reach Wells IADC/SPE #3511996 IADC/SPE Drilling Conference in New Orlea

Louisiana.

3. Guild, G. J., Hill, T. H., and Summers, M. A. Designing aDrilling Extended Reach Wells, Petroleum Engin

International January 1995, pp35- pp41.

4. MacDonald, G. C., and Lubinski, A. Straight-Hole DrillingCrooked-Hole Country, Drilling and Production Practice, A

1951.

5. Woods, H. B. and Lubinski, A. How to Determine Best HAnd Drill-Collar Size, The Oil and Gas Journal, June 7, 195

6. Gaynor, T. M., Chen, D. C-K, Maranuk, C., and Pruitt, J. Improved Steerable System: Working Principles, Modeliand Testing, SPE #63248, 2000 SPE Annual TechniConference and Exhibition in Dallas, Texas.

7. Dykstra, M. W., Chen, D. C-K, Warren, T. M., and ZannoniA. Experimental Evaluations of Drill Bit and Drill StrDynamics, SPE 28323, 1994 SPE Annual Techni

Conference and Exhibition in New Orleans, Louisiana.


7/12


Table 1. Friction Factors from over 100 wells Drilled by Conventional Assemblies

Mud System Actual

Casing

F.F.

Planning

Casing

F.F.

Actual

Open Hole

F.F.

Planning

Open Hole

F.F.

Water Based

Generic 0.18 0.24 0.24 0.32

Polyseal / Barasilc 0.25 0.34 0.30 0.40

Thixal 0.22 0.29 0.27 0.36

Pure Oil Based

Generic

0.10 0.13 0.12 0.16

Pseudo Oil Based

Generic 0.15 0.20 0.17 0.23XP07 0.17 0.23 0.17 0.23

Petrofree 0.14 0.19 0.18 0.24

Ecomul 0.16 0.21 0.20 0.27

Table 2. Tortuosity Scale Factors and Friction Factors for the New Drilling System with Pseudo Oil Based Mud

Field HoleInc.

HoleSize

MD

MD In

MD

MD OutActualOpen

Hole F.F.

PlanningOpen Hole

F.F.

TortuosityScale

Factor

Comments

A 63 12 8817ft 18215ft 0.14 0.16 1.11 Friction Factor calculatedhigher than normal due

to effect of 6 5/8 drillpipe.

B 3-76 12 3010ft 9213ft 0.10 0.11 1.08

C 50-87 8 2906m 4040m 0.14 0.16 1.13 Offshore Germany well.

D 41-63 8 7818ft 11590ft 0.06 0.06 1.03

D 58-16 8 8619ft 12970ft 0.01 0.01 1.06

E 18-70 8 6544ft 10078ft 0.05 0.07 1.26

F 39-86 6 9990ft 13622ft 0.07 0.10 1.30 Torque showed 2200 ft-lbs. more than expected.

Probably miss-calibration.


8/12


Dbit

DDC

Ddrift

FIGURE 1- Relationship between bit diameter and drill collar diameter creating

a self-limiting system as per Lubinski. The drill collar diameter determines the

maximum lateral displacement of the bit from center. While superficially this

may appear to be simply the radial clearance, it is actually the radial clearance

divided by 2. Every displacement in one direction creates a limiting boundary

on the opposite side of the hole, so the net result is that the bit can only move

half of the radial clearance in any given direction. There is no logical reason for

this motion to be confined to two dimensions since it is created with a rotating

(360) drilling machine. Therefore it will naturally form a helix.


9/12


Figure 2 - Spiral Borehole #1 as shown by the 2D (Tracks 1 and 2) and 3D (Track 3) images obtained from a wireline CAST tool i

Well in South America. The section was between depth of 11,108 and 11,119. Note the spiral changed direction at the depth abo

11,115 and had a pitch about 2

Figure 3 - Spiral Borehole #2 as shown by the 2D (Tracks 1 and 2) and 3D (Track 3) images obtained from a wireline CAST tool i

Well in South America. The section was between depth of 11,183 and 11,194.


10/12


DIFF CALINCHES

20...20

DEEP RES 24OHM-M

.2 20

DEN POR%

60 0

DEEP RES 30OHM-M

.2 20

NEUT POR%

60 0

CALIPERIN

23 3

CALIPERIN

3 2

BIT SIZEIN

23 - - - - - - - - - - - - - - - - - - - 3

BIT SIZEIN

3 - - - - - - - - - - - - - - - - - - - 2

Figure 4 Evidence of profound spiraling as detected

by a differential caliper tool on a wireline density

measurement. The log indicates that the hole is under-

gauge approximately by 1.5 every 4 feet and rarely

over gauge . The underage magnitude matches to that

calculated from Lubinskis drift equation. This

phenomenon is repeated over thousands of feet on this

Figure 5 Typical example of extremely gauge hole. T

hole quality was evident over thousands of feet. This w

was drilled with the new steerable system (a matched l

gauge bit and positive displacement mud motor). The

entire 12,000 ft interval was drilled in only 2.7 days wi

no short trips.


11/12


Figure 6. Pick-Up and Slack-Off Weights from North Sea Well #1 using the New Steerable Drilling System

Average pick-up friction factor 0.07 and

average slack-off friction factor 0.05

T&D Data from a North Sea Well Using the New Steerable Drilling System

90

110

130

150

170

190

210

230

250

270

7500 8000 8500 9000 9500 10000 10500 11000 11500 12000Depth (ft)

0

10

20

30

40

50

60

70

80

90

100

Pick Up (al l weight values in klbs) Calibrated Pick Up (al l weight values in klbs) f f=0.1 Pick Up (al l weight values in klbs) f f=0.2

Slack Off (all weight values in klbs) Calibrated Slack Off (all weight values in klbs) f f=0.1 Slack Off (all weight values in klbs) f f=0.2

Rotating Off Bottom (klbs) Calculated Inc

Average pick-up friction factor 0.09 and

average slack-off friction factor 0.03

Depth Inc Pick Up (all weight values in klbs) Slack Off (all weight values in klbs) Rotating Off Bottom (klbs)

feet degrees Actual Calibrated ff=0.1 ff=0.2 Calculated ff Actual Calibrated ff=0.1 ff=0.2 Calculated ff Actual Calculated

7818 41 190 191 182 182 0.19 105 106 110 110 0.19 140 141

7938 44 175 187 184 185 0.17 110 122 112 111 0.10 130 142

8261 54 172 187 188 190 0.08 110 125 114 112 0.00 130 145

8621 63 170 190 189 194 0.13 110 130 113 111 0.00 125 145

9127 63 170 181 191 197 0.00 110 121 114 110 0.00 135 146

9317 60 175 188 195 202 0.00 110 123 115 111 0.00 135 148

10074 63 180 195 205 214 0.00 115 130 119 114 0.00 140 155

10259 61 187 203 208 217 0.05 112 128 120 115 0.00 140 156

11117 62 200 219 220 232 0.09 110 129 124 118 0.02 145 164

11590 63 210 232 227 240 0.14 112 134 126 120 0.00 145 167

9 5/8" Casing set at 7813ft - friction factor calculated averaged as : 0.16

8" Hole - friction factor calculated averaged as : 0.09 in pick-up and 0.03 in slack-off


12/12


Figure 7. Pick-Up and Slack-Off Weights from North Sea Well #2 using the New Steerable Drilling System

T&D Data from another North Sea Well Using the New Steerable Drilling System

95

105

115

125

135

145

155

165

175

185

195

205

215

225

3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000

Depth (ft)

0

10

20

30

40

50

60

70

80

90

100

Pick Up (a ll we ight va lues in klbs) Cal ib ra ted Pick Up (al l weigh t values in k lbs) ff=0.1 Pick Up (a ll we igh t va lues in klbs) f f=0.2

Slack Off (al l weight values in klbs) Calibrated Slack Off (al l weight values in klbs) ff=0.1 Slack Off (al l weight values in klbs) ff=0.2

Rotating Off Bottom (klbs) Calculated Inc

Depth Inc Pick Up (all weight values in klbs) Slack Off (all weight values in klbs) Rotating Off Bottom (klbs)

feet degrees Actual Calibrated ff=0.1 ff=0.2 Calculated ff Actual Calibrated ff=0.1 ff=0.2 Calculated ff Actual Calculated

3166 11 95 105 105 106 0.09 90 100 100 100 0.10 93 103

3654 22 105 115 114 115 0.13 98 108 107 106 0.06 100 110

3940 28 108 117 118 120 0.05 100 109 109 107 0.12 105 114

4231 22 113 121 124 128 0.01 107 115 113 110 0.03 110 118

4611 17 124 132 134 139 0.06 111 119 120 116 0.12 119 127

5020 12 133 143 143 149 0.10 118 128 127 123 0.08 125 135

5650 3 150 162 158 165 0.16 125 137 138 132 0.12 135 147

5875 7 152 161 163 172 0.08 131 140 141 135 0.12 143 152

6505 20 173 181 176 188 0.14 143 151 149 141 0.08 154 162

6875 21 176 185 184 198 0.11 145 154 154 144 0.10 159 168

7158 26 182 192 189 205 0.12 149 159 157 147 0.08 162 172

7443 31 189 196 193 210 0.12 151 158 158 148 0.10 167 174

7720 42 193 202 197 215 0.13 150 159 159 147 0.10 167 176

7825 45 198 204 197 216 0.14 155 161 159 147 0.08 170 176

8298 61 194 198 197 218 0.11 152 156 156 143 0.10 170 174

8493 68 195 202 195 216 0.14 147 154 154 141 0.10 165 172

8875 76 185 190 190 213 0.10 142 147 148 135 0.11 162 167

13 3/8" Casing set at 2989ft - friction factor calculated averaged as : 0.09

12" Hole - friction factor calculated averaged as : 0.11 in pick-up and 0.09 in slack-off

Average pick-up friction factor 0.11 andaverage slack-off friction factor 0.09

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MicroTortuosity Drilling Problem

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