Copyright 2003, SPE/IADC Drilling Conference This paper was prepared for presentation at the SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 19–21 February 2003. This paper was selected for presentation by an SPE/IADC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers or the International 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, IADC, their officers, or members. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Torque and drag can be critical issues in drilling directional wells especially in extended reach drilling (ERD). During well planning, torque and drag must be projected to ensure the rig’s rotating and hoisting equipment are adequately sized and to evaluate the limits for slide-oriented drilling motors. Depending upon formations, typical open hole friction factors (FF) used in simulation range from 0.22 in oil base mud to 0.35 in water based mud. These friction factors are scaled to a higher value than those measured in the field in order to account for tortuosity created by drilling assemblies.

A new drilling technology has been developed with the objective to reduce torque and drag by drilling a smooth and straight wellbore. The technology involves extended-gauge bit design with a matched steerable motor system or a point-the-bit rotary steerable system. Friction factor was studied for North Sea‘s wells drilled by the conventional motor systems and by new drilling systems. Significant reductions in the actual friction factors and the tortuosity index have been seen from the wells drilled by the new drilling systems. Introduction Roughly a decade ago our ability to make measurements downhole matured to a point where we had achieved the bulk of what we still measure today in terms of well placement and formation evaluation. While these important areas of measurement have continued to be refined, their primary use continues to be focused on the reservoir and near reservoir sections of the wells we drill. In the last few years we have had the luxury of being able to add to our armory a series of sensors that have allowed us to build significantly on our understanding of the drilling process itself. An enhanced armory has lead to an improved ability to impact the economics of drilling the overburden as well as the reservoir.

Initially these sensors were intended to help avoid hazardous conditions while drilling, and might be viewed as providing the ability to observe and manage the symptoms of sub-optimal behavior. These sensors include vibration, pressure while drilling, caliper, weight on bit, and torque. We have also added the ability to integrate improved surface data logging with these downhole measurements to provide a more comprehensive record of the behavior of the complete drilling system. More recently the ability to provide imaging logs in the FEWD environment has provided further evidence of small scale bore hole geometry effects over a larger number of wells.

Many of these sensors measure attributes of the process

that also are amenable to modeling. This capability is significant in as much as it brings a focus to managing the drilling process that starts with the planning phase. When we plan, we build a series of engineering and economic models of expected behavior. There is nothing particularly earth shattering about this. The outcome of the modeling exercises are encapsulated in the familiar items like the well trajectory, drilling program, torque and drag estimates, BHA, drill string design, bit selection, hydraulics, time depth curve, mud program, AFE and so on.

It would be peculiar if, having made these predictions

about what we are setting out to do, we did not then compare reality with the expectation. However, many of the comparisons we have traditionally made contain significant “fudge factors” that collected together all the elements we either did not understand or could not measure in detail. A good example of “fudge factors” is the use of the euphemism “Friction Factor” (FF) in torque and drag calculations. Any engineer worth his salt would cringe at the implication that this bore any relation to a “coefficient of friction” (COF) between the drill strings and the formations.

During literature search, it is difficult to find any definitive

measurements of the range of coefficients of friction between the materials used in drill string components and the formations likely to be encountered. However we believe these to be of the order of perhaps 0.05 to 0.151-2. Clearly the conditions of the material surfaces and the lubricity of the medium in which they are immersed will have some effect on the range. The FF used in torque and drag models is a catch all for the detail that we cannot “see” or do not understand. The

SPE/IADC 79919

New Drilling Technology Reduces Torque and Drag by Drilling a Smooth and Straight Wellbore D. Stuart, Peak Well Management, C. D. Hamer, C. Henderson, T. Gaynor, and D. C-K Chen, Halliburton Sperry-Sun

2 D. STUART, C.D. HAMER, C. HENDERSON, T. GAYNOR, AND D. C-K CHEN SPE/IADC 79919

use of FF therefore degrades the models to a gross generalization of the interaction between the drilling systems and the formations they are trying to excavate.

Despite these recognized shortcomings the model results

are constructed from the summation of a series of contacts along the drill strings and BHA that individually are treated as frictional contact events. As we also derive our FFs from the loads measured in the field (pick up, slack off and off bottom rotating hook loads and torque) anything that affects the loads is interpreted as a frictional effect.

We believe this kind of procedure reduces the clarity with

which the engineer can “see” deteriorating hole conditions and is probably true for much of what we pretend to know and understand about drilling. Our vision is clouded by the fudges involved in comparing idealized single issue models with measurements that capture multiple issues.

What tends to confirm this belief is the obvious (historical)

reliance on brute force rather than real engineering to try and improve efficiencies. “If you’re not sure why it’s not moving, just hit it harder”. If we could measure the energy required to cut and lift the volume of rock from a well with the energy applied through the drilling system to achieve this result, we suspect none of us would be surprised by gross imbalance that would be apparent. What we are attempting to show in this paper is an improved ability to replace brute force with more elegantly engineered solutions.

The advent of the new drilling optimization related sensors

has helped to add another level of detail to our understanding of these processes. This understanding was initially focused on managing the symptoms of sub-optimal performance by providing the ability to intervene in real time and change behavior, mainly through adjusting the drilling parameters. However, we re-iterate that this make-do arrangement only allowed us to manage the symptoms and not cure the underlying causes.

What has been most revealing have been the detailed

measurements provided in higher density in recorded mode, which have enabled much more thorough post bit run analysis. The improvement in quality of measurements has allowed us to continue to apply the “Model, Measure, Optimize” short term (real time) cycle, and also to add to this cycle the ability to influence the design and planning phase on a medium and long term basis.

If we can make more accurate and more detailed model

based predictions and compares these with equally detailed measurements, then where there are excursions between model and measurement (good or bad) we can add to our knowledge and understanding. Comparis on and feedback lead to making better use of existing systems and guide the design of new systems.

Early Evidence of Problems (Beginning To Recognize the Symptoms and How to Manage Them) So, our story really begins more than a decade ago. If we look back to the days when even MWD still only provided a survey measurement every 30ft or so along hole, then it is clear that any small scale tortuosity (such as hole spiraling) in the well trajectory or shape would not be visible. As soon as we began to make measurements with a density of one per foot or less, as is the case with Formation Evaluation sensors, we began to see evidence of rugosity on a scale of a few feet. The “ripple” on the log trace was christened “The Lace Curtain Effect” and this nickname has stuck

In Fig. 1, inferred hole rugosity is most obvious on the

SLD standard deviation ratio (SDEV track 1). A period of approximately 2 meters is suggested. The SLD caliper suggests hole enlargement of around 0.5 inches between peak and trough. The hole is roughly 0.5 to 1.0 inches over gauge. The conventional SLD density (SBDC track 3) is clearly affected. The rapid sample corrected density improves the measurement. The neutron is slightly affected. The resistivity data shows lace curtain response (SEXP, SESP, SEMP, SEDP track 2), the peaks on the resistivity data coinciding with the peaks on the standard deviation ratio.

Fig. 2 is a more recent example of hole spiralling observed

using the Azimuthal Density sensor. The centre track shows the bed boundary event imaged from the azimuthal density. In the right hand track, by selecting the output from the near (short spaced) detector only, a clearer picture of the bore hole geometry is visible. A clearer picture results because the near detector is more sensitive to stand off. The spiralling shows as the regular cross hatching effect.

For some time after these effects had been noticed we

struggled to understand what mechanism was at work that would produce these variations with such consistent “pitch”, when the pitch was apparently independent of ROP and bit RPM. A significant piece of knowledge was the observation that the typical 3 to 4 feet pitch corresponded to the distance from the bit to the first contact point on the steerable motor. It seemed likely that this distance was in some way related to the pitch of the rugosity. It also became obvious that the hole spiraled with constant gauge rather than moved in and out of gauge, but we were at a loss as to how the spiraling was generated and moderated by the BHA.

At this time the symptoms of high vibration, poor hole

cleaning, and difficulty in running casing and liners, were visible. Attempts to manage them were made using the drilling optimization sensors, and by spending time back reaming and “conditioning” the hole.

The detailed data gathered enabled a more complete

understanding of the process. This understanding contributed to the design changes that led to a cure, rather than a method of managing the symptoms.

SPE/IADC 79919 NEW DRILLING TECHNOLOGY REDUCES TORQUE AND DRAG BY DRILLING A SMOOTH AND STRAIGHT WELLBORE 3

The Cure – The Matched Extended-Gauge Bit and Steerable Motor System The cure was surprisingly simple. Stabilize the bit so that it only rotates about its true centre. To steer, do not push it sideways but point the axis of rotation in the desired direction. Achieving steerability was the difficult part which lead to the development of a new matched steerable drilling system4. A typical bit is shown in Fig. 3 next to a pin-down motor.

Stabilization of the cutting structure, causing it to rotate as

the designers intended, makes the cutting structure itself behave as the designers intended it to – or thought it did. Energy that previously was expended in whirling, slip/stick, and lateral vibration is saved. Weight transfer in a smooth bore ought to be improved, and less weight should be supported on the wellbore. WOB recorded on surface should be smaller – although weight actually on the bit may be the same. These factors should, and in fact do lead to the life of the cutting structure being greatly extended since damage to the cutters from abnormal loading and acceleration is eliminated.

We have demonstrated that by adopting these techniques

we have removed a significant part of the brute force application of energy from the drilling process. As most of this energy historically had been consumed in damaging vibration and abrasion these new “quiet” BHA’s have already improved the reliability of the entire drilling system, but also extended bit life, reduced trips, and virtually eliminated back reaming5. Other Applications – Point-the-bit rotary steerable system This same philosophy of making the bit function as the designers intended, and steering by pointing it instead of trying to push it sideways, can be applied to other systems. The next generation of rotary steerable systems that are emerging onto the market are “point the bit” tools and the only one commercially available uses long gauge bits. It points the bit in the desired direction by bending the drive shaft which ensures that rotation of the bit is still concentric with the hole axis at that depth6. (See Fig. 4) Confirmation of the Cure While we can point to “improved ROP”, lower vibration, and other symptoms of better health the real proof of a cure is the ability to use this new performance envelope in the planning of future wells. The objectivity of “improved ROP” is limited. Comparisons are as good as the data used in them. Lower vibration is reasonably objective as long as you are comparing closely similar hole sections and formations.

A measure that we feel is much more objective is the

condition of the bits when they are pulled. With the balanced systems described above, many of the bits have been pulled in virtually “green” condition, with one notable report grading the bit “NPL”. (It was later discovered this meant “No Paint Left”). Since our claim is to have designed drilling systems that make the cutting structure work efficiently, having bits come out of hole with minimal damage after long runs seems to us to be quite objective evidence.

The other measure is that of the FFs used in calculating Torque and Drag. As our claim is that these balanced systems drill smooth profiles, then there should be evidence of reduced torque and drag. Furthermore, there should be improved weight transfer to the bit as a consequence.

This is not only important in supporting the claims for

these systems but also in being able to design well profiles that take advantage of this benefit. If the claims are true then we should be able to drill longer and more complex profiles with these “point the bit” matched long gauge Bit and Motor systems than with a conventional steerable motor system. The same argument may also be used for point the bit Rotary Steerable Systems compared to other side force rotary steerable systems.

In order to verify our predictions we have collected some

of this evidence. One of the difficulties is in having valid “before and after” comparisons. However if, for a given development, wells have been modeled and then drilled using FFs derived from experience at that location, there should be a “typical” range of FF values that apply. Any one who has been involved with planning wells will know that these factors do not vary hugely in a particular area for a reasonably similar group of wells, and that even the global variation is not large unless there are exceptional circumstances.

The calculation of empirical FFs is based on recording the

pick up and slack off weights. The study conducted by one of the authors, D. Stuart, looked at over 100 hole sections drilled conventionally7. A summary of the results is given in the first column of Table 1. When field derived FFs are applied to new well plans, there is a requirement to account for tortuosity, since the basic well plan is a theoretical one and perfectly smooth. In this case a simple approach of applying a scale factor to the FFs is used. The scale factor is referred to as the Tortuosity Index (TI). The TI is derived from the comparison of the actual loads observed on the “as drilled” well in comparison to those predicted for the proposed well. Over the wide range of wells studied these TI values ranged from 1.3 to 1.35 with an average of 1.34 for conventionally drilled wells. The second column in Table 1 shows the scaled up FF required for planning purposes. Table 2 shows the comparison of these results with those for wells drilled using point the bit technologies, and the long gauge bit design that these systems employ.

If these are correct, then they should support the other

expectation of much lower weight applied at surface If we were applying a load of the order of 30,000 to 40,000 lbs at surface but 3,000 to 4,000 lbs only for comparable wells drilled with the new systems, then clearly something has changed. Changes of this order have been reported. What is clear from these data is that when we get this issue of hole quality right, the back calculated FFs are of the order of 0.08 to 0.15 and the TI averages 1.08. This difference suggests that the more typical FF numbers ranging upwards from around 0.2 are really accommodating the effects of small-scale tortuosity that are not input to the model as part of the well bore trajectory. FF numbers will also be higher as a result of

4 D. STUART, C.D. HAMER, C. HENDERSON, T. GAYNOR, AND D. C-K CHEN SPE/IADC 79919

capturing non-frictional effects. By addressing the root cause in the form of the bits interaction with the formation, we have been able to effect a cure, not just treat the symptoms. The Proofs –field Results and Friction Factor Study Many of the proofs that the systems described deliver the improved performance characteristics (including the reduction in tortuosity and FF) can be found in references 3-7. What we shall show here are some comparisons of field data that illustrate what we have described. Fig. 5 shows a graph of hook load (pick up, slack off, and off bottom rotating) for a well drilled with conventional steerable motor assemblies in the North Sea. The measured loads are graphically compared to predictions based on FFs of 0.1 and 0.2.

It can be seen that the measured loads correspond to an equivalent FF that lies between these two predictions as the well is drilled through the relatively benign Tertiary sequence. On entering the Cretaceous the characteristics change and for the pick up loads an equivalent FF of perhaps 0.5 might be required to force the model to match the measured values. Under these conditions weight transfer to the bit is difficult, leading to weight stacking, sudden weight transfer. Generally directional drilling becomes very difficult. ROP also suffers.

Fig. 6 is a subsequent well drilled in the same field. Here

the operator again drilled the tertiary sequence conventionally, but elected to use a side force driven rotary steerable tool in the Cretaceous. It is quite clear from the measured loads that this system did not perform significantly differently to the conventional mo tors.

Fig. 7 shows a later well in the field. In this case the

Operator agreed to try the motor based “point-the-bit” system in the Tertiary, but was not confident enough yet to attempt its use in the Cretaceous. The profile of the well also suggested that a simple rotary BHA incorporating an adjustable gauge stabilizer (AGS ) tool would be adequate. Note that on this graph the predicted loads are based on the smaller FFs of 0.05 to 0.15

Clearly the performance in the Tertiary is better. It is also

worthy of note that the simple rotary/Adjustable Gauge Stabilizer BHA that was used to drill the Cretaceous performed better in terms of its torque and drag characteristics than either conventional steerable motors or the side force rotary steerable. This phenomenon is not unusual. We have observed that, if high quality hole is drilled from the outset, then there is follow-through later in the well. Conversely, if spiraled or rugose hole is drilled initially, the effects of these distortions persist throughout the remainder of the well bore. You have to get it right first time.

Fig. 8 shows a later well in the same field where

confidence in the point the bit systems had been built and the motor driven point the bit system was used throughout the Tertiary and Cretaceous sequences. Torque and drag characteristics remain good throughout. None of the previously troublesome weight transfer problems were encountered, and directional control remained good

throughout. The “spread” between slack-off traces and “pick-up” traces has diminished, which is strongly indicative of reduced resistance to movement of the drill string in the wellbore.

Clearly, the direct effect of the smoother well bore is

improved torques and drag characteristics. The proof that these are being achieved is captured in the lower FFs derived from measured loads in the field. However, the additional capability that point-the-bit systems offer, lead to other benefits such as much more efficient and smooth weight transfer to the bit, and greater precision of directional control

The motor driven point-the-bit system utilizes much

smaller bend angles for the same dog leg capability. Smaller bend angles reduce concerns of rotation speeds and stresses on the motor. When coupled with an adjustable gauge stabilizer, if properly designed, this can lead to systems that will drill ERD profiles with minimal oriented drilling.

A good example of this is shown in Fig. 9. This well

drilled in the Dutch sector completed the long 12 ¼” section in two bit runs, using only one bit. The percentage of time spent rotating as opposed to sliding in oriented mode was in excess of 95%. The inclination was 78 degrees.

Fig. 10 shows a quad lateral well in the Irish Sea. In this

case the point the bit rotary steerable system was used to drill the four laterals. In this case the challenge was to drill the all of the 4 x 8 ½” legs within a +/- 2ft TVD window. For an explanation of the reasons for this degree of flatness please see reference 8.

With this type of complex profile, the degree of precision

required needed the ability of the “point-the-bit” rotary steerable system. A “point-the-bit” system generates the steering control necessary within the tool, close to the bit. Pointing and drilling is done independently of what the rest of the string is doing, other than the basic requirement to apply weight and torque to the bit sufficient to maintain efficient cutting action. The smooth profile provided ensures that this transfer of weight and torque is efficiently and smoothly applied.

Results, Observations, and Conclusions 1. Industry’s first attempt to study the actual friction factor

and friction factor attributed to both small scale and large scale tortuosity. Field data show that a straight and smooth wellbore (low, small-scale tortuosity) can reduce the actual friction factor by as much as 25%. in the study reported here, the tortuosity index has been reduced from 1.34 to 1.08 with the new balanced motor/long gauge bit combination. It has been reduced to near 1.0 with a rotary steerable system that also utilizes long gauge bits. The total reduction in frictional effects can be as much as 55%.

2. Lower friction factors, and therefore lower torque and drag, can have a significant impact on drilling operations, from improved ROP to increased drilling interval.

SPE/IADC 79919 NEW DRILLING TECHNOLOGY REDUCES TORQUE AND DRAG BY DRILLING A SMOOTH AND STRAIGHT WELLBORE 5

3. The benefits of a smooth straight wellbore include not only reduced torque and drag, but also better hole cleaning, lower vibration, and better LWD/MWD tool responses and reliability. Entirely contrary to expectations and to widespread opinion,: motor systems have proved capable of providing similar hole cleaning to some steerable systems.

With 20/20 hindsight, it would be nice to claim that we set

out on the road of addressing the root causes of some of the drilling problems we encountered. Clearly this route was not the case. What we set out to do was detect and manage a series of symptoms. As with many other industries and sciences, a series of small incremental steps, each initiated to deal with a particular aspect of the process, can eventually lead to a build up of knowledge that produces a significant step change.

It is collecting that body of knowledge which is difficult.

The resulting change is often both simple and blindingly obvious in hindsight. In the case of the “point-the-bit” systems design, it lead to the first sustainable step change in ROP in a mature development area in more than 15 years. This success has subsequently been repeated world wide. In addressing the root cause, the approach also improved hole quality, with all the knock on benefits that improvements bring.

It also demonstrates how operators, by supporting the

provision of some incremental optimization services at relatively low cost, eventually reap the benefits of the improved knowledge that these small increments collectively provide. There are no losers in this process, and the risks are minimal. At worst these systems are no worse than “conventional” ones and, at best, provide benefits that range far out into the life of the well and far beyond the drilling process itself.

Equipment reliability, from the bit right through the drill

string and on up to the top drive, is improved. Bit life is extended. NPT is reduced. Measurements are of a higher quality. Casing and completing the well is greatly enhanced. Damage to wire wrap screens is less likely, and gravel packing should be more secure due to the smooth concentric annulus Ultimately it does it faster, cheaper, and potentially deeper. (Less Drag = Longer Reach)

What we see is a need to improve many of our modeling

techniques to remove — or at least isolate — as much as we can the “fudge factors” that we have lived with for too long. In the context of torque and drag, the models generally assume an idealized set of circumstances where only frictional effects are present. We came to realize the hidden danger. However convenient it was to label measures “Friction Factor” or “Tortuosity Index” and to model the process as though that’s what they were, Friction Factor doesn’t encompass only friction and Tortuosity Index doesn’t encompass only tortuosity. In fact friction and tortuosity are relatively minor contributors.

By drilling with techniques that provide a very smooth well bore, we make the comparison of the measurements with the modeled data more secure. Mechanical interference effects that were previously captured by the load measurements and therefore interpreted as frictional effects, are not present unless hole conditions deteriorate. This should lead to earlier identification of these events, and to earlier and more appropriate intervention to deal with them.

Having evolved to our present state, we believe that the

future lies in maximizing the benefits of the “Model, Measure, Optimize” real time cycle and the post-run “Root Cause Analysis” in a systematic way. A procedure of systematic comparison and analysis of data of known high quality is the way a true “learning organization” should function. Such a procedure makes the most of our ability to intervene while the process is in progress and to feed back the knowledge gained to influence future designs.

In this age of key performance indicators, perhaps we

should consider “Friction Factor” as the most important measure of drilling performance and hole quality since it subsumes so many others. Acknowledgements The authors wish to thank the management of Peak Well Management and Halliburton Company for permission to publish this paper. References 1. Bol, G.M., “Effect of Mud Composition on Wear and Friction of

Casing and Tool Joints”, SPE Drilling Engineering, October, 1986.

2. Maldla, E. and Wojtanowicz, A., “Laboratory Study of Borehole Friction Factor with a Dynamic-Filtration Apparatus”, SPE Drilling Engineering, September, 1990.

3. Gaynor, T., Chen, D. C-K, Stuart D., Comeaux B., “Tortuosity versus Micro-Tortuosity – Why Little Things Mean a Lot” SPE/IADC 67818, 2001, Amsterdam.

4. Gaynor, T., Chen, D. C-K, Maranuk, C., and Pruitt, J., “An Improved Steerable System: Working Principles, Modeling, and Testing”, SPE #63248, presented at the 2000 SPE Annual Technical Conference and Exhibition held in Dallas, Texas.

5. Gaynor T, Irvine G, Boulton R, Gilchrist D, Lane I – “Step Change in Drilling Efficiency in Mature North Sea Fields from a new Motor and Bit Drilling System”, SPE #56936, 1999, Aberdeen

6. Yonezawa, T., et al., “Robotic Controlled Drilling: A New Rotary Steerable Drilling System for the Oil and Gas Industry” IADC/SPE # 74458, presented at the 2002 IADC/SPE Drilling Conference in Dallas, Texas.

7. Gaynor, T. , Hamer, C.D., Chen D. C-K, Stuart, D., “ Quantifying Tortuosities by Friction Factors in Torque and Drag Model” – SPE #77617 – 2002, San Antonio

8. Yaliz, A., Chapman, T., Downi, J., “Case Study of a Quad-Lateral Horizontal Well in the Lennox Field: A Triassic Oil Rim Reservoir” SPE 75249, 2002, Tulsa.

6 D. STUART, C.D. HAMER, C. HENDERSON, T. GAYNOR, AND D. C-K CHEN SPE/IADC 79919

Figure 2 – Azimuthal density image log.

Fig. 1— Lace Curtain effect due to hole spiralling.

SGRCapi0 150

SDEV10 0

SCALinch6 16

TVDm2750 2700

75 SGRC

SDEV 1.2

8.5 SCAL

SEXPohmm0.2 2000

SESPohmm0.2 2000

SEMPohmm0.2 2000

SEDPohmm0.2 2000

SFXEhrs0.2 2000

SPLFpu45 -15

SBDCg/cc1.95 2.95

SCORg/cc-0.75 0.25

SBD2g/cc1.95 2.95

SCO2g/cc-0.75 0.25

2970

2980

2990

Evidence of spiraling

Density Image Near Detector

SPE/IADC 79919 NEW DRILLING TECHNOLOGY REDUCES TORQUE AND DRAG BY DRILLING A SMOOTH AND STRAIGHT WELLBORE 7

Fig. 3— Matched extended-gauge bit and pin-down motor system.

Fig. 4 — Point-the-bit rotary steerable system using the same extended-gauge bit principles

8 D. STUART, C.D. HAMER, C. HENDERSON, T. GAYNOR, AND D. C-K CHEN SPE/IADC 79919

Table 1

Table 2

Mud type Actual CasingFF

Actual OH FFSlickBore drilledwells

Actual OH FFConventionallydrilled wells

Tortuosity IndexSlickBore drilledwells

Tortuosity IndexConventionallydrilled wells

Water based 0.21 0.21 0.27 1.08 1.34Pure oil 0.10 0.10 0.12 1.08 1.34Pseudo oil 0.15 0.14 0.18 1.08 1.34

Mud System Actual OpenHole F.F.

Planning OpenHole F.F.

Water Based

Generic 0.24 0.32

Polyseal /Barasilc

0.30 0.40

Thixal 0.27 0.36

Pure Oil BasedGeneric 0.12 0.16

Pseudo Oil Based

Generic 0.17 0.23XP07 0.17 0.23Petrofree 0.18 0.24Ecomul 0.20 0.27

SPE/IADC 79919 NEW DRILLING TECHNOLOGY REDUCES TORQUE AND DRAG BY DRILLING A SMOOTH AND STRAIGHT WELLBORE 9

Fig. 5 Fig. 6

Amerada Hess, 15/22-J19, 12 1/4" Hole - Conventional motors

1 2 0

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Amerada Hess, 15/22-J20 - Autotrack

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12 ¼” hole - side force RST

10 D. STUART, C.D. HAMER, C. HENDERSON, T. GAYNOR, AND D. C-K CHEN SPE/IADC 79919

Fig. 7 Fig. 8

Amerada Hess, 15/22-J12Y -Slickbore followed by Rotary AGS

100

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Amerada Hess, 15/22-J17 - Slickbore

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Inc

#1 Slickbore AGS #2 Motor+NBS #3 Slickbore AGS #4 Motor+NBS

Palaeocene E k o f i s k Flounder Her r ing H i d r a

Matched Motor and Long Gauge Bit

SPE/IADC 79919 NEW DRILLING TECHNOLOGY REDUCES TORQUE AND DRAG BY DRILLING A SMOOTH AND STRAIGHT WELLBORE 11

Fig. 9 ERD Well – Dutch Sector

Total Depth at 5253.06m

Hold Angle at 79.302°

End of Build at 1223.06m

Continue Build at 805.00m (3.5/30m)

Continue Build at 500.00m (2.5/30m)

Kick-Off at 350.00m (1.5/30m) 20" Casing 500 MD/TVD

13 3/8" Casing 1069 MD/962 TVD

9 5/8" Casing 3100 MD/1361 TVD

7" Liner 4230 MD/1571 TVD 4 1/2" Liner

5253 M D/1761 TVD Base Volpriehausen Sst

Vertical Section Section Azimuth: 153.710° (Grid North) Scale: 1cm = 250m

Vertical Depth

Scale: 1cm = 250m

0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 0 -250

0 0

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Eastings Scale: 1cm = 400m

Northings

Scale: 1cm = 400m

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-3200

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Prepared by: Ben Martell

Date/Time: 26 September, 2000 - 10:50

Checked: Approved:

Clyde Q8 Q8-A Platform Q8-A03 Plan 7

Clyde Petroleum Exploratie B.V.

Hold Azimuth at 153.71

20" Casing

13 3/8" Casing

9 5/8" Casing

7" Liner

4 1/2" Liner Base Volpriehausen Sst

12 ¼” Bit from Dutch well Bit Grade: 1-2-ER-A-X-I-PN-TD After drilling 2961 metres in 171.5 hours

12 D. STUART, C.D. HAMER, C. HENDERSON, T. GAYNOR, AND D. C-K CHEN SPE/IADC 79919

Fig. 10 The very flat Quad Lateral well described in reference 8

5 1/2" Liner

13 3/8" Casing

9 5/8" Casing

DrillQuest 2.00.08.003

BHP Petroleum

Lateral 1

Lateral 2

Lateral 3

Lateral 4(Main Well)

20" Conductor

Grid North

LennoxSlot 2L10 Multilateral

Eastings Reference is Grid NorthScale: 1cm = 500ft

EastingsScale: 1cm = 500ft

Nor

thin

gsS

cale

: 1cm

= 5

00ft

Nor

thin

gsS

cale

: 1cm

= 5

00ft

0 500 1000 1500 2000 2500 30000-500-1000-1500-2000-2500-3000-3500-4000-4500-5000-5500-6000-6500-7000-7500-8000-8500

0 500 1000 1500 2000 2500 30000-500-1000-1500-2000-2500-3000-3500-4000-4500-5000-5500-6000-6500-7000-7500-8000-8500

0

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