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Copyright 2007, SPE/IADC Drilling Conference This paper was prepared for presentation at the 2007 SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 20–22 February 2007. 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 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 and 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 1 .972. 952.9435. Abstract Torque and drag (T&D) modeling is regarded as an invaluable process to assist in well planning and to predict and prevent drilling problems. Although T&D software has existed for over 20 years, some confusion still exists over the validity of the models used to characterize drilling and completion operations. This paper provides an assessment of current limitations of the various T&D models (soft-string and stiff- string) and appraises their validity. Field data from various operations is used to illustrate certain limitations. The paper defines future requirements for what is considered to be the next generation of T&D models . Probably the most important technical requirement is a more realistic stiff-string model to correctly account for the impact of tubular stiffness, hole clearance and tortuosity effects. Introduction The basic mathematical model that underlies most T&D software has not changed significantly since its original inception 1 . By contrast, software user interfaces have improved dramatically as computer hardware, processor power and software functionality have evolved. Based on over two decades of industry access to drillstring simulation software, it is considered that the time is now right to reflect on the state of current models and identify future user requirements. This paper first examines some of fundamental issues associated with the core drillstring models . This is followed by specific discussions on coefficients of friction (friction factors), tubular buckling, wellbore tortuosity and fluid flow effects. A section is devoted to the practical limitations of T&D models and highlights common mistakes made by users. The paper concludes by defining some user requirements to satisfy needs of future drilling and completion communities for the next 20 years. Torque and Drag Software T&D software is commonly used during planning to ensure that the proposed wellpath can be drilled and completed with available equipment. It is also used for rig sizing and drillstring optimization to ensure that well designs are feasible. At a more advanced level it is used to determine drilling limits for fie ld development options. During planning, it is a common practice to build a degree of conservatism into the models to allow for the uncertainty that invariably exists . For challenging or complex wells, T&D software is often used in real-time mode. This is where T&D trend lines are predicted in advance and monitored during operations for adherence or deviation. The intent is to allow the drill site team to respond to any unexpected trend changes in a timely fashion. It is important to note that virtually all T&D software use steady state models. This means calculations are carr ied when the string is moving in a steady manner, i.e. no transient effects are incorporated. Soft-String Model The original soft-string T&D programs were based on a model developed by Exxon Production Research 1,2 . The soft- string model is so called because it ignores any tubular stiffness effects; this means that the pipe is treated as a heavy cable, chain or rope lying along the wellbore. This means that a xial tension and torque forces are supported by the string and contact forces are supported by the wellbore. This model assumes that the loads on the string result solely from the combined effects of gravity and frictional drag; a result of contact between the string and the wellbore. The frictional force is simply the product of the normal force acting between the string and wellbore and the coefficient of friction. The schematic in Figure 1 illustrates the forces acting on a single drillstring element. The normal force, N, can be calculated from Eq. 1 ( ( 2 2 sin W T sin T N θ φ θ φ = (Eq. 1) where, T is the tension force at the lower end of the string element ∆φ is the change in azimuth angle over the string element θ is the inclination at the lower end of the string element W is the buoyed weight of the string element SPE/IADC 104609 Step Changes Needed To Modernize T&D Software Colin J. Mason, BP Exploration, and David C.-K. Chen, Halliburton Sperry Services

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Page 1: [Society of Petroleum Engineers SPE/IADC Drilling Conference - (2007.02.20-2007.02.22)] Proceedings of SPE/IADC Drilling Conference - Step Changes Needed To Modernize T&D Software

Copyright 2007, SPE/IADC Drilling Conference This paper was prepared for presentation at the 2007 SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 20–22 February 2007. 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 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 and 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 1.972.952.9435.

Abstract

Torque and drag (T&D) modeling is regarded as an invaluable process to assist in well planning and to predict and prevent drilling problems. Although T&D software has existed for over 20 years, some confusion still exists over the validity of the models used to characterize drilling and completion operations. This paper provides an assessment of current limitations of the various T&D models (soft-string and stiff-string) and appraises their validity. Field data from various operations is used to illustrate certain limitations. The paper defines future requirements for what is considered to be the next generation of T&D models . Probably the most important technical requirement is a more realistic stiff-string model to correctly account for the impact of tubular stiffness, hole clearance and tortuosity effects. Introduction

The basic mathematica l model that underlies most T&D software has not changed significantly since its original inception1. By contrast, software user interfaces have improved dramatically as computer hardware, processor power and software functionality have evolved. Based on over two decades of industry access to drillstring simulation software, it is considered that the time is now right to reflect on the state of current models and identify future user requirements.

This paper first examines some of fundamental issues

associated with the core drillstring models . This is followed by specific discussions on coefficients of friction (friction factors), tubular buckling, wellbore tortuosity and fluid flow effects. A section is devoted to the practical limitations of T&D models and highlights common mistakes made by users. The paper concludes by defining some user requirements to satisfy needs of future drilling and completion communities for the next 20 years.

Torque and Drag Software T&D software is commonly used during planning to

ensure that the proposed wellpath can be drilled and completed with available equipment. It is also used for rig sizing and drillstring optimization to ensure that well designs are feasible. At a more advanced level it is used to determine drilling limits for fie ld development options. During planning, it is a common practice to build a degree of conservatism into the models to allow for the uncertainty that invariably exists .

For challenging or complex wells , T&D software is often

used in real-time mode. This is where T&D trend lines are predicted in advance and monitored during operations for adherence or deviation. The intent is to allow the drill site team to respond to any unexpected trend changes in a timely fashion. It is important to note that virtually all T&D software use steady state models. This means calculations are carr ied when the string is moving in a steady manner, i.e. no transient effects are incorporated.

Soft-String Model

The original soft -string T&D programs were based on a model developed by Exxon Production Research1,2 . The soft-string model is so called because it ignores any tubular stiffness effects; this means that the pipe is treated as a heavy cable, chain or rope lying along the wellbore. This means that axial tension and torque forces are supported by the string and contact forces are supported by the wellbore.

This model assumes that the loads on the string result

solely from the combined effects of gravity and frictional drag; a result of contact between the string and the wellbore. The frictional force is simply the product of the normal force acting between the string and wellbore and the coefficient of friction. The schematic in Figure 1 illustrates the forces acting on a single drillstring element. The normal force, N, can be calculated from Eq. 1

( ) ( )22 sinWTsinTN θ+φ∆+θφ∆= (Eq. 1)

where,

T is the tension force at the lower end of the string element ∆φ is the change in azimuth angle over the string element θ is the inclination at the lower end of the string element W is the buoyed weight of the string element

SPE/IADC 104609

Step Changes Needed To Modernize T&D Software Colin J. Mason, BP Exploration, and David C.-K. Chen, Halliburton Sperry Services

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2 SPE/IADC 104609

The normal force equation is used to evaluate the change in tension and torque as detailed in Eq. 2 and Eq. 3.

NcosWT µ±θ=∆ (Eq. 2)

RNM µ=∆ (Eq. 3) where , ∆T is the increment in tension across the string element ∆M is the increment in torque across the string element µ is coefficient of friction between the string and wellbore R is the radius of the string element.

Virtually all T&D soft -string models3,4 assume that the

drillstring is made up of short elements joined by connections that transmit tension, compression, and torsion, but not bending moment. The basic equations of friction are applied to each segment with the calculations starting at the bottom of the string and proceeding upward to the surface. Each short element contributes increments of torque, axial drag and weight. Forces and torque values are summed to produce the cumulative loads on the drillstring. Initial conditions are usually specified at the bit and for drilling operations the inputs would be weight-on-bit (WOB) and bit torque values.

The most significant assumption is that the string is in

continuous contact with the wellbore over its entire length. This also means that radial clearance effects are ignored and that the bending moment is not considered in the model.

Stiff-S tring Model

The stiff-string model should account for string bending stiffness (flexural rigidity) and radial clearance by allowing initially unknown sections of the string not to be in contact with the wellbore. Higher side wall forces occur as stiff tubulars are forced around curved sections and reduced side wall forces occur as the pipe straightens. Variation of contact area between a string component and the wellbore will also occur. Concentrated bending moments at stabilizers and casing centralizers, as well as at drillpipe connections must also feature in a comprehensive stiff-string model. In summary, the stiff-string method is intended to produce a more realistic analysis of the configuration, stresses and loads acting upon the string and borehole wall.

Some confusion exists over whether the stiff-string model

should be used in preference to the soft -string model. Some rules of thumb do exist5, but it is not always clear what their basis is. Intuitively stiff-string models are considered to be more relevant to the following situations. • well designs with highly tortuous trajectories • well paths of very high dogleg severity • casing running with stiff tubulars • well designs with narrow radial clearances

Stiff-string mathematical models are considerably more complex to solve than soft-string counterparts. A greater variety of numerical methods including finite difference, finite

element and semi-analytical techniques have been used. However based on the authors’ experience of using different stiff-string programs it appears that the models fail to properly account for the effect of hole size and/or radial clearance.

This disparity between theory and practice can have

significant implications for the planning engineer who may be lulled into falsely believing results. For example, this may explain, why significantly higher friction factors are associated with running casing than with tripping drillpipe in the same wellbore6. It is possible that the higher casing running friction factors contain the effect of hole clearance and stiffness effects that is not properly accounted for in the models. This aspect is discussed further in the next section.

As an illustration, Figure 2 comprises a casing running

drag plot where both the soft-string and stiff-string models have been used. In this example, a flush 9-5/8” casing string is being run into a high angle well with a nominal 12¼” hole size. The sensitivity of the stiff-string model is examined by decreasing the hole size and looking at the impact on hookloads. It can be seen that the trend of the results is correct, but with a hole size of 9.7” (just 0.0375” radial clearance) the program still indicates casing will get to depth, which seems unrealistic. Figure 3 illustrates the corresponding survey inclination, azimuth and dogleg severity data that was used in the T&D analysis. What is needed is a clear understanding of the validity of models in such circumstances.

The following field example also illustrates the importance

of understanding the influence of hole size on casing running performance. In this situation a 21½” hole section was drilled and underreamed using a big bore rotary steerable assembly. The previous 26” casing was set at 360m with the wellbore inclined at 19°. Despite erratic performance of the rotary steerable system, drilling continued to the target depth of 970m with the wellbore now inclined at 31°. Surveys also indicated that some uncontrolled 5 (°/30m) doglegs had been generated. The drilling team were also concerned that the underreamer had not produced a minimum gauge 21½” hole. The 18-5/8” casing string was subsequently run, but ran out of weight when working through a 5 (°/30m) dogleg at 720m. Figure 4 illustrates hookload weights for this casing run. Excessive slack-off and pick-up weights can be seen almost as soon as the open hole section had been entered. It was considered that the “out of gauge” 21½" hole with 5 (°/30m) doglegs (wellbore turning) may not have been sufficiently large enough to allow the stiff 18-5/8" casing to pass through. It can be seen from the theoretical pick-up and slack-off plots that there should be little drag in an operation such as this, due to the low inclinations involved.

The forward plan involved making a run with two

underreamers in tandem dressed to 21½” and then another run using an underreamer with roller cone cutters to open the hole to 24”. The drag trend for the rerun casing is illustrated in Figure 5. It can be seen that drag is considerably improved allowing the casing to run to depth. However despite the larger open hole size, excessive drag can still be seen beyond 720m.

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SPE/IADC 104609 3

This example illustrates that despite changes in hole size the theoretical T&D models produce very similar but unrealistic results. This could be a case where the model is being used beyond its capability. Only by analyzing field examples such as this will the engineer correctly understand the linkage between casing size, hole size, inclination, casing s tiffness and tortuosity effects and limitations of T&D modeling

Another important observation is that the performance of

the stiff-string model is dependent on the resolution of survey data that is available. In order to accurately define the string configuration as it is constrained within the wellbore, a higher density of survey data may be required. This is an area that clearly requires further investigation.

Another topic that has yet to be addressed is that if a string

is bent beyond its yield limit, a bending plasticity model would be needed to enable accurate calculations. Friction Factors / Coefficient of Friction

A key modeling parameter in T&D modeling is the so-called friction factor (FF) or coefficient of friction (CoF). One potential area of confusion is that the term friction factor is also commonly used in thread compound testing. Fortunately most engineers are able to understand the context whenever the term friction factor is used.

A friction factor is a dimensionless parameter and in this

case is intended to represent the roughness between the drillstring and borehole wall. However due to the complex nature of drilling, friction factors not only represents true mechanical friction but also includes a multitude of other downhole effects. This is the reason why friction factors are often disparagingly called fudge factors. Unwanted contributions to friction factors include the following: • pipe stiffness effects (not included in soft -string model) • viscous drag (fluid resistance due to pipe movement) • cuttings beds (mechanical wellbore obstructions) • stabilizers/centralizers (impact stand-off / string stiffness ) • formation types (variations in lubricity) • pore pressure (susceptibility to differential sticking) • circulation losses (possible loss of lubricity) • wellbore break-out (due to wellbore instability) • micro -tortuosity (rippling between survey points); • wellbore spiralling (reduction in drift)

Examining T&D or friction factor trends can give

powerful insights into wellbore quality7. In its purest form, the friction factor will only represent true mechanical friction.

To further add to the engineer’s confusion, two types of

frictional effects must be considered. These are generally referred to as “static” and “dynamic” friction forces.

The coefficient of dynamic friction is characterized by the

frictional force between two moving surfaces in a steady manner. The dynamic friction factor is what should be used in

T&D modeling. For the majority of rotary drilling operations, (dynamic) friction factors range between 0.10 and 0.30. Extreme values can be as low as 0.05 and as high as 0.50.

Conventional static friction forces arise from the

interlocking of irregularities of two surfaces. These forces increase to prevent any relative motion up until some limit when motion occurs. It is that threshold of motion which is characterized by the coefficient of static friction. In drilling operations, static friction is commonly associated with a differential sticking environment, where the formation creates a suction force on the string. The effect is usually unpredictable in terms of when it will occur and also the magnitude of the effect. The coefficient of static friction is typically larger than the coefficient of dynamic friction. Figure 6 illustrates the differences between static and dynamic friction effects when running in a single joint of casing. Here it can be seen that considerable slack-off weight is required before the casing starts to move. Once the casing is moving, drag returns to normal. It should be noted that in many wells, static and dynamic friction effects are indistinguishable.

In terms of T&D software, it is important to note that

friction factors are not necessarily inter-changeable between soft -string and stiff-string models . In theory one would expect lower values to be associated with the stiff-string model since additional factors are included in the mathematical model. This too is an area that merits further investigation.

Buckling

Buckling is an important issue in T&D modeling for several reasons. Firstly, buckling causes an increase in contact force between the string and wellbore. This means that as weight is released from the derrick the string is progressively supported by wellbore friction rather than the bit . Ultimately “lock-up” can occur where the string weight is consumed by the buckled portion of the string – i.e. a situation where further load cannot be applied to the bit. For example, lock-up is a common occurrence during coiled tubing operations.

Buckling is generally visualized in a fairly simplistic way

and has recognized snaky, transition and helical buckling modes . In its most benign form, buckling occurs when the string snake s along the wellbore. This form of buckling is also known as sinusoidal buckling. As compression continues to build up in the string, the buckled portion transitions into a helix, resulting in what is known as helical buckling.

Many buckling models have been developed by the oil and

gas industry and also by the academic community. Relatively simply closed form formulae have been derived which account for the onset of both sinusoidal and helical buckling modes. While there is only one sinusoidal buckling model developed by Paslay and Dawson8, several helical buckling limits have been proposed. The most commonly used formula is Chen and Cheatham model9 because it provides the lowest force needed to initiate helical buckling. For illustration the critical forces that initiate sinusoidal and helical buckling are represented below in Eq. 4 and Eq. 5.

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4 SPE/IADC 104609

θ= sinr

EIwFS 2 (Eq. 4)

SH FF 2= (Eq. 5)

where, FS represents the sinusoidal buckling initiate force FH represents the helical buckling initiate force E is Young’s modulus I is the second moment of area w is the buoyed weight of pipe θ is inclination angle r is radial clearance

Buckling may then be assessed by calculating the friction

force F and then comparing it with the various inequalities as defined below:

bucklinghelicalFF

initiatedbucklinghelicalFFF

initiatedbucklingsnakyFFF

bucklingnoFF

S

SS

SS

S

<

<<

<<

<

22

222

2

In the case of snaky buckling no allowance is made for an

additional increase in wall force, however in the case of helical buckling the wall force is increased. Much work has continued since this time to generalize buckling models to curvilinear wellbores and to distinguish behavior between rotary and sliding operations. A state of the art review10 provides an excellent overview of issues associated with each of the buckling models and identifies a list of remaining technical challenges.

In practical terms, the drilling engineer attempts to design

an operation to avoid buckling, if at all possible. Generally accepted guidance is that sinusoidal buckling can normally be tolerated but helical buckling should be avoided. If helical buckling is unavoidable, then T&D models need to accurately calculate the additional drag created in the post-buckled portion of the string. This is needed to predict the loss of WOB, the potential for lock-up and impact on fatigue.

In terms of future work, the implications of drilling in a

post-buckled state must be better understood. Drillstring failure s can occur due to excessive local stresses in the post-buckled region. Similarly, the increase in cyclic stresses which result s from pipe rotation around a buckled axis will reduces the fatigue life of the component. Linking the behavior of theoretical buckling models with practical field experience will continue to help understand this complex phenomenon.

A comprehensive post buckling algorithm is also needed to

produce more detailed information regarding buckling extent and severity. Approaches based on developing buckling

profiles as functions of amplitude and pitch show considerable merit11. In this situation, amplitude represents the deviation of the string from the bottom of the wellbore and pitch the frequency between buckling peaks. Graphical methods that help the engineer to visualize string buckling within a wellbore will assist with improved understanding, well planning and decision making.

Interestingly, there are cases when buckling models in the

literature appear deficient. For example, consider running a weightless casing string in a deviated well. Most buckling models indicate that the string will instantaneously buckle, see Eq. 4. This casing running example does occur in practice, in extended-reach wells , where floatation techniques can render the casing neutrally buoyant. This state is highly desirable since it ensures frictional drag is minimized. The anomaly is that casing string has significant stiffness, but is weightless and some resistance to buckling would be expected.

Perhaps the biggest requirement is a set of recommended

guidelines for operating drillstring in a post-buckled state. Drilling and completion engineers would like to know under what circumstances and for how long is it safe to operate in a sinusoidal or helical buckling mode. It is likely that helical buckling can be tolerated in a number of applications. This means that additional expense could be avoided in engineering unnecessary alternative solutions. Bridging the gap between the theoretical models and practical experience is an area that still requires attention.

Fluid Flow Effects

Another area of confusion is the effect of fluid flow on T&D calculations. Fluid flow during drilling or circulation results in the loss of the normal component of fluid pressure due to frictional contact between the fluid and the string. There is also an additional tangential component caused by viscous drag (shear stresses) on the string due to fluid flow.

Fluid flow can significantly reduce the effective weight of

the string. The magnitude of this “uplift” effect is primarily dependent upon hole size, string size and flow rate combination. Fluid flow has the most effect on pick-up, slack-off and off-bottom rotating weights, but much less so on torque. In practice, drilling 8½” hole section appears most sensitive to this effect, due to the combination of radial clearance and hole cleaning flow rates involved. Coiled tubing drilling and casing drilling operations are also sensitive to this effect, where the so-called “pump -off” effect has to be overcome before WOB can be applied.

Some T&D models account for fluid flow, but a number

ignore this effect. Spurious results will occur if a non-fluid-flow enabled T&D program attempts to model record ed weights with pumps on. In such situations the hydraulics uplift effect can be so large as to render meaningless results. Due to the large number of rheological models and options, there is greater variability in results between the various hydraulics enabled T&D programs.

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SPE/IADC 104609 5

Tortuosity Effects To make a planned wellpath resemble an as-drilled profile,

a tortuosity model is often applied to the smooth planned survey. This effectively superimposes a rippling effect over a portion of the wellbore. The intent is that T&D predictions will be as realistic as possible. There are various tortuosity models described in the literature12. These include sine wave, random inclination and azimuth, and random inclination dependent azimuth formulae. Amplitude and wavelength values are used to define the intensity and magnitude of the rippling effect.

The correct application of tortuosity models requires an

understanding of the likely as-drilled tortuosity values. This information is not routinely available and recommended or default values might be inappropriate. In practical terms , two tortuosity types exist in the wellbore . These are those generated by steerable motors and micro-tortuosity commonly associated with hole spiraling.

Conventional tortuosity, as illustrated in Figure 7 , is easy

to recognize from survey data and a tortuosity model can be defined to simulate the effect. However, hole spiraling can only be seen from image or caliper logs as the MWD survey tool crosses the trough or valley of a spiral hole , as shown in Figure 8. This means that the axis of the drift is measured rather than that of the spiraled wellbore. The consequence is that strings are being run in spiraled wellbores with reduced drift. The means that T&D levels can be expected to increase in such circumstances. Currently no T&D models account for the smaller drift associated with a spiraled wellbore.

In terms of modeling, it is possible to back-calculate

tortuosity values by comparing T&D values using the final planned and as -drilled surveys. By adjusting the parameters of a tortuosity model, results between the two sets of T&D analyses can usually be matched fairly closely13.

An alternative and simpler approach adopted by some

engineers is to ignore the effect of tortuosity and account for it indirectly by using inflated friction factors. Torque and Drag Management

One particular area that can result in a great deal of confusion is T&D management14, 15. This area is usually concerned with managing a drilling operation in which a limitation arising from excess frictional effects has been identified. For example , this can be due to a rig top drive, torque limitation or excessive axial frictional drag when running a long casing string in an extended-reach well.

A plethora of tools and techniques exist to help overcome

such problems. However there is usually uncertainty regarding the absolute performance of such equipment. This is due, in part, to laboratory performance test results being extrapolated to the downhole environment. Part of the problem also concerns not consistently measuring performance at the rig site. Whilst service companies acknowledge these issues, part of the problem is that operators do not always provide the required quantitative feedback on tool performance. A large

number of variables can impact performance of T&D tools and highly detailed information is usually required to understand their net effect on operations.

Most T&D software permits the user to link friction

reduction with tools installed on a portion of the string. This is implemented in varying degrees of complexity among the various T&D programs.

A set of guidelines to help both operators and service

companies in this area would go a long way to help establish consistency and promote accurate measurement of effectiveness of T&D reduction tools in the field.

Limitations of Current T&D Models

There are many examp les of where T&D results have been misunderstood or limitations not realized. This is a persistent problem and measures must be implemented to prevent their recurrence in the future. The following examples still occur regularly.

• Users unaware that hole size makes no difference to

T&D results . A typical example is that an unplanned dogleg has been created during drilling operations. The engineer is concerned that the casing will not be able to make it through the dogleg. The T&D model is run and everything look satisfactory. The soft-string model and even to some extent the stiff-string model are not designed to determine whether a string will pass through a given dogleg.

• Friction factors calculated from drilling operations are used to model casing runs. Usually different friction factor values apply to each operation within the same wellbore. Only by back-calculating friction factors for each operation will the engineer appreciate the diversity and range of values that can occur. In many cases friction factors from casing running are often double those calculated from drilling operations6.

• Static and dynamic friction effects . Static friction is a highly complex mechanism compared with dynamic friction. It is unpredictable and its severity has resulted in many stuck pipe situations. Some engineers have tried to fit friction factors to static friction data. It is considered that this is inappropriate and other methods of trending this data are applicable. It is recommended that T&D software should only be used for modeling dynamic friction.

Functional Requirements for T&D Models

Working towards the next generation of T&D models , a list of functional requirements has been proposed. These are divided into enabling and enhancing functions.

The following proposed functional requirements are

classified as enabling functions : • Improved stiff-string model . A more accurate and

validated stiff-string model that can accurately account for the effects of hole size, clearance, and post-buckling

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6 SPE/IADC 104609

would be of long term benefit to the industry. It is envisioned that the advanced stiff-string model will require longer computational time and has a special application for modeling casing and liners

• Inclusion of static friction in T&D model . Static friction effects are currently not explicitly modeled in any T&D software model. Inclusion of the static friction would be valuable to accurately model the potential for sticking. The inputs to this may reflect the amount of pressure overbalance in the wellbore and the amount surface contact area of the string. This would require the accurate calculation of sag and stand-off which may be possible with an improved stiff-string model.

• Full integration with hydraulics software. T&D and hydraulics software should be integrated into a single package. This would save time in well planning by allowing drillpipe sizing be performed without iterating between several packages. Some integrated software systems have already been developed that support this utility.

• Productivity improvements. Given a casing and well design, the software would calculate the required drillpipe size for each hole section. This would require the use of an integrated package as mentioned above to carry out hole cleaning, pressure drop, equivalent circulating density (ECD) and T&D calculations.

• Wellbore spiraling characterization. An advanced feature to model a spiraled wellbore based on the inputs such as pitch and amplitude or drift of spiral would be extremely helpful. Elevated wall forces would occur in a spiraled wellbore section and as above, a stiff string model would be needed to support such calculations.

• Casing wear calculations. Integration of a proven and industry recognized casing wear algorithm into T&D models is highly desirable. The basic inputs are essentially the same . Only a minimal amount of additional data is needed to define a casing wear model. This feature would save the drilling team a great deal of time, improve consistency and help eliminate errors.

• Domain charts. Domain charts are used to graphically illustrate zones of drilling operability. This prototyping tool utilizes only a minimal set of input data to carry out multiple analyses to define a two-dimensional operating envelope. This approach will assist the drilling engineer or technical specialist to rapidly identify rig and drillpipe requirements for conceptual field development. A domain chart as illustrated in Figure 9 display the drilling envelope for 6-5/8” drillpipe using a set of simplified assumptions.

• Versatility. T&D programs need to be more adaptable so that non-conventional operations and tubulars can be defined. For example this means the ability to define new material types, tractors, wireline operations, underbalanced coil tubing drilling operations, pipeline drilling options and possible combinations of the above.

• Completion and Intervention. T&D programs need to be generalized and to be made more appropriate for the completions and intervention community. The ability to explicitly define and set packers; correctly define the

mechanical properties of expandable sand screens (ESS); the ability to specify Open Hole Gravel Packs (OHGP) with wash pipe and repres enting the complex pipe-in-pipe tubulars using correct mechanical models.

• Dynamic T&D models. For advanced applications transient T&D programs could prove beneficial. Some applications have already been implemented17. These currently focus on bit performance and drillstring vibration. A major challenge with such models is validation since results can only be compared with sensors in the BHA (bottom hole assembly) and surface logging data. With the emergence of wired drillpipe, the future possibility of providing a full scale validation does exist.

The proposed functional requirements that are classified as enhancing requirements include the following

• Instantaneous calibration of T&D models. The use of

online or real-time T&D programs is advocated. Such systems currently exist16. However their application is not widespread and during the next 20 years it is envisioned that such software will be part of a standard drilling surveillance system.

• Torque vs. RPM Effect. Interestingly torque is not just a function of the drillstring model and well design. In practice it is also a function of string RPM. Figure 10 illustrates the variation of torque with RPM while rotating off-bottom. Viscous torque or fluid effects contribute to this variation, but are considered relatively small. It is more likely that at certain speeds, the drillstring is excited through events such as whirl and precession. T&D models for rotary drilling operations do not take this phenomenon into account, since it is a dynamic or transient effect. The RPM adds a degree of complexity to T&D analysis unless same RPM is used consistently throughout. However a recommended approach would be to use a suffix for friction factors, e.g. FF120 would represent a friction factor corresponding to drilling at 120 RPM.

• Sensitivity Metrics. T&D programs can be readily exploited to prove or disprove that certain technologies are beneficial. A sensitivity metric would be a useful aid to the engineer to help understand how responsive the well design is to change in friction factors.

• Model limitations warnings. Proactively make the user aware of any model limitations or key assumptions after each run. Many users have short memories and easily forget the fundamentals.

• Friction factor database . There is considerable amount information in the literature on friction factors for operations in different fields. There is a opportunity for improved sharing of information to enable more accurate FFs to be used for both planning and operations. An industry shared database of FFs would be valuable, however entries would need to be controlled for quality assurance. Friction factor information would be accessible from a standard database and would contain entries by region, mud type, hole size, drillpipe size and operation.

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SPE/IADC 104609 7

Conclusions 1. Despite the availability of T&D software models for over

20 years, only incremental improvements have been made to the underlying mathematical models . The soft -string model is still used in the majority of applications.

2. Many stiff-string models have been developed to overcome soft-string limitations and are available in commercial software packages. However, field data indicates that stiff-string models fail to accurately model the effect of hole size / clearance effects / tortuosity which is considered significant for casing and liner running operations .

3. T&D models used for planning extended-reach and other challenging wells usually only provide a guideline for performance. There is another level of detail, often related to dynamic effects that should ideally be factored into the planning process.

4. It is a common perception that T&D analysis is routine and does not demand a great degree of skill . This perception stems from the fact that it is a straightforward process for the engineer to input data and calculate results. The true value lies in understanding how the software is applied in practice. Skill is needed in understanding friction factors , results sensitivity, T&D management and most importantly being aware of model limitations and their impact on results.

5. Most engineers understand the basic concepts of drillstring buckling. However they are less aware of the model limitations and the practical issues regarding interpretation. Improved education around this topic will help remedy this deficiency.

6. Data collection and analysis is fundamental to a true understanding of the accuracy and applicability of T&D models. Not only must consistency be assured, but data collection at the required frequency is essential.

7. One of difficulties for the engineer is to decide when the stiff string model should be used. Currently there are no definitive guidelines. Ultimately it would be better to have just a single model which the engineer can rely for all calculations.

8. A list of limitations of current T&D models has been discussed. Meanwhile, functional requirements for next generation T&D models have been proposed. The intent is to provide the required assurance that future programs conform to a minimum set of requirements and certifications.

Acknowledgements

The authors wish to thank BP Exploration and Halliburton Energy Services for their support and permission to publish this paper. References 1. Johancsik, C. A., Friesen, D.B and Dawson, R.., “Torque and

Drag in Directional Wells – Prediction and Measurement”, IADC/SPE 11380, IADC/SPE Drilling Conference, New Orleans, February 1983.

2. Kevin, T., and Dawson, R., “Drillstring Design for Directional Wells”, Oil and Gas Journal, April 30, 1984, pp. 61-66.

3. Sheppard, M.C., Wick, C. and Burgess, T., “Designing Well Paths to Reduce Torque and Drag”, SPE 15463, SPE Annual Technical Conference and Exhibition, New Orleans, LA, U.S.A., 5-8 October 1986.

4. Child, A.J. and Ward. A.L., “The Refinement of a Drillstring Simulator: Its Validation and Applications”, SPE 18046, SPE ATCE, Houston, TX, U.S.A., 2-5 October 1988.

5. Rezmer-Cooper, I., Chau, M., Hendricks, A., Woodfine, M., Stacey, B., Downton, N., “Field Data Supports Use of Stiffness and Tortuosity in Solving Complex Well Design Problems”, SPE/IADC Conference, Amsterdam, Holland, 9-11 March 1999.

6. Mason, C.J., Allen, F.M., Ramirez, A.A. and Wolfson, L., “Casing Running Milestones for Extended-Reach Wells”, SPE/IADC 52842, SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 9-11 Mar 1999.

7. Mason, C.J. and Chen, D, C-K, “The Wellbore Quality Scorecard (WQS)”, IADC/SPE 98893, IADC/SPE Drilling Conference, Miami, Florida, U.S.A., 21–23 February 2006.

8. Dawson, R. and Paslay, P.R., Drillpipe Buckling in Inclined Holes, SPE 11167, Sep 1982.

9. Chen, Y. C. and Cheatham, J. B., “Wall Contact Forces on Helically Buckled Tubulars in Inclined Wells”, Trans., ASME 112, 142-144, June 1990.

10. Mitchell, R.F., “Tubing Buckling – The State of the Art”, SPE 104267, SPE Annual Technical Conference and Exhibition, San Antonio, Texas, U.S.A., 24-27 September 2006.

11. Payne, M.L. and Abbassian, F., “Advanced Torque and Drag Considerations in Extended-Reach Wells”, SPE 35102, IADC/SPE Drilling Conference, New Orleans, Louisiana, U.S.A., 1-15 March 1996.

12. Lesso Jr., W.G., Mullens, E. and Daudey, J., “Developing a Platform Strategy and Predicting Torque Losses for Modeled Directional Wells in the Amauligak Field of the Beaufort Sea, Canada”, SPE 19550, , SPE Annual Technical Conference and Exhibition, San Antonio, Texas, U.S.A., 8-11 October 1989.

13. Samuel, G.R., Bharucha, K. and Luo, Y., “Tortuosity Factors for Highly Tortuous Wells: A Practical Approach”, SPE/IADC 92565, SPE/IADC Drilling Conference, Amsterdam, Netherlands, 23-25 February 2005.

14. Aston, M.S., Hearn, P.J. and McGhee, G, “Techniques for Solving Torque and Drag Problems in Today's Drilling Environment”, SPE 48939, SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, U.S.A., 27-30 September 1998.

15. Schamp, J.H., Estes, B.L. and Keller, S.R., “Torque Reduction Techniques in ERD Wells”, IADC/SPE 98969, IADC/SPE Drilling Conference, Miami, Florida, U.S.A., 21–23 February 2006.

16. Adewuya, O.A. and Pham, S.V., “A Robust Torque and Drag Analysis Approach for Well Planning and Drillstring Design”, IADC/SPE 39321, IADC/SPE Drilling Conference, Dallas, TX, U.S.A., 3-6 March 1998.

17. Aslaksen, H., Annand, M., Duncan, R., Fjaere, A., Paez, L., and Tran, U., “Integrated FEA Modelling Offers System Approach to Drillstring Optimization”, SPE 99018, IADC/SPE Drilling Conference, Miami, Florida, U.S.A., 21-23 February 2006.

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8 SPE/IADC 104609

Figure 1: Soft-String T&D Model Schematic

0

20

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60

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100

120

140

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 6,500

Measured Depth (ft)

Ho

okl

oad

(kl

bs)

Soft String Model (12¼" Hole Size: Radial Clearance = 1.3125")

Stiff String Model (12¼" Hole Size: Radial Clearance = 1.3125")Stiff String Model (11" Hole Size: Radial Clearance = 0.6875")

Stiff String Model (10" Hole Size: Radial Clearance = 0.1875")

Stiff String Model (9.75" Hole Size: Radial Clearance = 0.0625")

Stiff String Model (9.70" Hole Size: Radial Clearance = 0.0375")

Running 9-5/8" Casing 47 ppfTooljoint OD = 9-5/8"

Figure 2: Casing Running – Soft-String vs. Hard String T&D Sensitivity

T + ∆T

θ + ∆ θ, φ + ∆φ

T

WN

Ff = µ Nθ , φ

T + ∆T

θ + ∆ θ, φ + ∆φ

T

WN

Ff = µ Nθ , φ

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SPE/IADC 104609 9

0

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0 1,000 2,000 3,000 4,000 5,000 6,000 7,000

Measured Depth (ft)

Incl

inat

ion

(°) /

Azi

mut

h (°

)

0

2

4

6

8

10

12

14

16

Do

gleg

Severity (°/100ft)

Inclination

Azimuth

Dogleg Severity

Figure 3: Well Profile Characteristics for Casing Run

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0 100 200 300 400 500 600 700 800 900 1,000

Measured Depth (m)

Ho

okl

oad

(kl

bs)

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14

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18

20

Do

gleg

Severity (°/30m

)

Slack-Off: FF=0.10/0.12

Pick-Up: FF=0.10/0.12

1st Run - Pick-Up Weight

1st Run - Slack-Off Weight

Dogleg : deg/30m

26" Shoe @ 361.7 m

Traveling Block Weight = 85 klbs

Figure 4: Run 18-5/8” Casing in 21½” Hole with 5 (°/30m) Doglegs

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10 SPE/IADC 104609

0

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0 100 200 300 400 500 600 700 800 900 1,000

Measured Depth (m)

Ho

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oad

(kl

bs)

0

2

4

6

8

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12

14

16

18

20

Do

gleg

Severity (°/30m

)

Slack-Off: FF=0.10/0.12Pick-Up: FF=0.10/0.121st Run - Pick-Up Weight1st Run - Slack-Off Weight2nd Run - Pick-Up Weight2nd Run - Slack-Off WeightDogleg : deg/30m

26" Shoe @ 361.7 m

Traveling Block Weight = 85 klbs

Figure 5: Run 18-5/8” Casing in 24” Hole with 5 (°/30m) Doglegs

0

50

100

150

200

250

300

06:04:30 06:05:00 06:05:30 06:06:00 06:06:30 06:07:00 06:07:30

Time (hh:mm:ss)

Ho

okl

oad

(klb

s)

0

0.2

0.4

0.6

0.8

1

1.2

Block V

elocity (ft/s)

Hookload

Block Velocity

Static Drag

Dynamic Drag

Figure 6: Static vs. Dynamic Drag Illustration

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SPE/IADC 104609 11

Figure 7: Tortuosity created from Steerable Motors as seen from Survey Data

Figure 8: MWD Surve y Tool Measurement in Spiraled Hole

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12 SPE/IADC 104609

0

5,000

10,000

15,000

20,0000 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000

Horizontal Departure (ft)

TV

D (f

t)

0

1,000

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4,000

5,000

6,000

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000

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TV

D (m

)

OK

TORQUELIMITED

TORQUE & OVERPULLLIMITED

HYDRAULICSTORQUE &OVERPULL

LIMITED

Sliding Drilling Difficult

Casing Wear Risk HYDRAULICS & TORQUE

LIMITED

HYDRAULICSLIMITED

Figure 9: Domain Chart – Operability Envelope of 6-5/8” Drillpipe

0

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14:34:05 14:41:17 14:48:29 14:55:41 15:02:53 15:10:05

Str

ing

RP

M

0

5,000

10,000

15,000

20,000

25,000

Su

rfac

e T

orq

ue

(kft

-lb

)

String RPM

Surf Torque

Figure 10: Torque vs. RPM Relationship