Femi Oyedokun

A PROJECT ON EXTENDED-REACH COILED-TUBING DRILLING SPE 168240 Extending the Reach of Coiled Tubing in Directional Wells With Downhole Motors Oyedokun, O. and Schubert J, Texas A&M University Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition held in The Woodlands, Texas, USA, 25-26 March 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers 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 SPE copyright. Abstract A rigorous study has dispelled a longtime myth about coiled-tubing technology. The inability to rotate the tubing limits its reach in the lateral section of the wellbore. Past and current extended-reach techniques for coiled-tubing drilling (CTD) have not been sufficient (individually) in significantly increasing the reach of the tubing in the wellbore; often four or five extended-reach methods are combined to have significant tubing displacement in the wellbore, which is quite expensive to do. After much rigorous investigations and computer simulation tests, the study has demonstrated that a downhole motor (second motor) can be employed in extending significantly the reach of coiled tubing in the wellbore. This technique is expected to also improve hole cleaning process (during CTD), since the configuration allows for the rotation of the coiled tubing string. With the proposed technology having two tubing segments (rotating and nonrotating segments), the investigations show that the two segments will not buckle under applied torsional loads in the course of using a hydraulic downhole motor. But the nonrotating segment of the tubing string will be subjected to severe twisting. Downhole electric motors and a dynamic torque anchor (or full-gaged stabilizer) coupled to a hydraulic motor can be employed to achieve the primary aim of the technology and prevent twisting of the nonrotating segment (the twisting of the segment destabilizes the drilling process). Although the use of a dynamic torque anchor or full-gaged stabilizer can be employed in arresting the twisting moment, it induces high frictional forces, which reduce the lateral displacement of the tubing (relative to an electrodrill). To solve this problem, a new “dynamic torque arrestor” has been proposed in this project. The simulation tests show that the lateral displacements of the tubing in the wellbore (when the newly proposed dynamic torque arrestor is coupled to a hydraulic motor) are greater than the displacements achieved with the use of dynamic torque anchor or full-gaged stabilizer. 2 SPE 168240 Since the proposed technology does not require the intense modification of the current configuration of the coiled tubing unit, its application will be inexpensive. Introduction Sliding the coiled-tubing string along the walls of the wellbore (deviated and lateral sections) generates axial frictional force. As the length of the tubing in these wellbore sections increases, the axial compressive force in the tubing exceeds the critical sinusoidal buckling force. With the tubing having a sinusoidal configuration, the axial drag force acting on the tubing increases and the compressive force in the tubing increases further (coupled with increased tubing length in the lateral section). The third stable configuration of the tubing develops when the axial compressive force exceeds the helical buckling force. The unit normal contact force between the helically-buckled tubing and the wellbore is high and it increases as the axial compressive force in the tubing increases. After having long helically-buckled tubing length, pushing the tubing farther into the wellbore will be impossible (lockup condition). Many techniques have been developed to delay the occurrence of lockup of the tubing in the wellbore but they have their limitations. One of the techniques is buoyancy reduction. Additional reach is achieved by reducing the magnitude of the normal force between the tubing and the wall of the wellbore; but the additional reach of CT in the lateral section of the wellbore is less than 15% (Bhalla 1995). Also, the application of chemical friction reducers has been attempted to extend the reach of CT in the wellbore. The chemicals decrease the friction factor in the wellbore and consequently reduce the frictional force on the tubing. Unfortunately, the chemicals are ineffective in reducing the friction factor in the openhole sections. Similarly, these chemicals cannot be used with air drilling operations. The chemicals are capable of increasing the reach of CT in the wellbore by 35%. Another extended-reach technique that has been explored is straightening of CT. Deploying CT into the wellbore exposes it to large bending stresses. The tubing plastically deforms in the process and a permanent residual curvature is induced in it. The residual curvature limits the extent of the tubing in wellbores. Straighteners are then used to remove the residual bend by subjecting the curved tubing through a reverse bending process. The removal of the residual curvature in the tubing has been seen to extend the reach of CT in deviated and horizontal wellbores by 23% approximately. Although the straightening of the tubing reduces the magnitude of the normal force on the tubing, the technique is not sufficient to highly increase the tubing displacement in the wellbore. Therefore, another extended-reach technique would need to be added to further reduce the drag force. Furthermore, the use of tapered CT was considered to prevent early buckling of the tubular in the wellbore. Delaying the buckling of the tubing in the wellbore postpones lockup. Welding continuous sections of tubing with different wall thicknesses derates the yield strength of the tubing string; the welding joints are the points of weakness. Therefore, the use of tapered string has not been fully accepted in the industry. In addition, tractors have been designed to pull or push the tubular into the wellbore. The tractors are powered by the hydraulic energy of the circulated drilling fluid. The tractors are ineffective in poor hole conditions and increase pipe sticking problems (Leising et al. 1997). Also, the application of axial vibration on the CT marginally increases the reach of the tubing in the deviated and lateral sections of the wellbore (Newman 2007). Torsional vibration is ineffective in extending the reach of the tubing string in wellbores and that the tubing will be subjected to severe fatigue loads during the process. SPE 168240 3 Seeing the failures and limitations of some of the extended-reach techniques, efforts were then directed at revisiting the abandoned idea of Reilly’s coiled-tubing rotary table. In 2003, Reilly designed a rotary table powered by two guide motors. The proposal was not accepted because of its impracticality. Therefore, a canister concept was developed to rotate the coiled-tubing unit in 2006, but the idea is impracticable; the concept could not be commercialized because it was too complicated and ineffective. Reel Revolution Limited in 2007 designed a rotary CT unit having operational characteristics similar to Reilly’s rotary table. The proposed design is known as the Revolver. The CT reel is placed vertically on a turntable, unlike Reilly’s design, which places the reel horizontally. The turntable is operated with a guide motor placed on the work platform. The reel’s weight and other forces are statically and dynamically balanced on the table by a counterbalanced weight (the other forces on the reel are the axial forces generated by pressurized mud in the coiled tubing and the tug from the injector). Unfortunately, this novel idea is not receiving much enthusiasm from the oil and gas companies. One of the reasons is that the rotation of a massive coiled tubing reel, mounted on a skid that is about 4 to 10 ft high, can present itself as a hazard. Furthermore, the design is limited to a maximum rotary speed of 20 rpm, which will not be effective in overcoming the drag in the wellbore at high rates of penetration and increased CT diameter size. Configuration of the Proposed Extended-Reach Method The proposed method is based on the rotation of a predetermined length of the CT string while the section of the string upstream of the downhole motor does not rotate (Fig. 1). As a result of no rotation of the upstream segment of the tubing string, the segment will be subjected to twisting (if a downhole hydraulic motor is used) caused by the effect of the reactive torque from the operation of the hydraulic motor. To prevent the twisting of the nonrotating segment, a dynamic torque anchor or full-gaged adjustable stabilizer can be attached to the top sub of the mud motor (Fig. 2). The rotating segment of the CT string will be powered by a hydraulic motor installed on the tubing string. CT connectors, preferably the dimple type, can link the hydraulic motor to the string at both ends of the motor. The dimple type is preferred because of its ability to withstand high torque and drilling shocks. In case the pin of the connector does not fit into the mud motor’s top or bottom connecting box, an adapter that can withstand high torque will connect the motor to the tubing string. The mud motor would have high torque and low speed characteristics. This simply means that the number of turbine stages for a turbo-drill mud motor would be high while a high lobe ratio would be required for a positive displacement motor (PDM). Also, increasing the eccentricity of the rotor to the stator axis for a PDM can be useful in achieving low rotary speed. Consequently, the high torque demand by the mud motor would lead to an increase in the pressure drop across it. Thus, the predetermined pressure drop must be added to the circulating pressure requirement for CTD operation to maintain the bottomhole pressure. The location of the hydraulic motor on the coiled-tubing string is primarily determined by calculating the length of the rotating section of the coiled tubing. The rotating length of the coiled tubing string is primarily dependent on the hydraulic horse power of the mud motor and the torsional limit of the coiled tubing. Alternatively, a downhole electric motor (Fig. 3) can be used in lieu of a hydraulic motor to prevent twisting. A downhole electric motor is a three-phase asynchronous motor with a spindle (screwed to the motor through a conic thread with journal bearings) that transmits the rotary torque to the driven load. 4 SPE 168240 Use of a Downhole Electric Motor. Downhole electric motors have been used for drilling with jointed drillpipes since the early 1960s. But the running of the electrical cable inside jointed drillpipes, to power the downhole motor, is a big problem. However, coiled tubing provides a good medium for the running of the electrical cable (Fig. 4). The electric cable is insulated from the drilling fluid to prevent electrocution (especially with high conductive drilling fluids). With the insulation kits on the cable, there is a reduction in the area of flow for the drilling fluid. The reduced area of flow increases the flow velocity of the fluid; but the reduced area increases the pressure drops in the tubing. Reducing the rotary speed transmitted to the rotating tubing segment from the electric motor shaft is essential. The output speed from the electric motor is too high for a safe drilling operation; the rotor speed can be as high as 3,000 RPM. To step the rotary speed to a reasonable range, variable speed drive systems can be used in regulating the frequency of the electric power supply; the systems can reduce the frequency of the power supply to reduce the rotary speed of the rotor (Newman et al. 1996). The rotor speed is 2 60 1 1 . Despite the use of the variable speed drive systems, a gear system (Fig. 5) can be used to further reduce the rotary speed; the planetary gear train is a good option for this application. The gear train can provide high gear ratio within a short distance. Large diameter gears are needed to make the significant speed reduction demanded. But the space limitation downhole may preclude the use of large diameter gears. Unless the rotor speed is significantly reduced by the variable speed drive systems or an alternative method to further reduce the rotary speed output from the epicyclic gear train is developed in the future, the use of a downhole electric motor to rotate the coiled tubing string may be difficult. At stage-1 of the gear train system, the sun gear should be the input to the planetary gear assembly (Figs. 6a and 6b) while the planet carrier speed is transmitted to the sun gear at stage-2; this gear selection approach is aimed at having high gear ratio. The governing equations for planetary gear assembly is 2 , 2 , 1 , 0. , 2 3 , Where, 1, 2, . . … . . For this application, the annulus gear is held stationary. Therefore, the gear ratio for each stage is , 1 , , . The rotary speed of the planet carrier at the last stage of the gear train system is derived as 4 SPE 168240 5 , , 5 . 2 Where, 1 and 6 is the number of gear stages. Increasing the number of stator poles may be another way of reducing the synchronous speed of the motor but the length of the motor would have to increase by the order of number of poles to maintain the same power output. Using a downhole electric motor will require that the electric supply (Fig. 7) from the feeder be carefully designed to avert short circuiting and other electrical hazards. Use of a Downhole Hydraulic Motor. A high torque-low speed motor characteristic is preferred for the rotation of the tubing segment. Using a dynamic torque anchor or full-gaged adjustable stabilizer to prevent the twisting of the nonrotating tubing segment generates additional normal contact forces (Figs. 8a and 8b). The magnitude of the induced normal contact forces depends primarily on the magnitude of the applied torque and size of the hole. If the twisting-restraining tools are not used, the nonrotating tubing segment will twist as long as advancement is made into the wellbore; the nonrotating tubing will not buckle under the applied torque, since the minimum buckling torque of the string is higher than the torsional yield strength. The rate of change of the twist angle of the nonrotating tubing segment was derived by Oyedokun (2013) as , , , , , . 7 Eq. 7 does not consider the effect of the traction forces acting on the nonrotating tubing segment; the equation is valid as long as the nonrotating tubing is not buckled. Noting that , and 8 , , . , 9 The twisting of the nonrotating tubing segment will cause destablization to the smooth running of the coiled tubing string. When the rate of change of the reactive torque is zero, the rate of change of the twist angle will reduce but will never be zero as long as the rate of change of the nonrotating tubing length changes. The rate of change of the twist angle becomes , , . 10 When the nonrotating tubing segment buckles under high axial compressive force (greater than the critical helical buckling load), the helically buckled section of the tubing resists the twisting moment. But the unit normal contact force within the helical buckled section where the effect of the twisting moment is felt will be higher than the rest of the helical buckled section “passive” to the twisting torque. 6 SPE 168240 Maximum Rotating-Tubing Length In determining the maximum length of the rotating segment the torsional yield strength of the CT material plays a big role. Since the applied torque on the string increases as the length to be rotated increases (for constant rotary speed), at a critical length of the tubing segment the rotary torque will equal the permissible torque (the product of safety factor and the tubing torsional yield strength) in the tubing string. Similarly, the geometry of the well also affect the length of the rotating segment. The more tortuous the well path the lesser would be the rotating length (because of the increase in drag in the wellbore). The location in the wellbore where the maximum power would be expended by the downhole motor needs to be identified. The location could be at the kickoff point or at the end of build. The ratio of the unit normal contact forces at the curved and lateral sections of the wellbore is a key criterion. As an illustration, considering a 2D well profile (Figs. 9a and 9b); the greatest torque will be applied to the rotating segment when the hydraulic motor reaches the kickoff point if , , , , 1. On the other hand, if 1, then the maximum power will be expended when the mud motor reaches the end of build. The average unit normal force in the curved section of the 2D wellbore is 1 , | 11 | Mitchell et al. (2011) derived the curvature of a wellbore as 12 For a well profile with no azimuth change, 13 For the lateral section of the wellbore, the unit normal force is . , 14 In the quest to determine the location where the maximum torque would be applied on the rotating segment, the first case must be examined (i.e. , , 1 . But the first case is usually valid; the unit normal force in curved section is usually greater than the unit normal force in the lateral section, if the tubing in the lateral section is not buckled. The axial force in the tubing, at the end of built, is SPE 168240 7 , , 15 . The torque required to rotate unbuckled tubing (under high tension) in the curved section of the wellbore is derived (for a 2D well profile) as , 2 cos . 16 For unbuckled tubing under low tension, the required torque is derived as , . 17 But the length of the rotating segment in the lateral section of the wellbore, when the second mud motor reaches the kick off point, is unknown. Therefore, , is derived by summing the required rotary torques for each of the two sections under consideration (lateral and curved) to equal the permissible torque in the rotating segment (i.e. the product of the torsional yield strength of the tubing and a reasonable safety factor). Considering high tension in the curved section of the wellbore when the mud motor gets to the kick off point, the lateral length of the rotating segment is ∑ , , , 2 , . (19) cos 20 sin For low tension, the lateral length of the rotating segment is ∑ , , 18 , , . 21 The rotating length is thus derived as . , 22 In practice, the maximum rotating length may not be achievable because of the prevailing situation in the field. With coiled-tubing drilling, the measured depth at lockup, when the conventional CT drilling method (slide-drilling) is used, provides the available rotating length. On the other hand, if the lateral displacement at lockup (for slide-drilling) is greater than the rotating length (Eq. 22), then, the second motor can be placed at the end of build before rotating the string. Thus, the maximum rotating length of the tubing is ∑ , , , . 23 8 SPE 168240 Since the tubing in the vertical section of the wellbore has low critical buckling loads, having a segment of the rotating length buckled is not desirable (although sometimes it cannot but be allowed). Therefore, to avert the buckling of the rotating length when high weight on bit is required, the following must be taken into consideration: a. Ensure the maximum weight on bit is less than the critical buckling loads (especially the helical buckling load) of the tubing in the lateral section of the wellbore. b. Determine if the tubing string (rotating) in the vertical section of the wellbore will buckle anytime during the drilling operation before reaching the target, by calculating the critical buckling loads and comparing them with the estimated compressive forces in the string. c. If the tubing (rotating segment) in the vertical section of the wellbore will buckle during the course of drilling, the rotating length should be calculated by placing the second motor at the kick off point. Since the rotating tubing in the curved and the lateral sections of the wellbore will not buckle because of higher critical buckling loads (if the maximum weight on bit is not greater than the critical loads at inclined and curved sections), the whirling of the rotating segment and other phenomena resulting from the rotation of buckled tubing will be prevented during the drilling process. d. The weight of the second motor most be considered when determining the weight of the bottomhole assembly. Downhole motors with high torque specification have high weights which can be very significant for coiled-tubing drilling operations. If the weight of the second motor is not considered, the rotating length of the tubing string can be under excessive compressive force than designed for. Although the proposed system configuration can be applied in a drilling operation demanding a high weight on bit (greater than helical buckling load), the procedures above will not be applicable in determining the maximum rotating length of the tubing string. Similarly, it should be noted that the proposed extended-reach technique cannot be effective in extending the reach of coiled tubing in the wellbore when very high weight on bit (greater than the helical buckling load of the tubing string) is applied on the string. With high inclination angle, the contributions of the bottomhole assemblies to the weight on bit may not be sufficient. Therefore, the rotating tubing segment will be under high compression. Since the segment is to be prevented from buckling, the permissible length can be estimated. The length of the rotating tubing (excluding the bottomhole assembly at the bit) that can support the weight on bit without buckling is , . ∑ , 24 , , 25 , In practice, 0.9. Thus, the bottomhole assemblies (plus the second motor assembly) must be adjusted to ensure that the inequality is satisfied. SPE 168240 9 By comparing the values of from Eq. 25 and Eq. 22 (or Eq. 23), the lower of the two is selected as the maximum rotating length of the tubing. Generally, the rotating length must be selected such that the tubing does not buckle when being pushed into the wellbore. Maximum Lateral Displacement The maximum lateral displacement is the algebraic sum of the buckled and unbuckled lengths of the nonrotating segment and the rotating segment of the tubing string (including the bottomhole assembly) at lockup. As an illustration on how this calculation can be done in a typical well configuration, let us consider Fig. 10. Knowing the values of the axial forces at points A to G will be useful in determining the lateral dislpacement at lockup. The rotating segment of the tubing string is prevented from buckling since the maximum weight on bit applied is less than the sinusoidal buckling load. The value of the axial force at point A can be easily determined through F 26 . Using a downhole electric motor, the force at B is , . , 27 On the other hand when a full-gaged stabilizer or dynamic torque anchor is mounted directly to the mud motor, the force at point B is , , , 28 . The length of the straight section in the nonrotating tubing string segment is , 29 . At point C, the sinusoidal buckling of the nonrotating segment is initiated; the value of the axial force is equal to the sinusoidal buckling load of the tubing in the lateral section (Eq. 37). Similarly, at point D the axial force is equal to the helical buckling force of the tubing in the inclined section of the wellbore. The sinusoidal buckled length was derived by Oyedokun (2013) as 2 1 2 2 , 1 2 √ √ 2 , √ . 30 10 SPE 168240 Where, 31 32 Gao and Miska (2009) derived the coefficients a, b, and c as 5 4 24 33 1 5 24 12 24 2 34 5 1 5 4 25 24 5 35 1 5 36 the critical sinusoidal buckling force for a tubing in the inclined section of the wellbore as 2 , 37 , where, 1 2 2 3 1 1 2 2 2 1 2 0.193 0.774 1 1 8 2 8 38 39 , 40 0.371 , and the critical helical buckling force for a tubing in the inclined section of the wellbore as 2√2 , 41 , where, 6 2 3 5 . 10 42 As more length of the nonrotating tubing string lies in the lateral section, points A to D will behave as “rigid points.” Conversely, the displacement between points D and E continues to increase until pushing the tubing further into the wellbore becomes practically impossible (lockup phenomenon); lockup occurs when the compressive force at the kick off point approaches the maximum value , √ , √ , . 43 Since, the critical buckling load in the curved section of the wellbore is very high, this analysis assumes no buckling in that section of the wellbore. Therefore, the force at the end of build when lock up occurs in the vertical section of the wellbore can be derived by solving the differential equation, SPE 168240 11 | | 1 44 0, for a 3D well profile, | | 2 . 45 For a 2D well profile, with constant curvature, the axial force distribution in the tubing (unbuckled) string lying in the curved section of the wellbore is 2 1 1 1 2 1 46 Knowing the force at the end of build and comparing the value with the critical buckling loads (of the tubing in the lateral section of the wellbore), the configuration of the tubing in the lateral section of the wellbore can be known. If the value of the force at the end of build is greater than the helical buckling force (Eq. 41), it suggests that the nonrotating tubing segment will have straight, sinusoidally buckled, and helically buckled sections. Eq. 29 can be used to estimate the length of the sinuoidally buckled section, while the length of the helically buckled section can be estimated by using the model derived by Oyedokun (2013), 2 1 2 1 2 √ , √ √ . 47 48 Where, Therefore, the lateral displacement at lockup (if lockup occurs in the lateral section) is . 49 Discussion Considering the following specification for a horizontal coiled-tubing drilling operation: kick off point at 6,000 ft, build rate of 150/100 ft, openhole size of 6.5 in., openhole friction factor of 0.35, 6.5 in. internal diameter for the casing in the vertical section, 0.3 friction factor in the vertical section, mud density of 8.6ppg, and maximum weight on bit of 3,000 lbf. Assuming a 2 in. tubing with the following specification is being used for the drilling operation: torsional yield strength (CT grade 90) is 3,844 lbf-ft (70% safety factor is assumed), unit weight 3.64 lbf/ft, internal diameter 1.624 in., Young’s Modulus of steel is 30,000 psi. The weight of the downhole motor used (electric or hydraulic) in rotating the tubing is assumed to be 1,800 lbf. The weight of the two stabilizers is assumed to be 550 lbf (with four blades per stabilizer), coefficient of static friction (protective pad-casing) 0.4, and coefficient of static friction (protective pad-openhole) 0.42. 12 SPE 168240 Solution: The friction correction factor for sinusoidal buckling load 1.7631; and helical buckling load 2.6237. Consequently, the buckling loads for the tubing in the horizontal section are: , 9,268 lbf. 4,404 lbf and , a. Without the Rotation of the Tubing The maximum compressive force at the kick off point, from Eq- √0.3 4,560.4 , 4,174.88 But the axial force at the end of build, assuming constant curvature, is 2 1 ⁄ , 1 1 0.7 1 . 4,- 4,558 lbf 0.09 0.09 3,140 lbf Since , , the lateral section of the tubing will not buckle; the tubing displacement in the lateral section, derived is - |- | 126 ft b. Using a hydraulic motor: From the calculations above, the axial force at the end of build, 3,140 lbf and the axial friction force presumed to be induced in the lateral section when the hydraulic motor is assumed to be in the lateral section is- 550 Since this frictional force is greater than curved section of the wellbore. 1 8.6 65.5 - 4,887 lbf , it suggests that the hydraulic motor is either in the vertical or At the end of build, the axial compressive force in the tubing must equal the weight on bit, because the tubing is subjected to rotation (which eliminates axial drag force). Therefore, determining the force at the . kick off point, From Eq. 46, the axial compressive force at the kick off point is 3000 - But, 1800 1,792 lbf 24 550 1 8.6 65.5 - 3,725 lbf The buckled length of the tubing in the vertical section , , can be obtained from Eq. 5.51: SPE 168240 13 √ , This suggests that -√0.3 2498 , maintaining √ a constant weight on -√0.3 bit, the lateral 1,654 ft displacement is Since the mud motor is at the kick off point (Fig. 11), only the rotating length is in the lateral section of the wellbore, for this case. 0.7 3844 - -,891 ft ⁄2 3.1621 87.5 To maintain the maximum weight on bit of 3,000 lbf, the compressive force at the kick off point is lower than the maximum compressive force 4,588 lbf. The tubing can still be pushed a little bit into the curved section of the wellbore, but the compressive force at “A” may approach the maximum compressive force. c. Using a Downhole Electric Motor: Assuming that the electric motor is in the lateral section of the wellbore, the axial friction induced on the tubing string by the installation of the electric motor is 547 lbf. Estimating the length of the nonrotating tubing length in the lateral section, - |- | 368 ft The negative value validates that the electric motor is not in the lateral section of the wellbore, but in the curved or vertical section if the weight on bit is to remain 3,000 lbf. This suggests that the force at the end of built will be 3,000 lbf, since only the rotating tubing segment is in the lateral section of the wellbore. In determining the lateral displacement the electric motor is assumed to be at the end of build. And the length of the electric motor is assumed to be 50 ft and weighing 1800 lbf. From Fig. 12a 50 2 7.51 . 1 It thus implies, the angle of inclination at point Y in Fig. 12is Therefore, the axial compressive force at point Y- And the axial force at the kick off point is 2 1 1 1 But, 0 . 82.49 . 82.49 2 1 3,338 lbf. 1 1 14 SPE 168240 3338 1 1 - . . 1 - 82.49 82.49 4,832 lbf The axial compressive force at the kick off point is greater than the maximum compressive force, 4,588 lbf. This result suggests that the motor assembly is located in the curved section of the wellbore (Fig. 12b), but the exact location is unknown. Through a wise guess, the approximate location of the electric motor can be determined. , noting that 7.51 Assuming Therefore, 41.25 The axial compressive force at point Y-,204 lbf-,389 lbf. And the axial force at the kick off point is 1 0.35 0.7 . -,779 lbf Therefore, the assumed position of the motor assembly is not exact, but it will be located between the assumed inclination angle and the end of build. To estimate the buckled length of the tubing in the vertical section, √ , , √ 1779√- -√0.3 594 ft The displacement of the tubing in the lateral section is 28,-,216 Conclusions After much rigorous investigations, the application of downhole motors in rotating a determined length of coiled tubing, as an extended-reach technology for coiled tubing applications, has proven to be practicable. The other main conclusions are: 1. The twisting moment applied on the nonrotating segment will cause great destabilization when a hydraulic motor is used in rotating the tubing string. Although the rate of change of the twisting moment is zero when the second mud motor and the primary downhole tools are in the same wellbore section, the rate of change of the twist angle will not be zero; the destabilization will still persist. 2. A dynamic torque anchor or a full-gaged stabilizer assembly can be attached to a hydraulic motor to prevent twisting of the nonrotating segment of the tubing string. The use of these wall contact tools in “arresting” the twisting moment induces high normal and binormal contact forces in the wellbore. The induced normal and binormal forces increase the axial frictional forces acting on SPE 168240 15 the tubing string in the wellbore, thus reducing hookload. Nevertheless, the example calculation shows an increase in the lateral displacement of the tubing. 3. Alternatively, a downhole electric motor can be used in lieu of a downhole hydraulic motor (positive displacement motor and turbodrill) to prevent twisting of the nonrotating tubing string. The example calculation shows that the lateral displacement of the tubing in the wellbore increases significantly when a downhole electric motor is used to rotate the tubing segment (despite the additional weight contribution from the second motor). 4. Maximizing the length of the rotating segment of the tubing string increases significantly the lateral displacements of the tubing in the wellbore. The magnitude of the rotating length primarily depends on the torsional yield strength of the tubing and well geometry. 5. Rigorous investigations into the dynamics of the newly proposed coiled-tubing string configuration are needed to improve the robustness of the design. Nomenclature Buoyancy factor Young’s Modulus (psi) Unit vector in the binormal direction to the wellbore path Unit vector in the normal direction to the wellbore path Unit vector in the tangent direction to the wellbore path Frequency of power supply to the electric motor (Hz) Internal shear force in the tubing binormal to its axis (lbf) Critical helical buckling load (lbf) Critical sinusoidal buckling load (lbf) Critical sinusoidal buckling load in a horizontal section with same wellbore diameter ratio and friction factor (lbf) Axial force at the end of build Internal shear force in the tubing normal to its axis (lbf) , , Total shear force in the tubing (lbf) Internal force along the axis of the tubing (lbf) , , , , , Shear modulus of the tubing (psi) Gear ration at a stage Second moment of area of the tubing (in.4) Polar moment of area of the tubing (in.4) Length of the stabilizer/dynamic torque anchor assembly (ft) Length of a BHA component (ft) Lateral displacement (ft) Total length of the second bottomhole assembly Length of a component of the second bottomhole assembly Length of helical buckled section (ft) Instantaneous length of the nonrotating tubing in the wellbore (ft) Total rotating length of the tubing string, excluding the length of the BHA (ft) Rotating length of the tubing when mud motor gets to the KOP (ft) Length of sinusoidal buckled tubing section (ft) Length of the straight section of the nonrotating tubing ft) tubing- 16 SPE 168240 Applied torque on the rotating tubing (lbf-ft) Reactive torque acting on the nonrotating tubing segment (lbf-ft) , Form factor at a gear train stage Number of annulus gear teeth Number of poles in the stator of the electric motor Number of planet gear teeth Number of sun gear teeth Radius of curvature (ft) Distance from the tip of the stabilizer’s (or torque anchor) blade to the center of the wellbore. (in.) Radius of a BHA component (in.) , , , , Radial clearance between tubing and the wellbore/casing (in.) Outer radius of the tubing (in.) Measured depth along the wellbore path (ft) Depth of the kick off point (ft.) Slip velocity fraction , , Weight on bit (lbf) , , , , Safety factor Torsional yield strength of the tubing (lbf-ft) Unit weight of the full-gaged stabilizer assembly or the dynamic torque anchor (lbf/ft) Unit weight of a component of the bottomhole assembly (lbf/ft) Unit normal contact force between unbuckled tubing and the wellbore (lbf/ft) Unit normal contact force between the rotating tubing end (lbf/ft) attached to the bottomhole assembly and the wellbore (lbf/ft) Average unit normal contact force between unbuckled tubing and the wellbore in the curved section (lbf/ft) Average unit normal contact force between unbuckled tubing and the wellbore in the lateral section (lbf/ft) Unit normal contact force between the rotating tubing end attached to second motor and the wellbore (lbf/ft) Weight of the second downhole motor (lbf) Unit weight of the tubing (lbf/ft) Weight of the stabilizer or dynamic torque anchor(lbf) Buckled length of the tubing in the vertical section of the wellbore (ft) Dogleg angle (o) Velocity angle between rate of penetration and the rotary speed of the tubing (o) Friction correction factor for critical sinusoidal buckling force Friction correction factor for critical helical buckling force Azimuth angle of the well (o) Curvature of the wellbore (ft-1) Friction factor SPE 168240 17 Torsion of the wellbore (ft-1) Angle of twist of the nonrotating length of the tubing (o) Rotary speed of the planet carrier at a stage (rev/min) Rotary speed of the rotor shaft (rev/min) Rotary speed of the sun gear at a stage (rev/min) , , References Bhalla, K. 1995. Coiled Tubing Extended Reach Technology. Paper presented at the Offshore Europe, Aberdeen, United Kingdom. SPE-30404-MS. Gao, G. and Miska, S. Z. 2009. Effects of Friction on Post-Buckling Behavior and Axial Load Transfer in a Horizontal Well. Paper presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma. SPE-120084-MS. Leising, L.J., Onyia, E.C., Townsend, S.C. et al. 1997. Extending the Reach of Coiled Tubing Drilling (Thrusters, Equalizers and Tractors). Paper presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands. SPE-37656-MS. Newman, K.R. 2007. Vibration and Rotation Considerations in Extending Coiled-Tubing Reach. Paper presented at the SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, U.S.A. SPE-106979-MS. Newman, K. R., Stone, L. R., Wolhart, L. C. and Wolhart, S. 1996. The Feasibility of Using an Electric Downhole Motor to Drill with Coiled Tubing. Paper presented at the SPE/ICoTA North American Coiled Tubing Roundtable, Montgomery,Texas. SPE36343. Oyedokun, Oluwafemi I, 2013. Extending the Reach of Coiled Tubing in Directional Wells with Downhole Motors. Master’s Thesis, Texas A&M University. Reel Revolution Limited. http://www.reel-revolution.com/. Accessed 2012 SI Metric Conversion Factors ft x 3.048* E 01 =m in. x 2.54* E+01 = mm lbf x 4.448 E+00 =N *Conversion factor is exact. 222 18 SPE 168240 Injector Head System BOP Stack Nonrotating Tubing Segment Dual-Full-Gaged Adjustable Stabilizer Rotating Tubing Segment Downhole Hydraulic Motor Fig. 1—Using a downhole hydraulic motor, coupled with a dual-full-gaged adjustable stabilizer, to rotate a determined tubing length can extend the reach of coiled tubing in the lateral section of the wellbore. SPE 168240 19 Coiled Tubing Coiled-Tubing Connector Dual-Full-Gaged Adjustable Stabilizer with blades covered with elastomeric pads Downhole Electric Motor Downhole Hydraulic Motor Gear Box Coiled-Tubing Connector Coiled Tubing Fig. 2─Schematic drawing of the hydraulic motor and a dual-full-gaged stabilizer assembly. The elastomeric pads on the stabilizer blades are to prevent damage to casings. Fig. 3─Schematic drawing of the downhole electric motor assembly. Moderately big diameter gears will be needed to significantly reduce the rotor speed to a safe tubing rotary speed. 20 SPE 168240 Cable Insulator Power Cable Coiled Tubing Fig. 4—The cable (two wires) transmits high voltage from the surface to the variable drive system, which regulate the frequency of the power supply to the electric motor (after Maurer 2013). Sun Gear Rotor Shaft Annulus Gear Bearing Annulus Gear Gear Train Planet Gears Planet Carrier Adapter Fig. 6a—Epicyclic gear system provides high gear ratio within a short distance. The gears are oil field and hydraulic protected. In this drawing the planet carrier assembly is hidden. Fig. 5—With the use of a variable speed device system, the number of planetary gear train stages reduces; consequently reducing the diameter of the gear in the last stage. SPE 168240 21 Annulus Gear Planet Carrier Output shaft from the Planet Carrier Fig. 6b—The rotary speed of the planet carrier is transmitted to the next planetary gear stage (or the tubing) through the output shaft. The shaft is not connected to the sun gear but coaxial to it. Fig. 7—Electric feed system for the running of the downhole electric motor (Maurer 2013) Stabilizers’ blades with protective pads Fig. 8a—The twisting moments induce normal and binormal contact forces between the stabilizer blades (having eight blades) and the wellbore (top view). 22 SPE 168240 , 8 , , 6 8 8 6 , 6 8 Fig. 8b—The twisting moments induce normal and binormal contact forces between the stabilizer blades (with 8 blades) and the wellbore (end view). , , Nonrotating segment , , Fig. 9b─The unit weight of the tubing in the curved section of the wellbore varies with the axial load in the string. , , Fig.9a─When the second mud motor approaches the KOP, the maximum torque is applied to the rotating segment. SPE 168240 23 G F E D C B A Fig. 10—Schematic representation of possible configuration of the tubing string at lockup condition 1,654 ft 100 ft 3,000 lbf Fig. 11—The induced axial friction caused by the action of the twisting moment on the stabilizer limits the position of the mud motor to the vertical or curved section of the wellbore. 24 SPE 168240 3000 lbf 3000 lbf Fig. 12b—The electric motor in the curved section of the wellbore. 50 ft Fig. 12a—The electric motor at the end of build. US-A1 ( 19) United States (12 ) Oyedokun Patent Application Publication ( 10) Pub . No.: US 2018 /- A1 et al. (43) Pub . Date: (54 ) OPTIMIZED COILED TUBING STRING DESIGN AND ANALYSIS FOR EXTENDED REACH DRILLING (US) ; Robello Samuel, Cypress , TX (US); Gareth M . Braund , Houston , TX (US) 15 /770 , 183 Dec . 16 , 2015 (86 ) PCT No.: PCT/US2015/066014 ABSTRACT System and methods for optimizing coiled tubing string configurations for drilling a wellbore are provided . A length of a rotatable segment of a coiled tubing string having rotatable and non -rotatable segments is estimated based on the physical properties of the rotatable segment. A friction estimated length . An effective axial force for one or more points of interest along the non -rotatable and rotatable string segments is calculated , based in part on the friction factor. Upon determining that the effective axial force for at least one point of interest exceeds a predetermined maximum $ 371 (c )( 1 ), ( 2 ) Date : Apr. 20 , 2018 force threshold , an effective distributive friction factor is estimated for at least a portion of the non - rotatable segment Publication Classification of the string. The rotatable and non - rotatable string segments (51) Int. Cl. E21B 17 /20 (57 ) factor for the rotatable segment is calculated based on the (22 ) PCT Filed : E21B 7 / 06 E21B 17 /20 ( 2013 .01 ); E21B 44 /00 (2013 .01); E21B 77061 (2013 .01 ) (71) Applicant: LANDMARK GRAPHICS CORPORATION , Houston , TX (US ) (72 ) Inventors: Oluwafemi I. Oyedokun , Bryan , TX (21) Appl. No.: (52) CPC U.S . CI............... Oct. 25 , 2018 are redefined for one or more sections of the wellbore along a planned trajectory, based on the effective distributive ( 2006 . 01) ( 2006 .01) friction factor. odce 2 GOLDER ????? ONGRURJ?? mas s ? wwwwwwwwwwww NESANCONG 595 hacerca 424 422 EduWiki de AP opo -432 Patent Application Publication Oct. 25 , 2018 Sheet 1 of 7 ? ? 120 116 ) - US 2018/- ?1 11? 119 ? 1 ? * ? * ? * * . . . . . * . * * ?? ? * ? :? ? . ?? ?? ? ?? * ? ? Z #N ? ? ? ? ?- FIG . 1A 100 Patent Application Publication ww w w ht Oct. 25 , 2018 Sheet 2 of 7 US 2018 /- A1 ar AN N * * 1322 134. whitew KRAKKA 1 whetmnraous P h etisht women 1200 FIG . 1B T 114 Patent Application Publication Oct. 25 , 2018 Sheet 3 of 7 WRRRRRRRRRRRRAAAAANNNNNVVYYYYYYY YyyyyyyYYYYYYYYYYYYYXRX FIG . 2A 2 FIGW0 0 . 2B US 2018 /- A1 Patent Application Publication US 2018 /- A1 Oct. 25 , 2018 Sheet 4 of 7 Define sections of wellbore along planned trajectory XXX *** ANXY V Identify drilling assembly MEW W components arom Determine drill pipe and coil tube physical properties WETTE Estimate length of rotatable and non - rotatable string segments Determine friction factor for 3101 rotatable string segment XXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXXH CXXXKXcsecsecsexxXXSXXXXX X WSCASSESSEX Determine effective axial force for point(s ) of interest uwwww w wwwwwx000xxwwwvwwwwx-nwwwww w zhookload ? 312 Use previously estimated lengths of rotatable and No Axial force at PN 308 non - rotatable segments pan a 320 X1000X70CESTOVANIA 318 Estimate distributive friction factor for whole non rotatable segment < 328 distributive friction 324 Is Pn Yes Estimate factor for non - rotatable Kot stort of Refine estimated segment in loteral and curve ? length of non curved wellbore sections 322 a curved wellbore de section ? THREE * * * * * * * * ** T AKANAN Estimate distributive friction factor for non - rotatable segment in lateral section LOKAKUOS ILLORKOIRAKOKONANIARONOKKRAKKUDAIKIN FIG . 3 TRXLUA SOKXULWEC X rotatable and / or rototable segment( s ) based on friction factor( s ) Patent Application Publication US 2018 /- A1 Oct. 25 , 2018 Sheet 5 of 7 M 4Fa3hr2t SETNUXNAR - 11- 4 4 AB * 420b KANw vW * M*WANAMK * All U*MKUAL AH KRAMNWXvw * W * *XWUvornx ?? , Y W WAw 2 w ORKE xv w LA KA W PENA G 402 - AU KN HAR K w wta bylo NAMNA Poump pume ? ty n t 2X X FYZRNAXpVP 4 . FIG Patent Application Publication Oct. 25 , 2018 Sheet 6 of 7 US 2018/- A1 the Obtain input data for at least one segment of coiled tubing string KEND Determine appropriate parameters for hydraulics analysis based on input dato Oooooommmwww kommwwwxxXXXXKKEN Include cuttings t strength mud ? Yves 508 * CKKA No Measured depth Include viscous TERNYAPHM torque and drag ? Estimate equivalent fluid plastic viscosity WAONE Yes YX41W30 524 (MD) > = Tdepth ? VAATA *K KX X K522ocwmd Enoble RPM option for Hydroulics Anolysis Include high gel XKXX * * KXXXX 520 506 Yes No . No loading effect ? * . ox IV korxWX * * XXXXXWW WWWWWW X *X X X Pipe rotation penetration rate V XXXXXXXXK * segment of string ? warto ONDA * * * * * Circulation rate > critical flow rate ? * 526 ANKWLAMRUMR Yes ve 528 Estimate stress distribution with RPM and bit torque set to zero FOX G * * * * Laminar flow wigox ADOS * * Estimate stress distribution with set to equipollent value RPM set to zero and bit torque No Disoble RPM option for Hydraulics set RPM to zero ) 530 FIG . 5 Patent Application Publication US 2018 /- A1 Oct. 25 , 2018 Sheet 7 of 7 919 TORE NetworkInterface X0 0 X wand wwww WIXIXIXIX * * * * * * * FETTE 606 OutputDeviceInterface AAAAARRRRRRRRRRRRR SystemRowan RAYVwt DeviceInterface kke I I+237I5I2 602 0 0WX Storage 608 Procesor klo 6 . FIG 7199 US 2018 /- A1 OPTIMIZED COILED TUBING STRING DESIGN AND ANALYSIS FOR EXTENDED REACH DRILLING Oct. 25, 2018 BRIEF DESCRIPTION OF THE DRAWINGS 10005) FIG . 1A is a diagram of an illustrative drilling system for drilling a deviated wellbore through a subsurface formation using a segmented coiled tubing string configu ration with a downhole motor located upstream from the FIELD OF THE DISCLOSURE [0001 ] The present disclosure relates generally to direc tional drilling operations using coiled tubing and , more particularly, to extending the reach of coiled tubing within wellbore tions. tubing string for which frictional forces induced by an subterranean formations during directional drilling opera BACKGROUND [0002] To obtain hydrocarbons, such as oil and gas, bore holes are drilled by rotating a drill bit attached to the end of a drill string. Advances in drilling technology have led to the advent of directional drilling, which involves a drilling deviated or horizontal wellbore to increase the hydrocarbon production from subterranean formations. Modern direc tional drilling systems generally employ a drill string having a bottom -hole assembly (BHA ) and a drill bit situated at an end thereof. The BHA and drill bit may be rotated by rotating the drill string from the surface , using a mud motor (i. e ., downhole motor) arranged downhole near the drill bit , or a combination of the mud motor and rotation of the drill string from the surface . Pressurized drilling fluid , commonly referred to as “ mud " or " drilling mud ,” is pumped into the drill pipe to cool the drill bit and flush cuttings and particu lates back to the surface for processing. The mud may also be used to rotate the mud motor and thereby rotate the drill bit. 100031 In some drilling systems, the drill string may be implemented using coiled tubing, typically composed of using such coiled tubing strings include eliminating the need metal or some type of composite material. Advantages of for conventional rigs and drilling equipment. However, the inability to rotate the tubing is one of the primary disadvan tages of conventional coiled tubing strings , as this limits the reach of the string and deviated portion of the wellbore within the formation . Also , conventional coiled tubing strings are likely to buckle as the BHA penetrates the borehole deeper into the formation . Buckling is particularly acute in deviated wells where gravity does not assist in forcing the tubing downhole . Depending on the amount of deviation and the compression of the drill string, the drill string may take on a lateral or sinusoidal buckling mode. When the drill string is in the lateral bucking mode, further compression of the drill string may cause the drill string enters a helical buckling mode . The helical bucking mode may also be referred to as “ corkscrewing.” [ 0004 ] Buckling may result in loss of efficiency in the drilling operation and premature failure of one or more drill string components. For example , as the tubing buckles, the torque and drag created by the contact with the borehole becomes more difficult to overcome and often makes it string ' s bottom hole assembly . [0006 ] FIG . 1B is an enlarged view of a portion of the drilling system of FIG . 1A located at the surface of the 100071 FIG . 2A is a schematic view of a segmented coiled upstream downhole motor are shown for different segments of the string 10008 ]. FIG . 2B is a schematic view of another segmented coiled tubing string for which frictional forces induced by an upstream downhole motor with a twisting-restraining tool are shown for different segments of the string. [0009 ] FIG . 3 is a flowchart of an illustrative process for estimating a distributive friction factor for different seg ments of a coiled tubing string configuration along different sections of a planned wellbore to be drilled within a sub surface formation . [0010 ] FIG . 4 is a schematic view of an illustrative drilling system including a segmented coiled tubing string with a downhole motor located upstream from the string ' s bottom hole assembly for drilling a deviated wellbore through a subsurface formation . [0011 ] FIG . 5 is a flowchart of an illustrative process for analyzing the effect of a segmented coiled tubing string configuration on fluid flow characteristics in one or more sections of the planned wellbore of FIG . 3 . [0012] FIG . 6 is a block diagram of an illustrative com puter system in which embodiments of the present disclo sure may be implemented . DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS [0013] Embodiments of the present disclosure relate to optimizing the design and analysis of coiled tubing strings for drilling deviated wellbores within a subsurface forma tion . While the present disclosure is described herein with reference to illustrative embodiments for particular applica tions, it should be understood that embodiments are not limited thereto . Other embodiments are possible , and modi fications can be made to the embodiments within the spirit and scope of the teachings herein and additional fields in which the embodiments would be of significant utility . [0014 ] In the detailed description herein , references to “ one embodiment," " an embodiment ," " an example embodi ment,” etc ., indicate that the embodiment described may include a particular feature, structure, or characteristic , but every embodiment may not necessarily include the particu lar feature , structure , or characteristic . Such phrases are not necessarily referring to the same embodiment.Further, when a particular feature , structure , or characteristic is described tubing often fatigues from cyclic bending early in the in connection with an embodiment, it is submitted that it is within the knowledge of one skilled in the art to implement such feature, structure , or characteristic in connection with other embodiments whether or not explicitly described . pipe and a rig . relevant art that the embodiments, as described herein , can be implemented in many different embodiments of software , hardware , firmware, and /or the entities illustrated in the impractical or impossible to use coiled tubing to reach distant bypassed hydrocarbon zones. Further, steel coiled drilling process and must be replaced . In such cases , coiled tubing may be as expensive to use for extended reach drilling as a conventional drilling system with jointed steel [0015 ] It would also be apparent to one of skill in the US 2018 /- A1 figures . Any actual software code with the specialized con - trol of hardware to implement embodiments is not limiting Oct. 25, 2018 bottom hole assembly (BHA ) attached to the end of the string. The BHA may include , for example , a rotary steer of the detailed description . Thus , the operationalbehavior of able tool and a drill bit for drilling the wellbore along a embodiments will be described with the understanding that planned path through the subsurface formation in addition to various measurement-while -drilling (MWD ) and /or log modifications and variations of the embodiments are pos sible , given the level of detail presented herein . [0016 ] The disclosure may repeat reference numerals and/ or letters in the various examples or figures . This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodi ments and / or configurations discussed . Further , spatially relative terms, such as beneath , below , lower, above , upper, uphole , downhole , upstream , downstream , and the like, may be used herein for ease of description to describe one element or feature 's relationship to another element(s ) or feature (s ) as illustrated , the upward direction being toward the top of the corresponding figure , the downward direction being toward the bottom of the corresponding figure, the uphole and upstream directions being toward the surface of the wellbore , and the downhole and downstream directions ging -while - drilling (LWD ) sensors for collecting different types of downhole data while the wellbore is drilled . In contrast with conventional drill string configurations in which the downhole motor is integrated within the BHA at the end of the string , the downhole motor of the coiled tubing string described herein is attached to the string as a separate component that is located upstream from the BHA and therefore, may be referred to herein as an " upstream downhole motor” or simply , " upstream motor.” The use of such an upstream motor may also bemore cost effective than using conventional articulated tractor technique for extended -reach drilling operations, as the rotation of a significant length of the string may significantly reduce the cuttings bed volume in the lateral section of the wellbore and thereby reduce operating costs allotted to the surface pump being toward the toe of the wellbore . Likewise , the term that is generally used in coiled tubing systems. uphole direction with respect to a particular component of a may be used to rotate the rotatable segment of the string “ proximal” may be used herein to refer to the upstream or drill string, and the term “ distal” may be used herein to refer to the downstream or downhole direction with respect to a particular drill string component. Unless otherwise stated , the spatially relative terms are intended to encompass dif ferent orientations of the apparatus in use or operation in addition to the orientation depicted in the figures . For example , if an apparatus in the figures is turned over, elements described as being " below ” or “ beneath ” other elements or features would then be oriented “ above” the [0019 ] During the drilling operation , the upstream motor including the drill bit at the very end of the string for purposes of drilling the wellbore through the subsurface formation . The rotational forces applied to the rotatable segment of the string by the motor may cause significant twisting of the non -rotatable segment of the string . Such twisting can destabilize the coiled tubing string and limit the reach of the string and wellbore within the subsurface formation . In some implementations , a stabilizer or twisting restraining tool may be placed between the upstream motor other elements or features . Thus, the exemplary term and the non - rotatable segment to prevent or at leastmitigate below . The apparatus may be otherwise oriented (rotated 90 However, the non - rotatable segment of the string may still degrees or at other orientations ) and the spatially relative descriptors used herein may likewise be interpreted accord be subjected to high axial compressive forces , particularly in curved or tortuous sections of the wellbore path , which can " below ” can encompass both an orientation of above and ingly . [0017] Moreover even though a figure may depict a hori zontal wellbore or a vertical wellbore , unless indicated otherwise , it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in wellbores having other orien tations including vertical wellbores, slanted wellbores, mul tilateral wellbores or the like . Likewise, unless otherwise noted , even though a figure may depict an onshore opera tion , it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in offshore operations and vice - versa . Further, unless otherwise noted , even though a figure may depict a cased hole , it should be understood by those skilled in the art that the apparatus according to the present disclo sure is equally well suited for use in open hole operations . [0018] As will be described in further detail below , any twisting that may occur in this portion of the string . lead to buckling that also limits the reach of the string during the drilling operation . Therefore, an effective design and implementation of such a coiled tubing string configuration should account for the drilling forces expected during a directional drilling operation so as to ensure that such forces remain within an optimal range over the course of the operation and thereby maximize the rate of penetration and reach of the string and wellbore within the formation . [0020 ] Illustrative embodiments and related methodolo gies of the present disclosure are described below in refer ence to FIGS. 1A -6 as they might be employed , for example , in a computer system for well planning and analysis. For example, the disclosed techniques may be implemented as part of a comprehensive workflow provided by a well engineering application executable at the computer system for analyzing different sets of parameters related to the coiled tubing string configuration described above during embodiments of the present disclosure may be used to optimize the design and analysis of a segmented coiled the design and /or implementation phases of a directional drilling operation . Such a workflow may be used to optimize tubing string configured with a downhole motor located upstream from the string' s bottom hole assembly for drilling a deviated wellbore within a subsurface formation . In one or more embodiments, the coiled tubing string may include a the configuration of the coiled tubing string as well as the different types of analysis that may be performed on the string configuration for a particular drilling operation . Other features and advantages of the disclosed embodiments will non - rotatable segment that extends from the surface of the wellbore to a proximal end of a downhole motor. The distal be or will become apparent to one of ordinary skill in the art upon examination of the following figures and detailed end of the downhole motor may be attached to a rotatable segment of the string that extends from the motor to a and advantages be included within the scope of the disclosed description . It is intended that all such additional features US 2018 /- A1 Oct. 25, 2018 embodiments . Further, the illustrated figures are only exem plary and are not intended to assert or imply any limitation with regard to the environment, architecture , design , or process in which different embodiments may be imple detail below with respect to FIG . 6 . mented . control system 110 of drilling system 100 shown in FIG . 1A , area or wide -area network , such as the Internet. An example of such a computing device will be described in further [0025 ] FIG . 1B is an enlarged view of coiled tubing [0021] FIG . 1A is a diagram of an illustrative drilling system 100 for drilling a deviated wellbore through a subsurface formation using a segmented coiled tubing string as described above. As shown in FIG . 1B , control system the string' s bottom hole assembly . As shown in FIG . 1A , system 100 includes a coiled tubing control system 110 at the surface of a wellbore 102. Control system 110 includes by injector 118 through a blowout preventer 134 into the configuration with a downhole motor located upstream from a power supply 112 , a surface processing unit 114 , and a coiled tubing spool 116 . An injector head unit 118 feeds and directs a drill string or coiled tubing string 120 from spool 116 into wellbore 102 . Coiled tubing string 120 includes a 110 includes a spool 116 for feeding coiled tubing string 120 stripper 132 . In operation , coiled tubing string 120 is forced over a guide 128 and through an injector 118 in line with a subsurface formation . A power supply 112 is electrically connected by electrical conduits 138 and 140 to correspond ing electrical conduits in the wall of coiled tubing string 120 . [0026 ] Also , as shown in FIG . 1B , surface processing unit 114 includes communication conduits 142 and 144 that are non -rotatable segment 120a that extends from the surface of wellbore 102 to a proximal end of a downhole motor 122 and a twisting -restraining tool 124 . The distal end of down connected to corresponding conduits housed in the wall of coiled tubing string 120 . It should be appreciated that while only power conduits 138 , 140 and communication conduits 142, 144 are shown in FIG . 1B , any number of power string 120 within a horizontal or lateral section 104 of desired for a particular implementation . It should also be hole motor 122 is attached to a rotatable segment 120b of wellbore 102. conduits and / or communication conduits may be used as segment 120b along with the drill bit attached to a BHA 130 appreciated that power conduits 138 , 140 and communica tion conduits 142 , 144 may extend along the entire length of coiled tubing string 120 . 102 through the subsurface formation . However, it should be 140 and communication conduits 142, 144 in some imple [0022] Downhole motor 122 may be, for example, a hydraulic motor ( e. g ., a mud motor ) used to rotate rotatable at the very end of string 120 for purposes of drilling wellbore appreciated that the disclosed embodiments are not limited to hydraulic motors and that other types of motors (e .g ., electric motors ) may be used instead . Twisting - restraining tool 124 may be , for example , a stabilizer or other drill string component for restraining non -rotatable segment 120a of coiled tubing string 120 to prevent or at least mitigate any twisting of this portion of the string due to the rotational [0027 ] Referring back to FIG . 1A , power conduits 138 , mentations may also be connected to downhole motor 122 and BHA 130 or component thereof. In one ormore embodi ments , communication conduits 142 and 144may be used to transfer data and communication signals between surface processing unit 114 and BHA 130 or component (s ) thereof. For example, communication conduits 142 and 144 may be used to transfer downhole measurements collected byMWD forces applied by motor 122 during the drilling operation . As and /or LWD components of BHA 130 to surface processing downhole motor 122 in this example is a separate compo nent of string 120 that is located upstream of BHA 130 , downhole motor 122 may be referred to as an " upstream motor,” as described above. [ 0023] In one or more embodiments , BHA 130 may unit 114 . Additionally , surface processing unit 114 may use include a drill bit and one or more downhole tools within a housing that may be moved axially within wellbore 102 as attached to coiled tubing string 120 . Examples of such downhole tools may include , but are not limited to , a rotary steerable tool and one or more MWD and /or LWD tools for collecting downhole data related to formation characteristics and drilling conditions over different stages of the drilling operation . In some implementations, one or more force sensors (not shown ) may be distributed along coiled tubing string 120 and BHA 130 for measuring physical force , strain , or material stress at different points along coiled tubing string 120 and BHA 130 . [ 0024 ] The data collected by such downhole tools and conduits 142 and 144 to send control signals to BHA 130 for controlling the operation of BHA 130 or individual compo nents thereof. In this way, surface processing unit 114 may implement different kinds of functionality, e.g ., adjusting the planned trajectory of the wellbore , during different stages of the drilling operation . Similarly , surface processing unit 114 may use conduits 142 and 144 to send control signals for controlling the operation of downhole motor 122 during the drilling operation . [0028] In one or more embodiments , surface processing unit 114 may provide an interface enabling a drilling opera tor at the surface to adjust various drilling parameters to control the drilling operation as different sections of well bore 102 are drilled through the subsurface formation . The interface may include a display for presenting relevant information , e . g ., values of drilling parameters , to the opera tor during the drilling operation as well as a user input sensors may be transmitted to surface processing unit 114 via telemetry ( e . g., mud pulse telemetry ) or electrical signals device (e. g., a mouse , keyboard , touch -screen , etc .) for transmitted via a wired or wireless connection between BHA conditions may continually change over the course of the operation , the operator may use the interface provided by further detail below . Surface processing unit 114 may be surface processing unit 114 to react to such changes in real time and adjust various drilling parameters from the surface in order to optimize the drilling operation . Examples of 130 and surface processing unit 114 , as will be described in implemented using, for example , any type of computing device including at least one processor and a memory for storing data and instructions executable by the processor. Such a computing device may also include a network interface for exchanging information with a remote com puting device via a communication network , e. g ., a local receiving input from the operator. As downhole operating drilling parameters that may be adjusted include , but are not limited to , weight on bit, drilling fluid flow through the drill pipe, the drill string rotational speed , and the density and viscosity of the drilling fluid . US 2018 /- A1 [0029] As described above , the rotational forces applied to the rotatable segment of a coiled tubing string, such as string 120 , by an upstream downhole motor may cause significant twisting of the non- rotatable segment of the string . Conven tional wellbore analysis techniques are generally designed to implement and analyze directional drilling operations using conventional coiled - tubing or jointed -pipe strings . However, an effective design and implementation of a directional drilling operation using the segmented coiled tubing string configuration described herein should account for the types of forces that may be imposed on different segments of the string during the drilling operation , as shown in FIGS. 2A Oct. 25, 2018 friction factor may be applied to a corresponding portion of the non -rotatable string segment; Werk is the wall contact force acting on the string; W , cos 0 ; is the string weight component in the axial direction ; and F , is the axial force in the string . (0035 ] In one or more embodiments , the effective -dis tributive friction factor may be estimated for the non rotatable segment of the coiled tubing string as part of a workflow for developing an overall well plan for a direc tional drilling operation . As will be described in further and 2B detail below with respect to FIGS. 3 -5 , such a workflow may involve performing different types of analyses, including , but not limited to , a torque and drag analysis and a hydrau lics analysis , for the non - rotatable and rotatable segments of the coiled tubing string configuration . downhole motor. FIG . 2B is a schematic view of the portion of the segmented coiled tubing string shown in FIG . 2A , workflow may be implemented as part of the functionality [0030 ] FIG . 2A is a schematic view of a portion of a segmented coiled tubing string that illustrates the various axial forces that may be induced by such an upstream which shows the additional friction thatmay be induced by a twisting-restraining tool, such as twisting -restraining tool 124 of FIG . 1A . To obtain the same force boundary condi tions as in FIG . 2A , i.e ., where no twisting - restraining tool is used , the additional frictional drag forces may be distrib uted over a selected length of the non - rotatable segment of the string . [ 0031] In one or more embodiments, inversion techniques may be used to estimate an effective - distributive friction factor representing the distribution of frictional forces for any cumulative length of the non - rotatable segment of the string. The primary aim of the techniques that are used may be to ensure that the force boundary conditions estimated for starting and ending points of the non -rotatable segment of a string design are representative of the real -world conditions that may be expected during the actual drilling operation . [ 0032] The value of the effective - distributive friction fac tor may depend on , for example , the length of the non rotatable segment of the string . In one or more embodi ments, the length of the non -rotatable segment may be constrained to a predetermined length of the string over which the frictional forces are to be distributed . The length of the non - rotatable string segment may be based on , for example, physical properties of this segment of the string . Examples of such physical properties include , but are not limited to , the torsional yield strength of the tubing material associated with this section of the string and the weight of the string . Other factors that may constrain the length of the non - rotatable segment in the string design may include the planned trajectory of the wellbore (or tortuosity thereof) and the viscosity of the drilling fluid that may be used during the drilling operation . [0033 ] The effective -distributive friction factor for differ ent portions of a particular string configuration may be expressed using Equation ( 1) as follows: [0036 ] In one or more embodiments , the steps of the provided by a well engineering application executable at a computing device of a user (e .g., drilling engineer). The computing device may be implemented using any type of computing device having at least one processor and a processor-readable storage medium for storing data and instructions executable by the processor. As will be described in further detail below with respect to FIG . 6 , such a computing device may also include an input/ output (1/0 ) interface for receiving user input or commands via a user input device , e.g ., a mouse, a QWERTY or T9 keyboard, a touch -screen , a graphics tablet , or a microphone. The I/O interface also may be used by each computing device to output or present information to a user via an output device . The output device may be, for example , a display coupled to or integrated with the computing device for displaying various types of information , including information related to the torque and drag and hydraulics analyses described herein . 10037 ] FIG . 3 is a flowchart of an illustrative process 300 for estimating an effective -distributive friction factor for one or more segments of a coiled tubing string configuration along different sections of a deviated wellbore to be drilled along a planned trajectory within a subsurface formation . For discussion purposes, process 300 will be described using drilling system 100 of FIGS. 1A and 1B , as described above . However, process 300 is not intended to be limited thereto . For example , the coiled tubing string configuration for which the effective - distributive friction factor is estimated may be coiled tubing string 120 of FIGS. 1A and 1B , as described above . As described above , the deviated wellbore in this example may be drilled using an upstream downhole motor ( e . g ., downhole motor 122 of FIG . 1A , as described above), which rotates a drill bit of a BHA attached to the end of a rotatable segment of the coiled tubing string . The rotatable segment of the string may be attached to a distal end of the downhole motor while a non -rotatable segment extending from the surface of the wellbore is attached to a proximal end of the motor. - meeves +wcases; [0038 ] As shown in FIG . 3 , process 300 begins in step 302 , which includes defining a plurality of sections for the planned wellbore trajectory to be drilled within the subsur face formation . The sections that may be defined in step 302 [0034 ] where Ek is a Boolean parameter that defines the string configuration for the non -rotatable segment of the string along a particular section of the wellbore ; k is an index may include, for example, vertical, curved , and lateral section of the wellbore for which an effective distributive refine a previously estimated length of the rotatable and /or defining the tubing configuration ; j is an index defining the sections of the planned wellbore trajectory . As will be described in further detail below , the effective - distributive friction factor estimated using process 300 may be used to US 2018 /- A1 Oct. 25, 2018 non - rotatable segments of the string for one or more of these sections of the planned wellbore trajectory, e .g., as part of the overall well plan being developed for the directional drilling operation in this example. [0039 ] In step 304, components of the coiled tubing string associated with each of the non - rotatable and rotatable segments are identified . The components that may be iden tified for the non -rotatable segment may include , for example and without limitation , one or more stabilizers or twisting - restraining tool( s ) ( e . g ., twisting -restraining tool 124 of FIG . 1A , as described above ) . The physical or mechanical properties of the non - rotatable and rotatable string segments along the wellbore trajectory are then deter mined in step 306 . In step 308 , a length of the rotatable segment of the string along one or more sections of the wellbore may be estimated , based on the corresponding properties of the rotatable segment within one or more wellbore sections. Similarly , the length of the non - rotatable segment may be estimated based on the corresponding properties of the non -rotatable segment within one or more wellbore sections . [ 0040 ] In one or more embodiments, the length of the rotatable segment of the string may be estimated using a three -dimensional (3D ) torque and drag model, e.g., as expressed by Equation (2 ): IR = M.- f *wraß –Mawio– wysing Swastimi (2 ) M ;l'p Wpsing R(f** – B“)+ 34 where B * and B * * may represent curved sections of the wellbore trajectory, e. g., in the form of dog legs , within the subsurface formation . The estimated length may exclude the portions of the rotatable segment corresponding to the downhole motor and the BHA . 0041] In the above torque and drag model according to Equation (3 ), it is assumed that no surface pump constraints are imposed on the downhole coiled tubing string , e . g ., as in drilling system 100 of FIGS. 1A and 1B , as described above . However, a different model may be used to estimate the rotatable length of the coiled tubing string when constraints are imposed on the string by a surface pump , as shown in the example of FIG . 4 . [0042 ] FIG . 4 is a schematic view of an illustrative drilling mented coiled tubing string configuration with a downhole motor 422 located upstream from the BHA for drilling a deviated wellbore through a subsurface formation . As shown system 400 including a surface pump coupled to a seg in FIG . 4 , a surface pump 410 may be used to pump or inject pressurized drilling fluid , e . g ., drilling mud , into a wellbore 402 via a coiled tubing string 420 fed from a spool 412 at the implementations, downhole motor 422 may be a hydraulic motor (e .g ., a mud motor) and the drilling fluid (e .g ., mud ) may also be used to rotate the motor and thereby rotate drill bit 432 [0043 ] Similar to coiled tubing string 120 of drilling tubing string 420 includes a non -rotatable segment 420a that extends from the surface of wellbore 402 and attaches to a system 100 of FIGS. 1A and 1B , described above , coiled proximal end of downhole motor 422 and a twisting -re straining tool 424 . The distal end of downhole motor 422 is attached to a rotatable segment 420b of string 420, which is located within a horizontal or lateral section of wellbore 402 in this example . In contrast with drilling system 100 of FIGS . 1A and 1B , the use of surface pump 410 in system 400 may impose constraints on coiled tubing string 420 within wellbore 402 . [0044 ] For example, the pressurized fluid injection capa bility or discharge capacity of surface pump 410 may constrain the length of rotatable segment 420b during the drilling operation . In one or more embodiments, the amount of pressure change (AP ) may be estimated for different points of interest along the length of coiled tubing string 420. In the example as shown in FIG . 4 , APA may represent the pressure drop at downhole motor 422 while APs and APG may represent pressure drops in the drill pipe/tubing and annulus, respectively , corresponding to rotatable segment 420b. Accordingly , the pressure drop AP , along coiled tubing string 420 , excluding downhole motor 422 and rotat able string segment 420b , may be expressed as the sum of the pressure drop values at the remaining points of interest along the length of coiled tubing string 420 , as expressed by Equation (3 ): AP1+AP 2 + AP 3 + AP 7 + AP : + AP , = APL ( 3 ). [0045] In one or more embodiments, the constrained ment may be estimated based on an optimization technique length and /or other dimensions of the rotatable string seg that accounts for such surface constraints on the string configuration at different points within wellbore 402 . Such an optimization technique may be based on , for example , a Pareto optimization or Lagrange multiplier. The objectives of the optimization may include maximizing the total mea sured depth (1m ) , maximizing the total length (1, ) of rotat able segment 420b , and minimizing the pressure drop within rotatable segment 420b of coiled tubing string 420 , as expressed by Equations (4 ), (5 ), and (6 ), respectively: Maximize: Ime= 2;=1'1 - > Maximize: Al, =f(AP 4, ) Minimize: APs =f(a , 0 ) where x and W are vectors of parameters affecting the rotating length estimation which can be optimized in the process of determining constrained optimum value of the surface of the wellbore. While not shown in FIG . 4 , it should length . As used herein , the term “measured depth ” may refer to a depth of the string that is estimated or expected to be control system that includes a power supply and a surface measured for one or more sections of the wellbore once it is actually drilled along its planned trajectory within the sub surface formation . [0046 ] The constraints for the above-described optimiza tion technique may be expressed by Equations (7 ), (8 ), and be appreciated that spool 412 may be part of a coiled tubing processing unit, e .g ., similar to control system 110 of FIGS. 1A and 1B , as described above . The drilling fluid may be used , for example, to cool a drill bit 432 attached to the end of a BHA 430 as well as to flush cuttings and particulates back to the surface during the drilling operation . In some ( 9 ) as follows: US 2018 /- A1 Oct. 25, 2018 Ppump=2;=, AP; OMSE < Oy (8) Fo =S (9) where P pump is the pumping pressure, Omse is the mechani cal specific energy of the string , o ,, is the string 's yield strength , Fo is the force applied to a top portion or proximal end of the string 's downhole assembly or BHA within the subsurface formation , § is the force applied at a bottom portion or distal end of the string' s downhole assembly or BHA within the subsurface formation . [ 0047 ] Referring back to FIG . 3, once the length of the rotatable segment is estimated in step 308 , e . g ., using either the torque and drag model or the optimization technique as described above, process 300 then proceeds to step 310 , which includes calculating a friction factor for the rotatable segment based on the estimated length . In step 312 , an effective axial force may be estimated for one or more points of interest along the non -rotatable and rotatable segments of the drill string, based in part on the friction factor calculated for the rotatable segment in step 310 . [0048 ] Process 300 then proceeds to step 314, which includes determining whether or not the effective axial force estimated in step 312 for at least one point of interest exceeds a predetermined maximum hook load threshold. If it is determined that there are no points of interest for which the effective axial force exceeds the predetermined maxi segment in either of steps 320 or 326 may then be used in step 328 to refine the length of the non -rotatable segment as previously estimated ( in step 308 ) for one or more sections of the planned wellbore trajectory . In one or more embodi ments, the refined length of the non -rotatable segment may also be used to refine the previously estimated length of the rotatable segment of the string. 10051 ] In one or more embodiments, the steps of process 300 , including the estimation of the effective- distributive friction factor for the non -rotatable string segment as described above , may be part of a torque and drag analysis of the string configuration . The distributive friction factors resulting from the torque and drag analysis may then be incorporated into a hydraulics analysis for the string con figuration . The hydraulics analysis may include, for example, analyzing the effect of rotating a portion of the coiled tubing string (e . g ., rotatable segment 420b of string 420 of FIG . 4 , as described above ) on the fluid flow characteristics expected for one or more sections of the wellbore along its planned trajectory through the subsurface formation . [0052] In one or more embodiments , such an analysis may involve adjusting a plastic viscosity parameter of a drilling fluid to be used with the particular coiled tubing string configuration . The plastic viscosity parameter may be adjusted according to , for example , Equation (10 ): mum hook load threshold , process 300 proceeds to step 316 , ( 10 ) in which the previously estimated length of the rotatable string segment (from step 308 ) for one or more sections of the wellbore trajectory is used for the coiled tubing string design . However, if the effective axial force for at least one point of interest is determined to exceed the predetermined maximum hook load threshold , process 300 proceeds to step 318, which includes determining whether or not the particu lar point of interest is within or corresponds to a curved where K2 is the resultant plastic viscosity due to the rotation of the rotatable segment of the string , K1 is the initial plastic viscosity , and Ay is the shear rate of deformation of the fluid as a result of the rotation of the string segment. In addition section of the wellbore . to adjusting the plastic viscosity parameter using Equation ( 10 ), the hydraulic analysis may include adjusting or cali process 300 proceeds to step 320 , which includes estimating trajectory , as will be described in further detail below with brating operating parameters of the string configuration that [0049] If it is determined in step 318 that the point of may impact the fluid flow along the planned wellbore interest does not to correspond to a curved wellbore section , the effective - distributive friction factor for the entire non respect to FIG . 5 . rotatable segmentof the drill string, including for portions of [0053] FIG . 5 is a flowchart of an illustrative process 500 lateral sections of the planned wellbore trajectory . However, configuration on fluid flow characteristics in one or more the non - rotatable segment within the vertical, curved , and/ or if the point of interest is determined to correspond to a curved wellbore section , process 300 proceeds to step 322 , for analyzing the effect of a segmented coiled tubing string sections of the planned wellbore of FIG . 3 , as described above. For discussion purposes , process 500 will be which includes determining whether or not the point of interest is located on a part of the non -rotatable string segment at or near the start of the curved section . described using drilling system 100 of FIGS. 1A and 1B , as described above . However, process 500 is not intended to be step 322 to be located at or near the start of the curved section , process 300 proceeds to step 324 , which includes described above, but is not intended to be limited thereto . [0050 ] If the particular point of interest is determined in estimating the effective - distributive friction factor for a portion of the non -rotatable segment corresponding to the curved and lateral sections of the planned wellbore trajec limited thereto . Also , for discussion purposes, process 500 will be described using drilling system 400 of FIG . 4 , as For example , the coiled tubing string configuration may be implemented using either string 120 of FIGS. 1A and 1B or string 420 of FIG . 4 , as described above . [0054] Process 500 begins in step 502 , which includes tory . Otherwise, it may be assumed that the point is located obtaining input data for initiating the hydraulics analysis for on a part of the non - rotatable string segment at or near the at least one segment of the coiled tubing string . The input end of the curved section and process 300 proceeds to step 326 , which includes estimating the effective -distributive of the subsurface formation in which one or more sections friction factor for a portion of the non - rotatable segment corresponding to only the lateral section of the planned wellbore trajectory . The effective- distributive friction factor that is estimated for the portion ( s) of the non -rotatable data may include, for example, data related to the properties of the wellbore are to be drilled along with the properties of the drilling fluid associated with the well plan . Additionally, the input data may include operating parameters associated with the drilling operation including , but not limited to , the US 2018 /- A1 rotation rate or rotary speed of the rotatable segment of the tubing string, e.g., as measured in revolutions per minute (RPM ), which may initially be set to a value of zero . The input data may further include the pump rate and other parameters thatmay be relevant to the particular type of fluid to be used for drilling . [0055 ] Process 500 then proceeds to step 504 , which includes determining appropriate parameters for the hydrau lics analysis based on the input data . In addition to the fluid plastic viscosity parameter described above , examples of other parameters that may be considered for the hydraulics analysis include , but are not limited to , cuttings loading effect, mud type , measured depth , pipe rotation or penetra tion rate , circulation rate, and type of flow regime. As illustrated in the example of FIG . 5 , step 504 may be performed as a series of decisions regarding whether or not such parameters are to be included in the hydraulics analy sis , as will be described in further detail below with respect to steps 506 , 508 , 510 , 512 , 514 and 516 of process 500. [0056 ] In one or more embodiments , such decisions may be made based on input from a user of a well engineering application executable at the user 's computing device , as described above. For example, the steps of process 500 may be implemented as part of the functionality provided to the user by the well engineering application . In one or more embodiments, the user may access such functionality via a graphical user interface (GUI) of the well engineering application. The user may interact with the GUI to specify various options corresponding to the parameters of interest for the torque and drag analysis described above with respect to process 300 of FIG . 3 as well as the hydraulics analysis based on process 500 . In some implementations, the parameters associated with each type of analysis may be displayed as user- selectable options within a corresponding Oct. 25, 2018 proceeds to step 510 ,which includes determining whether or not a “measured ” depth (MD ), which may be an estimated depth of the string or value of the depth expected to be measured within the subsurface formation , is greater than or equal to a predetermined threshold depth (Tdepth ). The estimated depth of the wellbore trajectory may be based on , for example, a length of the rotatable segment of the coiled tubing string , e.g ., as estimated in step 308 of process 300 of FIG . 3, as described above. 10059 ] If it is determined in step 510 that such a measured depth is less than the predetermined threshold depth , process 500 proceeds directly to step 518 and the string's RPM is excluded from the hydraulics analysis as described above . However , if the measured depth is determined to be greater than or equal to the predetermined threshold , process 500 proceeds to step 512 , which includes determining whether or not a pipe rotation / penetration rate exceeds a predetermined threshold rate ( Trate ) . [0060] If it is determined in step 512 that the pipe rotation / penetration rate does not exceed the predetermined threshold rate , process 500 proceeds directly to step 518 as before . Otherwise , process 500 proceeds to step 514 , which includes determining whether or not a circulation rate of the drilling fluid exceeds a predetermined critical flow rate . If it is determined in step 514 that the fluid ' s circulation rate does not exceed the predetermined critical flow rate, process 500 proceeds directly to step 518 . Otherwise , process 500 pro ceeds to step 516 , which includes determining whether or not the type of flow regime associated with the fluid is a laminar flow regime. [0061 ] If it is determined in step 516 that the type of flow regime is not laminar flow , process 500 proceeds to step 518 , after which process 500 ends . Otherwise , process 500 pro settings panel or other dedicated window or area of the GUI for providing user control options for each type of analysis ceeds to step 520 , in which the string ' s rotation rate ( or RPM ) is taken into account, e . g ., RPM option is enabled and to be performed for the string configuration in this example. set to a specified value, for the hydraulics analysis, as [ 0057 ] In one or more embodiments , the inclusion or which includes determining whether or not to include vis exclusion of certain parameters may be used to determine whether or not the rotation rate /rotary speed ( or RPM ) ofthe string should be included in the hydraulics analysis , e . g ., whether or not to automatically , without user intervention , disable (step 518 ) or enable ( step 520 ) an RPM option within a hydraulics analysis settings panel of the GUI provided by the well engineering application , as will be described in further detail below . [0058] For example , step 506 may include determining whether or not to include the effect of a cuttings loading parameter in the hydraulics analysis . If the cuttings loading effect is determined not to be included (e.g., the user has disabled this option for the hydraulics analysis ), process 500 proceeds directly to step 520 , in which the string 's rotation rate /rotary speed ( or RPM ) is taken into account for the hydraulics analysis , e .g., by automatically enabling the RPM option in the hydraulics settings panel of the as described above . Otherwise , process 500 proceeds to step 508, which includes determining whether or not the drilling fluid under analysis is a high gel strength mud . If the fluid is determined not to be a high gel strength mud , process 500 proceeds directly to step 518 , in which the string's rotation rate (or RPM ) is excluded from the hydraulics analysis , e . g., by automatically disabling the RPM option in the hydraulics described above . Process 500 then continues to step 522 , cous torque and drag as part of the hydraulics analysis . [0062] If it is determined in step 522 that viscous torque and drag is to be included in the hydraulics analysis , process 500 proceeds to step 524 , which includes estimating an equivalent fluid plastic viscosity . Otherwise, process 500 proceeds to step 526 , which includes determining whether or not the particular segment of the coiled tubing string that is currently under analysis is a non -rotatable segment of the string. [0063] If it is determined in step 526 that the current segment is a non -rotatable segment of the string, process 500 proceeds to step 528, which includes estimating or calcu lating the stress distribution for the non - rotatable segment with the string ' s rotation rate or RPM and bit torque set to values of zero . However, if it is determined that the current segment is a rotatable segment of the string, process 500 proceeds to step 530 , which includes estimating the stress distribution for the rotatable segment with the string 's RPM set to zero and the bit torque set to an equipollent value. In one ormore embodiments, the torque and string rotary speed may be implemented as separate modules within the above described well engineering application , where the modules may provide corresponding sets of input options for the settings panel as described above or setting the string' s hydraulics analysis in different areas of the application ' s rotation rate to a value of zero . Otherwise, process 500 GUI. US 2018 /- A1 [0064] FIG . 6 is a block diagram of an illustrative com puter system 600 in which embodiments of the present disclosure may be implemented . For example , the steps of processes 300 and 500 of FIGS . 3 and 5 , respectively , as described above, may be performed by system 600 . Further , system 600 may be used to implement, for example , surface processing unit 114 of FIGS . 1A and 1B , as described above . System 600 can be any type of electronic computing device or cluster of such devices, e . g., as in a server farm . Examples of such a computing device include, but are not limited to , a server, workstation or desktop computer, a laptop com puter, a tablet computer, a mobile phone, a personal digital Oct. 25, 2018 devices (also called “ cursor control devices ” ). Output device interfaces 606 enables, for example , the display of images generated by the system 600 . Output devices used with output device interface 606 include, for example , printers and display devices, such as cathode ray tubes (CRT) or liquid crystal displays (LCD ). Some implementations include devices such as a touchscreen that functions as both input and output devices. It should be appreciated that embodiments of the present disclosure may be implemented using a computer including any of various types of input and output devices for enabling interaction with a user. Such interaction may include feedback to or from the user in assistant (PDA ), a set -top box , or similar type of computing device . Such an electronic device includes various types of different forms of sensory feedback including , but not lim computer readable media and interfaces for various other types of computer readable media . As shown in FIG . 6 , back . Further, input from the user can be received in any form including , but not limited to , acoustic , speech , or tactile system 600 includes a permanent storage device 602 , a system memory 604 , an output device interface 606 , a transmitting and receiving different types of information , system communications bus 608 , a read -only memory (ROM ) 610 , processing unit(s ) 612 , an input device inter face 614 , and a network interface 616 . [0065 ] Bus 608 collectively represents all system , periph eral, and chipset buses that communicatively connect the numerous internal devices of system 600 . For instance , bus 608 communicatively connects processing unit(s ) 612 with ROM 610 , system memory 604 , and permanent storage device 602 . [0066 ] From these various memory units, processing unit ( s ) 612 retrieves instructions to execute and data to process in order to execute the processes of the subject disclosure . The processing unit(s ) can be a single processor or a ited to , visual feedback , auditory feedback , or tactile feed input. Additionally , interaction with the user may include e .g ., in the form of documents, to and from the user via the above -described interfaces. 10070] Also , as shown in FIG . 6 , bus 608 also couples system 600 to a public or private network (not shown ) or combination of networks through a network interface 616 . Such a network may include , for example , a local area network ("LAN ” ), such as an Intranet, or a wide area network (“ WAN ” ), such as the Internet. Any or all compo nents of system 600 can be used in conjunction with the subject disclosure . [0071] These functions described above can be imple mented in digital electronic circuitry , in computer software , firmware or hardware . The techniques can be implemented multi- core processor in different implementations. using one or more computer program products . Program [ 0067 ] ROM 610 stores static data and instructions that are needed by processing unit ( s ) 612 and other modules of mable processors and computers can be included in or packaged as mobile devices. The processes and logic flows system 600 . Permanent storage device 602 , on the other can be performed by one or more programmable processors hand , is a read - and -write memory device . This device is a non - volatile memory unit that stores instructions and data even when system 600 is off. Some implementations of the subject disclosure use a mass-storage device (such as a magnetic or optical disk and its corresponding disk drive ) as permanent storage device 602 . [ 0068 ) Other implementations use a removable storage device (such as a floppy disk , flash drive , and its corre sponding disk drive ) as permanent storage device 602 . Like permanent storage device 602, system memory 604 is a read - and -write memory device . However, unlike storage device 602 , system memory 604 is a volatile read - and -write memory , such a random access memory . System memory 604 stores some of the instructions and data that the pro cessor needs at runtime. In some implementations, the processes of the subject disclosure are stored in system memory 604 , permanent storage device 602 , and /or ROM 610 . For example, the variousmemory units include instruc tions for computer aided pipe string design based on existing string designs in accordance with some implementations. From these various memory units, processing unit( s ) 612 retrieves instructions to execute and data to process in order to execute the processes of some implementations . and by one or more programmable logic circuitry . General can be interconnected through communication networks. [0072 ] Some implementations include electronic compo and special purpose computing devices and storage devices nents , such as microprocessors , storage and memory that store computer program instructions in a machine-readable or computer- readable medium (alternatively referred to as computer-readable storage media , machine -readable media, or machine -readable storage media ). Someexamples of such computer-readable media include RAM , ROM , read -only compact discs (CD -ROM ), recordable compact discs (CD R ), rewritable compact discs (CD -RW ) , read -only digital versatile discs (e .g ., DVD -ROM , dual- layer DVD -ROM ), a variety of recordable/rewritable DVDs (e . g., DVD -RAM , DVD -RW , DVD +RW , etc .), flash memory ( e.g ., SD cards, mini-SD cards , micro - SD cards, etc .), magnetic and/or solid state hard drives , read -only and recordable Blu -Ray® discs , ultra density optical discs, any other optical or magnetic media , and floppy disks. The computer-readable media can store a computer program that is executable by at least one processing unit and includes sets of instructions for per forming various operations. Examples of computer pro [0069] Bus 608 also connects to input and output device interfaces 614 and 606 . Input device interface 614 enables grams or computer code include machine code, such as is produced by a compiler, and files including higher -level code that are executed by a computer, an electronic com to the system 600 . Input devices used with input device interface 614 include , for example , alphanumeric , QWERTY, or T9 keyboards, microphones, and pointing [0073] While the above discussion primarily refers to microprocessor or multi -core processors that execute soft ware , some implementations are performed by one or more the user to communicate information and select commands ponent, or a microprocessor using an interpreter. US 2018 /- A1 integrated circuits, such as application specific integrated circuits (ASICs ) or field programmable gate arrays (FP GAS ). In some implementations, such integrated circuits execute instructions that are stored on the circuit itself. Accordingly , the steps of processes 400 and 500 of FIGS. 4 and 5 , respectively , as described above ,may be implemented using system 600 or any computer system having processing circuitry or a computer program product including instruc tions stored therein , which , when executed by at least one processor , causes the processor to perform functions relating to these processes. [0074 ] As used in this specification and any claims of this application, the terms “ computer” , “ server” , “ processor” , and “ memory ” all refer to electronic or other technological devices. These terms exclude people or groups of people . As used herein , the terms " computer readable medium ” and " computer readable media ” refer generally to tangible , physical, and non -transitory electronic storagemediums that store information in a form that is readable by a computer. [0075 ] Embodiments of the subject matter described in Oct. 25, 2018 processing circuitry or a computer program product includ ing instructions which , when executed by at least one odology described herein . processor, causes the processor to perform any of the meth [0079 ] As described above, embodiments of the present disclosure are particularly useful for optimizing coiled tub ing string configurations for drilling operations. In one or more embodiments of the present disclosure , a method for optimizing coiled tubing string configurations for drilling operations includes : determining a plurality of sections for a wellbore to be drilled along a planned trajectory through a subsurface formation ; determining physical properties of a coiled tubing string for drilling the wellbore along the planned trajectory, the coiled tubing string having a non rotatable segment and a rotatable segment; estimating a length of the rotatable segment of the coiled tubing string, based on the physical properties corresponding to the rotat able segment; calculating a friction factor for the rotatable segment based on the estimated length of the rotatable segment; estimating an effective axial force for one ormore points of interest along the non - rotatable and rotatable this specification can be implemented in a computing system that includes a back end component, e . g ., as a data server, or that includes a middleware component, e . g ., an application segments of the coiled tubing string, based in part on the server , or that includes a front end component, e . g ., a client determining that the effective axial force for at least one of the one or more points of interest exceeds a predetermined computer having a graphical user interface or a Web browser through which a user can interact with an implementation of the subject matter described in this specification , or any combination of one ormore such back end, middleware, or front end components. The components of the system can be interconnected by any form or medium of digital data communication , e . g ., a communication network . Examples of communication networks include a local area network (“ LAN ” ) and a wide area network (“ WAN ” ) , an inter network (e .g., the Internet), and peer-to -peer networks ( e.g ., friction factor calculated for the rotatable segment; upon maximum force threshold , estimating an effective distribu tive friction factor for at least a portion of the non -rotatable segment of the coiled tubing string ; and redefining the rotatable and non -rotatable segments of the coiled tubing string for one or more of the plurality of sections of the wellbore to be drilled along the planned trajectory, based on the estimated effective distributive friction factor for the portion of the non - rotatable segment. [0080 ] For the foregoing embodiments , the method or ad hoc peer-to -peer networks). steps thereof may include any of the following elements , 10076 ) The computing system can include clients and servers . A client and server are generally remote from each either alone or in combination with each other: the effective other and typically interact through a communication net distributive friction factor represents a distribution of fric segment of the coiled tubing string along one or more of the tional drag forces over a selected length of the non -rotatable work . The relationship of client and server arises by virtue of computer programs running on the respective computers and having a client- server relationship to each other. In some maximum force threshold is a predetermined maximum embodiments , a server transmits data ( e . g ., a web page ) to a client device ( e . g ., for purposes of displaying data to and mated for portions of the non -rotatable segment correspond receiving user input from a user interacting with the client device ). Data generated at the client device ( e . g ., a result of the user interaction ) can be received from the client device at the server. [ 0077 ] It is understood that any specific order or hierarchy of steps in the processes disclosed is an illustration of exemplary approaches . Based upon design preferences, it is plurality of sections of the wellbore ; the predetermined hook load ; the effective distributive friction factor is esti ing to lateral and curved sections of the wellbore along the planned trajectory ; the effective distributive friction factor is estimated for a portion of the non -rotatable segment corre sponding to a lateral section of the wellbore along the planned trajectory ; the rotatable segment ofthe coiled tubing string includes a downhole motor and a bottom hole assem bly , and the downhole motor is located upstream from the understood that the specific order or hierarchy of steps in the processes may be rearranged , or that all illustrated steps be performed . Some of the steps may be performed simultane bottom hole assembly on the rotatable segment of the coiled and parallel processing may be advantageous . Moreover, the motor is a hydraulic motor. ously . For example , in certain circumstances , multitasking separation of various system components in the embodi ments described above should not be understood as requir ing such separation in all embodiments , and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software prod ucts . [ 0078 ] Furthermore , the exemplary methodologies described herein may be implemented by a system including tubing string; the non - rotatable segment ofthe coiled tubing string extends from a surface of the wellbore and attaches to a proximal end of the downhole motor; and the downhole [0081 ] Also , a system for optimizing coiled tubing string configurations for drilling operations has been described . Embodiments of the system may include at least one pro cessor and a memory coupled to the processor having instructions stored therein , which when executed by the processor, cause the processor to perform functions includ ing functions to : determine a plurality of sections for a wellbore to be drilled along a planned trajectory through a subsurface formation , determine physical properties of a US 2018 /- A1 coiled tubing string for drilling the wellbore along the planned trajectory , where the coiled tubing string has a non - rotatable segment and a rotatable segment ; estimate a length of the rotatable segment of the coiled tubing string, based on the physical properties corresponding to the rotat able segment; calculate a friction factor for the rotatable segment based on the estimated length of the rotatable segment ; estimate an effective axial force for one or more points of interest along the non - rotatable and rotatable segments of the coiled tubing string , based in part on the friction factor calculated for the rotatable segment ; deter mine whether or not the effective axial force for at least one of the one ormore points of interest exceeds a predetermined maximum force threshold ; estimate an effective distributive friction factor for at least a portion of the non -rotatable segment of the coiled tubing string, when the effective force for at least one of the one or more points of interest is determined to exceed the predetermined maximum force threshold ; and redefine the rotatable and non -rotatable seg ments of the coiled tubing string for one or more of the plurality of sections of the wellbore to be drilled along the planned trajectory, based on the estimated effective distribu tive friction factor for the portion of the non -rotatable segment. Likewise , a computer -readable storage medium has been described and may generally have instructions stored therein , which when executed by a computer cause the computer to perform a plurality of functions, including functions to : determine a plurality of sections for a wellbore to be drilled along a planned trajectory through a subsurface formation; determine physical properties of a coiled tubing where the coiled tubing string has a non -rotatable segment and a rotatable segment; estimate a length of the rotatable segment of the coiled tubing string , based on the physical string for drilling the wellbore along the planned trajectory , properties corresponding to the rotatable segment ; calculate a friction factor for the rotatable segment based on the estimated length of the rotatable segment; estimate an effec tive axial force for one or more points of interest along the non - rotatable and rotatable segments of the coiled tubing string, based in part on the friction factor calculated for the rotatable segment; determine whether or not the effective axial force for at least one of the one or more points of interest exceeds a predetermined maximum force threshold ; estimate an effective distributive friction factor for at least a portion of the non -rotatable segment of the coiled tubing string, when the effective force for at least one of the one or more points of interest is determined to exceed the prede termined maximum force threshold ; and redefine the rotat able and non - rotatable segments of the coiled tubing string for one or more of the plurality of sections of the wellbore to be drilled along the planned trajectory , based on the estimated effective distributive friction factor for the portion of the non -rotatable segment. [ 0082] For any of the foregoing embodiments, the system or computer - readable storage medium may include any of the following elements , either alone or in combination with each other: the effective -distributive friction factor repre sents a distribution of frictional drag forces over a selected length of the non -rotatable segment of the coiled tubing string along one or more of the plurality of sections of the wellbore ; the predetermined maximum force threshold is a predetermined maximum hook load ; the effective distribu tive friction factor is estimated for portions of the non rotatable segment corresponding to lateral and curved sec Oct. 25, 2018 tions of the wellbore along the planned trajectory ; the effective distributive friction factor is estimated for a portion of the non -rotatable segment corresponding to a lateral section of the wellbore along the planned trajectory ; the rotatable segment of the coiled tubing string includes a downhole motor and a bottom hole assembly, and the downhole motor is located upstream from the bottom hole assembly on the rotatable segment of the coiled tubing string; the non - rotatable segment of the coiled tubing string extends from a surface of the wellbore and attaches to a proximal end of the downhole motor ; and the downhole motor is a hydraulic motor. [0083 ] While specific details about the above embodi ware descriptions are intended merely as example embodi ments and are not intended to limit the structure or implementation of the disclosed embodiments. For instance , ments have been described, the above hardware and soft although many other internal components of the system 600 are not shown , those of ordinary skill in the art will appreciate that such components and their interconnection are well known . [0084 ] In addition , certain aspects of the disclosed embodiments , as outlined above , may be embodied in soft ware that is executed using one or more processing units/ components. Program aspects of the technology may be thought of as “ products ” or “ articles of manufacture " typi cally in the form of executable code and /or associated data that is carried on or embodied in a type ofmachine readable medium . Tangible non -transitory " storage” type media include any or all of the memory or other storage for the computers, processors or the like , or associated modules thereof , such as various semiconductor memories, tape drives, disk drives , optical or magnetic disks , and the like, which may provide storage at any time for the software programming. [0085 ] Additionally , the flowchart and block diagrams in the figures illustrate the architecture, functionality , and operation of possible implementations of systems, methods and computer program products according to various embodiments of the present disclosure. It should also be noted that, in some alternative implementations, the func tions noted in the block may occur out of the order noted in the figures . For example , two blocks shown in succession may, in fact, be executed substantially concurrently , or the blocks may sometimes be executed in the reverse order, depending upon the functionality involved . It will also be noted that each block of the block diagrams and / or flowchart illustration , and combinations of blocks in the block dia grams and/ or flowchart illustration , can be implemented by special purpose hardware -based systems that perform the specified functions or acts, or combinations of special pur pose hardware and computer instructions. [0086 ] The above specific example embodiments are not intended to limit the scope of the claims. The example embodiments may be modified by including , excluding , or combining one ormore features or functions described in the disclosure . [0087] As used herein , the singular forms “ a” , “ an ” and “ the ” are intended to include the plural forms as well , unless the context clearly indicates otherwise . It will be further understood that the terms " comprise " and/ or " comprising," when used in this specification and/or the claims, specify the presence of stated features , integers , steps, operations, ele ments , and /or components, but do not preclude the presence US 2018 /- A1 or addition of one or more other features, integers , steps, operations, elements , components, and/or groups thereof. Oct. 25, 2018 5 . The method of claim 1 , wherein the effective distribu tive friction factor is estimated for a portion of the non The corresponding structures , materials , acts, and equiva lents of all means or step plus function elements in the wellbore along the planned trajectory . claimsbelow are intended to include any structure, material, or act for performing the function in combination with other of the coiled tubing string includes a downhole motor and a claimed elements as specifically claimed . The description of the present disclosure has been presented for purposes of illustration and description , but is not intended to be exhaus tive or limited to the embodiments in the form disclosed . Many modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the disclosure . The illustrative embodiments described herein are provided to explain the principles of the disclosure and the practical application thereof, and to enable others of ordinary skill in the art to understand that the disclosed embodiments may be modified as desired for a particular implementation or use. The scope of the claims is intended to broadly cover the disclosed embodiments and any such modification . What is claimed is : 1. A method for optimizing coiled tubing string configu rations for drilling operations, the method comprising : determining a plurality of sections for a wellbore to be drilled along a planned trajectory through a subsurface formation ; determining physical properties of a coiled tubing string for drilling the wellbore along the planned trajectory, the coiled tubing string having a non -rotatable segment and a rotatable segment; estimating a length of the rotatable segment of the coiled tubing string, based on the physical properties corre sponding to the rotatable segment; calculating a friction factor for the rotatable segment rotatable segment corresponding to a lateral section of the 6 . The method of claim 1 , wherein the rotatable segment bottom hole assembly , and the downhole motor is located upstream from the bottom hole assembly on the rotatable segment of the coiled tubing string . 7 . The method of claim 6 , wherein the non -rotatable segment of the coiled tubing string extends from a surface of the wellbore and attaches to a proximal end of the downhole motor. 8 . The method of claim 6 , wherein the downhole motor is a hydraulic motor. 9. A system for optimizing coiled tubing string configu at least one processor ; and a memory coupled to the processor having instructions stored therein , which when executed by the processor, rations for drilling operations, the system comprising: cause the processor to perform functions including functions to : determine a plurality of sections for a wellbore to be drilled along a planned trajectory through a subsurface formation; determine physical properties of a coiled tubing string for drilling the wellbore along the planned trajectory , the coiled tubing string having a non - rotatable segment and a rotatable segment; estimate a length of the rotatable segment of the coiled tubing string, based on the physical properties corre sponding to the rotatable segment; calculate a friction factor for the rotatable segment based on the estimated length of the rotatable segment; based on the estimated length of the rotatable segment; estimating an effective axial force for one or more points of interest along the non -rotatable and rotatable seg ments of the coiled tubing string, based in part on the friction factor calculated for the rotatable segment, estimate an effective axial force for one ormore points of interest along the non - rotatable and rotatable segments one of the one or more points of interest exceeds a a predetermined maximum force threshold ; estimate an effective distributive friction factor for at least a portion of the non - rotatable segment of the coiled upon determining that the effective axial force for at least predetermined maximum force threshold , estimating an effective distributive friction factor for at least a portion of the non -rotatable segment of the coiled tubing string; and redefining the rotatable and non -rotatable segments of the coiled tubing string for one or more of the plurality of sections of the wellbore to be drilled along the planned trajectory , based on the estimated effective distributive friction factor for the portion of the non -rotatable segment. 2 . The method of claim 1, wherein the effective-distribu tive friction factor represents a distribution of frictional drag forces over a selected length of the non - rotatable segment of the coiled tubing string along one or more of the plurality of sections of the wellbore . 3 . The method of claim 1, wherein the predetermined maximum force threshold is a predetermined maximum hook load . 4. The method of claim 1, wherein the effective distribu of the coiled tubing string, based in part on the friction factor calculated for the rotatable segment; determine whether or not the effective axial force for at least one of the one or more points of interest exceeds tubing string, when the effective force for at least one of the one or more points of interest is determined to exceed the predetermined maximum force threshold ; and redefine the rotatable and non - rotatable segments of the coiled tubing string for one or more of the plurality of sections of the wellbore to be drilled along the planned trajectory, based on the estimated effective distributive segment. 10 . The system of claim 9 , wherein the effective-distribu tive friction factor represents a distribution of frictional drag forces over a selected length of the non -rotatable segment of the coiled tubing string along one or more of the plurality of sections of the wellbore . 11 . The system of claim 9 , wherein the predetermined friction factor for the portion of the non - rotatable maximum force threshold is a predetermined maximum tive friction factor is estimated for portions of the non hook load . tions of the wellbore along the planned trajectory . tive friction factor is estimated for portions of the non rotatable segment corresponding to lateral and curved sec 12 . The system of claim 9 , wherein the effective distribu US 2018 /- A1 Oct. 25, 2018 rotatable segment corresponding to lateral and curved sec tions of the wellbore along the planned trajectory . estimate an effective axial force for one or more points of 13 . The system of claim 9 , wherein the effective distribu of the coiled tubing string , based in part on the friction interest along the non - rotatable and rotatable segments tive friction factor is estimated for a portion of the non rotatable segment corresponding to a lateral section of the tive-distributive friction factor representing a distribu of the coiled tubing string includes a downhole motor and a along one or more of the plurality of sections of the wellbore along the planned trajectory . 14 . The system of claim 9 , wherein the rotatable segment bottom hole assembly, and the downhole motor is located upstream from the bottom hole assembly on the rotatable segment of the coiled tubing string . 15 . The system of claim 14 , wherein the non -rotatable segment of the coiled tubing string extends from a surface of the wellbore and attaches to a proximal end of the downhole motor. 16 . The system of claim 14 , wherein the downhole motor is a hydraulic motor . 17 . A computer - readable storage medium having instruc tions stored therein , which when executed by a computer cause the computer to perform a plurality of functions, including functions to : determine a plurality of sections for a wellbore to be drilled along a planned trajectory through a subsurface formation ; determine physical properties of a coiled tubing string for drilling the wellbore along the planned trajectory , the coiled tubing string having a non -rotatable segment and a rotatable segment, the rotatable segment including a bottom hole assembly and a downhole motor located upstream from the bottom hole assembly, and the wellbore and attaching to a proximal end of the down non - rotatable segment extending from a surface of the hole motor ; estimate a length of the rotatable segment of the coiled tubing string, based on the physical properties corre sponding to the rotatable segment; calculate a friction factor for the rotatable segment based on the estimated length of the rotatable segment; factor calculated for the rotatable segment, the effec tion of frictional drag forces over a selected length of the non -rotatable segment of the coiled tubing string wellbore ; determine whether or not the effective axial force for at least one of the one ormore points of interest exceeds a predetermined maximum force threshold ; estimate an effective distributive friction factor for at least a portion of the non -rotatable segment of the coiled tubing string, when the effective force for at least one of the one or more points of interest is determined to exceed the predetermined maximum force threshold ; and redefine the rotatable and non - rotatable segments of the coiled tubing string for one or more of the plurality of sections of the wellbore to be drilled along the planned trajectory, based on the estimated effective distributive friction factor for the portion of the non -rotatable segment. 18 . The computer - readable storage medium of claim 17 , wherein the predetermined maximum force threshold is a predetermined maximum hook load . 19 . The computer-readable storage medium of claim 17 , wherein the effective distributive friction factor is estimated for portions of the non - rotatable segment corresponding to lateral and curved sections of the wellbore along the planned trajectory. 20 . The computer- readable storage medium of claim 17, wherein the effective distributive friction factor is estimated for a portion of the non - rotatable segment corresponding to a lateral section of the wellbore along the planned trajectory. SPE-180384-MS Uphole Motor Technology Oluwafemi Oyedokun, Texas A&M University, Robello Samuel, Landmark Graphics, Jerome Schubert, Texas A&M University Slide 2 Presentation Outline 1. Background/Motivation 2. String Configuration 3. Rotating String Design a. Buckling Consideration b. Pump Constraint c. Whirling Check d. Other Constraints 4. Example Calculations 5. Further Works 6. Conclusions SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 3 Background/Motivation • Significant extended-reach achievable • Improved cuttings transport • Inexpensive o Reduced standpipe pressure o No or little rig modification • Viable? Highly probable SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 4 String Configuration Non-rotating Section Bottomhole Assembly Uphole Assembly • Coiled tubing in the non-rotating section • Coiled tubing or drillpipe in the rotating section • Use of high torque uphole-motor • Adjustable stabilizers in the uphole assembly Rotating Section SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 5 Rotating String Design Design Variables/Parameters Design Constraints • Constrained circulation rate Limited pump pressure • Required uphole-motor configuration • Assumed parasitic flow coefficients • Minimum rotary torque • No whirling • Injector Head Pulling Capacity • Safe rotary speed • Tubing Yield Strength • Rotating pipe dimensions • No lateral buckling of the rotating pipe • SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 6 Rotating String Design: Design Procedure 1. Determine the unit weight and diameter of the rotating pipe • 2. Critical sinusoidal buckling load must be greater than maximum weight on bit B C Locate where uphole-motor “experiences” maximum rotary torque A Rock n-1 • Where maximum weight-on-bit is applied Rock n Rock n-3 • Kick-off point 𝑊1 Rock n-2 𝑊0 𝑊0 SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 7 Rotating String Design: Design Procedure  3. 4. 5. Specify the flow coefficients 𝑠, and 𝐾𝐿 M t  r p Express the rotating length and pump pressure as functions of winding ratio and flow rate, and read-off 𝑛 and 𝑞𝑚 that satisfy the available pump pressure Estimate other parameters: a. b. c. Rotating length Minimum rotary torque Pressure drop across the motor l R q m , n   2   1 wc Rd  M bit   sin  N  wbp, j l j r p, j j 1 wbp r p sin   q Ppm (q m , n)  K L l R  nl R  m   s  R 2  1      2 pm  1pmB  pb  SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 8 Example Calculation -1: Large Hole Drilling with CT Parameter Value Parameter Friction Factor Mud Weight Density of Steel Max.Weight on Bit 0.3 10 ppga 65.5ppga 8000lbf Constant Flow Ratio, Flow Ratio, PDM Power Output Turbulence Index, s Constant Bit Rotary Speed 1.75 Flow Coefficient, Value 4e − 5 1 1 40hp 6,000 ft. 0.1 1591 ft. 0.01 200rpm Constant Uphole-Motor Rotor Speed 5252 20rpm/40rpm 6.5 inch hole. Available pump pressure is 7000 psi ?? SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 9 Example Calculation-1 Tricone Bit: 6.5 in OD Bleed Sub: 3.875in. Cross-over Sub: 3.875in. Orienting Sub: 4.75 in. Hydraulic Disconnect: Cross-over sub: 3.875 in. 3.875 in. Check Valve: 4 in. Downhole Motor: Positive Displacement, 4.75 in OD MWD: SAE 4145, 4.75 in. OD Circulation Sub: 3 in. Drillpipe: 2.875 in. CS API 55D Bottomhole Assembly SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 10 Example Calculation-1 Cross-over sub: 5.5 in. OD Under-gauged stabilizer: 4.75 in. OD, 3.5 in. Box and Pin Drillpipe: 2.875 in. CS API 55D Cross-over sub: 4.5 in. OD Coiled Tubing: 3.5 in. OD Uphole Hydraulic Motor: 4.75 in. x 2.81 in. Sperry Dual-Full-Gauged Adjustable Stabilizer with blades covered with elastomeric pads: 6 in. OD, 6.5 in. maximum extension Coiled-Tubing Connector: 4.5 in. x 3.5 in. Uphole Assembly SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 11 Example Calculation-1 7000 psi Pump Pressure Variation with Winding Ratio and Flow Rate, 𝑵𝒎 = 20 RPM or 40 RPM SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 12 Example Calculation-1 Required rotating length for 20 RPM rotary speed is 6,520 ft. Required rotating length for 40 RPM rotary speed is ∼6,420 ft. SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 13 Example Calculation-1 Minimum rotary torque for 20 RPM rotary speed is 1278 lbf-ft. Minimum rotary torque for 40 RPM rotary speed is 1262 lbf-ft. SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 14 Example Calculation-1 Pressure drop across uphole-motor for 20 RPM rotary speed is 29.5psi. Pressure drop across uphole-motor for 40 RPM rotary speed is 59 psi. SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 15 Example Calculation-1 Rotating the string at 20 RPM will cause no whirling; critical speed is at 31.8 RPM With a rotor speed of 40 RPM, the speed should be stepped down below the critical speed of 30 RPM SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 16 Example Calculation-1 Conventional CTD Use of Uphole Motor 22,716 lbf. 22,716 lbf. 23,674 lbf. 23,674 lbf. 17438 lbf./16654 lbf 13162 lbf 20RPM. 190 ft. 90 ft. 6,520 ft. 104 ft. 6,420 ft. 2,837 ft. 40RPM. SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 17 Example Calculation-1:Injector-Head Pulling Capacity Injector Head Ratings: 100,000lbf Pull Capacity; 40,000lbf Snub Capacity Speed 200 ft./min 3.5” OD, 3.094” ID, CT 2.875” OD, 2.151 ID, 10.14lb/ft. DP String Component Unit Weight (lb./ft.) Component Length (ft.) Component Weight (lbf.) Bottomhole Assembly - 78.31 2,680.30 Rotating DP 10.14 6520.00 66,112.80 Uphole Assembly - 62.73 4,473.18 3.5” OD CT 7.199 7681.00 55,295.52 14,342.04 128,561.5 Total Failed! Re-select the CT and DP, choose lighter tubulars SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 18 Example Calculation-1: Re-design Tubular Unit Weight (lb./ft.) Outer Diameter (in.) Inner Diameter (in.) Critical Helical Buckling Load (lbf.) Critical Sinusoidal Buckling Load (lbf.) CT 4.541 2.875 2.563 6,884.18 4,696.99 DP 6.16 2.875 2.441 9,142.85 6,464.97 Allowing for sinusoidal buckling of the drillpipe (WOB is 8,000 lbf.) Required pump pressure is 4,800 psi SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 19 Example Calculation-1: Snaking Motion of DP Static Post-Buckling Configuration of the Drillpipe Dynamic Displacements Dynamic Lateral Displacements of DP Phase Diagram SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 20 Example Calculation-1 Reduced circulating rate, 300 gal/min, rotating length is 6,940 ft. Required rotary torque is 1436 lb.-ft. SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 21 Example Calculation-1 Uphole Motor Pressure Drop is 45 psi Critical Rotary Speed is 26 RPM SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 22 Example Calculation-1: Injector-Head Pulling Capacity Injector Head Ratings: 100,000lbf Pull Capacity; 40,000lbf Snub Capacity Speed 200 ft./min 2.875” OD, 2.563” ID, CT String Component Unit Weight (lb./ft.) Component Length (ft.) Component Weight (lbf.) Bottomhole Assembly - 78.31 2,680.30 Rotating DP 6.16 6940.00 42,750.40 Uphole Assembly - 62.73 4,473.18 2.875” OD CT 4.541 7591.00 34,470.73 14,672.04 84,374.21 Total 2.875” OD, 2.441 ID, 6.16lb/ft. DP Passed! SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 23 Example Calculation-1: Check on Tubing Yield Strength  VME  83,995.4 psi Passed! SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 24 Example Calculation-2: Small Hole Drilling with CT Parameter Value Parameter Friction Factor Mud Weight Density of Steel Max.Weight on Bit 0.3 10 ppga 65.5ppga 8000lbf Constant Flow Ratio, Flow Ratio, PDM Power Output Turbulence Index, s Constant Bit Rotary Speed 1.75 Value 4e − 5 1 1 40hp 6,000 ft. 0.15 Flow Coefficient, 1591 ft. 0.01 200rpm Constant Uphole-Motor Rotor Speed 5252 20rpm/40rpm 4.1 inch hole. Available pump pressure is 7000 psi Use two uphole motors in reverse operations. ?? SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 25 Example Calculation-2 Tricone Bit: 4.1 in OD Bleed Sub: 2.875in. Cross-over Sub: 2.875in. Orienting Sub: 2.75 in. Hydraulic Disconnect: Cross-over sub: 2.875 in. 2.875 in. Check Valve: 2 in. Downhole Motor: Positive Displacement, 2.75 in OD MWD: SAE 4145, 2.75 in. OD Circulation Sub: 3 in. Drillpipe: 2.875 in. CS API 55D Bottomhole Assembly SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 26 Example Calculation-2 Under-gauged stabilizer: 2.75 in. OD, 3.5 in. Box and Pin Drillpipe: 2.875 in. CS API 55D Cross-over sub: 2.5 in. OD Thrust/Ball Bearing Housing 2- Uphole Hydraulic Motors: 2.75 in. x 1.81 in. Sperry Cross-over sub: 2.5 in. OD Coiled Tubing: 2.875 in. OD Coiled-Tubing Connector: 3.5 in. x 2.875 in. Uphole Assembly SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 27 Example Calculation-2 Tubular Unit Weight (lb./ft.) Outer Diameter (in.) Inner Diameter (in.) Critical Helical Buckling Load (lbf.) Critical Sinusoidal Buckling Load (lbf.) CT 4.541 2.875 2.563 11,426.70 8,079.90 DP 6.16 2.875 2.441 15,198.40 10,746.90 No sinusoidal buckling of the drillpipe (WOB is 8,000 lbf.) Required pump pressure is 5,200 psi SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 28 Example Calculation-2 Circulating rate, 300 gal/min, rotating length is 6,960 ft. Required rotary torque is 1436 lb.-ft. SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 29 Example Calculation-1 Uphole Motor Pressure Drop is 45 psi Critical Rotary Speed is 39 RPM SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 30 Example Calculation-1: Injector-Head Pulling Capacity Injector Head Ratings: 100,000lbf Pull Capacity; 40,000lbf Snub Capacity Speed 200 ft./min 2.875” OD, 2.563” ID, CT 2.875” OD, 2.441 ID, 6.16lb/ft. DP String Component Unit Weight (lb./ft.) Component Max. Length (ft.) Component Max. Weight (lbf.) Comp. Req. Length (ft.) Component Req. Weight (lbf.) Bottomhole Assembly - 78.31 2,480.30 78.31 2,480.30 Rotating DP 6.16 6,960.00 42,873.60 6,960.00 42,873.60 Uphole Assembly - 62.73 4,273.18 62.73 4,273.18 2.875” OD CT 4.541 11,537.24 52,390.61 11,000.00 49,951.00 18,638.27 102,017.39 18,101.04 99,578.08 Total Passed! But with higher safety margin, the CT length can be reduced SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 31 Example Calculation-2: Check on Tubing Yield Strength  VME  96,868.7 psi Passed! SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 32 Further Works 1. Compatibility with articulated tractor and other mechanically operated extended-reach techniques 2. Collaboration with industry partner(s) for field testing SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 33 Conclusions 1. Relatively inexpensive technology 2. Significant lateral extent achievable 3. Applicable to small hole CT drilling; use caution with large-hole drilling 4. Increase fatigue life of CT 5. Combine with other extended-reach techniques 6. Although no experiment has been done, its viability is highly probable SPE-180384-MS • Uphole Motor Technology • Femi Oyedokun Slide 34 Thank You