Well drilling systems and methods for enhanced drill bit operational lifetime

Abstract

Drilling systems and methods are provided for drilling a wellbore, which employ a drill string operably coupled to a bottom hole assembly including a drill bit for drilling the wellbore. The drill string is configured to circulate drilling fluid into and through the wellbore during the drilling. The drill string can include insulated drill pipe or vacuum insulated drill pipe for all or part of the drill string. In another aspect, the drill string can include drill pipe with a wall thickness greater than 0.5 inch and / or an inner diameter surface of less than 4 inches in diameter. In embodiments, the formation can have a formation temperature less than approximately 175°C, and the wellbore can be configured to intersect a target hydro-carbon bearing reservoir disposed within the formation.

Description

WELL DRILLING SYSTEMS AND METHODS FOR ENHANCED DRILL BITOPERATIONAL LIFETIMECROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The subject disclosure claims priority from U.S. Application No.: 63 / 608,400, filed on December 11, 2023, herein incorporated by reference in its entirety.FIELD

[0002] The present disclosure relates generally to methods and systems for well drilling.BACKGROUND

[0003] During a typical well drilling operation, drilling fluid, which is commonly referred to as drilling mud, is circulated into and out of a wellbore. The drilling fluid can serve many useful purposes during the drilling operation, such as, for example, removing drill cuttings from the wellbore, controlling formation pressures and wellbore stability during drilling, sealing permeable formations, transmitting hydraulic energy to the drilling tools and bit, and cooling, lubricating, and supporting the drill bit and other parts of the bottom hole assembly during the drilling operations.

[0004] In conventional drilling applications, a wellbore can be drilled to intersect a target hydrocarbon-bearing reservoir with a formation temperature less than approximately 175°C. In these applications, the temperature of the drill bit or drilling tool can be significantly higher than the temperature of the drilling fluid. Such elevated temperatures can have significant detrimental effects on the cutter elements of the drill bit and other bottom hole components.More specifically, the temperature of cutter elements of the drill bit during the drilling can impact the operational lifetime (longevity) of the cutter elements. Many options have been pursued to improve the temperature tolerance of the cutter elements of the drill bit, such as leaching of cobalt from polycrystalline diamond compact cutters. Developments to increase the thermal conductivity of the cutter, such as thicker diamond bed or a longer high conductivity carbide substrate, have been shown to reduce the steady state temperature of the cutter elements by 30°C during dry drilling operations (dry cut test) and resulted in a significant improvement in durability and operation lifetime of the cutter elements.SUMMARY

[0005] In embodiments, drilling systems and methods are provided for drilling a wellbore, which employ a drill string operably coupled to a bottom hole assembly including a drill bit for drilling the wellbore. The drill string is configured to circulate drilling fluid into and through the wellbore during the drilling.

[0006] In embodiments, the formation can have a formation temperature less than approximately 175°C, and the wellbore can be configured to intersect a target hydro-carbon bearing reservoir disposed within the formation.

[0007] In embodiments, the drill string can include insulated drill pipe or vacuum insulated drill pipe for all or part of the drill string,

[0008] In embodiments, the drill string can include a top part different from a bottom part, wherein the top part includes insulated drill pipe or vacuum insulated drill pipe. The bottom part can include conventional steel drill pipe.

[0009] In embodiments, the drill string can include drill pipe with a wall thickness greater than 0.5 inch and / or an inner diameter surface of less than 4 inches in diameter.

[0010] In embodiments, the wall thickness can be in a range of 0.7 inch to 1 inch.

[0011] In embodiments, the wall thickness can add insulation material to improve thermal insulation of the interior of the drill pipe relative to the exterior environment of the drill Pipe

[0012] In embodiments, the inner diameter surface can be in the range of 3.5 inch to 3 inch in diameter.

[0013] In embodiments, the inner diameter surface can increase flow rate through the drill pipe and reduces time that drilling fluid, passing through the drill pipe, is exposed to heat.

[0014] In embodiments, the configuration of the drill pipe reduces drilling fluid temperature that flows through the bottom hole assembly and drill bit and results in improvement on the durability of cutter elements and the drill bit.

[0015] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.BRIEF DESCRIPTION OF THE DRAWINGS

[0016] The subject disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of the subject disclosure, in which like reference numerals represent similar parts throughout the several views of the drawings as described below.

[0017] FIG. 1 depicts the results of steady state finite element analysis (FEA) modelling of a PDC cutter during drilling operations. The maximum PCD temperature at the cutting tips is plotted against the temperature of the drilling fluid / ambient temperature;

[0018] FIG. 2 is a schematic diagram of a drilling system that can embody aspects of the present disclosure;

[0019] FIGS. 3 to 5 depicts results of a model that was built to calculate the temperature profile in a drilled wellbore by a drilling system as described herein; FIG. 3 shows the temperature profile along the flow path of the drilled wellbore as predicted by the model for the case of conventional steel drill pipe; FIG. 4 shows the temperature profile along the flow path of the drilled wellbore as predicted by the model for the case of insulated drill pipe; FIG. 5 shows the temperature profile along the flow path of the drilled wellbore as predicted by the model for the case of a vacuum insulated drill pipe;

[0020] FIGS. 6 and 7 depicts results of a model that was built to calculate the temperature profile in a drilled wellbore by a drilling system that employs insulated drill pipe for an upper part of the drill string and conventional steel drill pipe for the remaining lower part of the drill string as well as the baseline case that employs conventional steel drill pipe for the entire drill string. FIG. 6 shows the temperature profile along the flow path of the drilled wellbore as predicted by the model for the case of insulated drill pipe in varying lengths (15,000 ft and 22,500 ft) in the top part of the drill string and conventional steel drill pipe for the remaining lower part of the drill string as well as the baseline case that employs conventional steel drill pipe for the entire drill string. FIG. 7 shows the temperature profile along the flow path of the drilled wellbore as predicted by the model for the case of insulated drill pipe of 7,500 in length in the top part of the drill string and conventional steel drill pipe for the remaining lower part of thedrill string. The results are shown for drilling operations at the start of a lateral section and the end of the lateral section; and

[0021] FIGS. 8A and 8B are schematic diagrams of drill pipe that can embody aspects of the present disclosure. FIG 8A is a schematic front view of the drill pipe. FIG. 8B is a schematic cross-sectional view of the pipe body of the drill pipe of FIG. 8 A.DETAILED DESCRIPTION

[0022] The particulars shown herein are by way of example and for purposes of illustrative discussion of the embodiments of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure. In this regard, no attempt is made to show structural details in more detail than is necessary for the fundamental understanding of the subject disclosure, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice.Furthermore, like reference numbers and designations in the various drawings indicate like elements.

[0023] It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the disclosure may repeat reference numerals and / or letters in the various examples. This repetition is for the purpose of simplicity and clarity and will not in itself dictate a relationship between the various embodiments and / or configurations discussed.

[0024] As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements. Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements. Terms such as up, down, top and bottom and other like terms indicating relative positions to a given point or element may be utilized to more clearly describe some elements. Commonly, these terms relate to a reference point such as the surface from which drilling operations are initiated.

[0025] During well drilling operations, the heat generated at the cutting surface of the cutter elements of the drill bit is conducted through the cutter elements into the body of the drill bit and the BHA. At all points such heat is transferred to the drilling fluid as it flows through the BHA and drill bit. Ultimately (almost) all of the heat entering the cutter elements of the drill bit is transferred to the drilling fluid. In reality, for a fixed geometry in steady drilling, the temperature of the cutter tips is (only) a function of the heat entering the cutter elements, cutter / bit geometry, cutter / bit material properties, and the temperature and flow rate of the drilling fluid flowing from the lower BHA.

[0026] FIG. 1 depicts the results of finite element analysis (FEA) modelling of a PCD cutter during drilling operations. The maximum PCD temperature at the cutting tips is plotted against the temperature of the drilling fluid / ambient temperature. The results show that cooling the drilling fluid results in a 1 : 1 decrease in steady state temperature at the cutting tip.

[0027] Aspects of the present disclosure described herein can reduce the temperature of the drilling fluid that flows through the BHA and drill bit in order to reduce the temperature of the cutter elements. This reduction in temperature of the cutter elements, such as a 30°C drop intemperature, can result in significant improvement on the durability of the cutter elements and the drill bit as a whole.

[0028] FIG. 2 is a schematic illustration of a drilling system, generally denoted by the numeral 100. It should be noted that while FIG. 2 generally depicts a land-based drilling system, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea drilling operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.

[0029] By way of example, FIG. 2 shows a drilling system 100 for drilling into the earth to form a wellbore 114 in an earth formation 112. The temperature of the formation 112 is less than approximately 175°C. In embodiments, the trajectory of the wellbore 114 can be configured to intersect a target hydrocarbon-bearing reservoir disposed within the formation 112. The drilling system 100 includes a drill rig 116 located at the surface 117 and operated to turn a drilling tool assembly which extends downward from the surface 117 into the wellbore 114. The drilling tool assembly includes a drill string 118 operably coupled to a bottomhole assembly (BHA) 120. The BHA 120 includes a drill bit 122.

[0030] The drill string 118 can include several sections of drill pipe connected end-to-end through tool joints as is well known. The drill string 118 can transmit rotational power from the drill rig 116 to the BHA 120 and the drill bit 122. In some embodiments, the drill string 118 may further include additional components such as subs, pup joints, etc. The drill pipe can provide a fluid passageway through which drilling fluid is pumped from the surface 117. The drilling fluid can be discharged through nozzles, jets, or other orifices at or near the drill bit 122 for the purposes of cooling the drill bit 122 and the cutting elements thereon, for lifting cuttings out ofthe wellbore 114 as it is being drilled, for controlling influx of fluids in the wellbore 114, for maintaining the integrity of the wellbore 114, and for other purposes.

[0031] An example BHA 120 may include additional or other components (e.g., coupled between / to the drill string 118 and the bit 122). Examples of additional BHA components include a drill collar, stabilizers, measurement-while-drilling (MWD) tools, logging-whiledrilling (LWD) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or damping tools, other components, or combinations of the foregoing. The BHA 120 may further include a directional tool such as a bent housing motor or a rotary steerable system (RSS). The directional tool may include directional drilling tools that change the direction of the drill bit 122, and thereby the trajectory of the wellbore 114 being drilled. In some cases, at least a portion of the directional tool may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, or true north. Using measurements obtained with the geostationary position, the directional tool may locate the drill bit 122, change the course of the drill bit 122 and direct the drill bit 122 on a controlled trajectory. For instance, although the BHA 120 is shown as drilling a vertical portion of the wellbore 114, the BHA 120 (including the directional tool) may instead drill directional or deviated well portions as is well known.

[0032] In some embodiments, the BHA 120 may include a downhole motor to power downhole systems and / or provide rotational energy for downhole components (e.g., rotate the drill bit 122, drive the directional tool, etc.). The downhole motor may be any type of downhole motor, including a positive displacement pump (such as a progressive cavity motor) or a turbine. In some embodiments, a downhole motor may be powered by the drilling fluid flowing through the drill string 118. In other words, the drilling fluid pumped downhole from the surface 117 mayprovide the energy to rotate the downhole motor. The downhole motor may operate with an optimal pressure differential or pressure differential range. The optimal pressure differential may be the pressure differential at which the downhole motor may not stall, burn out, overspin, or otherwise be damaged. In some cases, the downhole motor may rotate the drill bit 122 such that the drill string 118 may not be rotated at the surface 117, or may rotate at a different rate (e.g., slower) than the rotation of the drill bit 122.

[0033] The drill bit 122 may be any type of bit suitable for degrading downhole materials such as earth formation 112. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits, roller cone bits, and combinations thereof.

[0034] In the embodiment of FIG. 2, the drill rig 116 supports traveling block 124, which suspends a swivel 126 that is connected to a kelly drive. The kelly drive cooperates with a rotary table to rotate the drill string 118 and to lower the drill string 118 through the wellhead 128. In other embodiments, a top drive can be used in place of the swivel 126, the kelly drive and the rotating function of the rotary table. Drilling fluid is pumped by pump 130 through flow line 132, gooseneck 134, the swivel 126 and kelly (or top drive), and down through the drill string 118 at high pressures and volumes to emerge through nozzles or jets or orifices at or near the drill bit 122. The drilling fluid then travels back up the wellbore 114 via the annulus formed between the exterior of the drill string 118 and the wellbore wall, through a blowout preventer 136, and into a tank 138 and / or pit 140 on the surface 117. At the surface 117, the drilling fluid is cleaned and then circulated again by the pump 130. The drilling fluid can be used to cool the drill bit 122, to carry cuttings from the base of the wellbore 114 to the surface 117, and to balance the hydrostatic pressure with respect to the formation 112.

[0035] The drilling system 100 can also include additional or other drilling components and accessories, such as special valves (e.g., kelly cocks and safety valves).

[0036] The drilling system can also include an active cooling system (typically referred to as a mud cooler) at the surface to reduce the temperature of the drilling fluid that is returned to the surface when drilling the wellbore 114.

[0037] In accordance with the present disclosure, a drilling system can be configured and used to drill a wellbore in a subterranean formation with a formation temperature less than approximately 175°C. In embodiments, the trajectory of the wellbore can be configured to intersect a target hydrocarbon-bearing reservoir disposed within the formation. The drilling system can embody a drill string that employs insulated drill pipe or vacuum insulated drill pipe for all or part of the drill string. This configuration can reduce drilling fluid temperature that flows through the BHA and drill bit, which can result in significant improvement on the durability of the cutter elements and the drill bit of the drilling system. For example, the drill string 118 of the drilling system 100 of FIG. 2 can employ insulated drill pipe or vacuum insulated drill pipe for all or part of the drill string 118.

[0038] As used herein, insulated drill pipe refers to a type of drill pipe designed with one or more layers of thermal insulating material disposed on the inside diameter surface and / or the outside diameter surface of the drill pipe. The thermal insulating material reduces heat transfer between fluid flowing through the pipe and the surrounding environment.

[0039] As used herein, vacuum insulated drill pipe refers to a type of drill pipe designed with a vacuum space between two concentric walls. The vacuum space reduces heat transfer between fluid flowing through the pipe and the surrounding environment.

[0040] In order to evaluate the reduction in drilling fluid temperature that flows through the BHA and drill bit as provided by the systems described herein, a model was built to simulate the temperature of drilling fluid in the drilled wellbore as detailed in Table 1. The model assumes turbulent flow in the drill pipe and the annulus of the drilled wellbore. The model also assumes radial heat conduction through the formation and steady state with a far field temperature 5 meters from the drilled wellbore.Table 1: Parameters used for simulation

[0041] The model was first configured to simulate three different scenarios for the drill pipe of the drill string as outlined in Table 2, including: conventional drill pipe, insulated drill pipe, and vacuum insulated drill pipe. The conditions are shown in Table 2 with an estimate of the drilling fluid temperature at the drill bit. The modelled temperature distributions are shown in FIGS. 3 to 5.Table 2: Drill pipe specification with modelled fluid temperatures

[0042] FIG. 3 shows the temperature profile along the flow path of the drilled wellbore as predicted by the model for the case of conventional steel drill pipe.

[0043] FIG. 4 shows the temperature profile along the flow path of the drilled wellbore as predicted by the model for the case of insulated drill pipe.

[0044] FIG. 5 shows the temperature profile along the flow path of the drilled wellbore as predicted by the model for the case of vacuum insulated drill pipe.

[0045] It is evident that by changing the drill pipe one can obtain a significant reduction in the bottom hole temperature of the drilling fluid. More specifically, with regard to the case that employs insulated drill pipe for the drill string, the bottom hole temperature of the drilling fluid is reduced by more than 80°C as compared to the case that employs conventional drill bit. This would result in considerable improvements to the durability and operational lifetime of the drill bit. The case that employs vacuum insulated drill pipe for the drill string provides an even larger reduction in the bottom hole temperature of the drilling fluid, and thus even further improvement to the durability and operational lifetime of the drill bit.

[0046] It is noteworthy that the fluid from the insulated drill pipe is returning to surface at a higher temperature. This is especially significant for the vacuum insulated pipe. If this was recirculated at this temperature the benefit in the well would be lost after a few circulations as the drilling fluid would be outside of its operating window. We therefore consider the need for active cooling at surface with a powered mud cooler or through having a sufficiently large volume of drilling fluid at surface so it can cool before being re-circulated.

[0047] The model was also configured to simulate two additional scenarios for the drill pipe of the drill string, which involves using insulated drill pipe for upper part of the drill string and conventional steel drill pipe for the remaining lower part of the drill string that coupled to the BHA as well as the baseline case that employs conventional steel drill pipe for the entire drill string as outlined in Table 3. The conditions are shown in Table 3 with an estimate of the drilling fluid temperature at the drill bit. The modelled temperature distributions are shown in FIGS. 6 and 7. These configurations reduce cost and simplify some of the dynamics which can be triggered with double walled insulated drill pipe.Table 3: Simulation results for various lengths of insulated drill pipe deployed from the top of the well

[0048] FIG. 6 shows the temperature profile along the flow path of the drilled wellbore as predicted by the model for the case of insulated drill pipe in varying lengths (15,000 ft and 22,500 ft) in the top part of the drill string and conventional steel drill pipe for the remaining lower part of the drill string as well as the baseline case that employs conventional steel drill pipe for the entire drill string.

[0049] FIG. 7 shows the temperature profile along the flow path of the drilled wellbore as predicted by the model for the case of insulated drill pipe of 7,500 in length in the top part of the drill string and conventional steel drill pipe for the remaining lower part of the drill string.The results are shown for drilling operations at the start of a lateral section and the end of the lateral section.

[0050] The results of FIGS. 6 and 7 show that the level of drilling fluid temperature reduction can be managed using a shorter length of insulated drill pipe in the upper part of the drill string. This is especially beneficial as it is known that some dual walled insulated drill pipe can generate challenging drilling dynamics so using conventional steel drill pipe close to the BHA will be beneficial.

[0051] In another aspect, a drilling system can embody a drill string that employs drill pipe with a wall thickness greater than 0.5 inch (and preferably in a range of 0.7 inch to 1 inch). The wall thickness can be embodied by the unitary metal body of the drill pipe or a composite structure that includes a metal body of the drill pipe together with thermal insulation material that forms the inner diameter surface of the drill pipe. In either case, the increased wall thickness adds extra thermal insulation material to improve thermal insulation of the interior of the drill pipe relative to the exterior environment which contains hot drilling fluid. Furthermore, the inner diameter of the drill pipe can be less than 4 inches (and possibly in a range of 3.5 inch to 3 inch). This reduced inner diameter can increase flow rate through the drill pipe, which can reduce the time that the drilling fluid, passing through the drill pipe, is exposed to heat. This configuration can reduce drilling fluid temperature that flows through the BHA and drill bit, which can result in significant improvement on the durability of the cutter elements and the drill bit of the drilling system.

[0052] FIGS. 8A and 8B illustrate example drill pipe. In the embodiment shown, the wall thickness of the pipe body can be greater than 0.5 inch (and more preferably in a range of 0.7 inch to 1 inch). Furthermore, the inner diameter of the pipe body can be less than 4 inches(and possibly in a range of 3.5 inch to 3 inch). In this embodiment, the wall thickness of the drill pipe is embodied by the unitary metal body of the drill pipe. In other embodiments, the wall thickness of the drill pipe can be embodied by a composite structure that includes metal body of the drill pipe together with insulation material that forms the inner diameter surface of the drill Pipe.

[0053] The advantages of this configuration can be illustrated with simple calculations of flow rate and Bernoulli’s equation. At an example well site, the maximum known drilling fluid flow rate is around 700 gallons per minute. Assuming a drill pipe inner diameter of 4.5 inch, this implies that current drill pipe technology exists that can handle average fluid velocities of around 170 in / sec. From this calculation, the 170 in / sec fluid velocity is used as a design limit for a lower flowrate (450 gallon per minute) system which was initially designed for drill pipe with a 4.5 inch inner diameter drill pipe. By using the 170 in / sec fluid velocity limit, the inner diameter drill pipe can be reduced to 3.6 in. This would give opportunities for significantly better insulation. Specifically, an additional 0.45 inch of insulative material thickness can be added to the wall thickness of the drill pipe. At the same time, the drilling fluid would spend 55% less time flowing through the drill pipe due to reduced inner diameter, giving it less opportunity to heat up due to heat exchange within the drill pipe. Thus, this configuration gives a dual heat transfer benefit due to a) better thermal insulation, and b) increased fluid velocity. In this manner, this configuration provides for a reduction in the bottom hole temperature of the drilling fluid, which results in improvement to the durability and operational lifetime of the drill bit.

[0054] Note that Bernoulli’s equation requires a significant reduction in fluid pressure(reduced by 1090 psi) with the reduced diameter drill pipe with higher velocity fluid, which may have some implications for decreasing the severity of pipe wear at the higher velocities.

[0055] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

WHAT IS CLAIMED IS:

1. A drilling system configured for drilling a wellbore in a subterranean formation with a formation temperature less than approximately 175°C, the drilling system comprising: a drill string operably coupled to a bottom hole assembly including a drill bit for drilling the wellbore, wherein the drill string is configured to circulate drilling fluid into and through the wellbore during the drilling; wherein the drill string comprises insulated drill pipe or vacuum insulated drill pipe for all or part of the drill string.

2. The drilling system of claim 1, wherein: the drill string comprises a top part different from a bottom part, wherein the top part comprises insulated drill pipe or vacuum insulated drill pipe.

3. The drilling system of claim 2, wherein: the bottom part comprises conventional steel drill pipe.

4. The drilling system of claim 1, wherein: the wellbore is configured to intersect a target hydro-carbon bearing reservoir disposed within the formation.

5. A method of drilling a wellbore in a subterranean formation with a formation temperature less than approximately 175°C, the method comprising: deploying a drill string to drill the wellbore in the subterranean formation, wherein the drill string is operably coupled to a bottom hole assembly including a drill bit for drilling the wellbore, wherein the drill string is configured to circulate drilling fluid into and through the wellbore during the drilling, and wherein the drill string comprises insulated drill pipe or vacuum insulated drill pipe for all or part of the drill string.

6. The method of claim 5, wherein: the drill string comprises a top part different from a bottom part, wherein the top part comprises insulated drill pipe or vacuum insulated drill pipe.

7. The method of claim 6, wherein: the bottom part comprises conventional steel drill pipe.

8. The method of claim 5, wherein: the wellbore is configured to intersect a target hydro-carbon bearing reservoir disposed within the formation.

9. A drilling system for drilling a wellbore in a subterranean formation, the drill system comprising: a drill string operably coupled to a bottom hole assembly including a drill bit for drilling the wellbore, wherein the drill string is configured to circulate drilling fluid into and through the wellbore during the drilling, and wherein the drill string comprises drill pipe with a wall thickness greater than 0.5 inch.

10. The drilling system of claim 9, wherein: the wall thickness is in a range of 0.7 inch to 1 inch.

11. The drilling system of claim 9, wherein: the wall thickness adds insulation material to improve thermal insulation of the interior of the drill pipe relative to the exterior environment of the drill pipe.

12. The drilling system of claim 9, wherein: the drill pipe has an inner diameter surface of less than 4 inches in diameter.

13. The drilling system of claim 12, wherein: the drill pipe has an inner diameter surface in the range of 3.5 inch to 3 inch in diameter.

14. The drilling system of claim 12, wherein: the inner diameter surface of the drill pipe increases flow rate through the drill pipe and reduces time that drilling fluid, passing through the drill pipe, is exposed to heat.

15. The drilling system of claim 9, wherein: the configuration of the drill pipe reduces drilling fluid temperature that flows through the bottom hole assembly and drill bit and results in improvement on the durability of cutter elements and the drill bit.

16. The drilling system of claim 9, wherein: the formation has a formation temperature less than approximately 175°C; and the wellbore is configured to intersect a target hydro-carbon bearing reservoir disposed within the formation.

17. A drilling system configured for drilling a wellbore in a subterranean formation, the drilling system comprising: a drill string operably coupled to a bottom hole assembly including a drill bit for drilling the wellbore, wherein the drill string is configured to circulate drilling fluid into and through the wellbore during the drilling, and wherein the drill string comprises drill pipe having an inner diameter surface of less than 4 inches in diameter.

18. The drilling system of claim 17, wherein: the drill pipe has an inner diameter surface in the range of 3.5 inch to 3 inch in diameter.

19. The drilling system of claim 17, wherein: the inner diameter surface of the drill pipe increases flow rate through the drill pipe and reduces time that drilling fluid passing through the drill pipe is exposed to heat.

20. The drilling system of claim 17, wherein:the configuration of the drill pipe reduces drilling fluid temperature that flows through the bottom hole assembly and drill bit and results in improvement on the durability of cutter elements and the drill bit.

21. The drilling system of claim 17, wherein: the formation has a formation temperature less than approximately 175°C; and the wellbore is configured to intersect a target hydro-carbon bearing reservoir disposed within the formation.

22. A method of drilling a wellbore in a subterranean formation, the method comprising: deploying a drill string to drill the wellbore in the subterranean formation, wherein the drill string is operably coupled to a bottom hole assembly including a drill bit for drilling the wellbore, wherein the drill string is configured to circulate drilling fluid into and through the wellbore during the drilling, and wherein the drill string comprises drill pipe with a wall thickness greater than 0.5 inch and / or an inner diameter surface of less than 4 inches in diameter.

23. The method of claim 22, wherein: the formation has a formation temperature less than approximately 175°C; and the wellbore is configured to intersect a target hydro-carbon bearing reservoir disposed within the formation.

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