WO2022155743A1

WO2022155743A1 - High temperature drilling and methods of use

Info

Publication number: WO2022155743A1
Application number: PCT/CA2022/050083
Authority: WO
Inventors: Mark Andreychuk
Original assignee: Arrow Geothermal Inc.
Priority date: 2021-01-20
Filing date: 2022-01-20
Publication date: 2022-07-28

Abstract

An improved drilling system capable of drilling wellbores to access hot geological formations has a dual-pipe drill string made up of an inner tubing string and an outer tubing string with a tubing annulus defined between. The inner string has an inner bore. Working fluid is circulated downhole from surface to a BHA through the inner bore to drive and cool components of the BHA. Control fluid is circulated downhole from surface through the tubing annulus for insulating the working fluid from formation heat. Layers of thermal insulation can be applied to the inner and outer tubing strings to provide additional thermal protection for the working fluid. The working fluid and control fluid can be cooled at surface and conditioned independently, or can be provided from a common parent fluid stream. The inner tubing string can be independently retrievable from the outer tubing string.

Description

HIGH TEMPERATURE DRILLING AND METHODS OF USE

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001 ] This application claims the benefit of US Provisional Application 63/139,639 filed January 20, 2021 and US Provisional Application 63/178,141 filed April 22, 2021 , the entirety of each of which are incorporated fully herein by reference.

BACKGROUND

[0002] Wellbores to subterranean formations are drilled for a variety of purposes, for example to reach formations having temperatures suitable for use as sources of geothermal power.

[0003] Accessing such resources has become more challenging, as wellbores have necessarily become deeper and more deviated, with significant horizontal legs, in order to reach said resources.

[0004] The increased need for horizontal and multi-lateral wells have required more sophisticated drilling techniques to locate the wellbore within the bounds of the target formation and, in the case of formations accessed by multiple wells, avoid unwanted collisions and intersection between wells. For formations having multiple wells that work in tandem, for example when one wellbore is used to inject fluids and another wellbore is used to produce fluid, it is desirable to control the proximity of the drilled wellbores to each other. As the wells can extend for kilometers, various tools and instrumentation have been developed to aid in steering the drilling operations, known as directional drilling.

[0005] Directional drilling typically comprises a downhole tool or bottomhole assembly (BHA) having at least a bent sub, a motor, and a drill bit at the downhole end of a tubing string extending from surface, also known as the drill string. Drilling fluid i.e. drilling mud is circulated downhole through the drill string to drive the motor, which in turn rotates the drill bit to cut the formation as the drill string advances along the newly cut wellbore. The bent sub re-orients the drill bit 360 degrees for controlling the direction of drilling. The downhole motor is typically fluid-powered, known in the industry as a mud motor or a positive displacement motor (PDM). The mud motor is a progressive cavity, positive displacement fluid device. A helical rotor is fit to an elastomeric stator forming a fluid cavity that progresses along the stator as the rotor rotates. Fluid, such as drilling mud, is pumped downhole and directed to the stator/rotor interface for fluid rotation of the rotor as the fluid cavity traverses the length of the motor. Directional drilling may also be performed using rotary steerable assemblies as opposed to PDMs.

[0006] Further, directional instruments are provided for determining the BHA’s location, orientation, and direction. Such instruments are predominantly electronic and are often referred to as measurement-while-drilling (MWD) tools, electromagnetic (EM) tools, or a combination thereof. Further, when drilling adjacent parallel or intersecting wells, the directional tools of one drilled wellbore can signal its location whilst the BHA of a nearby wellbore follows a path based on the location of the first well, for example to either intersect, avoid, and otherwise position itself relative to the first well. One type of drilling method is known as magnetic ranging, in which one offset well is used as a known source and a companion well is fit with an electronic sensor tool. The offset well acts as a passive source, for example by using the metallic structure of the casing itself, or as an active source, in which a downhole string having an electronic transmitting tool is run into the well.

[0007] Deep formations, especially those having a high temperature, can present a hostile operating environment for the mud motor and electronic directional drilling (e.g. MWD/EM) tools. The tools are located far from surface, are subject to high pressure fluids, significant vibrations, and elevated temperatures. As wells become deeper and longer, high temperatures pose an impediment to the use of directional drilling tools and techniques. Most directional drilling technologies have been developed in the context of drilling wellbores to access hydrocarbon formations, which typically reach temperatures as high as 150°C.

[0008] In geothermal contexts, where wellbores are drilled to access suitable geothermal formations for the production of energy, increasing energy conversion efficiencies are found at hotter formations. The general principle behind geothermal energy generation is to circulate a cool fluid to a geothermal formation having desirable thermal characteristics, and producing hot power fluid such as steam or CO2 to surface for the extraction of energy therefrom, then circulating the spent power fluid back into the system. With reference to Fig. 1A, approaches for fluid circulation include paired wells, open loop to the formation; single well, closed loop; and connected well-to-well loops. [0009] The efficiency of steam power plants increases as pressure and temperature increase to a point at which the latent heat of vaporization is zero, or when there is no boiling required. This is the case when a fluid is at its critical pressure and critical temperature. At such conditions, maximum energy is extracted as the pressure of the dry, supercritical steam drops across a steam turbine. As such, it is desirable to access hotter geological formations to improve geothermal plant efficiency.

[0010] It has been posited that three thermodynamic variables are required to generate cost-effective geothermal power. First, a formation with sufficient temperature, e.g. greater than 175°C, must be available. Second, a sufficient mass flow rate of power fluid must be provided to draw heat from the formation. Third, a sufficiently large contact area between the power fluid and the formation must be available. Such power fluid may be water, CO2, or any other suitable fluid. Applicant has found that a geothermal system having one or more injector/producer well pairs having adjacent horizontal sections with multiple fluid communication zones/channels spanning therebetween, as shown in Fig. 1A, meet the above criteria. Alternatively, with reference to Fig. 1 B, one may drill an injector bore having a horizontal portion located in the geothermal formation, and multiple vertical producer wells terminating adjacent the horizontal portion of the injector well for receiving power fluid introduced by the injector well into the formation. Conversely, multiple vertical injector wells may be drilled to terminate in the geothermal formation, and a producer well can be drilled having a horizontal section adjacent the injector wells for receiving power fluid introduced by the vertical injector wells into the formation. Ideally, the power fluid is introduced at such volumetric rate so as to extract sufficient energy from the formation while still permitting the formation to replenish its heat from the earth, thus providing a sustainable source of heat energy.

[0011 ] Efficient, dry stream geothermal power plants are now available at fluid supply temperatures of above about 175°C. Thus, it is desirable to drill geothermal wellbores to access formations having temperatures of 175°C or greater. However, formations with such temperatures have not been exploited to date, namely due to the difficulty in economically directionally drilling wells to access such hot formations with the sophistication needed to form horizontal legs or well loops therein using available directional drilling technologies. Specifically, the ability to access formations having higher temperatures is limited by the thermal operational limits of available directional drilling tools.

[0012] To date, conventional directional drilling technology has been generally rated for consistent directional drilling in formations with temperatures up to about 150°C and in some cases up to 175°C. Directional drilling tools designed for higher temperature environments are typically more expensive and less reliable in high pressure and vibration environments, due to their increased complexity. The electronics at the BHA can include MWD systems, electromagnetic (EM) sensors, transmitters, and receivers, acoustic transmitters and sensors, logging tools, ranging tools, and onboard memory. Such electronics packages can further include sensitive equipment such as digital signal processors, radio communications, and flash memory. Such components have temperature limitations due to parts such as printed circuit boards, solder, plastics, as well as the common need for heat sinks in conventional applications to shed heat. Further, the mechanical components of the BHA, including mud motors and fluid seals, are also adversely affected at high temperatures. Conventional directional drilling electronics and tooling can typically reliably operate up to 150°C. Beyond this point, the electronic components of the BHA, the elastomers of mud motors, and other components are liable to fail.

[0013] To expand project capabilities to hotter formations, such as those having temperatures of 300°C or greater, one can improve the temperature capability of known directional drilling technology to render them suitable for use in drilling to higher temperature formations by either developing high-temperature tolerant electronics, or cool conventional electronics to maintain them within their thermal operating parameters.

[0014] In greater detail, one can develop robust electronics to withstand hotter drilling environments, for example having temperature greater than 175°C. Progress in developing directional drilling electronics technology capable of reliably functioning above 150°C has been slow and expensive, and such instruments unreliable due to the high pressures, vibrations, and shock exposure the instruments are subjected to. [0015] Alternatively, existing electronics can be cooled, for example with drilling fluid, to enable them to operate in higher temperature environments. It is known to cool drilling fluid and pump said fluid down a conventional drill pipe to a conventional directional drilling BHA operating in a high temperature reservoir. To date, this surface drill fluid cooling process has been applied with respect to formations having modest temperatures (i.e. less than 100°C) and would only be effective in protecting standard directional electronics having a 150°C operating limit from formations having temperatures of up to, for example, 200°C. Therefore, these types of systems in general could be capable of drilling in reservoirs up to 200°C, which remains below the most desirable and efficient critical steam temperatures for harnessing geothermal power. Drilling fluid cooling systems are also limited in their capability as the drilling fluid is heated by the formation as it progresses downhole. Due to limitations in insulation and surface cooling technology, cooling with drilling fluid becomes less effective as the length of the wellbore increases.

[0016] There is a need for systems and methods to enable the economical and reliable directional drilling of wells to access extremely hot formations using conventional drilling tools and limiting the need for specialized high-temperature electronic and mechanical tools.

SUMMARY

[0017] Improved drilling technologies are described herein which enable access to hotter geological formations, such as those having temperatures of 175°C and above. Access to such hot formations has applications in the geothermal energy context. The improvements include systems enabling drilling operations, in particular directional drilling operations, in high temperature environments to construct wells providing improved energy production in the context of geothermal projects, and access to resource deposits that were heretofore uneconomical to pursue.

[0018] The ability to access high temperature wells is desirable, as such wells provide significantly higher energy returns, thus justifying drilling and completions costs. Such advantages are important in rendering geothermal energy an economical source of base load, non-intermittent, renewal energy competitive with fossil fuel energy sources such as natural gas and coal.

[0019] In embodiments, a concentric pipe-in-pipe drill string is provided for directional drilling operations, the drill string comprising an inner tubing string and an outer tubing string. A directional drilling bottom hole assembly (BHA) is connected to a downhole end of the drill string. The inner tubing string has an inner bore extending therethrough for permitting fluid communication between surface equipment and the BHA. A tubing annulus defined between the inner tubing string and outer tubing string permits fluid communication between surface equipment and a downhole section of the drill string. In embodiments, the tubing annulus is in communication with the BHA. [0020] A working fluid such as drilling mud can be circulated through the inner bore to the BHA to power components of the BHA, such as the PDM, and also provide cooling for BHA components such as directional drilling tools and the PDM. A control fluid can be circulated through the tubing annulus toward the BHA to act as a protective layer to insulate the power fluid in the inner bore from formation heat. The control fluid can be discharged at a point uphole of the BHA into the wellbore annulus defined between the outer tubing string and the wellbore or, in some embodiments, the control fluid can also be directed through the BHA to power and cool BHA components.

[0021 ] Insulating layers, such as spray-on materials, can be applied to some or all of the inner and outer walls of the inner and outer tubing strings to provide additional thermal insulation for the working fluid in the inner bore. [0022] In a broad aspect, a system for drilling a subterranean wellbore comprises: an outer tubing string having a first bore; an inner tubing string having an inner bore, the inner tubing string located within the first bore of the outer tubing string and defining a tubing annulus therebetween; a working fluid located within the inner bore; a control fluid located within the tubing annulus; and a bottom hole assembly (BHA) for drilling the wellbore connected to a downhole end of the inner tubing string; wherein the BHA is in communication with the inner bore for receiving the working fluid to power and cool the BHA and is configured to discharge the working fluid into the wellbore for return to surface via a wellbore annulus defined between the outer tubing string and the wellbore.

[0023] In an embodiment, the outer tubing defines one or more discharge ports for permitting the control fluid to flow from the tubing annulus to the wellbore annulus. [0024] In an embodiment, at least a portion of the outer tubing string corresponding axially to the location of electronic components of the BHA is made of a non-magnetic material.

[0025] In an embodiment, an uphole portion of the outer tubing string comprises upper tubing string sections having a greater thickness than that of outer tubing string sections downhole thereof.

[0026] In an embodiment, the system comprises one or more layers of insulating material applied to at least one of the inner tubing string and the outer tubing string. [0027] In an embodiment, the inner tubing string comprises a plurality of mechanically connected inner tubing segments and is independently axially moveable relative to the outer tubing string.

[0028] In an embodiment, the inner tubing string comprises an electrical conductor extending therealong for electrically connecting equipment at surface with the BHA.

[0029] In an embodiment, the electrical conductor is located along an outer wall of the inner tubing string.

[0030] In an embodiment, the system further comprises one or more diverter ports defined in the inner tubing string for permitting working fluid to flow from the inner bore to the tubing annulus.

[0031 ] In an embodiment, the BHA comprises an inner BHA flow conduit in communication with the inner bore, and a BHA annulus defined between the inner BHA flow conduit and an outer BHA housing, wherein the inner BHA flow conduit comprises one or more BHA ports for permitting the working fluid to flow between the inner BHA flow conduit and the BHA annulus.

[0032] In an embodiment, a plurality of sliding sleeve assemblies are installed and spaced along the outer tubing string, the plurality of sliding sleeve assemblies having at least one sleeve flow port for permitting communication between the first bore and the wellbore annulus, and a sleeve actuable between a closed position for blocking fluid flow through the at least one sleeve flow port, and an open position for permitting fluid flow through the at least one sleeve flow port. [0033] In an embodiment, the system further comprises a plurality of expansion joints located along the outer tubing string.

[0034] In another broad aspect, a method for drilling a subterranean wellbore comprises: locating an inner tubing string within a first bore of an outer tubing string, the inner tubing string defining an inner bore and a tubing annulus being defined between the inner tubing string and outer tubing string; delivering a working fluid downhole through the inner tubing string to a bottom hole assembly (BHA) located at a downhole end of the inner tubing string; delivering a control fluid downhole through the tubing annulus toward the BHA; and returning the working fluid and control fluid to surface via a wellbore annulus defined between the outer tubing string and the wellbore.

[0035] In an embodiment, the method further comprises cooling the working fluid and control fluid at surface.

[0036] In an embodiment, the working fluid and control fluid are cooled to different temperatures.

[0037] In an embodiment, the method further comprises directing the control fluid from the tubing annulus into the wellbore annulus at one or more locations.

[0038] In an embodiment, the method further comprises directing working fluid from an inner BHA flow conduit of the BHA in communication with the inner bore to a BHA annulus defined between the inner BHA flow conduit and BHA housing.

[0039] In an embodiment, the method further comprises directing working fluid from the BHA annulus back into the inner BHA flow conduit. [0040] In an embodiment, the method further comprises retrieving the inner tubing string to surface and leaving the outer tubing string in the wellbore.

[0041 ] In an embodiment, the method further comprises actuating one or more of a plurality of sleeve assemblies spaced along the outer tubing string from a closed position to an open position for permitting fluid communication between the first bore and the wellbore annulus.

[0042] In an embodiment, the method further comprises actuating a plurality of packers spaced along the outer tubing string for isolating one or more stages of the wellbore; actuating one or more sleeve assemblies spaced along the outer tubing string for exposing one or more sleeve flow ports of the sleeve assemblies corresponding to one or more selected stages of the one or more stages; blocking fluid flow in the first bore below the sleeve flow ports; and increasing fluid pressure in the first bore to induce hydro-shearing in a geological formation adjacent the wellbore. [0043] In an embodiment, the method further comprises stopping drilling and periodically delivering at least one of a pill of working fluid to the inner bore and a pill of control fluid to the tubing annulus.

[0044] In an embodiment, the method further comprises delivering a supercooled coolant into at least one of the inner bore and the tubing annulus.

BRIEF DESCRIPTION OF THE DRAWINGS

[0045] Figure 1A depicts an injector-producer well pair extending into a geothermal formation, the injector well introducing geothermal power fluid from surface into the formation, and the power fluid sweeping therethrough toward the producer well to be produced to surface;

[0046] Figure 1 B depicts an injector well having a horizontal portion introducing geothermal power fluid into a formation, and the power fluid sweeping therethrough toward a plurality of vertical producer wells;

[0047] Figure 2A depicts an embodiment of a surface fluid cooling system for the treatment and preparation of fluid to be introduced downhole through embodiments of Applicant’s drill string for cooling and powering downhole direction drilling tools;

[0048] Figure 2B depicts an example of a cooling lake for cooling return fluid from the drill string;

[0049] Figure 3A depicts a top drive flow swivel assembly for use with the drill string of Fig. 2A for introducing working fluid into an inner tubing bore and control fluid into a tubing annulus thereof;

[0050] Figure 3B depicts an alternative embodiment of a swivel assembly shown installed in a top drive of a drilling system;

[0051 ] Figure 3C is a cross-sectional view of the swivel assembly of Figure 3B with working fluid flowing through a central bore of a rotary seal body of the seal assembly and control fluid flowing through a side port into a swivel annulus of the swivel assembly;

[0052] Figure 3D is a detail cross-sectional view of the swivel assembly of Figure 3C; [0053] Figure 3E is a detail cross-sectional view of the swivel assembly of Figure 3D with surrounding top drive components removed;

[0054] Figure 4A is a cross-sectional representation of an embodiment of a dual pipe drill string for directional drilling into hot geological formations;

[0055] Figure 4B is an enlarged cross-sectional representation of the drill string of Figure 4A depicting the flow of control fluid through a tubing annulus and the flow of working fluid through an inner tubing bore of the drill string;

[0056] Figure 4C is a detail cross-sectional view of the drill string of Figure 4A depicting layers of insulating material on the inner and outer walls of the inner and outer tubing of the drill string;

[0057] Figure 4D is an illustration of an embodiment of the drill string of Figure 4A configured to discharge control fluid into the wellbore annulus at various points along the wellbore;

[0058] Figure 5A is a partial cross-sectional view of a BHA of an embodiment of a drill string having working fluid partially diverted from an inner BHA conduit in communication with the inner tubing bore into a BHA annulus;

[0059] Figure 5B is a cross-sectional view of a BHA wherein working fluid only flows through an inner BHA conduit in communication with the inner tubing bore;

[0060] Figure 5C is a cross-sectional view of a BHA wherein working fluid is partially diverted from the inner BHA conduit in communication with the inner tubing bore into a BHA annulus, and the working fluid stream returns into the inner BHA conduit thereafter; [0061 ] Figure 5D is a cross-sectional view of a BHA wherein working fluid is partially diverted from the inner BHA conduit in communication with the inner tubing bore into a BHA annulus, and the working fluid proceeds to the drill bit via the inner BHA conduit and a PDM annulus in communication with the BHA annulus;

[0062] Figure 6A is a cross-sectional view of inner and outer tubing segments of an embodiment of a drill string;

[0063] Figure 6B is a cross-sectional view of the inner tubing segment of Figure 6A;

[0064] Figure 6C is a cross-sectional view of the outer tubing segment of Figure 6A;

[0065] Figure 7A is an embodiment of a drilling operation for an injector/producer wellbore pair for sweeping thermal power fluid across a geothermal formation;

[0066] Figure 7B depicts a drilling BHA of one of the wells of Figure 7A being tripped out to be replaced with a ranging tool;

[0067] Figure 7C depicts the ranging tool of Figure 7B being used to communicate with the drilling BHA of the other well to range the wellbores to maintain the position of the injector and producer wells at a desired relative distance;

[0068] Figure 8A depicts a BHA having a prior art non-magnetic collar;

[0069] Figure 8B depicts an embodiment of a drill string having non-magnetic inner and outer tubing segments at axial locations corresponding to the location of directional tools of the BHA; [0070] Figure 9A depicts a BHA having a BHA housing that extends the length of the BHA;

[0071 ] Figure 9B depicts a BHA having a BHA housing that surrounds only the power section of the PDM;

[0072] Figure 10A depicts an embodiment of a 30m conventional drill string for directional drilling as compared to an embodiment of a 30m dual pipe drill string for directional drilling;

[0073] Figure 10B is a graph comparing the relative temperature performance of the drill strings of Figure 10A with respect to maintaining temperature of the working fluid;

[0074] Fig. 10C is a table depicting the temperature performance of the drill strings of Figure 10A with respect to maintaining temperature of the working fluid;

[0075] Figure 11 depicts a dual pipe drill string having outer tubing segments that are thicker in the uphole vertical section of the wellbore relative to the horizontal section downhole thereof;

[0076] Figure 12 depicts an embodiment of a dual pipe drill string with its tubing segments connected by upset subs;

[0077] Figure 13A depicts an embodiment of a dual pipe drill string in which the inner tubing string is independently axially moveable relative to the outer tubing string;

[0078] Figure 13B depicts a connection between inner and outer tubing segments of the drill string of Figure 13A, the inner tubing segment connections having threaded mechanical connections; [0079] Figure 14A depicts a connection between inner and outer tubing segments of a dual pipe drill string, the inner tubing segments having an electrical connection;

[0080] Figure 14B depicts a floating connection between inner tubing segments of a dual pipe drill string;

[0081 ] Figure 14C depicts a floating connection between inner tubing segments of a dual pipe drill string, the connection also having an electrical connection;

[0082] Figure 14D depicts a threaded mechanical connection between inner tubing segments of a dual pipe drill string, the connection also having an electrical connection;

[0083] Figure 15A is a cross-sectional view of an inner tubing segment of a dual pipe drill string having an electrical conductor wire located along an outer wall;

[0084] Figure 15B is a cross-sectional view of an inner tubing segment of a dual pipe drill string having an electrical conductor ribbon located along an outer wall; [0085] Figure 15C is a cross-sectional view of an inner tubing segment of a dual pipe drill string having an annular electrical conductor sandwiched between two electrically insulating layers and located along an outer wall of the inner tubing segment;

[0086] Figure 15D is a cross-sectional view of an inner tubing segment of a dual pipe drill string having electrical conductors located along an outer wall and embedded into the segment; [0087] Figure 16 is a representation of an electrically enabled dual pipe drill string configured to wirelessly transmit data between a short hop transmitter located at surface;

[0088] Figure 17 is a representation of an outer tubing segment of a dual pipe drill string having a sleeve assembly;

[0089] Figure 18A is a representation of a dual pipe drill string having a plurality of sleeve assemblies spaced therealong, the drill string being stuck-in-hole due to a collapsed portion of the wellbore;

[0090] Figure 18B depicts the inner tubing string of the drill string of Figure 18A having been retrieved to surface, leaving the outer tubing string in the wellbore;

[0091 ] Figure 18C depicts fluid being pumped out of the outer tubing string of Fig. 18B via ports of the sleeve assemblies for hydro-shearing the formation surrounding the wellbore;

[0092] Figure 18D is a representation of a dual pipe drill string having a plurality of sleeve assemblies and expansion joints spaced therealong, the drill string being stuck-in-hole due to a collapsed portion of the wellbore;

[0093] Figure 19A is a cross-sectional view of an embodiment of a dual pipe drill string, the drill string being stuck-in-hole due to a collapsed portion of the wellbore, having the directional tools thereof being retrieved to surface with a wireline tool;

[0094] Figure 19B is a cross-sectional view of an embodiment of a dual pipe drill string, the drill string being stuck-in-hole due to a collapsed portion of the wellbore, the inner tubing being retrieved to surface independently of the outer tubing; [0095] Figure 19C is a cross-sectional view of an embodiment of a dual pipe drill string, the drill string being stuck-in-hole due to a collapsed portion of the wellbore, the inner tubing being retrieved to surface with the BHA independently of the outer tubing;

[0096] Figure 20A depicts a partially-cased wellbore extending onto hard rock;

[0097] Figure 20B depicts a plug and perf tool setting a bridge plug in an open hole section of the wellbore of Figure 20A;

[0098] Figure 20C depicts a perforation gun creating perforations uphold of the bridge plug of Figure 20B;

[0099] Figure 20D depicts fluid being injected into the wellbore to hydro-shear the wellbore through the perforations of Figure 20C;

[0100] Figure 20E depicts a second bridge plug being set uphole of the hydrosheared stage of Figure 20D and a second set of perforations being created uphole of the second bridge plug;

[0101 ] Figure 20F depicts a partially-cased wellbore extending onto hard rock;

[0102] Figure 20G depicts the wellbore of Figure 20F having been preperforated at a plurality of stages by a plug and perf tool;

[0103] Figure 20H depicts a dual pipe drill string having a plurality of open hole packers and sleeve assemblies run in to the wellbore of Figure 20G; and

[0104] Figure 20I depicts the stages of the wellbore being hydro-sheared through the sleeve assemblies of the drill string. DETAILED DESCRIPTION

[0105] Improved directional drilling systems and methods are provided to enable access to hotter geological formations, such as for the purpose of improving geothermal energy extraction from the earth, and accessing any other hot formation to which access via wellbore is desirable. More specifically, embodiments disclosed herein enable directional drilling in geological formations having temperatures greater than the maximum design temperatures of conventional directional drilling technologies, typically 150°C-175°C. Such geological formations can be hot dry rock (HDR) formations having no natural porosity and permeability, and which require human intervention to introduce porosity and permeability, or traditional formations having some natural porosity and permeability, and natural fractures. While embodiments of the improved directional drilling technology herein are disclosed in the context of drilling geothermal wellbores, the technology can also be applied to the drilling of any wellbore for accessing high temperature geological formations.

[0106] Figs. 1A and 1 B depict exemplary geothermal well systems for generating geothermal power. Fig. 1 C depicts injector and producer wells 4I,4P having adjacent horizontal legs, the injector well introducing a fluid into the geothermal formation which is produced back to surface by the producer well after traversing through a plurality of fluid communication zones and being sufficiently heated by the formation. Figs. 7A-7C depict an exemplary process for drilling the injector/producer wellbore pair of Fig. 1A. Such well pairs are drilled by running multiple drilling rigs having their own drill string 10 and maintaining a predetermined vertical and/or horizontal distance between the horizontal legs of the wells. As the BHAs of the wells approach each other, greater accuracy may be required to maintain the proper distance between the wellbores. With reference to Fig. 7B, the drill string of a first well of the well pair is tripped out to change the drilling BHA for a ranging tool to assist with wellbore positioning. With reference to Fig. 7C, the ranging tool is run back into the first well to assist the drilling BHA of the second wellbore in positioning the second wellbore relative to the first wellbore. Once the wellbores have been drilled and properly positioned, both drill strings can be tripped out and well liner can be tripped in to case the wellbores, and a geothermal power plant can be built to circulate energy fluid T between the wellbores and across the geothermal formation to generate geothermal power (Fig. 1A). Likewise, the ranging process described above can be used to drill and position the injector well 4I and producer wells 4P of the geothermal system of Fig. 1 B relative to one another.

[0107] The efficiency of geothermal power systems, such as those described above, increases with the temperature of the geothermal formations accessed by the wellbores. The above drilling processes are example applications for embodiments of the improved drilling system and method disclosed herein. The operation of the conventional drilling BHAs, ranging tools, logging tools, and other equipment in extremely hot geological formations requires cooling to maintain the components within their design temperatures.

[0108] Embodiments herein provide improved directional drilling systems incorporating a stacked thermal insulation configuration comprising streams of fluid directed downhole to cool components of downhole drilling tools and also, optionally, one or more layers of passive thermal insulation applied to the drill string. The cooling can be extended to other aspects of the downhole tools including mechanical components sensitive to high temperatures including fluids, plastics, and elastomers. Deep well, high temperature tools that benefit from the disclosed cooling system include, but are not limited to, directional drilling BHAs including MWD and EM components, wellbore ranging tools, and logging tools.

[0109] In greater detail, cooling is provided for downhole components such as electronics associated with measurement-while-drilling (MWD) and/or electromagnetic (EM) tools and logging tools, such as for logging-while-drilling, collectively referred to herein as directional drilling tools 13. In embodiments associated with directional drilling, a MWD tool is connected to a directional drilling bottomhole assembly (BHA) and circulatory cooling is provided from surface. Conventional electronics, having maximum operating temperatures of about 150°C, and even purposed electronic packages having expanded operating ranges of up to 300°C, can be aided with cooling. Cooling the electronics and other components of the BHA enables the use of conventional, lower priced, and more rugged electronics packages at much higher temperatures than were previously feasible in the industry. Such conventional components may also be better able to withstand the pressures and vibrations common to such drilling operations. Herein, all downhole components of the drilling system, including the PDM, drill bit, MWD, EM, logging tools, and their associated components, are referred to as being part of the BHA 12.

[0110] With reference to Fig. 4A-4C and 5A, the systems and methods disclosed herein provide a localized temperature environment around the directional drilling BHA 12 where conventional directional drilling technology therein is protected thermally from the hot geothermal lithology around the BHA 12, which would otherwise raise the temperature of the components of the BHA 12 beyond their design temperature ranges. Temperature is managed by controlling the temperature of a working fluid P delivered from surface to the BHA 12 with a protective control fluid C and, in some embodiments, layers of insulating materials 60. Such systems and methods are advantageous as they decrease or dispense with the need for research and development of directional drilling tools capable of withstanding high temperatures, such as temperatures in the 175°C-400°C range presented by desirable geothermal formations. Additionally, temperature management of conventional directional drilling technologies present lower technical risk, as they are generally more reliable and less costly to develop and manufacture than new high temperature electronics and instrumentation. Further, Applicant’s technology is highly scalable in a short period of time, making it adaptable to a variety of drilling environments, including periods of drilling and also periods wherein drilling is paused. [0111 ] The insulation of the working fluid P from formation heat by the control fluid C and insulating layers 60 as it travels downhole toward the BHA 12 also results in cooler discharge fluids from the drill string 10 into the wellbore, thus cooling the surrounding wellbore and improving the ability to cement liner and/or install open hole packers in the wellbore and perform other operations better suited to lower temperature environments, such as open-hole logging. Tools such as logging-while- tripping tools may also be used with the drill string 10 by pumping said tools down the inner bore of the drill string 10 prior to tripping the drill string 10 to surface, such that the entire well may be logged while the drill string 10 is tripped out of the wellbore. Dual Pipe Drill String

[0112] In an embodiments, with reference to Figs. 4A-4C , 5A, and 6A-6C, an improved directional drilling system comprises a fluid-cooled, pipe-in-pipe drill string 10 extending downhole from surface and having a directional drilling BHA 12 attached at a downhole end thereof. Cooling systems 100 at surface can condition fluid(s) for delivery into the drill string 10 for cooling the BHA 12. Herein, the term “pipe-in-pipe” includes concentric tubing and may also be known as a dual pipe system.

[0113] The dual pipe drill string 10 comprises an inner tubing string 20 with inner bore or inner flow path 22, and an outer tubing string 30 having an outer bore 32. The inner tubing string 20 resides within the outer bore 32 of the outer tubing string 30, defining a tubing annulus 40 providing an annular flow path 42 between the inner and outer tubing strings 20,30. A wellbore annulus 50 is defined between the outer tubing string 30 and the drilled wellbore or casing lining the wellbore thereabout. As best shown in Fig. 4D, the dual pipe system 10 can optionally include thermal insulation 60, for example insulative layers 60, along any one of the inner and outer walls of the inner tubing 20 and outer tubing 30, or a combination thereof. Such insulation 60 can be a refractory mortar or any other suitable thermally insulating material.

[0114] Each of the inner and outer tubing string 20,30 can be comprised of a plurality of tubing segments connected end-to-end. With reference to Figs. 6A-6C, in an embodiment, the segments 38 of the outer tubing string 30 can each have a threaded box end 37 and a threaded pin end 39 such that the outer tubing segments 38 can be threadably connected to each other. The inner tubing string segments 28 can have box and pin ends 27,29 with floating connections such that inner tubing segments 28 are frictionally coupled together, such as via a frictional engagement with seals such as O-rings 24 to prevent fluid loss through the connections between the inner tubing segments. In some embodiments, the inner tubing segments 28 can be mechanically coupled to each other such as with threads or other connection mechanisms as opposed to floating connections. In embodiments, the connections of the outer tubing segments 38 can comprise metal-to-metal seals or other sealing methods not requiring elastomeric seals, as the outer tubing string 30 is exposed to extremely high formation temperatures that may compromise elastomeric seals. While threaded or frictionally engaged pin and box sections are described for the connections of the inner and outer tubing segments 28,38, any other suitable connection mechanism may be used to couple the segments to form the inner and outer tubing strings 20,30. One or more centralizers 23 can also be located between the inner and outer tubing segments 28,38 to maintain the radial spacing therebetween.

[0115] In embodiments, respective inner and outer tubing segments can be torsionally locked, such as with locking pins 26 inserted into corresponding grooves or apertures of the segments. In this manner, corresponding inner and outer tubing segments 28,38 can be rotationally coupled to each other prior to being connected to an adjacent inner and outer tubing segment pair which are themselves rotationally coupled. As depicted in Figs. 6A-6C, one or more locking pins 26 can be inserted into corresponding apertures 25 of a segment of inner tubing 20. The inner tubing segment 28 can then be inserted into a corresponding outer tubing segment 38 such that the locking pins 26 are seated in corresponding grooves 35 of the outer tubing segment 38. A lock ring 33 can then be used to axially lock the pins 26 in the grooves by expanding the locking ring 33 into a corresponding annular seat of the outer tubing segment 38. Rotational coupling of corresponding inner and outer tubing segments 28,38 simplifies the procedure for making up or breaking down the drill string 10. In embodiments, as described in further detail below, the inner tubing 20 and outer tubing 30 are not rotationally locked.

[0116] With reference to Figs. 3A-3E, in embodiments employing top drive drilling operations, flow swivels 14 are provided for the inner tubing string 20, such as through a swivel 14 at the top for the top drive, and for the tubing annulus 40 to outer tubing string 30 through a sealed fluid inlet housing and swivel below the top drive 16.

[0117] With reference to Figs. 4A-4C, once the drill string 10 has been assembled and connected to the BHA 12, working fluid P is circulated down the inner bore 22 of the dual string 10 to cool the components of the BHA 12. In embodiments, the working fluid P also acts as a power fluid to drive the progressive displacement motor (PDM) 18 of the BHA 12. Additionally, a control fluid C is circulated down the tubing annulus 40 toward the BHA 12. The control fluid C assists in maintaining the temperature of the working fluid P despite the long distances traversed from surface to the BHA 12. In other words, the control fluid C acts as an insulating layer protecting the working fluid P from the high downhole temperatures associated with deep subterranean formations. [0118] Cooling can be multi-purpose, firstly providing the working and control fluid P,C in the dual drill string 10 for maintaining some or all components of the BHA 12 within design temperatures, be they electronic or mechanical. Further, the control fluid C can assist in maintaining the integrity of the working fluid P itself, for example ensuring a liquid phase of the working fluid P at a downhole end of the drill string 10 for driving the downhole PDM 18.

[0119] For example, in an embodiment, working fluid P comprising drilling fluid, i.e. drilling mud, is circulated downhole for driving a PDM 18 of a directional drilling BHA 12, cooling the components of the BHA 12, and then flows back uphole for conveying drill cuttings to surface. In embodiments, two parallel streams are circulated downhole, namely: 1 ) the working fluid P which arrives at the BHA 12 at, or lower than, the maximum design temperatures of the components thereof, and 2) the control fluid C acting as an insulating layer or heat sink for the working fluid P, mitigating or slowing the heating of the working fluid P by the hot formation. The stream of control fluid C can be separately managed from the stream of working fluid P, thus permitting independent control of the temperature, flow rate, pressure, and other parameters of the streams. In other embodiments, the working and control fluid streams P,C can be parallel streams stemming from a common parent stream.

[0120] In embodiments wherein the control fluid C and working fluid P are separately controlled, the flow of control fluid C can be adjusted to compensate for various drilling conditions, including stoppage of drilling, without affecting the working fluid stream P, thus providing improved operational flexibility. [0121 ] The inner tubing string 20 forms the flow path for the working fluid P, reducing the exposed surface area and keeping the working fluid P separated from the tubing annulus 40 and the control fluid C therein. As discussed above, the tubing annulus 40 defined between the inner and outer tubing strings 20,30 forms the flow path for the control fluid C, providing a thermal barrier or heat sink for formation heat and insulating the working fluid P therefrom.

[0122] Insulative coatings or layers 60 can be applied to the inner and/or outer surfaces of the inner and/or outer tubing strings 20,30 to provide further protection for the working fluid P from formation heat. For example, with reference to Fig. 4D, insulative layers 60a, 60b, 60c, 60d can be applied to the inner and outer walls of the inner tubing string 20, and the inner and outer walls of the outer tubing string 30, respectively.

[0123] The control fluid C can also be discharged to the wellbore annulus 50 to join the returning working fluid P as a combined return fluid R. The control fluid C, as it is circulated downhole, need not be or remain as a single phase if it is not being used to drive the PDM. The uprising return fluids R can be lightened by the discharged control fluid C.

[0124] In embodiments, the control fluid C acts as a sacrificial fluid in the sense that it is used to thermally protect the working fluid P in the inner tubular 20 and is not necessarily used to directly cool or power the BHA 12. In other words, the control fluid C insulates the inner tubing 20 such that the working fluid P therein remains cool enough to cool the BHA components and power the drilling tools. In the embodiment shown in Figs. 5A-5D, the control fluid C is discharged into the wellbore annulus 50 via discharge ports 44 located uphole of the BHA 12 for return to surface. The control fluid C is directed to exiting the drill string 10 prior to reaching the BHA 12 as its temperature may already exceed the design temperature of the directional BHA 12, and if placed into contact with the BHA 12 could be detrimental thereto.

[0125] In embodiments, the control fluid C may not have to be discharged to the wellbore annulus 50 uphole of the BHA 12, for example if it is still below the maximum design temperature of the BHA components when it reaches the BHA 12. For example, the control fluid C could be diverted to the inner bore 22 via diverter ports 46 located at some point uphole of the BHA 12, which would provide additional fluid to cool and power the BHA 12. In other embodiments, the control fluid C could be discharged to the wellbore annulus 50 via discharge ports 44 located at some point intermediate the BHA 12 instead of uphole thereof.

[0126] With reference to Fig. 4E, the control fluid C can contain a gas, such as air or nitrogen, or be purely a gas, and discharge ports 44 can be spaced along the outer tubing string 30 for permitting a portion of the control fluid C to exit into the wellbore annulus 50 at various points prior to the toe of the well, for example along the vertical portion of the wellbore. Discharge of gas-containing control fluid C into the wellbore annulus 50 along the vertical portion can assist in reducing hydrostatic head at the vertical portion, which assists in reducing lost circulation zones. Additionally, the discharge of the control fluid C prior to the horizontal portion of the wellbore lessens the fluid pressure required to circulate the fluid to the toe of the well. Management of lost circulation zones is advantageous in scenarios such as underbalanced drilling, wherein circulation is lost to the formation through natural fractures or other lost circulation zones.

Drill String Materials

[0127] In embodiments, the outer tubing 30 can be made of a metal alloy to withstand the mechanical stresses of the drilling operation, such as vibrations, wellbore pressures, and temperature variations. As metal alloys provide relatively poor thermal insulation, as mentioned above and shown in Fig. 4D, insulating layers 60 can be applied to one or both of the inner and outer walls of the outer tubing 30 to improve the thermal insulation properties thereof. In other embodiments, materials such as fiberglass, composite carbon fiber, and the like with better insulative properties, and still able to withstand the mechanical stresses of drilling, may be used for the outer tubing 30. However, the improved insulation and cooling provided by the control fluid C in the tubing annulus 40 and the insulating layer(s) 60 may already provide sufficient protection for the working fluid P in the inner tubing 20, thus enabling the use of less costly, albeit less thermally insulating, metal alloys for the outer tubing string 30.

[0128] As the outer tubing 30 bears most of the mechanical and thermal stresses of the drilling operation, the material of the inner tubing string 20 can be selected to thermally protect, under pressure, the working fluid P therein. As such, while the inner tubing 20 may also be made of a metal alloy, it can also be made of other materials selected for their thermal insulative properties. For example, carbon fiber or fiberglass high pressure tubing could be selected due to their advantageous thermal isolation characteristics, having multiple times greater thermal efficiency over steel. Use of thermally efficient materials make fluid cooling logistics at surface simpler and more cost effective. Other suitable materials, such as ceramics and the like, may also be used for the inner tubing 20. A further advantage of using non-metal materials is that they may not have as severe thermal expansion/contraction characteristics when exposed to varying heat and extreme thermal gradients.

[0129] In embodiments, the inner tubing segment connections can use seals 24 if the working fluid P in the inner bore 22 can be kept at temperatures below temperatures at which seals become unreliable, for example 300°C.

[0130] The use of carbon fiber or ceramics for the inner tubing 20 may also result in reduced weight, which would lessen the load on the drilling rig hook at surface, increasing the drag load capacity and decreasing the probability of the drill string 10 becoming stuck-in-hole.

BHA Housing Flow Paths

[0131 ] With reference to Figs. 5A-5D, the working fluid P can be directed in multiple ways to cool and power the BHA 12. In one embodiment, with reference to Fig. 5B, the working fluid P can be directed entirely through a conventional BHA 12 to the PDM 18 and drill bit 19. The working fluid P drives the PDM 18 and also cools the BHA 12, including direction tools 13, from the inside outward. Alternatively, with reference to Figs. 5C and 5D, the BHA 12 can comprise an inner BHA flow conduit 54 and outer BHA housing 52, and be configured to stage working fluid P in a BHA annulus 56 defined between the inner BHA flow conduit 54 and the BHA housing 52 to provide more efficient cooling to the directional drilling tools 13 and other components of the BHA 12. More particularly, the BHA 12 can comprise an inner BHA flow conduit 54 in communication with the inner bore 22, and a BHA annulus 56 defined between the housing 52 and the inner BHA flow conduit 54. Ports 58 can be formed in the inner BHA flow conduit 54 to permit the working fluid P to flow from the BHA flow conduit 54 into the BHA annulus 56 to more efficiently cool the BHA components within the inner BHA flow conduit 54 with the working fluid P. In the embodiment depicted in Fig. 5C, the working fluid P can then flow back into the inner BHA flow conduit 54 via return ports 59 such that the entire flow of working fluid P is directed through the PDM 18. In this manner, the working fluid P, which has been kept at a relatively cool temperature by the control fluid C and insulating layers 60 (if present) as it travelled downhole from surface, is used to absorb heat from the outer housing of the BHA 12 which is exposed directly to the hot geothermal formation to further assist in protecting the components of the BHA 12 from formation heat. This cooling through the BHA annulus 56 using the heretofore insulated working fluid P provides improved cooling potential relative to conventional drilling tools.

[0132] In other embodiments, as shown in Fig. 5D, the flow of working fluid P in the BHA annulus 56 can be directed into the wellbore annulus 50 for return to surface, such as through an annulus of the PDM housing. Such flow of working fluid P in the annulus of the PDM housing also provides improved cooling to the PDM 18, if required. As shown, the working fluid P is further directed downhole out of the PDM housing to cool the formation being drilled. Top Drive Fluid Swivel Adaptor

[0133] The top drive 16 of the drilling system can be connected in various ways to the drill string 10. First, the top drive 16 can be connected directly to both flow paths down the inner tubing 20 and the tubing annulus 40 to deliver the same fluid to both, i.e. , the same fluid is used as the working fluid P and control fluid C. The two flow paths may require pressure control, such as through flow balancing orifices, to offset the pressure requirements to maintain adequate flow rates down both paths due to friction losses in either flow path. The two flow paths will also likely have different pressures as the working fluid P flowing down the inner bore 22 is also powering the BHA 12, which will create back pressure. The common fluid could be pumped from a common mud pump and cooled by a common fluid cooling system.

[0134] Alternatively, with reference to Figs. 3A-3E, the top drive 16 is coupled to a device such as flow swivel 14 enabling the flow paths of the working fluid P and control fluid C to be independent. With reference to an exemplary embodiment depicted in Figs. 3B-3E, the flow swivel 14 can replace the saver sub of the top drive 16 and comprise a rotary seal body 15 having an annular rotary seal package 17 surrounding the rotary seal body 15. Control fluid C can be introduced via a side port 11 into a swivel annulus of the flow swivel 14 in communication with the tubing annulus of the drill string 10. A central bore of the flow swivel 14 is in communication with the inner bore 22 of the drill string 10 to receive the flow of working fluid P, for example from the upper end of the top drive 16. [0135] In embodiments, the working fluid P and control fluid C have independent surface fluid handling/cooling systems and pumps. Independent flow down the inner bore 22 and tubing 40 allows for greater flexibility with respect to pumping fluids at different rates, temperatures, pill sizes, and having different compositions. For example, if the BHA 12 is becoming too hot, liquid cryogenic coolant N can be pumped down the tubing annulus 40 to rapidly cool the inner tubing string 20 and its contents.

Cooling When Not Pumping

[0136] The above describes dynamic operation and cooling of the BHA 12 and drill string 10 during drilling, that is, when working fluid P and control fluid C can be continuously pumped through the drill string 10. It is inherent in directional drilling operations that there be periods during which the BHA 12 is idle, such as upset conditions and when the drill string 10 is pulled out-of-hole, i.e. tripping. Accordingly, cooling can be provided to the drill string 10 and BHA 12 during both periods of drilling and idling.

[0137] While drilling, the working fluid P cools the components of the BHA 12 and acts as a power fluid for the PDM 18. During process interruptions, such as surface operations, mechanical failures, or when tripping the drill string 10 out of hole, fluid circulation of at least the working fluid P is interrupted, and the column of working fluid P becomes stagnant. Unable to be replenished, the stagnant working fluid P and BHA components begin to absorb formation heat. Unremedied, the BHA components can rise to temperatures above their design temperature range.

[0138] Accordingly, when drilling is suspended, working fluid P and/or control fluid C can be circulated at least periodically in a cyclical, batch process into either or both the inner bore 22 and the tubing annulus 40 to maintain temperatures at the BHA 12 within design temperatures for a longer period of time.

[0139] For surface operations during which continuous fluid circulation into the drill string 10 is precluded, such as tripping out or making connections, one or both of the working fluid P and control fluid C streams can be periodically refreshed with slugs or pills of cooler fluid to extend the time for performing such operations. Introduction of cooled fluids at surface displaces fluids nearer to surface, which are cooler due to the distance from the hot formation, downhole toward the hot formation and heated portions of the drill string 10 and BHA 12. Additional surface-cooled fluids can be introduced in quantities as desired, and to the depth required, to maintain the temperature at the BHA 12 within design temperatures and low enough for the BHA 12 to remain within design temperatures during the subsequent phase of tripping the drill string 10 out of hole. Such batch-cooling during operations wherein continuous fluid flow into the drill string 10 is not possible provides a relatively longer time period for such operations to be completed as compared to conventional drilling operations. In embodiments, a pill of supercooled liquid such as liquid nitrogen N can be injected into the inner bore 22 and/or tubing annulus 40 to provide even more time for surface operations to be completed. [0140] In an exemplary embodiment, when the drill string 10 is assembled using jointed concentric tubing, fluid circulation from surface to the BHA 12 is typically suspended during removal of each joint or stand of pipe sections. Fluid circulation for imparting a tranche or pill of cool fluid into the inner tubing bore 22 or tubing annulus 40 can be periodically performed, such as after a certain number of stands are racked. One, or both, of the control and working fluids C,P can be refreshed with a fresh fluid pill. The same fluid circulation process can be followed for tripping the drill string 10 out of the wellbore. As the drill string 10 and BHA 12 is pulled from the extremely hot bottom of the wellbore toward the relatively cool surface, fluid refreshing operations can be reduced in frequency.

Emergency cooling

[0141 ] In embodiments, the control fluid C can be pumped independently of the power fluid P. As such, the control fluid C can be pumped at a different temperature, flow rate, volume, and direction from the working fluid P, and can have a different composition therefrom, without interfering with the performance of the working fluid P. This also provides improved operational flexibility, enabling operators to address various situations during drilling in hot formations where BHA cooling control is required.

[0142] For example, if the bottom hole temperature (BHT) is becoming too hot and the fluid supply for the drill string 10 cannot be cooled sufficiently at surface, then supercooled fluid such as a pure cryogenic coolant N could be pumped directly into the tubing annulus 40 to cool the wellbore and the entire drill string 10. Such fluid could comprise liquid nitrogen or any other suitable supercooled fluid. Of course, one must consider metallurgy, cooling limits and drilling stresses during such operations. The cryogenic coolant may heat up and convert to gaseous form as it travels down the tubing annulus 40 and returns up the wellbore annulus 50. This rapid, aggressive cooling can be performed without detrimental effects on the working fluid P inside the inner tubing 20, as the coolant converts to gas in the tubing annulus 40 which is separated from the inner bore 22.

[0143] The above process could also be performed in reverse, wherein larger volumes of cryogenic coolant could be pumped down the wellbore annulus 50 at higher rates due to the larger cross-sectional flow area of the wellbore annulus 50. The coolant can then be returned up the tubing annulus 40. This process can be used to introduce coolant into the wellbore even faster to control temperatures at the BHA 12, such as in emergency situations. Such emergencies may be encountered as geothermal formations are not homogeneous and there may be temperature surges encountered while drilling.

[0144] In situations where there is a bleed-off flow rate into the formation itself, cryogenic coolant could be pumped down both the inner tubing 20 and tubing annulus 40 simultaneously, i.e. bullheaded, to provide even more rapid hole cooling. During this procedure, the flow of working fluid P in the internal tubing 20 could be stopped or pumped and bull headed as well. Cryogenic Surface Equipment

[0145] With reference to Fig. 2, an exemplary surface cooling system 100 is depicted for cryogenically cooling the working fluid P and control fluid C, and cooling and treating the return fluid R. In the depicted example, a cryogenic coolant N such as liquid nitrogen is used to provide cooling for the various fluids. Coolant N can be transported to the well site from plants and made available for cooling, or can be piped in directly from a coolant source.

[0146] In an embodiment, the fluid coolers 102 of the cooling system 100 are heat exchangers configured to supercool return fluid R coming out of the wellbore and working fluid P and/or control fluid C to be circulated into the wellbore. For example, pipes containing working fluid P, control fluid C, and/or return fluid R are jacketed with coolant conduits having coolant N flowing therethrough. Alternatively, conventional fluid cooling systems such as that provided by Drill Cool Systems may also be used to cool the working, control, and return fluids P,C,R. Fluid coolers 102 can also comprise cooling pools or lakes, as shown in Fig. 2B, wherein return fluid R flows through piping in contact with, or immersed in, coolant N contained in a vessel or lake 112, said cooling N being circulated from, and re-cooled at, a chilling tower 114. Applicant’s cryogenic cooling system 100 could simply be added to any other existing surface drill fluid mud cooling technology to enable the ability to supercool the drill fluid down to very cold temperatures.

[0147] The cryogenic coolers 102 can be sized and pressure rated accordingly to match the fluid rate requirements of the drilling operation, for example depending on wellbore diameter, mud motor requirements, hole cleaning rate requirements, drill fluid temperature control etc.

[0148] In the oil & gas context, nitrogen is generally not used in liquid form, but is rather used in a high volume gas form. Use of cryogenic liquid nitrogen N in its liquid form in the present cryogenic cooling system maximizes its ability to cool the various fluids to very cold, cryogenic temperatures, e.g. -196°C at atmospheric pressure. As the present cryogenic fluid cooling system 100 does not require the liquid cryogenic liquid nitrogen to be converted to a warm high pressure nitrogen gas at surface, as is required in oil & gas well applications, the cost of pumping is dramatically reduced and simplified. In fact, little to no pumping is required to circulate the liquid nitrogen, or low pressure pumping is only required to transport the liquid cryogenic nitrogen from the coolant transports to the storage bulkers at the wellsite, and from the bulkers to the heat exchangers/coolers 102. With the high- pressure conversion of the nitrogen from liquid to gas phase being eliminated, as described above, Applicant’s cryogenic cooling system is greatly simplified and is generally logistically reliant only on cryogenic liquid nitrogen volume required to adequately cool the drill fluids, i.e. the working and control fluids P,C, to their required surface temperatures to adequately cool the BHA 12 downhole.

[0149] In one embodiment, Applicant’s cryogenic surface cooling system 100 cools return fluid R, returning from a hot reservoir (i.e. at 400°C), to a re-injection fluid temperature of -60°C. The working and control fluids P,C can be selected to remain in liquid phase when being circulated at very cold temperatures such as at -60°C. From surface to the BHA 12, the control fluid C thermally insulates the working fluid P as it travels from surface. In an example case, the control fluid C is heated from a surface temperature of -60°C in this case to 150°C-210°C at the BHA 12, absorbing the formation heat and insulating the working fluid P in the inner tubing 20 such that the working fluid P, and in embodiments the control fluid C, cool the BHA 12 adequately to maintain its components within their design temperatures.

[0150] Fig. 2 depicts an example of a surface cryogenic cooling system 100. Return fluid R, comprising both spent working fluid P and control fluid C, returns to surface via the wellbore annulus 50. In this example, the temperature of the return fluid is 400°C. Special wellhead considerations, such as high temperature valves, seals and wellhead cooling systems, etc., may be fitted to according to the temperature of the return fluid R in the particular operation. Typically, seals have temperature limitations in the 200°C range. As such, the wellhead 8 can be cooled by pumping cooler fluid from the top of the BOP stack to the return line to mix with the return fluid R as needed to cool the fluid. Alternatively, or additionally, the temperature sensitive components of the wellhead can be jacketed with a suitable cooling system containing cooled drill fluids, cryogenic nitrogen, liquid CO2, or other suitable cold fluids or gases.

[0151] The hot return fluid R can be cooled quickly in a variety of ways immediately after it is discharged from the well. In this example an initial cryogenic fluid cooler 102 is used to initially drop the temperature of the return fluid R from 400°C to about 90°C such that the fluid can be then handled more effectively in conventional drilling mud handling systems 104 downstream of the initial cooler 102. The initial cooler 102 can be any suitable drill fluid cooler, such as a chilling tower. In cryogenic fluid cooler 102, liquid cryogenic coolant N, such as liquid nitrogen, is heated up by the return fluid R and economically converted to a gas G using the energy from the hot drilling fluid returns. The gas is directed to manifold 106, which acts as a collection point for gases from the return fluid R, fluid coolers 102, and separator 110. The gases then proceed to the coolant discharge stack 108, which can be substantially similar to a flare stack. The coolant can be pumped via bulker tank pressure differential or by a low pressure transfer pump from the bulker or coolant transport to the cryogenic fluid cooler 102 where the coolant fluid flows in a jacket around the drill fluid return pipes, converts to gas, and flows to the manifold 106 for discharge to the stack 108. In such an embodiment, high pressure coolant pumps are not required, and conversion of liquid cryogenic fluid at surface to warm gas is also not required, as the hot return fluid R provides the energy to convert the coolant to gas. Use of nitrogen as the coolant is advantageous as nitrogen is inert, and Earth’s atmosphere itself is 78% nitrogen, resulting in little environmental effects from discharging nitrogen into the environment. Nitrogen is also an effective chilling fluid, is abundant, and is relatively cost effective. In other embodiments, alternative suitable coolants may be used.

[0152] A separator 110, such as a conventional separator used in drilling operations, can receive the now cooled return fluid R and be used to drop the fluid pressure from the well in the event any back pressure is being held to deal with any gas/steam still in the drilling fluid. Some of the solids entrained in the return fluid R can be extracted in the separator 110. However, the separator 110 in the present example is primarily used for pressure control to mitigate gas or kicks from the well. [0153] As described above, coolant may also be used for cooling the working P or control fluid C in the well, for emergency cooling in the well, etc.. In such embodiments, a high-pressure liquid cryogenic pump can be provided at the well site, and the separator 110 can also be configured to mitigate gas pressure generated in the well by the coolant converting to a gas in the wellbore due to being heated therein. In embodiments, the separator 110 may not be required, depending on the well design, temperature of the reservoir, etc. In the present example, where the geothermal reservoir being accessed is 400°C, it is probable separator 110 will be required. Any gases extracted from the return fluid R in the separator 110 will be sent to the manifold 106 and then for discharge to the stack 108.

[0154] The return fluid R leaves the separator 110 at about atmospheric pressure and proceeds to a mud system for treatment, such as a conventional mud treatment process comprising centrifuge, shale shaker, chemical treatment, solids removal, etc. to condition the return fluid R to be recirculated downhole. Conventional cooling systems can also be used if further temperature adjustment of the treatment fluid is required. The fluid can then be conditioned and sent to mud pumps for repressurization. The mud pumps can be any suitable pump, such as mud pumps commonly used in common drilling operations. In the present example, the mud is pressurized and pumped to a second cryogenic fluid cooler 102b.

[0155] The second cryogenic fluid cooler 102b cools the fluid to a very cold temperature to maximize the temperature spread between the fluid temperature at surface and the temperature of the directional drilling BHA downhole. In the present embodiment, the fluid temperature is dropped to low temperatures downstream of the mud pump to alleviate potential cold temperature fluid issues with the mud pump itself. The fluid leaving this fluid cooler 102b will be fully pressurized to the pressure required to power the downhole drilling tools and drill the well. As above, the coolant N will be heated by the fluid and converted to a gas, which travels to the manifold 106 and then to the discharge stack 108.

[0156] The cooled fluid can then be pumped through the top drive 112 to the dual pipe drill string as the power fluid P and/or control fluid C. While the return fluid R can be processed as described above and divided into the power fluid P and control fluid C flow streams, in other embodiments, the individual streams can be further processed prior to recirculation downhole. For example, the return fluid R can be divided into the power fluid C and control fluid C streams prior to reaching the second fluid cooler 102b, and only one of the fluids are then directed to the second fluid cooler 102b for further cooling.

[0157] While one embodiment of a surface cooling system 100 is described, any other suitable cooling system for conditioning the temperature of drilling fluids at surface may be used.

Example Thermal Efficiency Comparison

[0158] Applicant’s technology seeks to convey working fluid P from surface to the BHA 12 in hot formation applications with as little thermal variance from surface temperature as possible. With reference to Figs. 10A-10C, depicting the results of thermal efficiency testing between Applicant’s drill string 10 and a conventional drill string, if working fluid P is being pumped at 10°C from surface, it must arrive at the BHA 12 deep underground, for example at a depth of 6000m and temperature of 300°C, at less than the maximum operating temperature of the BHA 12, such as 150°C. Traditional drill pipe, lined drill pipe, or vacuum -insulated tubulars may be used to improve the thermal efficiency of transferring fluid from surface to the BHA 12. However, these methods all have drawbacks, namely:

1 . Fluid flow is not continuous when tripping drill pipe into and out of a well while drilling. Whenever fluid circulation is stopped, heat from the reservoir rapidly reaches the ID of the drill string, reducing thermal isolation efficiency and requiring even more efficient isolation.

2. Virtually every drill string currently available does not have thermal isolation across the thread connections of the drill pipe.

[0159] In contrast, the dual pipe drill string 10 disclosed herein provides improved thermal isolation of the inner tubing 20 even during periods of no flow, and fluid pills of cool working fluid P and/or control fluid C could be introduced as needed to control temperatures at the BHA 12. Additionally, during drilling, the stream of control fluid C is continuous in the tubing annulus 40, thus providing full insulation even at the connections of the inner tubing 20.

[0160] In an experiment, the working fluid P in Applicant’s dual pipe drill string 10 is expected to only gain 0.4C over every 30m in a simulated test of a 300°C formation, which extrapolated over a 6,000m well is 80°C increase in the temperature of the working fluid P. Such expected increase added to a working fluid surface temperature of 10°C results in a temperatures of 90°C at the BHA 12, which is well within the operating limit of the directional tools thereof. However, this does not include losses during periods in which fluid flow is stopped, which may be significant if not managed properly. Applicant’s drill string design allows for mitigating operating practices that can be implemented to overcome such losses, such as the batch introduction of working and control fluids P,C described above, the combination of a dynamic layer of control fluid C and insulative layers 60 surrounding the working fluid P, and the staging of cool working fluid P into BHA annulus 56.

Example Application

[0161 ] Embodiments of the drill string 10 disclosed herein can be used to drill wellbores for use with a thermal sweep geothermal well system, such as that shown in Fig. 1 C comprising injector and producer wellbores having adjacent horizontal legs. Thermal fluid T can be injected into the formation via the injector bore at a plurality of stages, and the thermal fluid T flows toward and enters the producer well at corresponding stages after absorbing heat energy from the formation. The thermal fluid is then produced up to surface to extract energy therefrom.

[0162] Such thermal sweep systems can be constructed by drilling the injector and producer wells using embodiments of the drill string 10 to directionally drill into and access the formation. The wells can then be hydro-sheared at select stages to establish fluid communication channels between the injector and producer wells. If required, proppant can be introduced to maintain the fluid communication channels.

[0163] Applicant has found through various models that such thermal sweep systems are effective at providing the requisite mass flow rates and residence time between thermal fluid T and the formation to heat the thermal fluid T sufficiently to generate economical thermal power, while allowing the formation to recover heat from the earth at a rate sufficient to offset the energy absorbed by the thermal fluid T flowing therethrough, thus providing a sustainable source of geothermal energy.

[0164] In a test model, injector and producer wells were drilled to access a 300°C formation located 3000m below surface. The wells each comprised 7” casing having an ID of 6.25”, and were spaced with their vertical portions being 3000m apart, each well having a 3000m horizontal portion oriented generally parallel with each other and in the direction of the other well. The horizontal portions of the wells were spaced 200m apart. The wells were hydro-sheared to create 200, 30m tall stages along the horizontal portions of the wells establishing fluid communication therebetween, each stage having a width of about 1 -3mm. Such model indicated that the injection of 6m³/min (100kg/s) of water through the injector well nets 11.4-14.5 MWth, or 1100-1280 kJ/kg, over 5 years.

Additional Features

Tapered weight

[0165] With reference to Fig. 11 , Applicant’s drill string 10 can implement outer tubing 30 that is thicker and/or heavier in the vertical section relative to the horizontal leg to act as heavy weight drill collars (DCs) 34 to provide greater weight on the drill bit of the BHA 12. Such thicker vertical outer tubing segments 38L are useful for wells with short vertical sections where long horizontal displacements are required, in order to provide sufficient weight on the drill bit of the BHA 12 and avoid the BHA 12 hydraulicing off the bottom of the wellbore, that is, building up hydraulic pressure below the BHA 12 and impeding progress of the drill string 10. The heavy weight outer tubing sections 38 may or may not be as heavy as traditional DCs, as clearance between the outer tubing 30 and inner tubing 20 is required to provide sufficient flow area for the control fluid C. However, this can be mitigated to some degree for example with the number of heavy weight outer tubing segments 38, or constructing such segments out of a heavier material.

[0166] The thickness of the outer tubing sections 38 can be sized, and materials selected, according to factors such as weight to bit, annular hole clearance, and maintaining outer bore 32 diameter sufficient to accommodate insulating coatings 60, the inner tubing 20, centralization hardware, housing connections, desired fluid flow rates, etc. It is also desirable to size the OD of the outer tubing 30 to be large enough to avoid situations wherein the drilling BHA 12 hydraulics off the bottom of the well during drilling. This is typically an issue with casing drilling where the casing OD is sized for final liner dimensions/cementing (i.e. drilling with casing). For example, for a 12 1 ” diameter open hole well, the OD of the inner tubing 20 could be 8-8 5/8”, and the OD of the final casing string 9 5/8”.

Drill String Porting

[0167] In embodiments, the inner tubing 20 may be ported partially or entirely along its length to permit fluid to pass from the inner bore 22 the tubing annulus 40. This may be particularly helpful in situations where a small portion of the relatively cooler working fluid P in the inner tubing 20 could be added to the hotter control fluid C in the tubing annulus 40 to prolong cooling of the working fluid P along longer distances. However, such porting reduces the volumetric flow rate of working fluid P in the inner tubing 20. Conversely, the outer tubing string 30 could be ported partially or along the entirety of its length to vent hot control fluid C fluid from the tubing annulus 40 to the wellbore annulus 50, since the pressure in the tubing annulus 40 should be higher than that of the wellbore annulus 50. The various fluids of the system could be blended in other ways as desired to provide desired thermal control of the fluids.

Non-magnetic Portion

[0168] Traditional directional drilling BHA’s are comprised of typically magnetic drill pipe extending from surface to the BHA and non-magnetic drill collars which are used to separate the magnetic interference of the PDM and the drill string, which are both made of steel. Typically, the magnetically sensitive directional drilling tools are placed in the middle of the non-magnetic collar to properly isolate the telemetry of the directional tools thereof from interference by adjacent components.

[0169] Referring to Fig. 8A, using traditional non-magnetic collars with Applicant’s drill string 10 would require machining flow-by porting into the outer housing. Alternatively, with reference to Fig. 8B, traditional non-magnetic collars can be replaced with non-magnetic inner and outer tubing sections 28m, 38m of the drill string 10. Such non-magnetic sections 28m, 38m would otherwise be identical to standard inner and outer tubing sections 28,38 of the drill string 10, except that nonmagnetic materials are used in their construction. The magnetically sensitive directional tools 13 can be located in the inner bore 22 of the non-magnetic inner tubing section 28m of the drill string 10, similar to how they would be positioned in traditional non-magnetic collars. The ID of the non-magnetic inner tubing section 28m can be selected to be very close to the ID of a traditional non-magnetic collar to accommodate installation of said tools therein. Considerations for the IIBHO (universal bottom hole orientation) sub would have to be made to time the bent housing of the PDM 18 with the directional tools, for example a small sub between the drill string 10 and the PDM 18 for directing fluid in the BHA 12 entirely through the PDM 18 or into a BHA annulus 56, as described above. An advantage of using nonmagnetic drill string sections 28m, 38m is that no custom non-magnetic collars are required to be fitted to the drill string 10, the non-magnetic sections being made up with the drill string 10 in the same manner as regular sections.

[0170] Referring back to Figs. 5B-5D, in embodiments wherein a BHA housing 52 with inner BHA conduit 54 and BHA annulus 56 is implemented, the BHA housing 52 and inner BHA conduit 54 can be made of a non-magnetic material with the direction drilling tools 13 located therein. Mud Motor / PPM Cooling Only

[0171 ] In embodiments, it may be that the temperature limitation of the BHA 12 lies primarily with the power section, and not the bearing section, of the PDM. In particular, the power section may be more vulnerable to high temperatures than the seals and bearings in the bearing section of the PDM. For example, the bearing section 18b of a PDM may operate with acceptable reliability performance at temperatures up to 300°C, but such temperatures may not be acceptable for the power section 18a. In embodiments where this is the case, and with reference to Figs. 9A & 9B, external housing cooling may be provided only to the power section 18a of the PDM and not the bearing section 18b, greatly simplifying the engineering design of the PDM’s outer cooling housing, as the housing could be terminated above the bent housing. Such an arrangement may be advantageous, as adjustable housings could be used to drill and build the horizontal sections of the wellbore instead of fixed bent motors, permitting more flexibility in the field and requiring fewer motors at surface. Currently, there is no simple way of machining outer housing cooling ports into an “adjustable PDM”; and this would only be practical in a “fixed housing PDM”. Cooling housings for only the power section of PDMs could be supplied independently from the PDM itself, avoiding the need for custom-made PDM units. Not requiring special PDM units greatly simplifies the logistics and costs of cooling the outer housing of a PDM and permits the use of common PDMs as opposed to custom units. [0172] Figs. 9A & 9B depict the discharge point variance between systems wherein only the power section of a PDM is cooled (Fig. 9B) in comparison to cooling both the power section and the bearing section (Fig. 9A). Designing an exterior housing flow path across a fixed and or adjustable housing, such as that connecting the power section to the bearing section of a PDM, is not trivial, and significant cost and logistical advantages can be realized if the need for such flow paths can be avoided.

Upset Subs

[0173] With reference to Fig. 12, the drill string 10 may be designed with upset subs 36 connecting sections of the outer tubing 30. Such upset subs 36 provide a number of advantages, namely:

1 . more room internally to address the connection of the inner tubing sections without creating flow restrictions;

2. increased internal clearance to provide a thicker layer of thermal insulation 60 on the inner wall of the outer tubing 30;

3. standardizes the selection and potentially increases the selection of tubulars from steel/pipe suppliers that can be used for the outer tubing 30;

4. potential to increase the length of the sections of outer tubing 30;

5. localizes a majority of the thread wear to the upset subs 36 as opposed to the outer tubing segments 38;

6. the upset subs 36 can be consumable for thread wear during drill string 10 makeup and breakout tripping;

7. provides an alternative location to “anchor” the internal tubing 20 to the outer tubing 30; 8. provides slight standoff of the drill string 10 in the wellbore, specifically at the horizontal section; and

9. provides stronger connection points to overcome power tong crush forces and power tong gripping wear.

Retrievable Inner Tubing

[0174] In conventional directional casing drilling strings, it was generally desirable to retrieve BHA components such as directional tools and the mud motor while leaving the casing drilling string, i.e. casing, in the wellbore. Retrieval of the BHA was typically performed using wireline to “fish out” the BHA or components thereof such as the directional drilling assembly. Such procedures are unreliable due to issues with the release mechanism for disconnecting the BHA from the drill string, or the low tensile strength of the wireline itself. Other retrieval methods include reverse pumping the directional assembly to surface, which also presents reliability issues such as the assembly becoming stuck while being pumped uphole. Jointed tubulars or coiled tubing could also be used to fish the directional assembly to surface, but these methods are neither economical nor efficient.

[0175] With reference to Fig. 19A, in an embodiment, if the drill string 10 became stuck in a wellbore, the procedures above could be followed to fish out the directional drilling tools 13 of the BHA 12 while leaving the rest of the drill string 10 in the wellbore, as shown in dashed lines. [0176] Alternatively, the drill string 10 could be configured such that the inner tubing string 20 is retrievable to surface while the outer tubing string 30 remains in the wellbore. Such retrieval may be desirable in the event the wellbore collapses, trapping the outer tubing 30 therein, as more components of the drill string 10 may be recovered than would be possible through conventional means. Such embodiments of the drill string 10 may also be used for casing-while-drilling operations, the outer tubing 30 to be left in hole as the wellbore casing while the inner string 20 is retrieved for reuse in another drilling operation.

[0177] With reference to Figs. 13A, 13B, 14D, 19B, and 19C, an embodiment of a drill string 10 has inner tubular connections that are pressure sealed and mechanically connected via threads or other connection means. In such embodiments, the inner tubing segments 28 do not torque up with, and are not coupled to, the outer tubing segments 38. Centralizers 23 may still be located between the inner and outer tubing 20,30 to maintain clearance therebetween. In the depicted embodiment in Figs. 13A, 19B, and 19C, the threaded connections between the inner tubing segments 28 of the drill string 10 enable the inner tubing 20 to be pulled to surface without becoming disconnected from each other. With reference to Fig. 13B, an embodiment of the connection between retrievable inner tubing segments 28 is shown having a progressive and sealing engagement of the internal and outer tubing segments, such that as the outer casing segments 38 are threaded together, the makeup of the inner tubing sections 28 is internal.

[0178] If the outer tubing 30 of such an embodiment of the drill string 10 became stuck in the wellbore, the inner tubing string 20 can be removed independently of the outer tubing string 30, with directional tools and potentially the PDM 18 and drill bit. At the same time, the well remains useful and does not need to be abandoned due to a drill string and inner tubular being stuck therein. For example, turning to Fig. 19B, the inner tubing 20 can be detached from the PDM and drill bit and retrieved to surface with the directional tools 13 of the BHA 12. The outer string 30, PDM, and drill bit are left in the wellbore, as shown in dashed lines. Turning to Fig. 19C, in another embodiment, the outer string 30 can be sized to permit the PDM 18 and drill bit to pass therethrough, such that the inner tubing 20, directional tools 13, PDM 18, and drill bit 19 can all be pulled to surface, leaving only the outer tubing 30 in the wellbore, as shown in dashed lines. The PDM 18 can be connected to the inner tubing 20 via a BHA anchor sub.

[0179] Various inner tubing segment connections can be designed to provide the ability to remove the inner tubing string 20 and some or all of the directional and BHA components therewith.

Electric

[0180] In embodiments, with reference to Figs. 14A-16 the drill string 10 can be provided with electrical connectivity for powering tools and providing communication between surface and downhole components in real-time or with delay.

[0181 ] It is known to provide electrical power and connectivity between surface and downhole tools using wireline inserted into coiled tubing or jointed pipe. While attempts have been made to provide single-wall drill pipe with electrical connectivity, such technologies have significant drawbacks such as unreliable electrical connectivity, high cost to embed wireline within segments of drill pipe, exposure of electrical connections to drilling debris, and exposure to drilling mud flow.

[0182] With reference to Figs. 14A-16, in an embodiment, electrical connectivity can be incorporated in the inner tubing 20 of the drill string 10 by running an electrical conductor 70 therealong, with each inner tubing segment 28 having electrical connections 72 for electrically connecting the conductor 70 across the segments 28. In the dual pipe drill string 10, the inner tubing string 20 is not required to withstand the torque and mechanical stresses of a drilling application. Instead, the outer tubing 30 bears such stresses. This enables the integrity of the electrical connections 72, associated with the inner tubing 20, to be managed in a less demanding, more conventional, reliable, and cost-effective manner.

[0183] In embodiments, the electrical connection between inner tubing segments 28 can be a form of “wet connect” connection, capable of reliably connecting and disconnecting under very debris intensive, wet fluid environments. Such wet connections are known and readily available. For example, suitable “wet connect” connections are available from Rampart Products and are more reliable than currently available electrically enabled drill pipes.

[0184] As the flow in the tubing annulus 40 of the dual pipe drill string 10 will generally not be the working fluid P, i.e. drilling mud, the flow challenges for making electrical connections is reduced. For example, embodiments can use the outer wall of the inner tubing 20 for supporting electrical conductors 70. In the less demanding fluid environment of the tubing annulus 40, the electrical connections 72 between inner tubing segments 28 can be made conventionally with proper electrical isolation and spring loaded contact surfaces, such that when the drill string 10 is vibrating or being screwed/unscrewed together, the electrical contacts 74 remain in contact and radially opposed instead of axially opposed, as shown in Figs. 14C and 14D, such that debris is less likely to be caught between an axial gap between the contacts 74 and potentially impact the connection. In such embodiments, the internal diameter (ID) of the inner tubular 20 is also unencumbered by the electrical conductor 70, and the conductor 70 is not subject to interference or damage from the flow of working fluid P in the inner tubing 20.

[0185] Turning to Figs. 15A-15D, cross-sectional views of various embodiments of electrically-enabled internal tubing 20 are shown for illustrating implementation and configuration of electrical conductor 70.

[0186] In Fig. 15A, an electrical conductor 70 can simply be run as a wireline in the tubing annulus 40, as the flow therein is generally not the abrasive working fluid P. The wireline can be run in many ways, for example it could be run in the ID of the inner tubing 20 as well in certain applications as appropriate.

[0187] In Fig. 15B, an electrical conductor 70 can be in the form of a ribbon conductor, with one or many conductors or leads, running along the OD or ID of the inner tubing 20. Ribbons 70 can be glued or otherwise affixed to the outer surface of the inner tubing 20 more easily than a round wireline. Conductors of many designs, electrical capacity, for data or power transfer and even fiber optic cables may be plausible. [0188] In Fig. 15C, a conductive inner tubing 20 (e.g. steel) is electrically insulated about its outer diameter by an insulative layer 76. An annular conductor 70 circumferentially surrounds, completely or partially, the OD of the insulated inner tubing 20 and is itself isolated by electrical insulation 76 about the conductor’s outer diameter. The electrical insulation 76 protects and insulates the conductor 70 from the tubing annulus 40 for electric isolation. In other words, a tubular conductor 70 is sandwiched between tubular electrical insulator layers 76. Such a design could be used with BHA applications that require very high-power capacity. The electrical insulation 76 can be the thermal insulative layers 60 or be a discrete layer.

[0189] In Fig. 15D, a non-conductive inner tubing 20, for example made from a composite material, is provided wherein discrete conductors 70 are embedded in or encapsulated in the wall of the inner tubing 20. As shown, some conductors 70 can be embedded in the inner tubular wall, for example formed within fiber glass or carbon fiber tubing. Further, examples of electrical wireline/ribbon 70 are shown than can be encapsulated or secured in coatings surrounding the inner tubing 20. Again, these examples could be applied to conductors secured in the ID of the inner or outer tubular as well.

[0190] Incorporation of an electrical connection in embodiments of the drill string 10 herein provides improved flexibility to drilling operations. For example, electrical connectivity enables the drill string 10 to transfer high rates of data uni- or bi-directionally, and provide electrical power from surface to the BHA 12. Such connectivity is desirable in geothermal contexts. This permits real-time monitoring of drilling parameters such as PDM performance and can even enable the use of mixed- phase fluid to be circulated to the BHA 12 via the inner tubing 20.

[0191 ] With reference to Fig. 16, for an EM directional tool and logging apparatus located at the downhole end of an electrically enabled drill string 10, a short hop data transmission device 78 at surface, for example located in the top drive, can be used to wirelessly transmit and receive data between the drill string 10 and surface equipment. In such embodiments, the drill string 10 can have a corresponding transmission device located at an uphole end for communicating with the short hop data transmission device 78.

[0192] Alternatively a hard wired, electrically enabled swivel can be located at the wellhead for directly electrically connecting surface equipment to the electrically enabled drill string 10. An example of such an electrically enabled swivel is the E-Link Rotating Joint by Nexus Energy Technologies™.

Sleeve Assemblies

[0193] With reference to 17-18D, sliding sleeve assemblies 80 can be adapted for use with the drill string 10 in a high temperature environment. The outer tubing 30 can utilize high temperature-capable sliding sleeve assemblies 80 that may be opened or closed to the formation for various operations such as well completion, hydro-shearing of the formation, or fluid sweep across the formation from an injector to a producer well. [0194] In an embodiment, with reference to Fig. 18A, the outer tubing 30 of the drill string 10 has one or more sleeve assemblies 80 installed therealong, either between outer tubing segments 38 or intermediate along an outer tubing segment 38. The sleeve assemblies 80 can be located between every outer tubing segment 38, intermediate along every outer tubing segment 38, or only between or along select outer tubing segments 38. As shown in Fig. 18A, drill string 10 having a plurality of sleeve assemblies 80 is run into a wellbore having an intermediate casing 6 along the vertical portion thereof.

[0195] The sleeve assemblies 80 may be any suitable sleeve assembly known in the art and actuable mechanically via a coiled tubing, service rig, or wireline tool, or electronically such as via wireless signals from surface or from components located along an electronically enabled inner tubing 20, the sleeve assemblies 80 having built-in electronic components for receiving a processing such wireless signals and triggering an actuator to actuate their respective sleeves.

[0196] In an embodiment, the sleeve assemblies 80 are used as a mitigation measure when drilling in problematic rock where the drill string 10 can become stuck in a wellbore beyond recovery. In such circumstances, the wellbore can be at least partially saved with the multistage completion capacity made available by the sleeve assemblies 80, particularly in hot formations (e.g. >150°C) where conventional multistage well completion systems such as plug & perf, ball drop, coiled tubing conveyed sleeves, and the like would not be available due to the extreme temperature. [0197] In an embodiment, if the drill string 10 having sleeve assemblies 80 therealong were to become stuck, the wellbore could be saved and the directional tools 13 and other components of the BHA 12 retrieved. As described above, the inner tubing 20 can be configured to be retrievable with the directional tools 13 and other BHA components independently of the outer tubing 30. The well with the remaining outer tubing string 30 stuck therein could be cemented and subsequently completed in a staged manner as illustrated in Figs. 18A-18C. In Fig. 18A, a drill string 10 becomes trapped in the wellbore due to a collapse in the horizontal leg. In Fig. 18B, the inner tubing 20 is pulled out of the wellbore along with the direction drilling tools 13, leaving the PDM and drill bit. In Fig. 18C, the sleeves 80 spaced along the outer tubing 30 are actuated to the open position, such as with a downhole tool, to permit completion, hydro-shearing of the formation, and/or fluid sweep across the formation for geothermal power generation.

Thermal Conductive Stimulation in Geothermal Well

[0198] In embodiments having the sleeve assemblies 80 spaced along the drill string 10, it is possible to pump thermally conductive material T through the outer bore 32 such that the conductive material T expands the thermal contact area of the well to the surrounding formation without the need for the migration of any fluid from the formation into the wellbore. The sleeve assemblies 80 can then be closed to prevent fluid from entering the outer tubing 30. The introduction of such conductive material T into the formation may be desirable as it is not dependent on porosity or fluid permeability of the formation, merely that it possesses an attractive thermal temperature. There is also less corrosion as compared to operations where fluid flows from the formation into the wellbore, as corrosive wellbore fluids in this embodiment are limited to contact on the outside of the outer tubing 30. Such embodiments also allows temperature to build up in the outer bore 32 to more effectively heat the fluid in wellbore to drive a turbine or generate power or heat.

[0199] In another embodiment, the sleeve assemblies 80 of the drill string 10 can also be used in a thermal sweep operation, wherein the sleeve assemblies 80 of an injector well are opened and the permeability/porosity of the formation is increased via known methods. Fluid can then be pumped into the injector well to the formation via the sleeve assemblies 80 to sweep to a producer well, accumulating thermal energy from the formation along the way that is harnessed by producing the fluid to surface with the producer well. Select sleeve assemblies 80 can be actuated opened or closed as desired, for example using a CT or wireline tool, to control and tune the flow characteristics between the injector and producer wells.

Expansion Joint

[0200] With reference to 18D, in another embodiment, due to the differential thermal expansion of the outer tubing with respect to the hot formation, and expansion/contraction during thermal cycling of the wellbore, the drill string 10 can have axial expansion joints 90 spaced along the outer tubing 30, along at least a portion of the hot formation. The expansion joints 90 could comprise a part of the sleeve assemblies 80 for convenience, or otherwise fitted between the outer tubing segments 38. The inclusion of expansion joints 90 reduces the possibility that the outer tubing 20 could buckle under extreme expansion or pull apart under extreme contraction, which could occur when completing the well with fluid, cement, and other fluids. Any suitable expansion joint known in the art can be used, such as that disclosed in Application no. 63/178,450, filed by the applicant on April 22, 2021 and incorporated in its entirety herein.

Thermal Spalling

[0201 ] The drill string 10 can deliver fluid from surface to the drill bit of the BHA 12 at a large temperature differential from the surrounding formation. Such temperature differential creates extreme thermal stress on the rock face bring drilled. Because the working fluid P exiting the drill bit can be hundreds of degrees colder than the surrounding rock in a hot drilling environment, the thermal impact of the cold working fluid P on the hot rock will be extreme, causing the rock to spall/micro-spall and stress fracture. Such spalling and stress fracturing of the rock being drilled may improve drilling performance by over 20% as the bit can operate more efficiently by improving rate of penetration (ROP) and reducing dog leg severity (DLS). Such improvements to drilling performance in turn reduces drill rig time, improving economics of the operation. Open Hole Plug & Perf in Hard Rock Formation

[0202] With reference to Figs. 20A-20I, in some situations, the geothermal formation being drilled may comprise hot dry rock (HDR), including hard rock such as granite with negligible or no porosity or permeability. The ability to propagate fluid through such formations, such as between geothermal injector and producer wells, is extremely limited.

[0203] In instances wherein the entirety of the wellbore could be drilled in hard rock such as granite, where no natural fractures exist and no fractures are created during the drilling process, it is possible that the wellbore could be treated as an isolated wellbore where no hydro-shearing fissures can be placed due to the extreme forces that must be overcome in the rock to begin the hydro-shearing process. Such wellbores present an opportunity for open hole “plug and perf” operations, which can provide savings in casing and completion costs. Open hole completions may also be performed with an open hole isolation tool on a tubing string by setting the isolation tool in the open wellbore to isolate a section thereof, and stimulating the isolated section with or without pre-perforating the wellbore. An example of such a borehole is depicted in Fig. 20A.

[0204] With reference to Fig. 20B, a standard “plug and perf” completions assembly 120 is run-in-hole (RIH) into a hard rock wellbore. The assembly includes select fire perforating guns 122 modified for high temperature wells, such as “flasks” or another form of high temperature protection for environments over 150°C, and a bridge plug 124 configured at least for a single set and capable of operating in high temperatures. The bridge plug 124 can be dissolvable or millable to clear the wellbore after use. The perforating gun 122 and bridge plug 124 can be triggered wirelessly, such as with fluid pulses, as use of wireline may be impractical given the high downhole temperatures and the need to pump down wireline tools.

[0205] Referring still to Fig. 20B, the assembly 120 is run to the bottom of the well and the bridge plug 124 is set at a target stage of the wellbore. With reference to Fig. 20C, the perforation guns 122 are fired to create perforations at the target stage, and the assembly 120 is pulled out of hole (POOH).

[0206] With reference to Fig. 20D, hydro-shearing (HS) fluid is pumped downhole to propagate fissures from the perforations created by the perforation gun 122. As mentioned above, such operations in sedimentary rock, as opposed to hard rock, would be impossible, as the bridge plug 124 would not sufficiently hold fluid pressure in sedimentary rock, and the HS fluid itself would not reach the perforations as it is very likely the HS fluid would initiate many HS entry points along the wellbore uphole of the perforations. In hard rock, the HS fluid can only exit the perforations created by the perforation gun 122.

[0207] As shown in Fig. 20E, such perforation and hydro-shearing can be repeated to created the desired number of hydro-shearing stages. After the plug and perf hydro-shearing process is complete for the entire well, the bridge plugs can be drilled out, if not dissolved already, and fluid can be introduced into the wellbore to initiate geothermal power generation operations.

[0208] With reference to Figs. 20G-20I, a completion sequence is depicted where an open-hole hard rock formation, for example a granite formation, is preperforated for the purpose of permitting HS into the hard rock and then completed with a liner by. With reference to Fig. 20G, the entire horizontal formation is first preperforated at the desired stages. Turning to Fig. 20H, a wellbore liner/casing 130 is then run into the wellbore. In embodiments, the wellbore liner 130 can have open hole packers 132 spaced therealong and the open hole packers 132 can be set in the wellbore to isolate the HS stages. Alternatively, cement such as flexible cement that allows the liner 130 to thermally expand and contract can be introduced into the wellbore annulus between the liner 130 and wellbore. A plug & perf operation using conventional well completions procedure/equipment can then be performed on the liner 130, such as perforating the liner 130 at a selected stage, setting a bridge plug 124 in the liner 130 therebelow, and circulating fluid into the liner 130 to HS the selected stage. In embodiments, the liner 130 can further comprise release/expansion joints 90 for accommodating expansion and contraction of the liner due to thermal variation. In embodiments, the expansion joints 90 comprise axially shifting sleeves 92 configured to be engaged by the bridge plugs 124 and actuated with fluid pressure in the liner to shift the sleeves downhole to permit axial expansion/contraction of the liner. In such embodiments, the bridge plugs 124 serve to both isolate the selected stage and also actuate the expansion joints 90.

[0209] In embodiments, the liner 130 can further comprise shifting sleeve assemblies 80 for controlling fluid flow from the bore of the liner 130 into the wellbore to avoid the need to perforate the liner 130 prior to isolation and HS of the selected stage(s). In embodiments, the sleeve assemblies 80 are provided along the liner 130 with no expansion joints 90. In other embodiments, the sleeve assemblies 80 and expansion joints 90 are combined in a single sub and can be actuated concurrently i.e. the shifting of a sleeve assembly 80 to the open position also activates the corresponding expansion joint 90 for accommodate axial expansion/contraction. In still other embodiments, both the sleeve assemblies 80 and expansion joints 90 can be provided along the liner on separate subs and can be actuated independently. Actuation of the sleeve assemblies 80 and expansion joints 90 can be accomplished via ball drop, a downhole shifting tool conveyed on coiled tubing or wireline, or by any other means known in the art.

Claims

WHAT IS CLAIMED IS:

1 . A system for drilling a subterranean wellbore, comprising: an outer tubing string having a first bore; an inner tubing string having an inner bore, the inner tubing string located within the first bore of the outer tubing string and defining a tubing annulus therebetween; a working fluid located within the inner bore; a control fluid located within the tubing annulus; and a bottom hole assembly (BHA) for drilling the wellbore connected to a downhole end of the inner tubing string; wherein the BHA is in communication with the inner bore for receiving the working fluid to power and cool the BHA and is configured to discharge the working fluid into the wellbore for return to surface via a wellbore annulus defined between the outer tubing string and the wellbore.

2. The system of claim 1 , wherein the outer tubing defines one or more discharge ports for permitting the control fluid to flow from the tubing annulus to the wellbore annulus.

3. The system of claim 1 , wherein at least a portion of the outer tubing string corresponding axially to the location of electronic components of the BHA is made of a non-magnetic material.

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4. The system of claim 1 , wherein an uphole portion of the outer tubing string comprises upper tubing string sections having a greater thickness than that of outer tubing string sections downhole thereof.

5. The system of claim 1 , further comprising one or more layers of insulating material applied to at least one of the inner tubing string and the outer tubing string.

6. The system of claim 1 , wherein the inner tubing string comprises a plurality of mechanically connected inner tubing segments and is independently axially moveable relative to the outer tubing string.

7. The system of claim 1 , wherein the inner tubing string comprises an electrical conductor extending therealong for electrically connecting equipment at surface with the BHA.

8. The system of claim 7, wherein the electrical conductor is located along an outer wall of the inner tubing string.

9. The system of claim 1 , further comprising one or more diverter ports defined in the inner tubing string for permitting working fluid to flow from the inner bore to the tubing annulus.

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10. The system of claim 1 , wherein the BHA comprises an inner BHA flow conduit in communication with the inner bore, and a BHA annulus defined between the inner BHA flow conduit and an outer BHA housing, wherein the inner BHA flow conduit comprises one or more BHA ports for permitting the working fluid to flow between the inner BHA flow conduit and the BHA annulus.

11. The system of claim 1 , wherein a plurality of sliding sleeve assemblies are installed and spaced along the outer tubing string, the plurality of sliding sleeve assemblies having at least one sleeve flow port for permitting communication between the first bore and the wellbore annulus, and a sleeve actuable between a closed position for blocking fluid flow through the at least one sleeve flow port, and an open position for permitting fluid flow through the at least one sleeve flow port.

12. The system of claim 1 , further comprising a plurality of expansion joints located along the outer tubing string.

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13. A method for drilling a subterranean wellbore, comprising: locating an inner tubing string within a first bore of an outer tubing string, the inner tubing string defining an inner bore and a tubing annulus being defined between the inner tubing string and outer tubing string; delivering a working fluid downhole through the inner tubing string to a bottom hole assembly (BHA) located at a downhole end of the inner tubing string; delivering a control fluid downhole through the tubing annulus toward the

BHA; and returning the working fluid and control fluid to surface via a wellbore annulus defined between the outer tubing string and the wellbore.

14. The method of claim 13, further comprising cooling the working fluid and control fluid at surface.

15. The method of claim 14, wherein the working fluid and control fluid are cooled to different temperatures.

16. The method of claim 13, further comprising directing the control fluid from the tubing annulus into the wellbore annulus at one or more locations.

17. The method of claim 13, further comprising directing working fluid from an inner BHA flow conduit of the BHA in communication with the inner bore to a BHA annulus defined between the inner BHA flow conduit and BHA housing.

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18. The method of claim 17, further comprising directing working fluid from the BHA annulus back into the inner BHA flow conduit.

19. The method of claim 13, further comprising retrieving the inner tubing string to surface and leaving the outer tubing string in the wellbore.

20. The method of claim 13, further comprising actuating one or more of a plurality of sleeve assemblies spaced along the outer tubing string from a closed position to an open position for permitting fluid communication between the first bore and the wellbore annulus.

21 . The method of claim 13, further comprising: actuating a plurality of packers spaced along the outer tubing string for isolating one or more stages of the wellbore; actuating one or more sleeve assemblies spaced along the outer tubing string for exposing one or more sleeve flow ports of the sleeve assemblies corresponding to one or more selected stages of the one or more stages; blocking fluid flow in the first bore below the sleeve flow ports; and increasing fluid pressure in the first bore to induce hydro-shearing in a geological formation adjacent the wellbore.

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22. The method of claim 13, further comprising stopping drilling and periodically delivering at least one of a pill of working fluid to the inner bore and a pill of control fluid to the tubing annulus.

23. The method of claim 13, further comprising delivering a supercooled coolant into at least one of the inner bore and the tubing annulus.

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