Systems, processes, and modeling methods for drilling in hot dry rock using supercritical or dense phase carbon dioxide

Abstract

Systems and processes for dry hot rock drilling operations using sCO.sub.2 expanded across one or more downhole J-T valves or chokes to cool MWD components. Methods of modeling same.

Claims

1. A system for well trajectory control in dry hot rock (DHR) wells to connect injector and producer fractures comprising: (a) a cased portion of a well configured to accept a drillstring, the drillstring comprising a surface inlet; (b) a closed-loop CO.sub.2 recycle system comprising (i) a well returns conduit, (ii) a CO.sub.2 compressor, (iii) a supercritical CO.sub.2 pump, the CO.sub.2 compressor configured to produce supercritical CO.sub.2 (sCO.sub.2) and deliver it via the supercritical CO.sub.2 pump and a supply conduit to the surface inlet at a rate ranging from about 20 to about 25 kg/s (about 300 to about 400 gpm) at a pressure ranging from about 5,000 to about 7,500 psi, and the CO.sub.2 compressor configured to accept a return CO.sub.2 gas composition at a return pressure of at most 500 psi; (iv) one or more pressure control devices to manage pressure of the closed-loop CO.sub.2 recycle system; (v) one or more gas/solid separators receiving well returns through the well returns conduit, the one or more gas/solid separators configured to remove a major portion of drill cuttings and solids fines from the well returns and produce the return CO.sub.2 gas composition; (c) the drillstring comprising at least one measurement-while-drilling (MWD) component protected from malfunctioning by a cooling device, the cooling device configured to accept sCO.sub.2 and expel non-critical CO.sub.2 adjacent or nearly adjacent the at least one MWD component, thereby cooling the at least one MWD component by Joule-Thomson effect cooling.

2. The system of claim 1 wherein the one or more pressure control devices comprises one or more chokes.

3. The system of claim 1 wherein the one or more gas/solid separators is selected from one or more cyclones, one or more filters, and combinations of these.

4. The system of claim 1 wherein the cooling device is selected from a pressure letdown valve, a choke, and a Joule-Thomson valve.

5. The system of claim 1 wherein the at least one MWD component is selected from one or more temperature measurement devices, one or more pressure measurement devices, one or more density measurement devices, one or more mass flow measurement devices, one or more volume flow measurement devices, one or more radiation measurement devices, one or more gyroscopes, one or more magnetometers, one or more accelerometers, and combinations of two or more of these.

6. The system of claim 1 wherein the at least one MWD component is selected from one or more gyroscopes, one or more magnetometers, one or more accelerometers, and combinations of two or more of these.

7. A process for well trajectory control in DHR wells to connect injector and producer fractures, comprising: (a) inserting a drillstring comprising at least one measurement-while-drilling (MWD) component into a cased portion of a well, the drillstring comprising a surface inlet, the drillstring and cased portion of the well defining a first portion of an annulus; (b) drilling a borehole with the drillstring while trajectory controlling a drill bit attached to a distal end of the drillstring using at least one of the MWD components, the drillstring and borehole wall defining a second portion of the annulus; (c) pumping supercritical CO.sub.2 (sCO.sub.2) into the surface inlet at a rate ranging from about 20 to about 25 kg/s (about 300 to about 400 gpm) at a pressure ranging from about 5,000 to about 7,500 psi; (d) routing at least some of the sCO2 through a cooling device positioned adjacent or sufficiently adjacent the at least one MWD component, cooling the at least one MWD component by Joule-Thomson effect cooling, thereby protecting the at least one MWD component from malfunctioning, the cooling device expelling non-critical CO.sub.2 into the second portion of the annulus; (d) routing well returns comprising the non-critical CO.sub.2 through the first and second portions of the annulus to a well returns conduit; (e) routing the wells returns to a CO.sub.2 compressor of a closed-loop CO.sub.2 recycle system, producing the sCO.sub.2, the CO.sub.2 compressor accepting a return CO.sub.2 gas composition at a return pressure of at most 500 psi; (f) routing the sCO.sub.2 to a supercritical CO.sub.2 pump, the supercritical CO.sub.2 pump delivering the sCO.sub.2 to the surface inlet; (g) controlling pressure in the first and second portions of the annulus and in the closed-loop CO.sub.2 recycle system using one or more pressure control devices; (h) removing a major portion of drill cuttings and solids fines from the well returns using one or more gas/solid separators receiving the well returns through the well returns conduit, the one or more gas/solid separators producing the return CO.sub.2 gas composition.

8. The process of claim 7 wherein the controlling of the pressure in the first and second portions of the annulus and in the closed-loop CO.sub.2 recycle system comprises operating one or more chokes.

9. The process of claim 7 wherein the removing of the major portion of the drill cuttings and solids fines from the well returns comprises routing the well returns to one or more cyclones, one or more filters, and combinations of these.

10. The process of claim 7 wherein the cooling of the at least one MWD component by Joule-Thomson effect cooling comprises routing the sCO.sub.2 through a pressure letdown valve, a choke, or a Joule-Thomson valve.

11. The process of claim 7 wherein the at least one MWD component is selected from one or more temperature measurement devices, one or more pressure measurement devices, one or more density measurement devices, one or more mass flow measurement devices, one or more volume flow measurement devices, one or more radiation measurement devices, one or more gyroscopes, one or more magnetometers, one or more accelerometers, and combinations of two or more of these.

12. The process of claim 7 wherein the at least one MWD component is selected from one or more gyroscopes, one or more magnetometers, one or more accelerometers, and combinations of two or more of these.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) The manner in which the objectives of this disclosure and other desirable characteristics can be obtained is explained in the following description and attached drawings in which:

(2) FIG. 1 is a schematic pressure vs. temperature diagram for carbon dioxide;

(3) FIG. 2 is a schematic pressure vs. enthalpy diagram for carbon dioxide;

(4) FIG. 3 is a schematic screenshot of a sCO.sub.2 circulation thermal analysis tool Input Panel;

(5) FIG. 4 is a schematic screenshot of a sCO.sub.2 thermal-hydraulic model;

(6) FIG. 5 is a graph of standpipe pressure and temperature at MWD vs. mass flow rate of sCO.sub.2 for one embodiment using a 12 mm choke diameter;

(7) FIGS. 6A and 6B are schematic screenshot and graphs, respectively, presenting data of the embodiment of FIG. 5;

(8) FIG. 7 is a graph of annular velocity vs. mass flow rate for three different choke diameters;

(9) FIG. 8 graphically compares water and sCO.sub.2 standpipe pressure and temperature at MWD vs. mass flow rate for one embodiment using a 12 mm choke diameter; and

(10) FIG. 9 is a schematic illustration of a closed-loop CO.sub.2 recycle system in accordance with one embodiment of the present disclosure.

(11) It is to be noted, however, that the appended drawings are not to scale, and illustrate only typical system embodiments of this disclosure. Furthermore, FIG. 9 schematically illustrates only one of many possible closed-loop recycle systems and processes of this disclosure. Therefore, the drawing figures are not to be considered limiting in scope, for the disclosure may admit to other equally effective embodiments. Identical reference numerals are used throughout the several views for like or similar elements.

DETAILED DESCRIPTION

(12) In the following description, numerous details are set forth to provide an understanding of the disclosed apparatus, combinations, and processes. However, it will be understood by those skilled in the art that the apparatus, systems, and processes disclosed herein may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. All technical articles, published and non-published patent applications, standards, patents, statutes and regulations referenced herein are hereby explicitly incorporated herein by reference, irrespective of the page, paragraph, or section in which they are referenced. Where a range of values describes a parameter, all sub-ranges, point values and endpoints within that range or defining a range are explicitly disclosed herein. All percentages herein are by weight unless otherwise noted. In the event definitions of terms in the referenced patents and applications conflict with how those terms are defined in the present application, the definitions for those terms that are provided in the present application shall be deemed controlling. Where a range of values describes a parameter, all sub-ranges, point values and endpoints within that range are explicitly disclosed herein. This document follows the well-established principle that the words a and an mean one or more unless we evince a clear intent to limit a or an to one. For example, when we state flowing sCO.sub.2 into a surface inlet of a drillstring positioned inside a casing of a well, we mean that the specification supports a legal construction of a drillstring that encompasses structure distributed among multiple physical structures, and a legal construction of a well that encompasses structure distributed among multiple physical structures.

(13) As mentioned herein, Extraction of heat from Dry Hot Rock (DHR) presents several efficiency and power advantages over other EGS or CLGS approaches for geothermal energy recovery. To efficiently extract DHR heat, horizontal wells are drilled within the resource. However, DHR temperatures (>350? C.) are too high for the use of MWD or directional tools. At current state-of-the-art, MWD and directional tools are limited to about 150? C. (limiting the maximum resource temperature to ?200? C.). This restricts DHR drilling to vertical or uncontrolled deviated wells, with single shot surveys to guide directional control. In DHR wells where well trajectory control is critical to connect injector and producer fractures, this can pose a significant problem. As may be seen, current practices may not be adequate for all circumstances, and do not address problems with respect to MWD components and methods when drilling in DHR. There remains a need for more robust DHR drilling systems and processes. The systems and processes of the present disclosure are directed to these needs.

(14) Supercritical CO.sub.2

(15) Supercritical CO.sub.2 (sCO.sub.2) or dense phase CO.sub.2 offers the potential for management of MWD temperature. As illustrated in FIGS. 1 and 2, carbon dioxide becomes supercritical above 31? C. and 74 bar (1,073 psi). This property results in some advantages: CO.sub.2 is a familiar fluid with extensive industrial uses; positive Joule-Thomson coefficient and phase change allows for reduction of temperature with drop in pressure; low viscosity, reducing pump pressure required; high density, allowing the use of mud-pulse telemetry; supercritical in drillpipe upstream of MWD for telemetry; gaseous in annulus, further reduction in heat transfer.

(16) Challenges of working with CO.sub.2 include it's low specific heat, handling and processing in a closed loop system, and other operational considerations.

(17) As described in more detail herein with reference to the various drawing figures, systems and processes of the present disclosure address problems identified by the inventors herein, namely the unknown feasibility and effectiveness of using sCO.sub.2 in dry hot rock drilling to achieve lower temperatures for MWD operability. The inventors herein investigated use of downhole drillpipe choke(s) to create a pressure drop across MWD or directional tools to cool down drilling fluid below 150? C. In certain embodiments conditions in the annulus are managed to create gaseous phase CO.sub.2 in the annulus. In certain embodiments the surface annulus return temperature is maintained below 100? C. (for ease of handling and RCD and/or NRCD operability). In certain embodiments, the temperature across the MWD components being less than 150? C. and the temperature in the annulus at the surface being less than 100? C. are achieved within constraints of pump pressure and required flow rate to transport cuttings to surface.

(18) Modeling Methods

(19) The inventors herein have developed a custom Microsoft? Excel?-based program to model the problem.

(20) Model Method Inputs

(21) Transient Pressure-Enthalpy formulation; Built-in REFPROP (from NIST) module to obtain thermodynamic properties of fluids and their mixtures.

(22) In certain embodiments the modeling methods may comprise inputting (as shown in the screenshot of a thermal analysis input panel in FIG. 3): Drilling Fluid type; Mass Flow Rate (kg/s); Annulus Return Pressure (psi); Inlet Temperature) (? ? C.); Hole Length (m); Chokes: Depth (m) and diameter (mm); MWD Depth (m); Bit nozzles number and diameter ( 1/32 in.); Drill pipe, casing and hole data; Formation properties.

(23) Additionally, the models can handle both CO.sub.2 and water, and can be extended to include facilities.

(24) Modeling Method Outputs

(25) Outputs of plots for temperature, pressure, and specific enthalpy along depth; State diagram (pressure-enthalpy) showing state path of fluid in drill pipe and annulus; Temperatures at MWD, drill bit and surface returns; Pressures at standpipe, MWD and drill bit (surface back pressure is given, and a parameter of the problem); Annular velocity of fluid in annulus.

(26) In certain embodiments, such as illustrated schematically in the screenshot presented in FIG. 4, the modeling method outputs may include: Return Annulus Surface Temperature (? C.); Temperature at MWD location (? C.); Fluid Temperature above bit (? C.); Pump/Standpipe Pressure (psi); Fluid Pressure above bit (psi); Minimum Annular Velocity (m/s); Density at MWD (kg/m.sup.3); Plus various graphical displays of pressure and temperature profiles, state curve in p-H diagram, profiles of other properties (density, specific heat, and the like).
Example Well Case Study Well Geometry: Vertical well with TD of 10,000 ft Linear undisturbed geothermal temperature profile with temperature of 400? C. at well total depth 9,000 ft of 9? in. casing 1,000 ft of 8? in. hole 5 in. drill pipe (ID: 4.260 in.) MWD location is assumed at 2,850 m (9,350 ft) A bit has been included in the BHA and has a TFA of 0.589 in.sup.2 Operational Design Factors: sCO2 injection parameters: pressure is calculated, temperature is input (sensitivity parameter) Back pressure, number, location and diameters of chokes are inputs (sensitivity parameters) Target Temperature at MWD is 150? C. Target density at MWD>0.7 SG Return Annulus Temperature must be <100? C.

(27) Operationally, 5,000 psi pump pressure rating is typical for land rigs. Offshore rigs are typically equipped with 7,500 psi pump rating. To operate above 7,500 psi pump pressure range, certain embodiments may include specialized equipment, such as high pressure pumps, coiled tubing rigs, and combinations thereof. Standpipe pressure (SPP) above 15,000 psi is considered extreme. For this case study, we notionally target between 5,000 psi and 7,500 psi standpipe pressure.

(28) Another operational consideration for this example was annular velocity, which is responsible for cuttings transport in non-viscosified circulating media. Empirical rules of thumb for vertical wells are as follows: Clear liquids: 180 ft/min (55 m/min or 0.92 m/s); Annular mist: 1500 ft/min (460 m/min or 7.62 m/s); Dry gas: 3000 ft/min (920 m/min or 15.24 m/s).

(29) We surmised that CO.sub.2 in the annulus likely will change phase during its return flow, going from dense phase to gaseous phase, therefore, minimum annular velocity required may be a function of depth. Hole cleaning requirements have not yet been established for such fluids. For this Example Well Case Study, we assumed an annular velocity of about 1-3 m/s in dense phase, and >7 m/s in the high-pressure gaseous phase. These assumptions were arbitrary, and further work is required to quantify them, especially for deviated and horizontal wells. Table 1 provides addition data for this Example. Cases Reported: 42; annulus return pressure for all cases: 500 psi

(30) TABLE-US-00001 TABLE 1 Flow Rate, Choke Diameter, and Inlet Temperature Entity Minimum Base Maximum Flow rate, kg/s 5 20 60 (gpm) (80) (318) (955) Choke diameter, 6 10 12 mm Inlet temperature, 50 75 100 ? C.

(31) FIG. 5 is a graph of standpipe pressure and temperature at MWD vs. mass flow rate of sCO.sub.2 for one embodiment using a 12 mm choke diameter. Within the range of 19 kg/s to 25 kg/s, there is a distinct operating window. Further embodiments may have different choke location, different choke diameter, no choke options, and reduced annulus return pressure at wellhead. FIGS. 6A and 6B are schematic screenshot and graphs, respectively, presenting data of the embodiment using 12 mm diameter choke. Note from FIG. 6B, supercritical conditions existed in the drillpipe and a portion of the annulus. FIG. 7 is a graph of annular velocity vs. mass flow rate for the three different choke diameters of this Example, illustrating that minimum annular velocity was in the range of 1-2 m/s, occurring deep in the well in dense phase region. FIG. 8 graphically compares water and CO.sub.2 standpipe pressure and temperature at MWD vs. mass flow rate for one embodiment using a 12 mm choke diameter, illustrating that for the same flow rates, drilling with water results in much higher temperatures at the MWD: for sCO2: 150? C. to 50? C.; for water: 260? C. to 250? C.

(32) In certain embodiments it may be possible to eliminate downhole chokes by managing phase change location downhole. This may be modeled. Other embodiments may comprise hole cleaning using sCO.sub.2, and modeling same. Further numerical and experimental work to establish annular velocities for adequate hole cleaning using sCO.sub.2 are contemplated.

(33) FIG. 9 is a schematic illustration of a closed-loop CO.sub.2 recycle system in accordance with one embodiment 100 of the present disclosure. In this embodiment, inlet side with CO.sub.2 compressor and sCO.sub.2 pump 2 (both are commercially available) may produce the following: Inlet rate of sCO2 in conduit 4 flowing through rotating control device (RCD) 6, 20-25 kg/s (300-400 gpm); Pressure 5,000-7,500 psi.

(34) The return pressure of gaseous CO.sub.2 from the annulus 20 of well 18 at RCD 6 and return conduit 8 is expected to be 500 psi or lower, gaseous CO.sub.2.

(35) Closed loop system to recycle CO.sub.2 embodiment 100 may comprise: a choke 10 in return conduit 8 to manage system pressure; one or more cyclone separators 12 and filters 14 to remove drill solids (cuttings 16); optionally one or more CO.sub.2 dehydrators (not illustrated) if water influx.

(36) Other embodiments than that presented schematically in FIG. 9 are contemplated and considered within the present disclosure.

(37) Control devices may comprise a combination of: one or more pressure control devices, also referred to as chokes; one or more temperature control devices; one or more sCO.sub.2 pumping devices; one or more flow measurement devices (also referred to herein as mass flow meters or mass flow sensors); and in certain embodiments one or more accessory equipment such as one or more connectors, one or more isolation valves, one or more pressure relief devices, among others. The specific configuration of the well, drillstring, and closed-loop recycle system define the capabilities of each system and process embodiment. Redundancy of components may allow for extended service periods and mitigates risk of downtime due to component failure. An example would be a pressure control device (choke) plugging with drilled cuttings, or washout due to erosion. In this case, isolating the failed component and enabling another one allows for continued operations, and enables evaluation and/or modification of the operational parameters to minimize the risk of failure of the new component in use.

(38) Furthermore, certain systems and processes of the present disclosure may be designed to be installed in such a way that components may be retrieved from subsea to the surface, by using remotely operated vehicle (ROV) friendly quick connectors (or other means). These embodiments allow servicing components subject to potential failure during operations or in between hole sections, without the need to pull the riser to service components. These embodiments are particularly practical for servicing pressure control devices (or chokes), which may be subject to plugging or washouts.

(39) Systems and processes of the present disclosure may be operated using hydraulic and/or electric power. One possible configuration is full electric power to operate the CO.sub.2 compressor and sCO.sub.2 pump; other embodiments may employ hydraulic power to operate these units. In certain embodiments, both electric and hydraulic power supply may have redundant and/or back up power supply. In certain embodiments, hydraulic power may require installation of an additional hydraulic unit on the drilling rig, possibly including storage for pressurized fluid for backup power. In certain embodiments, the drilling unit's electric generators may provide electric power, and backup power may be provided by an uninterruptible power supply (UPS) battery system.

(40) In certain embodiments, the CO.sub.2 compressor, sCO.sub.2 pump, and other components may be stored on the drilling unit/floating vessel on the riser deck, on a dedicated crate fabricated for this purpose.

(41) With respect to data connection/integration, in certain embodiments control signals for the components of the systems of the present disclosure, as well as parameters measured or captured by the system's sensors (e.g., pressures, temperatures, fluid flow rates and density, position indicators, etc.) may be transmitted to and from the drilling unit/floating vessel from and to the closed-loop CO.sub.2 recycle system, and to chokes or other MWD cooling devices downhole. In certain subsea embodiments, umbilical control lines may provide the means for this data transmission. On the drilling unit/floating vessel, the data may be integrated at different levels, potentially with different control systems. Examples of control systems which can potentially integrate data to and from the systems of the present disclosure include control systems for MPD (installed ad hoc for MPD operations), mud logging, drawworks, top drive, rotary table, pipe handling, and the like. In certain embodiments, data integration may require running cables between different locations on the drilling unit/floating vessel. Industry standards, operator requirements, and/or local laws may dictate cable routing configurations.

(42) Flow control devices are key components of drilling systems and processes. One or more flow control devices enables sealing and pressure containment between the drill pipe and CO.sub.2 systems, while allowing the drill pipe to rotate and reciprocate without losing seal integrity. Flow control devices may be rotating flow control devices (RCD) or non-rotating flow control devices (NRCD), or combination thereof (for example, one RCD and one NRCD positioned in series). Several OEMs manufacture and provide flow control devices to the industry. Any known type of flow control device may be employed in practicing the systems and processes of the present disclosure. Suitable flow control devices and components typically used therewith include those currently commercially available from Weatherford International, Schlumberger, and NOV-AFGlobal.

(43) A well returns conduit directs the wells returns (comprising cuttings, CO.sub.2, and some hydrocarbons, and drilling fluid) back to the surface, or for offshore embodiments, ultimately to the drilling unit on surface floating vessel or other service vessel for processing and recirculation.

(44) One or more operational pressure control devices may enable accurate control of the pressure profile in the well, by manipulating restriction to the flow returns from the well. As pressure control devices may be prone to plugging or washing out under certain operational conditions, redundancy can provide means to continue operations should this deviation occur, or to maintain pressure control while addressing the causes, if possible. Adequate number and sizing of the pressure control device(s) may enable accurate pressure control for ample ranges of flow rates, by using more than one valve (and/or a larger size valve) for high flow conditions. Pressure control devices may be designed for remote operation from the drilling unit. Some examples are manual pressure control, semi-automated pressure control (i.e., pressure set point control at the valve location), or fully automated downhole pressure control, which typically involves a hydraulic model calculating in real time the required choke pressure set point for the desired downhole conditions.

(45) A dedicated contingency pressure control device may be used to quickly react to sudden increases in pressure, potentially due to one or more operational pressure control devices plugging with drilled cuttings, or other reasons. This contingency pressure control device may be controlled by an automated system to open and regulate a maximum pressure set point providing time to enable additional flow paths to bypass the blocked component, if available, or to stop operations to correct the deviation.

(46) A mass flow meter may enable monitoring the pressure on the returns side, and may provide early kick and loss detection by comparison of fluid flow and density out of the well against fluid flow and density being pumped into the well.

(47) During operation, one or all of T, P, mass flow rate, gas or vapor concentrations (or percentages of set point values) inside and/or outside the drillstring and in the annulus may be displayed locally on Human Machine Interface (HMI), such as a laptop computer having display screen having a graphical user interface (GUI), or handheld device, or similar. In certain embodiments the HMI may record and/or transmit the data via wired or wireless communication to another HMI, such as a laptop, desktop, or hand-held computer or display. These communication links may be wired or wireless.

(48) One or more control strategies may be employed. A pressure process control scheme may be employed, for example in conjunction with the pressure control devices and mass flow controllers. A master controller may be employed, but the disclosure is not so limited, as any combination of controllers could be used. Programmable logic controllers (PLCs) may be used.

(49) Control strategies may be selected from proportional-integral (PI), proportional-integral-derivative (PID) (including any known or reasonably foreseeable variations of these), and may compute a residual equal to a difference between a measured value and a set point to produce an output to one or more control elements. The controller may compute the residual continuously or non-continuously. Other possible implementations of the disclosure are those wherein the controller comprises more specialized control strategies, such as strategies selected from feed forward, cascade control, internal feedback loops, model predictive control, neural networks, and Kalman filtering techniques.

(50) Closed loop recycle systems and other components described herein may be built to meet ISO standards, Det Norske Veritas (DNV) standards, American Bureau of Standards (ABS) standards, American Petroleum Institute (API) standards, and/or other standards.

(51) The electrical connections, if used (voltage and amperage) will be appropriate for the zone rating desired of the system. In certain embodiments one or more electrical cables may be run and connected to an identified power supply at the work site to operate the HMI, CO.sub.2 recycle system, and other components. Certain embodiments may employ a dedicated power supply. The identified or dedicated power supply may be controlled by one or more logic devices so that it may be shut down. In exemplary embodiments, systems of the present disclosure may have an electrical isolation (lockout) device on a secure cabinet.

(52) In certain embodiments, internal algorithms in the logic device, such as a PLC, may calculate a rate of increase or decrease in pressure inside the drillpipe and/or annulus, and/or in the CO.sub.2 recycle system. This may then be displayed or audioed in a series of ways such as percentage to shutdown lights or sounds, and the like on one or more GUIs. In certain embodiments, an additional function within a HMI may be to audibly alarm when the calculated pressure rate of increase or decrease reaches a level set by the operator. In certain embodiments this alarm may be sounded at the well site, as well as remote from the well site, for example in a shipboard control room, or remote control room.

(53) What has not been recognized or realized are systems and processes for well trajectory control in DHR wells to connect injector and producer fractures that are robust and safe. What also has not been recognized or realized are methods of modeling use of sCO.sub.2 in drilling a well in dry hot rock using a drillstring having a drill bit and one or more MWD components. Systems and processes to accomplish this without significant risk to workers is highly desirable. As explained previously, systems and processes have been proposed by others to deal with the problem of protecting MWD components while drilling in hot dry rock formations (vacuum insulated piping; more robust MWD components), but they are not necessarily economical or even available. The present inventors, however, personally know of the inefficiencies of such practices.

(54) Thus the systems, processes, and modeling methods described herein afford ways to perform hot dry rock drilling efficiently, safely and economically, and with significantly reduced risk of injury and discomfort to rig workers.

(55) From the foregoing detailed description of specific embodiments, it should be apparent that patentable systems, processes, and modeling methods have been described. Although specific embodiments of the disclosure have been described herein in some detail, this has been done solely for the purposes of describing various features and aspects of the systems and processes, and is not intended to be limiting with respect to their scope. It is contemplated that various substitutions, alterations, and/or modifications, including but not limited to those implementation variations which may have been suggested herein, may be made to the described embodiments without departing from the scope of the appended claims. For example, some systems of this disclosure may be devoid of certain components and/or features: for example, systems devoid of cyclone separators, or devoid of filters; systems devoid of low-strength steels; systems devoid of threaded fittings; systems devoid of welded fittings; systems devoid of casing.