Patent Grant
12000283
The subject matter described herein relates to drilling in sub-surface geologic formations including conventional drilling and other techniques such as millimeter wave drilling, thermal drilling, and the like.
Conventional drilling, such as rotary drilling, can be used to form well boreholes so that natural resources, such as oil and gas, can be accessed within sub-surface geologic formations. Conventional drilling can be limited to accessing formations at shallow sub-surface depths and can be less effective at penetrating deeper geologic formations, which can include harder, less permeable rock. Formations of dense rock at deeper depths, often under higher temperature and pressure than rock present at shallow depths, can be accessed more efficiently utilizing non-conventional drilling techniques such as thermal drilling and/or millimeter wave drilling.
In one aspect, methods for monitoring and controlling the downhole pressure of a well are provided. In one embodiment, a method can include monitoring a downhole pressure of a well during formation of a borehole of the well using a millimeter wave drilling apparatus including a waveguide configured for insertion into the borehole. The monitoring can include determining the downhole pressure. The downhole pressure can include an amount of pressure present at a bottom of the well. The method can also include determining a lithostatic pressure of rock surrounding the well at the bottom of the well. The method can further include controlling the downhole pressure relative to the lithostatic pressure of the rock surrounding the well at the bottom of the well.
In another embodiment, monitoring the downhole pressure of the well can also include measuring a pressure of a fluid provided into and/or extracted from the borehole. Monitoring the downhole pressure of the well can further include determining the downhole pressure of the well using one or more of the pressure of the fluid provided into the borehole, the pressure of the fluid extracted from the borehole, a downhole pressure determined when forming a portion of the well using a mechanical drilling apparatus including a drill bit, a measure of energy input supplied to the millimeter wave drilling apparatus, and/or a depth of the bottom of the well. In another embodiment, determining the downhole pressure of the well can also include using at least a physical model associated with one or more of the downhole pressure determined when forming a portion of the well using the mechanical drilling apparatus including a drill bit, the measure of energy input supplied to the millimeter wave drilling apparatus, and the depth of the bottom of the well.
In another embodiment, the lithostatic pressure of rock surrounding the well at the bottom of the well can be determined using historical geologic survey data and/or a model of geophysical data associated with the well. In another embodiment, controlling the downhole pressure can be performed using a rotating pressure control head.
In another embodiment, controlling the downhole pressure can further include controlling one or more of an operation of a gas compressor located at a surface of the well and configured to supply a gas into the borehole of the well, an input valve position of the gas compressor, an output valve position of the gas compressor, and/or a flow rate of the gas supplied by the gas compressor. In another embodiment, the flow rate of the gas is between 0.5 m/s and 50 m/s.
In another aspect, a system for monitoring and controlling the downhole pressure of a well is provided. In one embodiment, the system can include at least one data processor and a memory storing computer-readable instructions, which when executed by the at least one data processor causes the at least one data processor to perform operations including monitoring a downhole pressure of a well during formation of a borehole of the well. The monitoring can include determining the downhole pressure. The downhole pressure can include an amount of pressure present at a bottom of the well. The operations can also include determining a lithostatic pressure of rock surrounding the well at the bottom of the well. The operations can further include controlling the downhole pressure relative to the lithostatic pressure of the rock surrounding the well at the bottom of the well.
In another embodiment, the operation of determining the downhole pressure of the well can also include using at least a physical model associated with one or more of the downhole pressure determined when forming a portion of the well using a mechanical drilling apparatus including a drill bit, the measure of energy input supplied to the millimeter wave drilling apparatus, and the depth of the bottom of the well.
In another embodiment, the operation of monitoring the downhole pressure of the well can also include measuring a pressure of a fluid provided into and/or extracted from the borehole. The operation of monitoring the downhole pressure of the well can further include determining the downhole pressure of the well using one or more of the pressure of the fluid provided into the borehole, the pressure of the fluid extracted from the borehole, a downhole pressure determined when forming a portion of the well using a mechanical drilling apparatus including a drill bit, a measure of energy input supplied to the millimeter wave drilling apparatus, and/or a depth of the bottom of the well. In another embodiment, the operation of determining the downhole pressure of the well can also include using at least a physical model associated with one or more of the downhole pressure determined when forming a portion of the well using a mechanical drilling apparatus including a drill bit, the measure of energy input supplied to the millimeter wave drilling apparatus, and the depth of the bottom of the well.
In another embodiment, the lithostatic pressure of rock surrounding the well at the bottom of the well can be determined using historical geologic survey data and/or a model of geophysical data associated with the well. In another embodiment, the operation of controlling the downhole pressure can be performed using a rotating pressure control head.
In another embodiment, the operation of controlling the downhole pressure can further include controlling one or more of an operation of a gas compressor located at a surface of the well and configured to supply a gas into the borehole of the well, an input valve position of the gas compressor, an output valve position of the gas compressor, and/or a flow rate of the gas supplied by the gas compressor. In another embodiment, the flow rate of the gas is between 0.5 m/s and 50 m/s.
In another aspect, a system for monitoring and controlling a downhole pressure of a well is provided. In one embodiment, the system can include means for monitoring a downhole pressure of a well during formation of a borehole of the well. The monitoring can include determining the downhole pressure. The downhole pressure can include an amount of pressure present at a bottom of the well. The system can also include means for determining a lithostatic pressure of rock surrounding the well at the bottom of the well. The system can further include means for controlling the downhole pressure relative to the lithostatic pressure of the rock surrounding the well at the bottom of the well. In another embodiment, monitoring the downhole pressure of the well can also include measuring a pressure of a fluid provided into and/or extracted from the borehole. Monitoring the downhole pressure of the well can further include determining the downhole pressure of the well using one or more of the pressure of the fluid provided into the borehole, the pressure of the fluid extracted from the borehole, a downhole pressure determined when forming a portion of the well, a measure of energy input supplied to the means for forming the borehole of the well, and/or a depth of the bottom of the well. In another embodiment, determining the downhole pressure of the well can also include using at least a physical model associated with one or more of the downhole pressure determined when forming a portion of the well using the means for forming the portion of the well, the measure of energy input supplied to the means for forming the borehole of the well, and the depth of the bottom of the well.
In another embodiment, the lithostatic pressure of rock surrounding the well at the bottom of the well can be determined using historical geologic survey data and/or a model of geophysical data associated with the well.
In another embodiment, controlling the downhole pressure can further include a means for one or more of a supply of a gas into the borehole of the well, an input valve position of the gas compressor, an output valve position of the gas compressor, and/or a flow rate of the gas supplied into the borehole of the well. In another embodiment, the flow rate of the gas is between 0.5 m/s and 50 m/s.
These and other features will be more readily understood from the following detailed description taken in conjunction with the accompanying drawings, in which:
It is noted that the drawings are not necessarily to scale. The drawings are intended to depict only typical aspects of the subject matter disclosed herein, and therefore should not be considered as limiting the scope of the disclosure.
Conventional drilling can be used to form boreholes of wells in order to access natural resources, which may be present within sub-surface geologic formations surrounding or close to the borehole. Conventional drilling can include rotary drilling, hammer drilling, and/or a combination of rotary drilling and hammer drilling. Conventional drilling can employ liquids, such as mud or water, and/or gases, such as air or foam, for cleaning and cooling during drilling. Conventional drilling can be employed to form boreholes within soft, porous rock and can include the use of rotating drill bits, such as polycrystalline diamond bits, roller cones, and high-pressure liquid jets. Conventional drilling can utilize rotating drilling apparatuses to cut or grind rock during the formation of the borehole. The cut or ground rock can be removed via a fluid provided into the borehole to lift the cut or ground material from the borehole. Conventional drilling can achieve limited and lower rates of penetration at deeper borehole depths due to increasing temperatures and increasing hardness of the rock present at deeper borehole depths. The ability to transmit power from the surface to the bottom of the borehole can also limit the rate of penetration achieved using conventional drilling in deep boreholes.
Thermal drilling, such as Millimeter Wave Drilling (MMWD) can achieve greater rates of penetration by providing large amounts of radiative energy into the borehole in combination with pressure to melt or vaporize rock. MMWD can be advantageous compared to conventional drilling because the need to physically remove cut, crushed, or ground rock is reduced or eliminated. Instead, rock is vaporized into very small particles or is melted. Higher rates of penetration can be achieved using MMWD compared to conventional drilling because the abundance of applied thermal energy is more effective at penetrating rock compared to rotating mechanical action of conventional drilling. Thus, MMWD can be beneficial forming deeper wells in order to access natural resources or hot dry rock, which can be present at greater depths below the surface.
Deciding when to switch from conventional drilling to thermal drilling, such as millimeter wave drilling, can be difficult to determine and errors in this determination can be costly and hazardous. Accurately identifying when to transition from conventional drilling to millimeter wave drilling can be important for maintaining cost effective rates of penetration during borehole formation. For example, conventional drilling can be used to form a first portion of a borehole down to a depth at which a rate of penetration of a conventional drilling apparatus slows due to the hardness of the rock and/or the presence of high temperatures. Performing conventional drilling at deeper depths can require additional time, personnel, and equipment to monitor and conduct the conventional drilling and can increase the costs and risks associated with forming the borehole at deeper depths compared to non-conventional drilling, such as MMWD.
Accordingly, some implementations of the current subject matter can provide for an approach to determining when to switch from conventional drilling to utilize a millimeter wave drilling apparatus. Because millimeter wave drilling extends the borehole by using thermal heating (e.g., the millimeter waves heat the rock), if the material is permeable, it may allow for liquid (e.g., water) to penetrate through the porous material into the borehole. Additional liquid within the borehole can interfere with the millimeter wave drilling system by cooling down the borehole. In other words, the millimeter waves will vaporize the liquid (e.g., water) rather than borehole rock. This can also increase the risk of a blowout. Accordingly, some implementations of the current subject matter include monitoring or inferring the permeability of the borehole while utilizing the rotational drilling approach and determining to use the millimeter wave apparatus once the permeability of the rock at the bottom of the borehole falls below a permeability threshold value. The monitoring can be direct or indirect, for example, it can be difficult to directly monitor (e.g., measure) permeability in low permeability zones. As a result, in some implementations, permeability can be inferred from other measurements, such as porosity of rock. Porosity can be more readily determined using some existing tools.
In some implementations, temperature and/or hardness of the rock at the bottom of the borehole can be monitored during conventional drilling and the decision to switch to MMWD can be further based on temperature and/or hardness of the rock. By basing the determination to switch to MMWD on permeability, temperature, and/or hardness of rock, rather than the costs associated with the drilling, some implementations of the current subject matter can provide for determining to switch to thermal drilling, such as MMWD, at a point in which the overall operation of the MMWD is improved, and therefore result in an improved approach to drilling.
In some implementations, during millimeter wave drilling, control of the well needs to be maintained to prevent collapse of the well. For example, conventional drilling approaches can use liquids (e.g., mud) to lubricate and to control the downhole pressure, and can utilize metallic casings and cement to support the borehole (e.g., to prevent collapse). The mud weight and filter cake formed around the wellbore walls by the mud can prevent collapse. Metallic casings can be inserted after drilling and can be cemented in place to maintain the stability of the wellbore. But liquids (e.g., mud) may not be transparent to millimeter waves. Installing casings and cementing can be increasingly difficult as the temperature within the borehole increases. Millimeter wave drilling can utilize gases but low pressures can cause the well to collapse. Accordingly, some implementations of the current subject matter include monitoring a downhole pressure of a well during formation of a borehole of the well using a millimeter wave drilling apparatus, determining a lithostatic pressure of rock surrounding the well at the bottom of the well, and controlling the downhole pressure relative to the lithostatic pressure of the rock surrounding the well at the bottom of the well. By controlling the downhole pressure using a managed pressure drilling approach as described herein, the downhole pressure can be controlled relative to the lithostatic pressure of the rock so that well control can be maintained and well collapse can be prevented or inhibited. In addition to controlling pressure to prevent wellbore collapse, pressure can be controlled to reach a lithostatic pressure, or a fracture pressure. Controlling pressure to reach or exceed the lithostatic pressure can enable a balanced or overbalanced condition. And controlling pressure to reach a fracture pressure can allow for pushing melt created by the MMWD process into the formation, instead of flowing the condensed rock particles back to surface.
The managed pressure drilling approach described herein can be advantageous compared to other pressure drilling approaches, which can create an overbalanced pressure condition within a closed volume of the wellbore. The managed pressure drilling approach described herein can be used in an open volume system. An open volume system can be configured to actively circulate fluids and/or gases from the surface, down the wellbore to the cutting front, and back to the surface. Actively circulating the fluids and/or gases can help cool and lubricate drilling components and can transport cuttings to the surface. The direction of the active circulation can be normal or reversed. In normal circulation, the fluid and/or gas is provided into the wellbore through the waveguide and returns through the wellbore annulus. In reverse circulation, the fluid and/or gas is provided into the wellbore via the wellbore annulus and returns from the wellbore through the waveguide. In contrast, a closed volume system forms a flow restriction along the circulation path. For example, a full blockage or partial blockage of the flow can be used to manage the downhole pressure. A closed volume system can be used to perform the managed pressure drilling approach described herein. In a closed volume system, the pressures within a closed loop of the closed volume system can be higher at each point of the circulation path as compared to the open volume system.
An improved system and method for performing hybrid MMWD to form well boreholes is described herein. The hybrid MMWD systems and methods can provide advantages that can be difficult to achieve using conventional drilling or MMWD alone to form an entire borehole. For example, conventional drilling can be performed efficiently in shallow subsurface rock formations between 0 km and 3 km deep where the rock is softer, shallower, and/or has a lower mechanical specific energy. For example, the mechanical specific energy for conventional drilling rock can be about 100 Joules/cm3 of rock, whereas the mechanical specific energy for melting rock can be about 5000 Joules/cm3 of rock. The mechanical specific energy for vaporizing rock can be about or greater than 12,000 Joules/cm3 of rock. At depths greater than 5 km, conditions can favor use of MMWD. Drilling wells deeper than 5 km using conventional drilling approaches can take a longer amount of time than if the wells were drilled using the hybrid MMWD systems and methods described herein.
As rock hardness, permeability, and borehole temperature increase at greater depths, the rate of penetration can slow and the cost of continuing the conventional drilling operation can increase. The mechanical efficiency of conventional drilling at greater depths and in less permeable rock can diminish due to the increased wear on the drill bit, and the increased friction and torque transmission required to penetrate the rock. Rotary drill bits can wear out more quickly in these conditions. The cost and workflow associated with maintaining the borehole can also be increased at depths using conventional drilling. For example, larger, more expensive, shallower borehole casings can be required to accommodate larger sized drill bits necessary to make boreholes at greater depths.
Borehole temperatures can also affect when to switch from conventional drilling to MMWD. For example, depths at which borehole temperatures can exceed 260 degrees C. can be problematic for the electronic components used in conventional drilling. In addition, at depths where these temperature conditions can be present, the lifting and cooling properties of the mud can diminish due to breakdown of the fluid by the high temperatures. Conventional drilling at these depths and temperatures can utilize drill bits rated to 300 degrees C., however this can require operators to circulate mud at high rates in a constant manner.
MMWD, while more efficient at forming boreholes in less permeable and/or hard rock at higher temperatures and greater depth, can be less advantageous when forming an initial portion of a borehole near the surface at least due to the lower mechanical specific energy required for shallower rock formations. For example, MMWD provides large amounts of radiative energy into the borehole to melt or vaporize rock. MMWD systems include millimeter wave producing apparatuses called gyrotrons and utilize waveguides to form and direct the energy into the borehole. Deploying such systems to form an entire borehole to significant depths is not always cost efficient or mechanically efficient to adequately remove certain types of rock present in initial portions of a borehole. For example, in shallow sub-surface formations where an initial portion of a borehole can be formed, the rock can include limestone which is not effectively vaporized or melted using MMWD. The hybrid MMWD system and methods described herein can utilize conventional drilling and subsequently MMWD to form boreholes to greater depths than conventional drilling alone and can provide greater rates of penetration when rock permeability and/or rock hardness decreases, and/or when borehole temperature or pressure increases, as exist in deeper sub-surface formations of rock.
Permeability of the first portion of the borehole can be monitored based on data associated with a fluid applied into and received from the borehole. For example, the fluid can be supplied into and received from the borehole to remove the cut or ground material. The rate of fluid or the pressure of the fluid can be used to infer a permeability of the rock surrounding the first portion of the borehole. In some embodiments, the permeability can be inferred from logging data collected while forming the first portion of the borehole or a borehole at a different location. Logging data can include, for example, logs from logging while drilling (LWD) records, which can be created by conventional drilling approaches. In some embodiments, permeability can be monitored based on core samples sent to a lab for direct measurement. For example, by flowing a single phase fluid thru a core of a known diameter and length, the pressure drop across the rock sample can be measured. The permeability of the core samples can be calculated using Darcy's law. In some embodiments, the permeability can be monitored via measurement with wireline logging tools. In some embodiments, the permeability can be monitored via measurement with downhole pressure and sampling tools. In some embodiments, the permeability can be monitored using drill stem testing (DST). DST can be used to determine the average in situ permeability based on transient analysis of downhole pressures. In some embodiments, the permeability can be determined based on historical data derived from offset wells that are drilled nearby a well being monitored. In some embodiments, the permeability can be inferred based on monitoring porosity and fluid saturation to infer an acceptable amount of ingress fluid within the borehole. In some embodiments, the permeability can be monitored or determined using measurement while drilling (MWD), which can include use of formation evaluation tools to provide reservoir information in real time or near real time.
Temperature of the borehole can be monitored using one or more downhole sensors. Downhole sensors can be utilized to approximately 300 degrees C. Currently “ultra-high” temperature drilling fluids are rated to 260 degrees C. or about 500 degrees F. and “ultra-high” temperature motors are similarly rated for 260 degrees C. or about 500 degrees F. The ultra-high temperature motors can operate in higher temperature zones than rotary steerable motors because they do not include downhole electrical components. Rotary steerable systems (RSS) and motors are typically limited to maximum downhole temperatures of 200 degrees due to the temperature limits associated with the downhole electrical components. “High”—temperature drilling fluids and motors can be rated to about 200 degrees C. or about 400 degrees F. “Normal” temperature drilling fluids and motors can be rated to about 150 degrees C. or about 300 degrees F. Conventional drilling can drill into high reservoir temperature zones, but can require circulating large volumes of drilling fluid to cool the borehole in order to keep within any temperature limits of the drilling equipment.
In some embodiments, the temperature of the borehole can be inferred from the fluid received from the borehole. In some embodiments, such as when performing MMWD, the temperature of the borehole can be determined using pyrometry and/or radiometry. In some embodiments, the temperature of the borehole can be measured while drilling, for example using a resistance temperature detector (RTD) or a fiber optic sensor. In some embodiments, the temperature of the borehole can be measured using wireline logging tools. In some embodiments, the temperature of the borehole can be determined based on historical data. In some implementations, temperature can be determined by analyzing LWD records. In some embodiments, RSS tools can monitor the control unit temperature. In some embodiments, the temperature can be monitored at the drill bit using a memory gauge. In some embodiments, the borehole temperature can be monitored using a RTD whilst logging while drilling. Other approaches are possible.
A rate of penetration (ROP) of the drill bit of the drilling apparatus can be monitored using one or more sensors configured on or associated with the drilling apparatus including the drill bit. In some implementations, ROP can be determined by analyzing LWD records. In some implementations, ROP may not be the only indicator for use in determining when to switch to use of the hybrid MMWD system and methods described herein. For example, ROP can be reduced for a variety of issues, all of which can be related to the RSS, motor, and drill bit, as well as how these components behave dynamically. ROP can also be reduced due to the presence of a hard rock layer in one location followed by a next rock layer that is more permeable and soft. Primary factors affecting ROP include rock depth, rock porosity, rock permeability, downhole temperature, and mechanical specific energy. Monitoring ROP from the surface, such as from a block position, is typically required as integrating accelerometers into the downhole environment can produce poor results. Measurements while drilling (MWD) can utilize accelerometers and magnetometers to provide spatial orientation of the bottom hole assembly (BHA) from which ROP can be determined.
An effective ROP (EROP) can be a ROP that accounts for the amount of time that is not spent on making the borehole deeper. For example, an EROP can include the amount of time needed to remove and replace a worn drill bit. MMWD does not require such extraneous time since MMWD does not require replacing worn drill bits or BHA components. As a result, the amount of non-productive time (NPT) spent forming the borehole can be reduced and the EROP, or a time to a target depth, can be significantly less than conventional drilling. In addition, the borehole formed via MMWD is vitrified and may not require the application of casings or cement therein. This can further reduce the amount of NPT and increase the EROP. In some embodiments, the hybrid MMWD system and methods described herein can achieve about 1 mm/second EROP. Thus, some example implementations of the hybrid MMWD system and methods described herein can achieve about 10 km of depth in 100 days of drilling.
A hardness of the material present within the first portion of the borehole can be monitored based on the rate of fluid exiting the borehole. In some embodiments, the hardness of the material can be inferred or measured from data associated with the permeability of the first portion of the borehole. In some embodiments, the hardness of the material can be inferred or measured from analyzing rock cuttings. For example, the type of rock can indicate a hardness of the rock. In some embodiments, the hardness of the material can be inferred or measured using a logging tool. The logging tool measurements can be acquired while drilling or using a wireline tool, such as a thru-bit logging configuration. In some embodiments, the hardness of the material can be inferred or measured from the frequency at which worn drill bits are changed. In some embodiments, the hardness of the material can be inferred or measured from direct measurement of core samples. In some embodiments, the hardness of the material can be inferred or measured from historical data. In some embodiments, the hardness of the material can be inferred or measured from an amount of surface torque or downhole torque, an amount of weight on a drill bit, the ROP, and/or revolutions per minute (RPM) of the drill bit. Excessive vibration and low ROP can be indicative of harder material. In some embodiments, at-bit or in-bit logging tools can provide weight-on-bit (WOB), down-hole WOB (DWOB), torque-on-bit (TOB), and/or down-hole TOB (DTOB) data from which hardness can be inferred. In addition, MWD tools can provide formation evaluation data from which a type of rock formation and corresponding rock hardness can be inferred.
Based on the aforementioned measurements, and/or data, proxy measurements corresponding to the hardness of the material can be calculated. In some embodiments, the proxy measurements can include an apparent formation strength. For example, the apparent formation strength can be calculated as (DWOB*RPM)/(ROP*depth). In some embodiments, the proxy measurements can include a measure of the drilling specific energy. For example, the drilling specific energy can be calculated as ((8 DTOB*RPM)/(depth2*ROP)). In some embodiments, the proxy measurements can include a measure of the mechanical work required to destroy a unit volume of rock.
In operation 110, a determination to utilize a MMWD apparatus including a waveguide configured for insertion into the borehole can be made. The determination can be made based at least on the permeability of the borehole falling below a permeability threshold value. For example, based on determining the permeability of the borehole and determining a decrease in permeability of the rock surrounding the borehole as the drilling apparatus drills deeper, the determination to switch to a MMWD apparatus can be made. In some implementations, the determination can be made by a first data processor of a first computing device associated with the monitoring performed in operation 105, by a second data processor associated with a second computing device located remotely from the data processor and computing device where the monitoring data is received, or by a combination of the first and second data processors. In some embodiments, the determination can be made based on inferred borehole permeability rather than a borehole permeability that is directly measured within the borehole.
The permeability threshold value can be a value determined from previous borehole formations. In some embodiments, the permeability threshold value can be determined based on geologic surveys identifying the composition of the sub-surface formations and rock present in the area of the well borehole. The threshold permeability value can be a value that would result in a fluid inflow, in m3/s or equivalent units, that would be too high for the amount of energy available to drill. For example, since MMWD can heat all materials within the downhole, a 1 mm/s ROP on an 8″ diameter borehole implies that material can be removed at a rate of 0.0000324 m3/s (3.24 E−5 m3/s) assuming a total energy to vaporize rock of 25000 Joules/cm3. If fluid was flowing into the borehole at the same rate, the ROP would become zero. In this example, ROP would be canceled because the energy generated via MMWD would be transmitted into the incoming fluid rather than the rock formations. Thus, a threshold permeability value can be a function of permeability, a difference in lithostatic pressure and wellbore pressure, and a desired ROP. In some embodiments, the permeability threshold value can be between 1.0 microdarcy (uD) and 10.0 milidarcy (mD) values.
In some embodiments, operation 110 can also include determining to utilize a MMWD apparatus based on a monitored temperature of the borehole exceeding a temperature threshold value. In some embodiments, the temperature threshold value can be determined as a function of the type of conventional drilling equipment used. For example, the maximum temperatures can be associated with a temperature rating of the equipment. The temperature rating for equipment that includes electronics within the drilling equipment can be limited to 260 degrees C., while the temperature rating for a motor lining of the drilling equipment can be limited to 150 degrees C. As a result, the maximum temperature can be determined by the lowest temperature of these two.
For non-geothermal wells, the well is formed without a RSS using geosteering. In this way, the well can be drilled deeper, but may not be truly vertical. As a result, a transition to MMWD may not be optimal. When RSS is used to form an initial portion of the borehole, the RSS should be operated in inclination hold mode so that any vertical deviation of the borehole formation is minimized. In some implementations, the borehole formed by the rotary drill is near-vertical to improve the performance of MMWD, and use of a RSS or similar technique can enable a more vertical borehole, as compared to some boreholes formed by rotary drills, which can appear helical.
In some embodiments, operation 110 can also include determining to utilize a MMWD apparatus based on an effective rate of penetration of the drill bit of the drilling apparatus falling below a rate of penetration threshold value. In some embodiments, the rate of penetration threshold value can be determined based on geologic surveys identifying the composition of the subsurface formations and rock present in the area of the well borehole. In some embodiments, the rate of penetration threshold value can be determined based on historical data. In some embodiments, the rate of penetration threshold value can be determined based on modeling and simulation data of expected EROP through known formation types for both rotary and MMWD systems and/or methods. In some embodiments, the effective rate of penetration threshold value can be between 0.5 and 2.0 mm/s.
In some embodiments, operation 110 can also include determining to utilize a MMWD apparatus based on a monitored hardness of a material present in the first portion of the borehole exceeding a hardness threshold value. In some embodiments, the hardness threshold value can be determined based on geologic surveys identifying the composition of the sub-surface formations and rock present in the area of the well borehole. In some embodiments, the hardness threshold can be determined based on analysis of cuttings removed from the borehole and based on analysis of a drill bit when the drill bit is replaced. In some embodiments, the hardness threshold can be determined based on a correlation between the ROP, weight on the drill bit, and torque applied to the drill bit. In some embodiments, the hardness threshold value can be between 4 and 6 as measured on the Mohs hardness scale. In some embodiments, the hardness threshold value can be a value above 100 MPa compressive strength of the rock. In some embodiments, the hardness threshold value can correspond to an amount of downhole torque or a mechanical specific energy.
In operation 115, a second portion of the borehole can be formed utilizing the MMWD apparatus in response to the determining. The MMWD apparatus can be configured to form a second portion of the borehole at the point it is determined that the conventional drilling apparatus is no longer achieving adequate progress to form the borehole with respect to the various threshold values used in operation 110. It can be advantageous to form the second portion of the borehole using a MMWD apparatus not based just on the financial cost of operating the conventional drilling apparatus, but instead, based on more robust analysis of geophysical variables associated with the conventional drilling operations, such as the permeability, temperature, hardness of the borehole, and the rate of penetration of the conventional drilling apparatus. In this way, the decision to change from a conventional drilling apparatus to a MMWD apparatus can be made in a more precise manner which can yield cost savings, greater penetration rates, and safer drilling operations than determining to change from conventional drilling to MMWD based on costs alone. The decision to change from the conventional drilling apparatus to the MMWD apparatus can also reduce or eliminate well completion steps requiring the need to install casings and cement. Prior to switching to the MMWD apparatus, the well can be cased and cemented, and the mud can be replaced by a gas configured for use in MMWD.
In operation 205, a downhole pressure of a well is monitored during formation of a borehole of a well using a MMWD apparatus including a waveguide configured for insertion into the borehole. The monitoring can include determining the downhole pressure of the borehole. The downhole pressure of the borehole can include an amount of pressure present at the bottom of the well or borehole. The downhole pressure of the well or borehole can be determined based on a surface pressure and a pressure of a gas supplied into the borehole during the MMWD. For example, one or more of a surface injection pressure, a flow rate, one or more fluid property, a flow area dimension, a depth, a bottom hole temperature, and/or a last physical bottom hole pressure measurement from conventional drilling methods may be known. An injection rate, the fluid properties, the flow area, and the depth can be used to calculate a pressure drop. The depth and the fluid properties can be used to calculate a hydrostatic pressure. The Ideal Gas Law, or another empirical equation, can be used to determine a pressure increase to due temperature increase, e.g., (PV=NRT). These calculated values can be used to determine the bottom hole pressure.
In some embodiments, a modified Bernoulli equation, a Darcy-Weisbach Equation, a Fanning equation, and/or a Hazen-Williams equation can be used to solve for the pressure at a 2nd point. By comparing the calculated bottom hole pressure to the last measurement bottom hole pressure measurement, a determination of the downhole pressure can be made in relation to the reference value. The last bottom hole pressure measurement can be linearly extrapolated to deeper bottom hole pressure values in a continuous manner to determine if the bottom hole pressure is sufficient or needs to be increased to maintain the integrity of the borehole.
In some embodiments, the model can further correlate an amount of input energy supplied to the gyrotron of the MMWD apparatus to downhole pressure. In some embodiments, the model can include downhole pressure data associated with conventional drilling, such as rotary drilling. In some embodiments, the downhole pressure can be determined via modeling the wellbore flow, based on the downhole temperature, the depth (e.g., the wellbore volume), the inflow, and the inlet/outlet pressure. In operation 210, a lithostatic pressure of rock surrounding the well at the bottom of the well can be determined. In some embodiments, the lithostatic pressure can be determined based on past geologic survey data and/or a model of geophysical data associated with the well site.
In operation 215, the downhole pressure can be controlled relative to the lithostatic pressure of the rock surrounding the well at the bottom of the well. Controlling the downhole pressure can be important to overbalance, underbalance, or balance the downhole pressure with respect to the lithostatic pressure to maintain the structural stability of the borehole and the well. A highly underbalanced condition of the downhole pressure relative to the lithostatic pressure of the surrounding rock could cause instability and collapse of the borehole. In some embodiments, a Rotating Pressure Control Head (RCPH) can be used.
In some embodiments, the downhole pressure can be controlled via controlling operation of a gas compressor positioned at the surface where the entrance to the borehole is located. The gas compressor can be configured to supply a gas into the borehole via one or more valves, such as input and output valves. The downhole pressure can be controlled by controlling an input valve position of the gas compressor, an output valve position of the gas compressor, and/or a flow rate of the gas supplied by the gas compressor. In some embodiments, the flow rate of the gas can be between 0.5 m/s and 50 m/s. In some embodiments, the downhole pressure can be controlled via the inlet mass flow and the back pressure of the compressor. In some embodiments, the downhole pressure can be controlled based on calculating a Mach number of the flow at different places (e.g., at orifice plates).
In operation 220, particulate matter generated by the MMWD apparatus can be removed. MMWD can produce small particulate matter formed as a result of vaporizing rock. For example, the particulate matter can be less than one micron in size. The particles can be removed by applying a gas flow to remove the particles. In some embodiments, the downhole pressure can be controlled to remove particles by driving them into fractures within the surrounding rock, thus reducing the need to lift the particles out from the borehole.
As part of the waveguide transmission line 308 there is an isolator 310 to prevent reflected power from returning to the gyrotron 302 and an interface for diagnostic access 312. The diagnostic access is connected to diagnostics electronics and data acquisition 316 by low power waveguide 314. At the window 320 there is a pressurized gas supply unit 322 connected by plumbing 324 to the window to inject a clean gas flow across the inside window surface to prevent window deposits. A second, pressurization unit 336 is connected by plumbing 332 to the waveguide opening 328 to help control the pressure in the borehole 348 and to introduce and remove borehole gases as needed. The window gas injection unit 322 is operated at slightly higher pressure relative to the borehole pressure unit 336 to maintain a gas flow across the window surface. A branch line 334 in the borehole pressurization plumbing 332 is connected to a pressure relief valve 338 to allow exhaust of volatized borehole material and window gas through a gas analysis monitoring unit 340 followed by a gas filter 342 and exhaust duct 344 into the atmosphere 346. In an alternative embodiment, the exhaust duct 344 returns the gas to the pressurization unit 336 for reuse.
Pressure in the borehole is increased in part or in whole by the partial volatilization of the subsurface material being melted. A thermal melt front 352 at the end of the borehole 348 is propagated into the subsurface strata under the combined action of the millimeter wave power and gas pressure leaving behind a glassy/ceramic borehole wall 350. This wall acts as a dielectric waveguide to transmit the millimeter wave beam to the thermal front 352.
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In some embodiments, a batch approach can be employed using the hybrid MMWD systems and methods described herein. For example, multiple well boreholes in a given area could be formed using the conventional drilling apparatus and methods prior to changing surface equipment to the MMWD apparatus used to deepen the borehole within the basement rock depths. As a result, time and resources may be saved by performing conventional drilling and MMWD in batches. In other embodiments, the conventional drilling apparatus 505 can be readily modified into a MMWD apparatus 1105 to switchover operations without moving the rig structure.
The improved system, devices, and methods described herein addresses the technical problem of monitoring and controlling the downhole pressure of a well during formation of a borehole of the well using a MMWD approach, such as a MMWD systems and methods described herein. The monitoring and controlling of the downhole pressure of the well can be useful for maintaining stability of the borehole during formation, efficiently operating equipment at well sites and performing well site planning based on geophysical characteristics of the sub-surface formations being accessed rather than operational costs. In this way, the hybrid MMWD system and methods described herein can enable deeper boreholes into less permeable and/or hard rock occurring at higher temperatures below the surface. As a result, deeper deposits of natural and thermal resources can be accessed more efficiently than using conventional drilling apparatus and methods.
Certain exemplary embodiments have been described to provide an overall understanding of the principles of the structure, function, manufacture, and use of the systems, devices, and methods disclosed herein. One or more examples of these embodiments have been illustrated in the accompanying drawings. Those skilled in the art will understand that the systems, devices, and methods specifically described herein and illustrated in the accompanying drawings are non-limiting exemplary embodiments and that the scope of the present invention is defined solely by the claims. The features illustrated or described in connection with one exemplary embodiment may be combined with the features of other embodiments. Such modifications and variations are intended to be included within the scope of the present invention. Further, in the present disclosure, like-named components of the embodiments generally have similar features, and thus within a particular embodiment each feature of each like-named component is not necessarily fully elaborated upon.
Approximating language, as used herein throughout the specification and claims, may be applied to modify any quantitative representation that could permissibly vary without resulting in a change in the basic function to which it is related. Accordingly, a value modified by a term or terms, such as “about,” “approximately,” and “substantially,” are not to be limited to the precise value specified. In at least some instances, the approximating language may correspond to the precision of an instrument for measuring the value. Here and throughout the specification and claims, range limitations may be combined and/or interchanged, such ranges are identified and include all the sub-ranges contained therein unless context or language indicates otherwise.
One skilled in the art will appreciate further features and advantages of the invention based on the above-described embodiments. Accordingly, the present application is not to be limited by what has been particularly shown and described, except as indicated by the appended claims. All publications and references cited herein are expressly incorporated by reference in their entirety.
This application is a continuation of U.S. patent application Ser. No. 17/230,716 filed on Apr. 14, 2021 which is a divisional of and claims priority under 35 U.S.C. § 120 to U.S. patent application Ser. No. 17/090,410, filed on Nov. 5, 2020 in the U.S. Patent and Trademark Office, the entire contents of which is incorporated herein by reference.
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| Number | Date | Country | |
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| Child | 17230716 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 17230716 | Apr 2021 | US |
| Child | 18295385 | US |
