Patent Description:
One method of well-bore stimulation uses a downhole laser tool to penetrate and ablate a hydrocarbon bearing formation. In such a system, a laser surface unit excites energy to a level above the sublimation point of a hydrocarbon bearing formation to form a high power laser beam. This high powered laser beam is transmitted from the laser surface unit to the desired downhole location via optic fiber. At the downhole end of the optical fiber, the laser beam enters a drill head, which directs and focuses the high power laser beam. Finally, the high power laser beam is discharged from the transformer to ablate the intended hydrocarbon bearing formation. Patent document <CIT> discloses an apparatus for drilling underground having at least one optical fiber for transmitting light energy from a laser energy source disposed above ground to an underground drilling location and a mechanical drill bit having at least one cutting surface and forming at least one light transmission channel aligned to transmit light from the at least one optical fiber through the mechanical drill bit by way of the at least one light transmission channel. Patent document <CIT> discloses methods for notching a wellbore while drilling.

A drilling tool in a formation according to the invention is defined by appended claim <NUM>. Specific embodiments are defined by the dependent claims. Such a drilling tool may comprise an optical fiber having a laser input end and a laser output end and a laser source optically connected to the laser input end. Further, the drilling tool may comprise an activating agent conduit having an activating agent inlet and an activating agent outlet and an activating agent source connected to the activating agent inlet that supplies an activating agent. Finally, the drilling tool may comprise a drill head. In some embodiments, the drill head may comprise a nozzle connected to the activating agent outlet that discharges the activating agent on an area of the formation, and a laser head optically connected to the laser output end and arranged to lase at least a portion of the area of the formation having the activating agent.

In some embodiments, the activating agent may increase energy absorption of the portion of the area of the formation when lased.

In some embodiments, the activating agent may comprise an activating material having at least one of a dark color, a high porosity, a high surface area, a small particle size, a high optical absorption, or a low optical reflectivity.

The activating agent comprises an activating material, the activating material comprising at least one of activated carbon, graphite, carbon black, carbon nanotubes, nanoparticles, paint, dye, molybdenum disulfide, a transition metal chalcogenide, or a metamaterial.

In some embodiments, the activating agent may further comprise a transport fluid, such that the transport fluid and the activating material are mixed prior to entering the activating agent inlet.

In some embodiments, the transport fluid may comprise at least one of water, brine, liquid adhesive, surfactant, acetone, ethanol, methanol, or isopropanol.

In some embodiments, the drilling tool may further comprise a carrying fluid conduit having a carrying fluid inlet and a carrying fluid outlet; and a carrying fluid source connected to the carrying fluid inlet that supplies a carrying fluid that carries the activating agent out the nozzle.

In some embodiments, the carrying fluid may comprise at least one of air, nitrogen, oxygen, argon, water, brine, liquid adhesive, surfactant, acetone, ethanol, methanol, or isopropanol.

In some embodiments, the drill head may further comprise an articulation module configured to direct the nozzle and the laser head toward the area of the formation.

In some embodiments, the drill head may further comprise a rotational module configured to direct the nozzle and the laser head toward the area of the formation.

In some embodiments, the rotational module may have an axis of rotation that lies in a plane dividing the drill head into a first half and a second half. In some embodiments, the nozzle may be disposed on the first half, and the laser is disposed on the second half.

A method for drilling in a formation using an activating agent and a laser according to the invention is defined by appended claim <NUM>. Specific embodiments are defined by the dependent claims. Such a method may comprise: inserting a drill head into a wellbore; advancing the drill head to an area of the formation; discharging an activating agent on the area of the formation using a nozzle in the drill head; and lasing at least a portion of the area of the formation using a laser head in the drill head.

In some embodiments, the method may further comprise maneuvering the drill head so the nozzle is directed toward the area of the formation.

In some embodiments, discharging the activating agent may further comprise rastering the nozzle while discharging the activating agent from the nozzle.

In some embodiments, discharging the activating agent may further comprise maneuvering the drill head.

In some embodiments, the method may further comprise maneuvering the drill head so the laser head is directed toward the area of the formation.

In some embodiments, lasing at least the portion of the area of the formation may further comprise rastering the laser head while lasing.

In some embodiments, lasing at least the portion of the area of the formation may further comprise maneuvering the drill head.

In some embodiments, the method may further comprise supplying a carrying fluid to an activating agent source located in a vicinity of the drill head such that the carrying fluid carries the activating agent from the activating agent source out the nozzle.

In some embodiments, the method may further comprise supplying a carrying fluid to an intermediate opening defined in an activating agent conduit such that the carrying fluid carries the activating agent from proximate to the intermediate opening out the nozzle.

Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

Throughout the figures, similar numbers are typically used for similar components.

In the figures, down is toward or at the bottom and up is toward or at the top of the figure. "Up" and "down" are generally oriented relative to a local vertical direction. However, as used throughout this disclosure, the terms "upflow" and "downflow" may refer to a position relative to the general direction of process or fluid flow, with upflow indicating a direction or position closer to start of the process and downflow referring to the direction or position closer to the end of the process. One of ordinary skill in the art would readily understand that an object or a process may be upflow or downflow of another object or process while having no general relation to the position relative to vertical orientation unless otherwise specifically stated.

While lasing with high power laser energy may produce a sudden increase in temperature in some formations from the original reservoir temperature to <NUM>, other formations may only reach <NUM>. Importantly, lower temperatures may be insufficient to sublime a rock formation and thus stimulate the wellbore production.

The maximum temperature achieved in a formation reflects the amount of laser energy absorbed by a given rock. While many factors contribute to the amount of laser energy absorbed by a formation, the primary factor is the color of the formation. To that end, brighter colored surfaces reflect a larger fraction of the incident laser light than do darker colored surfaces.

In order to enhance the amount of laser energy absorbed by a formation, this disclosure provides a method and a device for first spraying an area of a formation with an activating agent that increases the absorption and then lasing that area of the formation now coated with the activating agent.

<FIG> depicts one or more embodiments of a drilling tool <NUM> located in a wellbore <NUM> that includes a formation <NUM>.

Drilling tool <NUM> includes an activating agent source <NUM> connected to activating agent conduit <NUM> that ends in a drill head <NUM>. An activating agent is stored in activating agent source <NUM> and delivered to drill head <NUM> via activating agent conduit <NUM>.

Drilling tool <NUM> also includes laser source <NUM> connected to optical fiber <NUM> that ends in drill head <NUM>. Drill head <NUM> is located so it can interact with an area <NUM>. A laser is generated in laser source <NUM> and delivered to drill head <NUM> via optical fiber <NUM>.

Activating agent source <NUM> and laser source <NUM> are located above surface <NUM> of wellbore <NUM>.

Laser source <NUM> may generate a high power laser (for example, a laser having an output power of at least <NUM> kW, at least 20kW, at least 100kW, or in the megawatt range). Optical fiber <NUM> may be a fiber optic cable configured to transmit the high power laser light. Optical fiber <NUM> may transmit laser light between laser source <NUM> and drill head <NUM>. Given the depth of wellbore <NUM>, optical fiber <NUM> may be many kilometers meters long, such as <NUM>, <NUM>, or greater.

As discussed previously, an activating agent may be used to improve the laser absorption characteristics of a formation by increasing the energy absorption. In some embodiments, the activating agent may include an activating material. In some embodiments, the activating material may have a dark color, a high porosity, a high surface area, a small particle size, a high optical absorption, a low optical reflectivity, or a combination. In some embodiments, the activating material may be a solid or a liquid. In some embodiments, the activating material may be activated carbon, graphite, carbon black, carbon nanotubes, nanoparticles, paint, dye, molybdenum disulfide, a transition metal chalcogenide, a metamaterial, or a combination.

One illustrative example of an activating agent that includes only an activating material is dye. In drilling tool <NUM> as depicted in <FIG> and <FIG>, dye (the activating material) is stored at the surface <NUM> in the activating agent source <NUM>, flows down activated agent conduit <NUM>, and is ejected from nozzle <NUM>.

In some embodiments, the activating agent may include both an activating material and a transport fluid. In some embodiments, the activating material may be mixed with and transported from activating agent source <NUM> through activating agent conduit <NUM> and out nozzle <NUM> by a transport fluid. In some embodiments, the transport fluid may include a liquid such as water, brine, liquid adhesive, surfactant, acetone, ethanol, methanol, isopropanol, or a combination. In some embodiments, the transport fluid may be viscus, sticky, or both to aid the attachment of the activating agent to area <NUM> within wellbore <NUM>. In some embodiments, the activating agent may also include one or more additives such as surfactants, viscosifiers, wetting agents, emulsifiers, and others.

One illustrative example of an activating agent comprised of a transport fluid and an activating material is activated carbon (the activating material) in water (the transport fluid). As mentioned previously, such a mixture may also include one or more additive, such as a surfactant to help keep the activated carbon suspended in the water. In <FIG> and <FIG>, such an activated carbon/water mixture would be stored at the surface <NUM> in the activating agent source <NUM>, flow down activated agent conduit <NUM>, and is ejected from nozzle <NUM>.

<FIG> depicts a cross section of the drilling tool <NUM> depicted in <FIG> according to one or more embodiments.

Activating agent conduit <NUM> includes an activating agent inlet <NUM> connected to activating agent source <NUM> and an activating agent outlet <NUM> fluidly connected to a nozzle <NUM> in drill head <NUM>. Activating agent conduit <NUM>, thus, connects activating agent source <NUM> to nozzle <NUM> so activating agent may be ejected from nozzle <NUM>.

Within nozzle <NUM>, the activating agent may encounter one or more fluidic components known in the art. These fluid components may include one or more components (for example, pumps, conduits, inlets, outlets, sprayers, mixers, diffusers, and throats). These fluidic components may direct or pressurize the activating agent within nozzle <NUM> and/or upon emission from nozzle <NUM>. In some embodiments, the activating agent may pass through one or more components within nozzle <NUM> to control the size and direction of the activating agent before or during emission from nozzle <NUM>. In some embodiments, the activating agent when emitted from nozzle <NUM> may have any spray pattern (for example, a solid stream, a mist, a fog, a flat fan, a twin flat fan, a hollow cone, a solid cone, or a spiral full cone), any spray angle/geometry (for example, wide or narrow), and any spray geometry (for example, round or oval), depending upon the application. In some embodiments, nozzle <NUM> may be configured to raster the activating agent as it is emitted from nozzle <NUM>.

Similarly, optical fiber <NUM> includes a laser input end <NUM> connected to laser source <NUM> and a laser output end <NUM> connected to a laser head <NUM> in drill head <NUM>. Optical fiber <NUM>, thus, connects laser source <NUM> to laser head <NUM> so the laser may be emitted from laser head <NUM>.

Within laser head <NUM>, the laser may encounter one or more optical components known in the art. These optical components may direct or shape the laser. These optical components may include one or more transmissive component (for example, lenses, filters, windows, optical flats, prisms, polarizers, beamsplitters, wave plates, and additional optical fibers) or reflective component (for example, mirrors and retroreflectors). In some embodiments, the laser may pass through one or more lenses within laser head <NUM> to control the size and direction of the laser before or during emission from laser head <NUM>. In some embodiments, the laser emitted from laser head <NUM> may be focused or collimated, depending upon the application. In some embodiments, laser head <NUM> may be configured to raster the laser as it is emitted from laser head <NUM>.

In some embodiments, laser head <NUM>, nozzle <NUM>, or both may emit from drill head <NUM> on a radial side <NUM> of drill head <NUM>.

Since wellbores are frequently not vertical (as in horizontal drilling), a z-direction as depicted here may be parallel to the downhole direction in a region of wellbore <NUM> near drill head <NUM>. The spherical coordinates reference axis depicted here also includes theta O, the azimuthal angle perpendicular to the z-direction.

Drilling tool <NUM> also includes rotational module <NUM>, which rotates drill head <NUM> around an axis of rotation <NUM> as indicated by arrow <NUM>. Thus, rotational module <NUM> may change the azimuthal angle theta Θ of drill head <NUM>. One having skill in the art will appreciate the well-known structures that may be included in rotational module <NUM>.

Drilling head <NUM> may be manipulated in the z-direction using other means, such as by advancing/retracting drill tool <NUM> within wellbore <NUM> using equipment known in the art.

Axis of rotational <NUM> may be perpendicular to axial end <NUM> of drill head <NUM>. Axis of rotation <NUM> may be parallel with the depicted z-direction. Arrow <NUM> may indicate rotation in the theta Θ direction.

Axis of rotation <NUM> may be located in a plane (not depicted) that divides drill head <NUM> into a first half <NUM> and a second half <NUM>. In some embodiments, nozzle <NUM> may be located in first half <NUM> of drill head <NUM> and laser head <NUM> may be located in second half <NUM> of drill head <NUM>. Rotational module <NUM> may be used to arrange drill head <NUM> such that nozzle <NUM> and laser head <NUM> can successively be directed toward the same area within a formation as described further.

In <FIG>, nozzle <NUM> and laser head <NUM> are on opposing sides of drill head <NUM> such that an angle between nozzle <NUM> and laser head <NUM> is approximately <NUM>°. Thus, nozzle <NUM> and laser head <NUM> emit an activating agent and a laser, respectively, in opposite directions. While drill head <NUM> is depicted as a cylinder in <FIG>, one having skill in the art will appreciate that drill head <NUM> may have any shape, including a cube, a rectangular prism, a cuboid, or a hexagonal prism.

In some embodiments, the angle between nozzle <NUM> and laser head <NUM> may be angles other than <NUM>° in some embodiments (for example, <NUM>°, <NUM>°, <NUM>°, <NUM>°, or others). Additionally, some embodiments of drill head <NUM> may more than one nozzle <NUM> and/or more than one laser head <NUM>. In such an embodiment, each nozzle <NUM>/laser head <NUM> may be connected to a separate source or a single source may be divided and directed towards each nozzle <NUM>/laser head <NUM> using a splitter known in the art.

A case <NUM> protects the components of drill head <NUM> from the environment present in wellbore <NUM>. Similarly, a sheath <NUM> protects activating agent conduit <NUM> and optical fiber <NUM> from the environment present in wellbore <NUM>. Additional modules of drilling tool <NUM> such as rotational module <NUM> may be within case <NUM> and/or sheath <NUM> or may include a protective covering and/or coating to protect from the environment present in wellbore <NUM>.

<FIG> depicts a cross-sectional schematic of a drilling tool <NUM> according to one or more embodiments. As in <FIG>, laser source <NUM> connects to laser head <NUM> in drill head <NUM> via optical fiber <NUM>.

In contrast with <FIG>, activating agent source <NUM> is not located on surface <NUM> and is instead located near drill head <NUM>. Specifically, activating agent source <NUM> is located atop rotational module <NUM> with rotational module <NUM> located atop drill head <NUM>. In some embodiments, activating agent source <NUM> may be located within drill head <NUM> or in a component near drill head <NUM> such as within an adjacent or nearby sub.

Some embodiments, such as the embodiment depicted in <FIG>, may employ a carrying fluid. This carrying fluid is used to carry the activating agent from activating agent source <NUM> out nozzle <NUM>. The carrying fluid is stored in a carrying fluid source <NUM> located above surface <NUM>. Carrying fluid flows from carrying fluid source <NUM> through a carrying fluid inlet <NUM>, a carrying fluid conduit <NUM>, and a carrying fluid outlet <NUM> and into activating agent source <NUM>. Thus, the carrying fluid and the activating agent mix within activating agent source <NUM>.

In some embodiments, the carrying fluid may be a liquid or a gas. In some embodiments, the carrying fluid may include water, brine, liquid adhesive, surfactant, acetone, ethanol, methanol, isopropanol, air, compressed air, nitrogen, oxygen, argon, or a combination. In some embodiments, the carrying fluid may be viscus, sticky, or both to aid the attachment of the activating agent to area <NUM> within wellbore <NUM>. In some embodiments, the carrying fluid may also include one or more additives such as surfactants, viscosifiers, wetting agents, emulsifiers, and others to enhance the ability of the activating agent to be mixed with the carrying fluid.

One illustrative example of a carrying fluid and an activating agent is a combination of water (the carrying fluid) and activated carbon (the activating material). Here, water is being employed as a carrying fluid and not as a transport fluid as discussed in a previous example. In <FIG>, water (the carrying fluid) is stored in carrying fluid source <NUM> above surface <NUM> while activated carbon (the activating material) is stored in activated agent source <NUM> near drill head <NUM>. Thus, water (the carrying fluid) would flow down carrying fluid conduit <NUM> to activated agent source <NUM>. Within activated agent source <NUM>, water (the carrying fluid) and activated carbon (the activating material) mix. Thus, a mixture of water and activated carbon flows down activating agent conduit <NUM> and the mixture is sprayed out nozzle <NUM>. One having skill in the art will appreciate how, in such an embodiment, activating agent source <NUM> may include one or more components (for example, blenders, mixers, aerosolizers, and on) to improve the mixing of carrying fluid and activating agent.

<FIG> depicts a further embodiment of drilling tool <NUM> having a different configuration for activating agent source <NUM> and where carrying fluid and activating agent mix within activating agent conduit <NUM>.

In <FIG>, activating agent source <NUM> is located within drill head <NUM> and vertically below nozzle <NUM>. In some embodiments, activating agent source <NUM> may be located anywhere within drill head <NUM>, including vertically above nozzle <NUM>, level with nozzle <NUM>, or below nozzle <NUM>. In such an embodiment, activating agent conduit <NUM> may include an additional component such as a wicking material conduit or a pump to move the activating agent vertically, toward nozzle <NUM>, or both.

As before, activating agent conduit <NUM> is connected to an activating agent source <NUM> via an activating agent inlet <NUM> and is connected to nozzle <NUM> with an activating agent outlet <NUM>. Additionally, a carrying fluid is stored in a carrying fluid source <NUM>, moves into a carrying fluid inlet <NUM>, through a carrying fluid conduit <NUM> and out a carrying fluid outlet <NUM>.

However, in <FIG>, the carrying fluid and the activating agent mix upflow from nozzle <NUM> at the intersection of activating agent conduit <NUM> and carrying fluid conduit <NUM>. Specifically, carrying fluid conduit <NUM> intersects with activating agent conduit <NUM> near nozzle <NUM>. Thus, the carrying fluid exits carrying fluid conduit <NUM> via carrying fluid conduit <NUM>, flowing into activating agent conduit <NUM> via an intermediate opening <NUM> defined by activating agent conduit <NUM> and located along the length of activating agent conduit <NUM>. Thus, the carrying fluid picks up the activating agent within activating agent conduit <NUM> at or near intermediate opening <NUM> before being ejected out nozzle <NUM>.

As discussed previously, some embodiments may utilize a carrying fluid and an activating agent. One illustrative example of this configuration in drilling tool <NUM> is compressed air (the carrying fluid) and dye (the activating material). In <FIG>, compressed air (the carrying fluid) is stored in carrying fluid source <NUM> above surface <NUM> while dye (the activating material) is stored in activated agent source <NUM> within drill head <NUM>. Thus, compressed air (the carrying fluid) flows down carrying fluid conduit <NUM> into activating agent conduit <NUM> via intermediate opening <NUM>. Within activated agent conduit <NUM>, compressed air mixes with dye (the activating material). Thus, compressed air propels dye out nozzle <NUM>.

Some embodiments may include both a carrying fluid and an activating agent that includes both an activating material and a transport fluid. One illustrative example of this configuration is compressed air (the carrying fluid) and paint (the activating agent), which is a mixture of pigment (the activating material) and solvent (the transport fluid). In <FIG>, compressed air (the carrying fluid) is stored in carrying fluid source <NUM> above surface <NUM> while paint (the activating agent) is stored in activated agent source <NUM> within drill head <NUM>. Thus, compressed air (the carrying fluid) flows down carrying fluid conduit <NUM> into activating agent conduit <NUM> via intermediate opening <NUM>. Within activated agent conduit <NUM>, compressed air mixes with and/or picks up paint (the activating agent). Thus, compressed air propels paint out nozzle <NUM>.

<FIG> depicts an embodiment of a drilling tool <NUM> having many components arranged similarly to drilling tool <NUM> as depicted in <FIG>. However, in drilling tool <NUM>, drill head <NUM> is manipulated with an articulation module <NUM> as opposed to a rotational module <NUM>. Additionally, nozzle <NUM> and laser head <NUM> are located on an axial end <NUM> of drill head <NUM> and activating agent conduit <NUM> and optical fiber <NUM> are reconfigured appropriately.

In <FIG>, articulation module <NUM> manipulates drill head <NUM> within the depicted x-y-z coordinate space. As discussed previously, since wellbores are frequently not vertical (as in horizontal drilling), the z-direction may be defined as parallel to the downhole direction in a region near drill head <NUM>.

In some embodiments, articulation module <NUM> may manipulate drill head <NUM> in x-y-z space (meaning movement in the x, the y, and the z directions). In some embodiments, articulation module <NUM> may manipulate drill head <NUM> in x-y space, while manipulation in the z direction may be performed using alternative means (such as by advancing/retracting drill tool <NUM> within the wellbore using equipment known in the art). In some embodiments, drill head <NUM> may be grossly manipulated in the z-direction with said alternative means and finely manipulated in the z-direction using articulation module <NUM>. One having skill in the art will appreciate the well-known structures that may be included in articulation module <NUM>, such as a combination of joint(s) and micromotor(s).

One having skill in the art will appreciate how articulation module <NUM> may be readily incorporated into any drilling tool <NUM> of this disclosure. Additionally, a drilling tool <NUM> according to this disclosure may include both articulation module <NUM> and rotational module <NUM>, such that drill head <NUM> may be rotated by rotational module <NUM> and articulated in x-y or x-y-z space by articulation module <NUM>.

<FIG> depicts nozzle <NUM> and laser head <NUM> located on an axial end of drill head <NUM> in some embodiments, nozzle <NUM> and laser head <NUM> may be located on opposite radial sides <NUM> of drill head <NUM> as in <FIG> and as described previously. In some embodiments having more than one nozzle <NUM>, more than one laser head <NUM>, or both, nozzles <NUM> and/or laser heads <NUM> may be located on any combinations of surfaces of drill head <NUM>, including both axial end <NUM> and radial side <NUM>.

<FIG> depicts an embodiment of drilling tool <NUM> with laser head <NUM> and nozzle <NUM> both located in second half <NUM> of drill head <NUM>. Additionally, laser head <NUM> is located radially above nozzle <NUM> on drill head <NUM>.

Nozzle <NUM> is directed at a first area <NUM> of formation <NUM>, while laser head <NUM> is directed at a second area <NUM> of formation <NUM>. Thus, laser head <NUM> is currently positioned to laze at least a portion of second area <NUM> of formation <NUM>. Furthermore, after drill head <NUM> moves downward within wellbore <NUM> as indicated by arrow <NUM>, laser head <NUM> may be positioned to laze at least a portion of first area <NUM> of formation <NUM> after first area <NUM> has interacted with the activating agent.

<FIG> is a flow chart depicting a method for drilling in formation <NUM> with a drilling tool (like drilling tool <NUM>, <NUM>, <NUM>, <NUM>, <NUM>) that employs an activating agent and a laser. Not all depicted steps may be performed in all embodiments of this method.

Step S1 is inserting drill head <NUM> into wellbore <NUM>.

In some embodiments, the method may include step S1. <FIG> and <FIG> depict a drill head <NUM> after it has been inserted into wellbore <NUM>.

Step S2 is advancing drill head <NUM> to area <NUM> of formation <NUM> within wellbore <NUM>.

Some embodiments of the method may include step S2. <FIG> and <FIG> depict a drill head <NUM> that has been advanced to area <NUM> of formation <NUM> within wellbore <NUM>.

Some embodiments of the method may include step S3. Step S3 is using a carrying fluid to carry the activating agent to nozzle <NUM>.

In some embodiments, drilling tool (like drilling tool <NUM>, <NUM>) includes a carrying fluid source <NUM> and carrying fluid conduit <NUM>. Some embodiments of drilling tool (like drilling tool <NUM>, <NUM>) include a carrying fluid that mixes with an activating agent and carries the activating agent out nozzle <NUM>. In some embodiments, the carrying fluid may mix with an activating agent that includes a transport fluid.

In some embodiments, such as in drilling tool <NUM> depicted in <FIG>, the carrying fluid and the activating agent may mix within activating agent source <NUM>. Thus, the carrying fluid may carry the activating agent from activating agent source <NUM> out the nozzle <NUM>, in some embodiments.

In some embodiments, such as in drilling tool <NUM> depicted in <FIG>, the carrying fluid and the activating agent may mix within activating agent conduit <NUM> near intermediate opening <NUM>. Thus, the carrying fluid may carry the activating agent from activating agent conduit <NUM> near intermediate opening <NUM> out the nozzle <NUM>, in some embodiments.

Some embodiments of the method may not include step S3, such as those that do not employ a carrying fluid.

Some embodiments of the method may include step S4. Step S4 is maneuvering drill head <NUM> so nozzle <NUM> is directed towards area <NUM> of formation <NUM>.

Some embodiments of drilling tool (such as drilling tool <NUM>, <NUM>, <NUM>, <NUM>, <NUM>) include one or more mechanisms for manipulating drill head <NUM>. Some embodiments, such as drilling tool <NUM>, <NUM>, <NUM>, <NUM> depicted in <FIG>, include rotational module <NUM>. Some embodiments, such as drilling tool <NUM> depicted in <FIG>, include articulation module <NUM>. Some embodiments of the method may include maneuvering drill head <NUM> using rotational module <NUM>, articulation module <NUM>, or both. Some embodiments of the method may include advancing/retracting drill tool <NUM> using structures (not depicted) above surface <NUM> of wellbore <NUM>. Such maneuvering may position drill head <NUM> so that nozzle <NUM> is directed towards area <NUM> of formation <NUM>.

In some embodiments, this maneuvering may include one or more of rotation in theta Θ (as with rotational module <NUM>), translation in x-y space or x-y-z space (as with articulation module <NUM>), or advancing/retracting drill tool <NUM> in the z-direction (as with structures above surface <NUM> of wellbore <NUM>). In some embodiments, once maneuvering is completed, nozzle <NUM> may be directed toward area <NUM> of formation <NUM>.

Some embodiments of the method may not include step S4, such as those where drilling tool <NUM> lacks manipulation components (such as rotational module <NUM> or articulation module <NUM>); where manipulation occurs while the activating agent is being discharged from nozzle <NUM> (as in step S6); or where advancing drill head <NUM> to area <NUM> of formation <NUM> (as in step S2) places nozzle <NUM> toward area <NUM> of formation <NUM>.

Step S5 is discharging the activating agent on area <NUM> of formation <NUM> using nozzle <NUM>. As discussed previously, upon discharge from nozzle <NUM>, the activating agent may be mixed with a carrying fluid. Further, the activating agent may include an activating material, a transport fluid, or both. Thus, in some embodiments, nozzle <NUM> may discharge the activating agent including the activating material along with the carrying fluid, the transport fluid, or both.

As discussed further, in some embodiments, the activating agent may be discharged from nozzle <NUM> while drill head <NUM> is maneuvered (as in step S6), while nozzle <NUM> is rastered (as in step S6), or both.

Some embodiments of the method may include step S6. Step S6 is maneuvering drill head <NUM> while discharging the activating agent.

In some embodiments, drill head <NUM> may be maneuvered while discharging the activating agent from nozzle <NUM>. In some embodiments, maneuvering drill head <NUM> during discharge of the activating agent may increase the size of area <NUM> of formation <NUM> exposed to the activating agent. In some embodiments, this maneuvering may include one or more of rotation in theta Θ (as with rotational module <NUM>), translation in x-y space or x-y-z space (as with articulation module <NUM>), or advancing/retracting drill tool <NUM> in the z-direction (as with structures above surface <NUM> of wellbore <NUM>).

Some embodiments of the method may not include step S6, such as those where drilling tool <NUM> lacks manipulation components (such as rotational module <NUM> or articulation module <NUM>); those that include multiple nozzles <NUM> in drill head <NUM>; those where nozzle <NUM> rasters the discharge of the activating agent; or those where discharge is performed from a static drill head <NUM> including those where discharging and maneuvering are performed in a stepwise fashion (meaning: maneuver, discharge, maneuver, discharge, and on).

Some embodiments of the method may include step S7. Step S7 is rastering nozzle <NUM> while discharging the activating agent.

In some embodiments, nozzle <NUM> may be rastered while discharging the activating agent. In some embodiments, rastering may discharge the activating agent from nozzle <NUM> in any shape or pattern. In some embodiments, this rastering may be performed by any structure within nozzle <NUM>. In some embodiments, rastering nozzle <NUM> during discharge of the activating agent may increase the size of area <NUM> of formation <NUM> exposed to the activating agent.

Some embodiments of the method may not include step S7, such as those where nozzle <NUM> is unable to raster the discharge of the activating agent; those that include multiple nozzles <NUM> in drill head <NUM>; those where drill head <NUM> is manipulated before or during the discharge of activating agent; or those where discharge is performed from a static drill head <NUM> including those where discharging and maneuvering are performed in a stepwise fashion (meaning: maneuver, discharge, maneuver, discharge, and on).

In some embodiments, steps S6 and S7 may be performed simultaneously. Thus, in some embodiments, nozzle <NUM> may raster the discharge of the activating agent while drill head <NUM> is being manipulated.

In some embodiments, one or more of steps S4, S5, S6, or S7 may be performed in any order. In some embodiments, one or more of steps S4, S5, S6, or S7 may be repeated in any order.

As an illustrative example, one or more embodiments of the method may involve: maneuvering drill head <NUM> so nozzle <NUM> is directed towards area <NUM> (as in step S4); begin discharging the activating agent from nozzle <NUM> onto area <NUM> while drill head <NUM> is stationary (as in step S5); rastering nozzle <NUM> while discharging the activating agent on area <NUM> (as in step S7); maneuvering drill head <NUM> so nozzle <NUM> is directed towards a second area (as in step S4); begin discharging the activating agent from nozzle <NUM> onto a second area while drill head <NUM> is stationary (as in step S5); rastering nozzle <NUM> while discharging the activating agent on the second area (as in step S7); and on.

As a second illustrative example, one or more embodiments of the method may involve: maneuvering drill head <NUM> so nozzle <NUM> is directed towards area <NUM> (step S4), rotating drill head <NUM> in theta Θ while discharging (step S6), and rastering nozzle <NUM> parallel to z-direction while discharging (step S7). Here, as in some embodiments, drill head <NUM> rotates while nozzle <NUM> simultaneously rasters the discharge from nozzle <NUM>, which may increase the size of area <NUM>.

Thus, one having skill in the art will appreciate how any of steps S4, S5, S6, and S7 may be reordered, repeated, and/or combined to introduce the activating agent to area <NUM> of formation <NUM> as desired for a given application.

Some embodiments of the method may include step S8. Step S8 is maneuvering drill head <NUM> so laser head <NUM> is directed towards area <NUM>.

Some embodiments of the method may include maneuvering drill head <NUM> using rotational module <NUM>, articulation module <NUM>, or both. Some embodiments of the method may include advancing/retracting drill tool <NUM> using structures (not depicted) above surface <NUM> of wellbore <NUM>. Such maneuvering may position drill head <NUM> so that laser head <NUM> is directed towards area <NUM> of formation <NUM> that previously was introduced to the activating agent.

In some embodiments, this maneuvering may include one or more of rotation in theta Θ (as with rotational module <NUM>), translation in x-y space or x-y-z space (as with articulation module <NUM>), or advancing/retracting drill tool <NUM> in the z-direction (as with structures above surface <NUM> of wellbore <NUM>). In some embodiments, once maneuvering is completed, laser head <NUM> may be directed toward area <NUM> of formation <NUM>.

Some embodiments of the method may not include step S8, such as those where drilling tool <NUM> lacks manipulation components (such as rotational module <NUM> or articulation module <NUM>); where laser head <NUM> and nozzle <NUM> are configured to interact with the same area <NUM> (as with drilling tool <NUM>); or where manipulation occurs while laser head <NUM> lazes (as in step <NUM>).

Step S9 is lasing at least a portion of area <NUM> using laser head <NUM> in drill head <NUM>.

As discussed further, in some embodiments, laser head <NUM> may laze at least at least a portion of area <NUM> while drill head <NUM> is maneuvered (as in step S10), while laser head <NUM> is rastered (as in step S <NUM>), or both.

Some embodiments of the method may include step S10. Step S10 is maneuvering drill head <NUM> while lazing.

In some embodiments, drill head <NUM> may be maneuvered while laser head <NUM> lazes at least a portion of area <NUM>. In some embodiments, maneuvering drill head <NUM> during lazing may increase the size of area <NUM> of formation <NUM> exposed to the laser. In some embodiments, this maneuvering may include one or more of rotation in theta Θ (as with rotational module <NUM>), translation in x-y space or x-y-z space (as with articulation module <NUM>), or advancing/retracting drill tool <NUM> in the z-direction (as with structures above surface <NUM> of wellbore <NUM>).

Some embodiments of the method may not include step S10, such as those where drilling tool <NUM> lacks manipulation components (such as rotational module <NUM> or articulation module <NUM>); those that include multiple laser heads <NUM> in drill head <NUM>; those where laser head <NUM> rasters the laser during lazing, or those where lazing is performed from a static drill head <NUM> including those where lazing and maneuvering are performed in a stepwise fashion (meaning: maneuver, laze, maneuver, laze, and on).

Some embodiments of the method may include step S11. Step S11 is rastering laser head <NUM> while lazing.

In some embodiments, laser head <NUM> may be rastered while lazing. In some embodiments, laser head <NUM> may raster the laser in any shape or pattern. In some embodiments, this rastering may be performed by any structure within laser head <NUM>. In some embodiments, rastering laser head <NUM> during lazing may increase the size of the portion of area <NUM> of formation <NUM> exposed to the laser.

Some embodiments of the method may not include step S11, such as those where laser head <NUM> is unable to raster the laser; those that include multiple laser heads <NUM> in drill head <NUM>; those where drill head <NUM> is manipulated before or during lazing; or those where lazing is performed from a static drill head <NUM>, including those where lazing and maneuvering are performed in a stepwise fashion (meaning: maneuver, laze, maneuver, laze, and on).

In some embodiments, steps S10 and S11 may be performed simultaneously. Thus, in some embodiments, laser head <NUM> may raster the laser while drill head <NUM> is being manipulated.

In some embodiments, one or more of steps S8, S9, S10, or S11 may be performed in any order. In some embodiments, one or more of steps S8, S9, S10, or S11 may be repeated in any order.

As an illustrative example, one or more embodiments of the method may involve: maneuvering drill head <NUM> so laser head <NUM> is directed towards area <NUM> (as in step S8); begin lazing from laser head <NUM> onto area <NUM> while drill head <NUM> is stationary (as in step S9); rastering laser head <NUM> while lazing at least a portion of area <NUM> (as in step S11); maneuvering drill head <NUM> so laser head <NUM> is directed towards a second area that has been introduced to the activating agent (as in step S8); begin lazing from laser head <NUM> onto at least a portion of the second area while drill head <NUM> is stationary (as in step S9); rastering laser head <NUM> while lazing a portion of the second area (as in step S11); and on.

As a second illustrative example, one or more embodiments of the method may involve: maneuvering drill head <NUM> so laser head <NUM> is directed towards area <NUM> (step S8), rotating drill head <NUM> in theta Θ while lazing (step S10), and rastering laser head <NUM> parallel to z-direction while lazing (step S11). Here, as in some embodiments, drill head <NUM> rotates while laser head <NUM> simultaneously rasters the laser, which may increase the size of the portion of area <NUM> that is lazed.

Thus, one having skill in the art will appreciate how any of steps S8, S9, S10, or S11 may be reordered, repeated, and/or combined to laze at least a portion of area <NUM> of formation <NUM> as desired for a given application.

Furthermore, in some embodiments, one or more of steps S4, S5, S6, S7, S8, S9, S10, or S11 may be performed in any order. In some embodiments, one or more of steps S4, S5, S6, S7, S8, S9, <NUM>, or S11 may be repeated in any order.

In some embodiments, the method may include an alternating repetition of one or more steps of discharging the activating agent on an area <NUM> of formation <NUM> (as in steps S4, S5, S6 and/or S7) followed by one or more steps of lazing at least a portion of area <NUM> (as in steps S8, S9, S10, and/or S11).

In some embodiments, the method may include simultaneous lazing of at least a portion of a second area <NUM> that has been previously introduced to the activating agent (as in steps S8, S9, S10, and/or S11) and discharging the activating agent on a first area <NUM> of formation <NUM> that has not been previously introduced to the activating agent (as in steps S4, S5, S6 and/or S7). Some embodiments of drilling tool (such as drilling tool <NUM> depicted in <FIG>) may be specifically designed for simultaneous lazing from laser head <NUM> and discharging from nozzle <NUM>. Such embodiments may have multiple nozzle(s) <NUM>/laser head(s) <NUM>. Such embodiments may have include nozzle <NUM> and laser head <NUM> arranged to facilitate simultaneous discharging and lazing such as drilling tool <NUM> depicted in <FIG>.

The method of use for some embodiments of drilling tool (such as drilling tool <NUM> depicted in <FIG>) may simultaneously include: rotating according to arrow <NUM> (as with rotational module <NUM>), lazing second area <NUM> (as in steps S8, S9, S10, and/or S11), discharging the activating agent on a first area <NUM> (as in steps S4, S5, S6 and/or S7), and translating in a z-direction according to arrow <NUM> (as with articulation module <NUM> or by advancing/retracting from wellbore <NUM>). Such a spiraling manipulation combined with simultaneous discharge of the activating agent from nozzle <NUM> and lazing from laser head <NUM> may be one method for rapidly interacting with a large area of formation <NUM> within wellbore <NUM>.

In view of the previous disclosures and examples, one having skill in the art will appreciate how any of steps S4, S5, S6, S7, S8, S9, S10, or S11 may be reordered, repeated, and/or combined to introduce the activating agent to area <NUM> and then laze at least a portion of area <NUM> of formation <NUM> as desired for a given application.

<FIG> and <FIG> depict experimental results showing how lazing of a geologic sample is impacted by the addition an activating agent containing an activating material, both wet and dry. The incident beam for each experiment was a <NUM> kW laser and the sample was lazed for <NUM> seconds.

<FIG> are contour plots showing the maximum temperature (in °C) for each sample. An infrared camera captured the temperature of the sample including the incident spot of the laser. Areas of untreated rock sample <NUM> and areas of laser heating <NUM> are indicated. <FIG> are graphs of the temperature (in °C) as a function of elapsed time (in seconds). <FIG> were created using with the same infrared camera data plotted in <FIG> for each sample.

<FIG> and <FIG> reflect a control sample comprising a geologic sample (a block of limestone) without an activating agent. As seen in <FIG>, the maximum temperature of the limestone control is <NUM>. Additionally, <FIG> shows the laser heated a smaller spatial region than seen in <FIG>.

<FIG> and <FIG> reflect a similar block of limestone topped with dry activated carbon (the activating material). First, the heated region in <FIG> is more than four times larger than the heated region in <FIG> for of a sample without activated carbon. Additionally, the maximum temperature of the limestone with the activated carbon is <NUM>, which is more than double the maximum temperature for a sample without activated carbon as seen in <FIG>. Further, with activated carbon, the limestone reaches the maximum temperature in less than <NUM> seconds, compared to <NUM> seconds for the sample without activated carbon. Finally, after reaching the maximum temperature, the activated carbon sample essentially maintains this temperature for more than <NUM> seconds compared with less than <NUM> seconds for the control.

<FIG> and <FIG> reflect the impacts of the laser on a similar block of limestone coated with a mixture of activated carbon (the activating material) and water (such as might be used in a carrying fluid or a transport fluid). The heated area in <FIG> is similarly sized to that of the dry activated carbon as shown in <FIG>, and both are much larger than the control as depicted in <FIG>. After laser exposure, the maximum temperature of the limestone, activated carbon, and water is <NUM>, which is slightly less than the maximum temperature for the dry activated carbon (<NUM>) but still much higher than the maximum temperature for the control (<NUM>). Similarly, the maximum temperature for the sample in <FIG> is reached in <NUM> seconds, which is slower than the dry activated carbon (<NUM> seconds) but faster than the control (<NUM> seconds). Finally, in <FIG>, the maximum temperature is essentially maintained for about <NUM> seconds, which is shorter than the dry activated carbon (<NUM> seconds) but longer than the control (less than <NUM> seconds).

The results depicted in <FIG> and <FIG> confirm that either wet or dry activated carbon increase the maximum rock temperature by at least <NUM> times compared with limestone without activated carbon. Furthermore, these experiments prove activated carbon significantly improves the heat transfer into limestone for a <NUM> kW laser, which is a much lower powered laser than is typically used for wellbore stimulation.

Claim 1:
A drilling tool for drilling in a formation, the drilling tool comprising:
an optical fiber (<NUM>) having a laser input end (<NUM>) and a laser output end (<NUM>);
a laser source (<NUM>) optically connected to the laser input end (<NUM>);
an activating agent conduit (<NUM>, <NUM>) having an activating agent inlet (<NUM>, <NUM>) and an activating agent outlet (<NUM>, <NUM>) ;
an activating agent source (<NUM>, <NUM>, <NUM>) connected to the activating agent inlet (<NUM>, <NUM>) that supplies an activating agent comprising an activating material, the activating material comprising at least one of activated carbon, graphite, carbon black, carbon nanotubes, nanoparticles, paint, dye, molybdenum disulfide, a transition metal chalcogenide, or a metamaterial; and
a drill head (<NUM>), comprising:
a nozzle (<NUM>) connected to the activating agent outlet (<NUM>, <NUM>) that discharges the activating agent on an area of the formation (<NUM>), and
a laser head (<NUM>) optically connected to the laser output end (<NUM>) and arranged to lase at least a portion of the area of the formation (<NUM>) having the activating agent.