EA045945B1 - TOOL, UNIT AND METHOD FOR IN-WELL DETERMINATION OF MECHANICAL CHARACTERISTICS OF ROCK - Google Patents

Description

Cross reference to related applications

The patent application claims priority to Italian Patent Application No. 102019000015584, filed on September 4, 2019, the entire contents of which are incorporated herein by reference.

Technical field

The invention relates to oil drilling and, more particularly, to a testing tool, testing assembly and method for using them in measuring selected mechanical properties of rocks in a well.

Prior Art

It is useful, especially in exploration wells, to collect core samples for analysis in the laboratory. Such wellbore formation samples can provide useful performance data that can be used, for example, to evaluate wellbore stability.

In this regard, when carrying out oil and gas operations, cores are often taken from the formation at various stages of exploration and production. Core samples are useful because they provide an actual sample of the well's formation from which geologists can analyze the characteristics of the well. A core sample is often taken during the drilling of exploration, appraisal, development or injection wells. In this regard, the core sample may be taken at specific intervals according to the well plan, or may be taken on an ad hoc basis when the engineer or geologist requires the data to make decisions.

In fig. 1A shows a typical arrangement of the formation 100 in which the well 101 is drilled. It may be desirable to take core samples from the end region 102 of the well 101, for example, at the first core sample location 103 or at a location away from the end 102 of the well 101, and in the side wall wells 101, for example, at the second location 104 of the core sample. Typically, a core sample 105, which may be taken from a first or second core sample location, is brought to the surface for analysis. In this regard, in FIG. 1B shows a known location of the coring tool 106 within, but not at the end of, the drill string 107. The drill string 107 has a drill bit 108, and one or more core samples may be taken from a coring location 109 that is remote from the drill bit 108. Drilling may be stopped for a period of time to retrieve the core sample and then continued.

There are a number of commercial offers in the field of core samplers. For example, oilfield services company Baker Hughes offers a conventional HT30 Max Core Barrel System (RTM) core tool that can collect large core samples downstream and bring them to the surface for analysis. Another oilfield services company, Halliburton, offers a sidewall core sampler, the RSCT (RTM), which collects core samples from the sidewall of a well and retrieves them for analysis. Various companies also offer equipment for core analysis, both in a stationary laboratory and for testing core samples at the drilling site. In this regard, Epslog's Wombat core analysis tool is used to determine core properties and can be used in the laboratory or at the well site.

There are several problems with collecting core samples for testing using the traditional method. First, when a core sample is removed from the formation and transported to the surface, even if it is not taken to a laboratory located far from the well site, it is no longer in the original stress state in which it was found in its natural location. This may adversely affect the quality of the wellbore stability model that can be obtained from the analysis of the core sample. In addition, the core sample is often damaged and/or excessively cracked, so that analysis of the sample may not be possible. This increases wasted time as another sample must be obtained.

There is also a significant cost and time associated with retrieving the sample and transporting it to a laboratory for testing, especially if the laboratory is located several thousand kilometers from the sampling site. Removing and transporting the sample must be done with care to preserve its integrity, which again requires time and money. In addition, other operations may need to be suspended while the core sample is obtained, transported, and analyzed.

As with all oilfield operations, it is desirable from a safety perspective to reduce the number of manual tasks involved. Coring operations typically require lowering a core sampler into the hole, which requires assembly of the entire drill string, and then retrieving the core sample by disassembling the entire drill string. Both assembly and disassembly of the drill string are typically labor-intensive and potentially hazardous operations. Additionally, transporting core samples for analysis can pose logistical security challenges. Therefore, from a safety point of view, it is desirable to reduce the number of drill strings collected and core samples transported.

The invention is intended to solve one or more of these problems.

In this regard, to the parameters characterizing rocks, which are usually calculated on

- 1 045945 based on the analysis of core samples, include uniaxial (or otherwise unlimited) compressive strength and the angle of internal friction. Uniaxial (unconfined) compressive strength is a measure of the strength of a material and is defined in the Schlumberger Oilfield Glossary as the maximum axial compression that a straight cylindrical specimen of material can withstand under unconfined conditions, i.e. when the limiting voltage is zero. It is also known as the uniaxial compressive strength of a material because the application of compressive stress occurs along only one axis, the longitudinal axis of the specimen. The angle of internal friction is a measure of the ability of a unit of rock or soil to withstand shear stress. It is the angle measured between the normal force and the resultant force at which failure occurs in response to tangential stress. The friction coefficient is equal to the tangent of the internal friction angle.

When the formation is under stress, for example under significant pressure, it is desirable to measure the uniaxial compressive strength and the angle of internal friction in situ, that is, where the formation is subjected to stress. As mentioned above, retrieving a core sample has disadvantages because changes in local conditions change the stress state of the sample after it is removed from the formation, which can distort the measurement results.

The invention is aimed at overcoming the above-mentioned problems with core sampling and determination of the angle of internal friction or uniaxial compressive strength, especially for formations under stress.

Disclosure of the Invention

In a first aspect of the invention, there is provided a downhole tool for conducting downhole testing to determine the characteristics of rocks in a test section of a formation, comprising at least one surface preparation cutter and at least one testing cutter, wherein the at least one surface preparation cutter is adapted to remove debris between the test area and the tool in preparation for interaction of at least one test cutter with the test area. The tool allows for downhole testing to characterize rock formations, rather than taking a sample of the formation being tested and bringing it to the surface for testing in the traditional manner. This provides significant benefits, including maintaining the specimen in its original stress state, ensuring that the specimen is not damaged and/or excessively degraded before testing, increasing production time by eliminating the need to lift the specimen to the surface, increasing operational safety by eliminating the need to have tools on the well site to process the core sample and eliminate the need to lower tools in and out of the well to obtain a sample.

In a preferred embodiment, at least one surface preparation cutter is further adapted to remove a layer of the test area. This allows debris/mud cake to be removed from the test area so that the area can be effectively tested with a test cutter. Alternatively, the surface preparation cutter may remove the layer of the test section to remove a damaged or fractured area of the formation that was damaged by the drill bit during drilling of the well. This allows the formation that is not intended to be tested to be removed and frees up space for the appropriate test area on which the test cutter can conduct tests.

In a preferred embodiment, the at least one surface preparation cutter is preset to remove a layer of substantially 20 mm in depth. Therefore, removing about 20 mm of formation using a _121/4 inch (31.1 cm) diameter drill bit is usually sufficient to remove any damaged formation that is not suitable for testing with the test cutter. The achievable depth will vary depending on the size of the bit and the corresponding diameter of the hole being drilled or tested.

In a preferred embodiment, the at least one test cutter is substantially blunt for conducting the internal friction angle test. Essentially, a blunt cutter allows for internal friction angle testing, which is typically done with a core sample removed and raised to the surface.

In a preferred embodiment, the at least one test cutter is substantially sharp to conduct an unconfined compressive strength test. The sharp cutter allows for unconfined compressive strength testing to be performed in the hole rather than having to separate the core sample and bring it to the surface for unconfined compressive strength testing.

In a preferred embodiment, the at least one test cutter comprises a sharp cutter for conducting an unconfined compressive strength test and a blunt cutter for conducting an internal friction angle test. The use of both sharp and blunt cutters allows for unconfined compressive strength and friction angle tests to be performed in the well, rather than having to bring the core sample to the surface to perform both unconfined compressive strength and friction angle tests on the formation. .

- 2 045945

In a preferred embodiment, the surface preparation cutter is configured to move along a first circular path to prepare the surface. Moving the surface preparation cutter in a circular path clears the area to be tested with the test cutter. In addition, rotational motion along a circular path is relatively easily and reliably achieved when the surface preparation cutter is driven by a motor, since the motor can rotate the shaft on which the surface preparation cutter is positioned so that it cuts a circular path without the use of additional links or guides necessary to move the cutter along various trajectories.

In a preferred embodiment, the test cutter is configured to move along a second circular path to perform one or more of an internal friction angle test or a uniaxial (unconfined) compressive strength test. Moving the test cutter along a second circular path allows testing to be performed on the same circular path that was cleared by the surface preparation cutter, or on a smaller circular path within the larger circular path that was cleared by the surface preparation cutter.

It is convenient when the second circular path is within the circumference of the first circular path. This ensures that the test cutter path is directed only towards the test formation, which has been cleared by the cutter to prepare the surface from debris or cracked formation. This results in more accurate test results for the desired formation.

In a preferred embodiment, a sharp cutter and a dull cutter are integrated into a single test cutter. This allows a single test cutter to perform internal friction angle and unlimited compressive strength tests. This offers advantages over configurations in which the sharp cutter and the dull cutter are separate cutters. For example, there is no need for additional components that each type of cutter carries. Reducing the number of components offers advantages in terms of ease of manufacture and increased reliability. In a preferred embodiment, the test cutter has a profiled beveled cutting edge.

Conveniently, the at least one surface preparation cutter comprises a plurality of surface preparation cutters and the at least one testing cutter comprises a plurality of test cutters. This allows for faster surface preparation and/or simultaneous testing of multiple areas, and/or more accurate results, since the measured force along the axis of rotation of the test cutter and the cutting torque value can be taken from each of the test cutters and averaged, or Conflicting data can be eliminated, resulting in a more reliable test result. Using multiple surface preparation cutters reduces the load on each individual surface preparation cutter.

Conveniently, the at least one surface preparation cutter and the at least one testing cutter are positioned to be relatively movable so that they can be alternately positioned in active cutting and passive retracted states. This allows the surface preparation cutters and the testing cutters to move between the cutting state and the retracted state, so that surface preparation and testing can be performed alternately. In a preferred embodiment, the downhole tool is further configured such that the at least one surface preparation cutter can be selectively moved from a first tool position for removing debris to a second tool position allowing the at least one test cutter to conduct the test. This allows the tool to perform both surface preparation and testing without the need to lower a new tool into the hole or even move the drill string to bring another tool to the formation. This saves time during the test operation.

Conveniently, the downhole tool is further configured such that the at least one test cutter can be selectively moved from said first position, in which the at least one surface preparation cutter removes debris, to said second position of the at least one test cutter for carrying out the test. This allows the tool to perform both surface preparation and testing without the need to lower a new tool into the hole or even move the drill string to bring another tool into the formation. This saves time during the test operation.

In a preferred embodiment, the at least one surface preparation cutter and the at least one testing cutter are mechanically coupled such that movement of the surface preparation cutter from a first tool position to a second tool position causes movement of the test cutter from the first position to a second position . The use of mechanical coupling allows the surface preparation cutter and test cutter to be installed in one tool rather than different tools within the downhole assembly, which would require moving the drill string and downhole drill string assembly after the surface preparation cutters have prepared the surface. to bring the test cutters to the test area to be tested.

- 3 045945

Conveniently, the at least one surface preparation cutter and the at least one testing cutter are configured to move relative to each other using a hydraulic piston device. The use of a hydraulic piston device ensures reliable movement of the cutters relative to each other.

In a preferred embodiment, the downhole tool further comprises a core drill bit adapted to move at least one surface preparation cutter and at least one testing cutter to the area being tested. This makes it possible to install both types of cutters on one component, i.e. on a core drill bit that can be moved to the area being tested rather than moving each cutter individually. This provides a supporting base from which the cutters can extend for surface preparation and testing.

In a preferred embodiment, the core drill bit is moved in the test area at an angle relative to the axial direction of the well. Conveniently, the core drill bit is moved across the test area in a direction substantially perpendicular to the axial direction of the borehole. In this case, the cutters for surface preparation and the cutters for testing approach the formation at right angles.

In another aspect of the invention, there is provided a downhole tool assembly comprising the aforementioned tool, wherein the assembly has a support structure within which components of the tool can be isolated from the downhole environment, wherein one or more characteristics of the environment within the support structure are adjusted in accordance with downhole conditions. Adjusting the environmental characteristics within the supporting structure allows the characteristics to be balanced to ensure safe and accurate operation of the tool, while ensuring that the tool is not exposed to hazardous conditions that could damage the tool, particularly its seals or other delicate components.

In a preferred embodiment, the one or more characteristics include one or more of pressure and temperature. Changing these characteristics can significantly affect the effectiveness of the components. Balancing or controlling pressure and temperature ensures proper operation of the instrument.

It is convenient when the core drill bit is designed to be retractable from the supporting structure to the outside of the supporting structure. This allows the core drill bit to be moved to the area being tested for surface preparation or testing.

In a preferred embodiment, the downhole tool assembly further includes a compensator configured to pump fluid into or out of the support structure such that the pressure within the support structure is balanced with a local external pressure of the support structure. This ensures safe and accurate operation of the tool by ensuring that internal pressure does not become dangerous and/or damage or negatively affect the performance of tool components.

In a preferred embodiment, the downhole tool assembly further includes a deployable immobilizer for securing the assembly within the wellbore. This provides a fixation against which forces can be applied and measured either during surface preparation or formation testing. Without immobilizers, the tool will move in the wellbore, making it difficult to perform necessary surface preparation or testing.

In a preferred embodiment, the immobilizer comprises one or more shoe components to abut the borehole wall to create a locking response during testing. Shoe components provide clamping to stabilize the tool.

The downhole tool assembly may further comprise connecting means for connection to drill pipe or downhole drill string assembly tools. This allows downhole tools to be assembled in the drill string for running down to the test area. The downhole tool assembly in the drill string allows the downhole tool to be positioned where it can perform tests between each stand of drill pipe added, for example, during the drilling operation, or on demand during the drilling operation when necessary. In addition, it allows the downhole tool to be coupled to other components and tools in the downhole drill string assembly, allowing it to be run, for example, directly behind other measurement devices, which is likely the desired location where rock characterization data should be obtained.

In a preferred embodiment, the downhole tool assembly further includes a power module for supplying power to a motor to move the core drill bit toward the test site. This provides the benefit of a reliable system for moving the core drill bit to the test site and ensures that the core drill bit can be moved to the test site if necessary.

In a preferred embodiment, the power module is a battery

- 4 045945 battery. This has the advantage of independent rotation of the turbine to drive the motor from the circulation of drilling fluid through the system, allowing testing to be carried out in the absence of fluid circulation. In addition, the use of a rechargeable battery allows the use of a tool that does not require constant power from the surface, which has significant disadvantages and which may be unreliable in practice.

Conveniently, the downhole tool assembly further includes at least one force sensor adapted to detect a first force on the at least one surface preparation cutter. The advantage of using a force sensor is that it can provide a reaction force measurement to confirm that the surface preparation cutter has engaged the debris/mud cake to be cleaned or that it has engaged the formation, allowing the cutter to be accurately moved to surface preparation when preparing the test area for testing.

In a preferred embodiment, the downhole tool assembly further includes at least one force sensor and at least one torque sensor adapted to detect a second force and torque on the at least one test cutter. This makes it possible to use the measured force along the axis of rotation of the test cutter and the measured cutting torque to determine the angle of internal friction or unconfined compressive strength.

Conveniently, the downhole tool assembly further comprises processing means for calculating the angle of internal friction or unconfined compressive strength based on the second force along the axis of rotation of the test cutter and the measured cutting torque. This allows the tool to calculate the angle of internal friction or unconfined compressive strength directly, without the need to send the data to the surface for processing. This provides many benefits since transmission to the surface can be problematic due to significant transmission times, the possibility of data loss or degradation during transmission due to noise or interference. Data processing in the tool is free from these shortcomings. In addition, the amount of processed data may be significantly less than the amount of raw force data, so transmitting only processed data may be faster than transmitting raw force data. Alternatively, raw or processed data can be stored in the tool for the duration of the run and unloaded from the tool when the tool is raised to the surface at the end of the run.

In yet another aspect of the invention, there is provided a method of conducting tests to determine the characteristics of rock at a test site in a wellbore, the method comprising the steps of: placing a downhole tool or downhole tool assembly, as defined above, in the wellbore; moving at least one cutter to prepare the surface to the test area to remove debris located along the path of movement; moving at least one test cutter to the test area; and interact the test cutter with the test area. This method allows for downhole characterization of the rock rather than taking a test sample of the formation and bringing it to the surface for testing in the traditional way. This provides significant benefits, including maintaining the sample in its original stress state, ensuring that the sample is not damaged and/or excessively degraded before testing, increasing production time by eliminating the need to transport the sample to the surface, increasing operational safety by eliminating the need to use tools at the well site to work with the core sample and eliminate the need to lower tools into and out of the well to deliver the core sample to the surface.

In a preferred embodiment, once positioned downhole at the test site, the tool assembly is pressure-equilibrated such that one or more encased measurement components are at a pressure that corresponds to the local ambient pressure. Equalizing the pressure within the tool promotes safe and accurate operation of the tool by ensuring that the tool is not exposed to hazardous conditions that could damage or adversely affect the tool, particularly seals or other delicate tool components.

In a preferred embodiment, the method further includes the steps of: interacting a blunt cutter with the test area; and measure the force along the axis of rotation of the blunt cutter and the cutting torque. This provides measurements that can be used to calculate rock characteristics, particularly the angle of internal friction.

In a preferred embodiment, the method further includes the following steps: interacting a sharp cutter with a test area; and measure the force along the axis of rotation of the sharp cutter and the cutting torque. This provides measurements that can be used to calculate the properties of rocks, in particular they can be used to calculate unconfined compressive strength.

- 5 045945

In a preferred embodiment, the method further includes the following steps: calculating the angle of internal friction based on measurements made using a blunt cutter. This has the advantage that the core sample does not need to be removed and subsequently transported to the surface for analysis to determine the angle of internal friction.

In a preferred embodiment, the method further includes the following steps: calculating the uniaxial (unconfined) compressive strength based on measurements made using a sharp cutter. The advantage of this approach is that it does not require the removal of a core sample and its subsequent transportation to the surface for analysis to determine uniaxial (unconfined) compressive strength.

In yet another aspect of the invention, there is provided a cutter for use in a downhole tool, downhole tool assembly, or method as defined above, having a profiled beveled cutting edge such that it can function as either a blunt or a sharp cutter. In a preferred embodiment, the bevel has a radius of from 0.1 mm to 0.5 mm.

Brief description of drawings

Embodiments of the invention will now be described by way of example with reference to the drawings.

In fig. 1A is a schematic diagram of a prior art well structure drilled into a formation;

in fig. 1B is a prior art drill string containing a known tool for coring a well drilled into a formation;

in fig. 2 illustrates a rock characterization tool according to one embodiment of the invention, wherein the rock characterization tool is assembled within a downhole drill string assembly and located within a wellbore;

in fig. 3A shows an end view of a core drill bit of a rock characterization tool according to one embodiment of the invention;

in fig. 3B shows the core drill bit shown in FIG. 3A, and a side view of a rock characterization tool installed in a borehole and removing debris from the test area;

in fig. 4 - core drill bit according to one of the embodiments of the invention;

in fig. 5A illustrates a core drill bit according to yet another embodiment of the invention;

in fig. 5B is an alternative embodiment in which the core drill bit is advanced by an inclined cam;

in fig. 5C illustrates an alternative embodiment in which the core drill bit is advanced by a second motor connected by a worm gear;

in fig. 5D is an alternative embodiment in which the core drill bit is advanced by a bit holder connected to the core drill bit by a helical cam;

in fig. 5E illustrates an alternative embodiment in which the core drill bit is advanced by a worm gear coupled to a second motor;

in fig. 5F is an alternative embodiment in which the core drill bit is advanced by a hydraulic device;

in fig. 5G is an alternative embodiment in which the individual cutters are driven forward by a piston driven by a worm gear;

in fig. 5H - an alternative option in which each cutter has a dedicated hydraulic actuator;

in fig. 6 is a schematic illustration of a rock characterization tool assembly in one embodiment of the invention;

in fig. 7 shows two views of the main components of the rock characterization tool shown in FIG. 6;

in fig. 8 is a rock characterization tool shown in FIG. 7, sectional view;

in fig. 9A illustrates a rock characterization tool according to the invention being lowered into a borehole to conduct tests on a test section of a formation in accordance with one aspect of the invention;

in fig. 9B is the rock characterization tool shown in FIG. 9A, located at the test site for performing formation tests;

in fig. 10A is a side view of an example of a sharp incisor;

in fig. 10B is an example of the sharp cutter shown in FIG. 10A, front view;

in fig. 10C is an example of the sharp cutter shown in FIG. 10A, top view;

in fig. 10D is an example of the sharp cutter shown in FIG. 10A, isometric view;

in fig. 11A is a side view of an example of a blunt cutter;

- 6 045945 in Fig. 11B is an example of the blunt cutter shown in FIG. 11A, front view;

in fig. 11C is an example of the blunt cutter shown in FIG. 11A, top view;

in fig. 11D is an example of the blunt cutter shown in FIG. 11A, isometric view;

in fig. 12A is a side view of an example of a beveled cutter;

in fig. 12B is an example of the beveled cutter shown in FIG. 12A, front view;

in fig. 12C is an example of the beveled cutter shown in FIG. 12A, top view.

Embodiments of the Invention

As discussed above, FIG. 1A and 1B show known designs for taking core from a formation for analysis at the surface.

In contrast, the invention relates to a method for analyzing rock characteristics in a borehole, as well as a rock characterization tool and assembly that can be used to implement the method.

In this regard, as shown in FIG. 2, a rock characterization tool 200 is adapted to be lowered into a wellbore as part of a downhole drill string assembly 201. In the described embodiment, the rock characterization tool 200 is adapted to be positioned approximately 35-45 meters from the drill bit 202. Greater or shorter distances from the drill bit may be used depending on the configuration of the drill string, the formations being drilled, and the data being collected. In this regard, there may be from several hundred to several thousand meters of drill string behind the downhole drill string assembly 201. The downhole drill string assembly 201 typically includes, in addition to the drill bit 202, measurement-while-drilling (MWD) tools 204, logging-while-drilling (LWD) tools 205, and/or other equipment located behind the drill bit 202.

In the described embodiment, the rock characterization tool 200 is a stand-alone module, however, it should be understood that the rock characterization tool 200 may be integrated into another component of the downhole drill string assembly 201, such as, for example, the IPB tool 204 or the tool 205 KVB.

If the rock characterization tool 200 is a stand-alone module, it is configured to be connected to other components of the drill string 203. This is typically accomplished using a standard threaded connection, although any other connection means known in the art may be used. technology.

Likewise, the rock characterization tool 200 is configured to be communicated with while being used in the drill string and in the wellbore. To provide surface communications, the rock characterization tool 200 of this embodiment may utilize mud pulse telemetry. It will be understood that the rock characterization tool 200 may use any known communication technology to communicate with the surface, including, for example, signal conductive drill pipe.

The rock characterization tool 200 includes a core drill bit 300 shown in FIG. 3A, which, unlike prior art designs, does not extract a core sample from the formation. Instead, the core drill bit 300 includes one or more surface preparation cutters 301 and one or more testing cutters 302. Surface preparation cutters 301 are used to remove rock layers 303, as shown in FIG. 3B, which were deposited on the inner walls of the well. Such debris may include, but is not limited to, particles of drilling fluid that settle as a coating within the wellbore, commonly known as mud cake. The surface preparation cutters 301 are configured to cut through the rock debris 303 and expose the surface of the actual formation 304, that is, the wellbore, on which the test cutters 302 can perform tests. In this regard, FIG. 3B shows how the surface preparation cutters 301 cleared the rock debris so that the test cutters 302 were on the surface of the formation.

The surface preparation cutters may further cut into the formation 304, for example, to a depth of about 20 mm using a 31.1 cm diameter drill bit, to remove a portion of the formation that may have been damaged or otherwise adversely affected during the drilling process. This allows the test cutters 302 to test on an intact and more representative formation to obtain more accurate and reliable results. In this regard, the surface preparation cutters 301 remove debris from the test area on which the test cutters 302 will then conduct tests. The surface preparation cutters 301 may clear a larger area, such as a large circular area, with the test cutters 302 configured to interact with the formation 304 in a more focused area, such as a smaller circular area within the larger cleared area that has been cleared cutters 301 for surface preparation.

In the embodiment shown in FIG. 3A, surface preparation cutters 301 and testing cutters 302 are mounted on the same core drill bit 300, and each can be selected for use depending on need. 200 definition tool

- 7 045945 characteristics of rocks can be adjusted to allow the selection of the required cutters, i.e. either surface preparation cutters 301 or testing cutters 302, in either a passive configuration or an active configuration.

In this regard, the passively configured rock characterization tool 200 allows the cutters 301, 302 to be selected and switched without a dedicated actuator, typically using the gearing already present in the rock characterization tool 200 to rotate it. . The drive mechanism of the rock characterization tool 200 may have only one motor, and the gear train may include reduction gear and/or reverse gear configurations to allow surface preparation cutters 301 and testing cutters 302 to rotate clockwise with at different speeds/torques and counterclockwise at different speeds/torques. As is clear from FIG. 3A, in this configuration, the surface preparation cutters 301 are arranged such that they effectively perform surface preparation cuts when rotating in direction A and are ineffective in performing surface preparation cuts when rotating in direction B. On the other hand, the test cutters 302 effectively perform their test cuts or scratches when rotating in direction B and are ineffective when making test cuts or scratches when rotating in direction A.

In the embodiment discussed here, the core drill bit 300 can therefore effectively cut through the rock debris 303 while rotating in direction A, engaging the surface preparation cutters 301 with the rock debris 303 to be removed. After the core drill bit 300 has advanced to the position shown in FIG. 3B, the direction of rotation of the core drill bit 300 can be changed to direction B, thereby rotating the test cutters 302 in the direction required to perform their desired function. Each set of cutters may protrude slightly when rotated in the direction required to bring the cutters into contact with the formation or rock fragments. Torsion springs (not shown) can help ensure that one pair of cutters protrudes when needed while the other does not protrude.

In such an additional embodiment using a torsion spring, the surface preparation cutters 301 may be positioned to extend beyond the test cutters 302 in the first configuration, and the test cutters 302 may extend beyond the surface preparation cutters 301 in the second configuration.

The test cutter knives 302 may be configured such that when the core drill bit 300 is rotated in a first direction, a substantially blunt cutting edge is applied to the formation, and when the core drill bit 300 is rotated in a second direction opposite to the first direction, a substantially dull cutting edge is applied to the formation. essentially a sharp cutting edge.

Therefore, a blunt cutting edge is required to measure the angle of internal friction, while a sharp cutting edge is required to measure the unconfined compressive strength.

In fig. 4 is a sectional view showing a portion of a rock characterization tool assembly containing an active mechanism for moving surface preparation cutters 401 and test cutters 402 to the front of a core drill bit 400 ready for surface preparation or testing, respectively. The core drill bit 400 is typically rotatable via a gear train 403, 404, 405.

In this regard, the active mechanism includes a first screw 406A and a second screw 406B. Each of the first and second screws 406A, 406B has corresponding helical thread portions 407A, 407B that are arranged such that clockwise rotation and linear movement in direction C of the first screw 406A causes counterclockwise rotation and linear movement in direction D of the second screw 406B. The core drill bit 400 typically can be driven by a gear train 403, 404, 405 using a motor 408. The first screw 406A is driven by the motor 409, which does not need to drive the second screw 406B due to the previously described arrangement of interacting screw threaded sections 407A, 407B. The first screw 406A is attached to the cutter 401 for surface preparation, and the second screw 406B is attached to the cutter 402 for testing. Thread pitch, shaft length, etc. can be selected depending on requirements. The described structure is used to move each cutter 401, 402 into position when they are required and to retract the cutters 401, 402 when they are not required. In the described embodiment, only one surface preparation cutter 401 and one test cutter 402 are shown, however, it should be understood that any number of surface preparation cutters 401 and test cutters 402 can be used.

The mechanical extension and retraction of the first screw 406A and the second screw 406B may equally be replaced by electrically or hydraulically driven designs.

In fig. 5A shows an alternative embodiment of a core drill bit 500 that can be used in a rock characterization tool, such as, for example, the rock characterization tool shown in FIG. 4. In this embodiment, the core drill bit 500 uses an active mechanism to move the cutter 501 to prepare

- 8 045945 surface and cutter 502 for testing to the required position and return to the original position. The core drill bit 500 has a central shaft 503 that is coupled to a first insert 504 at its first end and to a hydraulically driven piston 505 at its opposite end. The insert 504 includes a surface preparation cutter 501 and is movable relative to the remainder of the core drill bit 500 in direction E to advance the surface preparation cutter 501 forward for use. The test cutter 502 is mounted in the arm 507 of the core drill bit 500. When the test cutter 502 needs to be advanced after using the cutter 501 for surface preparation, the insert 504 can be retracted by moving the hydraulic piston and spring 506 back, displacing the insert 504 back into retracted position. position. As an alternative to a hydraulic piston, the movement of the insert 504 may be controlled and accomplished by other suitable mechanisms, such as electrical means.

In the embodiment shown in FIG. 5A, only one surface preparation cutter 501 and one testing cutter 502 are shown, however, it should be understood that it is possible to modify the embodiment to provide both a plurality of surface preparation cutters 501 and a plurality of testing cutters 502. One such modification would be to provide a plurality of surface preparation cutters 501 on the insert and, likewise, a plurality of test cutters 502 on the body of the core drill bit 500. An alternative modification would be to provide multiple inserts, each carrying one or more cutters. 501 for surface preparation. It should be understood that the surface preparation cutters 501 and testing cutters mounted on the insert 504 and the core drill bit 500, respectively, can be used in a reverse arrangement, i.e. testing cutters 502 may be mounted on insert 504 and surface preparation cutters may be mounted on arm 507 of core drill bit 500.

Additionally, the test cutters 502 may have an edge configuration similar to that previously described with reference to FIGS. 3, i.e. with a blunt cutter edge facing the formation when the core drill bit 500 is rotated in a first direction, and a sharp cutter edge facing the formation when the core drill bit 500 is rotated in a second direction opposite to the first direction.

Alternatively, the configuration may include three separate and distinct cutters or three sets of cutters. The first set of cutters are surface preparation cutters, the second set are blunt cutters for measuring internal friction angle, and the third set are sharp cutters for measuring uniaxial compressive strength. Surface preparation cutters can be mounted on the arm of the core drill bit as described above. The blunt and sharp edged cutters may be mounted on separate first and second inserts, which may be moved independently of each other using a design similar to the embodiment described with reference to FIG. 5A.

Regardless of how the cutter is deployed, either by reversing the direction of rotation of the core drill bit and/or by bringing another cutter to the front, using surface preparation cutters along with blunt and sharp cutters on the same core drill bit allows the same general area to be tested formation for uniaxial (unlimited) compressive strength and the angle of internal friction.

In fig. 5B-5H show alternative options for moving the core drill bit and cutters out of the tool so that they can perform their functions in the wellbore. In these embodiments, the core drill bit and surface preparation and testing cutters are designated 500, 501, and 502, respectively, for ease of reference, but it should be understood that the embodiments shown in FIGS. 5B-5H are not limited to the specific features of the embodiment shown in FIG. 5A.

In fig. 5B shows an electromechanical subsystem in which the cutters 501, 502 are rotated by a first motor 508. The movement of the core drill bit 500 is provided by a second motor 509 driving a tilt cam 510. The second motor 509 may be coupled to the tilt cam 510 by a worm gear 511 or any other a suitable connection for converting the rotational motion of the second motor 509 into translational motion of the inclined cam 510 in the F direction, which causes the core drill bit 500 to advance in the E direction.

In fig. 5C shows another alternative embodiment in which the core drill bit 500 is driven by a second motor 509a in combination with a worm gear 511a coupled to the core drill bit 500. As shown in FIG. 5C, the second motor 509a is also configured to move the first motor 508a, which drives the cutters 501, 502, so that the core drill bit 500 and the first motor 508a are both jointly moved to a desired position by the second motor 509a and the worm gear 511a. It should be understood that the worm gear 511a is selected to convert the rotational motion of the second motor 509a into the translational motion of the core drill bit 500 and the first motor 508a, but any suitable mechanism may also be used.

In fig. 5D shows another alternative embodiment in which the first electric motor

- 9 045945 the gate 508b is connected to the core drill bit 500 for the purpose of actuating, i.e. rotation of the cutters 501, 502, and a second motor 509b is coupled to a bit holder 512, which is a support member configured to hold or enclose a portion of the core drill bit 500. The bit holder 512 is engaged with the helical cam 513 so that rotation The bit holder 512 by the second motor 509b will cause the core drill bit 500 to advance. This embodiment allows the core drill bit 500 to advance and the core drill bit 500 to rotate.

In fig. 5E shows an alternative embodiment in which the first motor 508c is coupled to the core drill bit 500 via a bit holder 512c. In this embodiment, the core drill bit 500 rotates due to the bit holder 512c being rotated by the first motor 508c. A second motor 509c is used to move the core drill bit 500 by driving a worm gear 511c that is coupled to the core drill bit 500.

In fig. 5F shows an alternative which is an electromechanical and hydraulic system. In this embodiment, the first motor 508d is coupled to the core drill bit 500d to rotate the core drill bit 500d. The core drill bit 500d is moved by a hydraulic piston, with a second electric motor 509d driving a worm gear 511d, which in turn moves the first piston 514 within the first hydraulic cylinder. 515. The first hydraulic cylinder 515 is connected to a similar second hydraulic cylinder 516 within the core drill bit 500d. The corresponding second piston 517 in the second hydraulic cylinder 516 is fixed, but the core drill bit 500d is configured to move freely relative to the fixed second piston 517. When the first piston 514 within the first hydraulic cylinder 515 moves, hydraulic fluid is pumped to one side of the second hydraulic cylinder 516 and is pumped out from the other side of the second hydraulic cylinder 516, causing the core drill bit 500d to move outward or inward relative to the stationary second piston 517.

In fig. 5G shows another alternative embodiment in which various cutters (i.e., surface preparation cutters 501 and testing cutters 502) are located on separate dedicated bits that are mounted on a slide structure 518. The slide structure 518 may be driven by a worm gear 519 , driven by electric motor 520 or any other suitable means. The cutters 501, 502 may be rotated by the rotation motor 521 and moved forward by the advance motor 522, which in the present embodiment advances the actuator 523 to engage the desired cutter 501, 502 via a worm gear 524.

In an alternative embodiment, the sliding structure 518 may be a rotating carousel, in which case the worm gear 519 shown in FIG. 5G, can be replaced with a suitable device for rotating the carousel so that the correct cutter 501, 502 can be selected.

In fig. 5H shows an alternative embodiment in which a dedicated hydraulic actuator is used for each cutter. In the embodiment shown in FIG. 5H, only two cutters 501, 502 are used, however it should be understood that in this embodiment any number of cutters can be used with corresponding hydraulic actuators adapted for this purpose for each cutter. As shown in FIG. 5H, the first cutter 501 is provided with a first hydraulic actuator 525, which is a piston cylinder design in which hydraulic fluid can be pumped under pressure to one side of the cylinder to cause the piston and therefore the cutter 501 to move outward. When the cutter 501 needs to be retracted, hydraulic fluid may be pumped to the other side of the piston to move the piston in the opposite direction and thereby retract the cutter. A similar design is provided separately for the second cutter 502. This embodiment allows each cutter 501, 502 to be controlled individually and also provides an embodiment in which the tool body does not need to be divided into parts, similar to the embodiment shown above in FIG. 5A.

Let us now turn to FIG. 6, which schematically illustrates a rock characterization tool assembly 600 containing a core drill bit 601, which may be a core drill bit in accordance with any of the previously described configurations. Regardless of the cutter configuration on the core drill bit 601, the surrounding system is designed to provide local environmental stability while measuring the internal friction angle or uniaxial compressive strength of the formation. In this context, the surrounding system is a supporting structure in the form of a housing 602 for isolating internal components from the external environment of the drilling fluid and immersing them in hydraulic oil. The compensator 603 maintains the pressure inside the housing 602 to match the external pressure.

In fig. 7A, 7B and 8 show in more detail an assembly of the type shown in FIG. 6. In this regard, node 600

- 10 045945 of the rock characterization tool provides a measurement system, a means of extending and retracting the core drill bit 601, along with features for providing load-bearing capacity and damping the forces encountered during the measurement of formation characteristics. The core drill bit 601 may have any of the previously mentioned core drill bit configurations. The supporting structure may include a first motor and gear unit 702, a second motor and gear unit 703, a linear guide 704, a wedge member 705, and a core drill bit support 706. These features provide a mechanism for converting rotational motion in the first or second motor and gearbox assembly 702, 703 into translational motion to move the core drill bit 601 forward to test the formation. The supporting structure further includes bushings/bearings 707 and dynamic seals that provide rotational movement of the core drill bit 601 without fluid leakage. Additionally, electrical connectors 708, 709 are provided to provide power and control to the motors and sensors. The support structure also includes hydraulic connectors to connect the compensator 603 and allow the support structure to be initially filled with oil.

The hydraulic compensator 603 is adapted to equalize the pressure of the fluid inside the assembly so that it substantially matches the pressure of the fluid outside the supporting structure, i.e. maintaining the lubricating oil pressure inside the assembly equal to the drilling fluid pressure in the annular space. A hydraulic compensator accomplishes this by pumping fluid into or out of the support structure to compensate for changes in the depth at which the rock characterization tool operates, changes in ambient temperature, and/or changes in internal volumes that change during the move operation. core drill bit 601.

When the assembly is in a balanced stable state, the described system allows the formation to be scratched to determine the angle of internal friction or uniaxial (unconfined) compressive strength. The scratching is preferably performed in a circular motion, as opposed to the traditional linear scratching of a core sample extracted from a borehole.

In fig. 10A-10D and FIG. 11A to 11D show various types of examples of sharp and blunt incisors, respectively.

In fig. 10A shows, in side view, an example of a sharp cutter 1000 with a cutting edge 1010. FIG. 10B, 10C and 10D show, in front, top and isometric views, a sharp cutter 1000. FIG. 11A shows, in side view, an example of a blunt cutter 1100, and FIG. 11B, 11C and 11D show, in front, top and isometric views, a blunt cutter 1100. Typical dimensions of a sharp cutter 1000 are shown in FIG. 10A-10C, and typical dimensions of a blunt cutter 1100 using a 31.1 cm drill bit are shown in FIG. 11A-11B. Please be aware that if other sizes of drill bits are used, the dimensions will be different and that these exact dimensions are only examples of dimensions that may be suitable.

As an alternative to having a separate sharp cutter and a separate blunt cutter, a single cutter can be used that can be used as both a sharp cutter and a blunt cutter. This is achieved through the use of a cutter with a profiled beveled cutting edge. An example of such a beveled cutter 1200 is shown in FIG. 12A-12C. The 1200 cutter can function as either a sharp cutter or a dull cutter. The 1210 bevel can have a radius ranging from 0.1mm to 0.5mm, depending on the situation. For example, you can use a bevel of 0.1 mm, 0.3 mm or 0.5 mm.

When the single cutter described above is used, evaluation of both the internal friction angle and the uniaxial compressive strength can be obtained with good accuracy while reducing the measurement time required to perform the test. In addition, the tool is simplified by eliminating the need to extend sharp and dull cutters into their respective positions and retract them.

Operation of the tool.

Accordingly, the invention relates to a module that can be installed in a downhole drill string assembly (approximately 35-45 m from the bit). To obtain measurements of uniaxial compressive strength and internal friction angle, the tool assembly sequentially performs the following main functions:

a) waiting for a valid actuation command:

the device is usually in a low power mode, in which only the module is responsible for detecting a valid actuation command from the surface, provided, for example, through a sequence of suitably encoded pressure waves or through a data transmission system, if any, in the drill string;

when such a command is detected, the module responsible for this checks its correctness based on the specified criteria (for example, at a minimum, it checks that the drill string is not rotating);

if the actuating command is confirmed, the module puts the system into operating mode, otherwise the module returns to the waiting mode for the actuating command;

b) immobilization/holding of the system on the inner wall of the well: the first function, which

- 11 045945 This system performs in operating mode, consists in extending the shoes, which, resting against the wall of the well, fix the drill string for subsequent cutting and scratching operations;

suitable sensors and/or ongoing measurements determine that the operation has been performed correctly in order to proceed sequentially to the next function or, if the result is negative, to abort the procedure;

c) preparation (cutting) of the well wall surface:

the measuring subsystem (or subsystems) causes the core drill bit to extend and rotate to prepare the surface;

the core drill bit passes through the layer of drilling fluid separating the tool from the borehole wall and comes into contact with the rock, contact is indicated by a sharp increase in force, measured by corresponding load cells built into the tool;

once contact occurs, the core drill bit is moved forward (rotating) to a predetermined depth (eg, about 20 mm using a 31.1 cm diameter core drill bit), thereby removing the potentially damaged layer of the formation through which the drill bit has passed;

d) scratching operation:

using a suitable mechanism, the measurement subsystem (or subsystems) switches from surface preparation cutters to scratching cutters for measuring uniaxial compressive strength (sharp cutters) and internal friction angle (dull cutters);

the core drill bit again comes into contact with the wall of the previously prepared formation;

the core drill bit performs the scratching operation sequentially at various depths and lengths in accordance with a predetermined program;

the operation is completed by returning the core drill bit;

e) detachment from the well wall when re-retracted into the housing shell:

the locking system retracts the shoes;

f) processing of the measured parameters of the formation (angle of internal friction and uniaxial (unlimited) compressive strength) in its initial stress state:

the system processes measurements based on a predefined code; the system writes the results to internal memory and possibly communicates with the surface (if a communication system is available);

g) waiting for the next actuation command:

The system goes into low consumption mode, waiting for a new actuation command.

The scraping operation described in paragraph d) operates on a principle similar to that of a conventional laboratory instrument such as EpsLog's Wombat: breaking down specified quantities (volumes) of rock to measure its angle of internal friction or uniaxial compressive strength using two sets of cutters. suitable shape for taking two different measurements.

The main difference between these two components (downhole measurement component and laboratory tool), in addition to the different measurement conditions (downhole is characterized by high pressure and high temperatures, compared to laboratory conditions with ambient temperature and pressure), is the way in which mechanical scratching of the formation is carried out , which is circular in the case of the first component and linear in the second case.

A possible embodiment of the invention involves the use of two adjacent measuring subsystems, one of which is used to determine the uniaxial compressive strength, and the other to determine the angle of internal friction. It is preferable for these systems to be located close to each other to ensure that they measure two parameters at two points in the same formation.

To provide greater stability during measurement, one or more immobilization/restraint systems may be provided on the inner wall of the borehole. These systems are designed to respond to the force generated by the measuring tools as they interact with the formation.

Other components are also designed to ensure the proper functioning of the system and provide the system with sufficient energy, which in the proposed solution comes from batteries.

A method for conducting tests to determine the uniaxial compressive strength and the internal friction angle of the formation at any point in the well is described with reference to FIG. 9A and 9B.

A rock characterization tool 902 in accordance with any of the previously described embodiments is provided in the downhole drill string assembly 903 approximately 35-45 m from the core drill bit 904 and is lowered into the wellbore 901 to the desired location 905 for testing the rock characteristics. those. to perform tests to determine uniaxial compressive strength and angle of internal friction. Then to the 902 tool to determine rock characteristics using fluid pulse telemetry

- 12 045945 the communication channel is commanded from the surface to bring the rock characterization tool 902 out of low power mode. Rock characterization tool 902 accordingly extends shoes into borehole 901, creating a force against which rock characterization tool 902 can apply pressure to perform tests in borehole 901. Sensors in rock characterization tool 902 determine whether they are installed correctly. shoes to proceed to the stage of preparing the formation for testing and conducting formation tests.

Formation preparation.

If the shoes are properly installed, the measurement subsystem of the rock characterization tool 902 causes the core drill bit (not shown in FIGS. 9A and 9B) to extend from the supporting structure and rotate to prepare the surface, i.e. to remove mud cake/debris layer. The core drill bit eventually makes contact with the formation after removing layers of debris. The rock characterization tool 902 determines when the core drill bit will contact the formation by a sudden increase in force detected by strain gauges built into the rock characterization tool 902. The core drill bit can then be advanced to a predetermined depth into the formation (usually about 20 mm) to remove the potentially damaged or disrupted layer of the formation that the drill bit passed through while drilling that portion of the well. The core drill bit is then removed to leave a portion of the formation ready for testing.

The rock characterization tool 902 has one of the previously described cutter configurations and cutter switching mechanisms. With the help of the mentioned mechanism, the cutters for surface preparation are retracted, retracted, and the cutters for testing are moved forward. The test cutters on the core drill bit then come into contact with the formation being tested. The test cutters can then perform a scratching operation on the formation to determine the uniaxial compressive strength and/or internal friction angle of the formation. The cutters perform this operation according to a predefined program or procedure, which is either predefined and programmed into the tool or sent from the surface as a command to the tool.

Data collection and transmission.

Once the necessary data is collected during a scratch test, the data may be processed in the tool 902 to characterize the rock or may be sent via mud-pulse telemetry or other communications to the surface where it can be processed for evaluation. The rock characterization tool 902 also stores logged data in the tool's internal memory, possibly along with time, temperature, vibration parameters, etc., which can be downloaded to provide high-quality surface data when the tool is removed from the hole and downhole assembly. 201 wells have been dismantled.

Retest or extract.

If necessary, additional scratch tests may be performed, otherwise the core drill bit and support shoes are retracted from the formation back into the supporting structure. Typically, the rock characterization tool 902 enters a low power mode and awaits a new activation command.

The invention disclosed herein provides both a method for analyzing the characteristics of rocks and a tool and assembly for determining the characteristics of rocks that can be used to implement the method.

As a result, the method, tool and assembly proposed according to the invention provide the following advantages:

improvement of the wellbore stability model due to the ability to measure the parameters of uniaxial compressive strength and the angle of internal friction of the formation directly on the inner wall of the well in their initial stressed state during the drilling stage;

the ability to obtain more characteristics than with core sampling, especially in environments where core sampling is not possible;

cost reduction due to the possibility of eliminating core sampling operations;

cost reduction by reducing wasted time, primarily due to the following aspects:

no slowdown in drilling operations, since it is assumed that the invention will be used when changing drill rods with active circulation;

no increase in waiting time for measurement results of the angle of internal friction or uniaxial compressive strength of the formation, since the values obtained and stored using the invention directly on site are available, for example, after each bit change; and increased operational safety by eliminating all activities associated with obtaining core from the well and subsequent handling/moving of the core, as well as eliminating all laboratory work.

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Claims (31)

In this regard, the tool proposed according to the invention can be used to directly measure the parameters of the angle of internal friction and uniaxial compressive strength of the formation in the well in its initial stress state using one or more measuring devices placed directly inside the module, which can be installed in the downhole assembly drill string. The tool may be activated from the surface by, for example, a sequence of suitably coded pressure waves or by a data transmission system if present in the drill string. Once the activation command is received, the system operates in a fully autonomous mode, sequentially performing the intended operations and measurements within the time required to change the drill rod, without any operator intervention, and ensuring the safety of the work. Moreover, the data recorded and stored on site can later be accessed, for example, at every bit change or in real time if the drill string has a data communication system. Calculation of unconfined compressive strength and angle of internal friction can be performed using the same theory as in known systems that determine the characteristics of rock at the surface, such as the Wombat system. The invention has the added benefit of reducing costs by improving wellbore stability models and reducing wasted time. CLAIM 1. A downhole tool for conducting downhole tests to determine the characteristics of rocks in the test section of the formation, containing at least one cutter for preparing the test section of the formation and at least one cutter for testing, with at least one cutter for preparing the test section of the formation adapted to expose the surface of the actual formation by removing debris deposited on the internal walls of the borehole in preparation for the interaction of at least one test cutter with the test area. 2. Downhole tool according to claim 1, in which at least one cutter for preparing the test section of the formation is additionally adapted to remove a layer of the test section. 3. The downhole tool of claim 2, wherein the at least one cutter for preparing the test section of the formation is preset to remove a layer of formation substantially 20 mm thick. 4. Downhole tool according to any one of claims 1 to 3, wherein at least one test cutter is substantially blunt for conducting an internal friction angle test. 5. Downhole tool according to any one of claims 1 to 3, wherein the at least one test cutter is substantially sharp to conduct a uniaxial unconfined compressive strength test. 6. A downhole tool according to any one of claims 1 to 3, wherein at least one test cutter comprises a sharp cutter for testing uniaxial unconfined compressive strength and a blunt cutter for testing the angle of internal friction. 7. Downhole tool according to any one of claims 1-6, in which the cutter for preparing the test section of the formation is configured to move along the first circular path to perform surface preparation. 8. Downhole tool according to any one of claims 1 to 7, wherein the test cutter is configured to move along a second circular path to conduct one or more internal friction angle tests or uniaxial unconfined compressive strength tests. 9. The downhole tool of claim 8, wherein the second circular path is within the circumference of the first circular path. 10. Downhole tool according to any one of claims 6-9, in which a sharp cutter and a blunt cutter are integrated into a single cutter for testing. 11. Downhole tool according to any one of claims 1 to 10, wherein at least one cutter for preparing the test section of the formation contains a plurality of cutters for preparing the test section of the formation and at least one cutter for testing contains a plurality of cutters for testing. 12. Downhole tool according to any one of claims 1-11, in which at least one cutter for preparing the test section of the formation and at least one cutter for testing are installed with the possibility of relative movement so that they are able to alternately be in active cutting and passive retracted states. 13. The downhole tool according to any one of claims 1 to 12, further configured such that at least one cutter for preparing the test section of the formation is capable of selectively moving from a first position of the tool for removing debris to a second position of the tool so that - 14 045945 allow at least one test cutter to carry out the test. 14. The downhole tool of claim 13, further configured such that the at least one test cutter is selectively movable from said first tool position, in which the at least one test cutter is capable of removing debris, to said second position. a tool in which at least one test cutter is capable of performing a test. 15. The downhole tool of claim 14, wherein the at least one test cutter and the at least one test cutter are mechanically coupled such that movement of the test cutter from a first tool position to a second tool position causes moving the test cutter from a first tool position to a second tool position. 16. Downhole tool according to any one of claims 12 to 15, in which at least one cutter for preparing the test section of the formation and at least one cutter for testing are configured to move relative to each other using one or more hydraulic piston devices or electrical devices. 17. Downhole tool according to any one of claims 1 to 16, further comprising a core drill bit configured to move at least one cutter to prepare the test section of the formation and at least one cutter for testing to the test section. 18. The downhole tool of claim 17, wherein the core drill bit is moved in a direction substantially perpendicular to the axial direction of the well in the area being tested. 19. Downhole tool according to any one of claims 1-3, in which the test cutter has a profiled cutting edge, beveled so that it can perform the functions of both a blunt and a sharp cutter. 20. Downhole tool according to claim 19, in which the bevel of the test cutter has a radius from 0.1 to 0.5 mm. 21. A downhole tool assembly containing a tool according to any one of claims 1 to 20, wherein the unit has a supporting structure, inside which the components of the tool can be isolated from the well environment, and the downhole tool assembly additionally contains a compensator configured to pump fluid. into or out of the supporting structure to equalize the internal pressure in the supporting structure with the local pressure outside the supporting structure. 22. Downhole tool assembly according to claim 21, in which the core drill bit is designed to be retractable from the supporting structure to the outside of the supporting structure. 23. The downhole tool assembly according to claim 21 or 22, further comprising a deployable immobilizing means for attaching the assembly to the inside of the well. 24. The downhole tool assembly of claim 23, wherein the immobilizer comprises one or more shoe components for abutting the wellbore wall to create a locking response during testing operations. 25. The downhole tool assembly according to any one of claims 21-24, further comprising connecting means for connecting to the drill pipe or tools of the downhole drill string assembly. 26. The downhole tool assembly according to any one of claims 21 to 25, further comprising a power module for supplying power to a motor for moving the core drill bit to the test area. 27. Downhole tool assembly according to claim 26, in which the power module is a battery. 28. Downhole tool assembly according to any one of claims 21-27, further comprising at least one force sensor adapted to detect the first force on at least one cutter for preparing the test section of the formation. 29. The downhole tool assembly of any one of claims 21 to 28, further comprising at least one force sensor and at least one torque sensor adapted to detect a second force and torque on the at least one test cutter. 30. The downhole tool assembly according to any one of claims 21 to 29, further comprising processing means for calculating the angle of internal friction or limited compressive strength based on the measurement of the second force and torque. 31. A method of conducting a test to determine the characteristics of rock in a test area in a wellbore, comprising the steps of placing a downhole tool according to any one of claims 1 to 20 or a downhole tool assembly according to any of claims 21 to 30 in the well; moving at least one cutter to prepare the test section of the formation to the test section to remove debris located along the path of movement; moving at least one test cutter to the test area and -