SYSTEMS AND PROCEDURES FOR DETERMINING MECHANICAL PROPERTIES IN SUBSOIL FORMATIONS

Abstract

A system for monitoring and establishing the mechanical properties of a formation may include a strain detection system and a controller. The strain detection system may include an elongated fiber, a light emitter, and a detector. The elongated fiber may be, or may include, a fiber optic cable. Monitoring and establishing the mechanical properties of a wellbore may involve determining a stress applied to a casing along a length of the wellbore and detecting, with the strain detection system, any strain that may result from the stress applied to the casing. Based on the stress applied to the casing and the detected strain, the controller can determine a value related to a mechanical property of the formation that extends along the length of the wellbore.

Description

SYSTEMS AND PROCEDURES FOR DETERMINING MECHANICAL PROPERTIES IN SUBSOIL FORMATIONS Cross-reference to related applications This application claims the benefit of U.S. Provisional Patent Application No. 62 / 914,008 filed on October 11, 2019, the description of which is incorporated herein by reference. Technical field This disclosure relates to monitoring systems and assessment tools, and the like. More specifically, this disclosure relates to strain monitoring systems and systems for determining mechanical properties and stress states in subsurface formations. Background A wellbore can be a hole drilled through the subsurface to aid in the exploration and recovery of natural resources (e.g., oil, gas, water, geothermal heat, etc.), to access an underground reservoir, and / or to assist in one or more of its intended functions. An underground reservoir can be an underground space containing one or more recoverable natural resources, an underground space used to process a transport fluid (e.g., a geothermal reservoir), etc. After a wellbore is formed, subsurface stress measurements can be performed. Subsurface stress measurements can be carried out, for example, using a hydraulic fracturing procedure, through which the minimum magnitude of principal stress in an isolated wellbore interval can be determined.Of the known approaches and systems for determining the mechanical properties and stress states of a subsurface formation, each has certain advantages and disadvantages. Brief description of the invention This disclosure is directed at various alternative designs, devices, and procedures for using monitoring systems and assessment tools. ηοζίτηη / ζζηζ / Ε / γίΛΐ Although monitoring approaches and systems are known, there is a need to improve those approaches and systems. Accordingly, an illustrative example of disclosure might include a procedure for determining the elastic properties of a formation along a wellbore. The procedure might involve initiating the application of disturbances to a casing string along the length of the wellbore. These disturbances cause a force to be applied to the casing along that length. In this procedure, a value related to the stress applied to the casing along the length of the wellbore can be determined based on the applied force, and a value related to the resulting strain can be identified from that stress value.The procedure may also include determining a value related to an elastic property of a formation that extends along the length of the wellbore as a function of the value related to the stress applied to the casing and the value related to the deformation resulting from the stress applied to the casing along the length of the wellbore. In addition, or as an alternative to any of the above embodiments, the start of the application of disturbances to the lining of a length of the wellbore enclosure may include the start of the application of disturbances to the lining of the length of the wellbore enclosure from a central lumen of the wellbore enclosure. In addition, or as an alternative to any of the above embodiments, the formation that extends along the length of the wellbore enclosure may extend along the outside of the casing pipe along the length of the wellbore enclosure. In addition, or as an alternative to any of the above embodiments, the formation extending along the length of the wellbore enclosure may have a plurality of layers; and determining a value related to elastic properties for the formation extending along the length of the wellbore enclosure may include determining the elastic properties for each layer of the plurality of layers of the formation. ηοζίτηη / ζζηζ / Ε / γίΛΐ In addition, or as an alternative to any of the above embodiments, the procedure may include receiving values ​​of a parameter measured by a distributed strain detection system that extends along the length of the wellbore enclosure. In addition, or as an alternative to any of the above realizations, the identification of the value related to the strain resulting from the stress applied to the casing pipe of the length of the wellbore enclosure may include the determination of the value related to the strain resulting from the stress applied to the casing pipe of the length of the wellbore enclosure based on the values ​​received from the parameter measured by the distributed strain detection system. Furthermore, or alternatively to any of the above embodiments, the start of the application of disturbances to a casing pipe of a length of the wellbore may comprise the start of the application of disturbances to the casing pipe of the length of the wellbore at a first time, t1, and at a second time, t2; determining the value related to the tension applied to the casing along the length of the wellbore as a function of the force applied to the casing pipe may comprise determining a value of the tension applied to the casing pipe along the length of the wellbore at the first time, t1, and at the second time, t2;Identifying the value related to the deformation resulting from the stress applied to the casing along the length of the wellbore may comprise determining a value related to the deformation resulting from the stress applied to the casing along the length of the wellbore at the first time, t1, and the second time, t2; and determining the value related to the elastic properties of a formation extending along the length of the wellbore based on the value related to the stress applied to the casing and the value related to the deformation resulting from the stress applied to the casing along the length of the wellbore may comprise determining a value related to the elastic properties of the formation extending along the length of the wellbore at the first time, t1, and at the second time, t2. In addition, or as an alternative to any of the above embodiments, the procedure may include determining a change in the value related to the elastic property determined at the first time, t1, and the value related to the elastic property determined at the second time, t2; comparing the change in the value related to the elastic property with a threshold level; and issuing a control action when the change in the value related to the elastic property reaches or exceeds the threshold level. In addition, or as an alternative to any of the above embodiments, the initiation of the application of disturbances to the casing along the length of the wellbore enclosure, the determination of the value related to the stress applied to the casing along the length of the wellbore enclosure, the identification of the value related to the deformation resulting from the stress applied to the casing along the length of the wellbore enclosure, and the determination of the value related to the elastic property of the formation extending along the length of the wellbore enclosure can be repeated at predetermined intervals. In addition, or as an alternative to any of the above realizations, the procedure may include maintaining a database of values ​​related to the elastic property of the formation that extends along the length of the wellbore enclosure that is determined at each of the predetermined intervals. In addition, or as an alternative to any of the foregoing embodiments, the procedure may include establishing a value related to a force to be applied by disturbances to the casing of the length of the wellbore enclosure; and wherein the value related to the force may be set to prevent fracturing of the wellbore enclosure and prevent fracturing of the formation that extends along the length of the wellbore enclosure. Another illustrative example of disclosure might include a controller configured to establish an elastic property of a formation extending along the outside of a wellbore casing. The controller might include a processor, an input port communicating with the processor, and memory storage instructions configured to be executed by the processor to cause the processor to: determine a value related to a stress applied to a wellbore casing of a length of the wellbore when disturbances are applied to the casing of the length of the wellbore; receive, through the input port, values ​​related to a parameter measured by a distributed strain detection system while disturbances are applied to the casing of the length of the wellbore;Determine a value related to a deformation resulting from the stress applied to the casing along the length of the wellbore based on the values ​​related to the parameter measured by the distributed strain detection system that are received; and determine a value related to an elastic property of a formation that extends along the length of the wellbore based on the value related to the stress applied to the casing along the length of the wellbore and the value related to the deformation resulting from the stress applied to the casing along the length of the wellbore. In addition, or as an alternative to any of the foregoing embodiments, the memory may further comprise instructions configured to be executed by the processor to cause the processor to establish a force-related value for disturbances to be applied to the casing pipe of the length of the wellbore enclosure In addition, or as an alternative to any of the above realizations, the force-related value can be configured to prevent fracturing of the wellbore enclosure and to prevent fracturing of the formation that extends along the length of the wellbore enclosure. In addition to or as an alternative to any of the above embodiments, the memory may further comprise instructions configured to be executed by the processor to cause the processor to determine a value related to the elastic property for each layer of a plurality of layers that make up the formation that extends along the length of the wellbore enclosure. ηοζίτηη / ζζηζ / Ε / γίΛΐ using the elongated fiber, the parameter values ​​are related to the deformation resulting from a stress applied to the well enclosure. In addition, or as an alternative to any of the above embodiments, the controller is configured to: receive an input of a value related to a stress applied to the casing of the length of the wellbore enclosure; and determine the elastic property of the formation extending along the outside of the casing of the length of the wellbore enclosure based on the measured parameter values ​​using the elongated fiber and the value related to the stress applied to the casing of the length of the wellbore enclosure. In addition, or as an alternative to any of the above embodiments, the controller is configured to: determine a value related to a stress that will be applied to the casing of the length of the wellbore enclosure; and determine the elastic property of the formation that extends along the outside of the casing of the length of the wellbore enclosure based on the values ​​of the parameter measured using the elongated fiber and the value related to the stress that will be applied to the casing of the length of the wellbore enclosure. The preceding summary of some example realizations is not intended to describe every disclosed realization or every implementation of the disclosure. Brief description of the drawings The disclosure can be more fully understood by considering the following detailed description of various embodiments in relation to the accompanying drawings, in which: Figure 1 is a schematic box diagram of an illustrative system for determining the mechanical properties of a subsurface formation; Figure 2 is a schematic diagram of an illustrative system for determining the mechanical properties of a subsurface formation implemented in a well enclosure; Figure 3 is a schematic diagram of an illustrative system for determining the mechanical properties of a subsurface formation implemented in a well enclosure with plugs in it and fluid between the plugs; nozfrnn / zznz / E / YiAi Figure 4 is a schematic diagram of an illustrative system for determining the mechanical properties of a subsurface formation implemented in a well enclosure with a plug in the same; Figure 5 is a schematic flowchart of an illustrative procedure for determining the mechanical properties of a subsurface formation; Figure 6 is a schematic flowchart of an illustrative procedure for developing a stiffness model of a subsurface formation; and Figure 7 is a schematic diagram of an illustrative technique for identifying stress states of a subsurface formation along a wellbore enclosure. While the disclosure is subject to various modifications and alternative forms, its specific details have been shown by way of example in the drawings and will be described in detail. It should be understood, however, that the intention is not to limit aspects of the claimed disclosure to the particular embodiments described. Rather, the intention is to cover all modifications, equivalents, and alternatives that fall within the spirit and scope of the claimed disclosure. Description For the following defined terms, these definitions shall apply, unless a different definition is given in the claims or elsewhere in this specification. All numerical values ​​in this document are assumed to be modified by the term "approximately," whether explicitly stated or not. The term "approximately" generally refers to a range of numbers that a person skilled in the art would consider equivalent to the stated value (i.e., having the same function or result). In many cases, the term "approximately" may indicate the inclusion of numbers that are rounded to the nearest significant figure. Mentioning numerical ranges by evaluation criteria includes all numbers within that range (for example, 1 to 5 includes 1, 1.5, 2, 2.75, 3, 3.80, 4 and 5). ηαζίτηη / ζζηζ / Ε / γίΛΐ Although some suitable dimensions, ranges and / or values ​​pertaining to various components, features and / or specifications are disclosed, a person skilled in the art, prompted by this disclosure, will understand that the desired dimensions, ranges and / or values ​​may deviate from those expressly disclosed. As used in this specification and the accompanying claims, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. As used in this specification and the accompanying claims, the term “or” is generally used in its sense which includes “and / or” unless the context clearly dictates otherwise. The following detailed description should be read with reference to the drawings, in which similar elements in different drawings are numbered in the same manner. The detailed description and the drawings, which are not necessarily to scale, represent illustrative embodiments and are not intended to limit the scope of the claimed disclosure. The illustrative embodiments depicted are for example purposes only. Selected features from any illustrative embodiment may be incorporated into a further embodiment unless clearly stated otherwise. Subsurface stresses affect a range of geological conditions that are important for several commercially relevant systems, including geothermal, oil and gas, and other systems. Successful implementation of such systems may require accurate information on the size, orientation, complexity, and / or other parameters related to natural and anthropogenic fracture systems. For example, knowledge of the subsurface stress state can be useful for the development of geothermal reservoirs, allowing well pads and / or designed fracture systems to be optimized for orientation, spacing, and / or subsequent productivity. Reducing the operating costs of oil well pads, gas well pads, geothermal reservoirs, and / or other suitable underground systems can be achieved by minimizing uncertainty in subsurface stress estimation. Existing subsurface stress measurements and / or prediction techniques (e.g., existing mechanical properties and / or other suitable techniques for determining properties or conditions) may only be valid at discrete points or relatively short sections of a wellbore. For example, while hydraulic fracturing techniques may be acceptable for measuring stress at a particular location, they have been found to have at least the following drawbacks: (1) they require the initiation of fracturing, which may or may not be beneficial at that location (e.g., creation of additional potential lost circulation zones), and (2) a stress state is measured at a particular location along a wellbore and only provides singular “calibration” points rather than determining a continuous stress estimate log along a length of the wellbore. The disclosed concepts provide improved procedures and systems for continuous measurements of subsurface stresses over large lengths (e.g., full lengths and / or other suitable large lengths) of wellbore enclosures and over long time scales (e.g., throughout the life of the wellbore enclosure).The procedures and system in this document can be used to generate a continuous stress prediction record through disturbances (e.g., wellbore disturbances and / or other suitable disturbances), strain detection (e.g., fiber optic distributed strain detection and / or other suitable strain detection), mechanical property characterization (e.g., anisotropic elastic property characterization and / or other suitable mechanical property characterization), mechanical property validation (e.g., an investment for elastic property validation), and / or other suitable features. Determining the mechanical properties of subsurface formations can facilitate the determination of how these formations can be fractured and, therefore, can be used to identify formation locations that can be fractured according to a desired profile. For example, the minimum horizontal stress values ​​for a formation location, which can be determined or estimated from the mechanical properties, can be considered a primary determinant of the shape and size of a fracture and, therefore, can be used to facilitate the identification of locations where formation fracturing should begin. In some cases, systems and procedures that generate a continuous stress prediction log may utilize an elongated fiber probe permanently installed in a well casing. This probe detects the stress resulting from applied stress on the well casing. Strain data obtained using the elongated fiber probe, and / or strain data obtained in one or more suitable ways, can be used to characterize the geological mechanical properties and / or other appropriate geological properties or conditions, including stress, size, orientation, complexity, and / or other parameters of a subsurface formation surrounding the well casings and / or reservoirs. From these characterized parameters of the subsurface formation surrounding the well casings and / or reservoirs, subsurface stresses can be determined.An accurate prediction of subsurface stresses can be beneficial when core material (e.g., material extracted from the subsurface formation when forming a well enclosure) cannot be obtained due to cost or poor core material recovery, there are no image records (e.g., center light) of the well enclosure, and / or beneficial in other suitable cases. Returning to the figures, Figure 1 discloses a system 10 for determining and / or establishing mechanical and / or other suitable properties or conditions of a subsurface formation. In some cases, system 10 can be configured to establish the elastic properties of a subsurface formation that extends around or around a wellbore and / or reservoir. System 10 may include, among other components, a strain detection system 12 and a controller 14. The strain detection system 12 may be any suitable type of strain detection system 12 configured to detect strain along a well enclosure. In one example, the strain detection system 12 may be a fiber optic distributed strain detection (DSS) system. The controller 14 may be any suitable controller configured to process data to or from the strain detection system 12. The controller 14 may be a component separate from the strain detection system 12, as shown in Figure 1, and / or the controller 14, or a part of the controller 14, may be a component of or included within the strain detection system 12. The strain detection system 12 may include, among other suitable components, an optical fiber cable 16, a detector 18 in communication with the optical fiber cable 16, and a light emitter 20 in communication with the optical fiber cable 16. The detector 18 (e.g., a light detector and / or other suitable detector type) may be connected to a first end of the optical fiber cable 16 and may be configured to detect light reflected back to the first end after interacting with a material (e.g., glass or other suitable material) of a fiber of the optical fiber cable 16. A 16-fiber optic cable may include one or more optical fibers configured to allow light to travel along each fiber. Light reflected back to the first end of the fiber may be the result of backscattering (e.g., Raiman, Brillouin, Rayleigh, and / or other mechanisms). Backscattering of light may be a spontaneous and diffuse reflection. Detector 18 can be any suitable type of light detector. In some cases, detector 18 can be configured to detect light reflected from detector 18 through fiber optic cable 16. For example, detector 18 can be configured to detect a quantity of light received at detector 18, a pattern of light received at detector 18, a wavelength of light received at detector 18, and / or one or more suitable parameters related to the light received at detector 18. Although not required, measurements of the quantity, pattern, wavelength, and / or other suitable parameters related to the light received at detector 18 can be stored in the strain detection system memory 12 and / or other suitable memory. The light emitter 20 can be any suitable type of light emitter 20 configured to provide light through one or more fibers of the optical fiber cable 16. In some cases, the light emitter 20 may incorporate one or more lasers, one or more light-emitting diodes (LEDs), one or more superluminescent light-emitting diodes (SLEDs), and / or other suitable light sources configured to send light waves through one or more fibers of the optical fiber cable 16. The light emitter 20 can emit light with a known wavelength. In some cases, the light emitter 20 can emit light at a wavelength within the range of 405 nanometers (nm) to 1580 nm and / or light at one or more suitable wavelengths. In addition to, or as an alternative to, the fiber optic cable 16, the detector 18, and the light emitter 20, the strain detection system 12 may include one or more components suitable for facilitating strain detection along the fiber optic cable 16. For example, the strain detection system 12 may include, among other features, one or more processors, memory, an input / output (I / O) unit, communication components, a user interface, a touchscreen, a display screen, selectable buttons, a housing, and / or other suitable components configured to facilitate strain detection along the fiber optic cable 16. In some cases, the detector 18 and / or the light emitter 20 may be, or may include, computer devices that have memory, one or more processors, and / or other suitable computer device components. In some cases, modulations in the detected light can be identified by the strain detection system 12 (for example, via detector 18 and / or another suitable computer component of the strain detection system 12) and / or controller 14. The modulations identified in the detected light may be indicative of a change in the tension acting on the optical fiber cable 16 (for example, tension acting over a length of the optical fiber cable 16). The modulations identified in the reflected light may include, among others, amplitude, phase, and / or frequency modulations, which can be spatially identified along the optical fiber cable 16 (for example, identification of a location of the modulations and / or a change in tension along the optical fiber cable 16).The spatial identification of the modulations identified in the light reflected along the optical fiber cable 16 can be determined using time-domain optical reflectometry (OTDR), frequency-domain optical reflectometry (OFDR), and / or other suitable techniques. The strain detection system 12 can be configured to provide a continuous strain profile along the optical fiber cable 16. The spatial resolution of the strain detection system 12 and / or the continuous strain profile along the optical fiber cable 16 can be determined by measuring the pulse width of the light emitted from the light emitter 20 and the frequency scan range of the light emitter. The strain detection system 12 can be configured to use one or more Rayleigh optical frequency domain reflectometry, Brillouin optical time domain reflectometry, and / or other suitable techniques to identify modulations in the light reflected along the optical fiber cable 16 and develop a continuous strain profile along the optical fiber cable 16. As shown in Figure 1, controller 14 can communicate with strain detection system 12. In some cases, controller 14 can be configured to receive data from strain detection system 12 and determine the mechanical properties and / or other suitable properties or conditions (e.g., which may or may not be related to mechanical properties) of a subsurface formation (e.g., a subsurface formation extending along the outside (e.g., an outer surface) of a casing pipe the length of a wellbore enclosure and / or other suitable subsurface formation). Examples of mechanical properties of subsurface formations include, but are not limited to, elastic properties, elastic moduli, stiffness, compressibilities, effective pressure coefficients, etc.Examples of other suitable properties or conditions of subsurface formations include, but are not limited to, stress gradients, vertical stress, pore water pressure, minimum horizontal stress, etc. Example data that controller 14 can receive from strain detection system 12 may include, among other things, values ​​related to the strain detected by strain detection system 12, time data associated with strain detection system 12, etc. Additionally, or alternatively, to receive data from strain detection system 12, controller 14 may determine a value related to a stress that will be applied to a casing pipe of a length of wellbore enclosure and / or receive an input of a value related to a stress applied to the casing pipe of the length of wellbore enclosure.In some cases, controller 14 can be configured to determine one or more mechanical and / or other suitable properties or conditions of the formation that extends along the outside of the casing for the length of the wellbore enclosure based on strain-related values ​​detected by strain-detection system 12 and stress-related values ​​applied or to be applied to the casing for the length of the wellbore enclosure. The illustrative controller 14 may include, among other suitable components, one or more processors 22, memory 24, and / or an I / O unit 26. For example, other suitable components of controller 14 not shown in Figure 1 may include, but are not limited to, communication components, a user interface, a touchscreen, a display screen, selectable buttons, an enclosure, a pump controller for facilitating the application of stress to a well enclosure, and / or other suitable controller components. As discussed above, one or more components of controller 14 may be separate from the strain detection system 12, as shown in Figure 1, and / or incorporated into the strain detection system 12. The processor 22 of controller 14 may include a single processor or multiple processors working individually or in conjunction with each other. The processor 22 may be configured to execute instructions, including instructions that can be loaded into memory 24 and / or other suitable memory. Example components of the processor 22 may include, but are not limited to, microprocessors, microcontrollers, multi-core processors, graphics processing units, digital signal processors, application-specific integrated circuits (ASICs), field-programmable gate arrays (FPGAs), discrete circuitry, and / or other suitable types of data processing devices. ηοζίτηη / ζζηζ / Ε / γίΛΐ Memory 24 of controller 14 may include a single memory component or multiple memory components, each operating individually or in conjunction with one another. Example memory types 24 may include random access memory (RAM), EEPROM, FLASH, suitable volatile storage devices, suitable non-volatile storage devices, persistent memory (e.g., read-only memory (ROM), hard disk, Flash memory, optical disk memory, and / or other suitable persistent memory), and / or other suitable memory types. Memory 24 may be, or may include, a non-transient, computer-readable medium. The controller 14's 26 I / O units may include a single I / O component or multiple I / O components, each operating individually or in conjunction with one another. Example 26 I / O units may be or include any suitable type of communication hardware and / or software, including, but not limited to, communication ports configured to communicate with the strain detection system 12 and / or other suitable devices or computer systems. Example types of 26 I / O units may include wired ports, wireless ports, radio frequency (RF) ports, Bluetooth Low Energy ports, Bluetooth ports, near field communication (NFC) ports, HDMI ports, Wi-Fi ports, Ethernet ports, VGA ports, serial ports, parallel ports, component video ports, S-video ports, composite audio / video ports, DVI ports, USB ports, optical ports, and / or other suitable ports. Figure 2 is a schematic partial cross-section diagram of system 10 for determining the mechanical and / or other suitable properties or conditions of a subsurface formation deployed in a well enclosure 30. In Figure 2, the well enclosure 30 and a subsurface formation 32 are shown in a schematic cross-sectional view, while the strain detection system 12 and controller 14 are shown in a schematic side view. As shown in Figure 2, the strain detection system 12 can communicate with the controller 14 and can include a housing 28. The housing 28 can house the fiber optic cable 16, the detector 18, the light emitter 20, and / or additional or alternative components, and the fiber optic cable 16 can extend from the housing 28. Although the housing 28 is shown in Figure 2, it can be omitted. Furthermore, although the controller 14 is shown in Figure 2 as a component separate from the strain detection system 12, the housing 28 can house all or part of the controller 14, and / or a housing (not shown) of the controller 14 can house all or part of the strain detection system 12. The subsurface formation 32 can be formed from one or more suitable layers 38 of material. The layers 38 of material that form the subsurface formation 32 can be of any suitable type of material and can be of any suitable size. In some cases, the subsurface formation 32 may have a single layer 38 of material extending the entire length of the wellbore enclosure 30 or two or more layers 38 of material extending the length of the wellbore enclosure 30. Examples of material layers include, but are not limited to, sand, topsoil, solid rock (e.g., granite, etc.), stones, clay, water, oil, sandstone, limestone, shale, carbonate, cinder, and / or other suitable geological materials (e.g., metamorphic, sedimentary, and / or igneous rocks / soil). Each layer 38 of subsurface formation 32 can be considered to have its own mechanical and / or other properties or suitable conditions due to, among other factors, how and when layer 38 formed and / or what materials it contains. In some cases, two adjacent layers of the same general material may have different mechanical and / or other properties or suitable conditions depending on how and / or when the layer formed, as well as the constituent composition of the material. As such, each layer 38 of subsurface formation 32 may have its own mechanical anisotropy and / or properties when viewed at the layer scale or the granular / fine scale. In some cases, the layers 38 of subsurface formation 32 may be inherently heterogeneous and / or have anisotropic properties.In addition, the overall subsurface formation 32 may have its own mechanical anisotropy and properties that are functions of all the layers 38 of the subsurface formation 32. ηοζίτηη / ζζηζ / Ε / γίΛΐ The type, size, mechanical properties, and / or other suitable properties or conditions of layers 38 and / or the overall subsurface formation 32 can be determined from subsurface formation core samples extracted during well enclosure formation 30 and / or exploration of well enclosure placement. However, core sample analysis is sometimes not possible due to cost, poor core sample recovery, and / or other suitable reasons. In cases where core sample analysis is not possible, and / or in other cases, it may be possible to determine the type, size, mechanical properties, and / or other suitable properties or conditions of layers 38 of the subsurface formation 32 and / or the overall subsurface formation 32 using system 10 through data captured by strain detection system 12, as previously mentioned and discussed in more detail below. Wellbore enclosures 30 can adopt any suitable configuration that extends through the subsurface formation 32. For example, the wellbore enclosure 30 may have casing 34 extending through the subsurface formation 32 and defining a central lumen 36 (e.g., a passage) for fluid and / or components to pass through the wellbore enclosure 30. In some cases, the wellbore enclosure 30 may extend through the subsurface formation 32 into one or more subsurface reservoirs (e.g., an oil reservoir, a gas reservoir, a geothermal reservoir, etc.).), said fluid can be pumped through the central lumen 36 of the well chamber 30 into the reservoir to force the reservoir fluid, so that the fluid can be removed from the reservoir through the central lumen 36 of the well chamber 30 (e.g., removed due to natural pressures in the reservoir pushing the fluid out of the reservoir and / or removed due to pumping the reservoir fluid), so that a fluid pumped through the central lumen 36 of the well chamber 30 can be heated or cooled by a geothermal reservoir, and / or in such a way that other suitable functions are achieved. The casing 34 of the wellbore enclosure 30 may adopt any suitable configuration designed to withstand the pressures provided in the central lumen 36. In one example, the casing 34 may consist of a first layer 40 (for example, an inner layer) forming an inner surface 41 of the casing 34 and a second layer 42 (for example, an outer layer) forming an outer surface 44 of the casing 34. In some cases, one or more of the first layer 40 and the second layer 42 may be omitted and / or one or more additional layers may be used. Additionally or alternatively, a layer other than the second layer 42 may form the outer surface 44 of the casing 34 and / or a layer other than the first layer 40 may form the inner surface of the casing 34. The first layer 40 and the second layer 42 can be formed from the same or a different material as one or more layers 40 and 42 of the casing pipe 34. For example, the first layer 40 could be formed from a steel material and the second layer 42 could be formed from or with a cement or concrete material. As shown in Figure 2, the fiber optic cable 16 can be laid along the length of the well enclosure 30 through the casing pipe 34. In the example shown, the fiber optic cable 16 can be laid along the length of the well enclosure 30 through the second layer 42 of the casing pipe 34, but this is not required. When the second layer 42 of the casing pipe 34 is a curable material (e.g., a cement-based or concrete-based material, or other suitable curable material), the fiber optic cable 16 can be laid along the first layer 40, and then the second layer 42 can be provided along the first layer 40 and cured or allowed to set to secure the fiber optic cable 16 within the casing pipe 34.When positioned in this way and / or otherwise along the length of the wellbore enclosure 30, the fiber optic cable 16 can act as a sensor and detect a deformation resulting from a stress applied to the casing pipe of a length of the wellbore enclosure 30. In some cases, tension can be applied to the casing 34 along a length of the wellbore enclosure 30 from within the central lumen 36, and the strain detection system 12 fiber optic cable 16 can be configured to detect strain or a change in strain in response to the tension applied to the casing 34. Tension can be applied to the casing 34 along the length of the wellbore enclosure 30 in any suitable manner. In some cases, plugs normally used to fracture a subsurface location can be used to apply tension to the casing 34, but in a manner that does not cause fracturing of the wellbore enclosure 30 and / or the subsurface formation 32 surrounding the wellbore enclosure 30. Figures 3 and 4 represent schematic diagrams of the system 10 that detects tension along the casing 34 of the wellbore enclosure 30 in response to disturbances applied to the wellbore enclosure 30 by the tension-inducing systems. Figure 3 shows a technique for applying disturbances to the wellbore enclosure that uses a zone isolation system with a first plug 46 and a second plug 48 separated distally from the first plug 46 and a fluid 52 (for example, the fluid 52 may be a single fluid type or formed from two or more fluid types) located between the first plug 46 and the second plug 48. Figure 4 represents a technique for applying disturbances to the wellbore enclosure that uses an elongated plug 50. Although the tension-inducing system configurations shown in Figures 3 and 4 are shown, other suitable tension-inducing systems are contemplated.The plugs 46, 48, 50 can be inflated to secure the plugs in a desired location in the central lumen 36 and can be inflated by pumping a fluid into the plugs with a pumping system (not shown, but which may be part of the tension induction system). In the configuration of Figure 3, disturbances can be applied to the casing pipe 34 of the wellbore enclosure 30 by means of a stress induction system that operates by inflating the first plug 46 at a first location along the length of the wellbore enclosure 30 and the second plug 48 at a second location along the length of the wellbore enclosure to define a volume along the length of the wellbore enclosure between the first plug 46 and the second plug 48. Fluid 52 can be supplied to the volume between the first plug 46 and the second plug 48 (at least after the distal plug is inflated and placed in the wellbore enclosure 30), so that the fluid 52 can be confined between the first plug 46 and the second plug 48.Fluid can be added to the volume between the first plug 46 and the second plug 48 in such a way that a desired pressure or stress can be applied radially outward (e.g., a fluid pressure) to a casing 34 of a length of the wellbore enclosure 30 from within the central lumen 36 to apply stress disturbances to the casing 34 and the subsurface formation 32 along the casing 34. In some cases, fluid 52 can be added to the volume between the first plug 46 and the second plug 48 using a suitable pump system (e.g., a surface pump or other suitable pump, not shown) and / or other suitable fluid movement system. The stress disturbances applied to casing 34 and the subsurface formation 32 along casing 34 may result from an increase in the volume of fluid 52 between the first plug 46 and the second plug 48. Although increasing the volume of fluid 52 between the first plug 46 and the second plug 48 by pumping fluid 52 into the space between the first plug 46 and the second plug 48 may be one technique for applying stress disturbances to casing 34 and the subsurface formation 32 along casing 34, there may be one or more additional or alternative techniques for applying stress disturbances.For example, stress disturbances can be applied to the casing 34 and the subsurface formation 32 along the casing 34 by using drastic temperature variations of the fluid pumped into the wellbore, using multi-component fluid chemical reactions that cause rapid gas expansion within the wellbore, and / or using other techniques that can be configured to increase the fluid volume 52 (e.g., increasing radial pressures outward) between the first plug 46 and the second plug 48. In the configuration shown in Figure 4, disturbances can be applied to the casing 34 of the wellbore chamber 30 by means of a tension induction system that operates by inflating the elongated plug 50. The elongated plug 50 can be inflated at a location along the length of the wellbore chamber 30 where it may be desired to apply tension to the casing 34 of the wellbore chamber 30. Furthermore, the elongated plug 50 can be inflated to a level configured to apply a desired external pressure or tension to the casing 34 along a length of the wellbore chamber 30 from within the central lumen 36. Any suitable measure of tension and / or pressure may be applied to the casing 34 using tension-inducing systems, so that the strain detection system 12 can detect or otherwise identify a value related to strain resulting from the tension / pressure applied to the casing 34. In some cases, the tension / pressure applied to the casing 34 of the wellbore enclosure 30 may be high enough to result in detectable strain, but may be kept below a pressure that could cause fracturing of the wellbore enclosure 30 and / or the subsurface formation 32.In an example of determining an amount of pressure or tension to apply to casing pipe 34, the plugs 46, 48, 50 can be inflated relatively slowly and / or the fluid can be added relatively slowly (e.g., increment or iteration additions) until the strain detection system 12 detects a first change in strain to avoid unnecessary fracturing of the wellbore enclosure 30 and / or adjacent subsurface formations.To help determine the mechanical and / or other suitable properties or conditions, the controller 14 and / or other computer devices or a user may record one or more of a pressure and / or strain at which the strain detection system 12 detected strain or a change in strain, a pressurization rate up to the pressure and / or strain that caused the detected strain, a time history of pauses and cycles of applying pressures and / or strains to the wellbore casing 34, and / or other suitable measurements related to the application of pressures and / or strains to the wellbore casing 34. Figure 5 represents a schematic flowchart of a procedure 100 for determining the mechanical properties of a formation (e.g., subsurface formation 32 and / or other suitable formations) along a wellbore enclosure (e.g., wellbore enclosure 30 and / or other suitable wellbore enclosures). In some cases, procedure 100 can be used to generate a continuous stress prediction log around the wellbore enclosure and / or can be used for other suitable purposes. Although procedure 100 can include several features, as shown in Figure 5, it can also include one or more additional or alternative features, as desired.Furthermore, the instructions for executing the features of procedure 100 can be stored in a non-transient state in memory (e.g., on a computer-readable medium such as memory 24 and / or other suitable memory) for execution by a processor (e.g., processor 22 and / or other suitable processor). The mechanical properties of the formation along a wellbore enclosure can be estimated or determined using systems similar to or different from those represented in Figures 3 and 4.Example systems used to determine the mechanical properties of the formation along the length of the wellbore enclosure may include, but are not limited to, one or more plugs (e.g., plugs 46, 48, 50 and / or other suitable plugs) to apply tension to a casing (e.g., casing 34 and / or other suitable casing) of the wellbore enclosure, a strain detection system (e.g., strain detection system 12 and / or other suitable strain detection system) configured to determine strain in or along the wellbore enclosure casing in response to tension applied to the casing, and a controller (e.g., controller 14 and / or other suitable controller) in communication with the strain detection system and / or a system configured to apply tension to the casing. Procedure 100 may include initiating 102 the application of disturbances to a casing at one or more locations along the length of the wellbore enclosure. The disturbances may cause a force to be applied to the casing along the length of the wellbore enclosure. When using a configuration similar to that shown in Figures 3 and 4, disturbances may be applied to the casing by using packers as a result of inflating the packers and / or as a result of inserting a fluid between two or more packers by means of a pump or other fluid movement mechanism. It is contemplated that tension may be applied to the casing of the wellbore enclosure at one or more known locations in one or more suitable ways.Furthermore, as discussed earlier, a certain amount of stress applied to the casing pipe can be kept below a level that would cause fracturing. Based on the disturbances applied or to be applied to the casing, a measure or value related to the amount of stress applied to the wellbore casing by the disturbances can be determined. The determination of the amount of stress applied to the wellbore casing can be based on the following equation: σ = F / A (1) where, F is a quantity of force applied to a surface and A is a quantity of surface area to which the force is applied. When plugs are used to apply a radial outward tension to a wellbore casing, as shown in Figures 3 and 4 and / or in other suitable cases, the force may be the pressure applied to the casing and the area may be the surface area on which the plugs apply the force and / or on which the fluid between the plugs applies the force. Any suitable amount of tension may be applied radially outward to the wellbore casing that can facilitate the identification of the mechanical properties of a formation along an outer or outer surface of the wellbore casing. For example, the suitable amount of tension applied might be large enough to cause detectable deformation in or along the casing, but low enough not to cause cracks or fractures in the wellbore and / or surrounding formations. In some cases, a controller (e.g., Controller 14 and / or another suitable controller) may determine a specific amount of tension to apply to the casing, but this is not required. Deformation can be detected along the length of the wellbore, and a measurement or value related to the deformation resulting from the stress applied to the casing can be identified along a length of the wellbore. When using the deformation detection system discussed with reference to Figures 1, 3, and 4, the measurement or value related to the deformation can be detected using a fiber optic cable (e.g., fiber optic cable 16 and / or other suitable fiber optic cables). The measurement or value related to the deformation can be identified based on the values ​​of a parameter measured using the fiber optic cable and received by a detector (e.g., detector 18 and / or another suitable detector) and / or a controller (e.g., controller 14 and / or another suitable controller).In one example, the parameter values ​​may be related to a quantity and / or pattern of light reflected and / or identified by the strain detection system's detector. Additionally, or alternatively, other strain detection systems may be used to detect strain along the length of the wellbore enclosure. In some cases, a strain / strain log or database can be set up and stored in memory (e.g., memory 24 of controller 14 and / or other suitable memory).The stress / strain log or database may include an entry for a value related to (for example, a value of or otherwise a value of a function of) an amount of force applied to the casing, a surface area where the force was applied to the casing, a value related to the amount of stress applied to the casing, the rate at which stress was applied to the casing, the location where stress was applied to the casing, the date and time stress was applied to the casing, a value related to strain detected along the length of the wellbore where stress was applied to the casing, and / or one or more suitable entries. Based on the determined value related to the stress applied to the wellbore casing and the identified value related to the deformation resulting from the value related to the stress applied to the casing along the length of the wellbore, a value related to a mechanical property of the formation extending along the length of the wellbore can be determined. In some cases, the mechanical property of the formation for which the value is determined may be one or more elastic properties, elastic moduli, stress gradients, vertical stress, pore water pressure, minimum horizontal stress, and / or one or more suitable mechanical properties. In some cases, the value related to the mechanical property of the formation can be determined, at least in part, based on Hooke's Law. Hooke's Law states that the deformation in a solid is proportional to the applied stresses within the elastic limit of that solid and can generally be represented as follows: σ = (C)(e) (2) where, σ represents an amount of stress applied to a solid, ε represents an amount of stress in the solid in response to the amount of stress applied to the solid, and C represents a stiffness of the solid, where the stiffness can be a function of one or more elastic constants and / or other suitable mechanical properties determined according to the type or types of material of the solid. Once determined, the value related to the mechanical property of the formation extending along the length of the wellbore enclosure can be added to the stress / strain log or database, if one or more are maintained. In some cases, features 102, 104, 106, and 108 of procedure 100 can be repeated at various locations along the length of the wellbore enclosure and / or at additional time (e.g., at predetermined time intervals and / or other suitable times) to facilitate the identification of the mechanical properties of the formation along the length of the wellbore enclosure and / or to facilitate the determination of how the mechanical properties of the formation change over time along the length of the wellbore enclosure. Using the general form of equation (2), the stiffness, other suitable mechanical properties and / or other suitable properties or conditions of the formation extending along the length of the wellbore enclosure can be determined based on the applied stress and the deformation detected in response to the applied stress.For example, and assuming a tight fit between the wellbore casing and the formation along the length of the wellbore, the value related to the stiffness of the formation can be a function of the mechanical properties of the casing and the mechanical properties of the formation that extends along the length of the wellbore, and if the mechanical properties of the casing are known (for example, since the casing material is usually well-defined materials that have known mechanical properties), the mechanical properties (for example, stiffness and / or other suitable mechanical properties) of the formation that extends along the length of the wellbore can be determined. In some cases, the value related to the mechanical property of the formation can be compared to a threshold level (e.g., a threshold value), and one or more control actions and / or other appropriate decisions can be taken based on the comparison (e.g., based on determining whether the value related to the mechanical property has reached or exceeded the threshold level). In one example, the control signal can be provided to highlight or mark a location along the length of the wellbore where it may be desirable to initiate fracturing of the formation extending along the length of the wellbore. Other appropriate control signals are considered. In some cases, disturbances applied to the casing along the length of the wellbore can begin at a first time, t1, and a second time, t2. When disturbances are applied to the casing along the wellbore at or approximately the first time, t1, and the second time, t2, a value for the stress applied to the casing along the length of the wellbore can be determined at the first time, t1, and at the second time, t2. Similarly, a value related to the strain resulting from the stress applied to the casing along the length of the wellbore can be determined at the first time, t1, and at the second time, t2. Therefore, a value related to the mechanical property of the formation along the length of the wellbore can be determined at the first time, t1, and at the second time, t2.In some cases, a change in the value related to the mechanical property of the formation can be identified or determined from the value determined at the first time, t1, to the value determined at the second time, t2. The change in the value related to the mechanical property can be compared with the threshold level (e.g., a threshold value) and a control action can be generated when the change in the value related to the elastic property reaches or exceeds the threshold level. Figure 6 represents a schematic flowchart of a procedure 200 for establishing a model of the mechanical properties of a formation (e.g., subsurface formation 32 and / or other suitable formations) that extends along a wellbore (e.g., wellbore 30 and / or other suitable wellbore). Example models of the mechanical properties of a formation (e.g., the subsurface formation extending along the length of the wellbore) may include a model of the mechanical properties of the formation along the entire length of the wellbore and / or models of the mechanical properties along one or more sub-lengths of the length of the wellbore. Although procedure 200 may include several features, as shown in Figure 6, it may also include one or more additional or alternative features, as desired. Furthermore, while the features of procedure 200 may be described and represented in a specific order in Figure 6, one or more of these features may be implemented in one or more suitable sequences. Additionally, the instructions for executing the functions of procedure 200 may be stored in a non-transient state in memory (e.g., in computer-readable memory, such as memory 24 and / or other suitable memory) for execution by a processor (e.g., processor 22 and / or other suitable processor). Procedure 200 may include determining or providing 202 an initial estimate of a stress gradient or stiffness of the formation material extending along or around the wellbore enclosure. This feature is optional, and it may be possible to model the mechanical properties of a formation without providing 202 an initial estimate of the stress gradient or stiffness of the formation material.Furthermore, although the initial estimate of a stiffness or stress gradient can be calculated and be useful when establishing one or more mechanical property models for the formation, the initial estimates of the stress or stiffness gradient may be linear gradients or sectioned by a linear section gradient, meaning that the initial estimates may be crude and may not take into account the variability of mechanical properties and / or stress in individual materials or at individual locations throughout the formation. The stress gradient or formation stiffness can be determined based on known values ​​related to the subsurface material assumed to be present in the subsurface formation along the length of the wellbore. Alternatively, or additionally, a more detailed estimate of the stress gradient or stiffness of the material forming the wellbore can be determined based on data acquired from diagnostic fracture injection (DFIT) tests, minifracturing tests, and / or other suitable tests or known quantities. An example of determining the formation's stress gradient or stiffness based on known values ​​of the subsurface material assumed to be present in the formation can utilize values ​​for one or more parameters (e.g., mechanical properties and / or other suitable properties or conditions) of the formation's constituent materials. Example parameters include, but are not limited to, vertical stress, pore water pressure, minimum horizontal stress, etc. In some cases, the lithology of a vertical section (e.g., the thickness and average density of the vertical section) of the formation can be used to determine vertical stress at one or more depths within the formation (e.g., at one or more locations along the length of the wellbore). Pore water pressure can be estimated based on wellbore tests.The minimum horizontal stress can be estimated from existing field data for a region, DFIT data, or wellbore tests. In an example of determining the stress gradient or stiffness of a formation in a subsurface formation in West Texas, the pore water pressure might be 0.45 psi / ft, the vertical stress might be 1.08 psi / ft, and the minimum horizontal stress might be 0.7 psi / ft. In this example, the stiffness or stress gradient (i.e., the minimum effective stress) might be 0.38 psi / ft. ηαζίτηη / ζζηζ / Ε / γίΛΐ Procedure 200 may include establishing 204 an initial model of formation stiffness or elasticity around the wellbore enclosure that can describe the mechanical properties and anisotropy of the materials assumed to form the formation. The formation layer material can be any suitable type of material, as discussed earlier, that has one or more different or similar mechanical properties. In some cases, the mechanical properties of the material may include homogeneous and isotropic properties that can be represented by two elastic constants (e.g., Young's modulus and Poisson's ratio), may include transverse isotropic properties that have five different elastic constants, may include orthotropic properties, and so on. The stiffness or elasticity model of the formation can be based on Hooke's Law, as discussed previously. An initial mechanical model (e.g., stiffness or elastic model) of a multi-layered formation around the wellbore can take the following form (transverse isotropy): ηοζίτηη / ζζηζ / Ε / γίΛΐ Γσ111 'Gi G2 Gs 0 0 0 Γ £11 1 σ22 G2 G2 Gs 0 0 0 ^22 σ33 σ23 = Gs 0 G3 0 Gs 0 0 C44 0 0 0 0 ε33 2^23 (3) σ31 0 0 0 0 C44 0 2^31 -σ21- . 0 0 0 0 0 Go -2^21- σ is stress, C is stiffness (e.g., a stress gradient), ε is strain, and the stress subscript σ and strain subscript ε represent a coordinate system (e.g., orientation axes), where “3” can be a direction or axis perpendicular to a bed plane or subsurface layer, and “1” and “2” represent directions or axes in the bed plane or subsurface layer. The stiffness C can be a function of the elastic constants (e.g., mechanical properties) of the formation material(s) around the wellbore. In an example of an initial model of the formation's mechanical properties, the initial stress gradient estimate for the formation (e.g., initial stress gradient estimates for the formation as a whole or initial stress gradient estimates per formation layer), when provided, can be used as the stiffness C (or stiffness Cij). The stress σ can be a combination of one or more natural stresses and / or human-applied stresses. For example, the stress σ applied to the formation along the length of the wellbore enclosure might include man-made stresses applied to the wellbore casing at one or more locations along the length of the wellbore (e.g., disturbances applied through plugs, seals, and pressurized fluid, and / or other suitable stress-applying techniques), known stresses from any overburdened formation material, tectonic stresses, etc. The strain ε can be detected in one or more ways and can be assumed to follow known or predictable strains. The strain ε can be a combination of (for example, a function of) the strain resulting from the stress applied to the wellbore casing that has been detected in one or more directions. If the strain is elastic, the strain-related values ​​can follow known strain profiles for a circular cavity. If the strain is inelastic, the strain-related values ​​can be determined using fracture mechanics. Procedure 200 may include the detection 206 of deformation along the length of the wellbore that may occur in response to stress applied to a casing (for example, casing 34 and / or one or more suitable casings) of the wellbore. In some cases, the detection of deformation along the length of the wellbore may include the identification of a value related to a deformation resulting from the stress applied to the casing. Deformation can be detected using any suitable strain detection system (e.g., strain detection system 12 and / or another suitable strain detection system). In some cases, deformation resulting from stress applied to the casing can be detected similarly to how deformation resulting from stress applied to the casing can be identified, as explained with respect to Procedure 100 and Figures 1, 3, and 4. ηοζίτηη / ζζηζ / Ε / γίΛΐ Tension can be applied to the wellbore casing radially outward from a central lumen (e.g., the central lumen 36 and / or another suitable central lumen) defined by the wellbore in a manner similar to how tension can be applied to the casing as described with respect to Procedure 100 and Figures 3 and 4. Alternatively or additionally, tension can be applied to the casing in one or more suitable ways. Once the stress resulting from the applied tension on the casing has been detected, an empirical stiffness or stress gradient (e.g., a stiffness coefficient) can be determined based on the applied tension and the detected stress using Hooke's Law. Once the empirical stress gradient has been determined for the location or length of the wellbore where the tension was applied to the casing, the initial stress gradient estimate can be updated to facilitate the determination of a formation stress gradient and the formation stress. The gradient can then be used to update the initial stiffness model to determine an empirically developed formation model of the mechanical properties of the materials comprising the formation along the length of the wellbore. In some cases, steps 206 and 208 can be repeated for each location and / or length where tension is applied to the casing. When this occurs, not only can formation tension gradients and formation models be established for each location, but an overall formation tension gradient and formation model can also be established for the formation along the entire length of the wellbore. For example, the formation tension gradient along the entire length of the wellbore can be a function of the formation tension gradients at individual formation locations adjacent to the intersection points where the tension applied to the casing intersects the tension detection system's resolution points.Alternatively or additionally, the formation stress gradient and / or formation model at particular locations can be interpolated or extrapolated to form the formation stress gradient and formation model for the formation along the entire length of the wellbore enclosure, even at resolutions higher than a stress-sensing system resolution, as discussed below. Once a formation model has been developed (e.g., for one or more locations along the length of the wellbore and / or for a full length of the wellbore) for a formation along a length (e.g., a full length or a portion) of the wellbore, the formation model can be used to determine formation models (e.g., physical properties and / or physical characteristics) for subsurface formation materials in sub-sections of the length of the wellbore.In one example, the length of a portion of the wellbore enclosure may be a three-foot section of the wellbore enclosure, and formation models may be determined for sub-sections of a subsurface formation along the three-foot section of the wellbore enclosure (e.g., formation models may be determined for subsurface formations on a fine scale, where a fine scale may be a scale or lengths smaller than the resolution of the strain detection system).Figure 7 shows a schematic illustration of the use of a formation model for a length of formation along a wellbore enclosure to determine a formation configuration, a number of formation layers (e.g., sub-reaches), a location of the formation layers, a type of formation layer material, a formation model for the formation layers, and / or other appropriate information about the formation along sub-reaches of the wellbore enclosure. As depicted in Figure 7, a first pillar 60 having a sub-span L0 can represent a formation model (or at least a stiffness gradient) of the formation along a length of wellbore. A second pillar 62, a third pillar 64, and an Nth pillar 66 can represent potential formation configurations, where each of the second pillar 62, the third pillar 64, and the Nth pillar 66 can have any suitable number of sub-spans. In the example in Figure 7, each of the second pillar 62, the third pillar 64, and the Nth pillar 66 can have a first sub-span L1, a second sub-span L2, a third sub-span L3, a fourth sub-span L4, and an Nth sub-span Ln.One pillar of solution 68 can be selected from the N pillars and can represent a more probable configuration of the formation along the length of the wellbore enclosure broken down into formation models of the formation in each of the N sub-sections of the length of the wellbore enclosure. The second pillar 62 may indicate that the formation along each sub-reach of the wellbore enclosure may have a different sub-reach formation model, as indicated by different markings (e.g., shading) in each sub-reach. The third pillar 64 and the Nth pillar 66 may indicate that the same formation model can be used to describe the formation along two or more sub-reaches of the wellbore enclosure (e.g., four (4) sub-reaches in the third pillar 64 and two sub-reach lengths in the Nth pillar 66), as indicated by a sub-reach having markings similar to those in one or more sub-reaches. Different layers of the subsurface formation can be identified when adjacent sub-reaches are described by different formation models. There can be any suitable number of formation configurations, which can be based on a number of possible material types (e.g., the types of materials known to be within or around the formation along the length of the wellbore), a number of sub-lengths (e.g., which can be defined by a strain detection system resolution, a known or estimated number of layers in a length of the formation, etc.), and / or other suitable parameters. For example, when the formation along the length of the wellbore is known to be divisible into five sub-lengths and there are eight possible material types, there can be 32,768 possible combinations of material types for those five sub-lengths.As such, when the length of the wellbore enclosure can be a three-foot section, there are 32,768 possible combinations of material types for the five sub-spans of the three-foot section. Although the example using a three-foot length of the wellbore provides an illustration of how to determine material types on a fine scale, similar concepts can be used to determine material types and / or physical properties or characteristics on other scales. Pillar 68 of the solution can be identified as the most probable subsurface formation configuration based on the statistical analysis of the overall formation model (e.g., a formation model for the subsurface formation along the entire length of the wellbore as opposed to a formation model for a portion of the subsurface formation along only a sub-section of the wellbore) with respect to the formation models associated with the possible formation configurations. For example, if the types of subsurface materials (e.g., rock, etc.) that can form the formation are known, and if the mechanical properties of those material types are generally known, it is possible to determine which combination of material types and where those material types are most likely to be located to form the formation along the length of the wellbore in order to produce the overall formation model. These techniques can be used to determine where, along the layers of the wellbore, a subsurface material type changes, the type of formation changes (e.g., how the material formed at that location, including, but not limited to, through heat, flooding, etc.), the mechanical properties change, and so on. Furthermore, in some cases, as mentioned earlier, it may be possible to apply these techniques on a fine scale, where the length along the wellbore is a length equal to the resolution of the strain detection system (e.g., one meter, three feet, and / or one or more suitable resolutions), to determine the mechanical properties of materials, material types, layer locations, and so forth at different locations within the formation that differ in location by less than the resolution of the strain detection system.For example, when the strain detection system resolution is one (1) meter, the fine-scale mechanical properties of a formation can be established for locations along the length of the wellbore that are between the first meter and the second meter of the wellbore, between the second meter and a third meter of the wellbore, etc. Once a formation model for the subsurface formation material has been developed based on empirical data and several stress or stiffness gradients (Cij) are known, the formation model and / or the stress or stiffness gradients of the formation model can be used to determine or estimate the mechanical properties and / or other appropriate properties or conditions (e.g., which may or may not be related to mechanical properties) of the subsurface formation. Example properties or conditions of the subsurface formation that can be determined or estimated include, but are not limited to, vertical stress, pore water pressure, minimum horizontal stresses, etc. One or more of a variety of techniques for determining or identifying properties or conditions (e.g., stresses) of subsurface formations can be used. One example technique for determining or identifying properties or conditions of subsurface formations includes the use of a lithostatic model, for example, as described in Engelder, T., 1993. Stress regimes in the lithosphere, Princeton Univ. Press., which is incorporated here by reference in its entirety. Another example of a technique for determining or identifying properties or conditions of subsurface formations includes the use of a friction equilibrium procedure, for example, as discussed in Brace, WF & Kohlstedt, DL, 1980. Limits on lithospheric stress imposed by laboratory experiments, J. Geophys. Res., 85(B11), 6248-5252, which is incorporated here by reference in its entirety, and Jaeger, JC, Cook, NGW and Zimmerman, RW, 2007. Fundamentals of rock mechanics, Blackwell Publishing.Another example of a technique for determining or identifying properties or conditions of subsurface formations includes the use of a laterally constrained model, for example, as discussed in Terzaghi, K. & Richart, FE, 1952. Stresses in rock about cavities, G'eotechnique, 3(2), 57-90, which is incorporated here by reference in its entirety, and Eaton, BA, 1969. Fracture gradient prediction and its application in oilfield operations, J. Pet. Technol., 246, 1353-1360, which is incorporated here by reference in its entirety. Another example of a technique for determining or identifying the properties or conditions of subsurface formations includes the use of an extended Eaton procedure, for example, as discussed in Savage, WZ, Swolfs, HS and Amadei, B., 1992. On the stress in the near-surface of the Earth's crust, Puré Appl. Geophys., 138(2), 207-228, which is incorporated herein as a reference in its entirety, and Thiercelin, MJ & Plumb, RA, 1994.Core-based prediction of lithologic stress contrasts in East Texas formations, SPE Form. Eval., 9(4), 251-258, which is incorporated here by reference in its entirety. Another example of a technique for determining or identifying the properties or conditions of subsurface formations includes the use of a viscoelastic Maxwell model, as discussed in Savage et al. 1992, which was incorporated by reference in its entirety above, Warpinski, NR, 1986. Elastic and viscoelastic model of the stress history of sedimentary rocks, Tech. Rep. Sand 86-0238, Sandia National Laboratories, which is incorporated herein by reference in its entirety, and Warpinski, NR, 1989. Elastic and viscoelastic calculations of stresses in sedimentary basins, SPE Formation Evaluation, 4, which is incorporated herein by reference in its entirety. As mentioned previously, the system and techniques discussed in this document can be used to capture sufficient information to provide a continuous wellbore log of horizontal stresses and / or material properties of the subsurface formation material along a wellbore. In other words, the techniques discussed here can be performed repeatedly along the length of the wellbore to provide a completely continuous log of fine-scale mechanical properties and / or horizontal stress estimates. Those skilled in the art will recognize that the present description may manifest itself in a variety of forms other than the specific embodiments described and contemplated herein. Accordingly, a deviation in form and detail may be made without departing from the scope and spirit of this disclosure as described in the appended claims.

Claims

1. A method for determining the elastic properties of a formation along a wellbore, the method comprising: initiating the application of disturbances to a casing of a length of the wellbore, the disturbances causing a force to be applied to the casing of the length of the wellbore; determining a value related to the stress applied to the casing along the length of the wellbore, based on the force applied to the casing; identifying a value related to the deformation resulting from the value related to the stress applied to the casing of the length of the wellbore;and determine a value related to an elastic property of a formation that extends along the length of the wellbore based on the value related to the stress applied to the casing and the value related to the deformation resulting from the stress applied to the casing along the length of the wellbore; 2. The method of claim 1, wherein the start of the application of disturbances to the casing of a length section of the wellbore includes starting the application of disturbances to the casing of the section of the wellbore from a central lumen of the wellbore.

3. The method of claim 1, wherein the formation extending along the length of the wellbore enclosure extends along the outside of the wellbore casing pipe.

4. The method of claim 1, wherein: the formation extending along the length of the wellbore enclosure has a plurality of layers; and the determination of a value related to the elastic property for the formation extending along the length of the wellbore enclosure includes determining the elastic property for each layer of the plurality of layers of the formation. nozfrnn / zznz / E / YiAi 5. The method of claim 1, further comprising: receiving values ​​of a parameter measured by a distributed strain detection system that extends along the length of the well enclosure.

6. The method of claim 5, wherein the identification of the value related to the deformation resulting from the stress applied to the casing pipe of the length of the wellbore enclosure includes determining the value related to the deformation resulting from the stress applied to the casing pipe of the length of the wellbore enclosure based on the values ​​received from the parameter measured by the distributed strain detection system.

7. The method of claim 1, wherein: the start of the application of disturbances to a casing pipe of a length of the wellbore comprises the start of the application of disturbances to the casing pipe of the length of the wellbore at a first time, t1, and at a second time, t2; the determination of the value related to the stress applied to the casing pipe along the length of the wellbore as a function of the stress applied to the casing pipe comprises determining a value of the stress applied to the casing pipe along the length of the wellbore at the first time, t1, and at the second time, t2;Identifying the value related to the deformation resulting from the stress applied to the casing along the length of the wellbore comprises determining a value related to the deformation resulting from the stress applied to the casing along the length of the wellbore at the first time, t1, and at the second time, t2; and determining the value related to the elastic property of a formation extending along the length of the wellbore, based on the value related to the stress applied to the casing and the value related to the deformation resulting from the stress applied to the casing along the length of the wellbore, comprises determining a value related to the elastic property of the formation extending along the length of the wellbore at the first time, t1, and at the second time, t2. ηαζίτηη / ζζηζ / E / γίΛΐ; 8. The method of claim 7, further comprising: determining a change in the value related to the elastic property determined at the first time, t1, and the value related to the elastic property determined at the second time, t2; comparing the change in the value related to the elastic property with a threshold level; and issuing a control action when the change in the value related to the elastic property reaches or exceeds the threshold level.

9. The method of claim 1, wherein the initiation of the application of disturbances to the casing pipe along the length of the wellbore enclosure, the determination of the value related to the stress applied to the casing pipe along the length of the wellbore enclosure, the identification of the value related to the stress resulting from the stress applied to the casing pipe along the length of the wellbore enclosure, and the determination of the value related to the elastic property of the formation extending along the length of the wellbore enclosure are repeated at predetermined intervals.

10. The method of claim 9, further comprising: maintaining a database of values ​​related to the elastic property of the formation that extends along the length of the wellbore enclosure that are determined at each of the predetermined intervals.

11. The method of claim 1, further comprising: establishing a force-related value to be applied by disturbances to the casing pipe of the length of the wellbore enclosure; and wherein the force-related value is configured to avoid fracturing the wellbore enclosure and avoid fracturing the formation that extends along the length of the wellbore enclosure.

12. A controller configured to establish an elastic property of a formation extending along the outside of a casing pipe in a wellbore, the controller comprising: a processor; an input port communicating with the processor; and memory storage instructions configured to be executed by the processor to cause the processor to: determine a value related to a stress applied to a casing pipe of a length of the wellbore when disturbances are applied to the casing pipe of the length of the wellbore; receive, through the input port, values ​​related to a parameter measured by a distributed strain detection system while disturbances are applied to the casing pipe of the length of the wellbore;Determine a value related to a strain resulting from the stress applied to the casing along the length of the wellbore based on the values ​​related to the parameter measured by the distributed strain detection system that are received; and determine a value related to an elastic property of a formation that extends along the length of the wellbore based on the value related to the stress applied to the casing along the length of the wellbore and the value related to the strain resulting from the stress applied to the casing along the length of the wellbore.

13. The controller of claim 12, wherein the memory further comprises instructions configured to be executed by the processor to cause the processor to: establish a value related to a disturbance force to be applied to the casing pipe of the length of the wellbore enclosure.

14. The controller of claim 13, wherein the force-related value is set to prevent fracturing of the wellbore enclosure and to prevent fracturing of the formation extending along the length of the wellbore enclosure.

15. The controller of claim 12, wherein the memory further comprises instructions configured to be executed by the processor to cause the processor to: determine a value related to the elastic property for each layer of a plurality of layers forming the formation extending along the length of the wellbore enclosure.

16. The controller of claim 12, wherein the memory further comprises instructions configured to be executed by the processor to cause the processor to: repeat at predetermined intervals: the determination of the value related to the stress applied to a casing pipe of a length of the wellbore; the reception, through the input port, of the values ​​related to the parameter measured by the distributed strain detection system; the determination of the value related to the strain resulting from the stress applied to the casing pipe of the length of the wellbore; and the determination of the value related to an elastic property of a formation extending along the length of the wellbore;and maintain a database of values ​​related to the elastic property of the formation that extends along the length of the wellbore enclosure determined at each of the predetermined intervals.

17. The controller of claim 12, wherein the distributed strain detection system includes an optical fiber cable extending along the length of the well enclosure and the values ​​received from the distributed strain detection system are related to one or both of a quantity of light and a light pattern received on a light detector of the distributed strain detection system.

18. A system for establishing elastic properties, the system comprising: a distributed strain detection system configured to detect a parameter related to the strain resulting from a stress applied to a casing pipe of a length equal to a wellbore enclosure, the distributed strain detection system comprising: an elongated fiber configured to extend along the length of the wellbore enclosure; and a strain detection controller configured to provide values ​​of a parameter measured using the elongated fiber, the parameter values ​​being related to the strain resulting from a stress applied to the wellbore enclosure;A controller in communication with the distributed strain detection system, the controller is configured to determine an elastic property of a formation that extends along the outside of the casing pipe the length of the wellbore enclosure based on the measured parameter values ​​using the elongated fiber.

19. The system of claim 18, wherein the controller is configured to: receive an input of a value related to a stress applied to the casing of the length of the wellbore enclosure; and determine the elastic property of the formation extending along the outside of the casing of the length of the wellbore enclosure based on the measured parameter values ​​using the elongated fiber and the value related to the stress applied to the casing of the length of the wellbore enclosure.

20. The system of claim 18, wherein the controller is configured to: determine a value related to a stress to be applied to the casing of the length of the wellbore enclosure; and determine the elastic property of the formation extending along the outside of the casing of the length of the wellbore enclosure based on the values ​​of the parameter measured using the elongated fiber and the value related to the stress to be applied to the casing of the length of the wellbore enclosure.

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