IN-SITU PROPERTY DETERMINATION

Abstract

In one possible implementation an in-situ property determination system includes a displacement tool configured for use in a wellbore. The displacement tool includes four or more pads symmetrically located about an axis of the displacement tool, with each pad having a contact surface configured to contact a wall of the wellbore. The four or more pads can extend from a first position proximate an outer surface of the displacement tool to a second position in contact with the wall of the wellbore such that the four or more pads deform the wellbore into an at least approximately circular cross section. The system also includes a recordation device to record force displacement information associated with extending the four or more pads from the first position to the second position.

Description

RELATED APPLICATIONS

This application claims the benefit of US Provisional Application having Ser. No. 62/317,084 entitled “In-Situ Property Determination” filed Apr. 1, 2016, which is incorporated in its entirety by reference herein.

BACKGROUND

Logging tools have long been used in wellbores to help operators infer properties associated with a formation, such as, for example, the permeability of a section of the formation, the types and amounts of fluids in the formation, etc. Common logging tools include resistivity (electromagnetic) tools, nuclear tools, acoustic tools, and nuclear magnetic resonance (NMR) tools, though various other types of tools for evaluating formation properties are also available. Common logging tools also include measurements tools that are in contact with the formation and stationary at a given depth for a short period of time while performing a measurement, such as dual-packer stress testing and/or fluid analyzer tools.

Early logging tools were run into a wellbore on a wireline cable after the wellbore had been drilled. Modern versions of such wireline tools are still used extensively.

The above descriptions and examples are not admitted to be prior art by virtue of their inclusion in this section.

SUMMARY

In-situ property determination is provided. In one possible implementation an in-situ property determination system includes a displacement tool configured for use in a wellbore. The displacement tool includes four or more pads symmetrically located about an axis of the displacement tool, with each pad having a contact surface configured to contact a wall of the wellbore. The four or more pads can extend from a first position proximate an outer surface of the displacement tool to a second position in contact with the wall of the wellbore such that the four or more pads deform the wellbore into an at least approximately circular cross section. The system also includes a recordation device to record force displacement information associated with extending the four or more pads from the first position to the second position.

In another possible implementation, a method of in-situ property determination includes activating a displacement tool at a desired depth in a wellbore to deform the wellbore from an at least approximately elliptical cross section to an at least approximately circular cross section. The method also includes recording force displacement information associated with deforming the wellbore from the at least approximately elliptical cross section to the at least approximately circular cross section.

In yet another possible implementation, a computer-readable tangible medium has instructions stored thereon that, when executed, direct a processor to access force displacement information associated with deforming a wellbore from an at least approximately elliptical cross section to an at least approximately circular cross section. The computer-readable tangible medium also has instructions stored thereon that, when executed, direct a processor to utilize at least a portion of the force displacement information associated with deforming the wellbore from the at least approximately elliptical cross section to the at least approximately circular cross section to estimate a far-field stress ratio associated with the formation.

This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

Features and advantages of the described implementations can be more readily understood by reference to the following description taken in conjunction with the accompanying drawings.

FIG. 1 illustrates an example wellsite in which embodiments of in-situ property determination can be employed;

FIG. 2 illustrates an example computing device that can be used in accordance with various implementations of in-situ property determination;

FIG. 3 illustrates an example concept of stress compensation for a wellbore configuration in accordance with implementations of in-situ property determination;

FIG. 4 illustrates an example displacement tool in accordance with implementations of in-situ property determination;

FIG. 5 illustrates example schematic force versus displacement curves for two pads at different angles with respect to the in-situ horizontal stress direction in accordance with implementations of in-situ property determination;

FIG. 6 illustrates an example ratio of forces acting on a first pad over a second pad for different positions of the first pad with respect to the maximum stress direction in accordance with implementations of in-situ property determination;

FIG. 7 illustrates an example ratio of the radial displacement u_r over radius “a” induced by the release of the far-field stress for different azimuthal positions with respect to the direction of maximum stress (σ₁) in accordance with implementations of in-situ property determination; and

FIG. 8 illustrates example method(s) in accordance with implementations of in-situ property determination.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure. However, it will be understood by those of ordinary skill in the art that systems and/or methodologies may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

Additionally, some examples discussed herein involve technologies associated with the oilfield services industry. It will be understood however that the techniques of in-situ property determination may also be useful in a wide range of other industries outside of the oilfield services sector, including for example, mining, geological surveying, etc.

Moreover, it will also be understood that the term “optimize” as used herein can include any improvements up to and including optimization. Similarly, the term “improve” can include optimization. Other terms like “minimize” and “maximize” can also include actions reducing and increasing, respectively, various quantities and qualities.

As described herein, various techniques and technologies associated with in-situ property determination can be used, for example, to estimate various properties of a formation by recording the forces used to alter the shape of a cross section of a wellbore. In one possible implementation, this can include recording forces to restore a wellbore from an at least approximately elliptical cross section to an at least approximately circular cross section. In another possible implementation, forces applied to hold the wellbore in the at least approximately circular cross section can be recorded. In still another possible implementation, forces applied to allow the wellbore to deform back to an at least approximately elliptical cross section from the at least approximately circular cross section can be recorded. It will be understood that the term “at least approximately elliptical cross section” as used herein, can denote an elliptical cross section as well as cross sections that fall short of being elliptical due to shape affecting wellbore issues including, for example, irregularities, small washouts, etc.

Example Wellsite

FIG. 1 illustrates a wellsite 100 in which embodiments of in-situ property determination can be employed. Wellsite 100 can be onshore or offshore. In this example system, a wellbore 102 is formed in a subsurface formation 104 by drilling in any manner known in the art, including for example, rotary drilling, directional drilling, etc.

In one possible implementation, a wellbore logging tool 106, such as, for example, a wireline tool (including a wireline measurement tool configured to take station measurements), can be used to acquire data that is associated with formation 104. Wellbore logging tool 106 can be disposed within wellbore 102 in any way known in the art and can be moved anywhere desired along wellbore 102 by, for example, an operator. In one possible implementation, wellbore logging tool 106 can include a variety of tools, including, for example, an NMR tool 108 to perform NMR measurements of formation 104, other nuclear tools, such as neutron porosity tools, to gather porosity data associated with formation 104, etc.

In one possible embodiment, wellbore logging tool 106 can also include a displacement tool 110 to perform various actions in accordance with the principles of in-situ property measurement described herein. In one possible aspect, displacement tool 110 can be alone on wellbore logging tool 106. In another possible aspect, displacement tool 110 can be accompanied by other tools on wellbore logging tool 106. It will also be understood that in other possible implementations, displacement tool 110 can be deployed in wellbore 102 on its own, using any deployment technologies and/or equipment known in the art.

In one possible implementation, wellbore logging tool 106 (and/or displacement tool 110) can be coupled to a processing system 112 using any technology known in the art, including, for example, wireless technologies, wireline technologies, etc. Processing system 112 can receive and process a variety of information associated with the various tools on wellbore logging tool 106, including displacement tool 110. Processing system 112 can also control a variety of equipment, including wellbore logging tool 106, displacement tool 110, etc.

Processing system 112 can be used with a wide variety of oilfield applications, including logging while drilling, artificial lift, measuring while drilling, wireline, etc. Processing system 112 can be located at a surface 114 of wellsite 100, below surface 114, proximate to wellbore 102, on displacement tool 110, remote from wellbore 102, and/or any combination thereof.

For example, in one possible implementation, information associated with displacement tool 110 can be processed by processing system 112 at one or more locations, including any configuration known in the art, such as in one or more handheld devices proximate and/or remote from wellsite 100, at a computer located at a remote command center, etc. In one possible implementation, processing system 112 can also perform various aspects of in-situ property determination, as described herein, to process various measurements and/or information.

The term “processing system” is not limited to any particular device type or system. For example, processing system 112 may include a single processor, multiple processors, or a computer system. Such a computer system may include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, or general purpose computer) for executing any of the methods and processes described herein. The computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card), or other memory device.

Some of the methods and processes described herein, can be implemented as computer program logic for use with the computer processor. The computer program logic may be embodied in various forms, including a source code form and/or a computer executable form. Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language, and/or a high-level language such as C, C++, Matlab, JAVA or other language or environment known in the art.). Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor. The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), and/or distributed from a server and/or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).

Alternately or additionally, processing system 112 may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and/or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)). In one possible aspect, any of the methods and processes described herein can be implemented using such logic devices.

In one possible implementation, wellbore logging tool 106 can take “continuous” measurements (such as, for example, as wellbore logging tool 106 is continuously pulled along wellbore 102 without contacting the wall of wellbore 102 or any completions elements in wellbore 102 such as pads, packers, etc.). Alternately, or additionally, measurements such as, for example, “station” wireline measurements may be taken where wellbore logging tool 106 and/or displacement tool 110 stops and anchors itself to the wall of wellbore 102 to collect sampling measurements, stress measurements (such as, for example, MDT stress tests), force measurements, etc.

Example Computing Device

FIG. 2 illustrates an example device 200, with a processor 202 and memory 204 for hosting a property determination module 206 configured to implement various embodiments of in-situ property determination as discussed in this disclosure. Memory 204 can also host one or more databases and can include one or more forms of volatile data storage media such as random access memory (RAM), and/or one or more forms of nonvolatile storage media (such as read-only memory (ROM), flash memory, and so forth).

Device 200 is one example of a computing device or programmable device, and is not intended to suggest any limitation as to scope of use or functionality of device 200 and/or its possible architectures. For example, device 200 can comprise one or more computing devices, programmable logic controllers (PLCs), laptop computers, handheld devices, mainframe computers, high-performance computing (HPC) clusters, clouds, etc., including any combination thereof.

Further, device 200 should not be interpreted as having any dependency relating to one or a combination of components illustrated in device 200. For example, device 200 may include one or more of a computer, such as a laptop computer, a desktop computer, a mainframe computer, an HPC cluster, cloud, etc., or any combination and/or accumulation thereof.

Device 200 can also include a bus 208 configured to allow various components and devices, such as processors 202, memory 204, and local data storage 210, among other components, to communicate with each other.

Bus 208 can include one or more of any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. Bus 208 can also include wired and/or wireless buses.

Local data storage 210 can include fixed media (e.g., RAM, ROM, a fixed hard drive, etc.) as well as removable media (e.g., a flash memory drive, a removable hard drive, optical disks, magnetic disks, and so forth), cloud storage, etc.

One or more input/output (I/O) device(s) 212 may also communicate via a user interface (UI) controller 214, which may connect with I/O device(s) 212 either directly or through bus 208.

In one possible implementation, a network interface 216 may communicate outside of device 200 via a connected network, and in some implementations may communicate with hardware, such as displacement tool 110, wellbore logging tool 106, etc.

In one possible embodiment, hardware, such as displacement tool 110, wellbore logging tool 106, etc., may communicate with device 200 as input/output device(s) 212 via bus 208, such as via a USB port, for example.

A media drive/interface 218 can accept removable tangible media 220, such as flash drives, optical disks, removable hard drives, software products, etc. In one possible implementation, logic, computing instructions, and/or software programs comprising elements of in-situ property determination module 206 may reside on removable media 220 readable by media drive/interface 218.

In one possible embodiment, input/output device(s) 212 can allow a user to enter commands and information to device 200, and also allow information to be presented to the user and/or other components or devices. Examples of input device(s) 212 include, for example, sensors, a keyboard, a cursor control device (e.g., a mouse), a microphone, a scanner, and any other input devices known in the art. Examples of output devices include a display device (e.g., a monitor or projector), speakers, a printer, a network card, and so on.

Various processes of property determination module 206 may be described herein in the general context of software or program modules, or the techniques and modules may be implemented in pure computing hardware. Software generally includes routines, programs, objects, components, data structures, and so forth that perform particular tasks or implement particular abstract data types. An implementation of these modules and techniques may be stored on or transmitted across some form of tangible computer-readable media. Computer-readable media can be any available data storage medium or media that is tangible and can be accessed by a computing device. Computer readable media may thus comprise computer storage media. “Computer storage media” designates tangible media, and includes volatile and non-volatile, removable and non-removable tangible media implemented for storage of information such as computer readable instructions, data structures, program modules, or other data. Computer storage media include, but are not limited to, RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other tangible medium which can be used to store the desired information, and which can be accessed by a computer.

In one possible implementation, device 200, or a plurality thereof, can be employed at wellsite 100. This can include, for example, in displacement tool 110, in wellbore logging tool 106, in processing system 112, etc.

Example System(s) and/or Technique(s)

In one possible implementation, various techniques and technologies associated with in-situ property determination can be used to measure in situ stresses and/or in situ mechanical rock properties in a formation 104 using displacement tool 110. In one possible implementation, displacement tool 110 can include anything deployable downhole in wellbore 102 that can be used to change a cross section of wellbore 102. In one possible aspect, displacement tool 110 can include, for example, a displacement controlled downhole mechanical tester. Further, in another possible aspect, displacement tool 110 can employ, for example, a stress compensation method to measure stresses and/or mechanical rock properties of formation 104.

As will be discussed in more detail below, in some possible implementations, displacement tool 110 can be used to estimate, for example: (i) a ratio of the far-field stresses (aka in-situ stresses) acting perpendicular to an axis of wellbore 102; (ii) an orientation of the far-field stress directions acting perpendicular to the axis of wellbore 102; and (iii) rock elastic moduli in a direction perpendicular to the axis of wellbore 102.

In one possible implementation, knowledge of the in-situ state of stress and/or knowledge of the pore-pressure field in formation 104 can be useful information for a wide variety of geomechanical applications from wellbore stability to hydraulic fracturing design and fluid production induced deformation (compaction/up-heave), etc. In one possible aspect, the state of in-situ stress at a point in the earth can be defined by six quantities: three principal stresses (the principal values of the stress tensor) and three corresponding principal directions. At depth, away from discontinuities and complex surface topographies, the vertical direction can be one of the principal directions of the stress state and the vertical stress magnitude (σ_v) can be estimated from the overburden weight:

σ_V(z)=∫₀^zgρ(z)dz

where g is the gravitational constant and ρ is the rock bulk density. Density logs can therefore be used to estimate the vertical stress. At depth, three additional quantities related to horizontal stresses can be used to characterize the initial in-situ state of stress: (1) the minimum horizontal in-situ stress magnitude (σ_h); (2) the maximum horizontal in-situ stress magnitude (σ_H); and (3) the direction of the maximum horizontal stress, or the direction of the minimum horizontal stress (which is perpendicular to the direction of the maximum horizontal stress). Often, measuring the horizontal in-situ stresses can be quite difficult.

FIG. 3 illustrates an example concept 300 of stress compensation for a configuration of wellbore 102 in accordance with implementations of in-situ property determination. In order to simplify calculations, it can be assumed, for example, that wellbore 102 has been drilled in the direction of one of the principal in-situ stress directions (i.e., wellbore 102 is either a vertical or a horizontal well). This does not mean, however, that the principles of in-situ property determination cannot be applied in other instances in which wellbore 102 is neither horizontal nor vertical (i.e., such as a deviated well), because the principles can. However, in such non vertical and/or non horizontal cases, estimation of stress magnitudes can be more lengthy and complicated.

As shown, a trace 302 of wellbore 102 prior to deformation due to stresses in formation 104 is approximately circular in cross section and has a diameter approximately equal to that of a drill bit used to create wellbore 102 in formation 104.

When the drill bit used to create wellbore 102 is removed, a cross section of wellbore 102 converges due to far field stresses (aka, in situ stresses) σ₁ and σ₂ in formation 104 such that trace 302 of the converged wellbore 102 becomes an elliptical converged trace 304.

In one possible implementation, four or more normal forces 306 exerted on a wall of wellbore 102 can be used to restore a shape of wellbore 102 from elliptical converged trace 304 to an at least approximately circular cross section 308. In one possible aspect, at least approximately circular cross section 308 can match trace 302, thus restoring the cross sectional shape of wellbore 102 to what it was before convergence due to the far field stresses (aka, in situ stresses) σ₁ and σ₂ in formation 104.

Normal forces 306 can differ at different points on the wall of wellbore 102, due to, for example, differences in the magnitudes of σ₁ and σ₂. Moreover, the magnitudes of normal forces 306 to deform the cross section of wellbore 102 from elliptical converged trace 304 to at least approximately circular cross section 308 can be directly related to stresses σ₁ and σ₂ in formation 104 and the pressure on wellbore 102.

For example, if it is assumed that wellbore 102 is drilled with a diameter d=2a in the direction of a principal stress, wellbore 102 can deform from its initial diameter d under the action of the far-field stresses σ₁ and σ₂ (aka the in situ stresses) and the pressure on wellbore 102. In such a scenario, the far-field stresses σ₁ and σ₂ can be denoted as the far-field stresses acting on a plane perpendicular to an axis of wellbore 102 (i.e., σ₁=σ_H and σ₂=σ_h in the case of a vertical well).

In one possible implementation, wellbore convergence deformation due to the drilling can be compensated for and the cross section of wellbore 102 can be restored to its initial shape. When such restoration is accomplished, the normal stresses to restore wellbore 102 to its initial shape (i.e., trace 302) can be directly related to the initial stress field from formation 104 acting on wellbore 102. Such a method can therefore involve the imposition of a shape (i.e., a radial displacement) and the recordation of associated forces used to produce such a displacement.

In some implementations the deformation of wellbore 102 can be relatively small (including, for example, displacement in 10⁻³ mm) but the stresses can be large (O(10⁶ Pa)).

FIG. 4 illustrates an example of displacement tool 110 with an axis 400 in accordance with various implementations of in-situ property determination. Displacement tool 110 is illustrated as having a cylindrical shape, however it will be understood that displacement tool can have any shape known in the art.

As shown, displacement tool is deployed within wellbore 102. An initial cross section of wellbore 102 is illustrated as trace 302 and a cross section of wellbore 102 deformed due to the far-field stresses in formation 104 is illustrated as elliptically converged trace 304.

In one possible implementation, a plurality of pads 402 can extend from displacement tool 110 and contact a wall 404 of wellbore 102. Pads 402 can comprise any shape known in the art, including, for example, a substantially half cylinder shape, such as is shown in a three dimensional view in FIG. 4.

Pads 402 can be symmetrically placed relative to an outer surface 406 of displacement tool 110 with each pad 402 having an equal angular arc φ. Even though four pads 402 are illustrated in FIG. 4, it will be understood that more than four pads 402 can also be employed. Similarly, even though the side view in FIG. 4 illustrates three rows (aka rings) of pads 402, it will be understood that more or fewer rings of pads 402 can also be deployed on displacement tool 110.

In addition to being extendible from outer surface 406, pads 402 can also be retractable back to outer surface 406. In one possible aspect, when fully retracted, pads 402 can be inside outer surface 406, flush with outer surface 406, protrude from outer surface 406, and/or any combination thereof.

In one possible embodiment, pads 402 can be equidistantly extended from outer surface 406 of displacement tool 100. This can include instances when displacement tool 110 is positioned at a center of wellbore 102. In such scenarios, contact surfaces 408 on pads 402 configured to contact wall 404 of wellbore 102 can form an at least approximately circular cross section 410. In some instances, such as when wellbore 102 is deformed into an ellipsoid cross section (such as elliptically converged trace 304), some pads 402 can come into contact with wall 404 of wellbore 102 earlier than other pads 402.

In one possible implementation, pads 402 can be extended to such an extent as to restore wellbore 102 to its original cross section (i.e. trace 302). In one possible aspect, tool 110 can extend pads 402 from a first position relative to outer surface 406 to a second position in which trace 302 is restored in a displacement control mode.

In one possible aspect, once a pad 402 touches wall 404 of wellbore 102, the rock of formation 104 can resist any imposed displacement represented by the further extension of pad 402. In such a case, the forces used to extend and/or hold each pad 402 (such as normal forces relative to each pad 402) in order to impose displacement of wall 404 can be recorded. In one possible aspect, a ratio of the normal forces acting on the various pads 402 for a given displacement of wall 404 of wellbore 102 can be related to the ratio of the far-field stresses in formation 104. Similarly, a force-displacement curve for each pad 402 can be used to estimate the in-situ elastic modulus of the rock in formation 104 in different directions perpendicular to an axis of wellbore 102. In the case of time-dependent deformation, force measurements under constant displacement (aka in a holding phase) during a sufficient amount of time can allow for an estimation of one or more time-dependent properties of formation 104 (such as, for example, drained/undrained moduli and hydraulic diffusivity in the case of a poroelastic formation, see Wang, H. F., 2000, Theory of linear poroelasticity, Princeton, ISBN: 9781400885688; creep properties for a viscoplastic formation, see Cornet, F. H., 2015, Elements of crustal geomechanics, Cambridge University Press, ISBN: 9780521875783 and Cristescu, N., 1989, Rock rheology, Volume 7, Series: Mechanics of Elastic and Inelastic Solids, Springer Netherlands, ISBN: 978-94-010-7654-8 (Print) 978-94-009-2554-0 (Online), DOI: 10.1007/978-94-009-2554-0).

Recordation of forces acting on pads 402 can be accomplished in any manner known in the art, and can be conducted using equipment, such as a recordation device, in one or more locations including subsurface equipment (such as within displacement tool 110, within other tool(s) on wellbore logging tool 106, etc.), surface equipment (such as within processing system 112, etc.), and/or any combination thereof.

In one possible implementation, one or more imaging modules, such as an ultrasonic wellbore imager module, can be used to select measurement depths with desirable wellbore quality at which displacement tool 110 can be placed in order to estimate a horizontal stress direction in formation 104 acting on wellbore 102. In one possible aspect, one or more such imaging modules can be located, entirely or in part, for example, in property determination module 206.

FIG. 5 illustrates example schematic force versus displacement curves 500 for two pads 402 at different angles with respect to the in-situ horizontal stress directions in accordance with implementations of in-situ property determination. Force versus displacement curve 500 (aka force-displacement curve 500) is associated with a pad #1 (aka, pad 402(1)) and force-displacement curve 500(2) is associated with a pad #2 (aka, pad 402(2)).

Loading curve 502 of force-displacement curve 500 denotes a loading phase in which pads 402 extend from a first position to a second, extended, position in order to push wall 404 of wellbore 102 in an effort to restore wellbore 102 from an elliptically converged trace 304 to an at least approximately circular cross section 308 (such as, for example, trace 302). The slope of loading curve 502 can be associated with the elastic modulus of rock in formation 402 being contacted by pads 402).

Portion 504 of force-displacement curve 500 illustrates a holding phase of force-displacement curve 500 in which a constant displacement of wall 404 or wellbore 102 can be maintained (such as, for example, when wellbore has an at least approximate circular cross section 308). Portion 504 can be used to measure a time-dependent response of the rock in formation 104. This can be accomplished, for example, by recording the forces applied to pads 402 to maintain a constant displacement of wall 404 of wellbore 102 (i.e., stresses can relax in the rock in formation 104 due to creep and/or poroelasticity (aka pore-pressure consolidation)).

Unloading curve 506 of force-displacement curve 500 illustrates the forces applied to pads 402 during an un-loading phase in which pads 402 retract from their extended position back towards their first position proximate outer surface 406 of displacement tool 110 (i.e., allowing the cross section of wellbore 102 to be deformed from at least approximate circular cross section 308 to elliptically converged trace 304 under, for example, the stresses in formation 104. The slope of unloading curve 506 can be associated with an elastic modulus of the rock of formation 104 in contact with pads 402.

In one possible aspect, for a given extension of a pad 402 from outer surface 406 of displacement tool 110, the value of forces F₁ and F₂ acting on pad 402(1) and pad 402(2) respectively, can differ due to the original deformation of the wellbore 102 due to the in situ stresses in formation 104 acting on wellbore 102. In one possible implementation, a ratio of forces F₁/F₂ on force-displacement curves 500, 500(2) can be a function of the far-field stresses in formation 104.

In one possible embodiment, a force-displacement curve 500 can be constructed for each set of pads 402 diametrically opposite to one another on displacement tool 110.

As noted above in conjunction with FIG. 4, as many rings of pads 402 as desired can be employed on displacement tool 110. In one possible implementation, an increase in the number of rings of pads 402 at different depths on displacement tool 110 can result in improved measurements from displacement tool 110 (i.e., an improved response of displacement tool 110).

Alternately, or additionally, any other designs involving arms to help stiffen the response of displacement tool 110 during deployment of tool 110 may be used. For example, in one possible implementation, arms lying approximately parallel to axis 400 of displacement tool 110 could be configured to extend out from axis 400 at an ever increasing angle to contact and displace the wall of wellbore 102. Such angularly extending arms could be reinforced by other arms or various constructions, including, for instance, supports extending approximately orthogonally from axis 400, between axis 400 and the angularly extending arms. In one possible aspect, displacement tool 110 can be approximately five times stiffer than formation 104.

In one possible implementation, displacement tool 110 can include an ultrasonic wellbore imager module (e.g., UBI) to allow for one or more additional measurements to: (i) get a 360 degree shape of wellbore 102 and the ellipse axes for the in situ stress direction, and (2) estimate the conditions of wellbore 102 and decide where to put displacement tool 110. In such a manner, pads 402 can be oriented in the directions of the in situ stresses σ₁ and σ₂, while avoiding various issues (i.e., frac, key seat, reaming, etc., can be avoided).

In one possible implementation, a far-field stress ratio and/or principal stress direction can be determined using aspects of in-situ property measurement. For example, in the case of a well drilled in the direction of one of the principal stresses, the forces acting on pads 402 can be associated with the remaining two far-field stresses acting perpendicular to the axis of wellbore 102. These stresses can be different for each set of pads 402 if the two far-field stresses are not equal. Imposing the same radial displacement U from the tool center on each pad 402 while recording the forces (F) being applied to pads 402 can result in different F versus U curves for the different pads 402.

In one possible aspect, pads 402 facing the direction of the maximum principal stress can come in contact with formation 104 (i.e., wall 404 of borehole 102) earlier than pads 402 facing the minimum stress given the ellipsoid cross section of elliptically converged trace 304.

In one possible implementation, for a given value of the imposed displacement U, the ratio of the corresponding forces between the two pads 402 in a vertical well can be associated with the ratio of the horizontal far-field stress magnitudes of σ₁ and σ2.

FIG. 6 illustrates an example graph 600 of a ratio of forces σ₁/σ₂ acting on pad 402(1) (aka pad #1) over pad 402(2) (aka pad #2) for different positions of pad 402(1) with respect to the maximum stress direction in accordance with implementations of in-situ property determination. As illustrated, x-axis 602 represents an azimuthal position of a center of pad 402(1) from a direction of σ₁, and y-axis 604 represents a ratio of force applied to pad 402(1))/force applied to 402(2).

In one possible implementation, a span φ of each pad 402 can have an angle of approximately 20 degrees (though other spans can also be used), and the pads 402 can be assumed to be perpendicular to one another. The stresses in this implementation are taken as σ₁=20 MPa, σ₂=7 MPa: i.e. σ₁/σ₂˜2.8, σ₂/σ₁=0.35, though other stresses can also be experienced.

In one possible embodiment, as a preliminary estimate, the effect of contact associated with a finite arc size of contact 408 of a pad 402 can be neglected. In one possible aspect, a numerical model (e.g., Finite Element, Boundary Element, etc.) can be performed to take into account such effects. Moreover, in one possible aspect, it can be assumed that the initial deformation due to the drilling of the well can be restored: i.e., the final radial extension of pads 402 on displacement tool 110 can be equal to the bit size used to drill wellbore 102. In one possible implementation, the final value of the forces applied to pads 402 once the original wellbore convergence has been restored (i.e., to trace 302) can be found.

In one possible implementation, for the sake of completeness, it is possible that the radial displacement u_r induced by the release of the far-field stress due to the drilling can be obtained from the poroelastic solution for isotropic elastic rocks (see, for example, Detournay, E. & Cheng, A.-D., Poroelastic response of a borehole in a non-hydrostatic stress field, International Journal of Rock Mechanics and Mining Sciences & Geomechanics Abstracts, 1988, 25, 171-182):

$u_r\left(\theta \right)=\frac{a}{2G}\left(\frac{1}{2}\left({\sigma }_1+{\sigma }_2\right)P_b+\frac{1}{2}\left(\begin{array}{cc}{\sigma }_1& {\sigma }_2\end{array}\right)\left(4\left(\begin{array}{cc}1& v\end{array}\right)1\right)\cos \left(2\theta \right)\right)$

where v is the Poisson's ratio, Pb is the wellbore pressure, σ₁ and σ₂ are the far-field stresses acting in the plane and θ is the angle from the direction of the maximum far field stress σ₁. G can denote the shear modulus of the rock in formation 104 and “a” in the equation above can be the radius of wellbore 102. In one possible aspect, this method can be done without knowledge of the elastic parameters of the rock in formation 104.

For anisotropic elastic rocks, if the elastic stiffness constants are known from other sources, the radial displacement can be analytically computed using, for example, the expression from Karpfinger et al. See Karpfinger et al., “Theoretical estimate of the tube-wave modulus in arbitrarily anisotropic media: Comparisons between semianalytical, FEM, and approximate solutions”, Geophysics, Vol. 77, No. 5 (September-October 2012).

In one possible implementation, the extension of pads 402 to restore such a displacement of wellbore 102 can be equal to the original bit-size used to drill wellbore 102. In one possible aspect, the forces to be exerted on pads 402 in order to restore the elastic displacement u_r(θ) can be found. The normal force acting on a pad 402 of angle (aka span) φ and height (located at an angle 9 from the maximum principal stress as illustrated in FIG. 4) at restoration of wellbore 102 to trace 302 can be given by the normal far-field in-situ stresses σ_n(θ)=(σ₁ P_b) (cos θ)²+(σ₂ P_b) (sin θ)² to the “restored” wellbore 102:

$F\left(\theta \right)={\int }_{\theta -\varphi /2}^{\theta +\varphi /2}{\sigma }_n\left(\theta \right)ad\theta =\frac{a}{2}\left(\left(\left({\sigma }_1+{\sigma }_2\right)2\mathrm{Pb}\right)\varphi +\left(\begin{array}{cc}{\sigma }_1& {\sigma }_2\end{array}\right)\sin \left(\varphi \right)\cos \left(2\theta \right)\right)$

In one possible implementation, if it is known that the initial displacement of wellbore 102 has been restored (i.e. to trace 302), one can quantitatively estimate the two principal stress magnitudes from the forces applied to pads 402.

In one possible aspect, it may be difficult to know in practice when a restoration of the original wellbore deformation to trace 302 is obtained. In one possible implementation, the ratio of the forces acting on different pads 402 for the same radial extension of pads 402 can be taken, and the ratio of the far-field stress can be estimated with such a method, along with the absolute value of each far-field stress magnitude.

In one possible implementation, this can be accomplished by taking the ratio of the forces between different pads 402. When the wellbore deformation is restored to trace 302, for example, the ratio of the forces between two pads 402 separated by an angle can be a function of the wellbore pressure, and the ratio of the far-field stress.

FIG. 6 illustrates the ratio of the forces acting on pad 402(1) (aka pad #1) over pad 402(2) (aka pad #2) for different positions of pad 402(1) with respect to the direction of maximum stress (GO in accordance with implementations of in-situ property determination.

FIG. 7 illustrates an example graph 700 showing the ratio of the radial displacement u_r over radius “a” induced by the release of the far-field stress for different azimuthal positions with respect to the direction of maximum stress (GO in accordance with implementations of in-situ property determination. X-axis 702 represents an azimuthal position with respect to a position of σ₁, and y-axis 704 represents a ratio of the radial displacement u_r over radius “a”.

In the implementation shown in FIG. 6, a span φ of each pad 402 has an angle of approximately 20 degrees (though other spans can also be used), and the pads 402(1), 402(2) are perpendicular to one another. The stresses are taken as σ₁=20 MPa, σ₂=7 MPa: i.e. σ₁/σ₂˜2.8 and σ₂/σ₁=0.35 (though other stresses can also be experienced).

In one possible embodiment, the orientation of the principal stress may not be known and/or displacement tool 110 may not be oriented such that a pad 402, such as 402(1), is oriented in a direction of the principal stress. FIG. 6 illustrates that an orientation of pad 402(1) with respect to a direction of the principal stress can have a first order effect on a value of the ratio of the forces acting on the two perpendicular pads 402(2), 402(2). In the case of four pads 402, due to the automatic centering of displacement tool 110 in wellbore 102 when pads 402 are symmetrically deployed from a center (aka about axis 400) of displacement tool 110, the forces on the opposite pads 402 can be equal. In one possible aspect, two independent measurements and one force ratio can exist. In such a case, a direction of the principal stress in formation 104 may not be measured.

In one possible embodiment, measurements of forces applied to pads 402 can be combined with an ultrasonic wellbore imager (UBI) to independently resolve a direction of the principal stress in formation 104 and thus relate the ratio of: (force applied to pad 402(2))/(force applied to pad 402(2)) to the ratio of the in-situ stresses σ₁/σ₂ (as shown in FIG. 6). In one possible aspect, an accuracy of such an estimation can be improved by using more pads 402 (for example, six or more pads 402) on displacement tool 110.

In another possible embodiment, once pads 402 have been extended and retracted as described herein, and corresponding measurements of forces applied to pads 402 to deform wellbore 102 from an elliptically converged trace 304 to an at least approximately circular cross section 308, and back again, etc., have been recorded, the number of force-ratio measurements of pads 402 relative to the principal stress in formation 104 can be increased by maintaining displacement tool 110 at the same depth while rotating displacement tool 100 a given angle (such as, for example, 45 degrees, etc.), and repeating the extension and retraction routine of pads 402 described herein while measuring the forces applied to pads 402. Rotation of displacement tool 110 in order to collect additional measurements of forces applied to pads 402 in this manner can be performed as many times as desired.

In one possible embodiment, the addition of an image from an ultrasonic wellbore imager may allow for the assessment of the quality of the deformation of wellbore 102 prior to stress compensation in order to ensure that no artifact linked to wellbore failures, reaming etc., affects the stress ratio estimation. Such an image would also allow for an estimation of the principal stress direction in formation 104 from measurement of the ovalization of the wellbore due to drilling.

In one possible implementation, a rock modulus of the rock in formation 104 can be estimated using a stress compensation test approach akin to an indentation test for each pad 402. For instance, in one possible aspect the loading curve 502 and the unloading curve 506 of the force-displacement curve 500 for a pad 402 can be used to estimate an elastic rock modulus for each pad 402. Estimation of elastic modulus from such indentation responses can be performed using any techniques known in the art including those, for example, described in Oliver W C, Pharr G M (1992) An improved technique for determining hardness and elastic modulus using load and displacement sensing indentation experiments; J Mater Res 7(6):1564-1583).

In one possible aspect, responses illustrated in curve 500 may vary based on the shape of a pad 402, so a model corresponding to the shape of a given pad 402 can be used in order to estimate the rock modulus from the force-displacement curve 500 for the given pad 402.

In one possible implementation, the above techniques can be used to provide a measurement of the quasi-static elastic modulus of rocks in formation 104 in-situ. Such a measurement can be made in a direction perpendicular to an axis of wellbore 102. In the case of an anisotropic rock (e.g., transverse isotropy) in formation 104, such a measurement can complement sonic measurements.

In another possible implementation, one or more time dependent properties can be estimated. This can be done, for instance, using information associated with forces applied to one or more pads 402 during a holding phase (i.e., portion 504 of force-displacement curve 500) at the end of a loading phase (loading curve 502) and prior to an unloading phase (unloading curve 506). During the holding phase an at least approximately circular cross section 308 is maintained in wellbore 102 by pads 402 on displacement tool 110 for a predetermined amount of time. This predetermined amount of time can vary based on the type of rock in formation 104. In one possible aspect, the predetermined amount of time can include a few minutes or more.

During the holding phase, rock in formation 104 contacting a pad 402 may exhibit a time-dependent response due to, for example, pore-pressure dissipation associated with a transition between an undrained to a drained response for a poroelastic material, etc. The intensity of such pore pressure consolidation may be associated with the rock permeability and/or the characteristic length of drainage which can be related to a size of pad 402 pressing against the rock. Such an effect may therefore be seen, for example, for very tight rock.

Some types of rock which may be in formation 104 (such as, for example salt) may also exhibit a viscoplastic behavior (see, for example, Cristescu, N., 1989, Rock rheology, Volume 7, Series: Mechanics of Elastic and Inelastic Solids, Springer Netherlands, ISBN: 978-94-010-7654-8 (Print) 978-94-009-2554-0 (Online), DOI: 10.1007/978-94-009-2554-0). For example, under a constant imposed displacement for a period of time, such as during the holding phase, the stresses inside a viscoplastic rock can relax: i.e., the forces acting on pad 402 in contact with the viscoplastic rock can decrease with time. Such a decay in the forces acting on pad 402 to maintain a constant displacement of wellbore 102 during the holding phase can be analyzed to estimate intrinsic creep time scales of the rock.

In one possible implementation, in order for a measurement to be sensitive to rock deformation, it may be desirable for displacement tool 110 and pads 402 to be substantially stiffer than the rock in formation 104.

In one possible embodiment, it may be desirable for a complete measurement analysis to account for the geometry of the contact between a pad 404 and displacement tool 110. In one possible aspect, it may be desirable for the finite arc size and the arc shape of the pads 402 to be included in calculations used to estimate the stress ratio and elastic modulus of the rock in formation 104. Such calculations (using, for example, the Finite Element Method) can be performed in order to take into account the geometry of displacement tool 110 in field applications.

In one possible aspect, the impact of a lower quality of wellbore 102 (i.e. due to tripping, etc.) on the stress estimations described herein can be assessed. In such an instance the addition of an image of wellbore 102 could be desirable.

Example Methods

FIG. 8 illustrates example method(s) for implementing aspects of in-situ property determination. The methods are illustrated as a collection of blocks and other elements in a logical flow graph representing a sequence of operations that can be implemented in hardware, software, firmware, various logic, manually, or by any combination thereof. The order in which the methods are described is not intended to be construed as a limitation, and any number of the described method blocks can be combined in any order to implement the methods, or alternate methods. Additionally, individual blocks and/or elements may be deleted from the methods without departing from the spirit and scope of the subject matter described therein. In the context of software, the blocks and other elements can represent computer instructions that, when executed by one or more processors, perform the recited operations. Moreover, for discussion purposes, and not purposes of limitation, selected aspects of the methods may be described with reference to elements shown in FIGS. 1-7. Moreover, in some possible implementation, all or portions of the methods may, at least partially, be conducted using, for example, computing device 200.

FIG. 8 illustrates an example method 800 associated with embodiments of in-situ property determination. At block 802, a displacement tool (such as, for example, displacement tool 110) can be activated at a desired depth in a wellbore (such as wellbore 102) in a formation (such as formation 104) to deform the wellbore from an at least approximately elliptical cross section (such as elliptically converged trace 304) to an at least approximately circular cross section (such as at least approximately circular cross section 308). The displacement tool can be lowered into the wellbore using any methods and/or equipment known in the art, and the desired depth can be chosen using any methods known in the art, including a study of one or more images (including, for example ultrasonic images) of the wellbore at different depths.

In one possible implementation, an axis of the at least approximately elliptical cross section of the displaced wellbore can be located and/or measured using one or more images of the wellbore. Such information can then be used to orient the displacement tool in the directions of maximum and minimum stress (such as σ₁ and σ₂) in the wellbore. In embodiments in which the displacement tool has pads, such as pads 402, this can include orienting at least one set of pads in the direction of maximum stress and another set of pads in a direction of minimum stress.

Once activated, the displacement tool 110 can restore the displaced wellbore back to an at least approximately circular cross section using any means known in the art, including through the use of four or more pads (such as pads 402), placed symmetrically around a body of the displacement tool. In one possible implementation, the displacement tool can displace the wellbore back into an at least approximately circular cross section with a diameter at least approximately equal to that of a drill bit used to create the wellbore.

At block 804, during the displacement of the wellbore, force displacement information associated with deforming the wellbore from its at least approximately elliptical cross section to the at least approximately circular cross section (such as forces being applied to pads if pads are present of the displacement tool) can be recorded. Recordation of such forces can be accomplished in any manner known in the art, and can be conducted using any equipment known in the art, including, for example, a recordation device, in one or more locations including in subsurface equipment (such as within displacement tool, within other tool(s) on a wellbore logging tool, etc.), in surface equipment (such as within a processing system, etc.), and/or any combination thereof.

At block 806, at least a portion of the force displacement information associated with deforming the wellbore from the at least approximately elliptical cross section to the at least approximately circular cross section (such as during a loading phase) can be utilized to estimate a far-field stress ratio associated with the formation. This can be accomplished using any of the methods disclosed herein, including use of a module, such as property determination module 206.

In one possible implementation, for example, when pads are employed on the displacement tool, loading curves (such as loading curves 502) can be created from the force displacement information for one or more of the pads on the displacement tool and be used to estimate the far-field stress ratio associated with the formation.

In one possible embodiment, the displacement tool can be used to maintain the displaced wellbore at the at least approximately circular cross section for a desired period of time (aka a holding phase). During this desired period of time, maintenance force information associated with maintaining the at least approximately circular cross section during the holding phase can be recorded. In one possible aspect, at least a portion of the maintenance force information can be used to estimate one or more time dependent properties, such as: poroelastic properties associated with the formation (see, for example, Wang, H. F., 2000, Theory of linear poroelasticity, Princeton, ISBN: 9781400885688); a hydraulic diffusivity of the formation (see, for example, Wang, H. F., 2000, Theory of linear poroelasticity, Princeton, ISBN: 9781400885688); and/or one or more rock creep properties of the formation (see, for example, Cristescu, N., 1989, Rock rheology, Volume 7, Series: Mechanics of Elastic and Inelastic Solids, Springer Netherlands, ISBN: 978-94-010-7654-8 (Print) 978-94-009-2554-0 (Online), DOI: 10.1007/978-94-009-2554-0), using any of the methods disclosed herein, including use of a module, such as property determination module 206.

In instances when pads are utilized on displacement tool 110, maintenance curves (such as portions 504) can be created from the maintenance force information associated with one or more of the pads on the displacement tool and used to estimate one or more of the time dependent properties associated with the formation.

In another possible implementation, force displacement information associated with allowing the wellbore to return from the circular cross section to an at least approximately elliptical cross section in an unloading phase can be recorded (aka an unloading phase). At least a portion of such force displacement information can be used to estimate Young's Modulus associated with the formation at the desired depth, using any of the methods described herein, including use of a module, such as property determination module 206.

In instances when pads are utilized on displacement tool 110, unloading curves (such as unloading curves 506) can be created from the force displacement information associated with allowing the wellbore to return from the circular cross section to an at least approximately elliptical cross section associated with one or more of the pads on the displacement tool and used to estimate Young's Modulus associated with the formation at the desired depth.

At block 808, once the wellbore has been allowed to be displaced from the at least approximately circular cross section to an at least approximately elliptical cross section, in one possible implementation, the displacement tool can be turned a desired angle at the desired depth in the wellbore. The displacement tool can then be activated as described above and forces can be recorded during one or more of a loading phase, a holding phase and an unloading phases, and used to estimate various rock and stress properties associated with the formation as described above. Rotation of the displacement tool at a given depth in this manner can occur as many times as desired.

Further, if desired, any and/or all of the blocks above can be repeated at one or more other depths along the wellbore. For example, after some or all of the above has been completed, the displacement tool can be moved to a new depth in the wellbore and any of the blocks/techniques above can be repeated. For instance, at the new depth the displacement tool can be activated to initiate a loading phase, a holding phase, and/or an unloading phase, and force information associated with each phase can be collected and used to estimate various rock and stress properties associated with the formation. After the unloading phase has been completed, the displacement tool can then be turned a desired angle, and the loading phase, the holding phase, and/or the unloading phase can be repeated with more force information associated with each phase being collected and used to improve the various estimated rock and stress properties associated with the formation. This can be done as many times as desired.

In one possible implementation, the recorded information and various estimated rock and stress properties associated with the formation can be used to improve an operator's (or other interested party's) understanding of the formation.

In one possible implementation, a robust one dimensional (1D) Mechanical Earth Model can be constructed along all or portions of wellbore 102 using aspects of in-situ property determination as described herein. In one possible aspect this can be done by, for example, forming an estimation of an overburden stress from one or more density log(s) and well survey(s) associated with wellbore 102. Further, in a vertical well, the ratio σ₁/σ₂ of the horizontal stresses in formation 104 can be estimated using any of the methods described above. Still further, an estimation of a direction of the horizontal stresses σ₁ and σ₂ in formation 104 can be produced from (1) the methods presented previously and/or from (2) one or more image logs associated with wellbore 102. Also, an estimation of the minimum horizontal stress σ₂ can be gleaned through use of, for example, a Modular Formation Dynamic Tester marketed by the Schlumberger Technology Corporation of Houston Tex., and/or leak off test (LOT) closure stress tests at a number of given depths in wellbore 102.

The maximum horizontal stress σ₁ can then be estimated from the ratio σ₁/σ₂ of the horizontal stresses in formation 104 and the estimation of the minimum horizontal stress σ₂. Moreover, elastic properties of rock in formation 104 can be derived from sonic measurements and combined with estimates of the rock modulus described above (e.g., estimates of the rock modulus from the force-displacement curve 500) to build a static to dynamic correction for a Mechanical Earth Model. Further a continuous depth profile of the minimum and maximum horizontal stresses (σ₂ and σ₁, respectively) can be built using, for example, the estimation of the overburden stress, the estimation of the minimum horizontal stress σ₂, the estimation of the maximum horizontal stress σ₁, and the static to dynamic correction for a Mechanical Earth Model.

Although a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the following claims. Moreover, embodiments may be performed in the absence of any component not explicitly described herein.

In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not just structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

1. An in-situ property determination system comprising:

a displacement tool configured for use in a wellbore in a formation, the displacement tool comprising:

four or more pads symmetrically located about an axis of the displacement tool, with each pad having a contact surface configured to contact a wall of the wellbore; wherein the four or more pads are further configured to extend from a first position proximate an outer surface of the displacement tool to a second position in contact with the wall of the wellbore such that the four or more pads deform the wellbore into an at least approximately circular cross section; and

a recordation device configured to record force displacement information associated with extending the four or more pads from the first position to the second position.

2. The in-situ property determination system of claim 1, wherein the recordation device is located at least partially within the displacement tool.

3. The in-situ property determination system of claim 1, further comprising:

a property determination module configured to utilize at least a portion of the force displacement information associated with extending the four or more pads from the first position to the second position to estimate a far-field stress ratio associated with the formation.

4. The in-situ property determination system of claim 1, wherein the recordation device is further configured to record maintenance force information associated with maintaining the four or more pads at the second position.

5. The in-situ property determination system of claim 4, further comprising:

a property determination module configured to utilize at least a portion of the maintenance force information associated with maintaining the four or more pads at the second position to estimate one or more of:

one or more poroelastic properties of the formation;

a hydraulic diffusivity of the formation; and

one or more rock creep properties of the formation.

6. The in-situ property determination system of claim 1, wherein the four or more pads are further configured to retract from the second position to the first position, and further wherein the recordation device is further configured to record force displacement information associated with allowing the four or more pads to retract from the second position to the first position.

7. The in-situ property determination system of claim 6, further comprising:

a property determination module configured to utilize at least a portion of the force displacement information associated with allowing the four or more pads to retract from the second position to the first position to estimate Young's Modulus associated with the formation.

8. A method of in-situ property determination comprising:

activating a displacement tool at a desired depth in a wellbore in a formation to deform the wellbore from an at least approximately elliptical cross section to an at least approximately circular cross section; and

recording force displacement information associated with deforming the wellbore from the at least approximately elliptical cross section to the at least approximately circular cross section.

9. The method of in-situ property determination of claim 8, further comprising:

utilizing at least a portion of the force displacement information associated with deforming the wellbore from the at least approximately elliptical cross section to the at least approximately circular cross section to estimate a far-field stress ratio associated with the formation.

10. The method of in-situ property determination of claim 8, further comprising:

choosing the desired depth based at least in part on one or more ultrasonic images associated with the wellbore.

11. The method of in-situ property determination of claim 8, further comprising:

identifying a location of an axis of the at least approximately elliptical cross section at least partially through use of a wellbore image.

12. The method of in-situ property determination of claim 8, further comprising:

recording maintenance force information associated with maintaining the at least approximately circular cross section; and

utilizing at least a portion of the maintenance force information to estimate one or more of:

one or more poroelastic properties of the formation;

a hydraulic diffusivity of the formation; and

one or more rock creep properties of the formation.

13. The method of in-situ property determination of claim 8, further comprising:

recording force displacement information associated with allowing the wellbore to return from the at least approximately circular cross section to an at least approximately elliptical cross section; and

utilizing at least a portion of the force displacement information associated with allowing the wellbore to return from the circular cross section to the at least approximately elliptical cross section to estimate Young's Modulus associated with the formation at the desired depth.

14. The method of in-situ property determination of claim 8 wherein activating the displacement tool includes:

extending four or more pads from a first position proximate an outer surface of the displacement tool to a second position in which the four or more pads have pushed a wall of the wellbore into the at least approximately circular cross section.

15. The method of in-situ property determination of claim 14, further comprising:

orienting the four or more pads in a direction of a maximum principal stress and a minimum principal stress in the formation.

16. The method of in-situ property determination of claim 8, further comprising:

allowing the wellbore to return from the at least approximately circular cross section to an at least approximately elliptical cross section;

turning the displacement tool by a desired angle and activating the displacement tool to deform the wellbore from an at least approximately elliptical cross section to an at least approximately circular cross section; and

recording force displacement information associated with deforming the wellbore from the at least approximately elliptical cross section to the at least approximately circular cross section.

17. The method of in-situ property determination of claim 8, further comprising:

moving the displacement tool to a second desired depth in the wellbore;

activating the displacement tool at the second desired depth to deform the wellbore from an at least approximately elliptical cross section to an at least approximately circular cross section; and

recording force displacement information associated with deforming the wellbore from the at least approximately elliptical cross section to the at least approximately circular cross section.

18. A computer-readable tangible medium with instructions stored thereon that, when executed, direct a processor to perform acts comprising:

accessing force displacement information associated with deforming a wellbore in a formation from an at least approximately elliptical cross section to an at least approximately circular cross section; and

utilizing at least a portion of the force displacement information associated with deforming the wellbore from the at least approximately elliptical cross section to the at least approximately circular cross section to estimate a far-field stress ratio associated with the formation.

The computer-readable tangible medium of claim 18, wherein the computer-readable tangible medium further includes instructions to direct a processor to perform acts comprising:

accessing maintenance force information associated with maintaining the at least approximately circular cross section of the wellbore; and

utilizing at least a portion of the maintenance force information to estimate one or more of:

one or more poroelastic properties of the formation;

a hydraulic diffusivity of the formation; and

one or more rock creep properties of the formation.

19. The computer-readable tangible medium of claim 18, wherein the computer-readable tangible medium further includes instructions to direct a processor to perform acts comprising:

accessing force displacement information associated with allowing the wellbore to return from an at least approximately circular cross section to an at least approximately elliptical cross section; and

utilizing at least a portion of the force displacement information associated with allowing the wellbore to return from the at least approximately circular cross section to the at least approximately elliptical cross section to estimate Young's Modulus associated with the formation.