WO2011040924A1

WO2011040924A1 - Determining anisotropy with a formation tester in a deviated borehole

Info

Publication number: WO2011040924A1
Application number: PCT/US2009/059258
Authority: WO
Inventors: Mark A. Proett; Mike Walker
Original assignee: Halliburton Energy Services, Inc.
Priority date: 2009-10-01
Filing date: 2009-10-01
Publication date: 2011-04-07

Abstract

A method for determining or calculating at least one of a formation anisotropy and a dip angle of a borehole is based on differences in formation measurements taken at different radially displaced locations around the borehole at a set depth. The radially spaced locations may be predetermined or specified orientations of a formation probe around the borehole at the depth. Pressure measurements may be taken at known orientations of the formation probe relative to the borehole, and the formation anisotropy or the dip angle may be determined as a function of the different formation pressure measurements corresponding to the different known orientations of the formation probe.

Description

DETERMINING ANISOTROPY WITH A FORMATION TESTER

IN A DEVIATED BOREHOLE

BACKGROUND

[0001] During the drilling and completion of oil and gas wells, it may be necessary to engage in ancillary operations such as evaluating the production capabilities of formations intersected by the wellbore. For example, after a well or well interval has been drilled, zones of interest are often tested to determine various formation properties such as permeability, formation pressure, formation pressure gradient, spherical mobility, bubble point, fluid type, fluid quality, fluid density, formation temperature, filtrate viscosity, formation fluid viscosity, coupled compressibility porosity, and skin damage (which is an indication of how the mud filtrate has changed the permeability near the wellbore). These tests are performed in order to determine whether commercial exploitation of the intersected formations is viable and how to optimize production.

[0002] It is well known that some earth formations exhibit anisotropic properties. That is, certain downhole parameters may have more distinctive qualities, or may be more pronounced, in one physical direction than another. In other terms, anisotropy is the difference between a formation property or characteristic in one direction versus another direction, and may be expressed as a ratio of the property values. While there may be many properties that exhibit this characteristic, focus is often placed on determining the hydraulic permeability anisotropy of earth formations. Thus, anisotropy may be expressed as a ratio of the vertical and horizontal permeabilities of the formation.

[0003] Permeability is a measure of how easily fluids flow through a particular environment. Earth formations having a very high permeability may flow greater volumes of liquids than formations having a low permeability for the same pressure differentials. Because of the way earth formations are formed, typically horizontal layer upon horizontal layer, the permeability of earth formations is generally higher in a direction substantially parallel to the layers of earth formation. Likewise, the permeability is generally lower in directions perpendicular to the layers of the earth formation. While it is generally true that the horizontal permeability is greater than the vertical permeability, this need not necessarily be the case.

[0004] Permeability of a formation generally may be determined by inducing a fluid flow from the formation into a test apparatus, and measuring the pressure differential created by the induced flow. The formation tester includes various structures for engaging the tester with the formation and creating a fluid flow therebetween. [0005] With directional drilling, a particular borehole may not be substantially vertical. That is, as the direction and inclination of the drilling process changes, the borehole may cross otherwise substantially horizontal bedding planes of the earth formation at an angle. Thus, the axis of the borehole at any particular location may have an angle of inclination, also known as the "dip angle," with respect to the direction of horizontal permeability. This difference in the angle between the axis of the borehole and the direction of horizontal permeability may also manifest itself where an otherwise vertical borehole crosses a formation bedding plane itself having an inclination. In other words, the dip angle also includes the angle of the bedding planes with respect to the borehole axis. Regardless of why the dip angle is present, the difference between an assumed horizontal permeability normal to the borehole axis and the actual horizontal permeability affects the determination of the actual horizontal and vertical permeability.

[0006] Correctly determining horizontal and vertical permeability, and thus the anisotropy of the earth formation, in the unpredictable downhole environment is difficult and elusive. Variables, such as dip angle, affect correct determinations of anisotropy. The principles of the present disclosure overcome these and other limitations in the art.

BRIEF DESCRIPTION OF THE DRAWINGS

[0007] For a detailed description of exemplary embodiments of the disclosure, reference will now be made to the accompanying drawings in which:

[0008] Figure 1 is a schematic view, partly in cross-section, of a drilling apparatus with a formation tester;

[0009] Figure 2 is a schematic view, partly in cross-section, of a formation tester conveyed by wireline;

[0010] Figure 3 is a schematic view, partly in cross-section, of a formation tester disposed on a wired drill pipe connected to a telemetry network;

[0011] Figure 4 is a cross-section view of a section of wired drill pipe;

[0012] Figure 5 is a side view, partly in cross-section, of a drill collar including a formation probe assembly;

[0013] Figure 6 is a cross-section view of an embodiment of a formation probe assembly in a retracted position;

[0014] Figure 7 is the formation probe assembly of Figure 7 in an extended position;

[0015] Figure 8 is a cross-section view of another embodiment of a formation probe assembly in an extended position; [0016] Figure 9 is a perspective view of an embodiment of a formation tester including multiple axially aligned probes;

[0017] Figure 10 is a side view of another embodiment of a formation tester including multiple probes spaced circumferentially about the tester at 90 degree intervals;

[0018] Figure 11 is a graphical representation of a formation pressure test;

[0019] Figure 12 is a schematic view, partly in cross-section, of a formation testing tool disposed in a deviated borehole having a dip angle relative to the formation bedding planes; and

[0020] Figure 13 is a radial cross-section view of the formation testing tool of Figure 12 showing multiple probe orientations about the borehole.

DETAILED DESCRIPTION

[0021] In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals. The drawing figures are not necessarily to scale. Certain features may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present disclosure is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results.

[0022] In the following discussion and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus should be interpreted to mean "including, but not limited to Unless otherwise specified, any use of any form of the terms "connect",

"engage", "couple", "attach", or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. Reference to up or down will be made for purposes of description with "up", "upper", "upwardly" or "upstream" meaning toward the surface of the well and with "down", "lower", "downwardly" or "downstream" meaning toward the terminal end of the well, regardless of the well bore orientation. In addition, it may be sometimes stated that certain components or elements are in fluid communication. By this it is meant that the components are constructed and interrelated such that a fluid could be communicated between them, as via a passageway, tube, or conduit. Also, the designations "MWD" or "LWD" are used to mean all generic measurement while drilling or logging while drilling apparatus and systems. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.

[0023] Tools for evaluating formations and fluids therein may take a variety of forms, and the tools may be deployed down hole in a variety of ways. This disclosure is not limited to the type or specific design of the downhole tool or the means for recording the data that is collected. For example, the evaluation tool may include a formation tester having an extendable sampling device, or probe, and pressure sensors. In some embodiments, the formation tester is coupled to a tubular, such as a drill collar, and connected to a drill string used in drilling the borehole. With reference to Figure 1, a drilling apparatus including a formation tester is shown. A formation tester 10 is shown enlarged and schematically as a part of a bottom hole assembly 6 including a sub 13 and a drill bit 7 at its distal most end. The bottom hole assembly 6 is lowered from a drilling platform 2, such as a ship or other conventional land platform, via a drill string 5. The drill string 5 is disposed through a riser 3 and a well head 4. Conventional drilling equipment (not shown) is supported within a derrick 1 and rotates the drill string 5 and the drill bit 7, causing the bit 7 to form a borehole 8 through formation material 9. The drill bit 7 may also be rotated using other means, such as a downhole motor. The borehole 8 penetrates subterranean zones or reservoirs, such as reservoir 11, that are believed to contain hydrocarbons in a commercially viable quantity. An annulus 15 is formed thereby. In addition to the tool 10, the bottom hole assembly 6 contains various conventional apparatus and systems, such as a down hole drill motor, a rotary steerable tool, a mud pulse telemetry system, MWD or LWD sensors and systems, and others known in the art.

[0024] In some embodiments, and with reference to Figure 2, a formation testing tool 60 is disposed on a tool string 50 conveyed into the borehole 8 by a cable 52 and a winch 54. The testing tool includes a body 62, a sampling assembly 64, a backup assembly 66, analysis modules 68, 84 including electronic devices, a flowline 82, a battery module 65, and an electronics module 67. The formation tester 60 is coupled to a surface unit 70 that may include an electrical control system 72 having an electronic storage medium 74 and a control processor 76. In other embodiments, the tool 60 may alternatively or additionally include an electrical control system, an electronic storage medium and a processor.

[0025] Referring to Figure 3, a telemetry network 100 is shown. A formation tester 120 is coupled to a drill string 101 formed by a series of wired drill pipes 103 connected for communication across junctions using communication elements as described below. It will be appreciated that work string 101 can be other forms of conveyance, such as coiled tubing or wired coiled tubing. A top-hole repeater unit 102 is used to interface the network 100 with drilling control operations and with the rest of the world. In one aspect, the repeater unit 102 rotates with the kelly 104 or top-hole drive and transmits its information to the drill rig by any known means of coupling rotary information to a fixed receiver. In another aspect, two communication elements can be used in a transition sub, with one in a fixed position and the other rotating relative to it (not shown). A computer 106 in the rig control center can act as a server, controlling access to network 100 transmissions, sending control and command signals downhole, and receiving and processing information sent up-hole. The software running the server can control access to the network 100 and can communicate this information, in encoded format as desired, via dedicated land lines, satellite link (through an uplink such as that shown at 108), Internet, or other means to a central server accessible from anywhere in the world. The testing tool 120 is shown linked into the network 100 just above the drill bit 110 for communication along its conductor path and along the wired drill string 101.

[0026] The tool 120 may include a plurality of transducers 115 disposed on the tool 120 to relay downhole information to the operator at surface or to a remote site. The transducers 115 may include any conventional source/sensor (e.g., pressure, temperature, gravity, etc.) to provide the operator with formation and/or borehole parameters, as well as diagnostics or position indication relating to the tool. The telemetry network 100 may combine multiple signal conveyance formats (e.g., mud pulse, fiber-optics, acoustic, EM hops, etc.). It will also be appreciated that software/firmware may be configured into the tool 120 and/or the network 100 (e.g., at surface, downhole, in combination, and/or remotely via wireless links tied to the network).

[0027] Referring to Figure 4, a section of the wired drill string 101 is shown including the formation tester 120. Conductors 150 traverse the entire length of the tool. Portions of wired drill pipes 103 may be subs or other connections means. In some embodiments, the conductor(s) 150 comprise coaxial cables, copper wires, optical fiber cables, triaxial cables, and twisted pairs of wire. The ends of the wired subs 103 are configured to communicate within a downhole network as described herein.

[0028] Communication elements 155 allow the transfer of power and/or data between the sub connections and through the tool 120. The communication elements 155 may comprise inductive couplers, direct electrical contacts, optical couplers, and combinations thereof. The conductor 150 may be disposed through a hole formed in the walls of the outer tubular members of the tool 120 and pipes 103. In some embodiments, the conductor 150 may be disposed part way within the walls and part way through the inside bore of the tubular members or drill collars. In some embodiments, a coating may be applied to secure the conductor 150 in place. In this way, the conductor 150 will not affect the operation of the testing tool 120. The coating should have good adhesion to both the metal of the pipe and any insulating material surrounding the conductor 150. Useable coatings include, for example, a polymeric material selected from the group consisting of natural or synthetic rubbers, epoxies, or urethanes. Conductors 150 may be disposed on the subs using any suitable means. A data/power signal may be transmitted along the tool 120 from one end of the tool through the conductor(s) 150 to the other end across the communication elements 155.

[0029] Referring next to Figure 5, an embodiment of an MWD formation probe collar section 200 is shown in detail, which is an exemplary tool that may be used as the tool 10 in Figure 1 or the tool 120 in Figure 3. A drill collar 202 houses the formation tester or probe assembly 210. The probe assembly 210 includes various components for operation of the probe assembly 210 to receive and analyze formation fluids from the earth formation 9 and the reservoir 11. An extendable probe member 220 is disposed in an aperture 222 in the drill collar 202 and extendable beyond the drill collar 202 outer surface, as shown. The probe member 220 is retractable to a position recessed beneath the drill collar 102 outer surface, as shown with reference to the exemplary probe assembly 700 of Figure 6. The probe assembly 210 may include a recessed outer portion 203 of the drill collar 202 outer surface adjacent the probe member 220. The probe assembly 210 includes a draw down piston assembly 208, a sensor 206, a valve assembly 212 having a flow line shutoff valve 214 and equalizer valve 216, and a drilling fluid flow bore 204. At one end of the probe collar 200, generally the lower end when the tool 10 is disposed in the borehole 8, is an optional stabilizer 230, and at the other end is an assembly 240 including a hydraulic system 242 and a manifold 244.

[0030] The draw down piston assembly 208 includes a piston chamber 252 containing a draw down piston 254 and a manifold 256 including various fluid and electrical conduits and control devices, as one of ordinary skill in the art would understand. The draw down piston assembly 208, the probe 220, the sensor 206 (e.g., a pressure gauge) and the valve assembly 212 communicate with each other and various other components of the probe collar 200, such as the manifold 244 and hydraulic system 242, as well as the tool 10 via conduits 224a, 224b, 224c and 224d. The conduits 224a, 224b, 224c, 224d include various fluid flow lines and electrical conduits for operation of the probe assembly 210 and probe collar 200.

[0031] For example, one of conduits 224a, 224b, 224c, 224d provides a hydraulic fluid to the probe 220 to extend the probe 220 and engage the formation 9. Another of these conduits provides hydraulic fluid to the draw down piston 254, actuating the piston 254 and causing a pressure drop in another of these conduits, a formation fluid flow line to the probe 220. The pressure drop in the flow line also causes a pressure drop in the probe 220, thereby drawing formation fluids into the probe 220 and the draw down piston assembly 208. Another of the conduits 224a, 224b, 224c, 224d is a formation fluid flow line communicating formation fluid to the sensor 206 for measurement, and to the valve assembly 212 and the manifold 244. The flow line shutoff valve 214 controls fluid flow through the flow line, and the equalizer valve 216 is actuatable to expose the flow line the and probe assembly 210 to a fluid pressure in an annulus surrounding the probe collar 200, thereby equalizing the pressure between the annulus and the probe assembly 210. The manifold 244 receives the various conduits 224a, 224b, 224c, 224d, and the hydraulic system 242 directs hydraulic fluid to the various components of the probe assembly 210 as just described. One or more of the conduits 224a, 224b, 224c, 224d are electrical for communicating power from a power source, and control signals from a controller in the tool, or from the surface of the well.

[0032] Drilling fluid flow bore 204 may be offset or deviated from a longitudinal axis of the drill collar 202, such that at least a portion of the flow bore 204 is not central in the drill collar 202 and not parallel to the longitudinal axis. The deviated portion of the flow bore 204 allows the receiving aperture 222 to be placed in the drill collar 202 such that the probe member 220 can be fully recessed below the drill collar 202 outer surface. Space for formation testing and other components is limited. Drilling fluid must also be able to pass through the probe collar 200 to reach the drill bit 7. The deviated or offset flow bore 204 allows an extendable sample device such as probe 220 and other probe embodiments described herein to retract and be protected as needed, and also to extend and engage the formation for proper formation testing.

[0033] Referring now to Figure 6, an alternative embodiment to probe 220 is shown as probe 700. The probe 700 is retained in an aperture 722 in drill collar 102 by threaded engagement and also by cover plate 701 having aperture 714. Alternative means for retaining the probe 700 are consistent with the teachings herein. The probe 700 is shown in a retracted position, beneath the outer surface of the drill collar 202. The probe 700 generally includes a stem 702 having a passageway 712, a sleeve 704, a piston 706 adapted to reciprocate within the sleeve 704, and a snorkel assembly 708 adapted for reciprocal movement within the piston 706. The snorkel assembly 708 includes a snorkel 716. The end of the snorkel 716 may be equipped with a screen 720. Screen 720 may include, for example, a slotted screen, a wire mesh or a gravel pack. The end of the piston 706 may be equipped with a seal pad 724. The passageway 712 communicates with a port 726, which communicates with one of the conduits 224a, 224b, 224c, 224d for receiving and carrying a formation fluid. [0034] Referring to Figure 7, the probe 700 is shown in an extended position. The piston 706 is actuated within the sleeve 704 from a first position shown in Figure 6 to a second position shown in Figure 7, preferably by hydraulic pressure. The seal pad 724 is engaged with the borehole wall surface 16, which may include a mud or filter cake 49, to form a primary seal between the probe 700 and the borehole annulus 52. Then, the snorkel assembly 708 is actuated, by hydraulic pressure, for example, from a first position shown in Figure 6 to a second position shown in Figure 7. The snorkel 716 extends through an aperture 738 in the seal pad 724 and beyond the seal pad 724. The snorkel 716 extends through the interface 730 and penetrates the formation 9. The probe 700 may be actuated to withdraw formation fluids from the formation 9, into a bore 736 of the snorkel assembly 708, into the passageway 712 of the stem 702 and into the port 726. The screen 720 filters contaminants from the fluid that enters the snorkel 716. The probe 700 may be equipped with a scraper 732 and reciprocating scraper tube 734 to move the scraper 732 along the screen 720 to clear the screen 720 of filtered contaminants.

[0035] The seal pad 724 is preferably made of an elastomeric material. The elastomeric seal pad 724 seals and prevents drilling fluid or other borehole contaminants from entering the probe 700 during formation testing. In addition to this primary seal, the seal pad 724 tends to deform and press against the snorkel 716 that is extended through the seal pad aperture 738 to create a secondary seal.

[0036] Another embodiment of the probe is shown as probe 800 in Figure 8. Many of the features and operations of the probe 800 are similar to the probe 700. For example, the probe 800 includes a sleeve 804, a piston 806 and a snorkel assembly 808 having a snorkel 816, a screen 820, a scraper 832 and a scraper tube 834. In addition, the probe 800 includes an intermediate piston 840 and a stem extension 844 having a passageway 846. The intermediate piston 840 is extendable similar to the piston 806 and the piston 706. However, the piston 840 adds to the overall distance that the probe 800 is able to extend to engage the borehole wall surface 16. Both of the pistons 806 and 840 may be extended to engage and seal a seal pad 824 with the borehole wall surface 16. The seal pad 824 may include elastomeric materials such that seals are provided at a seal pad interface 830 and at a seal pad aperture 838. The snorkel 816 extends beyond the seal pad 824 and the interface 830 such that a formation penetrating portion 848 of the snorkel 816 penetrates the formation 9. Formation fluids may then be drawn into the probe 800 through a screen 820, into a bore 836, into the passageway 846, into a passageway 812 of a stem 802 and a base 842, and finally into a port 826. [0037] In some embodiments of the formation tester, multiple probes are extendable from the tool body. Referring to Figure 9, a tool collar 1050 includes a first probe 1052 and a second probe 1054. The probes 1052, 1054 may include any of the various probes consistent with the teachings herein, with inner supporting testing equipment and apparatus 1056 as also consistent with the teachings herein. In some embodiments, the probe 1052 may be offset around the circumference of the tool body from the probe 1054. Thus, the probes 1052, 1054 extend in different radial directions toward the formation, thereby allowing separate tests to be taken substantially simultaneously at different angular orientations around the tool. In some embodiments, the probe 1054 is at an angular orientation 90 degrees offset from the probe 1052. In other embodiments, the probes are radially or angularly offset relative to each other around the tool body at various locations. In an exemplary embodiment, and with reference to Figure 10, a formation tester 1070 includes a first tool face 1082 having a first formation probe 1072. Angularly offset from the face 1082 is another tool face 1084 including a second probe 1074. In some embodiments, as shown, the second probe 1074 is approximately 90 degrees offset from the first probe 1072. Angularly offset from the faces 1082, 1084 is another tool face 1086 including a third probe 1076. In some embodiments, as shown, the third probe 1076 is approximately 90 degrees offset from the first probe 1072 in another direction from the second probe 1074. Thus, multiple angular orientations of test-taking probes is achieved with the tool 1070.

[0038] Disclosed herein are embodiments for a method of testing a formation and determining anisotropy of the formation with a formation tester. In some embodiments, the formation tester comprises a single formation probe assembly as shown in Figures 5-8. In some embodiments, the formation tester comprises a multi-probed formation tester as shown in Figures 9 and 10. In some embodiments, the probes can be aligned with each other along the well bore as shown in Figure 9. In other embodiments, the probes are rotated with respect to each other as shown in Figure 10. Useful relative probe orientations include 90 and 180 degrees.

[0039] In one embodiment, a formation probe is extended and engaged with the formation. With reference to Figure 11, probe engagement is represented at a probe set curve 902 of the overall pressure test curve 900. A pressure test now may be conducted, including drawing formation fluids into the probe and tool flowlines at a specific rate or pressure, as represented at a drawdown curve 904. When the drawdown fluid flow is stopped, the pressure increases as represented at a buildup curve 906. The pressure increases to the initial pressure 907 at the well bore interface, typically presumed to be the formation pressure. Frequently, multiple drawdown sequences are performed to verify the buildup and final pressures. As shown in Figure 11, a second drawdown 908 results in a second buildup 910. The flow rates Qi and Q₂ of the respective drawdowns can be calculated using the corresponding time differentials At_ddi and At_dd2. The difference between the flowing pressure of the drawdowns and the final buildup pressure is referred to as the drawdown pressure differential, and is represented as the pressure differentials AP_ddi and AP_dd2. These pressure differentials can be used to determine the drawdown spherical mobility. Mobility is defined as the ratio of the permeability divided by the viscosity, or k/μ. If the viscosity is known or measured, then the permeability can be determined. A buildup spherical mobility can also be determined from the transient analysis for the buildup data.

[0040] The probe is then retracted, represented by the portion 912 of the curve 900. The tool is rotated generally about the borehole or tool axis, and the probe is re-positioned at a different angular orientation around the borehole. The probe is re-extended and another pressure test is conducted at a different radial location in the borehole. By rotating the tool and testing at different locations around the borehole, while maintaining the same general axial position or depth of the tool and the probe, a change in the pressure response can be noted. For example, and with reference to Figures 12 and 13, in a horizontal or deviated borehole 1008 a pressure test is performed with a testing tool 1010 and a single probe 1012 facing upward in the borehole. The tool 1010 and the probe 1012 are then rotated from this first position 1014 at the top of the borehole to additional positions 1018 at different angles Θ_ρ relative to the first position 1014 to obtain test measurements at other positions in the borehole 1008, as shown in Figure 13.

[0041] In another embodiment, the tool includes multiple probes. For example, two probes are positioned around the tool body, 90 degrees offset from each other as disclosed herein. First and second pressure tests are performed substantially simultaneously, or without rotating the tool body, using both probes to obtain measurements from different angular locations in the formation. Thus, the radially or angularly displaced measurement-taking ability is built into the formation tester. The tests may be taken without translating or otherwise axially displacing the tool.

[0042] In some embodiments, the formation tester with the probes is rotatable relative to the tool string or other tool conveyance. The rotatable formation tester may include a downhole motor or other actuator, and rotatable interconnect assemblies coupled between the tool string or other conveyance above and below the formation tester. The actuator will rotate the formation tester while the interconnect assemblies allow rotation of the formation tester relative to the tool string.

[0043] The information obtained by the embodiments described are analyzed as follows. In exemplary embodiments, finite element modeling runs are executed assuming a 1 mDarcy formation with 0.1 anisotropy, or k_v/k (k_v = vertical permeability, k = horizontal permeability). In some cases, anisotropy is referred to as or k_z/k_r wherein k_z is the permeability of the formation in the longitudinal or z-axis direction of the borehole and k_r is the permeability of the formation in the radial direction from the borehole. The drawdown pressure is the maximum steady-state pressure differential from a 1 cc/sec drawdown flow rate. The dip angle is the angle between the bedding planes and the axis of the borehole. Referring again to Figure

12, the formation layers 1002, 1004, 1006 create a bedding plane 1016. One measure of the dip angle is a dip angle 0_di_P measured from a line normal to the bedding plane 1016 to the axis of the borehole 1008. The probe rotation or orientation angle is the angle of the probe relative to the probe being directed to the top or uppermost part of the borehole. Referring again to Figure

13, the upper position 1014 of the probe 1012 can be adjusted to another position 1018 around the borehole 1008 to create the probe rotation angle Θ_ρ, shown as 90 degrees. In some embodiments, the probe rotation angle Θ_ρ is specified or predetermined. The dip angle and probe rotation angle are varied to isolate and analyze the different pressure responses. Because of symmetry, the drawdown pressures are repeated for the various probe rotation positions around the borehole.

[0044] In a first example, and with reference to Table 1 below, a dip angle of 90 degrees is used, which simulates a horizontal borehole. A first pressure test Ai includes a probe orientation of 0 degrees, representing the probe being directed to the top or uppermost portion of the borehole. The resulting drawdown differential pressure measurement is 5,048 psi. The probe is then rotated 45 degrees in the borehole for a pressure test A₂, resulting in a drawdown differential pressure measurement of 3,705 psi. The probe is then rotated another 45 degrees in the borehole to a total of 90 degrees from the original position, for a pressure test A₃ resulting in a drawdown differential pressure measurement of 3,267 psi. Thus, the probe is rotated to specified or predetermined probe orientation angles.

(rotation = 0- 360 °)

Table 1

[0045] It is noted that the drawdown pressures are unique for the three probe rotation angles chosen for the three tests A_l5 A₂, and A3. The "drawdown ratio" is the ratio of drawdown pressures relative to the 0 angle probe position. Thus, the drawdown ratio for test A₂ is 5,048/3,705 = 1.36, representing a 36% difference or decrease in the measured pressures. The drawdown ratio for test A₃ is 5,048/3,267 = 1.55, representing a 55% difference or decrease in the pressure pulses. The drawdown ratio for test Ai is 1.00 because it is used as the reference test and probe orientation for the other tests. The ratios show the sensitivity of the pressure tests to anisotropy.

[0046] In another example, three additional simulations are executed to show the sensitivity of the drawdown pressures for a wellbore with a high dip angle relative to the bedding plane. A first pressure test A4 at the new dip angle of 45 degrees includes a probe orientation of 0 degrees, representing the probe being directed to the top or uppermost portion of the borehole. The resulting drawdown differential pressure measurement is 3,615 psi. The probe is then rotated 45 degrees in the borehole for a pressure test A5, resulting in a drawdown differential pressure measurement of 3,308 psi. The probe is then rotated another 45 degrees in the borehole to a total of 90 degrees from the original position, for a pressure test A₆ resulting in a drawdown differential pressure measurement of 3,103 psi.

[0047] It is noted that the drawdown pressures are unique for the three probe rotation angles chosen for the three tests A₄, A5, and A₆ at the dip angle 45 degrees. The drawdown ratio for test A₅ is 3,615/3,308 = 1.09 and the drawdown ratio for test A₆ is 3,615/3,103 = 1.17. Again, the ratios show the sensitivity of the pressure tests to anisotropy. While the drawdown ratios shown in Table 1 are unique, it is apparent that as the dip angle reduces from 90 degrees, or horizontal, there is less sensitivity to anisotropy.

[0048] In a final simulation, A₇, drawdown pressure responses are collected in a vertical well (i.e., dip angle = 0). Pressures taken in any direction around the borehole (0 through 360 degrees) in the vertical well are the same, 2,893 psi. Thus, a vertical well, or a well with no dip angle relative to the bedding planes, has the lowest drawdown pressure of any of the exemplary simulations, and no sensitivity to anisotropy with probe orientation.

[0049] As noted, anisotropy may be expressed as a ratio of the vertical and horizontal permeabilities of the formation. Permeability is a measure of how easily fluids flow through a particular environment. Permeability of a formation generally may be determined by inducing a fluid flow from the formation into a test apparatus, and measuring the pressure differential created by the induced flow. The detected pressures can be used to estimate or determine the vertical (k_v) and horizontal (k ) permeabilities. For example, a solution for determining vertical and horizontal permeabilities is presented in SPE 102659, "Anaylytical Solution of Single-Probe Tests in a Horizontal Well and Its Application to Estimate Horizontal and Vertical Permeabilities", JJ. Sheng, Baker Hughes.

[0050] Based on the information obtained by the pressure tests, it is possible to determine anisotropy. In some embodiments, if the dip angle is measured or assumed, then two drawdowns or tests at different angular probe orientations can be used to determine anisotropy. In some embodiments, if the dip angle is not assumed, then three drawdowns or tests at different angular probe orientations can be used to determine dip angle or anisotropy, or a combination thereof. In further embodiments, if more than three drawdowns or tests are taken at different probe rotations, then all of the data can be stacked using a regression analysis technique. In other words, with the known sensitivity of formation measurements, particularly formation pressure measurements, to anisotropic formations as disclosed herein, the collected formation measurements can be used to calculate anisotropy and/or dip angle of the intersected formation using mathematical equations or regression analysis techniques.

[0051] In further embodiments, between groups of tests taken angularly around the borehole, the formation tester is translated or otherwise moved along the borehole. Thus, multiple groups of angularly displaced formation tests are collected at discrete axial locations along the borehole. For example, the formation tester is lowered to a first depth in the borehole and the tests Ai - A₃ or the tests A₄ - A₆ are performed at the first depth. Then, the formation tester is moved axially in the borehole to a second depth, and the tests Ai - A₃ or the tests A₄ - A₆ are performed at the second depth. In some embodiments, the radially or angularly displaced tests Ai - A₃ or A₄, - A₆ are performed at multiple discrete axial locations over a defined interval of the borehole. The different axially displaced groups of angular formation measurements may be combined using an upscaling technique. In some embodiments, the result of the upscaling technique is one or a reduced number of refined measurements representing the various groups of angularly displaced measurements. In some embodiments, the upscaling technique includes defining an axial interval of the borehole. Finally, the anisotropy or dip angle, or a combination thereof, can be calculated as taught herein.

[0052] A numerical model or analytical solution can be used to compare the measurements or calculate the results, such as those previously referenced herein or those generally described in U.S. Patent No. 7,059,179.

[0053] Various embodiments presented herein reflect a method for determining a formation anisotropy including lowering a formation tester to a first depth in a borehole, testing the formation at the first depth to obtain a first formation measurement, testing the formation at the first depth at a radially displaced location to obtain a second formation measurement, and comparing the first formation measurement to the second formation measurement to obtain at least one of the formation anisotropy and a dip angle of the borehole. The method may include rotating the formation tester in the borehole before testing the formation, to obtain the first measurement or the second measurement at a predetermined or specified orientation. The method may include rotating the formation tester to obtain the second measurement by angularly re-orienting a formation probe to the predetermined or specified radially displaced location in the borehole. The method may include testing the formation to obtain a first measurement that includes measuring a pressure differential. The method may include measuring a pressure differential that includes drawing down a formation fluid and observing a pressure buildup. The method may include determining a formation permeability or a formation mobility, or a combination thereof, using at least one of the first and second measurements. The method may include obtaining a plurality of formation measurements at a plurality of radially displaced locations at the first depth, moving the formation tester to a second depth in the borehole, and obtaining a plurality of formation measurements at a plurality of radially displaced locations at the second depth. The method may include combining the plurality of measurements at the first depth with the plurality of measurements at the second depth to obtain at least one of the formation anisotropy and the dip angle of the borehole. The method may include obtaining a plurality of groups of measurements at a plurality of axially displaced depths over a pre-defined interval of the borehole. The method may include detecting a difference between the first measurement and the second measurement. The method may include determining the formation anisotropy further using a known dip angle.

[0054] In some embodiments, a method for determining a formation anisotropy includes lowering a formation tester to a first depth in a borehole, obtaining a plurality of formation pressure measurements at a plurality of angularly displaced locations around the borehole at the first depth, and calculating at least one of the formation anisotropy and a dip angle of the borehole using the plurality of formation pressure measurements. The method may include that the plurality of angularly displaced locations are known orientations of the formation tester relative to the borehole. The method may include that the plurality of formation pressure measurements are different from each other based on the known orientations of the formation tester. The method may include that the calculation of at least one of the formation anisotropy and the dip angle is a function of the different formation pressure measurements corresponding to the different known orientations of the formation tester. The method may include rotating a formation probe of the formation tester to the plurality of angularly displaced locations. The method may include rotating the formation probe relative to a work string coupled to the formation tester. The method may include extending multiple angularly offset formation probes of the formation tester. The method may include moving the formation tester to a plurality of depths in the borehole, and obtaining a plurality of angularly displaced formation pressure measurements at each of the plurality of depths.

[0055] In some embodiments, a system for determining a formation anisotropy includes a drill string including a MWD formation tester having an extendable formation probe and a processor coupled to the formation tester to receive a plurality of pressure measurements taken through the formation probe at a plurality of angularly displaced locations at a single depth in a borehole. The system may include that the plurality of angularly displaced locations are known orientations of the formation probe relative to the borehole. The system may include that the plurality of pressure measurements are different from each other based on the known orientations of the formation probe. The system may include that the processor is configured to calculate at least one of the formation anisotropy and the dip angle as a function of the different pressure measurements corresponding to the different known orientations of the formation probe. The system may include that the formation tester is rotatable relative to the drill string to place the formation probe at the plurality of angularly displaced borehole locations. The system may include that the formation tester includes a plurality of angularly offset formation probes to take the plurality of pressure measurements at the plurality of angularly displaced borehole locations. [0056] The embodiments set forth herein are merely illustrative and do not limit the scope of the disclosure or the details therein. It will be appreciated that many other modifications and improvements to the disclosure herein may be made without departing from the scope of the disclosure or the inventive concepts herein disclosed. Because many varying and different embodiments may be made within the scope of the inventive concept herein taught, including equivalent structures or materials hereafter thought of, and because many modifications may be made in the embodiments herein detailed in accordance with the descriptive requirements of the law, it is to be understood that the details herein are to be interpreted as illustrative and not in a limiting sense.

Claims

CLAIMS What is claimed is:

1. A method for determining a formation anisotropy comprising:

lowering a formation tester to a first depth in a borehole;

testing the formation at the first depth to obtain a first formation measurement; testing the formation at the first depth at a radially displaced location to obtain a second formation measurement; and

comparing the first formation measurement to the second formation measurement to obtain at least one of the formation anisotropy and a dip angle of the borehole.

2. The method of claim 1 further comprising rotating the formation tester in the borehole before testing the formation to obtain the first measurement or the second measurement at a predetermined orientation.

3. The method of claim 2 wherein rotating the formation tester to obtain the second measurement includes angularly re-orienting a formation probe to the predetermined radially displaced location in the borehole.

4. The method of claim 1 wherein testing to obtain the first measurement includes using a first formation probe, and testing to obtain the second measurement includes using a second formation probe angularly offset from the first probe.

5. The method of claim 1 wherein testing the formation to obtain the first measurement includes engaging a formation probe with the formation to receive formation fluids, and testing the formation to obtain the second measurement includes engaging the formation probe with the formation to receive formation fluids from the radially displaced location.

6. The method of claim 1 wherein testing the formation to obtain a first measurement includes measuring a pressure differential.

7. The method of claim 6 wherein measuring a pressure differential includes drawing down a formation fluid and observing a pressure buildup.

8. The method of claim 1 further comprising determining a formation permeability or a formation mobility, or a combination thereof, using at least one of the first and second measurements.

9. The method of claim 1 further obtaining a plurality of formation measurements at a plurality of radially displaced locations at the first depth.

10. The method of claim 9 further comprising moving the formation tester to a second depth in the borehole.

11. The method of claim 10 further comprising obtaining a plurality of formation measurements at a plurality of radially displaced locations at the second depth.

12. The method of claim 11 further comprising combining the plurality of measurements at the first depth with the plurality of measurements at the second depth to obtain at least one of the formation anisotropy and the dip angle of the borehole.

13. The method of claim 12 further comprising obtaining a plurality of groups of measurements at a plurality of axially displaced depths over a pre-defined interval of the borehole.

14. The method of claim 1 further comprising detecting a difference between the first measurement and the second measurement.

15. The method of claim 1 further comprising determining the formation anisotropy further using a known dip angle.

16. A method for determining a formation anisotropy comprising:

lowering a formation tester to a first depth in a borehole;

obtaining a plurality of formation pressure measurements at a plurality of angularly displaced locations around the borehole at the first depth; and

calculating at least one of the formation anisotropy and a dip angle of the borehole using the plurality of formation pressure measurements.

17. The method of claim 16 wherein the plurality of angularly displaced locations are known orientations of the formation tester relative to the borehole.

18. The method of claim 17 wherein the plurality of formation pressure measurements are different from each other based on the known orientations of the formation tester.

19. The method of claim 18 wherein the calculation of at least one of the formation anisotropy and the dip angle is a function of the different formation pressure measurements corresponding to the different known orientations of the formation tester.

20. The method of claim 16 further comprising rotating a formation probe of the formation tester to the plurality of angularly displaced locations.

21. The method of claim 16 further comprising rotating the formation probe relative to a work string coupled to the formation tester.

22. The method of claim 16 further comprising extending multiple angularly offset formation probes of the formation tester.

23. The method of claim 16 further comprising moving the formation tester to a plurality of depths in the borehole, and obtaining a plurality of angularly displaced formation pressure measurements at each of the plurality of depths.

24. A system for determining a formation anisotropy comprising:

a drill string including a MWD formation tester having an extendable formation probe; and

a processor coupled to the formation tester to receive a plurality of pressure measurements taken through the formation probe at a plurality of angularly displaced locations at a single depth in a borehole.

25. The system of claim 24 wherein the plurality of angularly displaced locations are known orientations of the formation probe relative to the borehole.

26. The system of claim 25 wherein the plurality of pressure measurements are different from each other based on the known orientations of the formation probe.

27. The system of claim 26 wherein the processor is configured to calculate at least one of the formation anisotropy and the dip angle as a function of the different pressure measurements corresponding to the different known orientations of the formation probe.

28. The system of claim 24 wherein the formation tester is rotatable relative to the drill string to place the formation probe at the plurality of angularly displaced borehole locations.

29. The system of claim 24 wherein the formation tester includes a plurality of angularly offset formation probes to take the plurality of pressure measurements at the plurality of angularly displaced borehole locations.