Formation evaluation instrument and method

Subsurface formation evaluation comprising, for example, sealing a portion of a wall of a wellbore penetrating the formation, forming a hole through the sealed portion of the wellbore wall, injecting an injection fluid into the formation through the hole, and determining a saturation of the injection fluid in the formation by measuring a property of the formation proximate the hole while maintaining the sealed portion of the wellbore wall.

BACKGROUND OF THE DISCLOSURE

It may be desirable to measure the response of permeable subsurface formations to the flow of fluids in the pore spaces of such formations. For example, the determination of effective permeabilities of water, oil or gas, residual oil saturations, irreducible water saturations, and rock wettabilities, among other petrophysical parameters, may be very useful in gauging the producibility of hydrocarbon bearing formations. Downhole testing tools may be used for making permeability and/or other hydraulic property measurements of subsurface formations surrounding wellbores. Descriptions of such tools may be found, for example, in U.S. Pat. Nos. 5,335,542, 6,528,995, 6,856,132 and 7,032,661, the disclosures of which are incorporated herein by reference.

Various factors may restrict movement of fluid between subsurface formations and downhole testing tools. For example, during drilling of a wellbore, particles from the mud may plug the pore spaces of permeable rock formations close to the wellbore wall and create a “damaged zone” or “permeability skin” Downhole testing tools may use a perforation through a portion of the wellbore wall, for example to establish a fluid communication therethrough. Descriptions of such tools may be found, for example, in U.S. Pat. No. 7,191,831 and U.S. Patent Application Pub. Nos. 2006/0000606, 2008/0066536 and 2008/0066537, the disclosures of which are incorporated herein by reference.

DETAILED DESCRIPTION

During and after drilling of a wellbore, connate fluid in the pore spaces of permeable formations may become partially or totally displaced by a filtrate phase of the wellbore fluid (or “drilling mud”) used to drill the wellbore and evacuate the drill cuttings. Wellbore fluid may seep into the formation due to the increased pressure in the wellbore with respect to the pressure of the connate fluid in the formation, and may create a so called “invaded zone”. The lateral depth of the invaded zone from the wellbore wall may depend on, among other factors, the type of drilling fluid used to drill the wellbore, the hydrostatic or hydrodynamic fluid pressure in the wellbore, the fluid pressure in the formation, the fractional volume of pore space (“porosity”) of the formation, and the time lapse occurred since drilling the wellbore. The term “lateral depth” as used herein is intended to denote the distance from the wellbore wall in a direction perpendicular to the longitudinal axis of the wellbore. Effects of such invaded zone may include, for example, chemical reactions between the mud filtrate and the formation rock and contamination of fluid samples by mud filtrate. Thus, the invaded zone may affect and sometimes prevent the measurements of some petrophysical parameters.

Further, particles in suspension in the wellbore fluid may accumulate in a shallow layer of the formation proximate the wellbore wall, and such may clog the pore spaces of the permeable rock formations. The particle accumulation may create a “damaged zone” or “permeability skin” which restricts movement of fluid between the reservoir formation and the testing tool. The lateral depth of the damaged zone from the wellbore wall may depend on, among other factors, the chemical composition of the drilling fluid, the physical nature of the solids in the drilling fluid used to drill the wellbore, the differential pressure between the hydrostatic or hydrodynamic fluid pressure in the wellbore and the fluid pressure in the formation, the initial permeability of the formation, the pore size distribution, and the fractional volume of pore space (“porosity”) of the formation. In addition, the particles also form a substantially impermeable layer on the wellbore wall sometimes referred to as a “mud cake”. Both the damaged zone and the mud cake may limit the flow of injected fluid into the formation, and/or of formation fluid into a downhole tester. Thus, both the damaged zone and the mud cake may affect and sometimes prevent the measurement of some petrophysical parameters.

Methods and apparatus for measuring petrophysical parameters that may be less affected by the fluid displacement described above are described herein. The methods and apparatus of the present disclosure may be used to measure petrophysical parameters while injecting fluid into or withdrawing fluid from a subsurface formation. For example, the methods and apparatus of the present disclosure may be used to measure the response of permeable formations to the injection of fluids into the pore spaces of portions of the subsurface formations.

In accordance with one or more aspects of the present disclosure, a formation evaluation apparatus may be positioned within a wellbore drilled through subsurface formations. The formation evaluation apparatus may be moved along the interior of the wellbore using an armored electrical cable (“wireline”), but may alternatively be conveyed any other manner known in the art and/or future developed. Conveyance manners known in the art include coupling the formation evaluation apparatus within a drill string (i.e., conveyed “while-drilling”), affixing the formation evaluation apparatus to the end of a coiled tubing, on a “slickline” or on production tubing, for example. The manner of conveyance is not intended in any way to limit the scope of the present disclosure.

In accordance with one or more aspects of the present disclosure, a sealing member, such as a probe seal, may be used for sealing off a portion of the wall of the wellbore penetrating a formation. Thus, fluid communication between the formation evaluation apparatus and the formation may be localized in a relatively small area, corresponding to the area of a port in the sealing member. In contrast with other sealing members, such as dual or straddle packers, a probe seal may have the advantage that the flow characteristics induced in the formation by the probe may be better determined (e.g., more uniform, well correlated to the pumping rate prescribed by the testing tool, etc). Also, the maximum flow rate of fluids close to the port in the sealing member that may be achieved using a downhole pump may be larger when using a probe than when using a straddle packer. This may be used to advantage in high mobility formations to perform tests over a relatively large range of flow rates. For example, sweep efficiency of the formation fluids by the injected fluids may be better determined at high flow rates and may provide more accurate measurements of residual oil saturation and/or other parameters. However, the manner of implementing a sealing member is not intended in any way to limit the scope of the present disclosure.

In accordance with one or more aspects the present disclosure, a drill bit, coring bit, and/or other perforating mechanism may be used to extend a hole through the mud cake and/or the damaged zone laterally through the wellbore wall and into the undamaged zone of the formation. As will be appreciated by those skilled in the art, the undamaged zone may include rock formation having substantially undisturbed permeability. Thus, the hole may bypass the portion of the formation that has reduced permeability. By doing so, the pressure required to inject fluid through the hole and into the formation may be low, which may reduce the risk of unintentionally fracturing the formation and/or loosing the seal with the formation. Further, the hole may extend through the invaded zone laterally proximate the wellbore and into the un-invaded zone of the formation. As will be appreciated by those skilled in the art, the un-invaded zone may include substantially entirely connate fluid within the pore spaces of the formation.

In accordance with one or more aspects the present disclosure, one or more petrophysical parameters, for example, parameters that are related to the fluid content (e.g., oil saturation) of the formation, or fluid flow in the formation may be measured before, during or after the pumping of fluid into and/or from the formation. Such measurements and pumping may be performed without the need to break the seal created against the wellbore wall. Thus, the pressure in the perforation may be maintained close to the wellbore pressure (and optionally below the formation pressure) during measurement, which may prevent or reduce re-invasion of the tested region by the wellbore fluid, or at least further movement of wellbore fluid while a measurement is being made after a fluid injection. Such measurement may enable determination of petrophysical parameter(s), such as saturation levels, as the volume of fluid pumped into the formation changes.

In accordance with one or more aspects the present disclosure, a plurality of injection fluids may be provided downhole. One or more of these injection fluids may be introduced in the formation and petrophysical measurements may be performed before, during or after the injection. In making petrophysical measurements, the sensors used to make the particular measurements may be configured such that the lateral depth into the formation from the wellbore in which the measurement is made generally corresponds to the lateral depth at which the fluid is injected into the formation. In this way, flow heterogeneity in the formation, saturation levels of injected and/or connate fluids, resistivity response of the formation due to different saturation levels of injected fluids, among others, may be determined. This information may in turn be used to estimate recoverable reserves, or to improve the oil recovery of the reservoir, among other uses.

The formation evaluation apparatus and methods disclosed herein may be used to determine petrophysical property values (e.g., permeability values) that are less affected by the mud cake and/or the damaged zone, and are more representative of the formation. In other words, a particular advantage that may be provided is that the formation evaluation apparatus may be in fluid communication with a portion of the formation that is relatively unaffected by the solid particles and/or the drilling fluid used to drill the wellbore. Further, the formation evaluation apparatus and methods disclosed herein may be used to determine petrophysical property values (e.g., residual oil saturation, rock wettability) within a zone of the formation that has not been invaded by wellbore fluid filtrate.

Turning toFIG. 1, an example well site system according to one or more aspects of the present disclosure is shown. The well site may be situated onshore (as shown) or offshore. A wireline tool200may be configured to seal a portion of a wall of a wellbore202penetrating a subsurface formation230, and form a hole235through the sealed portion of the wellbore wall. The wireline tool200may further be configured to inject an injection fluid into the formation230through the hole235, and determine a saturation of the injection fluid in the formation by measuring a property of the formation proximate the hole while maintaining the sealed portion of the wellbore wall.

The example wireline tool200may be suspended in the wellbore202from a lower end of a multi-conductor cable204that may be spooled on a winch (not shown) at the Earth's surface. At the surface, the cable204may be communicatively coupled to an electronics and processing system206. The electronics and processing system206may include a controller having an interface configured to receive commands from a surface operator. In some cases, the electronics and processing system206may further include a processor configured to implement one or more aspects of the methods described herein.

The example wireline tool200may include a telemetry module210, a sample carrier module238, a formation tester214, and injection fluid carrier modules226,228. Although the telemetry module210is shown as being implemented separate from the formation tester214, the telemetry module210may be implemented in the formation tester214. Additional components may also be included in the tool200.

The formation tester214may comprise a selectively extendable probe assembly216and a selectively extendable tool anchoring member218that are respectively arranged on opposite sides of the body208. The probe assembly216may be configured to selectively seal off or isolate selected portions of the wall of the wellbore202. The probe assembly216may include a perforating mechanism (not shown inFIG. 1) configured to form the hole235through the formation230beyond the wall of the wellbore202. A probe seal may be associated with the perforating mechanism and may be configured to substantially prevent movement of fluid into or out of the formation230other than through the hole235. Thus, the probe seal may be configured to fluidly couple components of the formation tester214, for example, pumps221and/or231, to the adjacent formation230via the hole235.

The formation tester214may be used to obtain fluid samples from the formation230, for example by extracting fluid from the formation using the pump231. A fluid sample may thereafter be expelled through a port into the wellbore or the sample may be sent to one or more fluid collecting chambers disposed in the sample carrier module238. In turn, the fluid collecting chambers may receive and retain the formation fluid for subsequent testing at the surface or a testing facility. Alternatively, or additionally, the sampled fluid may segregate in the sample carrier module238. One segregated portion of the fluid may selectively be removed from the sample carrier module and transferred into one or more fluid collecting chambers of the injection fluid carrier modules226,228. For example, the formation tester214may be provided with a sampling system of a type described in U.S. Pat. No. 7,195,063, the disclosure of which is incorporated herein by reference.

The formation tester214may also be used to discharge injection fluid into the formation230, for example, by moving the injection fluid from one or more fluid collecting chambers disposed in the injection fluid carrier modules226,228using the pump221. The injection fluid may be moved from the one or more fluid collecting chambers by applying hydrostatic pressure from within the wellbore to a sliding the piston disposed in the collecting chamber, in addition to or in substitution of using the pump221. While the wireline tool200is depicted as having pumps220and221, a single reversible pump may be provided on the wireline tool200.

The probe assembly216of the formation tester214may be provided with a plurality of sensors222and224disposed adjacent to a port of the probe assembly216. The sensors222and224may be configured to determine petrophysical parameters (e.g., saturation levels) of a portion of the formation230proximate the probe assembly216. For example, the sensors222and224may be configured to measure or detect one or more of electric resistivity, dielectric constant, magnetic resonance relaxation time, nuclear radiation, and/or combinations thereof.

The formation tester214may be provided with a fluid sensing unit220through which the obtained fluid samples and/or injected fluids may flow and which is configured to measure properties and/or composition data of the flowing fluids. For example, the fluid sensing unit220may include a fluorescence sensor, such as described in U.S. Pat. Nos. 7,002,142 and 7,075,063, incorporated herein by reference. The fluid sensing unit220may alternatively or additionally include an optical fluid analyzer, for example as described in U.S. Pat. No. 7,379,180, incorporated herein by reference. The fluid sensing unit220may alternatively or additionally comprise a density and/or viscosity sensor, for example as described in U.S. Patent Application Pub. No. 2008/0257036, incorporated herein by reference. The fluid sensing unit220may alternatively or additionally include a high resolution pressure and/or temperature gauge, for example as described in U.S. Pat. Nos. 4,547,691 and 5,394,345, incorporated herein by reference. An implementation example of sensors in the fluid sensing unit220may be found in “New Downhole-Fluid Analysis-Tool for Improved Formation Characterization” by C. Dong, et al., SPE 108566, December 2008. It should be appreciated, however, that the fluid sensing unit220may include any combination of conventional and/or future-developed sensors within the scope of the present disclosure.

The telemetry module210may comprise a downhole control system212communicatively coupled to the electrical control and data acquisition system206. The electrical control and data acquisition system206and/or the downhole control system212may be configured to control the probe assembly216, the extraction of fluid samples from the formation230, and/or the injection of fluids into the formation230, for example via the pumping rate of pumps221and/or231. The electrical control and data acquisition system206and/or the downhole control system212may be further configured to control the forming of the hole235.

The electrical control and data acquisition system206and/or the downhole control system212may be further configured to analyze and/or process data obtained, for example, from downhole sensors disposed in the fluid sensing unit220and/or from the sensors222and224, store measurements or processed data, and/or communicate measurements or processed data to the surface or another component for subsequent analysis. For example, a formation dielectric constant and/or a formation magnetic resonance relaxation time distribution measured by at least one of the sensors222and224may be processed to determine one or more of a connate fluid saturation (e.g., water, gas and/or oil), and an injected fluid saturation. Additionally, a formation electric resistivity measured by at least one of the sensors222and224may be correlated with the determined saturations to determine a relationship between saturation and electric resistivity of the formation. Also, composition data measured with the fluid sensing unit220and flow rate induced by the pump220and/or221may be correlated with the determined saturations to determine effective permeability curves.

Turning toFIGS. 2A and 2B, collectively, an example well site system according to one or more aspects of the present disclosure is shown. The well site may be situated onshore (as shown) or offshore. The system may comprise one or more sampling-while drilling devices320,320A,410that may be configured to seal a portion of a wall of a wellbore311,411penetrating a subsurface formation370,420, and form a hole456through the sealed portion of the wellbore wall. The sampling-while drilling device320,320A,410may be further configured to inject an injection fluid into the formation370,420through the hole456, and determine a saturation of the injection fluid in the formation by measuring a property of the formation proximate the hole456while maintaining the sealed portion of the wellbore wall.

Referring toFIG. 2A, the wellbore311may be drilled through subsurface formations by rotary drilling in a manner that is well known in the art. However, the present disclosure also contemplates others examples used in connection with directional drilling apparatus and methods.

A drill string312may be suspended within the wellbore311and may include a bottom hole assembly (BHA)300proximate the lower end thereof. The BHA300may include a drill bit305at its lower end. It should be noted that in some implementations, the drill bit305may be omitted and the bottom hole assembly300may be conveyed via tubing or pipe. The surface portion of the well site system may include a platform and derrick assembly310positioned over the wellbore311, the assembly310including a rotary table316, a kelly317, a hook318and a rotary swivel319. The drill string312may be rotated by the rotary table316, which is itself operated by well known means not shown in the drawing. The rotary table316may engage the kelly317at the upper end of the drill string312. As is well known, a top drive system (not shown) could alternatively be used instead of the kelly317and rotary table316to rotate the drill string312from the surface. The drill string312may be suspended from the hook318. The hook318may be attached to a traveling block (not shown) through the kelly317and the rotary swivel319, which may permit rotation of the drill string312relative to the hook318.

In the example ofFIG. 2A, the surface system may include drilling fluid (or mud)326stored in a tank or pit327formed at the well site. A pump329may deliver the drilling fluid326to the interior of the drill string312via a port in the swivel319, causing the drilling fluid326to flow downwardly through the drill string312as indicated by the directional arrow308. The drilling fluid326may exit the drill string312via water courses, nozzles, or jets in the drill bit305, and then may circulate upwardly through the annulus region between the outside of the drill string and the wall of the wellbore, as indicated by the directional arrows309. The drilling fluid326may lubricate the drill bit305and may carry formation cuttings up to the surface, whereupon the drilling fluid326may be cleaned and returned to the pit327for recirculation.

The bottom hole assembly300may include a logging-while-drilling (LWD) module320, a measuring-while-drilling (MWD) module330, a rotary-steerable directional drilling system and hydraulically operated motor350, and the drill bit305. The LWD module320may be housed in a special type of drill collar, as is known in the art, and may contain a plurality of known and/or future-developed types of well logging instruments. It will also be understood that more than one LWD module may be employed, for example, as represented at320A (references, throughout, to a module at the position of LWD module320may alternatively mean a module at the position of LWD module320A as well). The LWD module320may include capabilities for measuring, processing, and storing information, as well as for communicating with the MWD330. In particular, the LWD module320may include a processor configured to implement one or more aspects of the methods described herein. In the present example, the LWD module320includes a testing-while-drilling device as will be further explained hereinafter.

The MWD module330may also be housed in a special type of drill collar, as is known in the art, and may contain one or more devices for measuring characteristics of the drill string and drill bit. The MWD module330may further include an apparatus (not shown) for generating electrical power for the downhole portion of the well site system. Such apparatus typically includes a turbine generator powered by the flow of the drilling fluid326, it being understood that other power and/or battery systems may be used while remaining within the scope of the present disclosure. In the present example, the MWD module330may include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device. Optionally, the MWD module330may further comprise an annular pressure sensor and/or a natural gamma ray sensor. The MWD module330may include capabilities for measuring, processing, and storing information, as well as for communicating with a logging and control unit360. For example, the MWD module330and the logging and control unit360may communicate information (uplinks and/or downlinks) via mud pulse telemetry (MPT) and/or wired drill pipe (WDP) telemetry. In some cases, the logging and control unit360may include a controller having an interface configured to receive commands from a surface operator. Thus, commands may be sent to one or more components of the BHA300, such as to the LWD module320.

A testing-while-drilling device410(e.g., similar to the LWD tool320inFIG. 2A) is shown inFIG. 2B. The testing-while-drilling device410may be provided with a stabilizer that may include one or more blades423configured to engage a wall of the wellbore411. The testing-while-drilling device410may be provided with a plurality of backup pistons481configured to assist in applying a force to push and/or move the testing-while-drilling device410against the wall of the wellbore411. The configuration of the blade423and/or the backup pistons481may be of a type described, for example, in U.S. Pat. No. 7,114,562, incorporated herein by reference. However, other types of blade or piston configurations may be used to implement the testing-while-drilling device410within the scope of the present disclosure. A probe assembly406may extend from the stabilizer blade423of the testing-while-drilling device410. The probe assembly406may be configured to selectively seal off or isolate selected portions of the wall of the wellbore411to fluidly couple to an adjacent formation420. The probe assembly406may include a perforating mechanism (not shown inFIGS. 2A and 2B) configured to form the hole456through the formation420beyond the wall of the wellbore411. A probe seal may be associated with the perforating mechanism and may be configured to substantially prevent movement of fluid into or out of the formation420other than through the hole456. Thus, the probe seal may be configured to fluidly couple components of the testing-while-drilling device410, such as pumps475and/or476, to the adjacent formation420via the hole456. Once the probe406fluidly couples to the adjacent formation420, various measurements may be conducted on the adjacent formation420. For example, a pressure parameter may be measured by performing a pretest.

The pump476may be used to draw subterranean formation fluid421from the formation420into the testing-while-drilling device410via the hole456. The fluid may thereafter be expelled through a port into the wellbore, or it may be sent to one or more fluid collecting chambers disposed in a sample carrier module492, which may receive and retain the formation fluid for subsequent testing at another component, the surface or a testing facility. Alternatively, the fluid sample may segregate in the sample carrier module492. One or more segregated portions of the sampled fluid may be used as an injection fluid, as described above.

The testing-while-drilling device410may also be used to discharge injection fluid into the formation420, for example, by moving the injection fluid from one or more fluid collecting chambers disposed in an injection fluid carrier module490using for example the pump475. The injection fluid may be moved from the one or more fluid collecting chambers by applying hydrostatic pressure from within the wellbore to a sliding the piston disposed in the collecting chamber, in addition to or in substitution of using the pump475. While the testing-while-drilling device410is depicted as having pumps475and476, the testing-while-drilling device410may be provided with a single reversible pump.

In the illustrated example, the stabilizer blade423of the testing-while-drilling device410is provided with a plurality of sensors430,432disposed adjacent to a port of the probe assembly406. The sensors430,432may be configured to determine petrophysical parameters (e.g., saturation levels) of a portion of the formation420proximate the probe assembly406. For example, the sensors430and432may be configured to measure electric resistivity, dielectric constant, magnetic resonance relaxation time, nuclear radiation, and/or combinations thereof.

The testing-while-drilling device410may include a fluid sensing unit470through which the obtained fluid samples and/or injected fluids may flow, and which may be configured to measure properties of the flowing fluid. For example, the fluid sensing unit470may be of a type described in relation to the fluid sensing unit220depicted inFIG. 2. It should be appreciated that the fluid sensing unit470may include any combination of conventional and/or future-developed sensors within the scope of the present disclosure.

A downhole control system480may be configured to control the operations of the testing-while-drilling device410. For example, the downhole control system480may be configured to control the extraction of fluid samples from the formation420and/or the injection of fluids into the formation420, for example, via the pumping rate of the pumps475and/or476. The downhole control system480may be further configured to control the forming of the hole456.

The downhole control system480may be further configured to analyze and/or process data obtained, for example, from downhole sensors disposed in the fluid sensing unit470or from the sensors430, store measurement or processed data, and/or communicate measurement or processed data to another component and/or the surface (e.g., to the logging and control unit360ofFIG. 2A) for subsequent analysis. For example, a formation dielectric constant and/or a formation magnetic resonance relaxation time distribution measured by at least one of the sensors430and432may be processed to determine a connate fluid saturation (e.g., water, gas and/or oil) and/or an injected fluid saturation. Additionally, a formation electric resistivity measured by at least one of the sensors430and432may be correlated with the determined saturations to determine a relationship between saturation and electric resistivity of the formation. Composition data measured with the fluid sensing unit470and flow rate induced by the pump475and/or476may be correlated with the determined saturations to determine effective permeability curves. The logging and control unit360(inFIG. 2A) and/or the downhole control system480may include a processor configured to implement one or more aspects of the methods described herein.

While the formation tester214ofFIG. 1, and/or the testing-while drilling device410ofFIG. 2Bare depicted with one probe assembly, multiple probes may be provided with the formation tester214and/or the testing-while drilling device410within the scope of the present disclosure. For example, probes of different inlet sizes, shapes (e.g., elongated inlets) or counts, seal shapes or counts, may be provided.

Turning toFIG. 3, a formation evaluation apparatus500according to one or more aspects of the present application is shown. The formation evaluation apparatus500may be used to implement a portion of the formation tester214ofFIG. 1and/or the testing-while-drilling device410ofFIG. 2B. The formation evaluation apparatus500may be configured to seal a portion514of a wall512of a wellbore506penetrating a formation505, form a hole510through the sealed portion514of the wellbore wall512, and measure one or more petrophysical properties of the formation505proximate the hole510while maintaining the sealed portion514of the wellbore wall.

For example, the formation evaluation apparatus500may include a housing501configured for conveyance within the wellbore506. The formation evaluation apparatus500may be urged against the side of the wellbore wall512opposite a probe assembly (also referred to simply as the “probe”)507, for example, by actuating anchor pistons511. A piston-type or other actuator516may be used for moving the probe507between a retracted position (not shown inFIG. 3) during conveyance of the housing501and a deployed position (shown inFIG. 3) for sealing the region514of the wellbore wall512. Thus, the probe507may be carried by the housing501and may be configured, when urged against the wellbore wall512, to seal the region514of the wellbore wall512. The actuator516may be connected to a probe plate526for moving the probe plate526between the retracted and deployed positions, and a controllable power source (such as a hydraulic system) for extending and retracting the pistons (not shown separately). The probe507may comprise a seal524, such as an elastomer ring or similar sealing element, mounted to the probe plate526to create the seal between the wellbore wall512and the region514.

A drill may be rotated and moved longitudinally by a motor assembly (not shown). The drill may comprise a flexible drilling shaft509having a drill bit508at an end thereof. An example of the motor assembly may be found in U.S. Pat. No. 5,692,565, the disclosure of which is incorporated herein by reference. The drill may be used for penetrating the formation505proximate the sealed-off region514. For example, the flexible shaft509may be guided through a suitably shaped tube520and may convey rotational and translational power to the drill bit508from the motor assembly. The action of the drill may result in creating the lateral bore or hole510extending partially through the formation505away from the wellbore wall512.

The formation evaluation apparatus500further includes a flow line518extending from a fluid reservoir through a portion of the formation evaluation apparatus500and in fluid communication with the formation505, through the tube520and out through an opening522of the packer524. The fluid reservoir may be or comprise, for example, one or more fluid collecting chambers disposed in the injection fluid carrier modules226,228ofFIG. 1and/or the injection fluid carrier module490ofFIG. 2A. A pump (such as the pump221ofFIG. 1and/or the pump475ofFIG. 2B) may be provided in fluid communication with the formation505via the tube520and the flow line518. The pump may be used for pumping fluid from the reservoir into the formation505when desired. A sensor may be associated with the pump so that a volume of fluid pumped into the formation505may be monitored. However, other types of sensors configured to monitor the volume of fluid displaced into the formation505may be used within the scope of the present disclosure. Additionally, a fluid sensing unit (such as the fluid sensing unit220ofFIG. 1and/or the fluid sensing unit470ofFIG. 2B) may be carried within the housing501for measuring pressure and viscosity of the fluid within the flow line518, among other fluid properties.

The formation evaluation apparatus500further includes a flow line517extending through a portion of the tool body. The flow line517may be in fluid communication with an opening508in the shaft509. A pump (such as the pump231ofFIG. 1and/or the pump476ofFIG. 2B) may be provided in fluid communication with the formation505via the flow line517. The pump may be used for pumping fluid from the formation505when desired. A fluid sensing unit (such as the fluid sensing unit220ofFIG. 1and/or the fluid sensing unit470ofFIG. 2B) may be carried within the housing501for measuring composition data, viscosity, and/or pressure of the fluid within the flow line517, among other fluid properties.

Sensors530and532may be provided on the probe plate526adjacent to the seal524and may be configured to measure one or more petrophysical properties (e.g., saturation levels) of the formation505proximate the hole510while maintaining the sealed portion514of the wellbore wall. For example, the sensors530and532may be extended from the housing501and pressed against the mud cake lining the wellbore wall512. Pressing the sensors530and532against the wellbore wall512may minimize the need for correcting the measurements performed by the sensors for wellbore fluid effects. The sensors530and532may be mounted on a mechanically compliant system (not shown), such as a hydraulic cushion and/or springs. The compliant system may be configured to deform to facilitate the compression of the seal524and therefore insure a suitable hydraulic seal between the wellbore506and the sealed portion514. The sensors532and534may be further provided with sharp edges or points534configured to penetrate the mud cake and make contact with the formation505. The edges or points534may minimize the need for correcting the measurements performed by the sensors for mud cake effects.

The sensors530and/or532may be selected from the group consisting of electric resistivity sensors, dielectric constant sensors, magnetic resonance sensors, nuclear radiation sensors, and combinations thereof. For example, the sensors530and/or532may include electrodes for current injection into the formation or current return from the formation. Such sensors may comprise one or more arrays of electrodes provided to measure electric resistivity values associated with each of a plurality of sensing volumes of the formation proximate the hole and defined by electrode spacings or inter-distances. Guard electrodes may also be provided to define the sensing volumes away from the wellbore wall512. Alternatively, or additionally, the sensors530and/or532may include coils suitable for measuring electrical conductivity in the formation by electromagnetic induction and/or electromagnetic propagation. The sensors530and/or532may include permanent magnets and coils configured to perform nuclear magnetic resonance (NMR) analysis of the formation and fluids therein. The sensors530and/or532may include nuclear radiation detectors, such as a scintillation counter coupled to a multichannel pulse height analyzer, and may be configured to detect radiation emanating from the formation in response to a nuclear radiation source, such as a pulsed neutron source arranged to emit bursts of high energy neutrons into the formation. The radiation detected may include gamma rays resulting from interaction of the high energy neutrons with atomic nuclei in the formation. Oxygen activation and related spectra may be detected to derive a measurement related to the amount of the formation pore space that may be occupied by water, and the part that is occupied by hydrocarbons.

While the formation evaluation apparatus500is shown with flow lines517and518, only one flow line may be provided. Further, while the flow line518may be used to inject fluid into the formation505and the flow line517may be used to withdraw fluid from the formation505, both flow lines may be used to inject and/or withdraw fluid. For examples, contaminated fluid may be withdrawn via the flow518from a zone504contaminated by mud filtrate, while pristine fluid may be withdrawn via the flow line517from a connate zone503. Additional flow lines and/or seals may be provided on the shaft509, for example as described in U.S. Pat. No. 7,347,262, incorporated herein by reference.

Turning toFIGS. 4A to 4D, resistivity sensors according to one or more aspects of the present application are shown. The resistivity sensors may be associated with probe assemblies557a,557b, or557c, and may be used to implement a portion of the formation evaluation apparatus500ofFIG. 3. The probe assemblies ofFIGS. 4A to 4Dmay be configured to seal a portion of a wall562of a wellbore penetrating a formation555, form a hole560through the sealed portion of the wellbore wall by extending a bit558a,558b, or558cinto the formation555through the sealed portion, introduce an electrical current into the formation from the bit, and measure an electrical current of the formation while maintaining the sealed portion of the wellbore wall. Electrical current measurements may be performed while/after drilling the hole560, and/or before, during and after injecting fluid into the formation555or sampling fluid from the formation555. The current measurements may be used to determine a resistivity of the formation555. The resistivity of the formation555may further be related to the relative saturation of conductive and non-conductive fluids in the pore spaces of the formations, such as by relationships well known in the art.

Referring toFIG. 4A, electrical current may be introduced into the formation by implementing a transformer, in which the primary side comprises a transmitter toroid565, and the secondary side comprises a single conductive loop including a flexible shaft559a, the bit558a, a formation path570a, and a return path571a. For example, the transmitter toroid565may comprise turns of wire wound around a toroidal core and disposed in an insulating housing567. Electrical current may be introduced into the formation by passing an alternating driving current through the transmitter toroid565. The driving current may induce a magnetic field in the toroidal core. The magnetic field may induce an electrical field (that is, a voltage differential related to the driving current) in the flexible shaft559a. The electrical field may generate an electrical current in a conductive portion of the flexible shaft. The generated current may exit the flexible shaft and/or the bit558a, perpendicularly to the conductive surfaces thereof. The generated current may be introduced into the formation555from the bit558aand/or the shaft559a, for example when the fluid present in the hole560is sufficiently conductive and/or when the bit558aelectrically couples with the formation555. The current along the formation path570amay be forced to return at an outer diameter electrode572aof the probe assembly557aby providing an insulating material573aconfigured to cover an inner surface of the probe assembly557a. The single conductive loop may be completed through the return path571a(e.g., an insulated wire and/or a portion of the body of the probe assembly557a). The flexible shaft559amay be configured to provide adequate electrical contact with the return path571ato complete the conductive loop.

The driving current magnitude through the transmitter toroid565may be measured. The driving current magnitude is related to voltage differential in the conductive portion of the flexible shaft559a. A magnitude of the current generated in the conductive portion of the flexible shaft559amay be measured using a measurement toroid566coupled to an amperemeter (not shown). The generated current magnitude may depend on the geometry of the probe assembly557a, the resistivities of the formation555, the mud cake575, the fluid present in the hole560, the resistance of the return path571a, and the resistance of the flexible shaft559a. The generated current magnitude may originate from a combination of current paths flowing from the shaft559aand/or the bit558ato the electrode572a. However, appropriate simplifications or other modifications may be introduced to determine the resistivity of the formation555. For example, the resistance of the return path571aand/or the resistance of the flexible shaft559amay be known from calibration measurements, such as may be performed in a surface laboratory. The resistance of the fluid present in the hole560may also be known, such as from measurements performed in a surface laboratory and/or performed in situ using a fluid sensing unit (such as the fluid sensing unit220ofFIG. 1and/or the fluid sensing unit470ofFIG. 2B). The resistivities of the formation555and the mud cake575may be determined from multiple measurements associated with a plurality of sensing volumes. For example, the effective resistance between the shaft559aand/or the bit558aand the electrode572amay be determined from driving current and generated current measurements performed at multiple extensional positions of the bit558ain the hole560by moving the bit to different position inside the hole. The mud cake resistivity may be estimated from a measurement of the effective resistance performed with the bit in a recessed position in the hole. The formation resistivity may be determined from the estimated mud cake resistivity and a measurement of the effective resistance performed with the bit in an extended position in the hole. The resistivities of the formation555and the mud cake575may be determined by inversion techniques using measurements performed at a plurality of positions of the bit558awithin the hole560.

The resistivity sensor shown inFIG. 4Amay be limited in its accuracy due to the tendency for current to travel along a conductive fluid path in the hole560and/or along the mud cake575before reaching the electrode572a. The foregoing may be alleviated in part by use of a current focusing technique configured to keep the voltage differential along the mud cake575substantially at zero. For example, the electrode572amay be connected to a voltage controller580configured to maintain substantially zero voltage differential between the electrode572aand a focusing electrode581. Thus, the voltage differential along the mud cake575may be minimized, thereby forcing the formation current path570aaway from the wellbore wall562and deeper into the formation555. Alternatively, or additionally, the outer surface of the flexible shaft559amay be coated with an insulating material585configured to withstand the mechanical abrasion of the drilling operation. The insulating material585may comprise a diamond-like carbon (“DLC”) coating deposited on the shaft559ausing a chemical vapor deposition (CVD) process. By insulating the exterior of the shaft559a, the current generated in the conductive portion of the shaft may be permitted to only exit the shaft at the bit558a, which may provide a laterally deeper measurement. Insulating the flexible shaft may also facilitate locating the transmitter toroid565and/or the measurement toroid565further away from the probe assembly557abecause the insulating outer surface585may prevent a short circuit between the shaft and the body of the probe assembly557a.

Referring toFIG. 4B, electrical current may be introduced into the formation by coupling a conductive portion of a flexible shaft559band/or the bit558bto a current driver586(e.g., a power amplifier) via a collector587. The collector587may include a slip ring583(e.g., a rotating electrical contact) disposed in an insulating fluid584(e.g., hydraulic oil). The collector587may be configured to insure one or more electrical contacts with the conductive portion of the flexible shaft559bwhile allowing the flexible shaft559bto rotate and/or translate therethrough for actuating the bit558a. The flexible shaft559bmay be coated as previously described, or may alternatively be provided with one or more insulated electrical conductors therethrough connected to the bit558b. Thus, electrical current may be introduced into the formation555from the bit558b. The current may flow in the formation along a formation path570btowards one or more cylindrical electrodes572bdisposed in an insulating material573bconfigured to cover a surface of the probe assembly557b. The electrode572bis electrically coupled to the current driver586via a return path571b(e.g., an insulated wire and/or a portion of the body of the probe assembly557b).

In the electrical sensor ofFIG. 4B, the flexible shaft559bmay be electrically insulated except at the collector587and at the bit558b. Such isolation may facilitate the control and/or the measurement of the current introduced in the formation555by the current driver586. For example, voltage differential and current across the current driver586may be measured by electronics coupled to the driver. The measured voltage differential and current may be used to determine the formation and mud cake resistivities, among others, for example as described in relation toFIG. 4A.

Another resistivity sensor according to one or more aspects of the present disclosure is shown schematically inFIG. 4Cin frontal view andFIG. 4Din side view. The resistivity sensor ofFIGS. 4C and 4Dmay include a current injection electrode595, a focusing or “bucking” electrode590, a sensing electrode591, and a pair of voltage monitoring electrodes592aand592bassociated with the probe assembly557c, the flexible shaft559cand the bit558c. Placing the electrodes in a configuration as shown in or similar toFIGS. 4C and 4Dmay provide an enhanced sensitivity of the resistivity sensor to the resistivity in a region away from the wellbore wall562and/or a smaller sensitivity of the resistivity sensor to the resistivity in a region proximate the wellbore wall562. Thus, the contribution to the sensor measurements of the mud cake resistivity and/or the fluid present in the hole560may be minimized.

The current injection electrode595may be operatively coupled to the transmitter toroid565ofFIG. 4Avia the shaft559c. Alternatively, the current injection electrode595may be electrically coupled to the current driver586ofFIG. 4B. Thus, an injection current IA0of known amplitude may be introduced into the formation from the current injection electrode595.

The sensing electrode591may be configured to measure the voltage of the formation proximate the current injection electrode595. For example, the sensing electrode591may be disposed on the drill shaft559cadjacent the current injection electrode595.

The focusing or bucking electrode590may be operatively coupled to the monitoring electrodes592aand592bvia a voltage controller (e.g., similar to the voltage controller580ofFIG. 4A). The voltage controller may be configured to introduce and optionally measure a focusing or bucking current IA1in the mud cake575and/or the formation555so that the voltage differential between the monitoring electrodes592aand592bmay be maintained at substantially zero voltage differential.

The monitoring electrodes592aand592bmay further be coupled to a return path (not shown) to flexible shaft559cbehind the transmitter toroid565ofFIG. 4Aor the current driver586ofFIG. 4B. The probe assembly557cmay be provided with an insulating material573cconfigured to cover a surface of the probe assembly557c. Thus, the monitoring electrodes592aand592bmay provide an exclusive return path for the injection current IA0and the focusing or bucking current IA1.

A plurality of measurements of the injection current IA0and corresponding voltage differentials between the sensing electrode591and the pair of monitoring electrodes592aand592bmay be performed for different positions of the bit558c, up to the maximal extension of the bit558cinto the formation555. For example, a first measurement may be performed when the bit558cand/or the sensing electrode591is exposed to the mud cake575. A second measurement may be performed when the bit558cand/or the sensing electrode591is exposed to the formation555, that is, when the bit558cand/or the sensing electrode591is at least partially extended in the hole560. Such plurality of measurements may be used to determine the mud cake resistivity and thickness and the formation resistivity, among other characteristics. In some cases, appropriate corrections for the fluid resistivity may be introduced.

The resistivity sensors shown inFIGS. 4A-4Dmay be modified to measure the formation resistivity in a plurality of circumferential sensing volumes or quadrants (e.g., top, bottom, left and right quadrants) around the hole560and/or the bit (e.g., the bit558c). It should be appreciated, however, that the foregoing references to top, bottom, vertical and horizontal quadrants are for illustration purpose and are not intended in any way to limit the scope of the present disclosure. For example, the voltage monitoring electrodes (e.g., the monitoring electrodes592aand592b) may be segmented into a plurality of electrodes electrically insulated from each other and spanning each of a plurality of quadrants. A focusing or bucking current IA1may be provided between the focusing or bucking electrode (e.g., the focusing or bucking electrode590) and a pair of monitoring electrode segments in one of the plurality of quadrants, while other monitoring electrode segments are in open circuit. The operation may be repeated for others of the plurality of quadrants. Thus, injection current values and associated voltage differential values between the bit (e.g., measured with the sensing electrode591) and the pair of monitoring electrodes segments may be measured. The measured injection currents and voltage differentials may be used to determine formation resistivity values corresponding to different quadrants of the formation (or a resistivity image of the formation) and, in turn, fluid saturation values corresponding to different quadrants of the formation (or a saturation image).

The resistivity and/or saturation image may be used to quantify the local heterogeneity and/or anisotropy of the formation. For example, an injected fluid saturation larger in the left and right quadrants than in the top and bottom quadrants may indicate that the formation has a larger permeability in the horizontal plane than in the vertical plane. Conversely, an injected fluid saturation larger in the top and bottom quadrants than in the left and right quadrants may indicate that the formation has a lower permeability in the horizontal plane than in the vertical plane.

In the example shown inFIGS. 4C and 4D, the current injection electrode595comprises at least a portion of the bit558c. However, the current injection electrode595may be implemented separate from and extendable with the bit558cwithin the scope of the present disclosure. Further, the sensing electrode591may be omitted within the scope of the present disclosure. For example, the voltage differential between the sensing electrode591and the pair of monitoring electrodes592aand592bmay be estimated from the driving current of the transmitter toroid565(inFIG. 4A) and/or from the voltage differential across the current driver586(inFIG. 4B). Also, the sensing electrode591may be used to measure the spontaneous potential with respect to a common reference point or naturally occurring voltage, in addition to or in place of the resistivity measurements. Still further, other arrangements of focusing or bucking electrodes may be used within the scope of the present disclosure, and may be derived from arrangements known by the term laterolog 3 (“LL3”), laterolog 7 (“LL7”), laterolog 8 (“LL8”), or micro-spherically focused log (“MSFL”), among others.

Turning toFIGS. 5A-5H, magnetic resonance sensors according to one or more aspects of the present application are shown. The magnetic resonance sensors may be associated with probe assemblies600a,600b,600c, or600dand may be used to implement a portion of the formation evaluation apparatus500ofFIG. 3. The probe assemblies ofFIGS. 5A-5Hmay be configured to seal a portion of a wall of a wellbore penetrating a formation, form a hole through the sealed portion of the wellbore wall by extending a bit601a,601b,601c, or601dinto the formation through the sealed portion, induce spin precession in a portion of the formation located around the formed hole, and measure spin echoes of the portion of the formation while maintaining the sealed portion of the wellbore wall. Magnetic resonance measurements may be performed during or after drilling the hole, and/or before, during and after injecting fluid into the formation and/or sampling fluid from the formation. The magnetic resonance measurements may be used to determine a porosity of the formation, relative saturations of different fluids in the pore space of the formation and/or fluid flow rates in the formation.

The probe assemblies600a,600b,600cor600dmay include a magnetic steel plate, respectively604a,604b,604c, or604d. Actuators (such as the actuator516ofFIG. 3) may be connected to the plate for moving the plate between retracted and deployed positions. An insulating body603a,603b,603c, or603dmay be attached to the magnetic steel plate. The insulating body may be made with poly-ether-ether-ketone (PEEK), or similar material. The insulating body may comprise permanent magnets or electromagnets and magnetic antennas configured to perform nuclear magnetic resonance measurements. The insulating body may be configured to facilitate the transmission of the magnetic field generated by the magnets and/or the antennas to the formation. The magnetic steel plate may be configured to reflect the magnetic field generated by the magnets and/or the antennas towards the formation and away from the wellbore. Thus, relatively high magnetic fields may be generated into the formation, thereby providing sensing volumes at relatively large lateral depth in the formation and/or relatively large measurement signals.

In accordance with one or more aspects of the present disclosure, a nuclear magnetic resonance sensor associated with the probe assembly600ais schematically shown inFIG. 5Ain frontal view andFIG. 5Bin side view. The nuclear magnetic resonance sensor shown inFIGS. 5A and 5Bmay include permanent magnets or electromagnets605,606,607and608whose poles may be aligned to create a static magnetic field609having a selected spatial distribution in the formation. For example, the permanent magnets or electromagnets605,606,607and608may be configured to provide a transverse orientation of the static magnetic field609in the formation relative to the hole to be formed by the bit601a. Also, the permanent magnets or electromagnets605,606,607and608may be configured to provide a decreasing magnitude of the static magnetic field609as a function of the lateral depth into the formation. It should be appreciated that while four permanent magnets or electromagnets are shown, the permanent magnets or electromagnets may be divided, combined or connected to form any number of magnets.

Three antennas610,611and612are shown inFIGS. 5A and 5B. The antennas610,611and612may be coupled to electronics and configured to generate a pulsed radio frequency (“RF”) magnetic field having selected spatial distribution for inducing nuclear magnetic resonance phenomena and for performing nuclear magnetic resonance measurements. For example, the antenna610and/or612may be configured to induce nuclear spin precession in a portion of the formation located around the hole formed with the bit601a, and measure spin echoes of the portion of the formation while maintaining the sealed portion of the wellbore wall using a seal602a(e.g., an elastomeric ring). In addition, the antenna611may be configured to induce spin precession in a portion of the formation corresponding to the location of the hole to be formed with the bit601a, and measure spin echoes of said portion. Thus, the antenna611may be used to measure magnetic resonance properties of the formation prior to forming the hole with the bit601a. The antenna611may also be used to measure magnetic resonance properties of the fluid present in the hole during sampling and/or injection after forming the hole with the bit601a. Further, sensing volumes (e.g., sensing shells) having different lateral depths into the formation may be investigated by changing the frequency of the RF magnetic field generated by the antennas610,611and/or612. The sensing volumes may depend on the spatial distribution of the static magnetic field609in the formation. For example, the sensing volumes may correspond to regions in the formation where the static field609has a particular amplitude.

The radio frequency (“RF”) pulse may include spin echo sequences such as Carr-Purcell-Meiboom-Gill (“CPMG”) and modifications thereof to obtain quantities such as transverse relaxation time and distributions thereof, longitudinal relaxation time and distributions thereof, and diffusion constant. Various petrophysical parameters may be derived therefrom, such as formation porosity, saturation levels of one or more fluids in the pore space, and/or fluid flow rates in the formation and/or in the formed hole, among others. For example, residual oil saturations resulting from the injection of various fluids may be used to evaluate the efficacy of an enhanced oil recovery treatment by injection. Further, flow rate measurements may be performed while injecting fluid into the formation. Because the injected fluid may have a known NMR response, measurements of the flow of the injected fluid may be facilitated. In addition, relative permeabilities of fluids other than the formation fluid (such as injected fluids) may be measured using NMR techniques within the scope of the present disclosure.

Another magnetic resonance sensor according to one or more aspects of the present disclosure is schematically shown inFIG. 5Cin frontal view andFIG. 5Din side view. The nuclear magnetic resonance sensor shown inFIGS. 5C and 5Dis associated with the probe assembly600b. The probe assembly600bmay include permanent magnets or electromagnets615,616,617, and618configured in a similar manner as the permanent magnets or electromagnets605,606,607and608ofFIGS. 5A and 5B. The probe assembly600bmay be provided with a two-dimensional array614of antennas that may be configured to induce spin precession in a plurality of different sensing volumes of the formation located around the hole formed with the bit601b, and measure spin echoes in the sensing volumes while maintaining the sealed portion of the wellbore wall using a seal602b. For example, each of the plurality of sensing volumes may be indexed by a corresponding one antenna of the two-dimensional array614. Further, lateral depths into the formation of the sensing volumes may be selectively increased or decreased by changing the frequency of the RF magnetic field generated by the antennas of the two-dimensional array614. Thus, a three dimensional image of a formation property may be constructed.

Thus, by measuring a spatially resolved NMR image as fluid flows into or out of the formation from the probe assembly600b, formation matrix heterogeneity and/or features such as fractures, among other properties, may be determined. Further, preferential flow directions of a fluid injected to displace the connate oil in the formation may be determined. For example, by comparing vertical versus horizontal flow rate, among other directional flow rates, a permeability anisotropy of the formation matrix may be determined.

Another magnetic resonance sensor according to one or more aspects of the present disclosure is schematically shown inFIG. 5Ein frontal view andFIG. 5Fin side view. The nuclear magnetic resonance sensor shown inFIGS. 5E and 5Fis associated with the probe assembly600c. The probe assembly600cmay include permanent magnets or electromagnets620,621,622and623whose poles may be aligned to create a static magnetic field625having a selected spatial distribution in the formation. For example, the permanent magnets or electromagnets620,621,622and623may be configured to provide an orientation of the static magnetic field609in the formation aligned with the longitudinal axis of the hole to be formed by the bit601c. Also, the permanent magnets or electromagnets620,621,622and623may be configured to provide a “saddle point” in the static magnetic field625. A saddle point distribution may provide a substantially homogeneous static magnetic field at a particular lateral depth into the formation. A homogeneous static magnetic field distribution may increase the strength of the measured signals. It should be appreciated that while four permanent magnets or electromagnets are shown, the permanent magnets or electromagnets may be divided, combined or connected to form any number of magnets and/or saddle point static magnetic fields625.

Three antennas626,627and628are shown inFIGS. 5E and 5F. The antenna626and/or628may be configured to induce nuclear spin precession in a portion of the formation located around the hole formed with the bit601c, and measure spin echoes of the portion of the formation while maintaining the sealed portion of the wellbore wall using a seal602c. In addition, the antenna627may be configured to induce spin precession in a portion of the formation relatively closer to the location of the hole to be formed with the bit601c, and measure spin echoes of said portion. Thus, the antenna627may be used to measure magnetic resonance properties of the formation prior to forming the hole with the bit601c.

As shown, the antennas626and628may be implemented with “Figure-8” coils. Figure-8 coils may produce and/or detect a magnetic field that is parallel to the surface of the coil at the “crossover” of the “8”, and thus perpendicular to the static magnetic field625in the formation. The antenna627may be implemented with a “double Figure-8” coil disposed around the bit601c. The double Figure-8 coil may produce and/or detect a magnetic field that is parallel to the surface of the coil in two zones corresponding to the two crossovers.

Another magnetic resonance sensor according to one or more aspects of the present disclosure is schematically shown inFIG. 5Gin frontal view andFIG. 5Hin side view. The nuclear magnetic resonance sensor shown inFIGS. 5G and 5His associated with the probe assembly600d. The probe assembly600dmay include permanent magnets or electromagnets626,627,628, and629configured in a similar manner as the permanent magnets or electromagnets620,621,622and623ofFIGS. 5E and 5F. The probe assembly600dmay be provided with antennas630,631and632configured in a similar manner as antennas626,627, and628ofFIGS. 5E and 5F. In some examples, for example in NMR formation imaging, it may be desirable to have the capability to superimpose a gradient magnetic field onto the static magnetic field. In the example ofFIGS. 5G and 5H, gradient coils635may be configured to generate the gradient field in the formation aligned with the longitudinal axis of the hole to be formed by the bit601d. The gradient field may be used to selectively increase or decrease the magnitude of the static magnetic field625by changing the current in the gradient coils635. The spatial sensitivity of the NMR measurement, for example, the lateral depths into the formation of the sensing volumes associated with a given operating frequency of the antennas630,631, and/or632, may be varied. Thus, a three dimensional image of a formation property may be constructed. Further, the gradient magnetic field may be used to perform flow rate measurements in the formation, for example, to construct a three dimensional image of the flow rate distribution in the formation.

Turning toFIGS. 6A-6D, electromagnetic sensors according to one or more aspects of the present application are shown. The electromagnetic sensors may be associated with the probe assemblies650and/or700and may be used to implement a portion of the formation evaluation apparatus500ofFIG. 3. The probe assemblies ofFIGS. 6A-6Dmay be configured to seal a portion of a wall of a wellbore penetrating a formation, form a hole through the sealed portion of the wellbore wall by extending a bit651and/or701into the formation through the sealed portion, emit an electromagnetic wave in a portion of the formation using a transmitter coil aligned with a longitudinal axis of the formed hole, and measure the electromagnetic wave using at least one receiver coil radially from the longitudinal axis of the formed hole while maintaining the sealed portion of the wellbore wall. Electromagnetic measurements may be performed while and/or after drilling the hole, and/or before, during and/or after injecting fluid into the formation and/or sampling fluid from the formation. At frequencies in the kilohertz range, the amplitude and/or phase of the measured electromagnetic wave may be largely affected by the resistivity of the formation. As is known in the art, the type of fluid in the formation pores (e.g., water or hydrocarbon) may affect the formation resistivity. Thus, the electromagnetic measurements may be used to determine relative saturations of different fluids in the pore space of the formation, among others.

The probe assemblies650, and/or700may include a magnetic steel plate, respectively652,702. Actuators (such as the actuator516ofFIG. 3) may be connected to the plate for moving plate between retracted and deployed positions. An insulating body653and/or703may be attached to the magnetic steel plate. The insulating body may be made with PEEK or similar material.

An electromagnetic transmitter antenna660and/or710may be provided in the probe assemblies650and700respectively. The transmitter antenna may be implemented with a uni-axial antenna and may include one coil (as shown inFIGS. 6C and 6D). The transmitter antenna may also be implemented with a tri-axial antenna and may include a plurality of coils (as shown inFIGS. 6A and 6B). The electromagnetic transmitter antenna660and710may be coupled to electronics (not shown) and may be configured to emit an electromagnetic wave in a portion of the formation. InFIGS. 6A-6D, the transmitter antenna may be aligned with a longitudinal axis of a hole to be formed with the bits651and/or701. When the transmitter antenna is aligned with the longitudinal axis of the formed hole, the interpretation of electromagnetic measurements may be facilitated. Injection fluid (e.g., conductive injection fluid) in and/or around the formed hole and formation (e.g., hydrocarbon bearing formation) may exhibit a large resistivity contrast. The injection front may be symmetrical around the formed hole. Models describing the electromagnetic wave generated by a transmitter antenna aligned with the symmetry axis of the formed hole and/or of the injection front are known in the art, and may be used to interpret the electromagnetic measurements described below.

One or more electromagnetic receiver antennas761a-761dand/or711a-711dmay also be provided in the probe assemblies650and/or700. The receiver antennas may be implemented with uni-axial antennas and may include one coil (as shown inFIGS. 6C and 6D). The receiver antennas may also be implemented with tri-axial antennas and may include a plurality of coils (as shown inFIGS. 6A and 6B). The receiver antennas may be configured to measure the electromagnetic wave. For example, the voltage of one of the receiver antennas may be interrogated to determine a change in phase and/or a reduction in amplitude of the electromagnetic wave with respect to another of the receiver antennas and/or the transmitter antenna. InFIGS. 6A-6D, the receiver antennas may be spaced radially from the longitudinal axis of the formed hole.

An electromagnetic induction sensor according to one or more aspects of the present disclosure is schematically shown inFIG. 6Ain frontal view andFIG. 6Bin side view. The frequency of the driving voltage of the transmitter antenna660may be lower than 100 kHz (for example between 10 kHz and 50 kHz). The distance between the transmitter antenna660and the middle point between the receiver antennas pairs <661a,661b> and/or <661c,661d> may be around six inches. The distance between the receiver antennas661aand661bmay be around one inch. The distance between the receiver antennas661cand661dmay also be around one inch. The number of wire turns in the coils of the transmitter antenna660and in the coils of the receiver antennas661aand661d(i.e., the antennas most distant from the transmitter antenna) may be around10. The winding direction in the coils of the bucking receiver antennas661band661c(i.e., the antennas less distant from the transmitter antenna) may be reversed from the winding direction in the coils of the receiver antennas661aand661d. The number of wire turns in the coils of the bucking receiver antennas661band661cmay be adjusted to increase the sensitivity of the measurement in a desired region, for example away from the insulating body653. All coils may have a diameter of around two centimeters. All antennas may be implemented with tri-axial antennas to enable selective orientation of the electromagnetic wave.

An electromagnetic propagation sensor according to one or more aspects of the present disclosure is schematically shown inFIG. 6Cin frontal view andFIG. 6Din side view. In the example shown, the frequency of the driving voltage of the transmitter antenna710is higher than 100 kHz (for example between 100 kHz and 500 kHz). The distance between the transmitter antenna710and the middle point between the receiver antennas pairs <711a,711b> and/or <711c,711d> may around six inches. The distance between the receiver antennas711aand711bmay be around one inch. The distance between the receiver antennas711cand711dmay also be around one inch. The number of turns in all coils may be at most two. All antennas may be implemented with uni-axial antennas having dipole moments perpendicular to the plane of the probe assembly700. However, other uni-axial antenna orientations are possible.

It should be appreciated that two dimensional arrays of receiver antennas may be implemented in the probe assemblies650and/or700. By providing a two dimensional array of receiver antennas, for example similar to the antenna array614shown inFIGS. 5C and 5D, different sensing volumes may be investigated in the formation. For example, the two dimensional array of receiver antennas may provide measurement configurations having different spacings between transmitter and receiver(s). Thus, measurements indicative of the formation resistivity at various lateral depths may be performed. These measurements may be inverted and the effect of the filtrate invasion on the measured resistivity may be eliminated. A resistivity value representative of the injected zone beyond the zone invaded by drilling fluid may be determined. Further, a saturation level (e.g., a residual oil saturation level and/or an injection fluid saturation level) representative of the injected zone beyond the zone invaded by drilling fluid may also be determined. Furthermore, a front between immiscible fluids (e.g., between the injected fluid and the connate formation fluid) may be tracked as the volume of the injected fluid in (or out by reversing the pump) the formation is altered. Saturation changes with time as a function of injection pressure may be used to determine effective permeabilities of connate formation fluid and/or injected fluid in the formation.

Turning toFIG. 7, a dielectric sensor according to one or more aspects of the present application is shown. The dielectric sensor may be associated with the probe assembly670and may be used to implement a portion of the formation evaluation apparatus500ofFIG. 3. The probe assembly ofFIG. 7may be configured to seal a portion of a wall of a wellbore penetrating a formation, form a hole through the sealed portion of the wellbore wall by extending a bit671into the formation through the sealed portion, and image the formation while maintaining the sealed portion of the wellbore wall. Formation electric permittivity measurements (or dielectric measurements) may be performed while and/or after drilling the hole, and/or before, during and/or after injecting fluid into the formation and/or sampling fluid from the formation. At high frequencies, for example, in the megahertz to gigahertz range, the amplitude and/or phase of electromagnetic waves may be largely affected by the formation electric permittivity (or dielectric constant of the formation). As is known in the art, formation electric permittivity has been shown to provide, in combination with a porosity measurement, a hydrocarbon and/or water saturation measurement which is independent of saturation and cementation exponents (i.e., Archie parameters) utilized with resistivity sensors.

A two dimensional array680of antennas, for example embedded in an insulating body672, may be implemented to determine a three dimensional permittivity image. By sequencing the antennas that are transmitting and/or receiving electromagnetic waves in the formation, measurements obtained with different transmitter/receiver spacings may be performed, among other effects of the measurement geometry. Also, different sensing volumes of the formation may be investigated. Thus, a three dimensional image of the hydrocarbon and/or water saturation levels in the formation may be constructed. A plurality of images may be constructed for a plurality of volumes of injected fluid discharged into and/or volume of fluid withdrawn from the formation.

Resistivity sensors such as shown inFIGS. 4A-4D, magnetic resonance sensors such as shown inFIGS. 5A-5H, electromagnetic sensors such as shown inFIGS. 6A-6D, and/or dielectric sensors such as shown inFIG. 7may be associated with a single probe assembly or pad. The sensor(s) may be configured to measure petrophysical parameters of similar sensing volumes of the formation. For example, a sensor combination proximate an injection and/or sampling port may permit the measurement of the porosity of the formation, the measurement of connate and/or injection fluids saturation levels in the formation, as well as the resistivity of the formation. Thus, a plurality of saturations levels (e.g., injected fluid saturation levels in the formation pores) corresponding to each one of a plurality of injected fluid volumes may be determined. Further, a plurality of resistivity values corresponding to each one of the plurality of injected fluid volumes may be also be determined. Still further, a relationship between the determined saturation and an electric resistivity of the formation may be determined, such as saturation and cementation exponents for Archie's equation. Examples of sensors that may be used to determine formation porosity include NMR sensors and nuclear radiation sensors, among others. Examples of sensors that may be used to determine saturation levels include NMR sensors and dielectric sensors, among others. Examples of sensors that may be used to determine formation resistivity include galvanic sensors, induction sensors, and propagation sensors, among others.

Turning toFIG. 8, a formation evaluation apparatus720according to one or more aspects of the present application is shown. The formation evaluation apparatus720may provide a sensor combination proximate an injection and/or sampling port. The sensors may be configured to perform porosity, saturation and/or resistivity measurements while maintaining the sealed portion514of the wellbore wall.

The apparatus720may include a pad721mounted on an extension arm722affixed to a body723of the formation evaluation apparatus720. The extension arm722may be configured to extend the pad721against a wellbore wall740. The pad721may be provided with an elastomeric ring730configured to seal against the wellbore wall740and facilitating hydraulic communication between the formation evaluation apparatus720and a formation of interest725. An extendable bit724may be configured to form a hole through a mud cake728lining the wellbore wall740and several inches into the formation725, for example beyond a damaged and/or invaded zone726and into a pristine zone727of the formation725. A flow line729may be used to inject fluids into or withdraw fluid from the formation725.

Tri-axial antennas732may be provided in or on the extendable pad721, disposed for example on two opposite sides of a shaft coupled to the bit724and the flow line729. A coil of one of the tri-axial antennas may be used as a transmitter, and coils of the other tri-axial antennas may be used as receivers. Alternatively, or additionally, a toroid735(such as may be similar to the transmitter toroid565ofFIG. 4A) may be used as a transmitter and coils of the tri-axial antennas732may be used as receivers. By passing alternating current or various forms of switched current through the transmitter coils and/or the toroid735, and detecting voltages induced in one or more receiver coils, measurements related to the formation resistivity may be derived. For example, a method for measuring formation properties utilizing fluid injection in the formation that may be used in conjunction with the extendable pad721may combine tri-axial induction response and a toroidal excitation response. The transmitter coils and/or the toroid735may be driven at various frequencies so that the measurements at these frequencies may be inverted to produce a resistivity image of the formation in the injection zone.

In addition, NMR sensors731may be disposed in or on the extendable pad721. The NMR sensors731may be configured to investigate a sensing volume in the vicinity of the hole formed by the bit724. Using one or more of the sensors731, one or more of the diffusion distribution D, the polarization relaxation distribution T1and the precession relaxation distribution T2may be acquired. The acquired NMR measurements may be used to determine formation porosity and injected fluid saturation levels, for example using D-T2distributions. Thus, the NMR measurements may provide injected fluid saturation measurements independent from the formation resistivity. Also, by performing NMR measurements corresponding to different volumes and/or pressures of injected fluid, effective permeabilities of the formation may be determined.

It should be appreciated that other sensor combinations may be used within the scope of the present disclosure. For example, the antennas of the magnetic resonance sensors ofFIGS. 5A-5Hmay also be used for electromagnetic propagation measurements, such as by using frequency ranges for driving the coils sufficiently lower than the Larmor frequency. Thus, the sensors ofFIGS. 5A-5Hmay be used to implement a sensor assembly capable of combining NMR measurements and resistivity measurements. Further, micro-sensors (not shown) may be provided on the bit724, and may be configured to measure formation properties.

Turning toFIG. 9A, a formation evaluation apparatus750according to one or more aspects of the present application is shown. The formation evaluation apparatus750may be used to implement a portion of the formation tester214ofFIG. 1and/or the sampling-while drilling device410ofFIG. 2B. The formation evaluation apparatus750may be configured to seal a portion764of a wall762of a wellbore756penetrating a formation755, form a hollow cylindrical hole760through the sealed portion764of the wellbore wall, and measure one or more petrophysical properties of the formation755proximate the hole760while maintaining the sealed portion764of the wellbore wall.

For example, the formation evaluation apparatus750may include a housing751configured for conveyance within the wellbore756. The formation evaluation apparatus750may be urged against the side of the wellbore wall762opposite a core assembly757, for example, by actuating anchor pistons761. A piston-type or other actuator766may be used for moving the core assembly757between a retracted position (not shown inFIG. 9A) during conveyance of the housing751and a deployed position (shown inFIG. 9A) for sealing the region764of the wellbore wall762. Thus, the core assembly757may be carried by the housing751and may be configured, when urged against the wellbore wall762, to seal the region764of the wellbore wall762. The actuator766may be connected to a coring housing776for moving the coring housing776between the retracted and deployed positions, and a controllable power source (such as a hydraulic system) for extending and retracting the pistons (not shown separately). The coring assembly757may include a seal774, such as an elastomer ring or similar sealing element, mounted to the coring housing776to facilitate creating the seal between the wellbore wall762and the region764.

A drill may be rotated and moved longitudinally by a motor assembly749. The drill may comprise a coring shaft759having a coring bit758at an end thereof. An example motor assembly may be found in U.S. Pat. No. 6,371,221, the disclosure of which is incorporated herein by reference. The drill may be used for penetrating the formation755proximate the sealed-off region764. The action of the drill may result in creating the lateral bore760extending partially through the formation755away from the wellbore wall762.

The formation evaluation apparatus750may further include a flow line768extending from a fluid reservoir through a portion of the formation evaluation apparatus750and in fluid communication with the formation755through an opening772of the coring housing776. The fluid reservoir may be or comprise one or more fluid collecting chambers disposed in the injection fluid carrier modules226,228ofFIG. 1and/or the injection fluid carrier module490ofFIG. 2A. A pump (such as the pump221ofFIG. 1and/or the pump475ofFIG. 2B) may be provided in fluid communication with the formation755via the flow line768. The pump may be used for pumping fluid from the reservoir into the formation755. A sensor may be associated with the pump so that a volume of fluid pumped into the formation755may be monitored. However, other types of sensors configured to monitor the volume of fluid displaced into the formation755may be used within the scope of the present disclosure. Additionally, a fluid sensing unit (such as the fluid sensing unit220ofFIG. 1and/or the fluid sensing unit470ofFIG. 2B) may be carried within the housing751for measuring pressure and viscosity of the fluid within the flow line768, among other fluid properties.

The formation evaluation apparatus750further includes a flow line767extending through a portion of the tool body. The flow line767may be fluidly communicating with an extendable tube770. A pump (such as the pump231ofFIG. 1and/or the pump476ofFIG. 2B) may be provided in fluid communication with the formation755via the flow line767. The pump may be used for pumping fluid from the formation755when desired. A fluid sensing unit (such as the fluid sensing unit220ofFIG. 1and/or the fluid sensing unit470ofFIG. 2B) may be carried within the housing751for measuring composition data, viscosity, and/or pressure of the fluid within the flow line767, among other fluid properties.

A non-rotating sleeve748may be provided in the shaft759. The non-rotating sleeve may be configured to translate with the shaft759. However, the rotation of the non-rotating sleeve748may be uncoupled from the rotation of the shaft759. An example of such uncoupled sleeve may be found in U.S. Pat. No. 7,431,107, incorporated herein by reference. The uncoupled sleeve may be configured to sever and capture a formation core sample747therein.

Sensors780and782may be provided on the non-rotating sleeve748adjacent to the bit758and may be configured to measure one or more petrophysical properties (e.g., saturation levels) of the formation755while maintaining the sealed portion764of the wellbore wall. The sensors780and/or782may include one or more of electric resistivity sensors, dielectric constant sensors, magnetic resonance sensors, nuclear radiation sensors, and/or combinations thereof. For example, the sensors780and/or782may include electrodes for current injection into the formation or current return from the formation. Alternatively, or additionally, the sensors780and/or782may include coils suitable for measuring electrical conductivity in the formation by electromagnetic induction and/or electromagnetic propagation. The sensors780and/or782may include permanent magnets and coils configured to perform NMR analysis of the formation and/or fluids therein.

While the formation evaluation apparatus750is shown with flow lines767and768, only one flow line may be provided. Further, while the flow line768may be used to inject fluid into the formation755and the flow line767may be used to withdraw fluid from the formation755, both flow lines may be used to inject and/or withdraw fluid. For example, contaminated fluid may be withdrawn via the flow768from a zone754contaminated by mud filtrate, while pristine fluid may be withdrawn via the flow line767from a connate zone756.

Referring toFIG. 9B, a portion of the formation evaluation apparatus750is shown. The non-rotating sleeve748may be provided with an inflatable sealing sleeve785, similar to a Hassler sleeve, for example made with Viton. The inflatable sealing sleeve785may be configured to prevent fluid from bypassing the formation755and/or the core sample747. A control flow line786may be connected to a hydraulic fluid reservoir. The control flow line pressure may be reduced (e.g., below wellbore pressure) to cause the sealing sleeve785to be pulled open and thus reduce friction as the formation755and/or the core sample747is being inserted into the non-rotating sleeve748. Conversely, the control flow line pressure may be increased (e.g., above wellbore and formation pressure) to cause the sealing sleeve785to compress and seal around the formation755and/or the core sample747. Cleaning of the inflatable sealing sleeve785may be performed by retracting the inflatable sealing sleeve785and circulating fluid from the flow line768to the flow line767or vice versa.

The non-rotating sleeve748may optionally be provided with a porous disk788to facilitate fluid flow from and/or into the flow line767. Further, the non-rotating sleeve748may be provided with a hydrophilic or hydrophobic membrane787. The membrane787may be used to perform in situ capillary pressure measurement. For example, using a hydrophilic membrane, the formation755and/or the core sample747may be first flushed with formation hydrocarbon (e.g., oil) by appropriate operation of flow lines767and/or768. Then, the formation755and/or the core sample747may be injected with water and/or brine to increase water and/or brine saturation in stage until the irreducible saturation is achieved. The differential pressure across the formation755and/or the core sample747may be measured using a differential pressure gauge (not shown) between the flow lines767and768as a function of the water and/or brine saturation in formation755and/or the core sample747. Thus, a portion of a capillary pressure curve can be constructed. Alternately, a hydrophobic membrane may be used and the formation755and/or the core sample747may be injected with hydrocarbon fluid (e.g., oil) to increase hydrocarbon saturation in stage until the residual saturation is achieved. Thus, another portion of a capillary pressure curve can be constructed.

Turning toFIGS. 10A-10C, sensors according to one or more aspects of the present disclosure are shown. The sensor ofFIGS. 10A-10Cmay be used to implement the sensors780and/or782ofFIGS. 9A and 9B. For example, a resistivity sensor and an NMR sensor may be used to implement the sensors780and/or782ofFIGS. 9A and 9B. Thus, a relationship between saturation determined from NMR measurements, porosity determined from NMR measurements, and resistivity may be derived as saturation levels in the formation755and/or the core747are altered. For example, one or more of the Archie's equation cementation and saturation exponents may be inverted. Further, it should be appreciated that sensors ofFIGS. 10A-10Care movable with the bit758ofFIG. 9A. Thus, measurements on different portions of the formation755and/or the core747may be performed.

Referring toFIG. 10A, a resistivity sensor may include current injection and collection electrodes,792and793respectively. A voltage differential may be measured between monitoring electrodes794and795. A guard electrode792may be held at the same potential as the current injection electrode792and may be used to focus current towards the current collection electrode793.

Referring toFIG. 10B, another resistivity sensor may include a transmitter toroid784and a measurement toroid786. The transmitter toroid784may be used to induce an electric field such as the electric field line787in the formation755and/or the core747. The electric field lines may return via a portion of the non-rotating sleeve748(e.g., made with magnetic steel). The measurement toroid786may be used to determine the current in the formation755and/or the core747generated by the electric field lines such as787.

Referring toFIG. 10C, a magnetic resonance sensor may include permanent or electro magnets796and a solenoid798. The permanent or electro magnet796may be configured to generate a homogenous magnetic field797in the formation755and/or the core747. The solenoid798may be configured to generate a pulsed radio frequency magnetic field799having selected spatial distribution for inducing nuclear magnetic resonance phenomena and for performing nuclear magnetic resonance measurements.

Referring toFIG. 11, illustrated is a flow-chart diagram of at least a portion of a method800according to one or more aspects of the present disclosure. The method800may be performed using apparatus within the scope of the present disclosure and/or otherwise in conjunction with the operation of apparatus within the scope of the present disclosure. It should be appreciated that the order of execution of the steps of the method800may be changed and/or some of the steps described may be combined, divided, rearranged, omitted, eliminated and/or implemented in other ways within the scope of the present disclosure.

The method800may include a step805comprising moving the apparatus along a wellbore penetrating subsurface formations and/or orient the apparatus to a position adjacent a selected formation portion. The formation portion may be selected based on measurements such as resistivity images of the formation wall as is known in the art.

In optional step810, one or more measurements may be performed to establish a baseline measurement in the wellbore fluid. For example, the measurements may be performed when the probe of the apparatus is in a retracted position and may communicate with the fluid in the wellbore. The measurement(s) may be used to provide an estimate of wellbore fluid resistivity, viscosity and/or other wellbore fluid properties. The measurement(s) may alternatively, or additionally, be used to calibrate the sensors of the apparatus for pressure and/or temperature effects.

In subsequent step815, the apparatus is anchored and/or set. For example, the probe of the apparatus may articulate out from the apparatus to compress and seal against the wellbore wall, establishing a hydraulic seal with the formation. Thus, a portion of a wall of a wellbore penetrating the formation may be sealed.

In optional step820, one or more measurements may be performed on the formation, such as to provide a porosity value and/or a permeability value (e.g., using NMR measurements), and possibly fluid saturation values in the invaded zone.

In step825, the apparatus may be used to pump fluid from the formation into the apparatus, which may facilitate removal of filtrate from the formation near the probe. For example, pump fluid from the formation into the apparatus may involve withdrawing, via a first flow line (e.g., the flow line518inFIG. 3and/or the flow line768inFIG. 9B), a first fluid from a zone contaminated by mud filtrate; and withdrawing, via a second flow line (e.g., the flow line517inFIG. 3and/or the flow line767inFIG. 9B), a second fluid from a connate zone. A property of the withdrawn fluid may be measured for example using a fluid sensing unit coupled to the first or second flow line or other sensors such as the sensors780or782inFIG. 9A. The measurement(s) may be used to provide an estimate of formation fluid resistivity, viscosity and/or other formation fluid properties. One or more fluid samples may be collected in chambers for subsequent analysis.

In step830, one or more measurements may be acquired to provide fluid saturations and/or other petrophysical data after the filtrate has been cleaned-up in a zone close to the probe and replaced by formation fluid. This data may be representative of the petrophysical characteristics of the reservoir in its original or un-invaded state.

In step835, a drill may be used to form a lateral hole in the wellbore wall, wherein the lateral hole is sealed from communication with the wellbore other than through the probe. While forming the hole, the pressure at the sealed portion of the wellbore wall may be maintained below the formation pressure. This may facilitate the evacuation of cuttings, mud or other particles from the drilled hole. This may reduce the risk of mud or solid particles penetrating the drilled formation. This may facilitate fluid injectivity to the desired lateral depth in the formation. Formation evaluation (such as resistivity measurements) may be performed at a plurality of lateral depths by drilling the lateral hole further into the formation and repeating any testing. This may ensure that the lateral hole is extended beyond the invaded zone of the formation.

In step840, a fluid may be injected into the formation. The fluid may be provided in collecting chambers conveyed by the apparatus. The collecting chambers may be filled with the fluid at the surface, prior to lowering the apparatus in the wellbore. Alternatively, the fluid may be collected downhole, for example, from a formation penetrated by the wellbore, segregated in the apparatus and injected into the formation. The fluid may comprise fresh water, brine or hydrocarbon, completion fluid, other fluid formulated to modify the property of the formation fluid (such as its viscosity) and/or the formation rock (such as its wettability), or mixtures thereof in predetermined fractions. While injecting fluid from the apparatus into the formation, any or all of the above-described petrophysical parameters (such as injected fluid saturation levels and/or flow rates) may be determined. The petrophysical parameters may be determined by measuring one or more properties of the formation proximate the hole while maintaining the sealed portion of the wellbore wall. Also, both the injection pressure and an injected volume of the injection fluid may be monitored contemporarily to injecting fluid into the formation.

Subsequent step845may comprise analyzing the measurements performed at step840and/or previous measurements performed at step810,820and/or830.

For example, using the examples described herein, and/or others within the scope of the present disclosure, it may be possible to monitor changes in fluid saturation of the formation in three dimensions and/or to monitor the injected fluid front.

By measuring fluid injection pressure, injected fluid viscosity and flow rate at step840, it may be possible at step845to determine a relative permeability curve of an injected fluid. Relative permeability can be plotted as a function of fluid saturations in the formation, for example as illustrated in the example graph ofFIG. 12. Thus, in situ determinations of relative permeability curves of fluids in the formation can be made. The steps840and845may be repeated with different injection fluids, such as oil, water and gas, as desired. Thus, residual saturations (such as the residual oil saturation “SOR” which is the amount of oil remaining in the pore space after flushing with the water or the irreducible water saturation “SWIR” which is the amount of water remaining in the pore space after flushing with oil) may also be determined at step845. Also, step840may be repeated to inject chemicals such as enhanced oil recovery fluids (e.g., solvent, steam, carbon dioxide, and/or surfactants, among others) from the apparatus. Thus, changes of the relative permeability and/or residual saturation of one or more of the fluids caused by the injected chemical may be monitored. Also, fluorinated compounds may be injected to measure the formation permeability.

By measuring differential pressure across a hydrophilic or hydrophobic membrane (such as membrane787inFIG. 9B) during fluid imbibitions and/or drainage at step840, it may be possible at step845to determine capillary pressure curve, for example as illustrated in the example graph ofFIG. 13. A wettability index may then be determined, for example using the modified Amott/USBM technique. Step840may be repeated to inject chemicals (such as detergents) to change the wettability of the formation rock and quantify a resulting change of wettability at step845.

As mentioned before, the resistivity measurements and the fluid saturation measurements may be combined at step845to form saturation versus electric resistivity curves such as illustrated in the example graph ofFIG. 14. The formed curves may be used to estimate one or more of the saturation and cementation exponents of the Archie's equation or other equation such as the connectivity equation discussed in “A quantitative Model for the Effect of Wettability on the Conductivity of Porous Rocks” by B. Montaron, SPE 105041, March 2007. Thus, a relationship between the determined saturation and an electric resistivity of the formation may be determined. The Archie's equation or the connectivity equation may then be used to convert resistivity measurements into fluid saturations in other zone of the formation. Further, the parameters of the Archie's equation (such as the saturation exponent) may be used to determine a wettability parameter of the formation.

In optional step850, the probe is retracted and the apparatus may be rotated and/or moved to the next station to iterate one or more of steps810-845. For example, results obtained for different orientations at a single or multiple stations can be compared to identify discrepancies which may be indicative of rock heterogeneity, rock anisotropy, and/or micro-fractures having a preferential direction, among other uses.

Referring toFIG. 12, an example graph900depicts effective permeability (k) curves as a function of saturation (S). Effective permeability curves, such as shown in the graph900, may be determined using apparatus and/or methods within the scope of the present disclosure. For example, an oil effective permeability curve905and a water (or brine) effective permeability curve910may be determined as a function of water (or brine) saturation. Water saturation may be measured in a portion of the formation while water saturation is increased by injection. Water and/or oil effective permeabilities may be determined from one or more of successive saturation images of the portion of the formation, flow rate measurements in the apparatus flow lines and/or in the portion of the formation, pressure measurements in the apparatus flow lines, formation pressure, and/or viscosity values of oil and water, among others. Also, irreducible water saturation points911and/or one minus residual oil saturation point906may be determined.

Referring toFIG. 13, an example graph920depicts capillary pressure (Pc) curves as a function of saturation (S). Capillary pressure curves, such as shown in the graph920, may be determined using apparatus and/or methods within the scope of the present disclosure. For example, an imbibition curve having a spontaneous imbibitions portion925aand a forced imbibitions portion925bmay be determined as a function of water (or brine) saturation. A portion of formation may have an initial water (or brine) saturation indicated by point926, for example the irreducible water saturation. When placed in contact with water (or brine) at formation pressure, the water (or brine) saturation in the portion of the formation may increase to a level indicated by point927. By injecting water (or brine) at a pressure differential Pc across a hydrophilic membrane surrounding the portion of the formation, and measuring the resulting water (or brine) saturation, the forced imbibition curve925bmay be determined. Alternatively or additionally, a drainage curve having a spontaneous drainage portion930aand a forced drainage portion930bmay be determined as a function of water (or brine) saturation. A portion of formation may have an initial water (or brine) saturation indicated by point931, for example one minus the residual oil saturation. When placed in contact with oil at formation pressure, the water (or brine) saturation in the portion of the formation may decrease to a level indicated by point932. By injecting oil at a pressure differential Pc across a hydrophobic membrane surrounding the portion of the formation, and measuring the resulting water (or brine) saturation, the forced drainage curve930bmay be determined. An area above the imbibitions curve928and/or an area933below the drainage cure may further be determined. Wettability indices may be derived from the saturations points926,927,931and932, and/or the areas928and933, as is known in the art.

Referring toFIG. 14, an example graph940of electric resistivity R versus saturation S curves945and950corresponding to two different formations is shown. Electric resistivity versus saturation curves, such as shown in the graph940, may be determined using the apparatus and/or the method within the scope of the present disclosure. For example, one or more of the curves945and950may be fitted to a mathematical model, expressing a relationship between the determined saturation and an electric resistivity of the formation. Parameters of the mathematical model, such as the critical water saturation and/or the saturation exponent may be related to the proportion of the oil-wet pores of the formation rock and/or the formation rock wettability (see for example “Relationship Between the Archie Saturation Exponent and Wettability” by E. C Donaldson and T. K. Siddiqui, SPE 16790, pp 359-362, September 1989).

FIG. 15is a schematic view of at least a portion of an example computing system P100that may be programmed to carry out all or a portion of the example method800ofFIG. 11and/or other methods within the scope of the present disclosure. The computing system P100may be used to implement all or a portion of the electronics and processing system206ofFIG. 1, the downhole control system212ofFIG. 1, the logging and control unit360ofFIG. 2A, the downhole control system480ofFIG. 2B, and/or other control means within the scope of the present disclosure. The computing system P100shown inFIG. 15may be used to implement surface components (e.g., components located at the Earth's surface) and/or downhole components (e.g., components located in a downhole tool) of a distributed computing system.

The computing system P100may include at least one general-purpose programmable processor P105. The processor P105may be any type of processing unit, such as a processor core, a processor, a microcontroller, etc. The processor P105may execute coded instructions P110and/or P112present in main memory of the processor P105(e.g., within a RAM P115and/or a ROM P120). When executed, the coded instructions P110and/or P112may cause the formation tester214ofFIG. 1, the testing while drilling device410ofFIG. 2B, the formation evaluation apparatus500ofFIG. 3, the formation evaluation apparatus720ofFIG. 8, and/or the formation evaluation apparatus750ofFIG. 9A, to perform at least a portion of the method800ofFIG. 11, among other operations.

The processor P105may be in communication with the main memory (including a ROM P120and/or the RAM P115) via a bus P125. The RAM P115may be implemented by dynamic random-access memory (DRAM), synchronous dynamic random-access memory (SDRAM), and/or any other type of RAM device, and ROM may be implemented by flash memory and/or any other desired type of memory device. Access to the memory P115and the memory P120may be controlled by a memory controller (not shown). The memory P115, P120may be used to store, for example, measured formation properties (e.g., formation resistivity), petrophysical parameters (e.g., saturation levels, wettability), injection volumes and/or pressures.

The computing system P100also includes an interface circuit P130. The interface circuit P130may be implemented by any type of interface standard, such as an external memory interface, serial port, general-purpose input/output, etc. One or more input devices P135and one or more output devices P140are connected to the interface circuit P130. The example input device P135may be used to, for example, collect data from the sensors contemplated inFIGS. 1-10. The example output device P140may be used to, for example, display, print and/or store on a removable storage media one or more of measured formation properties (e.g., formation resistivity values or images), petrophysical parameters (e.g., saturation levels or images, wettability), injection volumes and/or pressures. Further, the interface circuit P130may be connected to a telemetry system P150, including, for example, the multi-conductor cable204ofFIG. 1, the mud pulse telemetry (MPT) and/or the wired drill pipe (WDP) telemetry system ofFIG. 2A. The telemetry system P150may be used to transmit measurement data, processed data and/or instructions, among other things, between the surface and downhole components of the distributed computing system.

In view of all of the above and the figures, those skilled in the art should readily recognize that the present disclosure introduces a method of subsurface formation evaluation comprising sealing a portion of a wall of a wellbore penetrating the formation, forming a hole through the sealed portion of the wellbore wall, injecting an injection fluid into the formation through the hole, and determining a saturation of the injection fluid in the formation by measuring a property of the formation proximate the hole while maintaining the sealed portion of the wellbore wall. The method may further comprise measuring at least one of a discharge pressure and a discharged volume of the injection fluid. The method may further comprise determining a relationship between the determined saturation and an electric resistivity of the formation. The method may further comprise estimating a wettability parameter of the formation based on the determined relationship. The method may further comprise withdrawing a fluid from the formation through the hole. Withdrawing a fluid from the formation may comprise: withdrawing, via a first flow line, a first fluid from a zone contaminated by mud filtrate; and withdrawing, via a second flow line, a second fluid from a connate zone. The method may further comprise measuring a property of the withdrawn fluid. The method may further comprise determining a relative permeability of the formation based on the measured property of the withdrawn fluid. The measured formation property may be selected from the group consisting of electric resistivity, dielectric constant, magnetic resonance relaxation time, nuclear radiation, and combinations thereof. Forming the hole may comprise extending a bit into the formation. The method may further comprise introducing an electrical current into the formation from the bit, and wherein measuring the property of the formation comprises measuring a return electrical current. The method may further comprise measuring a plurality of property values associated with each of a plurality of sensing volumes of the formation proximate the hole.

The present disclosure also introduces a method of subsurface formation evaluation comprising sealing a portion of a wall of a wellbore penetrating the formation, forming a hole through the sealed portion of the wellbore wall by extending a bit into the formation through the sealed portion, introducing an electrical current into the formation from the bit, and measuring an electrical current of the formation while maintaining the sealed portion of the wellbore wall. Such method may further comprise determining a property of the formation, wherein the formation property is selected from the group consisting of electric resistivity, dielectric constant, magnetic resonance relaxation time, nuclear radiation, and combinations thereof. Such method may further comprise extending the bit into the formation at a plurality of lateral depths and measuring the electrical current of the formation at the plurality of lateral depths.

The present disclosure also introduces a subsurface formation evaluation apparatus comprising means for sealing a portion of a wall of a wellbore penetrating the formation, means for forming a hole through the sealed portion of the wellbore wall, means for injecting an injection fluid into the formation through the hole, and means for determining a saturation of the injection fluid in the formation based on a property of the formation measured proximate the hole while maintaining the sealed portion of the wellbore wall. The apparatus may further comprise: means for determining a relationship between the determined saturation and an electric resistivity of the formation; and means for estimating a wettability parameter of the formation based on the determined relationship. The measured formation property may be selected from the group consisting of electric resistivity, dielectric constant, magnetic resonance relaxation time, nuclear radiation, and combinations thereof. The hole forming means may comprise means for extending a bit into the formation. The apparatus may further comprise means for introducing an electrical current into the formation from the bit, and the measured formation property may comprise a return electrical current. The apparatus may further comprise means for measuring a plurality of property values associated with each of a plurality of sensing volumes of the formation proximate the hole.