Non-azimuthal and azimuthal formation evaluation measurement in a slowly rotating housing

A steering tool configured for making azimuthal and non-azimuthal formation evaluation measurements is disclosed. In one embodiment a rotary steerable tool includes at least one formation evaluation sensor deployed in the steering tool housing. The steering tool may include, for example, first and second circumferentially opposed formation evaluation sensors or first, second, and third formation evaluation sensors, each of which is radially offset and circumferentially aligned with a corresponding one of the steering tool blades. The invention further includes methods for geosteering in which a rotation rate of the steering tool housing in the borehole (and therefore the rotation rate of the formation evaluation sensors) is controlled. Steering decisions may be made utilizing the formation evaluation measurements and/or derived borehole images.

RELATED APPLICATIONS

FIELD OF THE INVENTION

The present invention relates generally to downhole tools, for example, including directional drilling tools such as three-dimensional rotary steerable tools (3DRS). More particularly, embodiments of this invention relate to rotary steerable tools having formation evaluation sensors deployed in an outer housing thereof. The invention further relates to geosteering methods.

BACKGROUND OF THE INVENTION

Logging while drilling (LWD) techniques for determining numerous borehole and formation characteristics are well known in oil drilling and production applications. Such logging techniques include, for example, natural gamma ray, spectral density, neutron density, inductive and galvanic resistivity, micro-resistivity, acoustic velocity, acoustic caliper, physical caliper, downhole pressure, and the like. Formations having recoverable hydrocarbons typically include certain well-known physical properties, for example, resistivity, porosity (density), and acoustic velocity values in a certain range. Such LWD measurements (also referred to herein as formation evaluation measurements) may be used, for example, in making steering decisions for subsequent drilling of the borehole.

LWD sensors (also referred to herein as formation evaluation or FE sensors) are commonly used to measure physical properties of the formations through which a borehole traverses. Such sensors are typically deployed in a rotating section of the bottom hole assembly (BHA) whose rotational speed is substantially the same as the rotational speed of the drill string. LWD imaging and geo-steering applications commonly make use of focused FE sensors and the rotation (turning) of the BHA (and therefore the FE sensors) during drilling of the borehole. For example, in a common geo-steering application, a section of a borehole may be routed through a thin oil bearing layer (sometimes referred to in the art as a payzone). Due to the dips and faults that may occur in the various layers that make up the strata, the drill bit may sporadically exit the oil-bearing layer and enter nonproductive zones during drilling. In attempting to steer the drill bit back into the oil-bearing layer (or to prevent the drill bit from exiting the oil-bearing layer), an operator typically needs to know in which direction to turn the drill bit (e.g., up or down). Such information may be obtained, for example, from azimuthally sensitive measurements of the formation properties.

One drawback associated with the above described configuration (in which the FE sensors are rotationally coupled to the drill string) is that the vibration and shock sensitive FE sensors are subject to high lateral, axial, and torsional vibrations during normal drilling operations. Conventional FE sensor deployments are known to be susceptible to vibration and shock related errors and failures. Another drawback associated with the above-described conventional FE sensor deployments is that azimuthal logging techniques require a substantially uniform drill string rotation rate during drilling in order to suitably reduce statistical errors in the azimuthally focused logging data. While the above-mentioned conventional deployments are serviceable, and have been commercially utilized, an improved apparatus and method for acquiring near-bit formation evaluation sensor measurements is needed. In particular, there is a need for an apparatus that is less susceptible to shock and vibration related errors and failures and that is capable of providing both azimuthally focused and non-azimuthally focused formation evaluation sensor measurements.

SUMMARY OF THE INVENTION

The present invention addresses the need for improved formation evaluation sensor deployments and improved geosteering methods. Aspects of this invention include rotary steerable deployments including at least one (and preferably a plurality of) formation evaluation sensor(s) deployed in the steering tool housing. In one preferred embodiment, the steering tool housing includes at least first and second circumferentially opposed gamma ray sensors. In a second preferred embodiment, the steering tool includes at least first, second, and third neutron density sensors, each of which is radially offset and circumferentially aligned with a corresponding one of the steering tool blades. The invention further includes methods for geosteering in which a rotation rate of the steering tool housing in the borehole (and therefore the rotation rate of the formation evaluation sensors) is controlled via controlling blade force. The rotation rate may be controlled, for example, so as to promote formation evaluation measurements at or near predetermined tool face angles. The rotation rate may also be controlled so as to enable borehole imaging. Steering decisions may then be made utilizing the formation evaluation measurements and/or derived borehole images.

Exemplary embodiments of the present invention may advantageously provide several technical advantages. For example, deployment of the formation evaluation sensors in the steering tool housing has been found to reduce both shock and vibration exposure and therefore tends to minimize shock and/or vibration related errors and/or failures. Exemplary steering tool embodiments of the invention also advantageously provide for both azimuthal (focused) and non-azimuthal (non-focused) formation evaluation measurements. Exemplary steering tool embodiments of the invention may also provide for simultaneous formation evaluation and physical standoff measurements. Such physical standoff measurements tend to be more reliable than conventional ultrasonic standoff measurements and may be utilized to interpret the formation evaluation measurements (e.g., neutron density measurements).

The invention further provides near-bit, azimuthally resolved formation evaluation measurements which may be utilized, for example, in geosteering applications. The use of azimuthally resolved formation evaluation measurements in geosteering tends to advantageously optimize wellbore placement and reduce dependence on pre-well geological models. Such models are known to be limited by the resolution of seismic data and commonly fail to include faults and other complex geological features (even when correlated with nearby offset wells). Thus, the invention may also provide for improved wellbore placement in geosteering applications.

The invention also advantageously provides a method for controlling the rotation rate of the steering tool housing in the borehole during drilling (e.g., in the range of from about 0.1 to about 30 revolutions per hour). Since the formation evaluation sensor(s) are deployed in the steering tool housing, the invention also advantageously enables the rate at which these sensors rotate in the borehole to be controlled. Controlling the rotation rate of the housing advantageously enables the sensors to be maintained at a desired orientation (e.g., in high side or low side quadrants) for longer periods of time than an undesirable orientation (e.g., in left side or right side quadrants). Such control tends to be advantageous in geosteering applications.

Moreover, controlling the rotation rate of the steering tool housing advantageously enables borehole images (images based on formation evaluation measurements) to be acquired. Such borehole images may also be advantageously utilized in geosteering applications.

In one aspect the present invention includes a downhole steering tool configured to operate in a borehole. The steering tool includes a shaft deployed substantially coaxially in a housing, the shaft and the housing being free to rotate relative to one another about a longitudinal axis of the steering tool. A plurality of blades are deployed on the housing. The blades are disposed to extend radially outward from the housing and engage a wall of the borehole, said engagement of the blades with the borehole wall operative to eccenter the housing in the borehole. A plurality of circumferentially spaced formation evaluation sensors are deployed in the housing, each of the formation evaluation sensors being configured to individually provide a corresponding azimuthally focused sensor response. The plurality of formation evaluation sensors are further configured to collectively provide a non-azimuthally focused sensor response. A controller is configured to acquire sensor data from the formation evaluation sensors and to compute both azimuthally focused and non-azimuthally focused formation evaluation measurements.

In another aspect this invention includes a downhole steering tool configured to operate in a borehole. The steering tool includes a shaft deployed substantially coaxially in a housing, the shaft and the housing being free to rotate relative to one another about a longitudinal axis of the steering tool. At least first, second, and third blades are deployed on the housing. The blades are disposed to extend radially outward from the housing and engage a wall of the borehole, said engagement of the blades with the borehole wall operative to eccenter the housing in the borehole. At least first, second, and third circumferentially spaced formation evaluation sensors are deployed in the housing. Each of the first, second, and third formation evaluation sensors is axially spaced from and circumferentially aligned with a corresponding one of the first, second, and third blades. A controller is configured to compute a standoff distance at each of the formation evaluation sensors based on a radial position of the corresponding blades.

In another aspect the present invention includes a method for geosteering. The method includes deploying a steering tool in a subterranean borehole. The steering tool includes a housing deployed about a shaft, the housing and the shaft free to rotate relative to one another about a longitudinal axis of the steering tool. A plurality of blades are deployed on the housing, the blades disposed to extend radially outward from the housing and engage a wall of the borehole, said engagement of the blades with the borehole wall operative to eccenter the housing in the borehole. The steering tool housing further includes at least one formation evaluation sensor and a tool face sensor deployed therein; The method further includes causing the tool face sensor to measure a tool face angle of the formation evaluation sensor; processing the measured tool face angle to determine a target rotation rate of the housing in the borehole, and causing the housing to rotate in the borehole at about the target rotation rate.

In still another aspect the present invention includes a method for geosteering. The method includes deploying a steering tool in a subterranean borehole. The steering tool includes a housing deployed about a shaft, the housing and the shaft free to rotate relative to one another about a longitudinal axis of the steering tool. A plurality of hydraulically actuated blades are deployed on the housing, the blades disposed to extend radially outward from the housing and engage a wall of the borehole, said engagement of the blades with the borehole wall operative to eccenter the housing in the borehole. The steering tool housing further includes a hydraulic pressure sensor, at least one formation evaluation sensor, and a tool face sensor deployed therein. The method further includes causing the tool face sensor to measure a tool face angle of the formation evaluation sensor, processing the measured tool face angle to acquire a target hydraulic pressure, causing the hydraulic pressure sensor to measure a hydraulic pressure in the housing, comparing the target hydraulic pressure with the measured hydraulic pressure, opening at least one valve when the measured hydraulic pressure is greater than the target hydraulic pressure.

In a further aspect the present invention includes a method of geosteering. The method includes deploying a steering tool in a subterranean borehole, the steering tool including a housing deployed about a shaft, the housing and the shaft free to rotate relative to one another about a longitudinal axis of the steering tool. A plurality of blades are deployed on the housing, the blades disposed to extend radially outward from the housing and engage a wall of the borehole, said engagement of the blades with the borehole wall operative to eccenter the housing in the borehole. The steering tool housing further includes at least one formation evaluation sensor and a tool face sensor deployed therein. The method further includes causing the housing to rotate in the borehole at substantially a predetermined rotation rate, causing the at least one formation evaluation sensor and the tool face sensor to acquire a plurality of data pairs, each data pair comprising at least one formation evaluation measurement and a corresponding tool face angle and processing the acquired data pairs to construct a borehole image. The method still further includes processing the borehole image to acquire at least one image parameter and evaluating the at least one image parameter to control a direction of drilling, the direction of drilling being controlled via controlling extension and retraction of the blades.

The foregoing has outlined rather broadly the features of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other methods, structures, and encoding schemes for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

DETAILED DESCRIPTION

Referring first toFIGS. 1 through 4B, it will be understood that features or aspects of the embodiments illustrated may be shown from various views. Where such features or aspects are common to particular views, they are labeled using the same reference numeral. Thus, a feature or aspect labeled with a particular reference numeral on one view inFIGS. 1 through 4Bmay be described herein with respect to that reference numeral shown on other views.

FIG. 1illustrates a drilling rig10suitable for utilizing exemplary downhole steering tool and method embodiments of the present invention. In the exemplary embodiment shown onFIG. 1, a semisubmersible drilling platform12is positioned over an oil or gas formation (not shown) disposed below the sea floor16. A subsea conduit18extends from deck20of platform12to a wellhead installation22. The platform may include a derrick26and a hoisting apparatus28for raising and lowering the drill string30, which, as shown, extends into borehole40and includes a drill bit32and a steering tool100(such as a three-dimensional rotary steerable tool). In the exemplary embodiment shown, steering tool100includes a plurality of blades150(e.g., three) disposed to extend outward from the tool100. The extension of the blades150into contact with the borehole wall42is intended to eccenter the tool in the borehole, thereby changing an angle of approach of the drill bit32(which changes the direction of drilling). Steering tool100further includes at least one (and preferably a plurality of) formation evaluation sensor(s)120deployed in an outer housing110(FIG. 2). Drill string30may further include other known components, for example, including a downhole drilling motor, a mud pulse telemetry system, additional LWD or MWD sensors, and the like. The invention is not limited in these regards.

It will be understood by those of ordinary skill in the art that methods and apparatuses in accordance with this invention are not limited to use with a semisubmersible platform12as illustrated inFIG. 1. This invention is equally well suited for use with any kind of subterranean drilling operation, either offshore or onshore.

Turning now toFIG. 2, one exemplary embodiment of steering tool100fromFIG. 1is illustrated in perspective view. In the exemplary embodiment shown, steering tool100is substantially cylindrical and includes threaded ends102and104(threads not shown) for connecting with other bottom hole assembly (BHA) components (e.g., connecting with the drill bit at end104and upper BHA components at end102). The steering tool100further includes a shaft115(FIGS. 3,4A, and4B) deployed in a housing110. The shaft115is connected with the drill string30and is disposed to transfer both torque and weight to the bit32(FIG. 1). The housing110is constructed in a rotationally non-fixed (floating) fashion with respect to the shaft115. A plurality of blades150are deployed, for example, in corresponding recesses (not shown) in the housing110. Steering tool100further includes a plurality of formation evaluation (FE) sensors120deployed in housing110. FE sensors120may also be referred to herein as LWD sensors. FE sensors120typically include one or more of the following: gamma ray sensors, natural gamma ray sensors, spectral density sensors, neutron density sensors, inductive and galvanic resistivity sensors, micro-resistivity sensors, acoustic velocity sensors, and the like. Preferred FE sensor embodiments are discussed in more detail herein below with respect toFIGS. 4A and 4B. Steering tool100further includes hydraulics130and electronics140modules (also referred to herein as control modules130and140) deployed in the housing110. In general (and as described in more detail below with respect toFIG. 3), the control modules130and140are configured for measuring and controlling the relative positions of the blades150as well as the hydraulic system and blade pressures. Control modules130and140may include substantially any devices known to those of skill in the art, such as those disclosed in U.S. Pat. No. 5,603,386 to Webster or U.S. Pat. No. 6,427,783 to Krueger et al. Electronic control module140also includes FE sensors120and associated electronics.

Steering tool100may be used in directional drilling operations (including geosteering applications) to steer drill bit32along a predetermined drilling path. To steer (i.e., change the direction of drilling), one or more of blades150are extended and exert a force against the borehole wall. The steering tool100is moved away from the center of the borehole by this operation, altering the drilling path. It will be appreciated that the tool100may also be moved back towards the borehole axis if it is already eccentered. In general, increasing the offset (i.e., increasing the distance between the tool axis and the borehole axis) tends to increase the curvature (dogleg severity) of the borehole upon subsequent drilling. In the exemplary embodiment shown, steering tool100is configured for “push-the-bit” steering in which the direction (tool face) of subsequent drilling tends to be the same (or nearly the same; depending, for example, upon local formation characteristics) as the offset between the tool axis and the borehole axis. The invention is not limited to a push-the-bit configuration. It is equally well suited for “point-the-bit” steering in which a near-bit stabilizer is utilized and the direction of subsequent drilling tends to be opposite the offset between the tool axis and borehole axis.

As described above, shaft115and housing110are configured to rotate substantially freely with respect to one another. To facilitate controlled steering, the housing110preferably is substantially non-rotating or slowly rotating with respect to the borehole. By keeping the blades150in a substantially fixed position with respect to the circumference of the borehole (i.e., by limiting rotation of the housing110), it is possible to steer the tool without constantly extending and retracting the blades150. During a typical drilling operation, housing110typically rotates slowly in the borehole (e.g., at a rate in the range from about 0.1 to about 30 revolutions per hour). In order to accommodate the slow rotation of housing110and maintain a predetermined drilling direction, adjustments are typically made to the blade positions during drilling.

With reference now toFIG. 3, one exemplary embodiment of hydraulic module130is schematically depicted.FIG. 3shows blades150A,150B, and150C as well as certain of the electrical control devices (which are in electronic communication with electronic control module140). Hydraulic module130(FIG. 2) includes a hydraulic fluid chamber220including first and second, low and high pressure reservoirs226and236. In the exemplary embodiment shown, low pressure reservoir226is modulated to wellbore (hydrostatic) pressure via equalizer piston222. Wellbore drilling fluid224enters fluid cavity225through filter screen228, which is deployed in the outer surface of the non-rotating housing110. It will be readily understood by those of ordinary skill in the art that the drilling fluid in the borehole exerts a force on equalizer piston222proportional to the wellbore pressure, which thereby pressurizes hydraulic fluid in low pressure reservoir226.

Hydraulic module130further includes a piston pump240operatively coupled with drive shaft115. In the exemplary embodiment shown, pump240is mechanically actuated by a cam118formed on an outer surface of drive shaft115, although the invention is not limited in this regard. Pump240may be equivalently actuated, for example, by a swash plate mounted to the outer surface of the shaft115or an eccentric profile formed in the outer surface of the shaft115. In the exemplary embodiment shown, rotation of the drive shaft115causes cam118to actuate piston242, thereby pumping pressurized hydraulic fluid to high pressure reservoir236. Piston pump240receives low pressure hydraulic fluid from the low pressure reservoir226through inlet check valve246on the down-stroke of piston242(i.e., as cam118disengages piston242). On the upstroke (i.e., when cam118engages piston242), piston242pumps pressurized hydraulic fluid through outlet check valve248to the high pressure reservoir236. It will be understood that the invention is not limited to any particular pumping mechanism. In other embodiments, an electric powered pump may be utilized, for example, powered via electrical power generated by a mud turbine or from batteries such as lithium batteries.

Hydraulic fluid chamber220further includes a pressurizing spring234(e.g., a Belleville spring) deployed between an internal shoulder221of the chamber housing and a high pressure piston232. As the high pressure reservoir236is filled by pump240, high pressure piston232compresses spring234, which maintains the pressure in the high pressure reservoir236at some predetermined pressure above wellbore pressure. Hydraulic module130typically (although not necessarily) further includes a pressure relief valve235deployed between high pressure and low pressure fluid lines. In one exemplary embodiment, a spring loaded pressure relief valve235opens at a predetermined differential pressure (e.g., about 750 psi), thereby limiting the pressure of the high pressure reservoir236a predetermined amount above wellbore pressure. However, the invention is not limited in this regard.

With continued reference toFIG. 3, extension and retraction of the blades150A,150B, and150C are now described. Blades150A,150B, and150C are essentially identical and thus the configuration and operation thereof are described only with respect to blade150A. Blades150B and150C are referred to below in reference to exemplary hydraulic control methods that may be utilized in exemplary embodiments of the invention. Blade150A includes one or more blade pistons252A deployed in corresponding chambers244A, which are in fluid communication with both the low and high pressure reservoirs226and236through controllable valves254A and256A, respectively. In the exemplary embodiment shown, valves254A and256A include solenoid controllable valves, although the invention is not limited in this regard.

In order to extend blade150A (radially outward from the tool body), valve254A is opened and valve256A is closed, allowing high pressure hydraulic fluid to enter chamber244A. As chamber244A is filled with pressurized hydraulic fluid, piston252A is urged radially outward from the tool, which in turn urges blade150A outward (e.g., into contact with the borehole wall). When blade150A has been extended to a desired (predetermined) position, valve254A may be closed, thereby “locking” the blade150A in position (at the desired extension from the tool body).

In order to retract the blade (radially inward towards the tool body), valve256A is open (while valve254A remains closed). Opening valve256A allows pressurized hydraulic fluid in chamber244A to return to the low pressure reservoir226. Blade150A may be urged inward (towards the tool body), for example, via spring bias and/or contact with the borehole wall. In the exemplary embodiment shown, the blade150A is not drawn inward under the influence of a hydraulic force, although the invention is not limited in this regard.

Hydraulic module130may also advantageously include one or more sensors, for example, for measuring the pressure and volume of the high pressure hydraulic fluid. In the exemplary embodiment shown onFIG. 3, sensor262is disposed to measure hydraulic fluid pressure in reservoir236. Likewise, sensors272A,272B, and272C are disposed to measure hydraulic fluid pressure at blades150A,150B, and150C, respectively. Position sensor264is disposed to measure the displacement of high pressure piston232and therefore the volume of high pressure hydraulic fluid in reservoir236. Position sensors274A,274B, and274C are disposed to measure the displacement of blade pistons252A,252B, and252C and thus the extension of blades150A,150B, and150C. In one exemplary embodiment of the invention, sensors262,272A,272B, and272C each include a pressure sensitive strain gauge, while sensors264,274A,274B, and274C each include a potentiometer having a resistive wiper, however, the invention is not limited in regard to the types of pressure and volume sensors utilized.

In the exemplary embodiments shown and described with respect toFIG. 3, hydraulic module130utilizes pressurized hydraulic oil in reservoirs226and236. The artisan of ordinary skill will readily recognize that the invention is not limited in this regard and that pressurized drilling fluid, for example, may also be utilized to extend blades150A,150B, and150C.

Referring now toFIGS. 4A and 4B, preferred steering tool embodiments are described in more detail. As described above, exemplary embodiments of the invention include a plurality of FE sensors (e.g., sensors120A and120B in the preferred embodiment shown onFIG. 4Aor sensors120D,120E, and120F in the preferred embodiment shown onFIG. 4B).

FIG. 4Adepicts a preferred embodiment including first and second azimuthally focused FE sensors deployed on circumferentially opposing sides of housing110. In a most preferred embodiment, FE sensors120A and120B include azimuthally focused gamma ray sensors. In such an embodiment (in which FE sensors120A and120B include gamma ray sensors), steering tool100typically further includes a radiation source (not shown). The invention is not limited in this regard, however, since natural gamma ray sensors may be utilized to measure naturally occurring gamma ray emissions.

With further reference toFIG. 5, the preferred FE sensor arrangement depicted inFIG. 4Amay advantageously be utilized to acquire both azimuthal and non-azimuthal sensor responses. Gamma ray sensors120A and120B may be configured to have an approximately bell-shaped sensor responses as a function of the tool face angle (e.g., an approximately Gaussian function). The exemplary sensor response functions501and502depicted onFIG. 5may be fit using a suitable Gaussian type function having a background normalized intensity of about 0.1.FIG. 5plots the normalized sensor intensity as a function of tool face angle (azimuthal position about the circumference of the tool) for the preferred embodiment of the invention depicted onFIG. 4A. Along the tool face axis (the x-axis inFIG. 5), sensor120A has a peak response at about zero degrees (at the center of the gamma ray photo-multiplier tube). Sensor120B has a peak response at about 180 degrees (also at the center of the gamma ray photo-multiplier tube). In order to obtain azimuthally sensitive LWD sensor data, sensor responses501and502may be evaluated individually or compared with one another (for example via subtracting one from the other).

In the preferred embodiment depicted inFIGS. 4A and 5, the combined sensor response503(i.e., the sum of sensor response501and sensor response502) is substantially independent of the tool face angle (azimuthal position about the tool). As depicted, the variation in sensor response about the circumference of the tool is less 1%, which is within the statistical uncertainty of a Monte Carlo simulation model. The sensor response may therefore be considered to be essentially flat with tool face. In this preferred embodiment, the combined sensor response is configured to be essentially non-azimuthal, for example, by proper positioning of the gamma ray sensors (photo-multiplier tubes) in the tool housing110and/or proper selection of the geometry and composition of the shielding materials.

With reference now toFIG. 4B, another preferred embodiment is depicted.FIG. 4Bdepicts a steering tool100including first, second, and third FE sensors120D,120E, and120F deployed in tool body110. While not shown inFIG. 4B, it will be understood that sensors120D,120E, and120F are circumferentially aligned (but axially offset) with blades150(FIG. 2). Sensors120D,120E, and120F are preferably neutron density sensors, although the invention is not limited in this regard.

As is known to those of ordinary skill in the art, nuclear logging measurements are particularly degraded with increasing standoff distance (the distance between the FE sensor and the borehole wall) due to neutron scattering in the borehole fluids in the annulus between the sensor and formation. Therefore, a measurement of the standoff distance between the sensor and borehole wall is important in order to properly weight the acquired sensor data. Prior art neutron density logging tools often utilize simultaneous ultrasonic standoff measurements as the tool is rotating in the borehole. Alignment of the standoff sensor with the neutron sensors provides a determination of the standoff distance between the neutron sensors in the formation. While such prior art techniques are commercially serviceable, there are drawbacks. For example ultrasonic standoff tools are known to provide inaccurate or unreliable standoff measurements in certain borehole environments and drilling fluids. Ultrasonic caliper tools also tend to be expensive and prone to shock and vibration related failure during operation in harsh borehole environments. They also have difficulty measuring a reliable standoff when there are gas bubbles in the drilling fluid.

The preferred embodiment depicted inFIG. 4Badvantageously overcomes the above described drawbacks of the prior art by utilizing the blades150to make real-time physical caliper/standoff measurements. In other words, a physical standoff measurement may be computed in real time during drilling or reaming operations based on the radial position (the degree of extension) of each of the blades150(the larger the blade extension the larger the standoff distance at the corresponding circumferentially aligned sensor). It will therefore be appreciated that mechanical standoff (and caliper) measurements may be calculated substantially simultaneously with the FE sensor measurements. In this way, timely, reliable, and accurate standoff measurements may be made simultaneously with the neutron density sensor measurements.

The steering tool100described above with respectFIGS. 2 and 4may be advantageously utilized, for example, in geosteering applications. For example, as described in more detail below, a controller may be configured to control the force of at least one of the blades150against the borehole wall in order to control the rolling speed (rotation rate) of housing110with respect the borehole. As also described in more detail below, such control enables the circumferential (azimuthal) position of the FE sensor(s) to be controlled which provides for an optimum azimuthal FE sensor response.

During a typical directional drilling application (e.g., a geosteering application), a steering command may be received at steering tool100, for example, via drill string rotation encoding. Exemplary drill string rotation encoding schemes are disclosed, for example, in commonly assigned U.S. Pat. Nos. 7,222,681 and 7,245,229. Upon receiving the steering command (which may be, for example, in the form of transmitted offset and tool face values), new blade positions are typically calculated and each of the blades150A,150B, and150C is independently extended and/or retracted to its appropriate position (as measured by displacement sensors274A,274B, and274C). Two of the blades (e.g., blades150B and150C) are preferably locked into position as described above (valves254B,254C,256B, and256C are closed) with respect toFIG. 3. The third blade (e.g., blade150A) preferably remains “floating” (i.e., open to high pressure hydraulic fluid via valve256A) in order to maintain a grip on the borehole wall so that housing110is substantially non-rotating or slowing rotating during drilling.

It has been found that the rotation rate of the housing110with respect to the borehole is approximately inversely related to the force of the floating blade (e.g., blade150A) against the borehole wall. In other words, the rotation rate of the housing110tends to increase with decreasing floating blade force and decrease with increasing floating blade force. Therefore, in order to increase the rotation rate of the housing110, the force applied to the floating blade may be decreased. Alternatively, in order to decrease the rotation rate of the housing110, the force applied to the floating blade may be increased. It will be appreciated that it is typically necessary to maintain some minimum applied force to the floating blade so as not to degrade the steerability of the tool100(the blade force of the floating blade has also been found to effect the steerability of the tool100as is described in more detail in commonly assigned, U.S. application Ser. No. 11/595,054 now U.S. Pat. No. 7,464,770).

In one exemplary embodiment of the invention, the blade force of the floating blade may be controlled by controlling the system pressure of the hydraulic fluid used to extend the blades150. For clarity of exposition, control of the hydraulic fluid pressure will be described for a tool configuration in which blade150A is floating and blades150B and150C are locked in their predetermined positions (as described above). The invention is, of course, not limited in this regard. As described above with respect toFIG. 3, the system pressure in reservoir236may be maintained at a constant pressure (e.g., 750 psi) above well bore pressure via pressure relief valve235. At a system pressure of 750 psi above wellbore pressure, it has been found that the rotation rate of housing110is often less than one revolution per hour (e.g., from about 0.1 to about 1 revolution per hour). In order to increase the rotation rate of the housing110, the system pressure (in reservoir236) may be decreased, for example, by “short-circuiting” high-pressure reservoir236with low-pressure reservoir226through the floating blade150A by opening valve256A.

An exemplary geosteering operation is now described in more detail with respect toFIGS. 6 and 7.FIG. 6depicts a circular cross section of a subterranean borehole having four quadrants (e.g., referred to herein as high side601, right side602, the low side603, and left side604). In one common type of geosteering application, a borehole is routed through an approximately horizontal oil-bearing reservoir (e.g., having an inclination in the range from about 80 to about 100 degrees). A directional drilling tool is configured to change the drilling course when the on-board formation evaluation sensors detect the formation boundary (above or below the directional drilling tool). In such applications, it is advantageous for the azimuthal FE sensor(s) to detect formation contrast between high side601and low side603of the borehole or between the high601and/or low603sides and a non-azimuthal measurement. In this type of geosteering application, FE sensor measurements made towards the right side602and left side604are comparatively less important. As described above, steering tool100may be configured to control the rolling speed (rotation rate) of housing110in the borehole. In the above-described geosteering application, it is desirable for the FE sensors to spend more time in quadrants601and603than in quadrants602and604of the borehole. Therefore, in one exemplary embodiment of the invention, steering tool100may be configured to increase the blade force (of the floating blade) when the FE sensors120begin to enter quadrants601and603and to reduce the blade force when the FE sensors120depart into quadrants602and604so the housing110rotates relatively slowly when the sensors120are in quadrants601and603and relatively quickly when the sensors120are in quadrants602and604.

It will be appreciated that the housing110rotates significantly slower than the drill string. Therefore accelerometers may be advantageously utilized to measure the sensor tool face. The use of gravity-based sensors tend to be advantageous in steering tool100embodiments (as opposed to magnetometers) since the housing is often fabricated from at least some Ferro-magnetic materials. The invention is not limited in this regard, however, since magneto-sensitive devices (e.g. magnetometers) and/or gyroscopic sensors (e.g. mechanical gyro) can be used to obtain tool face angle.

FIGS. 7 and 8depict exemplary closed loop geosteering methods in accordance with the present invention.FIG. 7depicts a more general embodiment, whileFIG. 8depicts a preferred embodiment of the invention. In the method depicted inFIG. 7, the steering tool is deployed in the borehole and the steering tool blades150are extended into engagement with the borehole wall at702. At704, a controller causes the tool face angle (azimuthal position) of the FE sensor to be measured. At706, the controller processes the tool face angle measured at704to acquire (or select) a target rotation rate (or rotation rate range) of the housing110in the borehole. At708, the controller causes the housing to rotate at the target rotation rate (or within the range of rates). In one exemplary embodiment of the invention the controller causes the housing110to rotate at a first ration rate in the borehole when the measured tool face is in a first predetermined range and a second rotation rate when the measured tool face is in a second predetermined range. For example, the controller may cause the housing to rotate at a relatively fast first rotation rate in the range from about 1 to about 15 revolutions per hour when the measured tool face is in a right side or left side quadrant (quadrants602or604inFIG. 6) and at a relatively slow second rotation rate in the range from about 0.1 to about 1 revolution per hour when the measured tool face is in a high side or low side quadrant (quadrants601or603inFIG. 6).

It will be appreciated that the rotation rate of the housing110in the borehole may be controlled by controlling the extendable blades deployed in the housing. For example, in one exemplary embodiment, the housing may be made to rotate at the first rotation rate by causing at least one of the blades to engage the borehole wall at a first radial force and at the second rotation rate by causing the blade(s) to engage the borehole wall at a second radial force (with the first radial force being less than the second radial force). As described above, the rotation rate of the housing110typically decreases with increasing blade force. It will be understood that the blade force applied to the borehole wall may be controlled using either type of directional control mechanism described above in the Background Section of commonly assigned, co-pending U.S. Patent Application Publication 2008/0110674.

In a preferred embodiment of the method depicted inFIG. 7, the blades150are hydraulically actuated and receive hydraulic oil from a central system reservoir (e.g., reservoir236depicted inFIG. 3). In such an embodiment, the controller may cause the housing to rotate at the first rotation rate by causing the hydraulic oil in the system reservoir to be at a first hydraulic pressure. The housing may be made to rotate at the second rotation rate by causing the hydraulic oil in the system reservoir to be at a second hydraulic pressure, wherein the first hydraulic pressure is less than the second hydraulic pressure. It will be appreciated (as described above) that increasing the pressure in the system reservoir tends to increase the blade force and therefore decrease the rotation rate of the housing.

As stated above,FIG. 8depicts a preferred geosteering method in accordance with the present invention. In the method depicted inFIG. 8, the steering tool is deployed in the borehole and the steering tool blades150are extended into engagement with the borehole wall at802where two of the blades are preferably locked in place (in the manner described above with respect toFIG. 3). At804and806, respectively, a controller causes a hydraulic system pressure and the tool face angle of the formation evaluation sensor to be measured. At808, the controller processes the tool face angle measured at806to acquire (or select) a target hydraulic system pressure. At810, the pressure measured at804is compared with the target pressure acquired at808. If the measured pressure is greater than the target pressure, then the controller causes a valve (e.g., valve256A shown onFIG. 3) to be opened which reduces the system pressure (e.g., the pressure in reservoir236). In the most preferred embodiment (when valve256A is opened) the system pressure is reduced by short circuiting high pressure fluid (e.g., the fluid in reservoir236) with lower pressure fluid (the fluid in low-pressure reservoir226) through one of the blades (e.g., blade150A). If the measured system pressure is less than or equal to the target system pressure, the controller waits some predetermined time (e.g., one second) before returning to step804and repeating the above-described process.

After a predetermined time (e.g., 1 second), the blade pressure is measured again and is compared with the target pressure (at814and816). If the pressure measured at814is less than or equal to the target pressure acquired at808, the valve is closed at818and the controller returns to step804at which the hydraulic pressure is again measured after some predetermined time. If the measured pressure remains greater than the target pressure, the valve is left open and the controller waits for a predetermined time before repeating steps814and816.

The target system pressure may be acquired at step808using substantially any suitable protocol. For example, the controller may be preprogrammed to include first and second, upper and lower target system pressures. When the measured tool face of a preselected one of the sensors120is in either of the high side or low side quadrants601or603(FIG. 6), the controller may select the first, upper target system pressure thereby causing the housing110to rotate at a relatively slow rate (e.g., less than one revolution per hour). When the measured tool face is in either of the right side or left side quadrants602or604, the controller may select the second, lower target system pressure thereby causing the housing110to rotate at a relatively faster rate (e.g., greater than one revolution per hour). In this manner, sensors120will more quickly rotate out of quadrants602and604back into quadrants601and603(where they are most needed). It will be appreciated that the invention is not limited to the above-described exemplary embodiment. Those of ordinary skill in the art will readily be able to conceive of and implement other schemes for controlling the rotation rate of steering tool housing110. For example, system pressure/blade force may be selected to be a predefined continuous or semi-continuous function of the measured sensor tool face. In such an exemplary embodiment, the system may be configured, for example, to apply the highest blade force at tool face angles of 0° and 180° and the lowest blade force at tool face angles of 90° and 270° (i.e., the function may have maxima at 0° and 180° and minima at 90° and 270°).

It will further be appreciated that the system pressure may also be controlled via implementing a controllable system valve (e.g., a solenoid valve) in place of (or in parallel with) pressure relieve valve235(FIG. 3). In such a configuration, the method ofFIG. 8is configured to respectively open and close the system valve. In a configuration in which the system valve replaces pressure relief valve235, the system pressure may be controlled over substantially any suitable range of pressures. The invention is expressly not limited to the means by which the hydraulic system pressure is controlled. For example, in other alternative embodiments, the system pressure may be controlled via a controllable pump (e.g., a local piston pump) or other means known in the downhole arts.

It will be understood that the closed loop geosteering methods depicted inFIGS. 7 and 8typically further include additional method steps directed towards acquiring and evaluating formation evaluation measurements and utilizing those measurements to control the direction of drilling (e.g., via changing the position of at least one of the blades). In an exemplary embodiment utilizing first and second circumferentially opposed gamma ray sensors (e.g., sensors120A and120B onFIG. 4A), the difference or ratio between high side and low side counts may be utilized to sense bed boundaries above or below the tool. When the difference or ratio is outside a predetermined range of values (indicative of an approaching bed boundary), the direction of drilling may be appropriately changed so as to stay in the desired formation. For example, a ratio of high side to low side gamma ray counts above a first predetermined threshold may be taken to be indicative of an approaching bed boundary above the steering tool. The tool may thus be configured to change the direction of drilling downward when the count ratio is above the first threshold (e.g., via changing the position of at least one of the blades). Likewise, a ratio of high side to low side counts below a second predetermined threshold may be taken to be indicative of an approaching bed boundary below the steering tool. The tool may thus be configured to change the direction of drilling upward when the count ratio is below the second threshold. Alternatively, a ratio between the high side measurement and a non-azimuthal measurement (made for example as described above via summing or averaging the measurements at each of the FE sensors) and/or a ratio between the low side measurement and a non-azimuthal measurement may be used to determine the location of an approaching bed boundary.

Steering tool embodiments in accordance with the present invention may also be utilized to acquire formation evaluation images, which may be further utilized in geosteering applications. For example, the radial force on at least one of the blades150may be controlled such that housing110rotates at an approximately constant rate in the borehole. In general, a relatively fast, approximately constant rotation rate is desirable for acquiring images. A rotation rate in the range from about 5 to about 30 revolutions per hour has been found to be suitable for such formation evaluation imaging applications. Rotation rates less than about five revolutions per hour tend to be too slow for imaging applications at most serviceable rates of penetration. Rotation rates greater than about 30 revolutions per hour may adversely affect the steerability of the steering tool (since very low blade forces tend to be required). Rotation rates greater than about 30 revolutions per hour also tend to require a large hydraulic fluid pumping capacity in order to continually adjust the position of the blades.

In such imaging applications, formation evaluation measurements may be acquired and correlated with corresponding tool face measurements while the housing110rotates in the borehole. The formation evaluation measurements and corresponding tool face measurements may be used to construct a borehole image using substantially any know methodologies, for example, conventional binning, windowing, or probability distribution algorithms. U.S. Pat. No. 5,473,158 discloses a conventional binning algorithm for constructing a borehole image. Commonly assigned U.S. Pat. No. 7,027,926 discloses a technique for constructing a borehole image in which sensor data is convolved with a one-dimensional window function. Commonly assigned, U.S. patent application Ser. No. 11/881,043 (now U.S. Pat. No. 7,558,675) describes an image constructing technique in which sensor data is probabilistically distributed in either one or two dimensions. It will be appreciated by those of ordinary skill in the art that a borehole image is essentially a two-dimensional representation of a measured formation (or borehole) parameter as a function of sensor tool face and measured depth of the borehole.

The constructed borehole images may be evaluated uphole and/or downhole using techniques known to those of ordinary skill in the art. The evaluated borehole images may then be used as the basis for steering decisions (i.e., blade adjustment decisions). For example, the ratio of high side gamma ray counts to low side gamma ray counts may be obtained from the constructed borehole image and may be used to control the direction of drilling in the manner described above. Moreover, evaluation of the borehole image may advantageously enable a formation dip angle to be determined. The dip angle is known to those of ordinary skill in the art to be the tilt angle of the subterranean formation relative to the surface of the earth. The dip angle acquired from the borehole image may also be used as a basis for steering decisions.

With reference again toFIG. 2, the control modules130and140may include a digital programmable processor such as a microprocessor or a microcontroller and processor-readable or computer-readable programming code embodying logic, including instructions for controlling the function of the steering tool100(including implementing the method embodiments ofFIG. 7and/orFIG. 8). Substantially any suitable digital processor (or processors) may be utilized, for example, including an ADSP-2191M microprocessor, available from Analog Devices, Inc.

In the exemplary embodiments shown above, modules130and140are in electronic communication with pressure sensors262,272A,272B,272C and displacement sensors264,274A,274B,274C. Modules130and140are further in electronic communication with valves235,254A-C, and256A-C. The control modules130and140may further include instructions to receive rotation and/or flow rate encoded commands from the surface and to cause the steering tool100to execute such commands upon receipt. Module140typically further includes at least one tri-axial arrangement of accelerometers as well as instructions for computing gravity tool face and borehole inclination (as is known to those of ordinary skill in the art). Such computations may be made using either software or hardware mechanisms (using analog or digital circuits). Electronic module140may also further include one or more sensors for measuring the rotation rate of the drill string (such as accelerometer deployments and/or Hall-Effect sensors) as well as instructions executing rotation rate computations. Exemplary sensor deployments and measurement methods are disclosed, for example, in commonly assigned, U.S. Patent Publications 2007/0107937 and 2007/0289373.

Electronic module140typically includes other electronic components, such as a timer and electronic memory (e.g., volatile or non-volatile memory). The timer may include, for example, an incrementing counter, a decrementing time-out counter, or a real-time clock. Module140may further include a data storage device, various other sensors, other controllable components, a power supply, and the like. Electronic module140is typically (although not necessarily) disposed to communicate with other instruments in the drill string, such as telemetry systems that communicate with the surface and an LWD tool including various other formation sensors. Electronic communication with one or more LWD tools may be advantageous, for example, in geo-steering applications. One of ordinary skill in the art will readily recognize that the multiple functions performed by the electronic module140may be distributed among a number of devices.