US20110108325A1

US20110108325A1 - Integrating Multiple Data Sources for Drilling Applications

Info

Publication number: US20110108325A1
Application number: US12/941,670
Authority: US
Inventors: Andreas Hartmann; Christian Fulda; Mark Jenkins; Stefan Wessling; Douglas J. Patterson; Ulrich Michael
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 2009-11-11
Filing date: 2010-11-08
Publication date: 2011-05-12
Also published as: WO2011059959A2; WO2011059959A3; BR112012011092A2; NO20120537A1; GB2487337A; GB201208067D0

Abstract

A drilling system makes measurements of at least one drilling parameter such as downhole weight on bit, bit torque, bit revolutions, rate of penetration and bit axial acceleration, and at least one measurement responsive to formation properties. One or more processors use the measurements of drilling parameters and formation properties to adjust drilling parameters.

Description

CROSS-REFERENCES TO RELATED APPLICATIONS

This application claims priority from U.S. Provisional Patent Application Ser. No. 61/260,069 filed on Nov. 11, 2009 and from U.S. Provisional Patent Application Ser. No. 61/371,998 filed on Aug. 9, 2010.

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure
This disclosure relates to systems, devices and methods that utilize dynamic measurements of selected drilling parameters and measurements indicative of the lithology of a formation being drilled for controlling drilling operations.
2. The Related Art
To obtain hydrocarbons such as oil and gas, boreholes are drilled by rotating a drill bit attached at a drill string end. A large proportion of the current drilling activity involves directional drilling, i.e., drilling deviated and horizontal boreholes, to increase the hydrocarbon production and/or to withdraw additional hydrocarbons from the earth's formations. Modern directional drilling systems generally employ a drill string having a bottomhole assembly (BHA) and a drill bit at end thereof that is rotated by a drill motor (mud motor) and/or the drill string. A number of downhole devices placed in close proximity to the drill bit measure certain downhole operating parameters associated with the drill string. Such devices typically include sensors for measuring downhole temperature and pressure, azimuth and inclination measuring devices and sensors that measure the acceleration of the BHA in different directions and the bending moment. The latter data are used to characterize the drilling dynamics of the BHA, which depends on formation properties, the drill bit and the BHA configuration.
Additional downhole instruments, known as logging-while-drilling (“LWD”) tools, are frequently attached to the drill string to determine the formation geology and formation fluid conditions during the drilling operations. Logging-while-drilling (LWD) systems, or Measurement-While-Drilling (MWD) systems, are known for identifying and evaluating rock formations and monitoring the trajectory of the borehole in real time. For example, a resistivity measuring device is attached to determine the presence of hydrocarbons and water. An MWD set of tools is generally located in the lower portion of the drill string near the bit. The tools are either housed in a section of drill collar or formed so as to be compatible with the drill collar. It is desirable to provide information of the formation as close to the drill bit as is feasible. Several methods for evaluating the formation using sensors near the drill bit have been employed. These methods reduce the time lag between the time the bit penetrates the formation and the time the MWD tool senses that area of the formation. Another approach to determine formation or lithology changes has been to use the mechanic measurements available downhole and at the surface, such as measured rate of penetration (ROP) and bit revolutions per minute (RPM) and average or mean downhole weight on bit (WOB) and average or mean downhole torque on the bit (TOR) that are derived from real time in situ measurements made by an MWD tool.
The present disclosure is directed towards the use of measurements of drilling dynamics and measurements indicative of formation lithology for control of drilling operation.

SUMMARY OF THE DISCLOSURE

One embodiment of the disclosure is a method of conducting drilling operations. The method includes conveying a bottomhole assembly into a borehole in the earth formation, making dynamic measurements of at least one drilling parameter, using a formation evaluation (FE) sensor to make at least one FE measurement indicative of a property of the formation, and controlling a drilling operation using the at least one drilling parameter and the at least one FE measurement.
Another embodiment of the disclosure is an apparatus for conducting drilling operations. The apparatus includes a bottomhole assembly configured to be conveyed into a borehole in the earth formation, at least one first sensor configured to dynamically measure at least one drilling parameter at a downhole location, at least one formation evaluation (FE) sensor configured to make at least one FE measurement indicative of a property of the formation, and at least one processor configured to control a drilling operation using the measurement of the at least one drilling parameter and the at least one FE measurement.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings:

FIG. 1 is an elevation view of an exemplary drilling system suitable for use with the present disclosure

FIG. 2 is a block diagram of one exemplary system in accordance with the present disclosure for determining the lithology of a formation while drilling;

FIGS. 3 a and 3 b show exemplary resistivity measurements that may be used for geostopping;

FIG. 4 shows an exemplary cross-plot of downhole torque against resistivity;

FIG. 5 shows an example of a hierarchical clustering tree;

FIG. 6 illustrates the identification of thief zones from resistivity logs along with recorded annular pressures, the cumulative pit and tank volumes and the gamma ray log;

FIG. 7 a shows an exemplary data set recorded using a quadrupole logging tool in a transversely isotropic medium;

FIG. 7 b shows a result of the semblance analysis of the data of FIG. 7 a identifying the slow and fast modes;

FIG. 8 shows an embodiment of the present disclosure using a near-bit gamma ray sensor; and

FIG. 9 shows another embodiment of the present disclosure using a near-bit gamma ray sensor and a resistivity sensor.

DETAILED DESCRIPTION OF THE DISCLOSURE

The teachings of the present disclosure can be applied in a number of arrangements to generally improve the drilling process by using indications of the lithology of the formation being drilled. As is known, formation lithology generally refers to an earth or rock characteristic such as the nature of the mineral content, grain size, texture and color. Such improvements may include reduced drilling time and associated costs, safer drilling operations, more accurate drilling, improvement in ROP, extended drill string life, improved bit and cutter life, reduction in wear and tear on BHA, and an improvement in borehole quality. The present disclosure is susceptible to embodiments of different forms. These are shown in the drawings, and herein will be described in detail, specific embodiments of the present disclosure with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein.
Referring now to FIG. 1, there is shown an exemplary drilling system 20 suitable for use with the present disclosure. As is shown, a conventional rig 22 includes a derrick 24, derrick floor 26, draw works 28, hook 30, and swivel 32 A drillstring 38 which includes drill pipe section 40 and drill collar section 42 extends downward from rig 22 into a wellbore 44. Drill collar section 42 preferably includes a number of tubular drill collar members which connect together, including a measurement-while-drilling (MWD) subassembly including a number of sensors and cooperating telemetry data transmission subassembly, which are collectively referred to hereinafter as “MWD system 46”. The drill string 38 further includes a drill bit 56 adapted to disintegrate a geological formation and known components such as thrusters, mud motors, steering units, stabilizers and other such components for forming a wellbore through the subterranean formation 14. Other related components and equipment of the system 20 are well known in the art and are not described in detail herein.
Also, it should be understood that applications other than rotary drives (e.g., coiled tubing applications) may utilize other equipment such as injectors, coiled tubing, a drilling motor, thrusters, etc. Drilling systems utilizing coiled tubing as the drill string are within the scope of the present disclosure.
The MWD system 46 includes sensors, circuitry and processing firmware and software and algorithms for providing information about desired dynamic drilling parameters relating to the BHA, drill string, the drill bit and downhole equipment such as a drilling motor, steering unit, thrusters, etc. (collectively, a bottomhole assembly or BHA). Exemplary sensors include, but are not limited to, drill bit sensors, an RPM sensor, a weight on bit sensor, sensors for measuring mud motor parameters (e.g., mud motor stator temperature, differential pressure across a mud motor, and fluid flow rate through a mud motor), and sensors for measuring acceleration, vibration, whirl, radial displacement, stick-slip, torque, shock, vibration, strain, stress, bending moment, bit bounce, axial thrust, friction, backward rotation, BHA buckling and radial thrust. Sensors distributed along the drill string can measure physical quantities such as drill string acceleration and strain, internal pressures in the drill string bore, external pressure in the annulus, vibration, temperature, electrical and magnetic field intensities inside the drill string, bore of the drill string, etc. Suitable systems for making dynamic downhole measurements include COPILOT™, a downhole measurement system, manufactured by Baker Hughes Incorporated. Suitable systems are also discussed in “Downhole Diagnosis of Drilling Dynamics Data Provides New Level Drilling Process Control to Driller”, SPE 49206, by G. Heisig and J. D. Macpherson, 1998.
The MWD system 46 can include one or more downhole processors 70. The processor(s) 70 can include a microprocessor that uses a computer program implemented on a suitable machine readable medium that enables the processor to perform the control and processing. The machine readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks. Other equipment such as power and data buses, power supplies, and the like will be apparent to one skilled in the art. In one embodiment, the MWD system 46 utilizes mud pulse telemetry to communicate data from a downhole location to the surface while drilling operations take place. To receive data at the surface, a transducer 60 is provided in communication with mud supply line 54. This transducer generates electrical signals in response to drilling mud pressure variations. These electrical signals are transmitted by a surface conductor 62 to a surface electronic processor 64, which is preferably a data processing system with a central processing unit for executing program instructions, and for responding to user commands. For systems utilizing mud pulse telemetry or other systems having limited data transfer capability (e.g., bandwidth), the system can utilize the downhole processor 70 in conjunction with the surface processor 64. For example, the downhole processor 70 can process the downhole measured data and transmit reduced data and/or signals indicative of the lithology being drilled to the surface. The surface processor 64 can process the surface measured data, along with the data transmitted from the downhole processor 70, to evaluate formation lithology.
In another embodiment, the MWD system 46 utilizes a telemetry system providing relatively high bandwidth; e.g., conductive wires or cables provide in or along the drill string, radiofrequency (RF) or electromagnetic (EM)-based systems, or other systems. In such systems, “raw” or unprocessed data, in addition to or instead of processed data, can be transmitted to the surface processor 64 for processing. In such an arrangement, a downhole processor 70 may not be needed. In another arrangement, the surface measurements are transmitted downhole and the downhole processor 70 processes the surface and downhole data. In this arrangement, only the downhole processor 70 is used to obtain lithological indications. It should therefore be appreciated that a number of arrangements can be used for the processor 205 of FIG. 2; e.g., a surface processor that processes downhole and surface measurements, a downhole processor that processes downhole and surface measurements, and a surface and downhole processor that cooperatively process downhole and surface measurements.
Referring now to FIG. 2, there is shown in block diagram form one exemplary system made in accordance with the present disclosure for controlling drilling operations using measurements indicative of a lithology of a formation being drilled. The system includes a processor or processors 205 that communicate with downhole and surface sensors. The downhole sensors include two types of sensors. The surface sensors include one or more sensors that can dynamically measure drilling parameters such as instantaneous torque, weight on bit, and RPM of the drill bit. For the purposes of the present disclosure, the steering force, equivalent circulation density (ECD), and near bit inclination are also considered drilling parameters. Thus, dynamic measurements can provide greater details as to the behavior of a drill bit, drill string, or BHA during drilling.
The processor 205 uses measurements of drilling dynamics 201. In addition, the processor also uses measurements of formation properties 203. These may include gamma-ray measurements, resistivity measurements, acoustic (sonic)measurements, neutron porosity measurements and/or bulk density measurements. For gamma-ray measurements, the sensor arrangement disclosed in US Patent publication 20100089645 of Trinh et al., having the same assignee as the present disclosure and the contents of which are incorporated herein by reference, may be used. Disclosed therein is a drill bit that includes a bit body and a gamma ray sensor in the bit body. An advantage of this sensor arrangement is that gamma ray measurements indicative of formation lithology are made substantially simultaneously at the bit location. The use of the device of Trinh is not to be construed as a limitation and other arrangements may be used to provide gamma ray measurements.
For resistivity measurements, the sensor arrangement disclosed in U.S. Pat. No. 7,554,329 to Gorek et al., having the same assignee as the present disclosure and the contents of which are incorporated herein by reference, may be used. As disclosed therein, the drillbit and the adjacent portion of the drill collar are used as a focusing electrode for focusing the measure current from a measure electrode on the face or side of the drillbit. This provides the ability to see ahead of and azimuthally around the drillbit. The use of the device of Gorek is not to be construed as a limitation and other arrangements may be used to provide gamma ray measurements. For example, the device disclosed in U.S. Pat. No. 6,850,068 to Chemali et al., having the same assignee as the present application and the contents of which are incorporated herein by reference, may be used.
One embodiment of the disclosure uses, as an acoustic sensor, the quadrupole acoustic tool disclosed in U.S. Pat. No. 6,859,168 of Tang et al., having the same assignee as the present disclosure and the contents of which are incorporated herein by reference, may be used. The logging tool of this invention includes a transmitter conveyed on a drilling collar for exciting a quadrupole signal in a borehole being drilled by a drill bit and a receiver for receiving the signal. The transmitter is operated at a frequency below the cut-off frequency of the quadrupole collar mode. The received signal consists primarily of the formation quadrupole mode which, at low frequencies, has a velocity that approaches the formation shear velocity. The transmitter, in one embodiment, consists of eight equal sectors of a piezoelectric cylinder mounted on the rim of the drilling collar. The value of the cut-off frequency is primarily dependent on the thickness of the drilling collar. Alternatively, the transmitter may be operated to produce both the collar mode and the formation mode and a processor may be used to filter out the collar mode. U.S. patent application Ser. No. 11/502,792 (Patent Publication US 2007/0127314, now abandoned) of Georgi discloses a method of using resistivity measurements to predict overpressured formations ahead of the drillbit.
U.S. Pat. No. 7,650,241 to Jogi et al. having the same assignee as the present disclosure and the contents of which are incorporated herein by reference, teaches the determination of formation lithology using drilling dynamics measurements. Using a database, the processor(s) 205 outputs an indication of the lithology, which can serve a number of purposes, such as optimizing or adjusting drilling parameters, issuing drilling alerts relating to faults, high-pressure zones, geosteering the BHA, etc. In the present disclosure, using lithology measurements and drilling parameter measurements, the lithology is identified 207. In particular, if the lithology sensors are able to see ahead of the sensor or even ahead of the drillbit, changes in lithology may be anticipated and drilling parameters may be adjusted 209.
Turning to FIG. 3 b, an exemplary near bit resistivity measurement is shown. At the depth indicated by 305, there is a change in lithology as indicated by the resistivity curve 301. In this particular instance, it was desired to stop the drilling (“geostopping”) prior to penetration of the formation below depth 305. This basically means doing the geostopping based on the curve 303. As can be seen, identification of the deflection of the resistivity curve from a baseline defined by measurements above the depth 305 is not an easy task. The device of Gorek would have greater sensitivity to an approaching bed boundary, particularly if the boundary is approached at an inclination and azimuthal measurements made during rotation are used.
Formation evaluation measurements may or may not have a “look ahead” capability. The amount of look ahead determines the reference point of the sensor. For an at-bit measurement such as drilling dynamics measurements this should be the bit face. FE measurements are sensitive to the rock volume close to their sensor. Drilling dynamics measurements relate to the dynamic state of the BHA. One important factor determining this state is the bit-rock interaction. Thus it can be said that drilling parameters are sensitive to the rock formation at the bit. When using measurements with a “look ahead” capability, i.e. sensitive close to the bit or ahead of the bit, they may be combined with drilling dynamics measurements. This may be done by combining multiple measurements to derive a single (or multiple) indicators. For instance formation evaluation measurements and drilling dynamics data combined may be used to determine a lithology indicator. Algorithms that may be used include deterministic inversion, neural networks, any statistical classification, multiple regression, etc. For example, U.S. Pat. No. 7,193,414 to Kruspe, having the same assignee as the present disclosure and the contents of which are incorporated herein by reference, discloses the use of an expert system for using formation evaluation measurements for determination of formation lithology. In one embodiment of the present disclosure, the input to the expert system includes drilling dynamics measurements. The expert system described in Kruspe may be implemented as a neural net that has been trained and validated. The same methods may be used if FE sensors are used that are not sensitive at the bit. In this case the different data sources need to be depth-matched based on the time-depth assignment.
An exemplary method for combining a formation evaluation measurement and a drilling dynamic measurement is by using crossplots. Shown in FIG. 4 are crossplots of near-date resistivity (abscissa 401) against downhole torque (ordinate 403). The measurements in an earlier period are shown within the group 405 and are relatively stable. The more recent measurements 407 show a noticeable difference from the earlier measurements and are diagnostic of a lithology change. Identification of such a change in character can be made with more confidence using multiple measurements than with a single measurement as in FIG. 3.
Such a change in behavior can be identified using standard statistical tests. For a single measurement, such as resistivity at bit, a simple implementation is as follows:

- Take a base sample, for instance data from the last 10 min
- Take the current sample, for instance data from the last 2 min
- Compute mean and standard deviation for both samples
- Test hypotheses whether both samples belong to the same population, for instance use student t-test
  - Compute test measure T from mean and standard deviation
  - Compute significance level t_t,kfor defined significance level a (usually 0.05) and number of data points
  - If T>t_a,k, with (1−α) confidence (i.e. 95% for α=0.05) the samples are not from the same population i.e. the formation is changing
  - set formation change flag
- If the flag is set, display a warning.

When multiple data measurements are used, the problem is somewhat more complicated. In principle, with a total of n₁drilling dynamics measurements and n₂formation evaluation measurements, it is possible to define a multivariate distribution of n₁+n₂dimensions characterizing the measurements and doing a statistical test to see if the distribution over a first time interval is different from the distribution over a second time interval, a problem arises in having a sufficient number of samples to get a meaningful estimate of the multivariate distributions. Accordingly, in one embodiment of the disclosure, a clustering of the data is done. This may be a hierarchical clustering, such as that illustrated in FIG. 5. Each data sample represents drilling dynamics and formation evaluation measurements. On the left of the plot, we start with each data sample as being in a class by itself. Samples are then linked into larger and larger clusters by using a measure of distance such as a Euclidean distance. In one embodiment of the disclosure, distances between clusters are determined by the greatest distance between any two samples in two clusters. This method is appropriate when, as in this case, the samples naturally form distinct groups (e.g., Lithology A and Lithology B, or Continue drilling and Stop drilling). The choice of the particular method of clustering is not be construed as a limitation and other methods known in the art could be used.
Another embodiment of the disclosure is directed towards using downhole drilling dynamics and formation evaluation data to test a strategy for using losses for fracture gradient calibration. The strategy includes the detection of losses, the identification of the zones where losses took place (thief zones), and the characterization of thief zones. Losses can result from initiating fractures in the borehole wall whenever the annular pressure exceeds the load the borehole wall can bear. For undamaged borehole walls, the maximum load before fractures are initiated is the least principle near-field stress (which is re-distributed) around the borehole plus the tensile rock strength (which needs to be neglected when the borehole wall is damaged or if fractures already exist). Although fracture initiation may not necessarily result in significant losses, the propagation of the fracture into the far-field formations can be important. Losses caused by propagating fractures are thus encountered whenever the annular pressure exceeds the far-field minimum principle stress (existence of fractures presumed). The observation of mud losses can therefore be used to calibrate the fracture gradient. The losses indicate that the annular pressure exceeded the far-field minimum principle stress, provided that other causes such as faults or naturally fractured formations can be excluded.
FIG. 6 shows a plot 601 of the drilling depth (ordinate in the top plot) against time. Also shown are several resistivity logs, collectively denoted by 603, and the gamma ray log 605. The second plot shows the cumulative mud losses in the borehole 607 as a function of time and the third plot shows the ECD 609. The ECD is defined in the Schlumberger Oilfield Glossary as:

- The effective density exerted by a circulating fluid against the formation that takes into account the pressure drop in the annulus above the point being considered.
  Attention is drawn to the time intervals 611, 613 and the corresponding depth intervals 611′, 613′. In this interval, particularly in the deeper interval, there is considerable leakage of mud into the formation as indicated by the curve 607. The ECD also drops in these intervals as indicated by 609. In these intervals, there is a separation of the resistivity logs 603. Specifically, the high frequency resistivity measurements are greater than the low frequency resistivity measurements. This is consistent with invasion of the formation by the nonconductive borehole mud that would have a greater effect on the shallow (high frequency) measurements than on the deep (low frequency) measurements.

One objective in conducting drilling operations is to maintain the ECD below the load capacity of the borehole wall. This is done by adjusting the flow rate and/or the mud weight at the surface while, at the same time, avoiding a blowout of the well due to insufficient borehole pressure. Identification of zones of weakness plays an important role in this. Rapid identification of these zones will be facilitated by having the resistivity measurement at bit, at the same time as the ECD information. In another setup, a change in the dynamic forces on the BHA is observed when drilling into the weak zone. This gives an additional indicator of the approaching zone.
For this particular well, the shear velocity logs were not processed to specifically identify fractures. For MWD measurements, the quadrupole logging tool of Tang discussed above is used. It is well known in the art that the effect of aligned fractures in the subsurface is to produce a transverse isotropy in the velocity of propagation of shear waves. This can manifest itself in two ways. One is a variation in the velocity of propagation with the direction of propagation. The other is a splitting of shear waves into a “fast mode” and a “slow mode” depending upon the direction of polarization. Specifically, shear waves propagating with a polarization parallel to the fracture planes have a higher velocity than shear waves propagating with a polarization at right angles to the fracture planes.
FIG. 7 a shows a shot panel recorded with a quadrupole logging tool in a transversely isotropic medium. In this particular example, the transverse isotropy was due to layering and not due to fracturing, but the mathematics of the wave propagation is the same. FIG. 7 b shows a result of a semblance analysis of the data of FIG. 7 a in which a fast mode and a slow mode can clearly be seen.
In one embodiment of the disclosure, seismic sensors may be used to conduct a vertical seismic profile (VSP). The VSP has a capability of looking ahead of the drillbit, and the VSP data may be processed using known methods to estimate shear velocities ahead of the drillbit. These shear velocities are diagnostic of fracturing in the formation. Shear velocities ahead of the drillbit may also be estimated using a method disclosed in U.S. patent application Ser. No. 12/139,179 of Mathiszik et al., (US Patent Publication 2008/312839) having the same assignee as the present disclosure and the contents of which are incorporated herein by reference. In the method described by Mathiszik: a downhole acoustic logging tool is used for generating a guided borehole wave that propagates into the formation as a body wave, reflects from an interface and is converted back into a guided borehole wave. Guided borehole waves resulting from reflection of the body wave are used to image a reflector.
Fracturing of the formation may also be detected using commonly used imaging instruments, such as resistivity, nuclear and acoustic images of the borehole using known devices and methods.
Estimates of the rock strength may be made using bulk density measurements and/or porosity measurements. The porosity measurements may be obtained using a nuclear source or by nuclear magnetic resonance measurements.
Turning now to FIG. 8, shown therein is lower end of a modular drilling assembly. The modular drilling motor is depicted by 801. A modular thread connection is indicated by 803. A modular gamma ray sensor is indicated by 805 and the steering unit is indicated by 807. This arrangement of the gamma ray sensor is only for exemplary purposes. In one embodiment of the disclosure, the near-bit gamma ray sensor 805 may be run without a modular drilling motor 801. In an alternate embodiment of the disclosure, the gamma ray sensor may be closer to the drillbit, e.g., in the bit box 809. A natural-gamma ray detector suitable for high temperature using a wide band-gap photodiode has been disclosed in U.S. patent application Ser. No. 12/694,993 of Nikitin et al., having the same assignee as the present disclosure and the contents of which are incorporated herein by reference.
FIG. 9 shows another configuration of the lower end of the drilling assembly. A resistivity at bit sensor 904 is positioned just above the near-bit gamma ray module 805. The modular thread sub 803 is shown with the threads exposed. The location of the resistivity at bit sensor 904 relative to the near-bit gamma ray module 805 is not to be construed as a limitation. The sensor 904 could be positioned below the gamma ray module 805.
The arrangement shown in FIG. 9 may be used for making the gamma ray measurements and the resistivity measurements disclosed above and used for controlling drilling operations.
The processing of the measurements made may be done by the surface processor 64, by a downhole processor, or at a remote location. The data acquisition may be controlled at least in part by the downhole electronics. Implicit in the control and processing of the data is the use of a computer program on a suitable machine readable-medium that enables the processors to perform the control and processing. The machine-readable medium may include ROMs, EPROMs, EEPROMs, flash memories and optical disks. The term processor is intended to include devices such as a field programmable gate array (FPGA).

Claims

1. A method of conducting drilling operations, the method comprising:

conveying a bottomhole assembly into a borehole in the earth formation;

making dynamic measurements of at least one drilling parameter at a downhole location;

using a formation evaluation (FE) sensor to make at least one FE measurement indicative of a property of the formation; and

controlling a drilling operation using the at least one drilling parameter and the at least one FE measurement.

2. The method of claim 1 wherein the at least one drilling parameter is selected from a group consisting of: (i) downhole weight on bit, (ii) downhole torque on bit, (iii) drill bit revolution, (iv) drill string revolution, (v) axial acceleration, (vi) tangential acceleration, (vii) lateral acceleration, (viii) torsional acceleration, (ix) borehole pressure, (x) lateral vibration, (xi) a bending moment, and (xii) an equivalent circulating density.

3. The method of claim 1, wherein the at least one FE measurement is selected from: (i) a resistivity measurement, (ii) a gamma ray measurement, (iii) a shear velocity measurement made by a logging tool, (iv) a shear velocity estimated using a vertical seismic profile, (v) a borehole image. (vi) a porosity measurement, and (vii) a density measurement.

4. The method of claim 1 wherein the at least one FE measurement is indicative of a property of the formation ahead of the drillbit.

5. The method of claim 1 wherein controlling the drilling operation further comprises stopping further penetration of the BHA into the formation.

6. The method of claim 1 wherein controlling the drilling operation further comprises at least one of: (i) selecting a mud weight, and (ii) adjusting a flow rate of mud.

7. The method of claim 1 wherein controlling the drilling operation further comprises at least one of: (i) controlling a direction of drilling, (ii) selecting a casing point, and (iii) selecting a coring point.

8. The method of claim 1 wherein using the at least one drilling parameter and the at least one FE measurement for controlling the drilling operation further comprises comparing measurements made over a first time interval and measurements made over a second time interval of the at least one drilling parameter and the at least one FE measurement.

9. The method of claim 8 wherein comparing the measurements made over the first time interval and the measurements made over the second time interval further comprises performing a statistical analysis of the measurements.

10. The method of claim 8 wherein the statistical analysis is selected from: (i) a t-test, and (ii) a cluster analysis.

11. The method of claim 1 further comprising using the at least one drilling parameter and the at least one FE measurement for characterizing a thief zone wherein a loss of drilling fluid is encountered.

12. The method of claim 11 further comprising using an annular pressure in the borehole as an indication of a far-field minimum principal stress in the thief zone.

13. The method of claim 12 further comprising using the annular pressure for calibrating a fracture gradient in the borehole.

14. An apparatus for conducting drilling operations, the apparatus comprising:

a bottomhole assembly configured to be conveyed into a borehole in the earth formation;

at least one first sensor configured to dynamically measure at least one drilling parameter at a downhole location;

at least one formation evaluation (FE) sensor configured to make at least one FE measurement indicative of a property of the formation; and

at least one processor configured to control a drilling operation using the measurement of the at least one drilling parameter and the at least one FE measurement.

15. The apparatus of claim 14 wherein the at least one drilling parameter is selected from a group consisting of: (i) downhole weight on bit, (ii) downhole torque on bit, (iii) drill bit revolution, (iv) drill string revolution, (v) axial acceleration, (vi) tangential acceleration, (vii) lateral acceleration, (viii) torsional acceleration, (ix) borehole pressure, (x) lateral vibration, (xi) a bending moment, and (xii) an equivalent circulating density.

16. The apparatus of claim 14, wherein the at least one FE sensor is selected from: (i) a resistivity sensor, (ii) a gamma ray sensor, (iii) a shear velocity sensor, and (iv) a borehole imaging tool, (v) a porosity sensor, and (vi) a density sensor.

17. The apparatus of claim 14 wherein the drilling operation that the at least one processor is configured to control further comprises stopping further penetration of the BHA into the formation.

18. The apparatus of claim 14 wherein the drilling operation that the at least one processor is configured to control further comprises at least one of: (i) selecting a mud weight, (ii) controlling a direction of drilling, (iii) selecting a casing point, and (iv) selecting a coring point.

19. The apparatus of claim 14 wherein the at least one processor is further configured to control the drilling operation by further comparing measurements made over a first time interval and measurements made over a second time interval of the at least one drilling parameter and the at least one FE measurement.

20. The apparatus of claim 19 wherein the at least one processor is further configured to compare the measurements made over the first time interval and the measurements made over the second time interval by further performing a statistical analysis of the measurements.

21. The apparatus of claim 20 wherein the statistical analysis performed by the at least one processor is selected from: (i) a t-test, and (ii) a cluster analysis.

22. The apparatus of claim 14 wherein the at least one formation evaluation sensor further comprises a gamma ray sensor positioned above a steering unit.

23. The apparatus of claim 22 wherein the at least one formation evaluation sensor further comprises a wide-band gap photodiode positioned in a bit box.