U.S. patent application number 12/941670 was filed with the patent office on 2011-05-12 for integrating multiple data sources for drilling applications.
This patent application is currently assigned to Baker Hughes Incorporated. Invention is credited to Christian Fulda, Andreas Hartmann, Mark Jenkins, Ulrich Michael, Douglas J. Patterson, Stefan Wessling.
Application Number | 20110108325 12/941670 |
Document ID | / |
Family ID | 43973311 |
Filed Date | 2011-05-12 |
United States Patent
Application |
20110108325 |
Kind Code |
A1 |
Hartmann; Andreas ; et
al. |
May 12, 2011 |
Integrating Multiple Data Sources for Drilling Applications
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.
Inventors: |
Hartmann; Andreas; (Celle,
DE) ; Fulda; Christian; (Sehnde, DE) ;
Jenkins; Mark; (Celle, DE) ; Wessling; Stefan;
(Hannover, DE) ; Patterson; Douglas J.; (Spring,
TX) ; Michael; Ulrich; (Hannover, DE) |
Assignee: |
Baker Hughes Incorporated
Houston
TX
|
Family ID: |
43973311 |
Appl. No.: |
12/941670 |
Filed: |
November 8, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61260069 |
Nov 11, 2009 |
|
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61371998 |
Aug 9, 2010 |
|
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Current U.S.
Class: |
175/26 ; 175/24;
175/40 |
Current CPC
Class: |
E21B 49/005 20130101;
E21B 49/003 20130101 |
Class at
Publication: |
175/26 ; 175/40;
175/24 |
International
Class: |
E21B 44/00 20060101
E21B044/00; E21B 47/12 20060101 E21B047/12; E21B 7/06 20060101
E21B007/06; E21B 47/02 20060101 E21B047/02 |
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.
Description
CROSS-REFERENCES TO RELATED APPLICATIONS
[0001] 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
[0002] 1. Field of the Disclosure
[0003] 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.
[0004] 2. The Related Art
[0005] 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.
[0006] 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.
[0007] 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
[0008] 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.
[0009] 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
[0010] 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:
[0011] FIG. 1 is an elevation view of an exemplary drilling system
suitable for use with the present disclosure
[0012] 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;
[0013] FIGS. 3a and 3b show exemplary resistivity measurements that
may be used for geostopping;
[0014] FIG. 4 shows an exemplary cross-plot of downhole torque
against resistivity;
[0015] FIG. 5 shows an example of a hierarchical clustering
tree;
[0016] 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;
[0017] FIG. 7a shows an exemplary data set recorded using a
quadrupole logging tool in a transversely isotropic medium;
[0018] FIG. 7b shows a result of the semblance analysis of the data
of FIG. 7a identifying the slow and fast modes;
[0019] FIG. 8 shows an embodiment of the present disclosure using a
near-bit gamma ray sensor; and
[0020] 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
[0021] 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.
[0022] 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.
[0023] 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.
[0024] 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.TM., 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.
[0025] 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.
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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.
[0030] 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.
[0031] 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.
[0032] Turning to FIG. 3b, 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.
[0033] 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.
[0034] 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.
[0035] 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: [0036] Take a base
sample, for instance data from the last 10 min [0037] Take the
current sample, for instance data from the last 2 min [0038]
Compute mean and standard deviation for both samples [0039] Test
hypotheses whether both samples belong to the same population, for
instance use student t-test [0040] Compute test measure T from mean
and standard deviation [0041] Compute significance level t.sub.t,k
for defined significance level a (usually 0.05) and number of data
points [0042] If T>t.sub.a,k, with (1-.alpha.) confidence (i.e.
95% for .alpha.=0.05) the samples are not from the same population
i.e. the formation is changing [0043] set formation change flag
[0044] If the flag is set, display a warning.
[0045] When multiple data measurements are used, the problem is
somewhat more complicated. In principle, with a total of n.sub.1
drilling dynamics measurements and n.sub.2 formation evaluation
measurements, it is possible to define a multivariate distribution
of n.sub.1+n.sub.2 dimensions 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.
[0046] 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.
[0047] 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: [0048] 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.
[0049] 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.
[0050] 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.
[0051] FIG. 7a 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. 7b shows a result of a semblance analysis of the data of
FIG. 7a in which a fast mode and a slow mode can clearly be
seen.
[0052] 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.
[0053] 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.
[0054] 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.
[0055] 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.
[0056] 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.
[0057] 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.
[0058] 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).
* * * * *