Note: Descriptions are shown in the official language in which they were submitted.
CA 02547584 2001-09-19
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METHOD, SYSTEM AND TOOL FOR RESERVOIR EVALUATION AND WELL
TESTING DURING DRILLING OPERATIONS
This is a division of co-pending Canadian Patent Application
No. 2,448,404 filed on September 19, 2001.
Field of the Invention
The present invention relates generally to testing and evaluating a section
of reservoir intersected during the well construction process. More
particularly,
the present invention relates to methods, systems and tools used in testing
and
evaluation of a subsurface well formation during drilling of the wellbore.
Seiting of the Invention
A reservoir is formed of one or more subsurface rock formations
containing a liquid and/or gaseous hydrocarbon. The reservoir rock is porous
and permeable. The degree of porosity relates to the volume of liquid
contained
within the reservoir. The permeability relates to the reservoir fluids'
ability to
move through the rock and be recovered for sale. A reservoir is an invisible,
complex physical system that must be understood in order to determine the
value
of the contained hydrocarbons.
The characteristics of a reservoir are extrapolated from the small portion
of a formation exposed during the well drilling and construction process.
It is particularly important to obtain an evaluation of the quality of rock
CA 02547584 2007-02-28
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(formation) intersected during well construction. Even though a large body
of data may have been compiled regarding the characteristics of a specific
reservoir, it is important to understand the characteristics of the rock
intersected by a specific wellbore and to recognize, as soon
as possible during the process of well construction, the effective
permeability and
permeability differences of the formation intersected during well
construction.
The present invention is primarily directed to wellbore and formation
evaluation while drilling "underbalanced". Underbalanced drilling is a well
construction process defined as a state in which the pressure induced by the
weight of the drilling fluid (hydrostatic pressure) is less than the actual
pressure
within the pore spaces of the reservoir rock (formation pressure). In a more
conventional process, the well is typically drilled "overbalanced". In an
overbalanced drilling process, the pressure induced by the weight of the
drilling
fluid (hydrostatic pressure) is greater than the actual pore pressure of the
reservoir rock.
During underbalanced well construction, the fluids within the pore spaces
of the reservoir rock flow into the wellbore. Because flow is allowed to enter
the
wellbore, the fluid flow characteristics of the formation are more easily
observed
and measured. During overbalanced drilling, the drilling fluid may enter the
formation from the wellbore. While this overbalanced flow may be evaluated to
assess formation properties, it is more difficult to quantify fluid losses to
the
formation than it is to quantify fluid gains from the formation.
CA 02547584 2001-09-19
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There are significant benefits obtained from the application of
underbalanced well construction techniques. The rate of penetration or speed
of
well construction is increased. The incidence of drill pipe sticking is
decreased.
Underbalanced operations prevent the loss of expensive drilling fluids.
An understanding of the reservoir being penetrated during the well
construction process requires direct and indirect analysis of the information
obtained in and from the well. Core analysis and pressure, volume, temperature
(PVT) analyses of the reservoir fluids are measurements and testing performed
in
a laboratory after the wellbore has been drilled. This process of formation
evaluating is both costly and time-consuming. Also, it is not practical to
perform
core analysis and PVT studies on every well constructed within a reservoir.
During drilling of a wellbore, important information can be determined by
evaluating the fluids flowing to the well surface from the formation
penetrated by
the wellbore. The amount of gas included in the surface flow is particularly
important in evaluating the formation producing the gas. The volume of gas per
unit of time, or flow rate, is a critical parameter. The rate of gas flow from
the
formation is affected by the back-pressure exerted through the wellbore. The
information desired for a particular formation or layer is the flow rate
capacity
during expected flowing production pressure. The best measure of this flow
rate
occurs at the flowing production pressure, however, conventional gas flow
measuring instruments require flow restricting orifices in performing flow
measurements. Instruments using differential orifices as the basis for flow
CA 02547584 2001-09-19
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management are accurate only within a relatively narrow range of flow.
Sporadic
flow changes associated with penetration of different pressured or flowing
formations can produce flow rates outside the accuracy limits of the measuring
instrument. Surface measurements of gas flow are, consequently, performed at
pressures that are different from normal flowing pressures and the results do
not
accurately indicate the gas flow potential of the formation. The procedures
commonly employed to measure surface flow during drilling or constructing a
well
that restrict the flow as a part of the gas flow rate measurement reduce the
accuracy of evaluations of formation capacity based upon such measurements.
Conventional instruments that measure flow without restricting the flow are
typically incapable of making precise measurements. These instruments, which
generally use a Venturi tube in the flow line, produce unduly broad
indications of
flow rates.
Indirect analysis of information requires reference to well logs that are
recorded during well construction. A well log is a recording, usually
continuous,
of a characteristic of a formation intersected by a borehole during the well
construction process. Generally, well logs are utilized to distinguish
lithology,
porosity, and saturations of water, oil and gas within the formation.
Permeability
values for the formation are not obtained in typical indirect analysis. An
instrument for repeated formation tests (RFT) also exists. The RFT instrument
can indicate potentially provided permeability within an order of magnitude of
CA 02547584 2001-09-19
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correctness. Well logging can account for as much as 5 to 15 percent of the
total
well construction cost.
Another means of formation testing and evaluation is the process of drill
stem testing. Drill stem testing requires the stopping of the drilling
process,
logging to identify possible reservoirs that may have been intersected,
isolating
each formation of each intersected reservoir with packers and flowing each
formation in an effort to determine the flow potential of the individual
formation.
Drill stem testing can be very time consuming and the analysis is often
indeterminate or incomplete. Generally, during drill string testing, the
packers are
set and reset to isolate each reservoir intersected. This may lead to
equipment
failures or a failure to accurately obtain information about a specific
formation.
Because each formation is tested as a whole, the values or data obtained
provide an average formation value. Discrete characteristics within the
formation
must be obtained in another manner. The discrete characteristics within a
layer
of the formation are generally inferred from traditional well logging
techniques
and/or from core analysis. Well logging and core analyses are expensive and
time-consuming. The extensive time involved in determining the permeability
(productability) of each intersected reservoir layer in a wellbore through
multiple
packer movements and multiple flow and pressure buildup measurements
required during a drill stem test make the process expensive and undesirable.
CA 02547584 2007-02-28
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Summary of the Invention
It is an object of the present invention to provide a method, a system and
tool for obtaining information about a formation while constructing a wellbore
designed to intersect the formation. One characteristic of the formation that
determines the productability of the well is permeability. During production,
the
fluid flows through the medium of the reservoir rock pores with greater or
lesser
difficulty, depending on the characteristics of the porous medium. The
parameter
of "permeability" is a manager used to describe the ability of the rock to
allow a
fluid to flow through its pores. Permeability is expressed as an area.
However,
the customary unit of permeability is the millidarcy, 1 mD = 0.987 x 10-15m2.
Permeability is related to geometric shape of flow passages, flow rate,
differential
pressure, and fluid viscosity.
Parameters such as bottomhole temperature and pressure are acquired
through a bottomhole assembly during actual drilling operations and the
acquired
values are transmitted to the surface.
In accordance with one aspect of the present invention there is provided a
method for evaluating a formation characteristic in a well having a wellbore
for
intersecting a subsurface formation and being drilled from a wellbore surface
with
a drill bit carried at the end of a drill string, comprising: establishing a
measuring
system having measuring instruments for measuring a fluid flowing into and out
of said wellbore; forming a closed fluid flow system extending from said
wellbore
surface through said drill string and returning through an annulus between
said
wellbore and said drill string back to said wellbore surface whereby fluids
injected
into said drill string at said wellbore surface travel into and out of said
wellbore
through a confined flow passage defined in part by said drill string and
annulus;
measuring the flow of the fluid injected through the drill string into said
closed
fluid flow system with said measuring instruments; measuring the flow of the
fluid
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returning through said annulus from said closed fluid flow system with said
measuring instruments; making a calibration comparison of the measured flow of
the fluid injected into said closed fluid flow system with the measured flow
of fluid
returning from said closed fluid flow system; calibrating said measuring
system
as a function of the calibration comparison to form a calibrated measuring
system; measuring, with said calibrated measuring system, the fluid injected
into
said drill string from the wellbore surface; measuring, with said calibrated
measuring system, the fluid returning to the wellbore surface from said
annulus;
establishing, at a first subsurface wellbore location, a first formation
parameter
value associated with said formation; and correlating the calibration
measurements of fluid with said first formation parameter value for
determining a
characteristic of said formation at said first subsurface wellbore location.
In accordance with another aspect of the present invention there is
provided a downhole tool for connection with a drill bit in a drill string for
measuring a variable parameter in a wellbore while said wellbore is being
constructed, comprising: a longitudinally extending tool body having an
internal
passage for conveying fluid between first and second longitudinal ends of said
tool body; one or more longitudinally extending fluid recesses in said tool
body
external to said internal passage for receiving fluid to be measured; and
energy
transducers carried by said tool body for evaluating a fluid contained in said
fluid
recesses.
In accordance with yet another aspect of the present invention there is
provided a system having a bottomhole measuring instrument secured to a drill
string and bit for detecting a kick in a welibore of a well being drilled into
a
subsurface formation, comprising: a bottomhole measuring instrument having
an axially extending tool body and a central, axially developed passage for
conveying fluid between first and second axial ends of said tool body,
radially
and axially extending, circumferentially spaced blades carried on an external
CA 02547584 2007-02-28
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surface of said tool body, fluid receiving recesses defined between said
circumferentially spaced blades for receiving fluid located in an area
intermediate
said external surface of said tool body and the wellbore, energy transducers
carried by said blades for evaluating fluid contained in said fluid receiving
recesses, and a kick signaling system responsive to said transducer to
evaluate
said fluid contained in said fluid receiving recesses for signaling the
occurrence of
a kick in said well.
In accordance with still yet another aspect of the present invention there is
provided a method for evaluating a subsurface formation traversed by a
wellbore
constructed from a well surface with a drill bit carried at the end of a drill
string,
comprising: establishing a measuring system for measuring a fluid injection
rate
of fluid injected into the drill string from the well surface; taking a first
measurement of the rate of fluid flow between said wellbore and said formation
with a subsurface flow measurement tool carried on the drill string;
determining a
first location within said wellbore where said first rate of fluid flow is
measured;
determining the fluid injection rate while said first measurement is taken;
deepening said borehole with said drill bit, taking a second measurement of
the
rate of fluid flow between said wellbore and said formation with said
subsurface
flow measurement tool; determining a second location within said wellbore
where said second rate of fluid flow is measured; determining the fluid
injection
rate while said second measurement is taken; and correlating the fluid
injection
rates into the drill string and the locations within said wellbore where said
measurements are taken to determine a permeability change between said first
and second locations.
A feature of the present invention is the use of an ultrasonic gas flow
meter in the surface measurements of gas being produced from the formation to
permit unrestricted flow measurements that accurately reflect the formation's
flow
characteristics. A chromatograph is used in the surface measurements of
CA 02547584 2007-02-28
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annular fluid flow to precisely identify constituents of the flow. The results
of the
measurement assist in making well construction decisions as the well is being
drilled.
In the preferred embodiment of the tool, several types of transducers are
deployed along the tool's external surface to provide a large number of
different
well fluid measurements. The increased number of measurements permits
significant improvement in the accuracy of the flow rate measurements and
other
measurements made by the tool.
Brief Description of the Drawings
Figure 1 is a schematic illustration of a system of the present invention
used to evaluate a subsurface formation being intersected by a wellbore during
well construction;
Figure 2 is an elevation of an integral blade stabilizer body having energy
measurement transducers used for subsurface measurements while drilling;
Figure 3 is a partial cross section taken along the line 2-2 of Figure 1
illustrating the placement of three different types of energy transducers or
sensors integrated into the drilling stabilizer of Figure 1;
Figure 3A is an enlarged view of a focusing notch employed with the
induction transmitters of the present invention; and
Figure 3B is an enlarged view of illustrating details in the construction of
the capacitance transducers of the present invention.
CA 02547584 2001-09-19
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Detailed Description of the Illustrated Embodiments
Figure 1 illustrates a system of the present invention indicated generally at
10.
The system 10 is employed to determine the permeability of a formation F that
is to be
penetrated by a wellbore B. A drilling assembly comprising a bit 11, drilling
stabilizer
12, subsurface measuring and recording instrument 13 and drill string 14
extend from
the wellbore B to the wellbore surface T: Only a portion of the bottomhole
assembly is
illustrated in Figure 1. The projected wellbore trajectory is indicated by a
dotted line
section 15.
A measuring system 20 used in the evaluation of a formation F is equipped with
an inlet fluid measuring section 21, an outlet measurement section 22 and a
calibrated
instrument analysis section 23. The measuring system 20 measures and evaluates
the
fluids flowing into the wellbore B through the drill string 14 and measures
and evaluates
the fluids retuming to the top or surface of the welibore T through an annulus
A formed
between the drill string and the wellbore. As used herein, reference to
measuring or
evaluating "flow" of a fluid is intended to include measurement or evaluation
of
characteristics of the fluid such as temperature, pressure, resistivity,
density,
composition, volume, rate of flow and other variable characteristics or
parameters of
the fluid.
The calibrated enalysis section 23 may be supplemented with subsurface
parameter values obtained from a subsurface values section 24. The data from
the
sectiort 24 are delivered from either a data resource 25 or from an actual
downhole
measurements section 26. Data provided by the data resource section 25 may be
data
taken from historical data sources 25a, such as analogous or similar wells or
the data
may be derived from a computer data model 25b that performs mathematical
CA 02547584 2001-09-19
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calculations, or determines data from other inferential processes. The actual
downhole
measurements are provided through a real-time system section 27 or a near real-
time
system section 28.
In applying the method of the present invention to a system in which
subsurface
flow values are to be inferred or deduced from measurements or assumed values
of
related parameters, the system 20 is calibrated and checked before the
welibore B is
extended into the formation F. This step in the procedure assists in
determining system
noise and in determining circulating system responses to changes in the back-
pressure
in the annulus A.
The system calibration process and checking are preferably performed between
5 and 25 meters. above the anticipated top of the formation F. The top of the
formation
F may be determined using a geological marker from an offset well, seismic
data or
reservoir contour mapping. During the calibration process, a closed fluid flow
system
is established by the drilling assembly in the wellbore B such that fluids
introduced into
the drill string 14 travel through the drilling assembly 14, 13, 12, 11, and
exit the drilling
assembly through the bit 11 where they are returned to the well surface T
through the
annulus A. Only fluids introduced into the drill string 14 flow through the
closed system
during the calibration and checking process.
The calibration performed by circulating a known quantity and density of a
known fluid (gases included) while the drilling assembly and any downhole
sensing
equipment carried in the drilling assembly are deployed within the wellbore B.
A
material balance relating the injected fluids to the returned fluids is
preferably employed
in the calibration process. The calibration process is employed to establish a
standard
CA 02547584 2001-09-19
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or control to detect or determine changes in measurements that result from
encountering a productive formation environment.
In a preferred method of calibration, the following parameters are measured
for
a minimum of three different back-pressure values obtained at the annulus A
while
fluids are circulating through the system:
1) injection: pressures, temperatures and rates;
11) bottomhole: annulus pressures and temperatures;
111) return: pressures, temperatures and rates; and
IV) C 1 to C6 hydrocarbon percentage over a period of 1.1 to 15 wellbore
circulation volumes.
The time required for the fluid to complete circulation through the drilling
assembly and return to the surface through the annulus is monitored and
recorded. In
a preferred method, a circulation time measurement is performed with the
assistance
of a tracer added to the injection fluid stream entering the drill pipe 11 at
the well
surface T. The elapsed time from injection of the tracer until reappearance of
the tracer
in the fluid returns at the well surface annulus indicates the circulation
time. The tracer
material may be a carbide, or an inert substance such as neon gas, or a short
half-life
radioactive material or other suitable material.
After calibration and system checking are performed, the drilling operation is
resumed and the drilling assembly is used to extend the wellbore into the
formation F.
During extension of the wellbore, the rate of penetration is preferably
maintained at a
rate below 25 meters per hour. The weight on bit and rotary or bit motor
speeds are
maintained as constant as possible to enhance the accuracy of the results of
the
system measurements.
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In performing the method of the present invention during underbalanced
drilling
conditions, it is preferable to maintain an underbalanced bottomhole pressure
between
100 and 2000 psi below the anticipated pressure of the formation F. The
bottomhole
pressure can be adjusted by manipulation of the drilling fluid densities, pump
rates and
annular back-pressures.
The point at which the drill bit 11 encounters the top of the formation F may
be
determined by closely monitoring the system 20 for any significant change in
the
bottomhole pressure, bottomhole temperature, C1 or surface flow rates. Once
the top
of the formation F has been traversed, an additional 1 to 5 meters of welibore
depth is
drilled into the formation and the drilling is stopped as fluid circulation is
maintained.
In an underbalanced condition, reservoir flow and pressure response are
established while injecting fluid into the drill string 14 from the surface
and combining
the injected fluids with fluids flowing from the reservoir F into the weilbore
B. The
combined injection and formation fluids flow through the annulus A to the well
surface
T. During this step, the following sensor point measurements are performed:
I) injection: pressures, temperatures and rates;
II) bottomhole: annulus pressures and temperatures;
111) return: pressures, temperatures and rates; and
IV) Cl to C6 hydrocarbon percentage over a period of 1.1 to 15 wellbore
circulation volumes.
The measurements I)-tV) are made and recorded for a preferred period of time
equivalent to 1.5 to 15 times the "bottoms up" time. "Bottoms up" time is the
time
required to flow fluid at the bottom of the wellbore to the well surface. Once
a stabilized
annular flow through the annulus A has been established, the back-pressure in
the
CA 02547584 2001-09-19
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annulus is increased to achieve a second underbalanced flowing condition. If
the
annular flow does not stabilize at this increased back-pressure, the back-
pressure is
reduced by 25 percent and the annular flow is maintained for 1.5 to 15 times
the
bottoms up time to test for stabilization of the annular flow.
The next step in the method is to reduce the circulating back-pressure or
bottomhole pressure by 30 to 40 percent, preferably not to exceed 35 percent
of the
draw down on the bottomhole pressure (BHP) for a period of time of from 1.5 to
15
times the bottoms up time, depending on the annular flow conditions. The time
of each
back-pressure change is recorded, to be correlated with the flow measurements.
The
back-pressure is increased, using either a surface choke or by increasing the
bottomhole pressure, to a safe drilling level and then stabilized over
a.period of from
1.5 to 1 S times the bottoms up time.
Drilling is resumed and the borehole B is extended to the formation F at a
steady
drilling rate of preferably 10-20 meters per hour. During the resumption of
drilling, the
sensor points variable measurements 1)-IV) are continuously monitored and
recorded.
Drilling is continued until the formation F has been fully traversed. Once the
wellbore
extends below the bottom of the formation by 2 to 10 meters, drilling is
stopped. Fluid
flow through the annulus is continued for a time of from 2 to 15 times the
bottoms up
time. If the back-pressure in the annulus A cannot be increased without
killing the well,
the annulus back-pressure is decreased by 15-20 percent from the initial
pressure
value occurring following initial penetration of the formation bottom, If the
back-
pressure in the annulus A is still high enough to kill the well, the annulus
back-pressure
is decreased 30-40 percent from the initial pressure value.
CA 02547584 2001-09-19
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Once the measurements have been completed foliowing the application of the
different back-pressures in the annulus A, the original back-pressure existing
at the
penetration of formation bottom is restored and the wellbore drilling is
continued, or the
drilling assembly is pulled from the well if the total well depth has been
reached.
The flow rates and corresponding bottomhole pressures obtained from the
foregoing process are plotted to form Inflow Production (IPR) curves. The IPR
curves
are extrapolated to determine the virgin reservoir pressure P* of the
formation F or a
specific portion of the formation or layer of interest. This method is an
alternative
technique for determining the formation pressure P* without using direct
measurement
process of stopping circulating through the well, shutting in the well and
then alfowing
the pressure from the formation to build up to a stabilized level indicative
of P*.
With the collected data, Darcy's Radial Flow equation is used to solve for
matrix
permeability "k," or fracture transmissibility "kh." Skin effect S is assumed
to be zero
where underbalanced drilling conditions are used since the absence of drilling
fluid flow
into the formation exerts minimal skin damage to the formation. P* is taken
from the
IPR curves or shut in pressure buildup determination. These calculations can
conveniently be used to provide a graphical presentation of flow rate versus
drilling
depth.
Evaluation of the formation F using the measurements and data obtained in the
described process may be enhanced with the use of a computer model 29 of the
reservoir. The computer model can account for variances attributable to
multiple
formation layers, partial penetration of a zone, dual porosity of the
formation and the
occurrence of vertical, horizontal or high angle wellbores as well as other
variations in
parameters. The computer model may be employed to more accurately project well
CA 02547584 2001-09-19
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production and reserve estimates. Presentation of the evaiuation and
activation of
alarms is made by an evaluation section 30. A kick alarm 31 provides early
warning
of an influx of formation fluids into the wellbore.
The methods of the present invention may also be practiced in a system using
data obtained directly with downhole flow measurement instruments that
comprise a
part of the drilling assembly. In a directly measuring downhole system, the
requirement
for initial system calibration is reduced or becomes unnecessary. With the
exception
of the initial calibration step, the steps used in performance of the method
when using
direct downhole flow measurement instruments are substantially the same as
those
employed when downhole flow parameters are determined inferentially or are
obtained
from indirect measurements or a data resource. Using actually determined
subsurface
flow measurements eliminates the requirement for the computer model 29 or the
data
model 25b and otherwise reduces the need for extensive mathematical
correlations and
cal.culations to obtain accurate formation values. Direct measurements also
enable
rapid waming of a kick to initiate an alarm from the measuring component 31.
Figures 2 and 3 illustrate details in a preferred subsurface measurement tool,
indicated generally at 50, for assisting in determining permeability of the
formation F.
The measurement tool 50 is illustrated connected to a drill bit 51 to function
as part of
a near-bit stabilizer.. It will be appreciated that the tool 50 may be
employed at other
near-bit locations within a bottomhole drilling assembly and need not
necessarily be
connected immediately to the bit, the objective being to provide a stabilizing
relationship between the bit and the tool 50. The instrument tool 50 includes
three
separate types of detection devices in the vicinity of the drill bit
permitting a large
number of combinations of signals to be analyzed thereby producing increased
CA 02547584 2001-09-19
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flexibility and accuracy in both measurement while drilling (MWD) and
formation
analysis operations.
The instrument tool 50 is equipped with an axially extending body 52 having a
central, axially developed passage 55 for conveying fluid between a first
axial tool end
56 and a second axial tool end 57. Radially and axially extending,
circumferentially
spaced blades 60, 61 and 62 extend from an external tool surface 65. The
instrument
tool 50 is connected at its first end 56 to a bit 51 and at its second axial
end 57 to a
monitoring and recording tool 66 that processes and records the measurements
taken
by the instrument tool 50. The tool 66 records and/or transmits measurements
to.the
well. surface. Recorded measurements are retained in the recorded memory until
the
drilling assembly is retrieved to the well surface or the measurements may be
transmitted to the surface through fluid pulse telemetry or other suitable
communlcation
means.
The tools 50 and 66 are connected with the measuring system 20 for real-time
or near real-time measurements that permit formation evaluation. Analog to
digital
converters in the measuring system 20 process signals detected at the
transducer
receivers and capacitive energy transducers and supply numerical
representations to
a microprocessor system within the components 23, 29 and 30. The measuring
system
of the present invention employs a microprocessor and digital-to-analog
converters
20 to enable the production of many different types of signals with the
acoustic
transducers or electromagnetic antenna systems. Both high and low frequency
signals
can be created. In addition, fast rise time and slow fall time "saw tooth"
signals may be
employed to provide specific, more discrete rates of change in electronic
signaling as
compared to older techniques employing continuous variations of sine waves.
CA 02547584 2001-09-19
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The output signals from the energy transducers employed in the present
invention are calibrated and the programming employed in the measuring system
is
modified to counter intrinsic tool inductance and capacitance that would
normally distort
the output signals. Reduction in distortion and the presence of discreetly
rising and
falling signals contribute to greater accuracy in the measurement of the
inductance of
the fluids. Broad variations in times of signal changes are empioyed to cause
attenuations or reinforcements of signals depending upon gas bubble sizes or
oil
droplet diameters and volumes. The combinations of frequencies ranging from
high to
low, and varying rates of change within signals assist in sorting smaller and
larger
bubbles and globules. The dimensions of water concentrations between other
fluid
contacts also alters the broad range of signals in different ways. Significant
fluid
geometry information is extractable from the many signals being altered by the
flowing
fluids and then detected at the receivers of the present invention.
As best illustrated in Figure 3, several fluid receiving recesses 70,71 and 72
are
defined between the circumferentially spaced blades in an area intermediate
the
external surface 65 of the tool body and the weiibore wall (not illustrated).
The
recesses 70, 71 and 72 are illustrated in Figure 3 between dotted lines 73, 74
and 75,
respectively, and external tool surfaces 76, 77 and 78, respectively, of the
tool 50.
The primary monitored indicator of flow in the recesses 70, 71 and 72 is
preferabiy a marker comprising a bubble of gas or a gaseous cluster entrained
within
the liquid flowing through the recess being monitored. The electricai sensors,
circuitry
and analyticai process for correlating the measurements taken by the various
transducers determine a rate of movement of the bubble marker past the
transducers.
CA 02547584 2001-09-19
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Energy transducers are carried by the blades for evaluating characteristics of
fluid contained in the fluid receiving recesses. The measured characteristics
are
convertible into a measure of the flow rate of the fluid flowing through the
recesses.
To this end, acoustic transducer receivers 85 and acoustic transducer
transmitters 86
are carried in the blades 61 and 60, respectively. Electromagnetic induction
transmitting transducers 90 and electromagnetic receiving transducers 91 are
carried
in the blade 60 and 62, respectively. Electrical capacitance transducers 95,
96 and 97
are carried on the tool body between the blades 62 and 61.
Referring to Figure 2, the energy transducers carried by the tool 50 are
deployed
at axially spaced locations along the tool body 65 and blades 60, 61 and 62 to
enable
the transducers to detect variable parameters associated with axial movement
of fluid
flowing through the recesses with which the transducers are associated.
Accordingly,
three acoustic receivers 85a, 85b and 85c are deployed at axially spaced
locations
along the blade 61 and three acoustic transducer transmitters 86a, 86b and 86c
are
deployed at axially spaced locations along the blade 60. Similarly, two
electromagnetic
transmitters 90a and 90b are axially deployed along the blade 60 and three
electromagnetic receivers 91 a, 91 b and 91 c are axially deployed along the
blade 62.
Capacitive transducers are also deployed. at circumferentially and axially
spaced
locations along the body of the tool 50. Capacitive transducers 95, 96 and 97
are
displayed in Figure 3 at only one axial location. Similar arrays of capacitive
transducers (not illustrated) are deployed at other axially spaced locations
between the
blades 61 and 62. The various transmitters, receivers and capacitance energy
transducers are preferably located high within the protected areas between the
stabilizer blades to avoid the mud and rock cuttings that often accumulate in
greatest
CA 02547584 2007-02-28
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qualities on the lower portions of the blades. The blades function to form
fluid
channeling recesses to confine the fluid being monitored and also provide
protective
structure for the energy transmitters.
With reference to the detail drawing of the transducer 90 in Figure 3A, the
induction transmitting antennas of the transducers 90 are positioned within
notches in
the blade 62 that have curved shapes with sloping surfaces 90b that slightly
increase
from a parabolic shape to produce an over focusing from a parallel beam to a
concentrated point at the receiving transducers 91. Over focusing of the
transmitter
signal counteracts dispersion caused by bubbles and rock cuttings in the fluid
flowing
past the sensors. The angles between the transmitters and receivers are
preferably
optimized for vector processing relating to typical rotation speeds and
expected fluid
velocities:
As illustrated in the detail drawing of transducer 95, illustrated in Figure
3B, the
capacitance transducers 95, 96 and 97 are preferably provided with concave
surface
electrode shapes 95a to improve contact with the convex surfaces of bubbles or
rounded oil globules entrained within the fluid flowing past the transducers.
Gas
bubble shapes change sizes as a function of changing depth and pressure within
the
weilbore. The capacitance transducers preferably protrude slightly radia(ly
from the
body of the tool body 50 with the concave surface shapes having an increasing
curvature toward the top 95b of the tool 50 to permit better contact of the
surface with
both small and larger bubbles. The larger curvature at the top of the
transducers
permits improved matching of shapes of the smaller bubbles or oil globules
with the
transducers. The smaller curvature at the bottom 95a of the transducers forms
a better
match with the external surfaces of larger bubbles or globules.
CA 02547584 2001-09-19
-20-
In operation, the acoustic and electromagnetic transducers in the tool 50 and
associated instruments in the recording tool 66 monitor the characteristics of
the fluid
intercepted in the travel paths of the energy signals traveling between
transducers.
The capacitive transducers monitor the characteristics of the fluid engaging
the reactive
surfaces of the transducers. Each of the three acoustic transmitters
communicate with
each of the three acoustic receivers to produced nine transmission paths. The
paths
are identified as a function of their physical position within the fluid
receiving recess.
The electromagnetic transducers function similarly to produce a total of six
transmission
paths. The radial and axial displacement of transducer paths produces an array
of
readings that can be correlated both in time and location to provide the rate
of flow of
fluids flowing through the fluid receiving recesses. The change in capacitance
along
the axial distribution of the capacitive transducers provides a measure of the
flow past
the monitoring surfaces.
The measuring process performed by the tool 50 is preferably done while the
tool is rotating with the bit in the wellbore. The rotating motion of the tool
homogenizes
the liquid and gases into a uniform mixture that enhances the detection
capabilities of
the sensors. Rotation of the tool 50 also permits each set of three detection
systems
to provide full borehole coverage. The blades of the tool protect the
measuring devices
frotn impact with borehole walls and also afford protection from impact with
solids in the
returning well fluids.
Rotation of the tool produces centrifuging of certain fluids that enter the
fluid
receiving recesses of the tool. Gas, oil and water are inclined to be
differentially
concentrated by centrifuging. As a result, methane and other gases may be more
easily detected as they are concentrated within the receiving recesses by the
spinning
CA 02547584 2001-09-19
-21-
motion, pushing denser liquids to the outer edges of the blades. The spinning
of the
tool also significantly reduces segregation of fluids with respected to the
top or bottom
side of an inclined wellbore. Mixtures of iiquids commonly encountered in well
drilling
produce complex combinations of signal frequencies and signal wavelet shapes
transmitted from acoustic and reactive sources to detectors. Analysis of the
transmitted
signals provides numerous data sets for physically evaluating a slurry having
variations
in mixing rules or properties.
The tool 50 may be used as a kick detector during the construction of the
well.
The tool's kick detection capability stems from its ability to recognize
changes in the
subsurface wellbore conditions and fluids associated with a kick. Subsurface
detection
of increased flow rate or other variables can give an early kick warning. If a
wellbore
influx or kick occurs during drilling, the presence of oil bubbles in the
fluid flowing
through the recess 72 will slow acoustic travel times between the acoustic
sensors 85a,
85b, 85c and 86a, 86b, 86c. Gas bubbles in the recess 72 will cause far
greater
increases in acoustic travel time between the energy transducers significant
acoustic
wave amplitude attenuations will also occur upon the influx of oil or gas into
the recess
72. Wave shapes of acoustic signals will be distorted or exhibit complex
interference
and dielectric measurements will deviate from drilling mud readings. A
predetermined
combination of the described sensor readings causes the software or firmware
in the
measurement section 30 to alter mud pulsing priorities and send warnings to
the
surface kick detection component 31.
Gas or oil bubbles passing up past the bit during a trip out of the hole are
detected by leaving the power on to the induction and acoustic monitoring
systems
included in the tool 50. Since mud pulses are not being relayed during
tripping, a
CA 02547584 2001-09-19
-22-
warning system as relayed to the drilling crew by changing acoustic pulses to
a gas
detection indication sequence. A stethoscope type or amplified sound detection
and
filtering system in the component 31 enables a crewman to hear a kick warning
pulse
pattern (e.g., SOS) during a brief quiet period (block lowering time) between
pulling
each stand.
The tool 50 may also be used to indicate early wellbore stability problems.
Faster acoustic travel times, some resistivity changes, and some dielectric
changes can
indicate increases in quantities of rock cuttings. Mud velocity reductions or
other
actions may be taken to reduce excessive "washing out" or widening of the
borehole
after increased cuttings volumes from weaker formations are detected.
It will be appreciated that various modifications can be made in the design,
construction and operation of the present invention without departing from the
spirit or
scope of such invention. Thus, while the principal preferred construction and
mode of
o.peration of the invention have been explained in what is now considered to
represent
its best embodiments, which have been illustrated and described herein, it
wilt be
understood that within the scope of the appended Claims, the invention may be
practiced otherwise than as specifically illustrated and described.
