U.S. patent application number 14/943738 was filed with the patent office on 2017-05-18 for geological asset uncertainty reduction.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. The applicant listed for this patent is Gaurav Agrawal, Umesh Santosh Patil. Invention is credited to Gaurav Agrawal, Umesh Santosh Patil.
Application Number | 20170138191 14/943738 |
Document ID | / |
Family ID | 58691798 |
Filed Date | 2017-05-18 |
United States Patent
Application |
20170138191 |
Kind Code |
A1 |
Patil; Umesh Santosh ; et
al. |
May 18, 2017 |
GEOLOGICAL ASSET UNCERTAINTY REDUCTION
Abstract
A system and method for developing a wellbore is disclosed. A
sample is obtained from the wellbore during a drilling operation. A
first test device tests the sample to obtain a first measurement of
a parameter of the sample. The first measurement of the parameter
is input to a second test of the sample performed at a second test
device to obtain a second measurement of the parameter. A parameter
of the developing operation is altered based on the second
measurement of the parameter.
Inventors: |
Patil; Umesh Santosh;
(Maharashtra, IN) ; Agrawal; Gaurav; (Al-Khobar,
SB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Patil; Umesh Santosh
Agrawal; Gaurav |
Maharashtra
Al-Khobar |
|
IN
SB |
|
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
58691798 |
Appl. No.: |
14/943738 |
Filed: |
November 17, 2015 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 49/005 20130101;
E21B 49/088 20130101; E21B 25/00 20130101; E21B 49/08 20130101 |
International
Class: |
E21B 49/08 20060101
E21B049/08 |
Claims
1. A method of developing a wellbore, comprising: obtaining a
sample from the wellbore during a drilling operation; testing the
sample using a first test to obtain a first measurement of a
parameter of the sample; inputting the first measurement of the
parameter to a second test of the sample to obtain a second
measurement of the parameter; and altering a parameter of the
developing operation based on the second measurement of the
parameter.
2. The method of claim 1, wherein inputting the first measurement
of the parameter to the second test improves an accuracy of the
second measurement of the parameter compared to performing the
second test without inputting the first measurement of the
parameter.
3. The method of claim 1, further comprising performing a
continuous gas analysis on a fluid sample while a rock sample
retrieved alongside the fluid sample undergoes at least one of a
preparation stage and an analysis.
4. The method of claim 1, wherein the first test and the second
test include at least one of: (i) a microscopic mineralogical
analysis of the sample; (ii) X-ray diffraction; (iii) X-ray
fluorescence; (iv) Fourier-Transform infrared testing; (v)
pyrolysis; (vi) gas chromatography; (vii) scratch testing; (viii)
desorption testing; and (ix) acoustic velocity change measurement
testing.
5. The method of claim 1, wherein the first test is a test of a
geologic fluid sample and the second test is a test of a rock
sample retrieved from the borehole.
6. The method of claim 1, further comprising performing, while the
borehole is being drilled in a continuous operation, the steps of
retrieving the sample from the borehole, performing the first test
and the second test and altering the drilling parameter.
7. The method of claim 1, further comprising performing the first
test and the second test at a drilling site using a test station
that is portable to the drilling site.
8. The method of claim 1, wherein the sample includes at least one
of: (i) a geologic fluid obtained from the borehole; (ii) core
cuttings; (iii) a core sample; and (iv) well cavings.
9. The method of claim 1, further comprising calibrating a log of
the formation using the second measurement of the parameter.
10. The method of claim 1, further comprising obtaining a
measurement of mineral composition and using the measurement of
mineral composition to refine a measurement of minerology of the
formation.
11. A system for developing a wellbore, comprising: a tool at a
wellbore development site configured to retrieve a sample from the
borehole; and a test station disposed at the wellbore development
site that includes: a first test device that determines a first
measurement of a parameter from the sample, and a second test
device that uses the first measurement of the parameter as input to
determine a second measurement of the parameter, wherein a wellbore
development operation is altered based on the second measurement of
the parameter.
12. The system of claim 11, wherein an accuracy of the second
measurement of the parameter is greater than a measurement of the
parameter using only the second test.
13. The system of claim 11, wherein the first test device is gas
chromatography device that is performed on a fluid sample while a
rock sample retrieved alongside the fluid sample undergoes at least
one of a preparation stage and an analysis stage.
14. The system of claim 11, wherein the first test device and
second test device are selected from the group consisting of: (i) a
microscopic mineralogical analysis of the sample; (ii) X-ray
diffraction tester; (iii) an X-ray fluorescence tester; (iv) a
Fourier-Transform Infrared tester; (v) a pyrolysis tester; (vi) gas
chromatography tester; (vii) scratch test device; and (viii) a
desorption testing device.
15. The system of claim 11, wherein at least one of the first test
device and the second test device perform at least one test
selected from the group consisting of: (i) electromagnetic testing;
(ii) thermal testing; (ii) electron interaction testing; and (iv)
tests using separation techniques; (v) tests using purification
techniques; (vi) isotopic testing; and (vii) mechanical harness
testing.
16. The system of claim 11, wherein the first test device and
second test device provide information to an operator for making a
decision to alter the drilling operation while the borehole is
continuously being drilled.
17. The system of claim 11, wherein the test station is portable to
the drilling site.
18. The system of claim 11, first test device and the second test
device are operated in an order which reduces time for obtaining
the second measurement.
19. The system of claim 11, wherein the sample includes at least
one of: (i) a geologic fluid obtained from the borehole; (ii) a
core sample; (iii) core cuttings; and (iv) well cavings.
20. The system of claim 1, wherein the first measurement is a
measurement of mineral composition of the sample and the second
measurement is a measurement of sample mineralogy the measurement
of mineral composition is used to refine the measurement of
minerology.
Description
BACKGROUND OF THE DISCLOSURE
[0001] In petroleum exploration, a borehole is drilled through an
earth formation at an exploration site or drilling site using a
drill string. Formation evaluation tools, conveyed into the
borehole either on the drill string or separately on a wireline
tool, can be used to obtain logs of the earth formation, which logs
are used to determine formation lithology. However, conventional
log data does not always provide a proper characterization of a
shale reservoir or other subterranean formation. In order to
improve the characterization, the obtained logs are calibrated with
related measurements obtained from core samples and/or cuttings
obtained at various locations within the borehole. Calibration
measurements on the cores and/or cuttings are generally carried out
in specialized laboratories that are located away from the
exploration site. This calibration process therefore usually
requires several weeks to complete, which can slow down or delay
drilling operations until test results come in, at a considerable
cost of time and money. Additionally, cores and cuttings tend to
change their chemical nature during the weeks required to perform
the tests, leading to inaccurate knowledge of the earth
formation.
SUMMARY OF THE DISCLOSURE
[0002] A method of developing a wellbore includes: obtaining a
sample from the wellbore during a drilling operation; testing the
sample using a first test to obtain a first measurement of a
parameter of the sample; inputting the first measurement of the
parameter to a second test of the sample to obtain a second
measurement of the parameter; and altering a parameter of the
developing operation based on the second measurement of the
parameter.
[0003] A system for developing a wellbore includes: a tool at a
wellbore development site configured to retrieve a sample from the
borehole; and a test station disposed at the wellbore development
site that includes: a first test device that determines a first
measurement of a parameter from the sample, and a second test
device that uses the first measurement of the parameter as input to
determine a second measurement of the parameter, wherein a wellbore
development operation is altered based on the second measurement of
the parameter.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] For detailed understanding of the present disclosure,
references should be made to the following detailed description,
taken in conjunction with the accompanying drawings, in which like
elements have been given like numerals and wherein:
[0005] FIG. 1 shows an exemplary drilling system in one embodiment
of the present invention;
[0006] FIG. 2 illustrates a timeline for testing procedures
performed at the test station;
[0007] FIG. 3 shows a chart illustrating a preparation stage and
testing stage for various samples at the test station;
[0008] FIG. 4 shows a chart detailing a decision method for
selecting which tests to perform in order for an operator to make a
suitable decision with regarding the drilling operation; and
[0009] FIG. 5 shows a workflow for determining a parameter of a
formation sample of the borehole;
[0010] FIG. 6 shows a workflow for completing an analysis of
petrophysical properties of the formation sample; and
[0011] FIG. 7 illustrates a method for identifying a false positive
in mineralogy measured on a same set of formation samples.
DETAILED DESCRIPTION OF THE DISCLOSURE
[0012] FIG. 1 shows an exemplary drilling system 100 in one
embodiment of the present invention. The drilling system 100 is
disposed at a drilling site and includes a drill string 102 that
drills a borehole 104 (as referred to herein as a "wellbore") into
a formation 106. The drill string 102 extends into the borehole 104
from a surface location 108 and includes a drill bit 110 at a
bottom end for drilling the borehole 104. A rotor 110 rotates the
drill string 102 to drill the borehole 104. The rotor 110 may be at
the surface location 108, as shown, or a downhole motor (not
shown). The drill string 102 forms an annulus 105 with a wall 108
of the borehole 104.
[0013] A pump 120 is located at the surface location 108 to
circulate a drilling mud 122 from a mud pit 124 into the borehole
104. The pump 120 pumps the drilling mud 122a from mud pit 124
through a conduit 126 into the drill string 102 at the surface
location 108, and the drilling mud 122a travels downhole through an
interior bore of the drill string 102 to exit the drill string 102
at the drill bit 110. The drilling mud 122b then travels upward
from the drill bit 110 through annulus 105 and out of the borehole
104 to be returned to mud pit 124 via conduit 128. The returning
drilling mud 122b can include formation fluids that enter into the
borehole 104 during the drilling process as well as rock cuttings
that are produced by the drill bit 110 during drilling of the
borehole 104. The drilling mud 122b and rock cuttings can be
separated from each other back at the mud pit 124.
[0014] The drill string 102 includes at least one formation
evaluation sensor 113 for obtaining formation parameter
measurements. The sensor 113 can be a resistivity sensor, gamma ray
sensors, etc. The sensor 113 can be used as the drill string
progresses through the borehole in order to obtain a log of the
formation parameter with depth. The drill string 102 further
includes a core sample device 114 for cutting a core sample from
the formation 106 at a downhole location. The core sample device
114 is located on the drill string 102, usually near the drill bit
110, and cuts into the formation 106 to obtain a core sample. The
core sample can be stored in a chamber in the drill string 102 and
retrieved when the drill string 102 is tripped out of the borehole
104. In another embodiment, the core sample device 114 may be part
of a wireline device that is lowered into the borehole 104 after
the drill string 102 has been retrieved from the borehole 104. The
drill string 102 may further include a stabilizer or other device
that can be used to steer the drill string. Various drilling
parameters can be applied to the drill string in order to affect
the drilling operation. Exemplary drilling parameters include
weight-on-bit, rotations per minute, steering parameters, etc.
[0015] The drilling system 100 further includes an on-site test
station 132 for performing various tests on samples that are
retrieved from the borehole 104. In various embodiments, the
samples can include formation fluids retrieved by the drilling mud
122b, core cuttings retrieved by the drilling mud 122b, and/or core
sample(s) retrieved using the core sample device 114. The test
station 132 performs various tests on these samples to obtain test
results that can be used to enable an operator to make a decision
with respect to a future process in the drilling system 100. Due to
the proximity of the test station 132 to the drilling system 100
and drill string 102, an operator can select a goal or direction
regarding the drilling operation, run tests that generate
information applicable toward making an informed decision regarding
the selected goal or direction and come to a decision regarding the
goal or direction, all while the drill string remains continuously
drilling, i.e., without stopping the drilling process. In one
embodiment, a portion of drilling mud 122b (as well as the geologic
fluid and core cuttings) can be circulated from the mud pit 124 to
the test station 132 via a transport device 134. The transport
device 134 can be a pipe or conduit, a conveyor belt, an automotive
vehicle, etc. After being tested at the test station 132, the
drilling mud can be returned to the mud pit 124 via transport
device 136.
[0016] FIG. 2 illustrates a timeline 200 for testing procedures
performed at the test station 132. In general, geologic fluid
samples are most readily available to the test station 132 and are
often tested first. Rock fragments, such as drill cutting and
wellbore cavings, require a preparation stage prior to testing and
are therefore available for testing at a time later than the
geological fluid. The rock fragments can be tested after, as well
as concurrently with, tests performed on the geological fluids.
Core samples (e.g., whole core samples, sidewall core samples) are
available to the test station 132 only after the drill string 102
has been retrieved to the surface and therefore are generally
tested last.
[0017] FIG. 3 shows a chart 300 illustrating a preparation stage
and testing stage for various samples at the test station 132.
Drilled rock cuttings and drilling fluid are received 301 from mud
pit 124. Fluids are separated from the rock cuttings and sent to a
gas chromatography test device 303 while the rock cuttings are sent
to a preparation stage 304 which includes sampling 305, washing
307, drying 308 and grinding 309. The gas chromatography test 301
can be run continuously during the preparation stage 304 and
testing stage of the rock samples and can provide measurements that
can be used as input to other tests performed at the test station
132.
[0018] The rock cuttings undergo tests which can include, but are
not limited to, a microscopic mineralogical test (such as a Roqscan
test) 311, X-ray diffraction 313, X-ray fluorescence 315, Fourier
Transform Infrared analysis 317, and pyrolysis 319, as well as
other tests not shown in FIG. 2, such as core scratching,
desorption testing and acoustic velocity measurements including
changes in acoustic velocity. The tests are generally based on
different measurement principles or physical properties of the
formation. In various embodiments, the tests can include
electromagnetic testing, thermal testing or testing of thermal
properties, testing the formation sample through interaction with
elections, testing using separation techniques, and testing using
purification techniques, isotopic testing and mechanical harness
testing. While all of the tests 311-319 can be available at the
test station 132 an operator may only require some of these tests
in order to make a decision regarding the drilling operation.
[0019] The various tests shown in FIG. 3 take certain amounts of
time. Microscopic mineralogical analysis 311 takes about 30 minutes
to perform. X-ray diffraction 313 takes about 10 minutes to
perform. X-ray fluorescence 315 takes about 5 minutes to perform.
Fourier Transform Infrared analysis 317 takes about 2 minutes to
perform. Pyrolysis 319 takes about 45 minutes to perform. The order
in which a selected set of these test is performed can be selected
for efficiency, in order to produce useful information for changing
or affecting the drilling process within a selected time frame.
Additionally, tests can be scheduled so that test results from one
test can be used as input to another test.
[0020] FIG. 4 shows a chart 400 detailing a decision method for
selecting which tests to perform in order for an operator to make a
suitable decision with regarding the drilling operation. The chart
400 shows a first row indicating a number of goals that are
pertinent to the drilling operation. Exemplary goals include:
evaluating a gas potential for a formation 401, identifying a sweet
spot (i.e., a hydrocarbon location) in the formation 403,
determining a trajectory for geosteering 405 and designing and
optimizing a frac job 407. The second row includes various issues
that are to be addressed in order for a decision to be made with
respect to a given goal in the first row. Exemplary issues include:
determining organic matter facies, abundance and maturity 409,
determining an organic matter distribution and facies recognition
411, mapping the heterogeneities of a reservoir 413, and
determining rock properties 415. The third row includes various
tests that can be performed to resolve the issues in the second
row. Exemplary tests include: determining a total amount of organic
carbon 417, performing pyrolysis 419, performing gas extraction and
analysis 421, performing a chemical analysis 423, and performing
clay mineral characterization 425. Arrows between boxes indicates
which issues are related to which targets and which tests are used
to resolve which issues. Various of these tests include performing
multiple sub-tests at the test station 132. For example, a chemical
analysis 423 includes performing microscopic mineralogical analysis
311 and X-ray fluorescence 315 on the sample and a clay mineral
characterization includes performing microscopic mineralogical
analysis 311 and X-ray diffraction 313.
[0021] Referring still to FIG. 4, an operator can determine what
goals need to be decided upon and perform tests that will provide
measurements that allow the operator to make an informed decision
regarding the goal. For example, the operator wishes to design and
optimize a frac job 407. Designing a frac job requires mapping the
heterogeneities of the reservoir 413 and determining various rock
properties 415. Mapping the heterogeneities of the reservoir 413
includes performing pyrolysis 419, gas extraction analysis 421,
chemical analysis 423 and clay mineral characterization 425.
Determining the rock properties 415 includes chemical analysis 423
and clay mineral characterization 425. It is clear that chemical
analysis 423 is performed for each of mapping the heterogeneities
of the reservoir 413 and determining various rock properties 415
and need be performed only once.
[0022] In one embodiment, an operator can run multiple sample tests
simultaneously. In addition, the operator can run a first test on a
sample to obtain a first measurement of a parameter of the sample.
The operator can then run a second test on the sample or a related
to obtain a second measurement of the parameter of the sample,
using the first measurement from the first test as an input to the
second test. Using the results from the first test as input to the
second test improves an accuracy of the second measurement of the
parameter produced by the second test over a measurement of the
parameter than is obtained by running the second test without
input. In additional embodiments, the second measurement of the
parameter can be used as an input into a third test to obtain a
third measurement of the parameter, whereas the accuracy of the
third measurement is improved over the accuracy of the second
measurement, and so on. The parameter measurements from the first
test and the second test can further be integrated with formation
logs in order to calibrate the formation logs, thereby generating a
near real-time Mineralogical/Geochemical/Gas analysis log of an
entire shale sequence of the formation 106 during the drilling
operation. In another embodiment, the first measurement is of a
first parameter of the formation sample and the second measurement
is of a second parameter of the formation sample, and the first
measurement is used to refine, correct or calibrate the second
measurement of the formation sample.
[0023] The test station 132 can therefore be used to provide a
reliable preliminary Formation Evaluation and/or Reservoir
Characterization, enabling an operator to optimize the drilling
operation (e.g. quickly identify coring point, "sweet spot" for
possible frac job, smarter completion, etc.) The methods disclosed
herein can be used to select appropriate intervals for hydraulic
stimulation integrating LWD/wireline logs (e.g. image log, sonic
log).
[0024] The test station 132 can be a portable test station that can
be moved from one drilling site to another. In one embodiment, the
test station 132 can be transported on a truck or other vehicle.
Rock cuttings and core samples can therefore be analyzed as soon as
they are retrieved from the borehole 104, rather than after being
transported to a distant laboratory. In one embodiment, a single
testing device can be used to perform a plurality of tests on the
formation sample. The single testing device can have equipment for
performing the different tests integrated into the single testing
device. In another embodiment, multiple devices can be used to
perform the plurality of tests. Performing tests on-site thus leads
to improved test results vs. test results from distant
laboratories. Additionally, the quantity and types of tests to be
run at any time can be selected during the progress of the borehole
drilling. The methods disclosed herein thus allow an operator to
change drilling plans (geosteering, for example) or otherwise alter
a drilling parameters based on the measurements provided by the
test station 132, and to provide the flexibility of different
drilling plans from one well to another.
[0025] FIG. 5 shows a workflow 500 for determining a parameter of a
formation parameter of the borehole. In particular, the workflow
500 shows a method for determining a mineralogy 523 of a formation
layer. The workflow 500 includes tests on the formation sample by
performing X-ray diffraction 501, scanning electron microscopy 503,
X-ray fluorescence 505 and pyrolysis 507. The X-ray diffraction 501
can provide a measurement of mineral composition 509 of a formation
sample. X-ray fluorescence 505 provides an analysis of the
elemental composition 513 of the sample. Pyrolysis 507 provides a
measurement of an amount of inorganic carbon (mineral carbon) 517
in a formation sample. Since X-ray diffraction 501 and X-ray
fluorescence 505 are generally unresponsive to inorganic carbon,
the inorganic carbon measurements 515 from pyrolysis 507 can be
used to correct the elemental composition 513 obtained using the
X-ray fluorescence 505, thereby providing measurements that include
elemental composition and inorganic carbon 519.
[0026] The scanning electron microscope 503 determines a
distribution 513 of atoms, grain composition, grain sizes, etc., in
the formation sample. The elemental composition 511 and inorganic
carbon measurements 519 can be compared with the elemental
composition 511 to obtain a corrected elemental composition 517 of
the formation sample. The corrected elemental composition 517 can
then be used to compute mineralogy 521 of the formation sample. The
computed mineralogy 521 can be compared with the mineral
composition 509 from the X-ray diffraction 501 in order to improve
the accuracy of the computed mineralogy of the formation sample, as
shown by corrected mineralogy 523.
[0027] FIG. 6 shows a workflow 600 for completing an analysis of
the petrophysical properties of the formation sample. The workflow
600 can use the corrected mineralogy 523 derived from the workflow
500 of FIG. 5 in order to correct or calibrate logs of borehole
parameters or to correct or calibrate petrophysical models of the
formation. The corrected mineralogy 523 provides a mineral
composition 607. The scanning electron microscope 601 can be used
to determine various textural properties, such as porosity and pore
size distribution, dispersion, mineral particle size, mineral
distribution and dispersion 607. A gas adsorption device 603
provides measurements or porosity and permeability 611, which can
yield information on textural properties and an amount of gas in
place within the formation sample. Pyrolosis 613 measures an
organic composition of the formation sample and therefore can
provide a measurement of total organic carbon (TOC) 613. The
mineral composition 607, SEM measurements 609, porosity and
permeability measurements 611 and total organic carbon measurements
613 can be combined to provide a display 615 of corrected
mineralogy, textural properties, gas in place and total organic
carbon. The display 615 can be in the form of one or more parameter
logs. Other measurements not shown in FIG. 6 can also be provided
at the display 615. The displayed parameters can be compared to
logs of borehole parameters obtained from wellbore measurements in
order to correct and/or calibrate the wellbore logs. The displayed
parameters can also be input into a petrophysical model 613 to
determine various parameters, such as an amount of hydrocarbon in
the formation, an ease of hydrocarbon flow in the formation, an
amount of fracking fluid that is needed for a frac operation,
etc.
[0028] FIG. 7 illustrates a method 700 for identifying a false
positive in mineralogy measured on a same set of formation samples.
Panel 702 shows two mineralogy logs that are obtained using the
testing methods disclosed herein. In particular, mineralogy log
702a is obtained using scanning electron microscopy. Mineralogy log
702b is obtained using X-ray diffraction. In panel 704, differences
in the logs are noted at different zones of the borehole. In panel
706, X-ray fluorescence data log is overlapped with the mineralogy
logs 702a and 702b. In panel 708, a false positive in the
calculated log from the scanning electron microscopy has been
identified due to the comparison in pane 706 and corrected using
data from the mineralogy log from X-ray diffraction
measurements.
[0029] While the apparatus and methods disclosed herein are
described is being applicable to a drilling operation, the
apparatus and methods are equally applicable to operations for
developing a wellbore at a wellbore development site. Developing
can include drilling, completion, production, fracking, etc. and
the wellbore measurements can be obtained using any tool or
workstring, not just a drill string. The various measurements
obtained herein can be used to alter a drilling parameter during a
drilling operation, alter a step of a completion process, alter a
production parameter, make a decision with regarding to a fracking
operation, etc. In one embodiment, the results of the tests (i.e.,
the second measurement) obtained herein are used to enhance a
production from a formation.
[0030] Set forth below are some embodiments of the foregoing
disclosure:
[0031] Embodiment 1: A method of developing a wellbore, comprising:
obtaining a sample from the wellbore during a drilling operation;
testing the sample using a first test to obtain a first measurement
of a parameter of the sample; inputting the first measurement of
the parameter to a second test of the sample to obtain a second
measurement of the parameter; and altering a parameter of the
developing operation based on the second measurement of the
parameter.
[0032] Embodiment 2: The method of embodiment 1, wherein inputting
the first measurement of the parameter to the second test improves
an accuracy of the second measurement of the parameter compared to
performing the second test without inputting the first measurement
of the parameter.
[0033] Embodiment 3: The method of embodiment 1, further comprising
performing a continuous gas analysis on a fluid sample while a rock
sample retrieved alongside the fluid sample undergoes at least one
of a preparation stage and an analysis.
[0034] Embodiment 4: The method of embodiment 1, wherein the first
test and the second test include at least one of: (i) a microscopic
mineralogical analysis of the sample; (ii) X-ray diffraction; (iii)
X-ray fluorescence; (iv) Fourier-Transform infrared testing; (v)
pyrolysis; (vi) gas chromatography; (vii) scratch testing; (viii)
desorption testing; and (ix) acoustic velocity change measurement
testing.
[0035] Embodiment 5: The method of embodiment 1, wherein the first
test is a test of a geologic fluid sample and the second test is a
test of a rock sample retrieved from the borehole.
[0036] Embodiment 6: The embodiment of claim 1, further comprising
performing, while the borehole is being drilled in a continuous
operation, the steps of retrieving the sample from the borehole,
performing the first test and the second test and altering the
drilling parameter.
[0037] Embodiment 7: The embodiment of claim 1, further comprising
performing the first test and the second test at a drilling site
using a test station that is portable to the drilling site.
[0038] Embodiment 8: The embodiment of claim 1, wherein the sample
includes at least one of: (i) a geologic fluid obtained from the
borehole; (ii) core cuttings; (iii) a core sample; and (iv) well
cavings.
[0039] Embodiment 9: The embodiment of claim 1, further comprising
calibrating a log of the formation using the second measurement of
the parameter.
[0040] Embodiment 10: The embodiment of claim 1, further comprising
obtaining a measurement of mineral composition and using the
measurement of mineral composition to refine a measurement of
minerology of the formation.
[0041] Embodiment 11: A system for developing a wellbore,
comprising: a tool at a wellbore development site configured to
retrieve a sample from the borehole; and a test station disposed at
the wellbore development site that includes: a first test device
that determines a first measurement of a parameter from the sample,
and a second test device that uses the first measurement of the
parameter as input to determine a second measurement of the
parameter, wherein a wellbore development operation is altered
based on the second measurement of the parameter.
[0042] The use of the terms "a" and "an" and "the" and similar
referents in the context of describing the invention (especially in
the context of the following claims) are to be construed to cover
both the singular and the plural, unless otherwise indicated herein
or clearly contradicted by context. Further, it should further be
noted that the terms "first," "second," and the like herein do not
denote any order, quantity, or importance, but rather are used to
distinguish one element from another. The modifier "about" used in
connection with a quantity is inclusive of the stated value and has
the meaning dictated by the context (e.g., it includes the degree
of error associated with measurement of the particular
quantity).
[0043] The teachings of the present disclosure may be used in a
variety of well operations. These operations may involve using one
or more treatment agents to treat a formation, the fluids resident
in a formation, a wellbore, and/or equipment in the wellbore, such
as production tubing. The treatment agents may be in the form of
liquids, gases, solids, semi-solids, and mixtures thereof.
Illustrative treatment agents include, but are not limited to,
fracturing fluids, acids, steam, water, brine, anti-corrosion
agents, cement, permeability modifiers, drilling muds, emulsifiers,
demulsifiers, tracers, flow improvers etc. Illustrative well
operations include, but are not limited to, hydraulic fracturing,
stimulation, tracer injection, cleaning, acidizing, steam
injection, water flooding, cementing, etc.
[0044] While the invention has been described with reference to an
exemplary embodiment or embodiments, it will be understood by those
skilled in the art that various changes may be made and equivalents
may be substituted for elements thereof without departing from the
scope of the invention. In addition, many modifications may be made
to adapt a particular situation or material to the teachings of the
invention without departing from the essential scope thereof.
Therefore, it is intended that the invention not be limited to the
particular embodiment disclosed as the best mode contemplated for
carrying out this invention, but that the invention will include
all embodiments falling within the scope of the claims. Also, in
the drawings and the description, there have been disclosed
exemplary embodiments of the invention and, although specific terms
may have been employed, they are unless otherwise stated used in a
generic and descriptive sense only and not for purposes of
limitation, the scope of the invention therefore not being so
limited.
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