US20170138191A1

US20170138191A1 - Geological asset uncertainty reduction

Info

Publication number: US20170138191A1
Application number: US14/943,738
Authority: US
Inventors: Umesh Santosh Patil; Gaurav Agrawal
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 2015-11-17
Filing date: 2015-11-17
Publication date: 2017-05-18
Also published as: WO2017087482A1

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.

Description

BACKGROUND OF THE DISCLOSURE

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

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.
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

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:

FIG. 1 shows an exemplary drilling system in one embodiment of the present invention;

FIG. 2 illustrates a timeline for testing procedures performed at the test station;

FIG. 3 shows a chart illustrating a preparation stage and testing stage for various samples at the test station;

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

FIG. 5 shows a workflow for determining a parameter of a formation sample of the borehole;

FIG. 6 shows a workflow for completing an analysis of petrophysical properties of the formation sample; and

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

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.
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 122 a from mud pit 124 through a conduit 126 into the drill string 102 at the surface location 108, and the drilling mud 122 a 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 122 b 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 122 b 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 122 b and rock cuttings can be separated from each other back at the mud pit 124.
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.
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 122 b, core cuttings retrieved by the drilling mud 122 b, 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 122 b (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.
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.
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.
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.
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.
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.
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.
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.
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).
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.
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.
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.
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.
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 702 a is obtained using scanning electron microscopy. Mineralogy log 702 b 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 702 a and 702 b. 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.
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.
Set forth below are some embodiments of the foregoing disclosure:
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.
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.
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.
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.
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.
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.
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.
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.
Embodiment 9: The embodiment of claim 1, further comprising calibrating a log of the formation using the second measurement of the parameter.
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.
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.
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).
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.
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.

Claims

What is claimed is:

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.