Office Action 1: Notice of Allowance (2025-05-27)

CLAIMS:
AMENDMENTS TO THE CLAIMS

This listing of claims will replace all prior versions and listings of claims in the application.

1\. (Currently amended) A method, comprising:deploying a formation testing tool string into a wellbore, wherein the formation testing tool string comprises a wireline cable;
performing deep transient testing at a plurality of depths within the wellbore corresponding to a plurality formation zones of interest using a wireline formation testing tool of the formation testing tool string;
disconnecting the wireline cable from the formation testing tool string and \[\[;\]\] extracting the wireline cable out of the wellbore between the deep transient testing and drill stem testing;
performing the drill stem testing using a drill stem testing tool of the formation testing tool string after the deep transient testing; and
extracting the formation testing tool string out of the wellbore after the deep transient testing and the drill stem testing.
2\. (Cancelled)
3\. (Previously presented) The method of claim 1, further comprising closing a circulation sub of the wireline formation testing tool prior to disconnection and extraction of the wireline cable.
4\. (Previously presented) The method of claim 1, further comprising running the wireline cable into the formation testing tool string via a cable side entry sub of the formation testing tool string.
5\. (Previously presented) The method of claim 1, further comprising wirelessly communicating with the wireline formation testing tool and the drill stem testing tool while the wireline formation testing tool and the drill stem testing tool are deployed in the wellbore.

6\. (Previously presented) The method of claim 1, further comprising creating underbalance in the wellbore between the deep transient testing and the drill stem testing.
7\. (Previously presented) The method of claim 1, further comprising performing acid stimulation through the drill stem testing tool.

8\. (Previously presented) The method of claim 1, further comprising performing acid stimulation through the wireline formation testing tool.
9\. (Previously presented) The method of claim 1, further comprising performing proppant stimulation through the wireline formation testing tool.

10\. (Previously presented) The method of claim 1, further comprising launching markers and/or gel spacers into the wellbore through the wireline formation testing tool.

11\. (Original) The method of claim 1, wherein the wellbore is an open hole.

12\. (Original) The method of claim 1, wherein the wellbore is a cased hole.

13-20. (Cancelled)1419

21\. (Currently amended) A method, comprising:deploying a formation testing tool string into a wellbore, wherein the formation testing tool string comprises a wireline cable;
performing deep transient testing at a plurality of depths within the wellbore corresponding to a plurality formation zones of interest using a wireline formation testing tool of the formation testing tool string;
creating underbalance in the wellbore between the deep transient testing and drill stem testing;
performing the drill stem testing using a drill stem testing tool of the formation testing tool string after the deep transient testing; and

extracting the formation testing tool string out of the wellbore after the deep transient testing and the drill stem testing.

22\. (Previously presented) A method, comprising:deploying a formation testing tool string into a wellbore, wherein the formation testing tool string comprises a wireline cable;
performing deep transient testing at a plurality of depths within the wellbore corresponding to a plurality formation zones of interest using a wireline formation testing tool of the formation testing tool string;
performing proppant stimulation through the wireline formation testing tool;
performing drill stem testing using a drill stem testing tool of the formation testing tool string after the deep transient testing; and
extracting the formation testing tool string out of the wellbore after the deep transient testing and the drill stem testing.

23\. (Previously presented) A method, comprising:deploying a formation testing tool string into a wellbore, wherein the formation testing tool string comprises a wireline cable;
performing deep transient testing at a plurality of depths within the wellbore corresponding to a plurality formation zones of interest using a wireline formation testing tool of the formation testing tool string;
launching markers and/or gel spacers into the wellbore through the wireline formation testing tool;
performing drill stem testing using a drill stem testing tool of the formation testing tool string after the deep transient testing; and
extracting the formation testing tool string out of the wellbore after the deep transient testing and the drill stem testing.

OFFICE ACTION:
DETAILED ACTION
Notice of Pre-AIA  or AIA  Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Drawings
The drawings were received on 6/14/2024.  These drawings are accepted.
Allowable Subject Matter
Claims 1, 3-12, and 21-23 are allowed.
The following is an examiner’s statement of reasons for allowance:
US 20240401422 teaches a formation testing tool of particular interest (see fig. 10), but this reference fails to reasonably teach or suggest that there are steps of disconnecting the wireline cable from the formation testing tool string and extracting the wireline cable out of the wellbore between the deep transient testing and drill stem testing. This reference also fails to reasonably teach or suggest that there are steps of creating underbalance in the wellbore between the deep transient testing and drill stem testing, performing proppant stimulation through the wireline formation testing tool, or launching markers and/or gel spacers into the wellbore through the wireline formation testing tool.
US 20100169019 teaches a formation testing tool that has deep transient testing and creates underbalance (see fig. 1), but this reference fails to reasonably teach or suggest that there is any drill stem testing as required by all independent claims (paragraphs 0005-0006 teach away from drill stem testing).
US 4593771 teaches a formation testing tool that has drill stem testing and creates underbalance (see fig. 2), but this reference fails to reasonably teach or suggest that there is any deep transient testing as required by all independent claims.
The other cited prior art of record, whether considered alone or in combination, fails to overcome these deficiencies.
Any comments considered necessary by applicant must be submitted no later than the payment of the issue fee and, to avoid processing delays, should preferably accompany the issue fee.  Such submissions should be clearly labeled “Comments on Statement of Reasons for Allowance.”
Conclusion
The prior art made of record on form 892 and not relied upon is considered pertinent to applicant's disclosure.



CITED REFERENCE SUMMARIES: Ref US4593771A: Claims:
An apparatus for use in full-bore drill stem testing, comprising: a pressure measuring and recording system; carrier means for positioning said pressure measuring and recording system on a drill string in a borehole; groove means on the exterior of said carrier means for protecting said pressure measuring and recording system; bore means in said carrier means for providing continuous fluid communication between other components in said drill string and wherein said bore means produce substantially no pressure drop to fluids flowing through said bore; port means for communicating fluid pressures in said bore to said pressure measuring and recording system; and, transducer means communicating with said port means for detecting fluid pressures present at said port means.
a pressure measuring and recording system;
carrier means for positioning said pressure measuring and recording system on a drill string in a borehole;
groove means on the exterior of said carrier means for protecting said pressure measuring and recording system;
bore means in said carrier means for providing continuous fluid communication between other components in said drill string and wherein said bore means produce substantially no pressure drop to fluids flowing through said bore;
port means for communicating fluid pressures in said bore to said pressure measuring and recording system; and,
transducer means communicating with said port means for detecting fluid pressures present at said port means.
The apparatus of claim 1 further comprising, as part of said pressure measuring and recording system, transducer protection means for protecting said transducer means.
The apparatus of claim 2 wherein said transducer protection means comprises orifice plates for absorbing fluid shock pressures presented thereto.
The apparatus of claim 3 further comprising an oil-filled chamber for communicating fluid pressure to said transducer means while isolating said transducer means from fluids in said bore.
The apparatus of claim 1 wherein said carrier means is eccentrically ground.
The apparatus of claim 5 wherein the center line of said groove means is located at the maximum distance from said bore means.
The apparatus of claim 6 comprising a plurality of said groove means in axial alignment.
The apparatus of claim 1 comprising a plurality of said grooves equally spaced around the circumference of said carrier.
An apparatus for use in full-bore drill stem testing, comprising: an instrument for measuring a downhole parameter; eccentrically ground carrier means for use as a component in a drill string; bore means in said carrier means for providing continuous fluid communication between the bores of other components in said drill string and wherein said bore means in said carrier means produces substantially no pressure drop to fluids flowing therethrough; and groove means on the exterior of said carrier means for housing and protecting said instrument wherein said groove means is located on the major eccentric side of said carrier means with respect to said bore means.
an instrument for measuring a downhole parameter;
eccentrically ground carrier means for use as a component in a drill string;
bore means in said carrier means for providing continuous fluid communication between the bores of other components in said drill string and wherein said bore means in said carrier means produces substantially no pressure drop to fluids flowing therethrough; and
groove means on the exterior of said carrier means for housing and protecting said instrument wherein said groove means is located on the major eccentric side of said carrier means with respect to said bore means.
Ref US20250012776A1: Claims:
A method, comprising: flowing one or more fluids from a subterranean formation to flow through a downhole well tool disposed in a wellbore of a well during a deep transient testing (DTT) operation performed by the downhole well tool; measuring data related to one or more properties of the one or more fluids using one or more downhole fluid analysis sensors disposed within the downhole well tool; and predicting, via a control system, a first predicted DTT surface gas rate based on the data measured related to the one or more properties of the one or more fluids.
flowing one or more fluids from a subterranean formation to flow through a downhole well tool disposed in a wellbore of a well during a deep transient testing (DTT) operation performed by the downhole well tool;
measuring data related to one or more properties of the one or more fluids using one or more downhole fluid analysis sensors disposed within the downhole well tool; and
predicting, via a control system, a first predicted DTT surface gas rate based on the data measured related to the one or more properties of the one or more fluids.
The method of claim 1 , further comprising: predicting, via the control system, a second predicted DTT surface gas rate based on measurement data detected by surface equipment of the well; calculating, via the control system, a vapor fraction for each gaseous component of the one or more fluids, by comparing the first predicted DTT surface gas rate and the second predicted DTT surface gas rate.
predicting, via the control system, a second predicted DTT surface gas rate based on measurement data detected by surface equipment of the well;
calculating, via the control system, a vapor fraction for each gaseous component of the one or more fluids, by comparing the first predicted DTT surface gas rate and the second predicted DTT surface gas rate.
The method of claim 1 , wherein the first predicted DTT surface gas rate comprises hydrocarbon content of the one or more fluids and gas emissions relating to the one or more fluids.
The method of claim 1 , comprising: detecting, via a gas meter of a mud-gas separator, surface measurement data relating to the one or more properties of the one or more fluids; and predicting, via the control system, a second predicted DTT surface gas rate based on the surface measurement data relating to the one or more properties of the one or more fluids.
detecting, via a gas meter of a mud-gas separator, surface measurement data relating to the one or more properties of the one or more fluids; and
predicting, via the control system, a second predicted DTT surface gas rate based on the surface measurement data relating to the one or more properties of the one or more fluids.
The method of claim 1 , wherein the one or more fluids comprise an oil-based mud.
The method of claim 1 , wherein the one or more fluids comprise a water-based mud.
The method of claim 1 , wherein the downhole well tool comprises the control system, and wherein predicting the first predicted DTT surface gas rate comprises: determining, via the downhole well tool, each fluid of the one or more fluids flowing through the downhole well tool; mapping, via the downhole well tool, a flowrate to a fluid density estimation or fluid density measurement for each fluid of the one or more fluids; summing, via the downhole well tool, flowrates of similar fluids of the one or more fluids; and converting, via the downhole well tool, the summed flowrates from volume rates to mass rates by multiplying the volume rates to the fluid density estimation or fluid density measurement.
determining, via the downhole well tool, each fluid of the one or more fluids flowing through the downhole well tool;
mapping, via the downhole well tool, a flowrate to a fluid density estimation or fluid density measurement for each fluid of the one or more fluids;
summing, via the downhole well tool, flowrates of similar fluids of the one or more fluids; and
converting, via the downhole well tool, the summed flowrates from volume rates to mass rates by multiplying the volume rates to the fluid density estimation or fluid density measurement.
The method of claim 7 , wherein the fluid density estimation or fluid density measurement comprises a direct measurement of fluid density via a fluid density sensor of the one or more downhole fluid analysis sensors.
The method of claim 7 , wherein the fluid density estimation or fluid density measurement comprises an estimate of fluid density performed by the downhole well tool using one or more compositional measurements of the one or more fluids and a fluid model.
The method of claim 1 , wherein the downhole well tool comprises the control system, and wherein predicting the first predicted DTT surface gas rate comprises: determining, via the downhole well tool, a weight fraction for each fluid of the one or more fluids at a plurality of time steps; and determining, via the downhole well tool, a mass rate of each component of each fluid of the one or more fluids by multiplying the weight fraction for each component of each fluid of the one or more fluids by a total mass flowrate of the one or more fluids.
determining, via the downhole well tool, a weight fraction for each fluid of the one or more fluids at a plurality of time steps; and
determining, via the downhole well tool, a mass rate of each component of each fluid of the one or more fluids by multiplying the weight fraction for each component of each fluid of the one or more fluids by a total mass flowrate of the one or more fluids.
The method of claim 10 , comprising: determining, via the control system, a mass rate of gas released at a surface of the well by multiplying the mass rate of each component of each fluid of the one or more fluids with a vapor fraction of each component of each fluid of the one or more fluids; and determining, via the control system, a total mass of gas released at the surface of the well for each component of each fluid of the one or more fluids by summing the mass rate of gas released at the surface of the well over total time of the plurality of time steps.
determining, via the control system, a mass rate of gas released at a surface of the well by multiplying the mass rate of each component of each fluid of the one or more fluids with a vapor fraction of each component of each fluid of the one or more fluids; and
determining, via the control system, a total mass of gas released at the surface of the well for each component of each fluid of the one or more fluids by summing the mass rate of gas released at the surface of the well over total time of the plurality of time steps.
The method of claim 10 , comprising determining, via the control system, a total mass pumped into the wellbore of the well for each component of each fluid of the one or more fluids by summing the mass rate of each component of each fluid of the one or more fluids over total time of the plurality of time steps.
The method of claim 1 , comprising: determining, via the control system, a total number of moles of gas released at a surface of the well for each component of each fluid of the one or more fluids by dividing a mass of each component of each fluid of the one or more fluids by molecular weight of the one or more fluids; and determining, via the control system, a total volume of gas released at the surface of the well for each component of each fluid of the one or more fluids by multiplying a number of moles for each component of each fluid of the one or more fluids by a molecular volume for each component of each fluid of the one or more fluids.
determining, via the control system, a total number of moles of gas released at a surface of the well for each component of each fluid of the one or more fluids by dividing a mass of each component of each fluid of the one or more fluids by molecular weight of the one or more fluids; and
determining, via the control system, a total volume of gas released at the surface of the well for each component of each fluid of the one or more fluids by multiplying a number of moles for each component of each fluid of the one or more fluids by a molecular volume for each component of each fluid of the one or more fluids.
The method of claim 13 , comprising determining, via the control system, a total volume of gas released at the surface of the well by summing the total volume of gas released at the surface of the well for each component of each fluid of the one or more fluids.
The method of claim 1 , wherein the control system is a surface control system located at a surface of the well.
The method of claim 1 , wherein the downhole well tool comprises the control system.
The method of claim 1 , wherein the control system comprises a surface control system located at a surface of the well and a downhole control system disposed within the downhole well tool, wherein the surface control system and the downhole control system are communicatively coupled.
The method of claim 1 , further comprising: flowing the one or more fluids to a surface of the well, wherein the one or more fluids comprise gas and mud; and separating the gas and the mud of the one or more fluids at the surface using a separator.
flowing the one or more fluids to a surface of the well, wherein the one or more fluids comprise gas and mud; and
separating the gas and the mud of the one or more fluids at the surface using a separator.
Ref US20240401422A1: Claims:
A method comprising: conveying a wireline formation tester (WFT) via drill pipe within a wellbore penetrating a subterranean formation; setting two packers of the WFT on opposite sides of a zone of interest of the formation, thereby isolating an interval of an annulus between the WFT and a wall of the wellbore; performing deep transient testing of the formation by: operating WFT two pumps of the WFT to pump fluid from the formation via the isolated interval, through the WFT, and out of the WFT to the wellbore; and operating mud pumps to pump drilling mud into the wellbore and thereby convey a mixture of the drilling mud and the pumped formation fluid through the annulus to a mud gas separator located at a wellsite surface from which the wellbore extends; and using gas separated by the mud gas separator to measure a surface production rate of the formation fluid.
conveying a wireline formation tester (WFT) via drill pipe within a wellbore penetrating a subterranean formation;
setting two packers of the WFT on opposite sides of a zone of interest of the formation, thereby isolating an interval of an annulus between the WFT and a wall of the wellbore;
performing deep transient testing of the formation by: operating WFT two pumps of the WFT to pump fluid from the formation via the isolated interval, through the WFT, and out of the WFT to the wellbore; and operating mud pumps to pump drilling mud into the wellbore and thereby convey a mixture of the drilling mud and the pumped formation fluid through the annulus to a mud gas separator located at a wellsite surface from which the wellbore extends; and
operating WFT two pumps of the WFT to pump fluid from the formation via the isolated interval, through the WFT, and out of the WFT to the wellbore; and
operating mud pumps to pump drilling mud into the wellbore and thereby convey a mixture of the drilling mud and the pumped formation fluid through the annulus to a mud gas separator located at a wellsite surface from which the wellbore extends; and
using gas separated by the mud gas separator to measure a surface production rate of the formation fluid.
The method of claim 1 further comprising collecting samples of the formation fluid at or after an end of the deep transient testing.
The method of claim 1 further comprising performing downhole fluid analysis of the pumped formation fluid during the deep transient testing.
The method of claim 3 wherein the downhole fluid analysis comprises measuring, estimating, or determining one or more of pressure, contamination, gas-to-oil ratio, mass density, optical density, formation volume factor, viscosity, resistivity, fluorescence, American Petroleum Institute (API) gravity, and composition of the pumped formation fluid.
The method of claim 1 further comprising, prior to performing the deep transient testing: performing a pretest by operating the WFT pumps to pump fluid from the formation while sensing parameters of the pumped formation fluid to measure pressure of the formation and estimate mobility of the formation; after performing the pretest, activating a slip joint operable to compensate for temperature-dependent expansion and contraction of the drill pipe during at least the deep transient testing; after activating the slip joint, isolating the wellbore via operation of a blowout preventer (BOP); after isolating the wellbore via the BOP, operating the WFT pumps to pump a volume of fluid from the formation sufficient to reduce contamination of the pumped fluid to a predetermined level; and after sufficiently reducing contamination, operating the WFT pumps to perform a pressure buildup transient sufficiently long to identify radial flow of fluid from the formation and a wellbore skin.
performing a pretest by operating the WFT pumps to pump fluid from the formation while sensing parameters of the pumped formation fluid to measure pressure of the formation and estimate mobility of the formation;
after performing the pretest, activating a slip joint operable to compensate for temperature-dependent expansion and contraction of the drill pipe during at least the deep transient testing;
after activating the slip joint, isolating the wellbore via operation of a blowout preventer (BOP);
after isolating the wellbore via the BOP, operating the WFT pumps to pump a volume of fluid from the formation sufficient to reduce contamination of the pumped fluid to a predetermined level; and
after sufficiently reducing contamination, operating the WFT pumps to perform a pressure buildup transient sufficiently long to identify radial flow of fluid from the formation and a wellbore skin.
The method of claim 5 further comprising opening the BOP, then moving the WFT to another zone of interest, then repeating the deep transient testing and the surface production rate measurement.
A method comprising: utilizing a wellbore dynamics simulation to simulate liquid and gas behavior in a wellbore during a contemplated deep transient testing (DTT) of a subterranean formation penetrated by the wellbore, wherein the contemplated DTT utilizes a wireline formation tester (WFT) in the wellbore and a three-phase separator at a wellsite surface from which the wellbore extends, and wherein the simulated liquid and gas behavior in the wellbore includes during shut-in periods of the DTT and during drilling mud circulation periods of the DTT; utilizing results of the wellbore dynamics simulation to estimate: fluid migration velocity in the wellbore with and without drilling mud circulation; and mud column hydrostatic pressure behavior along the wellbore at any moment of the test; optimizing a job design for the contemplated DTT based on the wellbore dynamics simulation results, the estimated fluid migration velocity, and the estimated mud column hydrostatic pressure behavior; and performing the DTT by simultaneously: utilizing the WFT to pump fluid from the formation; utilizing mud pumps at the wellsite surface to pump drilling mud into the wellbore and, thereby, pump a mixture of the formation fluid and the drilling mud to the three-phase separator; and measuring gas rate obtained from the three-phase separator.
utilizing a wellbore dynamics simulation to simulate liquid and gas behavior in a wellbore during a contemplated deep transient testing (DTT) of a subterranean formation penetrated by the wellbore, wherein the contemplated DTT utilizes a wireline formation tester (WFT) in the wellbore and a three-phase separator at a wellsite surface from which the wellbore extends, and wherein the simulated liquid and gas behavior in the wellbore includes during shut-in periods of the DTT and during drilling mud circulation periods of the DTT;
utilizing results of the wellbore dynamics simulation to estimate: fluid 
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