The present disclosure relates generally to systems and methods for communicating electrical signals, such as power and data signals, in a well.
It is well known in the subterranean well drilling and completion arts to perform tests on formations intersected by a well bore. Such tests are typically performed in order to determine geological and other physical properties of the formations and fluids contained therein. For example, by making appropriate measurements, a formation's permeability and porosity, and the fluid's resistivity, temperature, pressure, and bubble point may be determined. These and other characteristics of the formation and fluid contained therein may be determined by performing tests on the formation before the well is completed. Formation sampling while drilling can be utilized to collect samples of formation fluid while drilling. During sampling while drilling, it can be difficult to obtain a clean sample due to the required power necessary to perform a pumpout operation.
For a more complete understanding of this disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts.
It should be understood at the outset that although an illustrative implementation of one or more embodiments are provided below, the disclosed systems and/or methods may be implemented using any number of techniques, whether currently known or in existence. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques illustrated below, including the exemplary designs and implementations illustrated and described herein, but may be modified within the scope of the appended claims along with their full scope of equivalents.
As utilized herein, “electrically coupling” indicates coupling of components (e.g., first component 45A and second component 45B of wet latch assembly 45) whereby an electrical signal (e.g., power and/or data signals) can be transferred between the electrically coupled components.
As utilized herein, the terms ‘virgin fluid’, ‘acceptable virgin fluid’, ‘uncontaminated fluid’, ‘virgin sample’, and the like are utilized to indicate a subsurface fluid that is pure, pristine, connate, uncontaminated, unadulterated, or otherwise considered in the fluid sampling and analysis field to be sufficiently or acceptably representative (e.g., to have a purity above a desired level and/or a level of contaminants below a desired or “threshold” level) of a given formation for valid hydrocarbon sampling and/or evaluation. A virgin fluid can be representative of the composition of unadulterated formation fluid under ambient formation conditions.
As utilized herein, “flow rate” can refer to volumetric flow rate (e.g., cm3/s).
A descriptor numeral can be utilized generically herein to refer to any embodiment of that component. For example, as described herein, a section or subassembly 31 of BHA 30 can refer to any section or subassembly 31A-31I depicted in
Herein disclosed are systems and methods for formation evaluation. Formation evaluation typically requires that fluid from the formation be drawn into a downhole drilling tool and/or a wireline tool for testing and/or sampling. Various devices, such as probes, are typically extended from the downhole tool to establish fluid communication with the formation surrounding the wellbore and to draw fluid into the downhole tool. A typical probe is a circular or prolate element that extends from the downhole tool and is thus positioned against a sidewall of the wellbore. A rubber packer at the end of the probe can be used to create a seal with the sidewall of the wellbore. In applications, a dual packer can be used to form a seal with the sidewall of the wellbore. With a dual packer, two elastomeric rings expand radially above and below the downhole tool to isolate a portion of the wellbore therebetween. The rings form a seal with the sidewall of the wellbore and permit fluid to be drawn into the isolated portion of the wellbore and into one or more inlets in the downhole tool. The mudcake lining the wellbore is often useful in assisting the probe and/or dual packers in making the seal with the sidewall of the wellbore. Once the seal is made, fluid from the formation can be drawn into the downhole tool through one or more inlets by lowering the pressure in the downhole tool relative to ambient formation pressure.
The collection and sampling of underground fluids contained in subsurface formations is well known. In the petroleum exploration and recovery industries, for example, samples of formation fluids are collected and analyzed for various purposes, such as to determine the existence, composition and/or producibility of subsurface hydrocarbon fluid reservoirs. This component of the exploration and recovery process can be crucial for developing drilling strategies, and can significantly impact financial expenditures. To conduct valid fluid analysis, the fluid samples obtained from the subsurface formation should be of sufficient purity, or be virgin fluid, to adequately represent the fluid contained in the formation and thus enable an accurate formation evaluation to be based thereon.
With reference to
As shown in
In order to perform a formation pumpout, the tool string 18 must typically remain stationary for a number of hours. During this time, mechanical pumps, such as mud motor 36, are actuated in order to draw fluid out of the formation 1 in an effort to flush the near wellbore 12 region with far field formation fluid 8 and clean the fluid stream of near wellbore drilling fluid filtrate contamination in order to acquire a low contamination sample. Unfortunately, the act of circulating mud lengthens the time of pumpout to obtain the cleanest sample possible and also increases a base level of contamination that may be achieved. According to this disclosure, a wet latch assembly is utilized to supply electric power from surface 5 to the formation tester 31B, and mud need not be circulated to provide power. Via the system and method of this disclosure, a level base level of contamination can thus be reduced, due to the absence of the degree of active invasion caused by the circulation of drilling fluid. Furthermore, a time required for a formation pumpout to reach a contamination level sufficiently close to the base level (e.g., to reach a threshold contamination level) can be reduced.
Because the formation tester 31B remains stationary for an extended period of time during the pumpout, a wireline cable 44 can be run through the interior flow bore 32 of the drill string 18 to a first section or subassembly (also referred to herein as a “wet connect collar”) 31A of BHA 30, described hereinbelow, whereby a first component (also referred to herein as a “wet connect”, a “wet latch”, or a “wet connect latch”) 45A of a wet latch assembly 45 can be electrically coupled with a second component 45B of the wet latch assembly 45 in order to supply power directly to the formation tester 31B via the assembled wet latch assembly 45. In order for this action to be practical, the first component 45A is retractable or retrievable from the wellbore 12, such as not to experience erosion or other damage during normal operations involving drilling fluid circulation.
The herein disclosed system and method comprise a first component 45A of a wet latch assembly 45 located in a BHA 30. The wet connect latch 45A is either retractable or disconnectable from the BHA 30, such that an interior flow bore 32B of the BHA 30 is not obstructed by the first component 45A during drilling. In other words, the first component or wet connect 45A remains flush with the inner surface of a drill pipe 18 during normal drilling operations (e.g., when drilling fluid is being circulated within flow bore 32 of drill string 18). The first component or wet connect 45A engages (e.g., extends into the interior flow bore 32B of the BHA 30) prior to latching with a wireline cable 44 via a second component 45B of the wet latch assembly 45.
With reference to
The BHA 30 comprises the first component 45A of the wet latch assembly 45 and a formation tester 31B (also referred to herein as a “formation tester section or subassembly 31B of BHA 30) and can include a downhole end comprising the drill bit 34. BHA 30 can comprise a number of other components. For example, BHA 30 can comprise a drill bit sub 35 for connection of the drill string with drill bit 34, a mud motor 36 operable to rotate drill bit 36, and a logging while drilling (LWD)/measuring while drilling (MWD) system (also referred to herein as a “formation testing system”) 31. Formation tester 31B can be a component of LWD/MWD system 31. BHA 30 can comprise a number of components and arrangements, as will be apparent to one of skill in the art and with the help of this disclosure.
The first component 45A of the wet latch assembly 45 is extendable into interior flow bore 32B of the BHA 30, and is configured for coupling, when extended into the interior flow bore 32B of the BHA 30, with a second component 45B of the wet latch assembly 45 to provide an assembled wet latch assembly 45, such that an electrical connection can be made between the first component 45A and the second component 45B.
The formation tester 31B is operable for performing a formation test, and is electrically connected with the first component 45A of the wet latch assembly 45, such that power can be provided to the formation tester 31B via the assembled wet latch assembly 45 during the formation test. The formation tester 31B can be a component of an LWD/MWD system 31. In embodiments, the LWD/MWD system 31 comprises one or more MWD sections, subassemblies or downhole tools operable to provide an MWD measurement selected from direction, inclination, survey data, downhole pressure (inside and/or outside drill pipe), resistivity, density, and/or porosity. For example, BHA 30 can comprise a section or subassembly 31D that can be an MWD subassembly configured for measuring direction and/or orientation; a section or subassembly 31F that can be an MWD subassembly configured for measuring pressure; a section or subassembly 31G that can be an MWD subassembly configured for measuring resistivity; and/or a section or subassembly 31I that can be an MWD subassembly configured for measuring density and/or porosity, for example, via gamma ray technology. BHA 30 can further comprise one or more sections or subassemblies comprising processors, such as section or subassembly 31C and section or subassembly 31E of
The BHA 30 can further comprise one or more rechargeable batteries. By way of non-limiting example, in
The formation tester 31B and/or another component of the BHA 30 can be electrically connected with the first component 45A of the wet latch assembly 45, such that telemetry of data can be provided from the formation tester 31B and/or from the another component of the BHA 30 uphole via the assembled wet latch assembly 45. For example, in embodiments, telemetry sub 31H is electrically connected with the first component 45A of the wet latch assembly 45, such that data obtained by one or more downhole tools of BHA 30 can be telemetered from the BHA 30 to the surface 5 (e.g., to an uphole processor 60, as depicted in
As depicted in the embodiment of
First section 31A of BHA 30 can comprise one or a plurality of (e.g., multiple, two, three, four, five, six, seven, eight, nine, or ten or more) first components 45A suitable for coupling with a second component 45B to provide a wet latch assembly 45. The first section 31A (e.g., the wet connect collar) may contain multiple (e.g., from 2 to 10, from 3 to 9, or from 2 to 8) first components 45A (e.g., wet connects) for redundancy or multiple use. For example, as depicted in the embodiment of
In embodiments comprising a plurality of first components 45A, the plurality of first components 45A can be spaced radially apart about an interior circumference of first section 31A that defines the portion of interior flow bore 32B of BHA 30 within first section 31A. Alternatively or additionally, as depicted in
As noted hereinabove, the first component 45A of the wet latch assembly 45 can be located in a first subassembly 31 of the BHA 30. The first subassembly 31B of the BHA 30 can be threadably connected with a last section of the conveyance 20, which conveyance can comprise, for example, drill pipe or coiled tubing. The last section of the conveyance 20 (e.g., of the drill pipe or coiled tubing) is a section of the conveyance 20 (e.g., coiled tubing or drill pipe) extending farthest into the wellbore 12 (e.g., farthest from surface 5 for a vertical wellbore 12). Although depicted as being in a separate section or subassembly 31 of BHA 30 in
A sealing mechanism on the first component or wet connect 45A can be operable to prevent drilling fluid from entering the wet connect housing (e.g., contact(s) housing 86 described hereinbelow with reference to
The first component of the wet latch assembly 45 can comprise a first contact component and the second component of the wet latch assembly 45 can comprise a second contact component. When the first component is coupled with the second component, an electrical signal can pass through the second contact component to the first contact component. The first contact component can comprise one or more contacts and the second contact component can comprise one or more contact receivers designed for electrically coupling with the contacts. In embodiments, the first component comprises a number of contacts and the second component comprises a same number of the contact receivers. For example, with reference to the embodiment of
With reference to the embodiment of
In embodiments, such as depicted in
The shape of first component 45A and the shape of second component 45B can be complementary, to facilitate coupling of the first component 45A with the second component 45B during assembling of wet latch assembly 45. The shape of first component 45A, second component 45B, or both can be asymmetric or otherwise designed to facilitate coupling of the first component with the second component during assembling of wet latch assembly 45.
The shape of the second component (e.g., jack 90 or contact receiver(s) housing 96) can be complementary to the shape of the first component (e.g., plug or contact(s) housing 86). For example, with reference back to
When second component 45B of the wet latch assembly 45 is coupled with the first component 45A of the wet latch assembly 45, the electrical connection is made between the first component 45A and the second component 45B, such that power can be provided to BHA 30 via uphole power source 50 (
As discussed further hereinbelow with reference to
A method of this disclosure will now be described with reference to
With reference now to
Method 100 comprises discontinuing drilling of the well by ceasing the drilling with (e.g., rotating of) the drill bit 34 at step 102. Method 100 further comprises assembling, downhole, a wet latch assembly 45, without removing the BHA 30 from wellbore 12. Assembling the wet latch assembly 45 comprises extending, into the interior flow bore 32B of the BHA 30, first component 45A of a wet latch assembly 45 to provide an extended first component 45A of the wet latch assembly 45, as depicted in
As depicted in
Assembling the wet latch assembly 45 can further comprise, as depicted in
As noted above, method 100 further comprises providing power to one or more components of BHA 30 via the assembled wet latch assembly 45 at step 104. Upon establishing the electrical connection/coupling of the first component 45A and the second component 45B, circulation of drilling fluid can be discontinued. Providing power to the one or more components of BHA 30 via the assembled wet latch assembly 45 at step 104 can comprise testing the formation 1 with the formation tester 31B, wherein testing the formation 1 comprises providing power to the formation tester 31B from the surface 5 (e.g., from power source 50) via the wet latch assembly 45 and the wireline cable 44. As detailed hereinabove, the formation tester 31B can comprise a logging while drilling (LWD) tool and/or a measurement while drilling (MWD) tool, such as a MWD or LWD tool, described hereinabove with reference to sections or subassemblies 31B-31I of
Testing the formation can be performed by any methods known to those of skill in the art, so long as power for the formation testing is provided at least in part via assembled wet latch assembly 45, such assembled wet latch assembly 45 depicted in
Due to powering of formation tester 31B via wet latch assembly 45 (and the concomitant absence or reduced amount of drilling fluid circulation during the pumpout), a pumpout time sufficient for the amount of the near wellbore contaminant present in the formation fluid to be reduced to a level at or below the threshold contamination level can be reduced relative to a pumpout time sufficient for the amount of the near wellbore contaminant present in the formation fluid to be reduced to the level at or below the threshold level via a formation tester 31B powered via circulation of wellbore drilling fluids. In embodiments, due to powering of formation tester 31B via wet latch assembly 45 (and absence of drilling fluid circulation during the pumpout), a pumpout can provide a formation sample having a level of contamination below (e.g., 1, 2, 3, 4, 5, 6, 7, 8, 9, or 10% less than) a level of contamination obtainable via a same formation tester 31B powered by circulation of wellbore drilling fluids. The threshold contamination level can be less than or equal to about 10, 9, 8, 7, 6, 5, 4, 3, 2, or 1 weight percent (wt %) contamination.
In embodiments, formation tester 31B comprises a focused or partially focused formation sampling apparatus. The terms “focused sampling” and “focused formation sampling” can refer to sampling (focused or partially focused) of a formation by manipulating the location of clean and contaminated formation fluid in the region of the formation in which the sampling is performed. The system and method of this disclosure can be utilized to provide power to a downhole formation tester to perform a formation sampling test that can provide one or more at least partially focused samples. In such applications, a single pump 70 of formation tester 31B can pump formation fluid via a sampling line 77 and a guard line 78 from a sampling zone and a guard zone, respectively, and a common line 78 to a discard line 74, configured to discard the fluid from the common line to the formation 1, or to one or more sample chambers 75, into which sample(s) of clean formation fluid can be collected for transport uphole for further formation evaluation. A flow restrictor can be utilized to restrict flow of fluid from guard line 76 during introduction of formation fluid into the one or more sample chamber(s) 75. One or more fluid identification (ID) sensors S can be located on the guard line 76, the sample line 77, and/or the common line 78, before or after pump 70, to determine when the pumpout time has been sufficient for the amount of the near wellbore contaminant present in the formation fluid in the sample line 77 to be reduced to the level at or below the threshold contamination level for sample collection in the one or more sample chambers 75. In the embodiment of
As an added advantage of the herein disclosed system and method, telemetry can also be supplied during the pumpout operations so that high resolution data can be transmitted uphole. The rate of wire line 44 telemetry is often on the order of a few (e.g., greater than or equal to about 1, 2, 3, 4, or 5) megabits (Mb)/s; thus, over the course of the few hours needed for a typical pumpout, data from a memory of the BHA (e.g., from processor section or subassembly 31C and/or processor section or subassembly 31E) can be uploaded to the surface 5 (e.g., to uphole processor 60) during the pumpout. Accordingly, in embodiments, method 100 further comprises supplying data telemetry from the formation tester 31B and/or from another component or subassembly 31 (e.g., section or subassembly 31C-31I in
As noted hereinabove, BHA 30 can comprise one or more rechargeable batteries, such as battery B1 of formation tester section or subassembly 31B, battery B2 of processor section or subassembly 31C, and battery B3 of processor section or subassembly 31E depicted in the embodiment of
Method 100 can further comprise, subsequent testing of the formation 1 and/or telemetry of data from BHA 30 to surface 5 (e.g., to uphole processor 60) via wet latch assembly 45 and wireline cable 44 and/or recharging of one or more rechargeable batteries of BHA 30 via wet latch assembly 45, wireline cable 44, and power source 50, retrieving the wireline cable 44 and the second component 45B of the wet latch assembly 45 from the wellbore 12. As depicted in
Alternatively, as depicted in
Subsequent retrieval of wireline cable 44 from wellbore 12, method 100 can further comprise continuing drilling of the well by recommencing drilling with the drill bit 34 (e.g., rotating of drill bit 34 or cutters thereof, as indicated by the arrow below drill bit 34 in
Also disclosed herein is a method of forming a BHA 30, the method comprising: coupling a first subassembly 31A of the BHA 30 comprising the first component 45A of the wet latch assembly 45 with a second subassembly 31B of the BHA 30 comprising the formation tester, such that power can be provided to the formation tester via the wet latch assembly 45 when the wet latch assembly 45 is assembled, wherein the first subassembly 31A has a first interior flow bore comprising a portion of BHA flow bore 32B and the second subassembly has a second interior flow bore comprising a portion of BHA flow bore 32B; and fluidly coupling the second subassembly 31B with the drill bit 34, whereby fluid can flow through the interior flow bore 32B of the BHA 30 comprising the interior flow bore of the first subassembly 31A and the interior flow bore of the second subassembly 31B through the drill bit 34 or vice versa. The method can further comprise coupling a third subassembly 36 comprising a rotational power generator with the drill bit 34 such that rotation of the drill bit 34 can be utilized to generate power, wherein the third subassembly 36 comprises a third interior flow bore comprising a portion of BHA flow bore 32B such that fluid can flow through the interior flow bore of the BHA 32B comprising the interior flow bore of the first subassembly 31A, the interior flow bore of the second subassembly 31B, and the interior flow bore of the third subassembly 36, through the drill bit 34 or vice versa. Such a method of forming a BHA 30 can further comprise coupling a fourth subassembly 31H into the BHA 30, wherein the fourth subassembly 31H comprises a pulse power generator operable to provide telemetry from one or more subassembly uphole (e.g., to uphole processor 60), wherein the fourth subassembly 31H comprises a fourth interior flow bore comprising a portion of BHA flow bore 32B, such that fluid can flow through the interior flow bore 32B of the BHA 30 comprising the interior flow bore of the first subassembly 31A, the interior flow bore of the second subassembly 31B, the interior flow bore of the third subassembly 36, and the interior flow bore of the fourth subassembly 31H, through the drill bit 34 or vice versa.
A method of this disclosure can comprise:
The order of the steps can be altered or two or more steps can be performed simultaneously or in an overlapping manner. For example, retracting the first component 45A of the wet latch assembly 45 from the interior flow bore 32B of the BHA 30 at step (14) can be performed prior to, during, and/or subsequent to decoupling the second component 45B of the wet latch assembly 45 from the extended first component 45A of the wet latch assembly 45 at step (12)(i).
Those of ordinary skill in the art will readily appreciate various benefits that may be realized by the present disclosure. The system and method of this disclosure allow power to be provided downhole to a formation tester 31B via a wet latch assembly 45 that provides an electrical connection (made downhole) between a first component 45A and a second component 45B. The first component 45A can be downhole prior to assembly of the wet latch assembly 45, and either remain downhole (e.g., be retracted into formation tester section or subassembly 31B) or be retrieved from the wellbore 12 subsequent use; and the second component 45B is conveyed downhole prior to assembly of the wet latch assembly 45 and retrieved from wellbore 12 subsequent use in wet latch assembly 45. Via the wet latch assembly 45 of this disclosure, electric power can be supplied more easily and less expensively than with conventional wired pipe.
The herein disclosed system and method can utilize a retractable or retrievable first component or wet connect 45A, such that an interior flow bore of a BHA 30 can be unimpeded by the wet connect subsequent operation of the wet latch assembly 45, prior to recommencement of mud circulation and drilling operations. Multiple first components of wet connect receptacles can be utilized to provide for multi-use operation. The use of a (e.g., retractable or retrievable) first component/wet connect 45A enables a wet latch assembly 45 of this disclosure to be utilized for providing power for formation testing on LWD.
By powering a pumpout via the wet latch assembly 45 rather than via circulation of drilling fluid, a better filter cake 4 can be maintained, due to a reduced amount of active invasion during the pumpout. By eliminating a need for the circulation of mud, which erodes the filter cake along the well bore, and can inhibit or prevent the filter cake from building to a sufficient thickness and can also can inhibit or prevent the curing of the filter cake, less leakage (e.g., a lower leakage rate) of mud filtrate into the formation from the filter cake is experienced relative to leakage experienced during drilling fluid circulation. Minimization of this active invasion can enable the acquisition of low contamination samples during the pumpout process of a formation testing, because a lower steady state contamination level is present. Accordingly, the system and method of this disclosure may provide for obtaining cleaner formation samples in a shorter period of time (e.g., a shorter pumpout time), optionally with the added advantages of providing telemetry to surface 5 (e.g., to uphole processor 60) during pumpout and potentially downloading information from memory on the BHA 30, and/or recharging battery components. The telemetry provided by the system and method of this disclosure can be superior to conventional pressure pulse (e.g., mud pulse) telemetry, which typically provides less than 10 bits per second. For example, the telemetry provided via the system and method of this disclosure can provide for data transmission at greater than or equal to about 1, 2, 3, 4, or 5 MB/s.
As will be known to those of skill in the art, at the end of a formation pumpout, a pressure wave or buildup produced by the formation fluid can be utilized to obtain information pertaining to an extent of the reservoir. By performing a pumpout via the herein disclosed system and method, without utilizing drilling fluid circulation for power production during formation testing (and pumpout), a better pressure measurement (e.g., a mini drill stem test (DST)) can be obtained due to the lack of the noise that is generally present due to the circulation of the drilling fluid. In embodiments, some amount of power required by BHA 30 is produced downhole and another amount is produced uphole and provided downhole via the wet latch assembly 45.
The system and method of this disclosure may further provide an advantage of better depth control on the wire line string 44, since the inner pipe tension would likely be more evenly distributed.
The following are non-limiting, specific embodiments in accordance with the present disclosure:
Embodiment A: A method comprising: without removing a BHA from a wellbore of a well extending into a formation, extending, into an interior flow bore of the BHA, a first component of a wet latch assembly to provide an extended first component of the wet latch assembly; conveying downhole via a wireline cable, from a surface through an interior flow bore provided by a drill string, a second component of the wet latch assembly, and coupling the second component of the wet latch assembly with the extended first component of the wet latch assembly such that an electrical connection is established between the first component and the second component and between the BHA and the surface via the wireline cable; and testing the formation with a formation tester of the BHA, wherein testing the formation comprises providing power and/or data telemetry for the formation tester via the wet latch assembly and the wireline cable.
Embodiment B: The method of claim 1 further comprising drilling, with a drill bit on a downhole end of the drill string, the wellbore, wherein the drill string comprises a conveyance coupled to the BHA whereby the conveyance and the BHA each have an interior flow bore and together provide the drill string with the interior flow bore provided by the drill string, and wherein the drilling comprises drilling while circulating a drilling fluid through the interior flow bore of the drill string, through ports in the drill bit, and through an annulus between the drill string and walls of the wellbore; and discontinuing drilling of the well by ceasing drilling with the drill bit.
Embodiment C: The method of Embodiment A or Embodiment B, wherein extending the first component is responsive to a signal received by the BHA from the surface.
Embodiment D: The method of any of Embodiment A to Embodiment C, wherein the second component is conveyed downhole through the interior flow bore provided by the drill string via circulation of the drilling fluid.
Embodiment E: The method of Embodiment D wherein the drilling fluid is circulated downhole at a first rate during the drilling, wherein the drilling fluid is circulated downhole at a second rate during the conveying downhole of the second component, and wherein the second rate is less than the first rate.
Embodiment F: The method of Embodiment D or Embodiment E further comprising, upon establishing the electrical connection, discontinuing circulation of the drilling fluid.
Embodiment G: The method of any of Embodiment A to Embodiment F, wherein the formation tester comprises a logging while drilling (LWD) tool and/or a measurement while drilling (MWD) tool.
Embodiment H: The method of any of Embodiment A to Embodiment G, wherein testing the formation comprises contacting a wellbore wall of the wellbore with a sampling probe of the formation tester and pumping formation fluid from the formation through the wellbore wall and probe into the formation tester.
Embodiment I: The method of Embodiment H, wherein the testing the formation further comprises determining an amount of a near wellbore contaminant present in the formation fluid.
Embodiment J: The method of Embodiment I, wherein the testing the formation further comprises pumping formation fluid from the formation for a pumpout period of time sufficient for the amount of the near wellbore contaminant present in the formation fluid to be reduced.
Embodiment K: The method of Embodiment J further comprising performing a drill stem test (DST) via the BHA subsequent the pumpout period of time.
Embodiment L: The method of any of Embodiment A to Embodiment K, wherein testing the formation comprises sampling the formation fluid and/or storing a sample of the formation fluid in the formation tester.
Embodiment M: The method of any of Embodiment I to Embodiment L, wherein the drilling fluid is an oil based drilling fluid and the near wellbore contaminant is an oleaginous filtrate from the drilling fluid during deposition of a filter cake on the walls of the wellbore by the oil based drilling fluid.
Embodiment N: The method of any of Embodiment A to Embodiment M, comprising supplying data telemetry from the formation tester and/or from another component of the BHA to the surface.
Embodiment O: The method of any of Embodiment I to Embodiment N further comprising supplying data telemetry from the formation tester to the surface, wherein the data telemetry is indicative of the amount of the near wellbore contaminant present in the formation fluid.
Embodiment P: The method of Embodiment O further comprising: analyzing, at the surface, the data telemetry to determine at least in part an amount of the near wellbore contaminant present in the formation fluid and whether to initiate the sampling of the formation fluid based at least in part upon the amount of the near wellbore contaminant; and upon a positive determination to initiate the sampling of the formation fluid, signaling the formation tester to sample the formation fluid.
Embodiment Q: The method of any of Embodiment A to Embodiment P further comprising recharging a battery of the BHA via the electrical connection.
Embodiment R: The method of any of Embodiment A to Embodiment Q further comprising: subsequent the testing the formation, retrieving the wireline cable and the second component of the wet latch assembly from the wellbore.
Embodiment S: The method of Embodiment R: wherein the first component of the wet latch assembly is retracted from the interior flow bore of the BHA subsequent the testing of the formation, such that the interior flow bore of the BHA is substantially unobstructed; or wherein the first component of the wet latch assembly decouples from the BHA, remains coupled to the second component of the wet latch assembly, and is retrieved from the wellbore with the wireline cable and the second component of the wet latch assembly, such that the interior flow bore of the BHA is substantially unobstructed.
Embodiment T: The method of any of Embodiment B to Embodiment S further comprising: continuing drilling of the well by recommencing drilling with the drill bit and recommencing circulation of the drilling fluid downhole through the interior flow bore of the drill string, through ports in the drill bit, and uphole through the annulus between the drill string and walls of the wellbore.
Embodiment U: The method of Embodiment T further comprising: discontinuing drilling of the well by ceasing the drilling with the drill bit; without removing the BHA from the wellbore, extending, into the interior flow bore of the BHA to provide an extended first component, the first component of the wet latch assembly for a second time or another first component of the wet latch assembly for a first time; conveying downhole via the wireline cable, from the surface through the interior flow bore provided by the drill string, the second component of the wet latch assembly, and coupling the second component of the wet latch assembly with the extended first component of the wet latch assembly such that an electrical connection is established between the first component and the second component and between the BHA and the surface via the wireline cable; and testing the formation with the formation tester for at least a second time, wherein testing the formation comprises providing power to the formation tester from the surface via the wet latch assembly and the wireline cable.
Embodiment V: A method comprising: (1) discontinuing drilling, with a drill string, of a well comprising an uncased wellbore intersecting a subsurface zone of interest below a surface, wherein the drill string comprises a conveyance and a bottom hole assembly (BHA) coupled to the conveyance, wherein the BHA comprises a formation tester and has a downhole end comprising a drill bit, wherein the conveyance and the BHA each have an interior flow bore and together provide the drill string with an interior flow bore extending from the surface to the drill bit, and wherein discontinuing the drilling comprises ceasing the drilling with the drill bit; (2) without removing the BHA from the wellbore, extending, into the interior flow bore of the BHA, a first component of a wet latch assembly to provide an extended first component of the wet latch assembly; (3) conveying downhole via a wireline cable, from the surface through the interior flow bore provided by the drill string, a second component of the wet latch assembly, wherein the conveying comprises circulating a drilling fluid downhole through the interior flow bore of the drill string, through ports in the drill bit, and uphole through an annulus between the drill string and walls of the wellbore; (4) providing an assembled wet latch assembly by coupling the second component of the wet latch assembly with the extended first component of the wet latch assembly such that an electrical connection is established between the first component and the second component and between the BHA and the surface via the wireline cable; (5) discontinuing circulating of the drilling fluid downhole through the interior flow bore of the drill string, through ports in the drill bit, and uphole through the annulus between the drill string and walls of the wellbore; (6) supplying power to the formation tester and/or another component of the BHA from the surface and/or telemetry of data between the formation tester and/or the another component of the BHA and the surface via the assembled wet latch assembly and the wireline cable; (7) initializing a testing of the formation, wherein the testing of the formation comprises performing a pumpout of the formation and sampling the formation; (8) performing the pumpout of the testing of the formation, wherein performing the pumpout comprises pumping formation fluid from the formation for a period of time sufficient for the amount of a near wellbore contaminant present in the formation fluid to be reduced; (9) supplying telemetry of data between the formation tester and/or another component of the BHA and the surface via the assembled wet latch assembly during the pumpout; (10) analyzing data telemetered from the formation tester to the surface at (9) indicative of the amount of the near wellbore contaminant present in the formation fluid to determine whether to initiate a sampling of the formation fluid and, upon a positive determination to initiate the sampling of the formation fluid, signaling the formation tester to sample the formation fluid, wherein sampling the formation fluid comprises taking a measurement of a property of the formation fluid and/or storing a sample of the formation fluid in the formation tester; (11) optionally recharging a battery of the formation tester and/or a battery of another component of the BHA via the assembled wet latch assembly at any time subsequent (4) and prior to (12); (12) subsequent the sampling of the formation fluid, (i) decoupling the second component of the wet latch assembly from the extended first component of the wet latch assembly or (ii) disconnecting the first component of the wet latch assembly from the BHA; (13) retrieving the wireline cable from the wellbore; (14) retracting the first component of the wet latch assembly from the interior flow bore of the BHA if the second component of the wet latch assembly was decoupled from the extended first component of the wet latch assembly at (12)(i); (15) recommencing circulation of the drilling fluid downhole through the interior flow bore of the drill string, through ports in the drill bit, and uphole through the annulus between the drill string and walls of the wellbore; and (16) continuing drilling of the well by recommencing drilling with the drill bit.
Embodiment W: A bottom hole assembly (BHA) comprising: a first component of a wet latch assembly, the first component configured for coupling, when extended into the interior flow bore of the BHA, with a second component of the wet latch assembly to provide an assembled wet latch assembly, such that an electrical connection can be made between the first component and the second component; and a formation tester operable for performing a formation test, the formation tester electrically connected with the first component of the wet latch assembly, such that power and/or telemetry can be provided to the formation tester via the assembled wet latch assembly during the formation test.
Embodiment X: The BHA of Embodiment W further comprising a battery, wherein the battery is electrically connected with the first component of the wet latch assembly, such that power can be provided to the battery via the assembled wet latch assembly.
Embodiment Y: The BHA of Embodiment W or Embodiment X, wherein the formation tester and/or another component of the BHA is electrically connected with the first component of the wet latch assembly, such that telemetry of data can be provided from the formation tester and/or the another component of the BHA uphole via the assembled wet latch assembly.
Embodiment Z1: The BHA of any of Embodiment W to Embodiment Y, wherein the first component of the wet latch assembly is located in a first subassembly of the BHA, wherein the first subassembly of the BHA is distal a drill bit located on a downhole end of the BHA.
Embodiment Z2: The BHA of any of Embodiment W to Embodiment Z1, wherein the first component is retractable back out of the interior flow bore of the BHA subsequent extension of the first component into the interior flow bore during the performing of the formation test and/or wherein the first component is designed for breakaway from the BHA subsequent the performing of the formation test.
Embodiment Z3: The BHA of any of Embodiment W to Embodiment Z2 comprising multiple first components.
Embodiment Z4: The BHA of Embodiment Z3, wherein the multiple first components of the wet latch assembly are positioned about an interior circumference of the interior flow bore of the BHA.
Embodiment Z5: The BHA of any of Embodiment W to Embodiment Z4, wherein the first component comprises a first contact component comprising a plug having one or more pins configured for coupling with a second contact component of the second component, wherein the second contact component comprises a complementary jack having one or more holes configured to accept the one or more pins of the plug.
Embodiment Z6: The BHA of any of Embodiment W to Embodiment Z5, wherein the formation tester further comprises a sampling probe, wherein the sampling probe is configured for contacting the wellbore wall during pumping of formation fluid from the formation through the wellbore wall and the sampling probe into the formation tester during the performing of the formation test.
Embodiment Z7: A system comprising: a drill string comprising a conveyance coupled to the BHA of any of Embodiment V to Embodiment Z5, wherein the conveyance also comprises an interior flow bore, such that the flow bore extends from the surface to a drill bit on a downhole end of the BHA, whereby, during drilling, a drilling fluid can be circulated downhole through the interior flow bore of the drill string, through ports in the drill bit, and uphole through an annulus between the drill string and walls of the wellbore; the second component of the wet latch assembly, wherein the second component of the wet latch assembly is coupled with the first component of the wet latch assembly such that the electrical connection is made between the first component and the second component, and wherein the second component is attached to a logging cable, wherein the logging cable extends to a surface from which the drill string extends.
Embodiment Z8: The system of Embodiment Z7, wherein the drill string further comprises drill pipe or coiled tubing.
Embodiment Z9: The system of Embodiment Z8, wherein the first component of the wet latch assembly is located in a first subassembly of the BHA, wherein the first subassembly of the BHA is threadably connected with a last section of the drill pipe or coiled tubing, wherein the last section of drill pipe or coiled tubing is a section of coiled tubing or drill pipe extending farthest into the wellbore.
Embodiment Z10: The system of any of Embodiment Z7 to Embodiment Z9, wherein the first component comprises a first contact component comprising a plug having one or more pins.
Embodiment Z11: The system of Embodiment Z10, wherein the second component comprises a second contact component including a complementary jack having one or more holes configured to accept the one or more pins of the plug.
Embodiment Z12: The system of Embodiment Z11, wherein the first component and/or the second component comprises a rubber and/or fluid filled housing, such that the first contact component of the first component, the second contact component of the second component, or both can be wiped clean during coupling and de-coupling of the first component and the second component.
Embodiment Z13: The system of any of Embodiment Z7 to Embodiment Z12, wherein the second component is asymmetric or otherwise designed to facilitate coupling of the first component with the second component.
Embodiment Z14: The system of any of Embodiment Z7 to Embodiment Z13, wherein the first component is spring loaded for extension into the interior flow bore of the BHA or for retraction from the interior flow bore of the BHA.
Embodiment Z15: A method of forming a BHA of any of Embodiment W to Embodiment Z6, the method comprising: coupling a first subassembly of the BHA comprising the first component of the wet latch assembly with a second subassembly of the BHA comprising the formation tester, such that power and/or telemetry can be provided to the formation tester via the wet latch assembly when the wet latch assembly is assembled, wherein the first subassembly has a first interior flow bore and the second subassembly has a second interior flow bore.
Embodiment Z16: The method of Embodiment Z15 further comprising: fluidly coupling the second subassembly with a drill bit on a downhole end of the BHA, whereby fluid can flow through the interior flow bore of the BHA comprising the interior flow bore of the first subassembly and the interior flow bore of the second subassembly through the drill bit or vice versa; and coupling a third subassembly comprising a rotational power generator with the drill bit such that rotation of the drill bit can be utilized to generate power, wherein the third subassembly comprises a third interior flow bore such that fluid can flow through the interior flow bore of the BHA comprising the interior flow bore of the first subassembly, the interior flow bore of the second subassembly, and the interior of the third subassembly, through the drill bit or vice versa.
Embodiment Z17: The method of Embodiment Z16 further comprising coupling a fourth subassembly into the BHA, wherein the fourth subassembly comprises a pulse power generator operable to provide telemetry from one or more subassembly uphole, wherein the fourth subassembly comprises a fourth interior flow bore, such that fluid can flow through the interior flow bore of the BHA comprising the interior flow bore of the first subassembly, the interior flow bore of the second subassembly, the interior flow bore of the third subassembly, and the interior flow bore of the fourth subassembly, through the drill bit or vice versa.
Embodiment Z18: A method comprising: drilling, with a drill string, a well comprising an uncased wellbore intersecting a subsurface zone of interest below a surface, wherein the drill string comprises a conveyance and a bottom hole assembly (BHA) of any of Embodiment V to Embodiment Z5 coupled to the conveyance, wherein the conveyance and the BHA each have an interior flow bore and together provide the drill string with an interior flow bore extending from the surface to the drill bit, and wherein the drilling comprises drilling with the drill bit while circulating a drilling fluid downhole through the interior flow bore of the drill string, through ports in the drill bit, and uphole through an annulus between the drill string and walls of the wellbore; discontinuing drilling of the well by ceasing the drilling with the drill bit; without removing the BHA from the wellbore, extending, into the interior flow bore of the BHA, the first component of a wet latch assembly to provide an extended first component of the wet latch assembly; conveying downhole via a wireline cable, from the surface through the interior flow bore provided by the drill string, the second component of the wet latch assembly, and forming the assembled wet latch assembly by coupling the second component of the wet latch assembly with the extended first component of the wet latch assembly such that the electrical connection is established between the first component and the second component and between the BHA and the surface via the wireline cable; and testing the formation with the formation tester, wherein testing the formation comprises providing power and/or telemetry to the formation tester from the surface via the assembled wet latch assembly and the wireline cable.
Embodiment Z19: A method comprising: (1) discontinuing drilling, with a drill string, of a well comprising an uncased wellbore intersecting a subsurface zone of interest below a surface, wherein the drill string comprises a conveyance and a bottom hole assembly (BHA) of any of Embodiment V to Embodiment Z5 coupled to the conveyance, wherein the conveyance and the BHA each have an interior flow bore and together provide the drill string with an interior flow bore extending from the surface to the drill bit, and wherein discontinuing the drilling comprises ceasing the drilling with the drill bit; (2) without removing the BHA from the wellbore, extending, into the interior flow bore of the BHA, the first component of the wet latch assembly to provide an extended first component of the wet latch assembly; (3) conveying downhole via a wireline cable, from the surface through the interior flow bore provided by the drill string, the second component of the wet latch assembly, wherein the conveying comprises circulating a drilling fluid downhole through the interior flow bore of the drill string, through ports in the drill bit, and uphole through an annulus between the drill string and walls of the wellbore; (4) providing an assembled wet latch assembly by coupling the second component of the wet latch assembly with the extended first component of the wet latch assembly such that the electrical connection is established between the first component and the second component and between the BHA and the surface via the wireline cable; (5) discontinuing circulating of the drilling fluid downhole through the interior flow bore of the drill string, through ports in the drill bit, and uphole through the annulus between the drill string and walls of the wellbore; (6) supplying power to the formation tester and/or another component of the BHA from the surface and/or telemetry of data between the formation tester and/or another component of the BHA and the surface via the assembled wet latch assembly and the wireline cable; (7) initializing a testing of the formation, wherein the testing of the formation comprises performing a pumpout of the formation and sampling the formation; (8) performing the pumpout of the testing of the formation, wherein performing the pumpout comprises pumping formation fluid from the formation for a period of time sufficient for the amount of a near wellbore contaminant present in the formation fluid to be reduced; (9) optionally supplying telemetry of data between the formation tester and/or another component of the BHA and the surface via the assembled wet latch assembly during the pumpout; (10) analyzing data telemetered from the formation tester to the surface at (9) indicative of the amount of the near wellbore contaminant present in the formation fluid to determine whether to initiate a sampling of the formation fluid and, upon a positive determination to initiate the sampling of the formation fluid, signaling the formation tester to sample the formation fluid, wherein sampling the formation fluid comprises taking a measurement of a property of the formation fluid with the formation tester and/or storing a sample of the formation fluid in the formation tester; (11) optionally recharging a battery of the formation tester and/or a battery of another component of the BHA via the assembled wet latch assembly at any time subsequent (4) and prior to (12); (12) subsequent the sampling of the formation fluid, (i) decoupling the second component of the wet latch assembly from the extended first component of the wet latch assembly or (ii) disconnecting the first component of the wet latch assembly from the BHA; (13) retrieving the wireline cable from the wellbore; (14) retracting the first component of the wet latch assembly from the interior flow bore of the BHA if the second component of the wet latch assembly was decoupled from the extended first component of the wet latch assembly at (12)(i); (15) recommencing circulation of the drilling fluid downhole through the interior flow bore of the drill string, through ports in the drill bit, and uphole through the annulus between the drill string and walls of the wellbore; and (16) continuing drilling of the well by recommencing drilling with the drill bit.
While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of this disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the embodiments disclosed herein are possible and are within the scope of this disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, R1, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=R1+k*(Ru−R1), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.
Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. The discussion of a reference herein is not an admission that it is prior art, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.
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