EQUIPMENT AND METHOD OF USING SAME

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of US Provisional Application No. 62/134,824, filed on March 18, 2015, and US Provisional Application No. 62/299,581, filed on

February 25, 2016, the entire contents of each are incorporated by reference herein.

BACKGROUND [0002] The present disclosure relates generally to testing wellsite equipment, and in particular, but not limited to, tools and methods for testing and/or characterizing the integrity and functionality of the wellsite equipment.

[0003] Exploration may be used to locate valuable hydrocarbons, such as oil and gas. Rigs are located at wellsites to drill wellbores to access subsurface reservoirs and produce fluids. Various equipment is used at the wellsite to perform various functions, such as drilling, wireline, completion, production, etc. Such equipment includes, for example, rigs to drill the wellbores, wireline tools deployable into the wellbore to perform subsurface tests, injection tools to inject fluid into formations, production tools to produce fluids, and blowout preventers to prevent leakage of fluids from the wellbore. [0004] Tests may be performed at the wellsite to assure proper operation of the wellsite. For example, downhole tools, such as the wireline tools, are deployed by a wireline into the wellbore to collect subsurface samples for evaluation. Such downhole tools are also provided with devices to take downhole measurements and communicate with the surface via the wireline cable. [0005] Tests may also be performed to assure proper operation of the wellsite equipment. For example, regulations exist that require testing, inspection and maintenance of well systems to ensure that the well systems are operating properly. Current regulations require that the components of the well systems, such as the blowout preventers (BOP), are tested regularly to ensure proper operation and to assure that such systems hold the required functionality and pressure. See, for example, 30 CFR § 250.516. [0006] Such tests may be time consuming and may be required at regular intervals. As such, there exists a need to provide techniques for efficiently performing tests in a manner that assures proper operation of wellsite equipment. The present disclosure is directed at such a need. SUMMARY

[0007] In at least one aspect, the disclosure relates to a test tool for testing wellsite equipment of a wellsite positioned about a subsurface formation. The test tool includes a test body, a cable head, and a no-go guide. The test body is deployable into the wellsite equipment via a wireline, and has a test portion with an outer surface shaped to receivably engage the wellsite equipment upon activation of the wellsite equipment. The cable head is at a surface end of the test body, and is operatively connectable to the wireline. The no- go guide is at a subsurface end of the test body, and has an outer surface shaped to conform to an inlet of the wellsite equipment and seatable therein to position the test portion about the wellsite equipment whereby performance of the wellsite equipment may be determined. [0008] In another aspect, the disclosure relates to a test tool for testing wellsite equipment of a wellsite positioned about a subsurface formation. The test tool included a test body and sensor(s). The test body is deployable into the wellsite equipment via a wireline. The test body has a cable head at a surface end and a no-go guide at a subsurface end with a test portion between the cable head and the no-go guide. The cable head is connected to the wireline. An outer surface of the test body is shaped to receivably engage the wellsite equipment upon activation of the wellsite equipment. The no-go guide seatable in the wellsite equipment to position the test portion about the wellsite equipment during engagement thereby whereby performance of the wellsite equipment may be determined. The sensor is positioned about the test body to measure wellsite parameters. [0009] Finally, in another aspect, the disclosure relates to a method of testing wellsite equipment of a wellsite positioned about a subsurface formation. The method involves deploying a test tool from a surface location of the wellsite and into the wellsite equipment. The test tool includes a cable head at a surface end and a no-go guide at a subsurface end with a test portion between the cable head and the no-go guide. The method further involves determining performance of the wellsite equipment by seating the no-go guide into an inlet of the wellsite equipment and activating the wellsite equipment to engage the test portion.

[0010] Various aspect of the disclosure may also relate to a method for testing wellsite equipment, such as function testing the integrity of a hydrocarbon well system. The method includes the steps of lowering a test tool to subsurface equipment via a wireline. The method includes determining relative placement of the tool and the BOP with a no-go guide positioned near a subsurface end of the test tool. The no-go guide has a

flanged/bullnose portion. The method may further include engaging the no-go guide in the wellsite equipment for testing. The method may involve, for example, placing the no-go guide in the wellhead and performing a BOP function test.

[0011] In yet another aspect, at least one embodiment of the present disclosure is directed to a test tool that is instrumented to include at least one sensor for characterizing the BOP and/or the riser.

[0012] In another aspect, at least one embodiment of the present disclosure is directed to a method of using a wireline-conveyed test tool as a test plug for pressure testing. The method includes positioning the tool in a BOP and using the no-go of the tool as a subsea- removable test plug to isolate the well from the pressure test.

[0013] In yet another aspect, at least one embodiment of the present disclosure relates to a method of using the wireline-conveyed test tool as a detachable test plug for pressure testing the shear rams.

[0014] A pipe tool and complementary methods and systems are presented for testing the integrity of a hydrocarbon well system. In one aspect, a pipe tool is disclosed, including an adapter connecting the pipe tool to a wireline, a guide for positioning the pipe tool in the wellsite equipment, and a test body extending between the adapter and the guide. [0015] In another aspect, a method is disclosed for testing the integrity of a hydrocarbon well system. The method includes the steps of lowering a pipe tool through a riser of an offshore rig and to subsurface equipment via a wireline. The method includes determining relative placement of the test tool to the wellsite equipment and a no-go guide positioned near a subsurface end of the test tool having a flange portion to determine a no-go stop relative to the wellsite equipment. [0016] The test tool may be instrumented to include at least one sensor for characterizing the BOP and/or riser. The test tool may also contain a subsystem including an expanded portion or bird's nest along the test body to prevent the wireline from falling therebelow.

BRIEF DESCRIPTION OF DRAWINGS [0017] Figure 1 is a schematic diagram of an offshore wellsite with a test tool deployed into wellsite equipment in accordance with at least one aspect of the present disclosure.

[0018] Figures 2 A - 2E are schematic diagrams illustrating additional views of deployment of the test tool into wellsite equipment including a BOP in accordance with at least one aspect of the present disclosure. [0019] Figure 3 is a schematic diagram illustrating a unitary test tool in accordance with at least one aspect of the present disclosure.

[0020] Figures 4A-4C are plan, cross-sectional, and exploded views, respectively, illustrating a modular test tool in accordance with at least one aspect of the present disclosure. [0021] Figure 5 is a cross-sectional view illustrating the test tool of Figure 4A positioned in the wellsite equipment for testing in accordance with at least one aspect of the present disclosure.

[0022] Figures 6A and 6B are schematic diagrams illustrating a detachable test tool in accordance with at least one aspect of the present disclosure. [0023] Figures 7A-7C are schematic diagrams depict various versions of an instrumented test tool in accordance with at least one aspect of the present disclosure.

[0024] Figure 8 is a flow chart depicting a method of testing wellsite equipment.

DETAILED DESCRIPTION

[0025] In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it will be understood by those skilled in the art that the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments are possible. [0026] A test tool for testing wellsite equipment is provided. The test tool includes a test body that is deployable through or into the wellsite equipment and seatable therein for performing tests of the wellsite equipment. The test tool may include a test body with a cable head and a no-go guide. The cable head is connectable to existing wireline rigging. The no-go guide is matingly receivable in the wellsite equipment and seatable therein for testing. The tool may be unitary or modular, and provided with sensors for taking measurements to verify health of the wellsite equipment.

[0027] In at least one implementation, the test tool and methods presented herein are designed to perform tests using existing wireline rigging. These may also be used to reduce, or eliminate, the need to trip drill pipe into and out of wellsite equipment, for example, for functional testing of the BOP. In at least one other implementation, the tool and testing method presented herein may provide a better understanding of reliability and maintenance needs of the wellsite equipment. The various embodiments presented herein have the potential to safely test the health of various equipment, such as the riser, the BOP and/or other wellsite equipment, which may reduce significant costs per exploration well and accelerate time to first oil. These embodiments may also be used to enable expedition of testing.

[0028] Figures 1 - 2E depict various examples of wellsites 100, 200 with a test tool (or assembly) 104 for testing wellsite equipment 102a-c, 202a-c. The examples shown include offshore wellsites with wellsite equipment 102a-c, 202a-c positioned at various locations about the wellsites. The wellsites 100, 200 are depicted as being positioned at offshore locations above a wellbore 106 extending through sea floor 108, but could also be land- based. The test tool 104 is deployed from a surface location and through the wellsite equipment 102a-c, 202a-c via a wireline 112. [0029] Figure 1 shows a wellsite 100 including surface wellsite equipment 102a, subsurface wellsite equipment 102c, and intermediate wellsite equipment 102b therebetween. The surface wellsite equipment 102a includes an offshore platform 114 with a rig 116 and a surface unit 118 at a surface location. The rig 116 may include conventional wireline rigging for deploying wireline logging or other tools from the surface. The term "wireline" as used herein should be interpreted to include slickline and E-line or other conveyance for deploying logging or testing tools where appropriately relevant as determined by a person having ordinary skill in the art.

[0030] The subsurface equipment 102c includes wellsite equipment 121 positioned about the sea floor 108. Intermediate wellsite equipment 102b includes a riser 120 suspended below the platform 114 and to the subsurface wellsite equipment 102c. The wellsite equipment 102a-c has a passage 122 for passing equipment and/or materials therethrough. As shown the test tool 104 is deployed from the offshore platform 114 via the wireline 112, and passes through the riser 120 into the subsurface wellsite equipment 102c. The test tool 104 may be configured for performing tests about the wellsite 100 as it passes through the wellsite equipment 102a,b and/or when seated in the subsurface wellsite equipment 102c (e.g., lower marine riser package (LMRP) 221) as is described further herein.

[0031] Referring to Figures 2A - 2E, deployment of the test tool 104 into subsea equipment 202c including an LMRP 221 is illustrated. As shown in Figure 2A, the wellsite 200 is an offshore wellsite and the surface wellsite equipment 202a includes a vessel 224 at a surface location. The test tool 104 is shown as being lowered to the subsurface wellsite equipment 202c from the offshore vessel 224 via the wireline 112. Although, not illustrated for simplification purposes, the test tool 104 may be lowered to the subsurface wellsite equipment 202c through a riser at 202b (e.g., riser 120 of Figure 1).

[0032] As shown in further detail in Figures 2A - 2E, the subsurface wellsite equipment 202c is an LMRP 221 connected to a wellhead 226 positioned about the wellbore 106. The test tool 104 passes into the LMRP 221 and a subsurface end of the test tool 104 is seated in a wear bushing 228 (inlet) of the wellhead 226 for testing as is described further herein.

[0033] Referring now to Figure 3, an embodiment of the test tool 304 is illustrated. The test tool 304 includes an elongate test body 330 with a cable (or wireline) head 332 at a surface end and a no-go guide 334 at a subsurface end thereof. The test body 330 may be a tubular body (or shaft) deployable into and/or through various wellsite equipment. The test body 330 may be, for example, one or more sections of pipe (or bar). In the example shown, the test body 330 is integral with the no-go guide 334, and connected to the cable head 332. [0034] The test body 330 may be connected to the wireline 112 by the cable head 332. The cable head may be in the form of, or include, an adapter (or "wireline head adaptor") connecting the test tool 304 to the wireline 112. The cable head 332 may have a cylindrical portion conforming to the shape of the test body 330 and having a tapered upper end to receive the wireline 112. The cable head 332 may be removably connected to the test body 330 or integral therewith. The cable head 332 may also be removably connected to the wireline 112. The cable head 332 may include a conventional quick release mechanism or other device capable of connection to the wireline 112.

[0035] The cable head 332 and/or test body 330 may be provided with electronics 336 for exchanging signals with the surface via the wireline 112. The electronics 336 may be positioned in various portions of the test tool 304, such as in the cable head 332 as shown. The electronics 336 may include, for example, power and/or communication devices (e.g., transceivers, batteries, etc.) for operation with the wireline 112.

[0036] The no-go guide 334 may be removably connected to the test body 330 or integral therewith. The no-go guide 334 may be shaped for matable and/or receivable engagement by the wellsite equipment, such as the wellhead 226 as shown in Figures 2B, 2C and 2E. As shown, the no-go guide 334 has a ring portion 338 with a tapered portion 340 extending therefrom. The tapered portion 340 has a shape corresponding to the wellhead 226 and seatable therein. The ring portion 338 has an outer diameter Dr larger than an outer diameter Db of the tubular body. The ring portion 338 may conform to a surface of the wellhead 226 and support the test tool 334 thereon. The ring portion 338 may also terminate advancement of the no-go guide 334 into the wellhead 226 to prevent the test tool 304 from passing therethrough.

[0037] The test body 330 may have dimensions configured to fit through and/or into various of the wellsite equipment. The test body 330 as shown is generally cylindrical in shape, having the outside diameter Db similar to a drill pipe (for example, but not limited to, 3 1/2 inches (8.9cm), 4 inches (10.2 cm), 5 inches (12.7 cm), 5 1/2 inches (14.0 cm), 5 7/8 inches (14.9 cm), or 6 5/8 inches (16.8 cm)). The test body 330 may have a height Hb longer than the wellsite equipment being tested. The length of the tool may be determined as a function of the height of the wellsite equipment to be tested. The test body 330 may have an outer surface along portions thereof shaped for engagement by the wellsite equipment as is described further herein

[0038] Figures 4 A - 4C show another version of the test tool 404. In this version, the test tool 404 includes an elongate test body 430, a cable head 432, and a no-go guide 434. This version also includes a centralizer 436 and a bumper 438.

[0039] In this version, the test tool 404 is a modular tool with the cable head 432 and no- go guide 434 threadedly connected to the test body 430. The test tool 404 has a passage 440 extending therethrough. The passage 440 may be used to support the wireline 112, electronics, or other devices therein. The cable head 432 receives the wireline 112 through the upper end thereof. The wireline 112 may be connected to electronics within the test tool for operation therewith.

[0040] The no-go guide 434 of this version includes tapered upper and lower ends with a flanged (expanded) portion therebetween. The no-go guide 434 may be shaped to facilitate insertion and removal of the test tool through the wellsite equipment. The tapers may be used, for example, to prevent the no-go guide from being snagged on any portions of the wellsite equipment as it passes therethrough. The tapered upper end is connectable to the test body 430 and conforms to the shape thereof. The tapered upper end tapers out to the flanged portion. The flange portion has an outer diameter Df greater than the diameter Db of the test body 430. The tapered lower portion of the no-go guide 434 tapers from the flange portion to a reduced diameter De at the subsurface end thereof. The tapered lower portion is receivably engaged by the wellsite equipment and seatable therein.

[0041] The tapered lower portion is shaped to conform to a seat in the wellsite equipment, such as the wear bushing 228 in the wellhead 226 of Figure 2C and 2E, and to rest therein in mating engagement with the wear bushing. The tapered lower portion may engage the wellhead 226 by seating, mating engagement, contact, connection, landing thereon, and/or other means of engagement. For example, the tapered lower portion may have a tapered mating surface to rest in the wear bushing 228 of the well head 226 and seat therein with or without connection to the wear bushing 228. The mating between the tapered lower portion and the well head wear bushing 228 can provide a set depth of the test tool 404 and keep the subsurface portion of the test tool 404 centered within the wellsite equipment. [0042] The flange/bullnose portion defines a no-go stop that may be tapered to mate with an inlet or seat in the wellsite equipment, such as the wear bushing 228 in the wellhead 226. This portion may also be used to prevent the test tool 404 from entering the wellbore and/or to vertically center the test tool 404 within the wellsite. The shape of the no-go guide 434 and/or the flange portion thereof may be dimensioned to support the test tool in the seated position on the wellsite equipment and/or terminate advancement therethrough.

[0043] The mating surface of the no-go guide 434 may be lined with a material adapted to minimize damage to the wellsite equipment (e.g., the wear bushing, the LMRP, the BOP, the riser, etc.). A bumper 438 may optionally be provided at a subsurface end of the no-go guide 434 to absorb impacts on contact with the wellsite equipment. The bumper 438 may be made of a material, such as rubber or other material that is softer than the wellsite equipment and/or tester tool to prevent damage thereto and/or to absorb impact. As shown, the bumper 438 is in the form of a plug with a tubular portion inserted into an outer end of the no-go guide 434 and secured therein by fasteners (e.g., bolts), and a flanged portion covering the subsurface end of the test tool 404.

[0044] The test body 430 may also include an expanded centralizer 436 extending radially from the outer surface of the test body 430. The centralizer 436 may be integral with the test body 430, or may be positioned about an outer surface of the test body 430 and connected thereto. As shown, the centralizer 436 may be a cylindrical (or polygonal) member having a diameter Dc larger than the diameter Db of the test body 430, and with ends to facilitate passage through wellsite equipment.

[0045] The centralizer 436 may have one or more portions (e.g., hemispheres) disposable about the test body 430 and secured thereabout. In a modular version as shown in Figure 4B, the centralizer 436 may have an inner diameter shaped to receivingly engage an outer surface of the test body 430. The centralizer 436 may be secured to the test body 430 by threads, frictional engagement, bonding, and/or other means.

[0046] The enlarged diameter of the centralizer 436 may perform various functions, such as to control velocity, to position the test body 430, and/or to prevent items falling past the test tool 404. For example, the centralizer 436 may act as a velocity control mechanism (brake) to control the descent of the test tool through the wellsite equipment (e.g., the riser). The centralizer 436 has channels 437 therethrough and a pocket 439 therein to catch fluid therein to control movement of the test body 430. The centralizer 436 may be configured such that the test tool 404 moves at a velocity above the operational velocity of a wireline, for example, to maintain tension on the wireline 112.

[0047] The centralizer 436 may also be used, for example, to position the test body 430 centrally within the passage of the wellsite equipment. The centralizer 436 may also be used as a stop to terminate advancement of the test tool through certain wellsite equipment. The wider diameter Dc of the centralizer 436 may also act as a bird's nest block items from getting past the test tool 404 and to protect the well in the unlikely event that the wireline breaks and the test tool 404 free falls until impact [0048] The test body 430 includes multiple tubular members threadedly connected in series. The tubular members may include test portions Tp having various dimensions, such as a reduced diameter Dt as shown, to correspond to dimensions of wellsite equipment engageable therewith during testing as described further herein. The centralizer 436 may be positioned a distance above the test portion Tp to facilitate placement of the test portion Tp relative to the wellsite equipment when seated.

[0049] Figure 5 depicts an operational example using the testing tool 404 of Figures 4A- 4C. This example involves testing the integrity of a subsea BOP 521. Tests may be performed by the test tool 404 alone or in combination with other testers, such as the wireline logging tool and/or a drill plug test. Such tests may be performed to assure operation of the BOP 521 to prevent leakage, such as a blowout. The term "blowout" is used herein to describe an uncontrolled sudden escape of fluids from a wellbore. The BOP 521, as described herein, refers to a stack of valves that enable the regulation, containment and control of fluid flow from the wellbore and hydrocarbon reservoir.

[0050] The test tool 404 may be used at a subsea well that is being characterized with a conventional wireline logging tool (not shown). The wireline logging tool may be a conventional wireline tool deployed by the wireline into the wellsite equipment using the wireline rigging. The wireline logging tool may also perform various tests, such as downhole measurements and/or sampling. The wireline logging tool may be removed to the surface, for example, upon completion or if the duration of well characterization service by the logging tool exceeds a minimum time to test the subsea BOP 521. The wireline logging tool may be removed from the wellbore and rigged down to allow other tools to be deployed to perform the testing.

[0051] After the wireline logging tool has been removed, drilling pipe may optionally be threaded together and tripped through the riser and into the BOP 521 to perform tests, such as function tests of the BOP 521 as defined in 30 CFR § 250.517. The function test may require a pipe to be present in the BOP 521 to test the pipe rams. Such a test may involve a seven day functional test requirement together with a drillship performing an exploration logging campaign via wireline which may extend more than 7 days while determining hydrocarbon characterization of the well. [0052] These tests may also require that the well be isolated from part of the BOP 521 performing the high pressure test. Example classical techniques involve using a test plug run by the drill string from a drilling rig. These techniques involve, for example, tripping the entire string out of the hole, adding a test plug to the string, tripping pipe to place the test plug, performing the test, tripping pipe to remove the test plug, then tripping pipe back into the hole to continue operation. These tests may involve activating the pipe rams to engage the drill pipe to confirm operation thereof. Once complete, each section of the drill pipe is unthreaded and removed so that the drill pipe is tripped out of the well. In some cases, when the drill pipe test is complete, the wireline must be rigged up again and re-run into the well to continue with the well characterization with the logging tool. [0053] Another existing test technique involves using a specialized test ram on the BOP 521 to isolate the well. This technique may use a pressure test while tripping pipe above the BOP 521, thereby eliminating the need to trip pipe the entire length of the riser to perform a function test, a pressure test, condition monitoring, and/or other tests on a subsea BOP 521 and/or riser. In the event that the BOP 521 does not have a test ram, a test tool with a detachable test plug may be used in its place as is described further herein (see, e.g., Figure 7B).

[0054] As shown by Figure 5, the tripping of drilling pipe may optionally be eliminated and the test tool 404 deployed from the surface using the same wireline rigging used to convey the wireline logging tool. The test tool 404 may be lowered by the wireline 112 into the wellsite equipment to perform equipment tests, such as the function and/or pressure test of the subsea BOP 521, as an alternative or supplement to the tests performed via drill pipe.

[0055] The test tool 404 may be deployed upon retrieval of the wireline logging tool with the wireline. Once accessible at the surface (e.g., topside of the offshore vessel), the wireline logging tool may be disconnected from the wireline 112, and the wireline 112 may then be attached to the cable head 432 of the test tool 404.

[0056] The test tool 404 can be lowered by the wireline 112 to a desired depth in the BOP 521 as shown in Figure 5. The pipe rams 542 of the BOP 521 may be in a closed position. The test tool 404 may be lowered until the test tool tags (or contacts) a portion of the wellsite equipment, such as the shear ram 544 of the BOP 521. The shear ram 544 may then be opened and the test tool 404 lowered until it tags another portion of the wellsite equipment, such as the wear bushing 228.

[0057] The distance between the shear ram 544 and the wear bushing 228, a known datum Hr, may be compared to the tag positions. If the positions match within a significant level of certainty, then it can be assumed that the no-go guide 434 of the test tool 404 is located at the wear bushing 228. If not, then the test tool 404 may be pulled up and tagged again.

[0058] In one implementation, where an annular BOP 521 is present, the annular 546 at the top of the BOP 521 can be activated to center the tool in the BOP 521. Subsequently, the pipe rams 542 can be activated for testing purposes. The annular 546 at the top of the BOP 521 can then be activated to center the top portion of the tool 404, allowing for function testing of the BOP pipe rams 542 to be conducted (see, e.g. , 30 CFR § 250.517).

[0059] In order to pressure test the BOP 521, the same method as described above for function testing is used except the no-go guide 434 functions as a removable test plug. Once the test tool 404 is at the wear bushing 228, the test plug/no-go guide 434 is secured in and/or landed on the wear bushing 228 and pressure is applied from the surface to activate the pipe rams 542. The annular 546 at the top of the BOP 521 can then be activated to center the top portion of the tool, allowing for pressure testing of the pipe rams 542 of the BOP 521 to be conducted. Once testing has been completed, the annular 546 can release the test tool 404. [0060] Once testing has been completed, the annular 546 can release the test tool 404. The test tool 404 can be retrieved to the surface (e.g., topside of the offshore vessel) where it can be disconnected from the wireline rigging. The wireline logging tool can then be reattached and well characterization can resume. The test results from the test tool 404 may be considered alone and/or with other test data, such as tests performed by the wireline logging tool and/or using the drilling pipe.

[0061] Figures 6A-7C depict variations of the test tool 604, 704a-c and operations thereof. Figures 6 A and 6B depict a detachable test tool 604 with additional features, such as a bird's nest 648. Figures 7A-7C depict an instrumented test tool 704 with sensors 752a,b thereabout. These figures also demonstrate that various shapes and features may be used for the test tool. These figures are depicted along with functional elements of a BOP 521 (e.g., annular 546 and pipe ram 542), but may be used with any wellsite equipment.

[0062] Figures 6A and 6B show the test tool 604 having an elongate cylindrical test body (or bar) 630 with a smooth outer surface, a tapered surface end 632, and an expanded subsurface end 634. As shown, the smooth outer surface is engageable by movable parts of the wellsite equipment, such as annular 546 and pipe rams 542 of the BOP 521 as schematically shown. The tapered surface end 632 may be a cable head 632 (similar to 432 of Figure 4A) and include a wireline adapter, bird's nest 648, and/or other features to facilitate operation with the wireline 112. [0063] The test tool 604 includes a wireline head adapter (similar to cable head 332) connecting the test body 630 to a wireline, and a bird's nest 640 to prevent the wireline 112 (broken or unbrocken) from passing into the BOP 521. The test tool 604 also includes a flanged/bullnose no-go guide 434, referred to herein as a no-go (or test plug), for positioning the tool in the BOP 521. The bird's nest 648 may be a wider diameter portion of the test body 630 (similar to centralizer 436 of Figures 4A and 4B) adapted to, in the unlikely event of wireline failure, to catch the wireline 112 (and/or other material) and prevent it from tangling or falling into the BOP 521. The bird's nest 648 may be used to prevent a broken portion of the wireline 112 from being tangled in the test tool 404 and/or the BOP 521. [0064] As shown in Figure 6B, the no-go guide 634 may be removably connected to the test body 630 by a connector 650 (e.g., a quick disconnect). The remainder of the test tool 604 may be separated from the no-go guide 634 for certain operations. For example, the no-go guide 634 may be detached and raised above the shear ram 544 so that, upon activation, the shear rams 544 may converge for function testing. The outer surface of the test body 630 may be engaged by the pipe rams 542 for additional function testing. After testing, the test body 630 can be lowered and re-attached to the no-go guide 634 by the connector 650. The test tool 604 may then be raised back to the surface.

[0065] Referring now to Figures 7A-7C, the instrumented test tool 704a-c is depicted as including with a cable head 732, a test body 730, and a no-go guide 734. The test tool 704a-c is provided with sensors 752a disposed in arrays 754 about test body 730 (Figure 7A,7C), sensors 752a on the no-go guide 734, and a sensor 752b extending from the no-go guide 734 (Figure 7B). These figures demonstrate that a variety of sensors may be provided about various locations of the test tool 704a-c. The sensors may include various types of sensors usable about the wellsite including, but not limited to, optical, sonic, infrared, ultrasound, sonar, echosounders, pressure sensors, temperature sensors, strain gauges, accelerometers, radiological, and/or other devices capable of measuring wellsite parameters, such as position, identification, velocity, temperature, pressure, vibration, x- ray readings, cracks, etc.

[0066] As shown in Figures 7A, the sensors 752a may be disposed about various locations along an outer surface of the test body 730 of the test tool 704a. The array 754a of the sensors 752a are depicted in rows distributed peripherally about an outer surface of the test body 730 at various depths. The sensors 752a may be provided at a given depth along a length of the test tool 704a for detecting a position of portions of the wellsite equipment as the test tool 704a passes thereby. The sensors 752a may be recessed into an outer surface of the test tool 704a for protection. [0067] The sensors may collect various readings from the wellsite equipment, such as the position/velocity of, for example, the pipe ram 542 and annular 546 during actuation and testing. The measurement of position/velocity of the rams can be compared against the expected position/velocity from the hydraulic feedback without damaging the tool. The measurement of position/velocity of the pipe ram 542 and annular 546 can be compared against the expected position/velocity from the hydraulic feedback. [0068] In an example, the sensors 752a may be strain gauges on a portion of the tool body 730 to measure, for example, the seal around the test body 730 when engaged by pipe rams 542. As shown, the array 754a of sensors 752a is positioned for engagement by the pipe rams. Such sensors 752a may be strain gauges positioned to detect a pressure applied thereto by the pipe rams, and/or sonic sensors on a test portion of the tool body 730 to measure the seal around the tool body 730.

[0069] These sensors 752a may also be deployed for collecting equipment measurements as the test tool 704a is deployed through wellsite equipment, such as the riser 120 (Figure 1) to monitor status thereof. For example, the instrumented test tool 704a may include accelerometers to measure the vibration of the wellsite equipment. When compared against a baseline, new, missing, or unexpected vibrations may highlight an irregularity with the wellsite equipment (e.g., the BOP), while expected vibrations may highlight healthy wellsite equipment.

[0070] Referring now to Figure 7B, the instrumented tool 704b may include, but is not limited to, at least one sensor 752a (e.g., sonic sensor) in an array 754b about the no-go guide 734 of the test tool 704 to collect measurements as described for Figure 7A. The test tool 704 may also include at least one sacrificial strain gauge 752b extending therefrom to be sheared by the shear ram 544. During its use, the sacrificial strain gauge 752b, which may be positioned below the no-go guide 734 of the test tool 704, may be used to provide at least one measurement, such as the pressure, from the shear ram 544.

[0071] In an example, the instrumented tool 704b may include, but is not limited to, at least one sensor 752a (e.g., radiological sensor) in an array 754b about the no-go gauge 734 of the test tool 704 to collect measurements as described for Figure 7A.

[0072] Referring now to FIG. 7C, the instrumented test tool 704c may include, but is not limited to, multiple sensors 752a (e.g., pressure and temperature sensors) in array(s) 754c on a portion of the test body 730 of the test tool 704c to measure the condition of wellbore fluid of the wellsite. The sensors 752a may be adaptable to provide measurements of the pressure and/or temperature of the wellbore fluid, which may be redundant to

measurements provided by sensor(s) at the wellsite. The sensors 752a may be positioned in the arrays 754a along tool body 730 at locations away from test portions of the test body 730 to be engaged by the pipe rams 542 or other equipment. For example, pressure and temperature sensors 752a may be positioned above and below the pipe ram 542 to measure wellsite fluids when changing mud mixture.

[0073] Figure 8 is a flowchart depicting a method 800 of testing wellsite equipment of a wellsite positioned about a subsurface formation. The method involves 860 - deploying a test tool from a surface location of the wellsite and into the wellsite equipment. The test tool includes a cable head at a surface end and a no-go guide at a subsurface end with a test portion between the cable head and the no-go guide (see, e.g., Figs. 4A-4C). The method also involves 862 -determining performance of the wellsite equipment by seating the no-go guide into an inlet of the wellsite equipment and activating the wellsite equipment to engage the test portion.

[0074] The test tool may also further comprise sensors (Figures 7A-7C) and the method further involves 864 sensing wellsite parameters during the deploying. The wellsite equipment may include a BOP with rams, and the determining may involve performing a function test of the BOP. These and other operations described herein may be performed. [0075] Part or all of the method may be performed in any order and repeated as desired.

[0076] The present disclosure is well adapted to attain the ends and advantages mentioned, as well as those that are inherent therein. For example, the test tool should not be interpreted to only be useful during well characterization operations by logging. The various embodiments disclosed herein are illustrative of certain uses in hydrocarbon operations. The present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Various combinations of one or more of the features may be provided on the test tool. Furthermore, no limitations are intended to the details of construction or design herein shown. [0077] While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations,

modifications, additions and improvements are possible. For example, one or more image may be performed using one or more of the techniques herein. Various combinations of the techniques provided herein may be used. [0078] Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.

[0079] The present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown. While systems and methods are described in terms of "comprising," "containing," or "including" various components or steps, the methods can also "consist essentially of" or "consist of" the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, "from a to b," or, equivalently, "from a-b") disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Whenever a numerical range having a specific lower limit only, a specific upper limit only, or a specific upper limit and a specific lower limit is disclosed, the range also includes any numerical value "about" the specified lower limit and/or the specified upper limit.