METHODS AND TOOLS FOR DETERMINING BLEED-OFF PRESSURE AFTER WELL SECUREMENT JOBS

BACKGROUND

In the oilfield arts, critical and high-risk often wells are secured with through tubing bridge plugs (TTBP's) and capped with cement, in order to isolate a reservoir. An important factor involved in installing a TTBP is its differential pressure rating, reflecting its ability to withstand an excess of reservoir pressure after installation. Particularly, differential pressure is defined as the difference between reservoir pressure and pressure in the wellbore right above the plug after installation. Thus, the differential pressure rating of a TTBP corresponds to the maximum differential pressure it can withstand, and a safety factor is also usually considered when installing the plug.

Conventionally, after well securement, an inflow test is then typically conducted to ensure that the TTBP plug is holding properly and there is no active reservoir communication. Usually, this step is merely done via bleeding off the shut-in wellhead pressure (SIWHP), or wellbore pressure at the top of the wellbore, and recording the pressure buildup so measured. A measured buildup of SIWHP, e.g., above a certain threshold, may be accepted as confirming the failure of the TTBP plug downhole.

However, such failure could easily arise from a variety of causes, which may include: an inherent structural deficiency or malfunction of the TTBP; issues or deficiencies in setting the TTBP; or the differential pressure at hand exceeding the limit of the plug. In most cases where the TTBP is set properly, the main cause of failure usually involves exceeding the differential pressure rating of the plug.

Normally, a rough estimation at best is available for attempting to determine actual differential pressure in the wellbore. Typically, the rough estimation can be based on the measured SIWHP as well as the presence and location of hydrostatic head due to fluid in the wellbore. However, any errors in such estimation may have serious consequences. For instance, while bleeding off pressure at the wellhead to check on plug integrity, the actual differential pressure may be high enough to cause the TTBP to dislodge or loosen, to literally move in one direction or another physically. As the TTBP then loses some or all of its intended function, it may need to be dismantled or retrieved, which typically is logistically difficult; for instance, TTBP plugs typically cannot be milled out or retrieved by tools sent down on a slickline or coil tubing. Permanent securement of the reservoir may then be difficult, and serious well integrity issues may then result.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In one aspect, embodiments disclosed herein relate to a method including: installing a through tubing bridge plug in a wellbore; deploying a slickline unit into the wellbore, wherein the slickline unit includes a pressure gauge; measuring bottomhole pressure with the pressure gauge; and setting a wellhead pressure based on the measured bottomhole pressure.

In one aspect, embodiments disclosed herein relate to a system for setting a wellhead pressure after a through tubing bridge plug is installed in a wellbore. The system includes a slickline unit that includes a static bottomhole pressure gauge, and the static bottomhole pressure gauge includes internal memory that stores a measured bottomhole pressure. The system further includes a pressure setting unit that sets a wellhead pressure based on the measured bottomhole pressure stored in the internal memory of the static bottomhole pressure gauge.

In one aspect, embodiments disclosed herein relate to a method including: installing a through tubing bridge plug in a wellbore; capping the through tubing bridge plug with cement; deploying a slickline unit into the wellbore, wherein the slickline unit includes a pressure gauge; measuring bottomhole pressure with the pressure gauge; storing, at a first data storage location, data that includes the measured bottomhole pressure; transferring the stored data from the first data storage location to a second data storage location; obtaining the data from the second data storage location to use in setting the wellhead pressure; and setting a wellhead pressure based on the measured bottomhole pressure.

Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.

FIG. 1 schematically illustrates, in a cross-sectional elevational view, a conventional wellbore and well control system by way of general background and in accordance with one or more embodiments.

FIG. 2 illustrates, in elevational view, a wellhead, and related components, employed for the wellbore and well control system of FIG. 1, by way of general background and in accordance with one or more embodiments.

FIG. 3 schematically illustrates, in a cross-sectional elevational view, a production wellbore in accordance with one or more embodiments.

FIG. 4 provides essentially the same view as FIG. 3, but with a tubing bridge plug installed, in accordance with one or more embodiments.

FIG. 5 provides essentially the same view as FIG. 4, but with a slickline unit deployed, in accordance with one or more embodiments.

FIG. 6 schematically illustrates, in a close-up elevational view, the slickline tool of FIG. 5, in accordance with one or more embodiments.

FIG. 7 schematically illustrates, in elevational view, a slickline unit in accordance with one or more embodiments.

FIG. 8 shows a flowchart of a method in accordance with one or more embodiments.

FIG. 9 schematically illustrates a computing device and related components, in accordance with one or more embodiments.

DETAILED DESCRIPTION

In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

To facilitate easier reference when describing FIGS. 1 through 9, reference numerals may be advanced by a multiple of 100 in indicating a similar or analogous component or element among FIGS. 1-9.

By way of general background in accordance with one or more embodiments, in the oilfield arts, valves at a wellhead and sub-surface safety valves (SSSV) are typically tested manually by an operator at the wellsite. Such testing normally involves installation of a pressure gauge above the crown valve to measure shut-in wellhead pressure (SIWHP), and wellhead integrity and SSSV tests are normally conducted manually. As noted above in particular, the integrity or failure of a TTBP plug downhole is also often checked conventionally by bleeding off SIWHP pressure at the top of the wellbore and recording the pressure buildup so measured. As such, FIGS. 1 and 2 illustrate a general environment in which one or more embodiments may be employed.

FIG. 1 schematically illustrates, in a cross-sectional elevational view, a wellbore and a well control system in accordance with one or more embodiments. The well system 106 includes a wellbore 120, a well sub-surface system 122, a well surface system 124, and a well control system (“control system”) 126. The control system 126 may control various operations of the well system 106, such as well production operations, well completion operations, well maintenance operations, and reservoir monitoring, assessment and development operations. The control system 126 includes a computer system that is the same as, or is in communication with, computer system 885 described below in FIG. 9.

In accordance with one or more embodiments, the wellbore 120 includes a bored hole that extends from the surface 108 into a target zone of the formation 104, such as the reservoir 102. An upper end of the wellbore 120, terminating at or near the surface 108, may be referred to as the “up-hole” end of the wellbore 120, and a lower end of the wellbore, terminating in the formation 104, may be referred to as the “down-hole” end of the wellbore 120. The wellbore 120 facilitates the circulation of drilling fluids during drilling operations, the flow of hydrocarbon production (“production”) 121 (e.g., oil and gas) from the reservoir 102 to the surface 108 during production operations, the injection of substances (e.g., water) into the formation 104 or the reservoir 102 during injection operations, or the communication of monitoring devices (e.g., logging tools) into the formation 104 or the reservoir 102 during monitoring operations (e.g., during in situ logging operations). As will be discussed further below, such monitoring devices may include a bottomhole pressure gauge included with a slickline tool (e.g., as indicated at 358 and 356, respectively, in FIG. 5.)

In accordance with one or more embodiments, during operation of the well system 106, the control system 126 collects and records wellhead data 140 for the well system 106. The wellhead data 140 may include, for example, a record of measurements of wellhead pressure (P_wh) (e.g., including flowing wellhead pressure), wellhead temperature (T_wh) (e.g., including flowing wellhead temperature), wellhead production rate (Q_wh) over some or all of the life of the well 106, and water cut data. Such measurements may be recorded in real-time, to be available for review or use within seconds, minutes, or hours of the condition being sensed (e.g., within one hour). Such real-time data can help an operator of the well 106 to assess a relatively current state of the well system 106, and make real-time decisions regarding development of the well system 106 and the reservoir 102, such as on-demand adjustments in regulation of production flow from the well.

In accordance with one or more embodiments, the well sub-surface system 122 includes a casing installed in the wellbore 120. For example, the wellbore 120 may have a cased portion and an uncased (or “open-hole”) portion. The cased portion may include a portion of the wellbore having casing (e.g., casing pipe and casing cement; see, e.g., 342 in FIGS. 3-5) disposed therein. The uncased portion may include a portion of the wellbore not having casing disposed therein. In embodiments having a casing, the casing defines a central passage that provides a conduit for the transport of tools and substances through the wellbore 120. For example, the central passage may provide a conduit for lowering logging tools into the wellbore 120, a conduit for the flow of production 121 (e.g., oil and gas) from the reservoir 102 to the surface 108, or a conduit for the flow of injection substances (e.g., water) from the surface 108 into the formation 104. The well sub-surface system 122 can include production tubing installed in the wellbore 120. The production tubing may provide a conduit for the transport of tools and substances through the wellbore 120. The production tubing may, for example, be disposed inside casing. In such an embodiment, the production tubing may provide a conduit for some or all of the production 121 (e.g., oil and gas) passing through the wellbore 120 and the casing.

In accordance with one or more embodiments, the well surface system 124 includes a wellhead 130. The wellhead 130 may include a rigid structure installed at the “up-hole” end of the wellbore 120, at or near where the wellbore 120 terminates at the Earth's surface 108. The wellhead 130 may include structures (called “wellhead casing hanger” for casing and “tubing hanger” for production tubing) for supporting (or “hanging”) casing and production tubing extending into the wellbore 120. Production 121 may flow through the wellhead 130, after exiting the wellbore 120 and the well sub-surface system 122, including, for example, the casing and the production tubing. The well surface system 124 may include flow regulating devices that are operable to control the flow of substances into and out of the wellbore 120. For example, the well surface system 124 may include one or more production valves 132 that are operable to control the flow of production 121. For instance, a production valve 132 may be fully opened to enable unrestricted flow of production 121 from the wellbore 120, the production valve 132 may be partially opened to partially restrict (or “throttle”) the flow of production 121 from the wellbore 120, and production valve 132 may be fully closed to fully restrict (or “block”) the flow of production 121 from the wellbore 120, and through the well surface system 124.

In accordance with one or more embodiments, the wellhead 130 includes a choke assembly. For example, the choke assembly may include hardware with functionality for opening and closing the fluid flow through pipes in the well system 106. Likewise, the choke assembly may include a pipe manifold that may lower the pressure of fluid traversing the wellhead. As such, the choke assembly may include set of high pressure valves and at least two chokes. These chokes may be fixed or adjustable or a mix of both. Redundancy may be provided so that if one choke has to be taken out of service, the flow can be directed through another choke. In some embodiments, pressure valves and chokes are communicatively coupled to the well control system 126. Accordingly, a well control system 126 may obtain wellhead data regarding the choke assembly as well as transmit one or more commands to components within the choke assembly in order to adjust one or more choke assembly parameters.

In accordance with one or more embodiments, the well surface system 124 includes a surface sensing system 134. The surface sensing system 134 may include sensors for sensing characteristics of substances, including production 121, passing through or otherwise located in the well surface system 124. The characteristics may include, for example, pressure, temperature and flow rate of production 121 flowing through the wellhead 130, or other conduits of the well surface system 124, after exiting the wellbore 120.

In accordance with one or more embodiments, the surface sensing system 134 includes a surface pressure sensor 136 operable to sense the pressure of production 121 flowing through the well surface system 124, after it exits the wellbore 120. The surface pressure sensor 136 may include, for example, a wellhead pressure sensor that senses a pressure of production 121 flowing through or otherwise located in the wellhead 130. In some embodiments, the surface sensing system 134 includes a surface temperature sensor 138 operable to sense the temperature of production 121 flowing through the well surface system 124, after it exits the wellbore 120. The surface temperature sensor 138 may include, for example, a wellhead temperature sensor that senses a temperature of production 121 flowing through or otherwise located in the wellhead 130, referred to as “wellhead temperature” (T_wh). In some embodiments, the surface sensing system 134 includes a flow rate sensor 139 operable to sense the flow rate of production 121 flowing through the well surface system 124, after it exits the wellbore 120. The flow rate sensor 139 may include hardware that senses a flow rate of production 121 (Q_wh) passing through the wellhead 130.

FIG. 2 illustrates, in elevational view, a wellhead, and related components, employed for the wellbore and well control system of FIG. 1, in accordance with one or more embodiments. As such, one or more of the modules and/or elements shown in FIG. 2 may be omitted, repeated, and/or substituted. Accordingly, embodiments of the invention should not be considered limited to the specific arrangements of modules and/or elements shown in FIG. 2.

In accordance with one or more embodiments, FIG. 2 illustrates details of the wellhead 130 and the flowline for the production 121 depicted in FIG. 1 above. As shown, the wellhead 130 includes a well cap 200, a crown valve 201, a wing valve 202, a surface safety valve 203, a master valve 204, a subsurface safety valve 205, an upstream pressure transmitter 206, a downstream pressure transmitter 207, a choke valve 208, and a plot limit valve 209. The crown valve 201, wing valve 202, surface safety valve 203, master valve 204, choke valve 208, and plot limit valve 209 are referred to as valves at the wellhead. In addition, a pressure gauge 210 and/or temperature gauge (not shown) is permanently installed between the crown valve 201 and the well cap 200. The pressure gauge 210 and/or temperature gauge (not shown) correspond to the pressure sensor 136 and temperature sensor 138, respectively, depicted in FIG. 1 above.

In accordance with one or more embodiments, the well cap 200 provides access to wellbore for interventions with wireline, coil tubing, slickline etc.; thus, this can provide access to a slickline with a tool 356 and pressure gauge 358 as discussed and illustrated herein with respect to FIG. 5. The crown valve 201 is the uppermost valve on wellhead. Typically, the crown valve 201 is closed until there is a need to access the well as described above. The wing valve 202 is for production flow control. In the case of needing to enter a well, this valve would be closed and the master valve would be open. The surface safety valve 203 is typically a hydraulic failsafe close valve located at surface. The surface safety valve 203 used in the event of an issue in the wellbore/surface equipment and for testing. The master valve 204 is the main valve controlling flow from the wellbore. The subsurface safety valve 205 is another safety device located below the surface, e.g., several hundred plus feet below the surface. The subsurface safety valve 205 makes up part of the production tubing and provides an arrangement for safety closure in the case of uncontrolled release of hydrocarbons, such as a kick. Also, the subsurface safety valve 205 may be used as a barrier when testing or needed to perform maintenance on the wellhead.

In accordance with one or more embodiments, the choke valve 208 is used for flow restriction in the event of bleeding down pressure during testing, loss of pressure in the wellbore, temperature management, etc. Thus, the choke valve 208 may be used for pressure-bleed off as described herein in connection with the illustrative working examples of FIGS. 3-9. The upstream pressure transmitter 206 is a pressure/temperature gauge located upstream of choke valve 208 and provides pressure data prior to reaching the choke valve 208. The downstream pressure transmitter 207 is a pressure/temperature gauge downstream of choke valve 208 and provides pressure data after passing the choke valve 208. The plot limit valve 209 is a valve for testing, maintenance and isolation purposes, e.g., if the upstream pressure transmitter 206, downstream pressure transmitter 207, or choke valve 208 were being replaced. The pressure gauge 210 located above the crown valve 201 is for testing each component of the wellhead. As generally treated herein, shut-in wellhead pressure (SIWHP) refers to the initial wellhead pressure from the reservoir as seen at surface and is a base line pressure for testing purposes, and can be measured by the pressure gauge 210. Indeed, this wellhead pressure gauge 210 may be employed in connection with the illustrative working examples of FIGS. 3-9. The initial manifold pressure refers to the initial pressure downstream of wellhead and is a base line pressure for testing purposes.

In one or more embodiments, the hydraulic valves and associated gauges are connected as depicted in FIG. 2. In particular, a pressure gauge 210 can be permanently installed between the well cap 200 and the crown valve 201. In a first open/close configuration, the subsurface safety valve, master valve, wellhead valve, crown valve, and plot limit valve are closed to record the initial manifold pressure using the downstream pressure transmitter.

In accordance with one or more embodiments, following the first open/close configuration and in the second open/close configuration, the subsurface safety valve, master valve, wing valve, and crown valve are opened with the plot limit valve closed to record the initial shut-in wellhead pressure (SIWHP) using the permanently installed pressure gauge between the well cap and the crown valve. The pressure gauge readings of the permanently installed pressure gauge, the upstream pressure transmitter, and the downstream pressure transmitter are compared with each other to validate gauge accuracy. All pressure gauge readings are observed for 10 minutes to record pressure changes, if any. If all three following conditions are true over the 10 minutes period: DPT=SIWHP, UPT=SIWHP, and PG=SIWHP, then the plot limit valve is determined as holding (i.e., no leakage). In particular, the gauge readings from the downstream pressure transmitter, the upstream pressure transmitter, and the pressure gauge between the well cap and the crown valve are denoted as DPT, UPT, and PG, respectively.

Following the second open/close configuration and in the third open/close configuration, the wellhead valve is closed and the plot limit valve is opened to observe all pressure gauge readings for 10 minutes and record pressure changes, if any. If both following conditions are true over the 10 minutes period: UPT=initial manifold pressure=DPT and PG=SIWHP, then the wellhead valve is determined as holding (i.e., no leakage).

Following the third open/close configuration and in the fourth open/close configuration, the crown valve is closed followed by closing the master valve and opening the wellhead valve. If both following conditions are true over the 10 minutes period: UPT=initial manifold pressure=DPT and PG=SIWHP, then the crown valve and the master valve are determined as holding (i.e., no leakage).

Subsequent to the first, second, third and fourth open/close configurations, the crown valve is opened to bleed the pressure to a flare pit. Specifically, PLV and WV are open. MV is closed and CV bleeds the trapped pressure between CV and MV into the flare pit.

The disclosure now turns to working examples of a system and method in accordance with one or more embodiments, as described and illustrated with respect to FIGS. 3-9. It should be understood and appreciated that these merely represent illustrative examples, and that a great variety of possible implementations are conceivable within the scope of embodiments as broadly contemplated herein.

Broadly described and contemplated herein, in accordance with one or more embodiments, are tools and procedures to help in calculating the bleed-off pressure at a wellhead after a well securement job, where such jobs may utilize a through tubing bridge plug (TTBP). Generally, in accordance with one or more embodiments, one or more pressure gauges may be added to a slickline tool, to provide a manner of calculating bottomhole pressure above the TTBP. The one or more pressure gauges may be embodied, e.g., by one or more static bottomhole pressure (SBHP) gauges.

FIG. 3 schematically illustrates, in a cross-sectional elevational view, a production wellbore in accordance with one or more embodiments. In the illustrated working example, a well has been drilled and completed for oil production, with a casing 342 cemented into place and a casing shoe 344 set across formation rock 304 at a predetermined depth. Production tubing 346, for recovering hydrocarbons from the formation rock 304 (or other subsurface regions), is then installed and nested coaxially within the casing 342. Further, as is generally known, a packer 348 may be included to seal the annular chamber between the casing 342 and production tubing 346. Also illustrated is a wellhead 330 in communication with a well control system 326; these may function and be configured analogously to the wellhead 130 and well control system 126, respectively, that are described and illustrated with respect to FIGS. 1-2

FIG. 4 provides essentially the same view as FIG. 3, but with a TTBP plug installed, in accordance with one or more embodiments. As shown, the well is secured with a TTBP 350 that is then capped with cement 352. It may be secured for any of a variety of reasons, such as for stopping the flow of hydrocarbons to the surface at least temporarily (e.g., until a rig arrives for workover of the well). For instance, there may be an issue with securely sealing the annular chamber between the casing 342 and production tubing 346, and a workover may be ordered to replace or fix one or more wellhead components (such as those shown in FIG. 2), thus warranting full securement of the well.

FIG. 5 provides essentially the same view as FIG. 4, but with a slickline unit deployed, in accordance with one or more embodiments. As shown, slickline 354 (in the form of a non-electric cable, as known) may extend downhole with a slickline unit 356 which includes one or more tools; such tools may include, by way of example, a gauge cutter or a lead impression block (LIB), and/or also a tubing end locator (TEL). As generally known, the slickline unit 356 can be employed to confirm that the TTBP 350 has been successfully set at its desired predetermined depth and that the cement cap 352 has been properly set. For instance, a LIB (which typically includes a softer material such as soft lead at its end face) can confirm whether cement cap 352 indeed is present above the TTBP 350, e.g., if there is no cement present then an impression will be made at the end face of the LIB that is consistent with the top of the TTBP 350. A TEL can be used, as known, to detect the end of production tubing 346 while a gauge cutter can be used to scrape and remove scale or debris (e.g., from an inner surface of production tubing 346), etc., as generally known.

As such, in accordance with one or more embodiments, a pressure gauge (or SBHP gauge) 358 may also be included with the slickline unit 356 to measure downhole pressure right above the TTBP 250. The gauge 358 can be placed directly above a terminal component 359 of the slickline unit 356, or may be placed in any other manner deemed suitable, with a general objective of measuring pressure close to the TTBP 250. By way of example, the terminal component 359 may be a gauge cutter or LIB.

In accordance with one or more embodiments, the slickline tool 356 (with gauge 358) may be deployed downhole at a suitable time interval after cement has been poured for the cap 352 (e.g., 48 hours later) to permit sufficient time for the cement to fully set. As such, any bottomhole pressure readings via gauge 358 will help in preemptively identifying the limits of pressure bleed-off at the wellhead 330, and will then facilitate maintaining well conditions within differential pressure limits of the TTBP 350, without adding any cost or time to existing operational procedures (including, additional wasted time/effort that may be devoted to retrieving a failed TTBP).

FIG. 6 schematically illustrates, in a close-up elevational view, the slickline unit of FIG. 5, in accordance with one or more embodiments. As shown, the slickline unit 356 includes terminal component 359 and, disposed axially adjacent thereto, pressure gauge 358. As noted, the terminal component 359 may be embodied by a lead impression block or gauge cutter disposed at a lower free end of slickline unit 356. Additionally, pressure gauge 358 includes therewithin internal memory 360. Bottomhole pressure measurements thus can be stored at least temporarily in internal memory 360, for later use in setting wellhead pressure based on such measurements. Indicated at 361, axially above pressure gauge 358, is a crossover component which physically provides a transition to one or more other components or tools of slickline unit 356. Further, in accordance with a variant embodiment, instead of a single pressure gauge 358 there may be two or more pressure gauges for measuring bottomhole pressure, e.g., one or more secondary pressure gauges could serve as a backup for a main pressure gauge in the event of its failure, and/or the readings from two or more pressure gauges may be averaged or otherwise mathematically combined in order to yield an even more precise calculation of bottomhole pressure.

Continuing with joint reference to FIGS. 5 and 6, a practical working example may be considered in accordance with one or more embodiments; the numerical values discussed here are merely provided illustrative purposes and should not in any way be regarded as restrictive. As such, in order to conduct an in-flow test to confirm that the TTBP 350 is properly secured in place, a “worst-case” scenario can be considered where it is assumed that the cement cap 352 is not set properly. Further, this working example assumes that the differential pressure rating of plug is 1000 psi and, for practical use, incorporates a safety factor of 20% (e.g., to accommodate dynamic fluid conditions within the wellbore). Thus, the effective differential pressure rating of the plug would be 800 psi.

In the present working example in accordance with one or more embodiments, with a known static reservoir pressure of 3528 psi, the gauge 358 may measure pressure above the plug 350 (and with the cement cap 352 securely in place) at 3386 psi, thus the extant differential pressure across the plug 350 would be 142 psi and well below the effective differential pressure rating. As such, the available SIWHP to bleed off for an in-flow test would be calculated at 658 psi (i.e., 800−142).

Accordingly, in accordance with one or more embodiments, if the SIWHP measured by gauge 358 is initially 1180 psi (as an illustrative example), then the minimum pressure that would need to be maintained at the wellhead 330 during an inflow test is 522 psi (i.e., 1180−658). Thus, in view of the data provided by gauge 358, it would be established that the SIWHP cannot be bled below 522 psi as that would result in breaching the effective differential pressure limit of the plug 350. Thus, by obtaining measurements from a SBHP gauge 386 pre-emptively, above the TTBP 350 and in concert with deployment of the slickline tool 354 as aforementioned, a serious risk of inviting unstable conditions for the TTBP 350 can be mitigated or avoided.

FIG. 7 schematically illustrates, in elevational view, a slickline unit 456 in accordance with one or more embodiments. Shown are several additional components that may be included in a slickline unit 456, and the unit 456 itself may essentially be considered to be interchangeable with the unit 356 described and illustrated herein with respect to FIGS. 5-6. Further, it should be understood that the unit 456 shown in FIG. 7 is provided merely by way of illustrative and non-restrictive example, and thus can also be considered to be interchangeable with slickline units including a different mix of components.

As such, in accordance with one or more embodiments, slickline unit 456 may be disposed at a lower free end of a slickline 454, and at its own lower free end may include a terminal component 459 (e.g., a gauge cutter or LIB as discussed previously). Proceeding in a generally upward direction with respect to the figure, a pressure gauge (or two or more pressure gauges) 458 may be disposed immediately axially adjacent to the terminal component 459, essentially as discussed previously. A crossover component 460 provides a physical transition to a TEL 462, the function of which is discussed elsewhere herein. Proceeding axially upwardly, a mechanical jar 464 may be disposed axially adjacent to the TEL 462; as known, the jar 464 may be configured to deliver an impact load, in a predetermined direction, to another downhole component. Axially above the mechanical jar 464, some standard structural components may be provided such as a straight bar (or weight bar) 465, knuckle joint 466 and rope socket/fish neck component 468, in that order. As known, the slickline 454 itself may connect into the rope socket/fish neck component 468.

FIG. 8 shows a flowchart of a method, as a general overview of steps which may be carried out in accordance with one or more embodiments described or contemplated herein.

As such, in accordance with one or more embodiments, a TTBP is installed in a wellbore (770), and the TTBP is capped with cement (772); this can correspond to the TTBP 350 and cement cap 352, respectively, described and illustrated with respect to FIGS. 4 and 5. A slickline unit is deployed into the wellbore, wherein the slickline unit includes a pressure gauge (774); thus, the slickline unit may correspond to the combination of tool 356 and pressure gauge 358 as described and illustrated herein with respect to FIGS. 5-6. Bottomhole pressure is measured with the pressure gauge (776), e.g., such as pressure gauge 358 described and illustrated with respect to FIGS. 5-6.

In accordance with one or more embodiments, at a first data storage location, data is stored that includes the measured bottomhole pressure (778). By way of illustrative example, the first data storage location may correspond to memory 360 described and illustrated with respect to FIG. 6. The stored data is transferred from the first data storage location to a second data storage location (780). The data from the second data storage location is obtained to use in setting the wellhead pressure (782), and the wellhead pressure is set based on the bottomhole pressure (784). As such, the second data storage location may correspond to computer memory, and/or an associated database, at a surface location such as the well control system indicated 326 described and illustrated with respect to FIGS. 3-5 or the computing device 885 (and memory 892) described and illustrated with respect to FIG. 9. Generally, the data from the second data storage location is used for manually setting the wellhead pressure based on the bottomhole pressure (e.g., via bleed-off a choke valve such as that indicated at 208 in FIG. 2). In one or more variant embodiments, such setting of the wellhead pressure can be performed automatically, as governed by the data at the second storage location.

In accordance with one or more embodiments, the slickline unit is deployed (774) to position the pressure gauge at a predetermined distance above the tubing bridge plug. Additionally, setting the wellhead pressure (782) may include determining wellhead pressure available for bleed-off. Further, determining wellhead pressure available for bleed-off can be based on the measured bottomhole pressure and a differential pressure limit of the plug. Illustrative and non-restrictive examples of these steps may be appreciated from FIGS. 3-7 and their related discussion herein.

It can be appreciated from the foregoing that, in accordance with one or more embodiments, solutions as broadly contemplated herein will be of great benefit in ensuring and preserving well integrity via outright prevention of the premature failure of TTBP's. This obviates the inefficiencies tied in with maintaining well integrity for an indeterminate period of time after a TTBP fails and rig equipment needs to be summoned to the well location to salvage the well. Additionally, by avoiding the premature failure of TTBP's as broadly contemplated herein, numerous challenges inherent in retrieving the plug and are avoided, along with the limitations of remedial options such as re-installing additional plugs above the failed one.

FIG. 9 schematically illustrates a computing device and related components, in accordance with one or more embodiments. As such, FIG. 9 generally depicts a block diagram of a computer system 885 used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures as described in this disclosure, according to one or more embodiments. In this respect, computer 885 may interface with a well control system 326 such as that described and illustrated with respect to FIGS. 3-5, either directly (e.g., via hard-wired connection) or over an internal or external network 899. Further, a dedicated database for storing bottomhole pressure measurement data may be housed in computer 885 (e.g., in memory 892), or may be housed or stored elsewhere in a manner to be controlled or communicated with by computer 885. Alternatively, the computer 885 illustrated in FIG. 9 may correspond directly to the well control system 326 described and illustrated with respect to FIGS. 3-5.

In accordance with one or more embodiments, the illustrated computer 885 is intended to encompass any computing device such as a server, desktop computer, laptop/notebook computer, wireless data port, smart phone, personal data assistant (PDA), tablet computing device, one or more processors within these devices, or any other suitable processing device, including both physical or virtual instances (or both) of the computing device. Additionally, the computer 885 may include a computer that includes an input device, such as a keypad, keyboard, touch screen, or other device that can accept user information, and an output device that conveys information associated with the operation of the computer 885, including digital data, visual, or audio information (or a combination of information), or a GUI.

The computer 885 can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles) of a computer system for performing the subject matter described in the instant disclosure. The illustrated computer 885 is communicably coupled with a network 899. In some implementations, one or more components of the computer 885 may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).

At a high level, the computer 885 is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, the computer 885 may also include or be communicably coupled with an application server, e-mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).

The computer 885 can receive requests over network 899 from a client application (for example, executing on another computer 885) and responding to the received requests by processing the said requests in an appropriate software application. In addition, requests may also be sent to the computer 885 from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.

Each of the components of the computer 885 can communicate using a system bus 887. In some implementations, any or all of the components of the computer 885, both hardware or software (or a combination of hardware and software), may interface with each other or the interface 889 (or a combination of both) over the system bus 887 using an application programming interface (API) 895 or a service layer 897 (or a combination of the API 895 and service layer 897. The API 895 may include specifications for routines, data structures, and object classes. The API 895 may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs. The service layer 897 provides software services to the computer 885 or other components (whether or not illustrated) that are communicably coupled to the computer 885. The functionality of the computer 885 may be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer 897, provide reusable, defined business functionalities through a defined interface. For example, the interface may be software written in JAVA, C++, or other suitable language providing data in extensible markup language (XML) format or another suitable format. While illustrated as an integrated component of the computer 885, alternative implementations may illustrate the API 895 or the service layer 897 as stand-alone components in relation to other components of the computer 885 or other components (whether or not illustrated) that are communicably coupled to the computer 885. Moreover, any or all parts of the API 895 or the service layer 897 may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.

The computer 885 includes an interface 889. Although illustrated as a single interface 889 in FIG. 9, two or more interfaces 889 may be used according to particular needs, desires, or particular implementations of the computer 885. The interface 889 is used by the computer 885 for communicating with other systems in a distributed environment that are connected to the network 899. Generally, the interface 889 includes logic encoded in software or hardware (or a combination of software and hardware) and operable to communicate with the network 899. More specifically, the interface 889 may include software supporting one or more communication protocols associated with communications such that the network 899 or interface's hardware is operable to communicate physical signals within and outside of the illustrated computer 885.

The computer 885 includes at least one computer processor 891. Although illustrated as a single computer processor 891 in FIG. 9, two or more processors may be used according to particular needs, desires, or particular implementations of the computer 885. Generally, the computer processor 891 executes instructions and manipulates data to perform the operations of the computer 885 and any algorithms, methods, functions, processes, flows, and procedures as described in the instant disclosure.

The computer 885 also includes a memory 892 that holds data for the computer 885 or other components (or a combination of both) that can be connected to the network 899. For example, memory 892 can be a database storing data consistent with this disclosure. Although illustrated as a single memory 892 in FIG. 9, two or more memories may be used according to particular needs, desires, or particular implementations of the computer 885 and the described functionality. While memory 892 is illustrated as an integral component of the computer 885, in alternative implementations, memory 892 can be external to the computer 885.

The application 893 is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer 885, particularly with respect to functionality described in this disclosure. For example, application 893 can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application 893, the application 893 may be implemented as multiple applications 893 on the computer 885. In addition, although illustrated as integral to the computer 885, in alternative implementations, the application 893 can be external to the computer 885.

There may be any number of computers 885 associated with, or external to, a computer system containing computer 885, wherein each computer 885 communicates over network 899. Further, the term “client,” “user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one computer 885, or that one user may use multiple computers 885.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

METHODS AND TOOLS FOR DETERMINING BLEED-OFF PRESSURE AFTER WELL SECUREMENT JOBS

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