Patent Application
20200291750
While the oil and gas industry has drilled more than 14,000 deepwater subsea wells, in the aftermath of the Macondo incident in the Gulf of Mexico off the southeastern coast of Louisiana and the Montara incident in the Timor Sea off the northern coast of Australia, the International Association of Oil and Gas Producers (“OGP”) formed the Global Industry Response Group (“GIRG”) to investigate these and other incidents around the world and develop recommendations to the industry. In 2011, the GIRG published their recommendations in a report entitled Deepwater Wells: Global Industry Response Group Recommendations (“Report No. 463”). In Report No. 463, the GIRG recommends that “operators maintain a permanently applied minimum of two well barriers when the well is capable of discharging hydrocarbons or other fluids to the surface or external environment. . . . During drilling, completion, and abandonment phases of a well we regard a [blowout preventer] BOP as a barrier for the purposes of such a policy even when operated in the open position—if the BOP and associated procedures meet the operator's policy in . . . configuration and certification; redundancy for the operations being undertaken; function and pressure testing; and operational controls to use the BOP to shut in the well.” See Section 1.1 of Report No. 463. As such, operators consider the subsea blowout preventer (“SSBOP”) one of the permanently applied well barriers and typically install a surface-controlled tubing-retrievable subsurface safety valve as the second permanently applied well barrier.
A subsurface safety valve is a failsafe device deployed downhole to prevent catastrophic failure by shutting-in a well when other means of control are compromised or lost. During initial completion operations, while the drilling rig is still on the well site, a tubing-retrievable type of subsurface safety valve is run into the well as part of the production tubing. The term tubing-retrievable means the subsurface safety valve is deployed as an integrated part of, and is only retrievable by pulling, the production tubing. During production operations, typically after the drilling rig has left the well site, the tubing-retrievable subsurface safety valve is hydraulically actuated into the open, or producing, state permitting production flow towards the surface. When the operator wants to halt production, the hydraulic pressure in the control line is sufficiently reduced or removed and the bias spring automatically closes the tubing-retrievable subsurface safety valve, preventing further production flow. In the event of a failure or other contingency, tubing-retrievable subsurface safety valves are designed to fail safely in the closed position to prevent further production flow. To that end, subsurface safety valves require the affirmative application of hydraulic pressure in the control line that is sufficient to overcome the bias spring, influenced by pressure at the setting depth, to open a unidirectional flapper or valve and controllably permit the flow of production fluids toward the surface. When the hydraulic pressure in the control line is sufficiently reduced or removed, intentionally or otherwise, the bias spring causes the flapper or valve to automatically close, thereby safely preventing any further production flow.
As tubing-retrievable subsurface safety valves were being set deeper in the well due to their use in deeper water, the valves had difficulty operating due to the hydrostatic head in the control line, which eviscerated the failsafe protection they were intended to provide. As such, tubing-retrievable subsurface safety valves were modified to provide additional biasing force to balance the increased hydrostatic head in the control line. These deep-set tubing-retrievable subsurface safety valves include additional biasing means, such as, gas-charged chambers described in, for example, U.S. Pat. Nos. 4,252,197, 4,660,646, 4,976,317, and 5,310,004, or balance lines described in, for example, U.S. Pat. Nos. 6,003,605 and 7,392,849 that provide additional biasing force to the biasing spring. In general, the additional biasing means are designed to offset the hydrostatic head in the control line so that the operating pressures within the control line remain relatively low, such that the subsurface safety valve may be actuated at depth and fully close as intended when the hydraulic pressure in the control line is sufficiently reduced or removed.
According to one aspect of one or more embodiments of the present invention, a method of intervention in a failed deep-set tubing-retrievable subsurface safety valve disposed in a deepwater or ultra-deepwater subsea well includes cutting or grinding a radial port in an interior facing portion of the failed deep-set tubing retrievable subsurface safety valve with an e-line wireline-deployable communication tool to communicate a hydraulic chamber housing of the failed deep-set tubing-retrievable subsurface safety valve. The method further includes running in a deep-set wireline-retrievable subsurface safety valve into a central lumen of the failed tubing-retrievable subsurface safety valve. The deep-set wireline-retrievable subsurface safety valve includes a closure actuation mechanism disposed below a closure device. The actuation mechanism includes a pressure-balanced piston exposed to wellbore fluids on both distal ends of the piston.
Other aspects of the present invention will be apparent from the following description and claims.
One or more embodiments of the present invention are described in detail with reference to the accompanying figures. For consistency, like elements in the various figures are denoted by like reference numerals. In the following detailed description of the present invention, specific details are set forth in order to provide a thorough understanding of the present invention. In other instances, well-known features to one of ordinary skill in the art are not described to avoid obscuring the description of the present invention. For purposes of clarity, as used herein, top, upper, or above refer to a portion or side that is closer, whether directly or in reference to another component, to the surface above a wellbore and bottom, lower, or below refer to a portion or side that is closer, whether directly or in reference to another component, to the bottom of the wellbore.
During drilling and pre-production operations, a marine riser system 125 facilitates fluid communication between drilling rig 115 and subsea well 110. An SSBOP 135 is disposed above a subsea wellhead, or wet tree, 130 disposed above subsea well 110. The wellhead 130 is in fluid communication with production tubing 140 disposed within the interior of wellbore 110. In this way, a central lumen is formed that fluidly connects drilling rig 115 to the interior of wellbore 110 for the deployment of drilling equipment and other tools (not shown). During initial completion operations, deep-set tubing-retrievable subsurface safety valve 105 is deployed as an integrated part of production tubing 140, typically disposed within 200 feet of the hanger (not independently illustrated) of the wet tree 130. After completion, drilling rig 115 is moved off the well site and a Floating Production and Storage Offloading (“FPSO”) vessel (not shown) is typically brought in to fluidly connect to the wet tree 130 to facilitate production activities. The FPSO (not shown) typically includes a surface-based control system (not shown) that communicates hydraulic actuation fluid through the wet tree 130 to the deep-set tubing-retrievable subsurface safety valve 105 via the control line (not shown). When the operator wishes to start production, the surface-based control system (not shown) provides hydraulic pressure in the control line (not shown) that overcomes the resistance of the biasing means (not shown), causing the flapper (not shown) or valve (not shown) to open, permitting production flow towards the surface. The production fluids may be directed from the wet tree 130 to a storage tank (not shown) on the FPSO (not shown) for storage and delivery.
As described in U.S. Pat. No. 5,310,004, valve 105 includes a central lumen 202 that extends from distal end to distal end and a flapper 204 connected to a lower portion of a housing 206 by a pivot pin 208. Valve 105 allows end-to-end communication through the central lumen 202 when flapper 204 is in the open position and prevents flow when flapper vale 204 is in the default closed position. Valve 105 includes a piston 210 and a cylinder 212 that are connected to a flow tube 214. To open valve 105, the application of hydraulic pressure, via the control line (not shown), to the top side of piston and cylinder assembly 216 causes flow tube 214 to move downward, forcing flapper 204 off of valve seat 218, opening valve 105 to production flow therethrough. In the absence of sufficient hydraulic pressure, biasing means, such as biasing spring 220 and a pressurized gas chamber 222, are biased to push flow tube 214 in an upward direction, thereby releasing flapper 204 to close valve 105. Spring 220 acts between a shoulder 224 on housing 206 and a shoulder 226 on flow tube 214. Pressurized gas chamber 222 includes a plurality of tubing coils 228 containing pressurized nitrogen.
As a failsafe, piston 210 includes a second piston 232 that is telescopically positioned in an end of first piston 210. The second piston 232 includes a first end 234 and a second end 236, where the second end 236 has a larger cross-sectional area than the first end 234. The first end 234 and second end 236 each sealably engage first piston 210 by seals 238 (not shown) and 240 (not shown). Seal 238 seals a smaller cross-sectional area than larger seal 240. The first piston 210 includes a hydraulic fluid passageway 242 that extends from a first side of the hydraulic piston and cylinder assembly 216 to the first end 234 of the second piston 232 and acts against seal 240. The second end 236 of second piston 232 is exposed to the gas pressure in chamber 222. Because the cross-sectional area of the second end 236 of second piston 232 has a larger seal area 240 than seal area 238 of first end 234, second piston 232 will remain in engagement in the end of first piston 210 with a lower gas pressure acting on second end 236 compared with hydraulic actuation fluid acting on first end 234. However, if gas pressure is lost, and unable to overcome the hydrostatic head of the hydraulic actuation fluid in the control line (not shown), the force of the gas pressure acting on second end 236 of the second piston 232 decreases allowing the hydrostatic pressure of the hydraulic fluid acting on the first end 234 to push the second piston 232 out of piston 210, thereby balancing the hydrostatic actuation fluid forces on piston 210, such that biasing spring 220 may close valve 105 safely. One of ordinary skill in the art will appreciate that the conventional deep-set tubing-retrievable subsurface safety valve described herein is merely exemplary and there are other designs, however, each of which relies on additional biasing means to assist in closing the valve against the increased hydrostatic head encountered in deep-set applications.
In the aftermath of the Deepwater Horizon incident, the use of deep-set tubing retrievable subsurface safety valves increased dramatically. While various original equipment manufacturers claim that deep-set tubing-retrievable subsurface safety valves are capable of reliable operation at substantial depth, until recently, their actual performance in deepwater and ultra-deepwater wells was not well characterized. Unfortunately, data from the field suggests that deep-set tubing retrievable subsurface safety valves have a substantially higher failure rate than that of conventional tubing-retrievable subsurface safety valves, resulting in non-commanded closures and other critical failure modes. Specifically, high-profile failures have shed light on the substantial risk these deep-set valves pose in deepwater and ultra-deepwater applications. In a litigation matter filed in the United States District Court for the Southern District of Texas, styled Hess Corporation® v. Schlumberger Technology Corporation® (case 4:16-CV-03415), Hess filed suit against Schlumberger for damages resulting from the alleged failure of Schlumberger's deep-set tubing retrievable subsurface safety valves deployed offshore. Hess purchased five (5) deep-set tubing-retrievable subsurface safety valves from Schlumberger for use in subsea wells in the Outer Continental Shelf of the Gulf of Mexico. As of the date of the complaint, three (3) of the five (5) deep-set tubing-retrievable subsurface safety valves deployed in deepwater subsea wells failed. According to Hess, this has resulted in significant production losses, costs associated with pulling and replacing the failed valves, costs associated with restoring production capabilities, property loss and damage, and deferred production costs associated with schedule delays on subsequent producer and injector wells. The subsea wells at issue were drilled in approximately 4,300 feet of water, with the wells themselves having an approximate total vertical depth of approximately 25,000 feet. These wells produced between 2,000 and 16,500 barrels of oil per day, before being shut-in by non-commanded valve closure and potentially other failure modes. In quantifying the substantial costs incurred due to these failures, Hess complained that, with respect to a single subsea well, it took 64 days and cost approximately $60 million dollars to restore production operations, exclusive of lost profits.
The issues complained of in the above-noted litigation highlight a longstanding problem in the industry that threatens the financial viability and overall feasibility of deepwater and ultra-deepwater plays. While tubing-retrievable subsurface safety valves are required in deepwater and ultra-deepwater applications, unfortunately, when they fail, the well must be re-completed in a time-consuming and expensive process that requires floating a drilling rig back onto the well site, pulling the production tubing, replacing the failed tubing-retrievable subsurface safety valve, and re-deploying the production tubing with the replaced tubing-retrievable subsurface safety valve. In addition to the substantial costs associated with the above-noted re-completion activities, profits lost for the duration of these operations are substantial. As noted in the real-world example, the frequency of failure of deep-set tubing-retrievable subsurface safety valves and the substantial time and cost required to re-complete a well jeopardize the safety of operations and many operators are shying away from such deepwater and ultra-deepwater plays, where a significant amount of oil and gas reserves are known to exist.
In a failed conventional, not deep-set, tubing-retrievable subsurface safety valve set at a shallower depth, typically less than 3,500 feet, one avenue for proceeding is to deploy a conventional wireline-retrievable subsurface safety valve within the failed tubing-retrievable subsurface safety valve. The wireline-retrievable subsurface safety valve may be run into the well on a lock that locates the wireline-retrievable subsurface safety valve within a desired location of the failed tubing-retrievable subsurface safety valve. The wireline-retrievable subsurface safety valve typically includes packing elements that isolate the hydraulic chamber that was previously used to control the now failed tubing-retrievable subsurface safety valve. The process of opening up the original hydraulic actuation pathway of the failed tubing-retrievable subsurface safety valve for use with the wireline-retrievable subsurface safety valve is referred to as communication. Once communication has been achieved, a surface-controlled pump system may pump hydraulic actuation fluid through the hydraulic chamber of the failed tubing-retrievable subsurface safety valve to the hydraulic chamber of the wireline-retrievable subsurface safety valve to hydraulically actuate the wireline-retrievable subsurface safety valve in a similar manner to that of the failed tubing-retrievable subsurface safety valve.
While the wireline-retrievable subsurface safety valve potentially reduces the flow rate of production fluids, it allows such wells to continue to produce after failure of the tubing-retrievable subsurface safety valve without the attendant costs of recompleting the well. Similar to the tubing-retrievable subsurface safety valve, the conventional wireline-retrievable subsurface safety valve is a failsafe device that fails in the closed state such that production flow is halted whenever hydraulic actuation pressure is sufficiently reduced or removed. As such, the conventional wireline-retrievable subsurface safety valve requires the positive application of hydraulic actuation pressure to open a flapper or valve to permit production flow through the subsurface safety valve. In the event of a failure or catastrophic event, once the hydraulic actuation is lost, the energy stored in a power spring disposed above the flapper of the wireline-retrievable subsurface safety valve causes the subsurface safety valve to close, thereby safely halting production flow.
Notwithstanding, conventional wireline-retrievable subsurface safety valves cannot be used in deepwater and ultra-deepwater subsea wells. The depth at which conventional wireline-retrievable subsurface safety valves may be deployed is constrained by the ability to provide sufficient hydraulic activation pressure at the setting depth. Conventional wireline-retrievable subsurface safety valves require the application of hydraulic actuation pressure to compress a bias spring disposed above the flapper or valve to controllably open the valve when production flow towards the surface is desired. If the conventional wireline-retrievable subsurface safety valve is deployed at a depth that exceeds the ability of the hydraulic actuation to overcome the hydrostatic head in the control line, the conventional wireline-retrievable subsurface safety valve cannot be opened, thereby preventing production flow.
Further, conventional wireline-retrievable subsurface safety valves require a bias spring disposed above the flapper or valve that is capable of storing sufficient energy to offset the increased hydrostatic head in the control line, at the setting depth, such that it can reliably fail in the closed state. However, this is not feasible because the size of the bias spring disposed above the flapper or valve is physically constrained by the inner diameter of the wireline-retrievable subsurface safety valve itself. Since the conventional wireline-retrievable subsurface safety valves require an inner diameter capable of fluidly communicating production flow, the amount of space above the flapper or valve is physically constrained, thereby limiting the amount of energy capable of being stored in the bias spring and, as a consequence, substantially limiting the depth at which the conventional wireline-retrievable subsurface safety valve may be set, typically much shallower than 3,500 feet.
As such, the current state of the art in the industry is to deploy a SSBOP and deep-set tubing-retrievable subsurface safety valve as a permanently installed two barrier system for deepwater and ultra-deepwater subsea wells. When the tubing-retrievable subsurface safety valve fails, for whatever reason, the operator must undertake a complex, time-consuming, and expensive process to re-complete the well in an attempt to resume production operations. As noted above, a drilling rig must be brought onto the well site, the production tubing must be pulled, the failed deep-set tubing-retrievable subsurface safety valve must be replaced, the production tubing must be run back into the well, and the well must be completed with a wellhead or wet tree.
Accordingly, in one or more embodiments of the present invention, a method of intervention in a failed deep-set tubing-retrievable subsurface safety valve disposed in a deepwater or ultra-deepwater subsea well does not require re-completion of the well and substantially reduces non-productive down-time, lost profits, and costs associated with resuming production. Advantageously, the production tubing, including the failed deep-set tubing-retrievable subsurface safety valve do not have to be pulled, dramatically simplifying operations and reducing costs. A light intervention vessel may be used as the platform for performing the intervention, rather than a conventional drilling rig or platform, substantially expediting operations and reducing costs typically associated with floating a large drilling rig back onto the well site. A deep-set wireline-retrievable subsurface safety valve may be deployed via wireline into the failed deep-set tubing-retrievable subsurface safety valve, where the deep-set wireline-retrievable subsurface safety valve has a closure actuation mechanism that is disposed below the closure device. In addition, the closure actuation mechanism includes a pressure-balanced piston that is exposed to wellbore fluids on both distal ends of the piston, thereby allowing the piston to actuate the closure device in deepwater and ultra-deepwater wells with significant hydrostatic head in the control line.
In certain embodiments, a robotically operated vehicle (“ROV”) 320 may be tethered to an ROV umbilical 325 to observe and assist in the intervention operations taking place at or near the seafloor 120. After wellbore access is achieved, a wireline-deployable lockout tool (not shown) is run into the wellbore (e.g., 110 of
Once properly located, the communication tool 405 may be turned on to remove material and form a radial cutout 410 that intersects at least one piston hole in the hydraulic chamber (not shown) of the failed deep-set tubing-retrievable subsurface safety valve 105, thereby establishing communication to enable operation of an insert valve, such as a deep-set wireline-retrievable subsurface safety valve (not shown). Continuing,
Once communication is complete, a deep-set wireline-retrievable subsurface safety valve 500 is run into a central lumen of the failed deep-set tubing-retrievable subsurface safety valve (e.g., 105 of
For purposes of illustration, an embodiment of a deep-set wireline-retrievable subsurface safety valve 500 is described herein. However, one of ordinary skill in the art, having the benefit of this disclosure, will appreciate that other designs that meet the above-noted requirements may be used in accordance with one or more embodiments of the present invention and their usage is contemplated by one or more methods of the claimed invention.
Continuing,
Power spring 689 may be disposed within a gas chamber formed by spring housing 690, intermediate power seal 684, hydraulic chamber housing 672, lower power seal 684, and nose cap housing 698. The gas chamber may be voided, filled with air, or charged with one or more gases, including potentially, nitrogen, although nitrogen charging is not required to uncompress power spring 689 at deepwater or ultra-deepwater depths. While upper power seal 660 and lower power seal 694 are in communication with production tubing pressure, both seals have the same diameter and are disposed on opposing ends of power piston 680. As such, their pressure areas are the same and the forces acting on the power piston 680 effectively cancel each other out, thus power piston 680 is said to be pressure balanced. As such, power spring 689 may not be sensitive to production tubing pressure. Thus, the hydraulic actuation pressure required to compress power spring 689 may be substantially less than the production tubing pressure and when that actuation pressure is sufficiently reduced or removed, power spring 689 does not require nitrogen charging to uncompress and fully close deep-set wireline-retrievable subsurface safety valve 500 at a deepwater or ultra-deepwater depths.
Continuing,
Continuing,
Once locked out and communicated, a deep-set wireline retrievable subsurface safety valve 500 (not shown) may be run into a central lumen of the failed tubing-retrievable subsurface safety valve 105. The deep-set wireline-retrievable subsurface safety valve 500 (not shown) may be landed within a no-go shoulder or other profile of the failed tubing-retrievable subsurface safety valve 105. Once landed, the deep-set wireline-retrievable subsurface safety valve 500 (not shown) may be locked into place at a location within the failed tubing-retrievable subsurface safety valve 105 that facilitates communication with the hydraulic chamber of the failed tubing-retrievable subsurface safety valve 105. Once installed, an FPSO 1100 may provide hydraulic actuation fluid from a surface-controlled pump system to the deep-set wireline-retrievable subsurface safety valve via a conduit that fluidly connects the wet tree 130 to the control line (not shown) of the failed deep-set tubing-retrievable subsurface safety valve 105. Because deep-set wireline-retrievable subsurface safety valve 500 (not shown) includes a closure actuation mechanism that is disposed below the closure device, where the actuation mechanism includes a pressure-balanced piston that is exposed to wellbore fluids on both distal ends of the piston, and the closure device includes an equalization system that equalizes pressure across the closure device to facilitate opening, the deep-set wireline-retrievable subsurface safety valve is capable of operation at deepwater and ultra-deepwater depths.
Advantages of one or more embodiments of the present invention may include one or more of the following:
In one or more embodiments of the present invention, method of intervention in a failed deep-set tubing-retrievable subsurface safety valve disposed in a deepwater or ultra-deepwater subsea well does not require re-completion of the well and substantially reduces non-productive downtime, lost profits, and costs associated with resuming production. Advantageously, the production tubing, including the failed deep-set tubing-retrievable subsurface safety valve, does not have to be pulled, dramatically simplifying operations and reducing costs.
In one or more embodiments of the present invention, method of intervention in a failed deep-set tubing-retrievable subsurface safety valve disposed in a deepwater or ultra-deepwater subsea well may use a light intervention vessel rather than a conventional drilling rig, substantially expediting operations and reducing costs.
In one or more embodiments of the present invention, method of intervention in a failed deep-set tubing-retrievable subsurface safety valve disposed in a deepwater or ultra-deepwater subsea well uses a deep-set wireline-retrievable subsurface safety valve having a closure actuation mechanism disposed below a closure device.
In one or more embodiments of the present invention, method of intervention in a failed deep-set tubing-retrievable subsurface safety valve disposed in a deepwater or ultra-deepwater subsea well uses a deep-set wireline-retrievable subsurface safety valve having an actuation mechanism including a pressure-balanced piston that is exposed to wellbore fluids on both distal ends of the piston, thereby allowing the piston to actuate the closure device in deepwater and ultra-deepwater subsea wells with significant hydrostatic head.
In one or more embodiments of the present invention, method of intervention in a failed deep-set tubing-retrievable subsurface safety valve disposed in a deepwater or ultra-deepwater subsea well uses a deep-set wireline-retrievable subsurface safety valve having a closure device that includes equalization means configured to equalize pressure across the closure device to facilitate opening the closure device.
In one or more embodiments of the present invention method of intervention in a failed deep-set tubing-retrievable subsurface safety valve disposed in a deepwater or ultra-deepwater subsea well establishes surface-control by communicating the hydraulic chamber housing of the failed deep-set tubing retrievable subsurface safety valve with the hydraulic chamber of the wireline-retrievable subsurface safety valve.
While the present invention has been described with respect to the above-noted embodiments, those skilled in the art, having the benefit of this disclosure, will recognize that other embodiments may be devised that are within the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the appended claims.
This application is a continuation-in-part of U.S. patent application Ser. No. 16/378,740, filed on Apr. 9, 2019, which claims the benefit of, or priority to, U.S. Provisional Patent Application Ser. No. 62/779,121, filed on Dec. 13, 2018, both of which are hereby incorporated by reference in their entirety. This application is a continuation-in-part of U.S. patent application Ser. No. 16/386,624, filed on Apr. 17, 2019, which claims the benefit of, or priority to, U.S. Provisional Patent Application Ser. No. 62/718,737, filed on Aug. 14, 2018, both of which are hereby incorporated by reference in their entirety.
| Number | Date | Country | |
|---|---|---|---|
| 62779121 | Dec 2018 | US | |
| 62718737 | Aug 2018 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 16378740 | Apr 2019 | US |
| Child | 16886665 | US | |
| Parent | 16386624 | Apr 2019 | US |
| Child | 16378740 | US |
