EP4328414A1

EP4328414A1 - A workover system for receiving a tubular string from a wellbore

Info

Publication number: EP4328414A1
Application number: EP23178255.8A
Authority: EP
Inventors: Antonius Stefan Von Der Heide; Sven HEIJWEGEN
Original assignee: Well Gear Group BV
Current assignee: Well Gear Group BV
Priority date: 2022-06-09
Filing date: 2023-06-08
Publication date: 2024-02-28
Also published as: NL2032110B1

Abstract

A workover system for receiving a tubular string from a wellbore pressurized by hydrogen, the system including:
- at least three BOPs (5, 6, 7) defining at least a first part (P 1) and a second part (P2) of a string passage there-between, each BOP (5, 6, 7) being configured to sealingly engage an outer surface of a tubular string (T) when the BOP (5, 6, 7) is in a sealing state and to disengage the outer surface of the tubular string (T) when the BOP is in a releasing state; and
-a pressure conditioning system (11, 12, 13, 14, 21, 22) configured to fill each of the first and second part (P1, P2) of the string passage with a buffer fluid, in particular during at pressurization period.

Also, there is provided a method for moving a tubular string through a wellbore.

Description

The invention relates to a workover system for receiving a tubular string from a wellbore.
Such a system (also called `snubbing unit') is commonly known in the field of oil production, and can generally be applied for stripping processes. In particular, the wellbore can be a bore extending from an underground well to a wellhead (aboveground), for receiving a tubular string for passing or pumping oil or natural gas from the well to the wellhead (to be received, transported, processed, stored, et cetera).
The tubular string can include or consist of an array of tube sections that are interconnected by tube coupling sections (or 'joints'), a length of the string e.g. being several hundreds of meters or at least 1 km (e.g. strings up to 5 km). Usually, the tube coupling sections have a diameter that is slightly larger than a diameter of each of the respective tube section. The string can e.g. be a tool string or a production string, e.g. a dewatering string, a kill string, or the-like. The wellbore as such can e.g. be provided with a casing and/or liner through which the string reaches between the well and the wellhead.
The wellhead as such can include one or more Blow Out Preventers (BOPs), for example ram-type BOPs, known per se, for shutting off the wellhead if required. Also, the workover system can include an array of BOPs, for sealingly engaging a string that is to be moved into or out of the wellbore. General information concerning the commonly known BOP can e.g. be found on https://en.wikipedia.org/wiki/Blowout_preventer.
As an example, WO2021096490 discloses a hydraulic workover unit for use with an overbalanced oil well, wherein wellbore pressure exceeds formation fluid pressure preventing the well from flowing. As follows from WO'490, a live well (snubbing) workover is applied, whereby the well remains under pressure during the workover. In such snubbing operations, equipment is ran into the well on a pipe string using a hydraulic workover rig. Unlike wireline or coiled tubing, the pipe sections that make up the pipe string are not spooled off a drum, but made up and broken up while running in and pulling out, much like conventional drill pipe. However, according to WO'490, even in wells that are overbalanced such that formation fluids are not flowing to the surface, there may be gas, such as hydrogen sulfide existing in the well between the formation fluid column in the well and the surface. This gas must be taken into consideration and contained during live well workovers. Thus, blow out preventer are positioned between the wellhead and the hydraulic jack utilized in the snubbing workover to trip tubing string in and out of the well. Where the tubing string is annular in cross-section, the BOP may be a conventional annular BOP with a dynamic seal that retains the seal as the tubing string is passed through the BOP. WO2021096490 discloses an example that includes using nitrogen as a purge gas in order to expel hydrogen sulfide from within an annulus extending along the string in the workover system.
A relatively recent field of technology concerns filling (and pressurizing) underground caverns/wells (e.g. salt caverns) with pure hydrogen (H₂). The hydrogen can e.g. be obtained using environmental-friendly processes such as electrolyzing water using green electricity (e.g. obtained from solar energy, wind energy, water power energy, or the-like). Underground cavities/wells are beneficial for storing large amounts of pressurized hydrogen. For example, such a well can be a depleted oil or natural gas reservoir, that can be reused by pumping hydrogen into the well. A said tubular string can be used for pumping the hydrogen into the well, for filling and pressurizing the underground well, and/or for receiving hydrogen from the underground well.
A problem of a hydrogen filled and pressurized well is the extreme flammability and low ignition energy of hydrogen. Risk of explosion is very high once hydrogen comes into contact with ambient air (much more risky than natural gas). Moreover, hydrogen is light-weight (moved up quickly, at 3 to 20 m/s according to an estimation), and is relatively difficult to contain (i.e. leakage risks are high). Also, hydrogen is an odorous gas. It follows that once an underground well has been substantially filled and pressurized with hydrogen, any movement of the tubular string with respect to string engaging structures of a work-over unit can be problematic due to risks of hydrogen leakage and resulting explosion risks.
CA2961815 concerns a sonic coring blowout preventer system and method for core sample recovery of unconsolidated, sand associated with solvent or steam assisted. gravity drainage swept reservoirs. A new class of blowout preventer (BOP) assembly is utilized that includes three annular BOPs and one set of blind rams. The BOP assembly is configured for sonic drilling and advancing of a drill pipe with independent advancing of a sonic casing, The BOP assembly allows for complete well control and stripping all tubular in and out of the core hole while sealing around different sizes of easing, tubulars and bottom hole assemblies. Each BOP is independently controlled for sealing operations against a sonic casing or drill pipe, allowing for advancement of the sonic casing and/or drill pipe under controlled pressure. The document does not concern hydrogen related problems.
The present invention aims to alleviate or overcome the above-mentioned problems. In particular, the invention aims to provide a system and method that can provide safe stripping in case of a hydrogen filled and pressurized well (in which case the respective wellbore contains pressurized hydrogen). The stripping can involve moving a string at least partly out of the wellbore that leads to the pressurized hydrogen well, or moving the string into the wellbore.
According to an aspect of the invention, this is achieved by the features of claim 1.
Advantageously, there is provided a workover system for receiving a tubular string from a wellbore pressurized by hydrogen, the system including:

at least three BOPs defining at least a first part and a second part of a string passage there-between, each BOP being configured to sealingly engage an outer surface of a tubular string when the BOP is in a sealing state and to disengage the outer surface of the tubular string when the BOP is in a releasing state; and
a pressure conditioning system configured to fill each of the first and second part of the string passage with a buffer fluid (during operation, e.g. during a pressurization period or pressurization mode of the system), the buffer fluid preferably being an inert gas and/or nitrogen and/or water and/or brine.

In this way, relatively safe stripping operation can be achieved concerning a wellbore pressurized by hydrogen. In particular, during operation, the pressure conditioning system can fill each of the two parts of the string passage (and in particular respective annular sections, i.e. string passage sections located between an outer surface of the passing string and opposite inner surfaces of the BOPs) with the buffer fluid. Thus, risks of leakage/escape of hydrogen from the wellbore can be significantly reduced. The three respective BOPs (Blow Out Preventers) can be operated in a suitable manner to allow movement of the tubular string, and in particular to allow passage or a widened section (such as a tube coupling section) of the string along each of the BOPs. During such a passage, the respective BOP can be opened (i.e. adjusted to a releasing state) whereas the two other BOPs can remain closed (i.e. retain their sealing states) to define a buffer fluid filled string passage part there-between. In particular, the system (i.e. the BOPs and the pressure conditioning system) can be controlled such that at any time of operating a buffer fluid filled section is available around the string (and between the BOPs) to prevent contact of wellbore hydrogen with ambient atmosphere (e.g. air).
The pressure conditioning system can be configured in various ways as will be appreciated by the skilled person. The pressure conditioning system can e.g. include a fluid supply for supply of the buffer fluid, the fluid supply having fluid supply ports to (independently) feed the fluid to each of the first of second part of the string passage. Also the pressure conditioning system can include one or more fluid discharge ports for discharging fluid from each of the first of second part of the string passage. The pressure conditioning system can e.g. include valves or valve means, for controlling fluid supply to the first of second part of the string passage and/or for controlling discharge of fluid from the first of second part of the string passage.
According to a preferred embodiment, one or more (e.g. each) of the three BOPs are ram-type BOPs (known as such). Alternatively or optionally, at least one of the three BOPs can be an annular BOP. Optionally, a BOP can be a ram-type BOP as well as an annular BOP.
Herein, said string passage in particular is an internal channel between the three BOPs, e.g. defined by/in wall structures of the BOPs or respective BOP mounting structures that can be part of the workover system, as will be appreciated by the skilled person. For example, during operation, the workover system and a tubular string can define an annular cylindrical space there-between, which annular cylindrical space is divided into two sections by the three BOPs, the two sections being filled with the buffer fluid during operation. In other words: the first part of the string passage (defined by the three BOPs) can include a first annular cylindrical space that is defined between an outer surface of the string and opposite inner surfaces of the first and second BOP. The second part of the string passage can include a second annular cylindrical space that is defined between an outer surface of the string and opposite inner surfaces of the second and third BOP. Said two annular cylindrical spaces can provide two buffer chambers, to be filled with the buffer fluid, e.g. during a pressurization step (i.e. during a pressurization period or pressurization mode of the system).
Also, herein, the first part of the string passage can be located relatively close to the wellbore (or a respective wellhead) and the second part of the string passage can be located farther away from the wellbore compared to the location of the first part of the string passage. In case of a substantially vertical displacement of the string, e.g. the first part of the string passage can be located (preferably immediately) below the second part of the string passage.
Besides, as will be clear to the skilled person, the first part and the second part of the string passage can be mutually separated and hermetically sealed from each other (in a gastight manner) by one of the three BOPs, in particular by an intermediate BOP, e.g. when that intermediate BOP is in a sealing state (and sealingly engages a string extending through the workover system). Moreover, in that case, the first part and second part of the string passage can be in fluid communication via the intermediate BOP when that intermediate BOP is in a respective releasing state (and does not sealingly engage the string, e.g. to allow passage of a widened string section).
According to a preferred embodiment, the pressure conditioning system is configured to entirely fill and pressurize each of the first and second part of the string passage with the buffer fluid when each of the three BOPs is in a respective closed state or sealing state. In particular, during operation, when a string extends through the BOP array, annular spaces between an outer surface of the string and inner surfaces of the BOP array are filled and pressurized with the buffer fluid, as will be clear to the skilled person.
Also, according to a preferred embodiment the pressure conditioning system is configured to pressurize the first part and/or the second part of the string passage, and preferably both the first part and the second part, with the buffer fluid to substantially the same pressure as a wellbore pressure or to a pressure higher than the wellbore pressure. In this way, an optimum buffer of buffer fluid can be provided in the workover system to prevent leakage of hydrogen into ambient air.
Good results and efficient operation can be achieved in case the pressure conditioning system is configured to pressurize the second part of the string passage with the buffer fluid to substantially the same pressure as a wellbore pressure or to a pressure higher than the wellbore pressure when a first BOP of the three BOPs is in a releasing state and an intermediate second BOP and a third BOP of the three BOPs are in respective sealing states.
According to an extra advantageous embodiment, the pressure conditioning system is also configured to depressurize the first part and/or the second part of the string passage (during operation, e.g. during a respective depressurization period or depressurization mode), to a pressure that is e.g. at most about 5% of a wellbore pressure, preferably atmospheric pressure, in particular when all three BOPs are in respective sealing states. In this way, substantially any or most wellbore hydrogen (H₂) that has entered the first part and/or second part of the string passage can be removed in a controlled manner, for example to be bled off or pumped away, and stored or burnt. For safety reasons, it is preferred that at least the part of the string passage that is be located relatively close to the wellbore (or a respective wellhead) is depressurized for removing hydrogen therefrom. In particular, during operation of the system, at least the first part of the string passage can be depressurized to remove substantially all hydrogen therefrom, e.g. in case all BOPs are in string sealing engagement states, and for example in case a tool coupling section of the string is present in that string passage part. Depressurization can e.g. involve bringing down pressure in the first string passage part from a wellbore pressure to atmospheric pressure. The system is preferably configured to repressure the first part of the string passage in a next step, by supplying the buffer fluid (as re-pressurization fluid) thereto, such that the first part of the string passage substantially contains the buffer fluid instead of the hydrogen. The system can e.g. be configured to supply the re-pressurization fluid from the second part of the string passage, in a pressure equalization step, providing efficient system operation. In a next step, an intermediate BOP of the three BOPs can be opened and the string can be moved, allowing e.g. safe passage of a widened string section (i.e. a string joint) from the first part of the string passage to the second part of the string passage. In a next step, the intermediate BOP can be closed after which the third BOP can be opened, allowing further movement of the string, e.g. to pass a string joint into ambient air for further string processing.
Also, an aspect of the invention provides a system including a subsurface reservoir, a wellbore and a tubular string configured to extend through the wellbore, wherein the reservoir includes pressurized hydrogen, wherein the system includes a workover system according to the invention for moving the tubular string through the wellbore.
In this way, above-mentioned advantages can be achieved.
In addition, there is provided an innovative method for moving a tubular string through a wellbore, for example utilizing a system according to the invention, wherein the tubular string includes an array of tube sections interconnected by widened tube joint sections, wherein the wellbore contains pressurized hydrogen, the method including:

providing three BOPs defining two subsequent string passage parts there-between;
a pressurization step of filling and pressurizing both of the string passage parts with buffer fluid when each of the three BOPs sealingly engages an outer surface of the tubular string;
adjusting one of the three BOPs to a releasing state allowing passage of a widened section of the string;
moving the widened section of the tubular string along the BOP that is in its releasing state while the other two BOPs sealingly engage the outer surface of the tubular string; and
adjusting the latter BOP back from its releasing state to a state to sealingly engage the outer surface of the tubular string.

Thus, safe stripping can be achieved on a string that extends through a hydrogen filled wellbore.
It is preferred that both of the string passage parts are entirely filled with the buffer fluid, and are pressurized to a wellbore pressure or to a pressure above wellbore pressure with the buffer fluid, during the pressurization step. Also, wellbore hydrogen can be removed in a controlled manner in case pressure reduction step is applied wherein fluid is discharged from a part of the string passage that is to receive and/or has received the widened string section. Besides, the method preferably includes refilling a string passage part with buffer fluid after a pressure reduction step has been carried out on that string passage part, to further reduce chances of explosion (the refilling in particular leading to a string passage part that substantially or entirely contains the buffer fluid, and e.g. a background H₂ content less than 5 vol%, preferably less than 2 vol%).
Further advantageous features of the invention are described in the dependent claims. In the following, the invention will be explained with reference to the drawings which show a non-limiting example.

Figure 1 schematically depicts a system that includes a hydrogen well, wellbore and a workover system;
Figure 2 schematically shows a detail Q of Fig 1, providing a cross-section of part of the workover system depicted in Fig. 1;
Figure 3 shows the workover system part of Fig. 2, during a first stripping step;
Figure 4 shows the workover system part of Fig. 2, during a second stripping step;
Figure 5 shows the workover system part of Fig. 2, during a third stripping step;
Figure 6 shows the workover system part of Fig. 2, during a fourth stripping step;
Figure 7 shows the workover system part of Fig. 2, during a fifth stripping step;
Figure 8 shows the workover system part of Fig. 2, during a sixth stripping step; and
Figure 9 shows the workover system part of Fig. 2, during a seventh stripping step.

In this application, similar or corresponding features are denoted by similar or corresponding reference signs.
Figure 1 schematically depicts a system including a subsurface (i.e. underground) reservoir W, a wellbore 1 and a tubular string T that reaches through the wellbore 1. A surface level is indicated by arrow G. The system includes a workover system 4 for moving the tubular T string through the wellbore 1, for example for moving the string in upwards direction Z (i.e. out of the wellbore) or vice-versa in downwards direction. The workover system 4 as such can include an actuating structure configured to engage the tubular string T and to draw the tubular string T with respect of the string passage. The actuating structure can e.g. include hydraulic means for engaging the string T and moving the string with respect to the wellbore 1. Also, the structure can include means for uncoupling (or coupling) mutual string sections, as will be clear to the skilled person.
The workover system 4 can e.g. be called a rigup, whereas operation of the system can be called a workover, or stripping, in particular in case of a pressurized well W. As will be appreciated by the skilled person, the string T (in assembled state) can be relatively long (at least 100 m, and/or up to e.g. 5 km) and can be made of numerous string sections that are interconnected by widened joints or joint sections TJ (see Fig. 5), e.g. screw-threaded joints (also called `thread joints', `tool joints'), known per se.
The workover system 4 includes a lower section 4a that can be coupled (in a sealed, gastight manner) to the wellhead 4a for passing the string T between the wellhead 4a and a further part of the workover system, the lower section 4a in particular being (directly) located above the wellhead 2. A non-limiting example of this section 4a is shown in Figure 2 (wherein the string T has not been depicted), and an example of its operation (i.e. various stripping steps) is shown in Figures 3-9. A coupling (e.g. including suitable coupling flanges and a sealing structure) between the workover system section 4a and the wellhead 2 can be such that it can withstand high operating pressures, e.g. internal wellbore pressures so that leakage of pressurized wellbore content via that coupling is prevented, as will be clear to the skilled person. As will be explained in more detail below, the lower workover system section 4a includes at least three BOPs 5, 6, 7 as well as a pressure conditioning system 11, 12, 13, 14, 21, 22.
The reservoir W includes pressurized hydrogen gas (H₂). For example, the reservoir W can be entirely filled with pure hydrogen, or at least partly with pure hydrogen (e.g. for at least 50%). In particular, the pressurized H₂ is present in the wellbore 1, for example in an annular space between an inner side of the wellbore 1 and an outer side of the string T.
For example, a pressure of the hydrogen in the wellbore 1, and in particular in the wellhead 2, can be relatively high, i.e. above atmospheric pressure, for example at least 50 bar, e.g. reaching up to 200 bar or more. It follows that during operation, an intermediate (e.g. annular, cylindrical) space between the string T and an inner side of the wellhead 2 can contain and be entirely filled with such pressurized hydrogen.
In order to prevent leakage of the highly volatile, pressurized hydrogen into ambient air, the lower section 4a of the workover system preferably has an array of at least three BOPs 5, 6, 7 defining (and enclosing) at least a first part P1 and a second part P2 of a string passage there-between. For example the first string passage part P1 can be located (immediately) below the second string passage part P2. Also, the first string passage part P1 can be located near or immediately above the wellhead 2 for passing the string T thereto and/or receiving the string T therefrom (but that is not required).
Each of the BOPs can include a respective controllable sealing structure 5a, 6a, 7a (known per se, e.g. an annular rubber or elastomeric, e.g. doughnut shaped, sealing element in case of an annular BOP or 'packing element', or in case of a ram-type BOP a stripper insert/ stripper packer, or a similar sealing element) for engaging the string T. It is preferred that each of the three BOPs is a ram-type BOP, but that is not required.
The array/assembly of BOPs can include respective mounting structures 8, 9 (e.g. sealing structure housing sections 8 and intermediate tubular supporting sections 9) for mounting the sealing structures 5a, 6a, 7a at mutually spaced-apart positions, thereby defining the two intermediate string passage parts P1, P2. The mounting structures 8, 9 of the BOP-array can be sealingly connected to each other by respective mounting flanges (to define a hermetically sealed string passage, i.e. sealed passage parts P1, P2, there-through). The BOPs may e.g. be hydraulically driven or operated, respective BOP actuating means are not depicted and known per se.
Each BOP 5, 6, 7 (in particular its sealing structure 5a, 5a, 7a) can be configured to sealingly engage an outer surface of the tubular string T when the BOP 5, 6, 7 is in a sealing state and to disengage the outer surface of the tubular string T when the BOP is in a releasing state (i.e. each BOP is an adjustable Blow Out Preventer). Preferably, at least one of the BOPs 5, 6, 7 and preferably each BOP 5, 6, 7 can also provide a respective further sealing state for locally closing/sealing the string passage in case no string T is present in that BOP (see Fig. 2).
A central controller/control unit (system) CU (for example a computer, processor, user operator panel/interface, data processor, or the-like) can be provided, the control unit CU being communicatively connected to the BOPs (e.g. to respective BOP actuating means, BOP-hydraulics) for controlling operation thereof. Such communication can e.g. be provided via wired and/or wireless communication means, and/or hydraulic control links, known per se (and not depicted). The control unit CU can e.g. be configured to execute respective control unit software to control the system 4 to carry out various operating steps of the present invention (see below). e.g. in a suitable order. Also, the control unit CU can be configured to be operated by a human controller (e.g. via a user-interface, a control panel or the-like) to control the system 4. It is preferred that the control unit CU can also be used to control the actuating structure of the workover unit 4, e.g. to synchronize string displacement with BOP states.
The two string passage parts P1, P2 can be or define two chambers or buffer sections, that can be separated by one of the BOPs (i.e. an intermediate BOP 6 of the BOP-array) when that BOP 6 is in a -closed-sealing state and engages the string T.
The workover system 4 is preferably configured to fill and pressurize each of the two parts/chambers P1, P2 of the string passage with a buffer fluid (i.e. a sealing fluid), for example pure gaseous nitrogen (N₂), water, brine (salt water), or the-like. In particular, the buffer fluid can be an inflammable fluid, i.e. a fluid that does not react with the hydrogen or ignite the hydrogen. The buffer fluid can e.g. be or include one or more (buffer) gases and one or more (buffer) liquids.
In particular, the workover system includes a pressure conditioning system 11, 12, 13, 14, 21, 22 configured to fill the string passage parts P1, P2 with the buffer fluid (during operation, e.g. during a respective pressurization period/mode). In case the string T extends through the BOP-array, respective local pressurization can be achieved between the outer surface of the string T and the opposite inner surface of the BOP array (i.e. in respective annular cylindrical spaces within the two chambers P1, P2 defined by the array 5, 6, 7).
The afore-mentioned control unit CU is preferably communicatively connected to the pressure conditioning system, in particular to controllable components thereof, e.g. valves and/or pumps, or respective one or more integrated component controllers, if available, for controlling operation thereof.
According to an embodiment, the pressure conditioning system can include a fluid supply system 11, 12 for feeding the buffer fluid to each of the first part P1 and to the second part P2 of the string passage. For example, the fluid supply system can include at least one fluid reservoir 11 (e.g. a storage tank) containing the sealing/buffer fluid (that may be pure nitrogen, or water or the-like), for example pressurized buffer fluid. Optionally, the fluid reservoir 11 can include or be provided with a pump or compressor (not shown) for pressurizing stored buffer fluid to a desired pressure before the fluid is being fed to a string passage part P1, P2.
As will be appreciated by the skilled person, the pressure conditioning system can include a first fluid line structure 12, for example fluid ducts or duct system, for connecting the fluid reservoir 11 to the BOP-array in fluid communication, and in particular to two respective fluid ports 13, 14 that lead into the string passage parts P1, P2. The fluid line structure can include e.g. a number of first valve means or valves 12a for controlling fluid flow there-through. Preferably, the configuration of the pressure conditioning system (e.g. respective fluid lines and valve means) is such, that pressurized buffer fluid can be independently fed into each of the two string passage parts P1, P2 of the BOP-array.
Further, the pressure conditioning system can have a fluid discharge system 21, 22 to discharge fluid from each of the first part P1 and the second part P2 of the string passage, in particular for depressurizing each of those parts P1, P2. It is preferred that the depressurization can be achieved independently. Optionally, the pressure conditioning system can include a fluid receiver unit 21, receiving the fluid from a fluid discharge line 22. The fluid receiver unit 21 can e.g. include a burner for burning a or any combustible part (e.g. said hydrogen) of discharged fluid, and/or a buffer fluid collector for collecting discharged buffer fluid.
The pressure conditioning system can e.g. include a second fluid line structure 22, for example fluid ducts and/or a bleed-off line, for connecting the fluid receiver 21 to the BOP-array in fluid communication, and in particular to two respective fluid port 13, 14 that lead into the string passage parts P1, P2. The second fluid line structure can include e.g. a number of second valve means or valves 22a for controlling fluid flow there-through. The first fluid line structure and second fluid line structure can e.g. be partly integrated, e.g. making use of the same fluid ports 13, 14 of the BOP array.
Optionally, the first and/or second fluid line structure 12, 22 (and e.g. respective valve means) can be configured to bring the two string passage parts P1, P2 via their ports 13, 14 in fluid communication with each other, e.g. to during a pressure equalization step.
The pressure conditioning system 11, 12, 13, 14, 21, 22 is preferably configured to entirely fill and pressurize each of the first and second part P 1, P2 of the string passage with the buffer fluid when each of the three BOPs is in a respective sealing state. Besides, the pressure conditioning system 11, 12, 13, 14, 21, 22 is preferably configured to pressurize the first part P1 and/or the second part P1 of the string passage, and preferably both the first part P1 and the second part P2, with the buffer fluid to substantially the same pressure as a wellbore pressure or to a pressure higher than the wellbore pressure. Also, the pressure conditioning system 11, 12, 13, 14, 21, 22 can be configured to pressurize the second part P2 of the string passage with the buffer fluid to substantially the same pressure as a wellbore pressure or to a pressure higher than the wellbore pressure when a first BOP 5 of the three BOPs is in a releasing state and an intermediate second BOP 6 and a third BOP 7 of the three BOPs are in respective sealing states. Moreover, the pressure conditioning system 11, 12, 13, 14, 21, 22 can be configured to depressurize the first part P1 and/or the second part P2 of the string passage (in particular during operation, during a respective depressurization period/mode), to a pressure that is e.g. at most about 5% of a wellbore pressure, preferably atmospheric pressure, when all three BOPs 5, 6, 7 are in respective sealing states.
It is preferred that the pressure conditioning system includes at least one pressure sensor 10 for detecting/measuring a wellbore pressure, the control unit CU e.g. being configured to control pressure conditioning based on a sensor signal of the pressure sensor 10. For example, such a pressure sensor 10 can be located near or at a lower BOP 5 of the BOP array, e.g. just below that BOP 5, and/or in the wellhead 2 and/or in the wellbore 1, or at a different location. The control unit CU and pressure sensor 10 can be communicatively connected (e.g. wireless or via wired communication means, not shown) for transmitting pressure sensor detection results from the sensor 10 to the control unit CU. The wellbore pressure can in particular be a pressure inside a string passage section extending below the lower BOP 5 of the system 4, e.g. a string passage section within a housing 8 of the respective BOP 5 below the respective sealing structure 5a, or pressure inside a string passage in a below wellhead 2, or a pressure in the wellbore 1 itself). In particular, since the well W contains hydrogen, the wellbore pressure is a hydrogen pressure.
Optionally, one or more pressure sensors (not shown) can be available for measuring pressure in the string passage parts P1, P2, such one or more pressure sensors e.g. being communicatively connected to said control unit CU for transmitting pressure measurement results thereto.
According to an embodiment, the control unit CU can be configured to provide at least one pressurization step (i.e. to set the system in a respective pressurization mode) wherein at least a part 11, 12, 12a of the pressure conditioning system is controlled to pressurize at least part of the string passage between at least two of the three BOPs, for example from atmospheric pressure to wellbore pressure, by feeding the buffer fluid to that part of the string passage, in particular when the at least two of the three BOPs are controlled to be in respective sealing states and sealingly engage a tubular string. During such pressurization step, pressure in a respective string passage part can e.g. be monitored by or via the control unit CU based on pressure measurement results received from a respective string passage part pressure sensor (if available).
According to an embodiment, the control unit CU can be configured to provide at least one pressure reduction step (i.e. to set the system in a respective depressurization mode) wherein at least a part 21, 22, 22a of the pressure conditioning system is controlled to depressurize at least part of the string passage between at least two of the three BOPs by discharging fluid from that part of the string passage, in particular when the at least two of the three BOPs are controlled to be in respective sealing states and sealingly engage a tubular string. The discharging of fluid can e.g. be such that the pressure in the respective part of the at the string passage becomes lower than a pressure in the wellbore 1.During such pressure reduction step, string passage part pressure can also be monitored by or via the control unit CU based on pressure measurement results received from above-mentioned pressure sensors (if available).
According to an embodiment, the control unit CU can be configured to provide a said pressurization step after a said pressure reduction step.
According to a preferred embodiment, the control unit CU can be configured to provide (e.g. to be operated by a human controller to provide) a string drawings step that includes:

bringing one of the three BOPs 5 to its releasing state whilst maintaining the other 6, 7 of the three BOPs in respective sealing states;
controlling the actuating structure to move a widened section TJ of the tubular string T along the BOP 5 that is in its releasing state; and
returning the one of the three BOPs 5 from its releasing state to its sealing state;

BOPs

In this way, the system 4 can provide optimum protection against hydrogen leakage (i.e. hydrogen from the wellbore 1-and wellhead 2- leaking away via the system into ambient air) and related explosion risks. During use, the system 4 can be operated to provide a method for moving a tubular string through the wellbore (e.g. w 'workover'), the tubular string T including an array of tube sections interconnected by widened tube joint sections TJ, and the wellbore 1 contains pressurized hydrogen (H₂), the method including:

providing (at least) three BOPs 5, 6, 7 defining two subsequent string passage parts P1, P2 there-between;
a pressurization step (e.g. during a pressurization period of the system, i.e. when the system is in a pressurization mode) of filling and pressurizing both of the string passage parts P1, P2 with buffer fluid (preferably nitrogen, or e.g. water or brine), when each of the three BOPs 5, 6, 7 sealingly engages an outer surface of the tubular string T;
adjusting one of the three BOPs to a releasing state allowing passage of a widened section TJ of the string T;
moving the widened section TJ of the tubular string along the BOP that is in its releasing state while the other two BOPs sealingly engage the outer surface of the tubular string T; and
adjusting the latter BOP back from its releasing state to a state to sealingly engage the outer surface of the tubular string T.

An example of the method is depicted in Figures 3-9.
Figure 3 shows part of the system, during or after said pressurization step, wherein each of the two (subsequent) string passage parts P1, P2 has been substantially (e.g. for at least 95%) or entirely filled with the inert fluid, e.g. pure nitrogen gas, water or brine. The pressurization can be achieved by the above-mentioned pressure conditioning system (wherein the control unit CU e.g. controls the fluid supply 11 and first fluid line valves 12a to feed pressurized fluid into each of the string passage parts P1, P2 via respective ports 13, 14, the controlling e.g. being an automatic controlling by the control unit itself or a human operator based controlling via the control unit, e.g. via an operating panel thereof). It is preferred that both of the string passage parts P1, P2 are entirely filled with the buffer fluid, and are pressurized to a wellbore pressure or to a pressure above wellbore pressure with the buffer fluid, during the pressurization step. For example, a said pressure sensor 10 can detect the wellbore pressure and provide a pressure detection result, wherein the control unit CU can use the pressure detection result for achieving the respective (same) pressure in each of the two string passage parts P1, P2, and/or provide such a detection result to a human operator (e.g. via a user interface) in order to initiate a subsequent step.
As follows from Figure 3, during the pressurization step, each of the three BOPs can be in a respective sealing state, sealingly engaging the string T that passes through the two string passage parts P1, P2 (from the wellbore, e.g. via the wellhead, towards an upper part of the workover system 4), so that each of the two string passage parts P1, P2 is sealed from its environment.
Figure 3 shows a widened section TS, in particular a tool joint, of the string T being located (just) below the lower BOP 5 of the three BOPs of the workover system 4. The string passage section just below the sealing structure 5a of the lower BOP 5 can be is substantially or entirely filled with pure pressurized hydrogen, emanating from the well W and from wellbore 1 (leading to that string passage section), the hydrogen being at the wellbore pressure.
When pressure of the lower P1 of the two string passage sections between the BOPs 5, 6, 7 has been substantially equalized with the wellbore pressure, the lower BOP can be opened, i.e. adjusted to a respective releasing state (by adjusting the respective sealing structure 5a), allowing passage of the widened section TJ of the string T into that lower chamber (string passage part) P1. This is depicted in Fig. 4. During this step, the intermediate BOP 6 and upper BOP 7 remain closed, thereby providing a hermetically sealed buffer chamber P2 above the lower chamber P1, the sealed chamber still being P2 being entirely filled with the buffer fluid (e.g. pure nitrogen, water or brine). Besides, during this step, due to the opening of the lower BOP 5, pure hydrogen will enter the lower chamber P1. Evenmore, since hydrogen is lightweight, a substantial part of the inert buffer fluid can flow or drop downwardly from the lower chamber P1, being replaced by the hydrogen. As a result, the lower chamber P1 can become substantially or entirely filled with pure pressurized hydrogen (at wellbore pressure). Preferably, during this step, all valves 12a, 22a of the pressure conditioning system remain closed, or at least the valves 12a, 22a of fluid lines leading to or associated with the fluid port 13 of the lower chamber P1 provided by the BOP-array. Thus, since the respective port 13 is closed, no hydrogen can escape via that port from the lower chamber P1 (yet). Subsequently, the widened section TJ of the tubular string T can be moved along sealing structure 5a of the lower BOP 5, whilst the other two BOPs sealingly engage the outer surface of the tubular string T. The movement can be achieved by an afore-mentioned actuating structure of the workover system 4, and can e.g. be controlled by the control unit CU.
Figure 5 depicts a pressure reduction step (i.e. when the system is in a depressurization mode) wherein fluid is discharged from the lower part P1 of the string passage that has received the widened string section TJ. During this step, at least lower BOP 5 and intermediate BOP 6 are in respective sealing states (providing gastight seals to adjoining string passage sections there-above and there-below). During depressurization (e.g. during a depressurization period), pressure of the first part P1 of the string passage in the BOP-array can be brought down e.g.to at most about 5% of the wellbore pressure, preferably to atmospheric pressure, or a vacuum (i.e. sub-atmospheric pressure) in case a vacuum pump is applied to evacuate that string passage part P1. The depressurization can include discharging the hydrogen from the lower chamber P1 via the respective fluid port 13 and fluid receiver unit 21, wherein the hydrogen can e.g. be burnt by the fluid receiver 21, or locally stored (e.g. in a sealed hydrogen reservoir) by that receiver 21.
Once the lower chamber P1 has been evacuated, that chamber contains substantially no or only a little amount of hydrogen, e.g. hydrogen at a vacuum pressure or at an atmospheric pressure. Subsequently, the lower chamber P1 is refilled with inert buffer fluid (see Fig. 6). The refilling is in particular such, that a hydrogen (H₂) to buffer fluid ratio (volumetric) is less than 1:50, more preferably less than 1:100 after the refilling has been finished.
The refilling (i.e. re-pressurization) can be achieved e.g. by the pressure conditioning system supplying inert fluid from a respective buffer fluid supply. Preferably, the refilling includes supplying buffer fluid from the second chamber P2 (as shown in Fig. 6), by bringing the respective fluid ports 13, 14 into fluid communication. The latter option provides the advantage that it can provide pressure equalization between the two chambers P 1, P2 within the BOP array, and leads to efficient operation as well as economical use of buffer fluid. It will be appreciated that the control unit CU can control respective pressure conditioning system components ( e.g. valves 12a, 22a, and optionally a buffer fluid supply pump) to provide suitable fluid supply flows to the first chamber P 1.
It is preferred that the refilling leads to pressure equalization between the first (lower) chamber P1 and the second (upper) chamber P2. In case buffer fluid from the second chamber P2 is used for re-pressurization of the first chamber P1, pressure in the second chamber will generally drop form its initial pressure to a lower pressure.
Next, the intermediate BOP 6 can be opened, i.e. adjusted to a respective releasing state (by adjusting the respective sealing structure 6a), allowing passage of the widened section TJ of the string T into the second (upper) chamber (string passage part) P2. This is depicted in Fig. 7. During this step, both string passage parts P1, P2 are substantially filled with the buffer fluid, as follows from the above.
After the widened section TJ of the string T has been positioned in the second chamber P2, the intermediate BOP 6 can be closed (see Fig. 8) after which the pressure in the second chamber P2 can be lowered (i.e. by the pressure conditioning system, via the respective port 14), e.g. to ambient atmospheric pressure. Then, the upper BOP 7 can be opened and the widened section TJ of the string T can be moved upwardly, out of the BOP-array (see Figure 9), in particular to be processed by the workover system, such as to decouple respective string sections from each other. During this step, the lower chamber P 1 in the BOP-array remains filled with the buffer fluid (preferably pressurized, i.e. at super-atmospheric pressure) and is hermetically sealed by the respective BOPs 5, 6 so that wellbore hydrogen is prevented to escape via the BOP-array into ambient air.
After the latter step, i.e. after the widened section TJ of the string T has passed the upper BOP 7, that BOP 7 can be closed again and the above steps can be repeated (e.g. starting with a chambers pressurization step) for safely passing a subsequent widened string section from the wellbore 1 (or respective wellhead 2) upwardly into ambient air.
It will be appreciated by the skilled person that the above-steps can be carried out substantially in a reverse order in case a widened section TJ of the string T is to be passed from ambient air downwardly into the wellbore 1. It is preferred that any time during system operation, when the lower BOP 5 is in a respective release state (providing a fluid communication between the lower chamber 1 and the hydrogen filled wellbore 1), each of the other two BOPs 6, 7 is in a closed state (sealingly, gas-tightly engaging the string T) to provide a hermetically sealed second chamber P2 (above the first chamber) that is entirely filled with the inert buffer fluid.
It is thus believed that operation and construction will be apparent from the foregoing description and drawings appended thereto. It will be clear to the skilled person that the invention is not limited to any embodiment herein described and that modifications are possible which may be considered within the scope of the appended claims. Also kinematic inversions are considered inherently disclosed and can be within the scope of the invention.
In the claims, any reference signs shall not be construed as limiting the claim. The terms 'comprising' and `including' when used in this description or the appended claims should not, unless context requires otherwise, be construed in an exclusive or exhaustive sense but rather in an inclusive sense. Thus expression as 'including' or 'comprising' as used herein does not, unless context requires otherwise, exclude the presence of other elements, additional structure or additional acts or steps in addition to those listed. Furthermore, the words 'a' and 'an' shall not be construed as limited to 'only one', but instead are used to mean `at least one', and do not exclude a plurality. Features that are not specifically or explicitly described or claimed may additionally be included in the structure of the invention without departing from its scope. Expressions such as: "means for ..." should be read as: "component configured for ..." or "member constructed to ..." and should be construed to include equivalents for the structures disclosed.
The use of expressions like: "critical", "preferred", "especially preferred" etc. is not intended to limit the invention. Additions, deletions, and modifications within the purview of the skilled person may generally be made without departing from the scope of the invention, as determined by the claims.
For example, the workover system can be configured to fill and pressurize each of the two parts/chambers P1, P2 of the string passage with buffer fluid at the same time (e.g. during a single pressurization period) or at different times (e.g. during different respective pressurization periods), or partly at the same time and partly at different times, as will be clear to the skilled person. Thus, the pressurization step of filling and pressurizing both of the string passage parts (P1, P2) with buffer fluid can include a single step, or for example be provided at least partly by at least two (sub)steps.

Claims

A workover system for receiving and/or installing a tubular string from/to a wellbore pressurized by hydrogen, the system including:
- at least three BOPs (5, 6, 7) defining at least a first part (P 1) and a second part (P2) of a string passage there-between, each BOP (5, 6, 7) being configured to sealingly engage an outer surface of a tubular string (T) when the BOP (5, 6, 7) is in a sealing state and to disengage the outer surface of the tubular string (T) when the BOP is in a releasing ; and

- a pressure conditioning system (11, 12, 13, 14, 21, 22) configured to fill each of the first and second part (P1, P2) of the string passage with a buffer fluid.
The system according to claim 1, wherein the pressure conditioning system (11, 12, 13, 14, 21, 22) is configured to entirely fill and pressurize each of the first and second part (P1, P2) of the string passage with the buffer fluid when each of the three BOPs is in a respective sealing state.
The system according to claim 1 or 2, wherein the pressure conditioning system (11, 12, 13, 14, 21, 22) is configured to pressurize the first part (P1) and/or the second part (P1) of the string passage, and preferably both the first part (P1) and the second part (P2), with the buffer fluid to substantially the same pressure as a wellbore pressure or to a pressure higher than the wellbore pressure.
The system according to any of the preceding claims, wherein the pressure conditioning system (11, 12, 13, 14, 21, 22) is configured to pressurize the second part (P2) of the string passage with the buffer fluid to substantially the same pressure as a wellbore pressure or to a pressure higher than the wellbore pressure when a first BOP (5) of the three BOPs is in a releasing state and an intermediate second BOP (6) and a third BOP (7) of the three BOPs are in respective sealing states.
The system according to any of the preceding claims, wherein the pressure conditioning system (11, 12, 13, 14, 21, 22) is also configured to depressurize the first part (P1) and/or the second part (P2) of the string passage, e.g. to a pressure that is at most about 5% of a wellbore pressure, preferably atmospheric, when all three BOPs (5, 6, 7) are in respective sealing states.
The system according to any of the preceding claims, wherein the pressure conditioning system includes a fluid supply system (11, 12) for feeding buffer fluid to each of the first part (P 1) and to the second part (P2) of the string passage, and a fluid discharge system (21, 22) to discharge fluid from each of the first part (P 1) and the second part (P2) of the string passage.
The system according to any one of the preceding claims, including a control unit (CU) communicatively connected to the BOPs and to the pressure conditioning system, for controlling operation thereof.
The system according to claim 7, wherein the control unit (CU) is configured to be operated by a human controller.
The system according to claim 7 or 8, wherein the pressure conditioning system includes a pressure sensor (10) for detecting or measuring a wellbore pressure, the control unit (CU) being configured to control pressure conditioning based on a sensor signal of the pressure sensor (10).
The system according to any of claims 7-9, wherein the control unit (CU) is configured to provide at least one pressurization step wherein the pressure conditioning system is controlled to pressurize at least part of the string passage between at least two of the three BOPs, for example from atmospheric pressure to wellbore pressure, by feeding the buffer fluid to that part of the string passage, in particular when the at least two of the three BOPs are controlled to be in respective sealing states and sealingly engage a tubular string.
The system according to any of claims 7-10, wherein the control unit (CU) is configured to provide at least one pressure reduction step wherein the pressure conditioning system is controlled to depressurize at least part of the string passage between at least two of the three BOPs by discharging fluid from that part of the string passage, in particular when the at least two of the three BOPs are controlled to be in respective sealing states and sealingly engage a tubular string, the discharging of fluid preferably being such that the pressure in the respective part of the string passage becomes lower than a pressure in the wellbore.
The system according to claims 10 and 11, wherein the control unit (CU) is configured to provide a said pressurization step after a said pressure reduction step.
The system according to any one of the preceding claims, wherein the at least three BOPs include controllable sealing structures, the BOPs further including at least one mounting structure (8, 0) for mounting the sealing structures at mutually spaced-apart positions.
The system according to any of the preceding claims, including an actuating structure (4) configured to engage the tubular string (T) and to draw the tubular string (T) with respect of the string passage, the actuating structure preferably being controllable by a control unit (CU) of the system.
The system according to at least claims 7 and 14, wherein the control unit (CU) is configured to provide a string drawings step that includes:
- bringing one of the three BOPs (5) to its releasing state whilst maintaining the other (6, 7) of the three BOPs in respective sealing states;

- controlling the actuating structure to move a widened section (TJ) of the tubular string (T) along the BOP (5) that is in its releasing state; and

- returning the one of the three BOPs (5) from its releasing state to its sealing state;
wherein the pressure conditioning system is controlled by the control unit (CU) to keep the part (P2) of the string passage between the two BOPs (6, 7) that remain in their sealing states, substantially filled with and pressurized by the buffer fluid.
System including a subsurface reservoir, a wellbore and a tubular string configured to extend through the wellbore, wherein the reservoir includes pressurized hydrogen, wherein the system includes a workover system according to any one of the preceding claims for moving the tubular string through the wellbore.
A method for moving a tubular string through a wellbore, for example utilizing a system according to any one of the preceding claims, wherein the tubular string (T) includes an array of tube sections interconnected by widened tube coupling sections (TJ), wherein the wellbore (1) contains pressurized hydrogen, the method including:
- providing three BOPs (5, 6, 7) defining two subsequent string passage parts (P1, P2) there-between;

- a pressurization step of filling and pressurizing both of the string passage parts (P1, P2) with buffer fluid when each of the three BOPs (5, 6, 7) sealingly engages an outer surface of the tubular string (T);

- adjusting one of the three BOPs to a releasing state allowing passage of a widened section (TJ) of the string (T);

- moving the widened section (TJ) of the tubular string along the BOP that is in its releasing state while the other two BOPs sealingly engage the outer surface of the tubular string (T); and

- adjusting the latter BOP back from its releasing state to a state to sealingly engage the outer surface of the tubular string (T).
The method according to claim 17, wherein both of the string passage parts (P1, P2) are entirely filled with the buffer fluid, and are pressurized to a wellbore pressure or to a pressure above wellbore pressure with the buffer fluid, during the pressurization step.
The method according to claim 17 or 18, including a pressure reduction step wherein fluid is discharged from a part of the string passage that is to receive and/or has received the widened string section (TJ).
The method according to claim 19, including refilling a string passage part with buffer fluid after a pressure reduction step has been carried out on that string passage part.
The method according to claim 20, wherein at least part of the buffer fluid is supplied from the other of the string passage part.
The method according to any one of claims 17-21, wherein the buffer fluid is nitrogen.
The method according to any one of claims 17-21, wherein the buffer fluid is water.
The method according to any one of claims 17-21, wherein the buffer fluid is brine.