Key information

Title: Riserless and rigless permanent plug and abandonment of subsea, surface and platform wells
Application number: 20240822
Case type: National
Status: 25.08.2025 Patent meddelt (B1)
Filed: 09.08.2024
Effective date: 09.08.2024
Publicly available: 25.08.2025
Next annual fee due: 31.08.2027
Applicant: REIN OFFSHORE AS (NO)
Owner: REIN OFFSHORE AS (NO)
Inventor: Helge Lone (NO) et al.
Agent: BRYN AARFLOT AS (NO)
Granted: 25.08.2025
Patent number: 349001
Expiry date: 09.08.2044

Abstract and drawing

Disclaimer: This text has been machine-scanned and may contain errors – please refer to "Publications" for legally binding content.

The present invention relates to a method for riserless and rigless permanent plug and abandonment of subsea, surface and platform wells.

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Date

Date	Doc. No.	Process	Case number	In/Out	Journal description	To/from
02.07.2026	12-01	Saksbehandling	20240822(349001)	UT	PT Varsel om betaling av første årsavgift (3317) (PT20240822)	BRYN AARFLOT AS
28.08.2025	11-01	Saksbehandling	20240822(349001)	UT	PT Registreringsbrev nasjonal patent (15) (PT20240822)
11.06.2025	10-01	Saksbehandling	20240822	UT	Intention to grant	BRYN AARFLOT AS
28.05.2025	09-01	Saksbehandling	20240822	INN	Korrespondanse (Hovedbrev inn)	BRYN AARFLOT AS
21.03.2025	08-05	Saksbehandling	20240822	INN	Response NIPO	BRYN AARFLOT AS
21.03.2025	08-04	Saksbehandling	20240822	INN	145800NO-claims-no	BRYN AARFLOT AS
21.03.2025	08-03	Saksbehandling	20240822	INN	145800NO - amended application - v2 tracked	BRYN AARFLOT AS
21.03.2025	08-02	Saksbehandling	20240822	INN	145800NO - amended application - v2 clean	BRYN AARFLOT AS
21.03.2025	08-01	Saksbehandling	20240822	INN	Korrespondanse (Hovedbrev inn)	BRYN AARFLOT AS
05.03.2025	07-01	Saksbehandling	20240822	UT	Substantive examination	BRYN AARFLOT AS
07.01.2025	06-04	Saksbehandling	20240822	INN	Response NIPO	BRYN AARFLOT AS
07.01.2025	06-03	Saksbehandling	20240822	INN	145800NO - amended application - final - tracked 20205.01	BRYN AARFLOT AS
07.01.2025	06-02	Saksbehandling	20240822	INN	145800NO - amended application - final - clean 20205.01	BRYN AARFLOT AS
07.01.2025	06-01	Saksbehandling	20240822	INN	Korrespondanse (Hovedbrev inn)	BRYN AARFLOT AS
08.11.2024	05-02	Saksbehandling	20240822	UT	PT report 01:24:04
08.11.2024	05-01	Saksbehandling	20240822	UT	Substantive examination	BRYN AARFLOT AS
14.08.2024	04-03	Saksbehandling	20240822	INN	Signed PoA	BRYN AARFLOT AS
14.08.2024	04-02	Saksbehandling	20240822	INN	Signed Declaration	BRYN AARFLOT AS
14.08.2024	04-01	Saksbehandling	20240822	INN	Korrespondanse (Hovedbrev inn)	BRYN AARFLOT AS
09.08.2024	03-01	Saksbehandling	20240822	UT	Formal Examination 1	BRYN AARFLOT AS
09.08.2024	02-01	Saksbehandling	20240822	UT	Informasjon til oppfinner	Asle Rein
09.08.2024	01-03	Saksbehandling	20240822	INN	Rev 31 version drawings riserless permanent plug and abandonment and ct	BRYN AARFLOT AS
09.08.2024	01-02	Saksbehandling	20240822	INN	145800NO application filed	BRYN AARFLOT AS
09.08.2024	01-01	Saksbehandling	20240822	INN	Søknadsskjema Patent	BRYN AARFLOT AS

Description, claims and drawings

Disclaimer: This text has been machine-scanned and may contain errors – please refer to "Publications" for legally binding content.

Description

349001

TECHNICAL FIELD

The present invention relates to plug and abandonment (P&A) of a wellbore which is a critical process in a lifecycle of any well / wellbore. This plug and abandonment 5 method involves securely sealing a well / wellbore that is no longer productive or needed, to ensure that no hydrocarbons and/or other fluids and/or gases can escape into the surrounding environment.

BACKGROUND OF THE INVENTION

The main steps in a plug and abandonment process / method of a wellbore typically comprise the following:

1. Opening a closed-in well, installing a blowout preventer (BOP), running in hole and eventually installing a deep set mechanical plug, punching and perforating the 15 tubing to equalize pressure.

2. Pulling the production tubing including the tubing hanger to the surface.

Setting mechanical plugs, wherein the mechanical plugs are placed at various depths within the wellbore. These plugs act as physical barriers to prevent fluid migration. Commonly used plugs include bridge plugs and/or cement retainers. Establishing a 20 primary barrier above the reservoir and establishing a secondary barrier where maximum anticipated pressure can be withstood. Cementing, wherein the cement is pumped into the wellbore above the mechanical plugs to create a solid and impermeable barrier. Multiple cement plugs might be set at various intervals to ensure complete isolation of different geological formations.

25 3. Verification, wherein the integrity of the plugs and cement barriers is verified through pressure testing and logging tools to ensure that there are no pathways for fluid migration.

4. Removing production equipment.

30 The permanent plugs normally consist of Portland cement, however recently some new techniques and materials have been introduced involving:

- Portland cement with additives,

- Low melting point metal alloys,

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- Thermosetting polymers (resins),

- Unconsolidated sand slurries,

- Geopolymers, and

- Thermic melting of casing, cement and formation.

The objective of the plug and abandonment process is to protect the environment by preventing the escape of hydrocarbons and/or other fluids and/or gases, thus ensuring that the well is safely and permanently abandoned.

10 On some occasions, rigs and risers are often used in the plug and abandonment process of a subsea wellbore, especially in offshore settings.

Drilling or workover rigs, with a drill string capacity, are used to provide a necessary platform and infrastructure for heavy equipment and personnel involved in the plug 15 and abandonment process of wells.

Risers are used on any platform, with e.g. drilling facilities, to connect the wellhead to the rig at the surface. They allow for the elevation and circulation of fluids as well as the deployment of tools and equipment.

Some drawbacks of the known plug and abandonment method of subsea wells are high rigrate and personnel costs, time and energy consumption, operational complexity, weather dependency, etc. Generally, the use of a drilling string in a plug and abandonment process is time consuming due to the need for mantling and 25 dismantling of drill string joints or singles.

Recently, some other alternative methods are being developed and tried in plug and abandonment operations of subsea wells.

30 Light well intervention vessels (LWIVs) can be used to perform some plug and abandonment tasks of subsea wells without any need for a full-scale drilling rig or riser, thus potentially reducing costs, time and energy consumption.

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Riserless and rigless plug and abandonment techniques can be used, wherein a coiled tubing or wireline is deployed from a vessel to offer a more cost-effective and less complex solution for certain plug and abandonment operations.

5 Rigless refers to the absence of a drilling rig and a drill string. Riserless operations refer to subsea activities without the use of a marine riser, which is the conduit connection from the subsea wellhead to the surface facilities, for example a drilling rig or a production platform.

10 US 9,388,653 B2 refers to a method and an apparatus for performing a plug and abandonment operation on a subsea well. A wellhead interface module is located on a wellhead, which accommodates a volume of wellbore fluid in fluid communication with the wellbore. A system control module receives a signal from a sensor in the chamber and is configured to derive volume data relating to a change in volume of 15 wellbore fluid in the chamber and compares the derived volume data with a volume change expected due to the removal of tubing from the wellbore. In embodiments of the invention, this enables a change in wellbore conditions to be characterized, for example a fluid influx or a fluid loss, from the volume data. The method may comprise providing wellbore fluid to the apparatus to replace fluid which enters the 20 wellbore to occupy the volume vacated by the tubing, and/or removing or adding fluid in fluid influx/loss situations respectively.

WO 2017089000 A1 describes an assembly for riserless light well intervention and an associated method for injecting a solidifiable fluid, such as cement, into a well. 25 The assembly is submergible to a subsea location and is connectable to a subsea well for performing an operation on the subsea well before the assembly is retrieved back to a topside location. The assembly comprises: a connection means for connecting the assembly to a bore of the subsea well; pressure control means (PCH) for providing pressure control of the subsea well and the assembly; launch means for 30 launching at least one separating element from within the assembly into the bore of the subsea well; and means for injecting a liquid through the assembly and into the bore of the subsea well.

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Exploring alternative methods that mitigate the above mentioned rig and riser related issues can provide more efficient and cost-effective solutions for any well to be plugged and abandoned, especially subsea wells.

5 SUMMARY OF THE INVENTION

It is an object of the present invention to provide a more operational efficient and cost-effective solution for plug and abandonment.

10 Another object of the invention is to provide a better riserless and rigless plug and abandonment method than the recently used methods.

Yet another object of the invention is to provide a less labor-intensive process and enhanced safety of personnel and environmental protection due to more efficient 15 operations.

Yet another object of the invention is to minimize and/or reduce time and energy consuming in the plug and abandonment process.

20 Yet another object of the invention is to provide increased flexibility and adaptability of the plug and abandonment process.

According to a first aspect of the invention this is achieved with a method for riserless and rigless plug and abandonment of a wellbore.

The present invention concerns a method for riserless and rigless plug and abandonment of a wellbore, the method comprising, in a recommended order, the steps of:

a) placing a pumping unit in close proximity to a wellhead of the wellbore;

30 b) placing a coiled tubing injector stack on top of the wellhead or on top of a Christmas tree on the wellhead if any;

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c) connecting a source on the pumping unit, using a connection comprising a first hose, to a choke valve arranged on the coiled tubing injector stack by using the first hose;

d) connecting the pumping unit to a pit or separator via a first umbilical or hose; 5 e) removing any unnecessary plug on the way down for the coiled tubing string by means of a stroker arranged at the operational end of the coiled tubing string; f) scraping and washing a section of the wellbore to be plugged by means of a scraper having high-pressure nozzles and brushes and using a washing fluid with solvents and anti-freeze agents, dropping a cleaning assembly and possibly a well 10 tractor into the wellbore, and displacing fluid and particles from the wellbore to maintain well integrity;

g) running a coiled tubing string into the wellbore, wherein the coiled tubing string is, for each run-in-hole operation, equipped, at an operational end thereof and depending on the operation to be performed, with at least one of: a stroker

15 configured for removing any unnecessary plug, a passive packer being unset under run-in-hole operation and configured to expand or set when pressure is increased over a predetermined level and/or assemblies comprising at least one perforation gun and/or a milling tool, and a plug;

h) milling and/or perforating the section of the wellbore to be plugged with its 20 adjacent production tubing, other adjacent casing and/or adjacent formation by means of the milling tool and/or the at least one perforation gun respectively;

i) optionally placing at least one packer and/or at least one plug above and/or below the section to be plugged, and/or using any existing packer and/or plug to isolate the section to be plugged;

25 j) pumping barrier materials through the coiled tubing string into the section to be plugged and through perforations and/or milled slots to create a first barrier, wherein the passive packer at the operational end of the coiled tubing string is being activated and opened by the increased pressure and isolates the annular space between the coiled tubing string and the production tubing; and

30 k) pulling out the coiled tubing string with the passive packer.

The connection to the pumping unit can be a Y-connection further comprising a second hose, and the source on the pumping unit can be connected to an annulus

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valve arranged on the possible Christmas tree or on the wellhead’s outlet valves by using the second hose to facilitate circulation to the surface.

The method for riserless and rigless plug and abandonment can further comprise the 5 steps of:

- if a valve cannot be manually operated, placing a hydraulic power unit in close proximity to the wellhead;

- connecting the hydraulic power unit, having at least one tank for control line sealant barrier material, to a wellhead port via an external control line.

The method for riserless and rigless plug and abandonment can further comprise the steps of:

- curing the barrier material of the first barrier; and

- optionally pressure testing the first barrier.

The method for riserless and rigless plug and abandonment can further comprise the step of:

- creating at least one second barrier above the first barrier using all or some of the steps a) - k).

Under step j) the barrier material can be circulated through the annuli, between the production tubing and casing, to the surface from the coiled tubing string placed inside the production tubing and through the created perforations or slots placed below the coiled tubing packer.

The method for riserless and rigless plug and abandonment can further comprise the steps of:

- curing the barrier material of said at least one second barrier; and

- optionally pressure testing said at least one second barrier.

The curing process can be delayed by placing colloidal silica dispersed in a freshwater pill prior to exposing the colloidal silica to seawater or salt brine in the formation and/or the reservoir.

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The method for riserless and rigless plug and abandonment can further comprise the steps of:

- bleeding off all downhole control lines; and

5 - sealing off the downhole control lines.

The method for riserless and rigless plug and abandonment can further comprise the step of:

- pouring cement through the coiled tubing string on top of the wellhead and/or 10 the possible Christmas tree to create a cement dome over them.

The method for riserless and rigless plug and abandonment can be configured for plug and abandonment of a subsea well, wherein a light well intervention vessel and at least one remote operated vehicle, ROV, connected to the vessel and operated by 15 at least one ROV umbilical can be used to perform some of the method steps.

Furthermore, the method for riserless and rigless plug and abandonment can be configured for plug and abandonment of a surface or platform well.

20 Finally, a tracer can be used to track and/or verify the circulation of the barrier material.

The main features of this invention are given in the independent claim. Additional features of the present invention are given in the dependent claims.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other aspects of the invention are apparent from and will be further elucidated, by way of example(s), with reference to the drawings, wherein:

30 Fig. 1 shows documentation of a well and/or nearby wells needed to be investigated by personnel to understand the plug and abandonment tasks.

Fig. 2 shows a process map separated into three main processes comprising: understanding P&A tasks, establishing barriers and verifying barriers.

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Fig. 3 shows a light well intervention vessel equipped for the plug and abandonment process of a wellbore. For onshore and platform wells see figures 57 and 58.

Fig. 4 shows a subsea horizontal Christmas tree and a subsea injection stack through which a coiled tubing string, equipped with a stroker and centralizers, is 5 ready to access the well.

Fig. 5 shows a subsea vertical Christmas tree and a subsea injection stack through which a coiled tubing string has accessed.

Fig. 6 shows a coiled tubing string with a washing train, after cleaning and scraping has been conducted, ready for washing and displacing.

10 Fig. 7-19 show variations of plugs and combinations of downhole assemblies including perforation gun(s), well tractor(s) and milling tool, with or without downhole communication, rigged up to access different annuli from within the production tubing.

Fig. 20-21 show placement of perforations conducted in the production liner, with or 15 without a plug.

Fig. 22-23 show milling of one or two slots of the production tubing.

Fig. 24-29 show one, two or three sets of perforations with or without a plug.

Fig. 30 shows lower perforations conducted in the production liner into the reservoir. Fig. 31 shows a coiled tubing string with a packer, squeezing barrier material through 20 the perforations and into all annuli and upwards in the a-annuli.

Fig. 32 shows a pressure test of the primary barrier across full cross section of the wellbore.

Fig. 33 shows placement of a secondary barrier across full section.

Fig. 34 shows a pressure test of the secondary barrier.

25 Fig. 35-38 show a sequence of placing two permanent barriers across full cross section. A primary permanent barrier is placed in the production liner, above a plug. The primary barrier plug is then extended above the foundation and below the production packer. A secondary permanent barrier is placed across full cross section above a plug adjacent to the intermediate casing shoe.

30 Fig. 39-41 show a coiled tubing string with a packer placed above the perforations into the reservoir. A train of barrier materials and spacers is ready to be squeezed into the reservoir, and the primary permanent barrier is cured in the reservoir.

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Fig. 42-44 show a cured and pressure tested primary barrier and a coiled tubing string with a packer placed above the production packer and above the perforations, made above a plug placed adjacent to the liner hanger packer. A secondary barrier material is squeezed into the formation and across full cross section. A third

5 permanent barrier is squeezed through perforations made above a plug placed adjacent to the intermediate casing shoe.

Fig. 45-46 show a cured and pressure tested permanent primary barrier in the production liner. The coiled tubing string with the packer is placed adjacent to the surface casing shoe, between two sets of perforations. When a secondary barrier 10 material is squeezed through the perforations, circulation in the a-annuli is achieved, verified by use of a tracer and/or a sensor.

Fig. 47 shows a cured and pressure tested permanent primary barrier in the production liner, a plug set adjacent to the production packer, with deep perforations just above the intermediate casing shoe, and a slot being milled in the surface casing 15 section, with the aim of obtaining circulation.

Fig. 48 shows a coiled tubing string with a packer placed adjacent to the surface casing shoe, squeezing barrier material across full cross section, and achieving circulation to the surface through the a-annuli.

Fig. 49 shows a cured and pressure tested permanent primary barrier in the

20 production liner. A plug set adjacent to the production packer. A slot is being milled in the production tubing, in the intermediate casing section.

Fig. 50-52 show a cured and pressure tested permanent primary barrier in the production liner. A plug set adjacent to the production packer, with the coiled tubing string with the packer, placed above the slot, squeezing barrier material with the plug 25 and production packer as foundation, achieving circulation through the a-annuli to the surface and hence a permanent secondary barrier.

Fig. 53-54 show a cured and pressure tested permanent primary barrier in the production liner. The coiled tubing string with the packer is placed between a milled slot and the perforations into the a-annuli, and squeezing barrier material with the 30 plug and production packer as foundation, achieving circulation to the surface.

Circulation can be verified by use of a tracer.

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Fig. 55 shows the well with a primary barrier into the reservoir, a secondary barrier above a plug in the production liner and a complete permanent sealing across full cross section, and circulation to the surface.

Fig. 56 shows the coiled tubing string and equipment installed on the vessel and the 5 well with a primary barrier into the reservoir and a cured complete permanent sealing across full cross section both radially and vertically, including sealing of all bores in the subsea tree. The control lines have been bled off before being sealed permanently.

Fig. 57 shows the coiled tubing string and equipment installed on a land well

10 onshore, with a cured and pressure tested permanent primary barrier squeezed into the reservoir. A secondary barrier is placed above a plug adjacent to the liner hanger packer cured and pressure tested. The coiled tubing string with the packer squeezes barrier material for a third barrier achieving circulation to the surface through the aannuli.

15 Fig. 58 shows the coiled tubing string and equipment installed on an offshore platform, with a cured and pressure tested permanent primary barrier squeezed into the reservoir. A secondary barrier is placed above a plug adjacent to the liner hanger packer cured and pressure tested. The coiled tubing string with the packer squeezes barrier material for a third barrier achieving circulation to the surface through the a-20 annuli.

Fig. 59 shows a permanently plugged and abandoned well, with the primary barrier into the reservoir, cured and pressure tested, and the secondary barrier and third cured permanent sealing across full cross section both radially and vertically, obtained through circulation, including all bores in the Christmas tree. The control 25 lines are being bled off, before being sealed permanently.

Figure 60 shows a permanent plugged and abandoned well with a cement dome covering the entire subsea structure.

DETAILED DESCRIPTION OF THE EMBODIMENTS

Figure 1 shows documentation (1) of a well to be permanently plugged and experiences from nearby wells, which is needed to be investigated by personnel (2) to understand the plug and abandonment tasks. Figure 1 also shows rooms with

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personnel (2) needed for team alignment and training as the permanent plugging operation, especially when conducted from a light vessel (6), is a rather complex process with a series of operations. On the right side of the figure there is a comparison of a P&A process using a rig (3) or a derrick (25) and a P&A process 5 using a light vessel (6) and/or a coiled tubing (12) with regard to cost (4) and time (5) needed for permanent plugging of a well. It is clear that the P&A process using the drilling rig (3) or the derrick (25) is much more expensive and time consuming than the P&A process using the light vessel (6) and/or the coiled tubing (12).

10 Figure 2 shows a process map of a permanent plug and abandonment method separated into three main processes, comprising: understanding P&A tasks, establishing barriers and verifying barriers. As the process of permanent plug and abandonment, PP&A, from a light vessel is new, and as this PP&A process requires multi-skilled personnel, early involvement and training is paramount. Continual 15 improvement in the planning and execution is required. All main and necessary steps are shown and described on figure 2.

This P&A process shall be done according to requirements defined by relevant authorities.

Figure 3 shows a light well intervention vessel (6) equipped with at least one remote operated vehicle, ROV, (19, 20), a coiled tubing (8-9, 11-13), a remote operated vehicle control unit (18), barrier materials (85a-85e), a mixer (65) and a stirrer (66), a pump (69), a pit or separator (26), chemicals and freshwater (61a-61e) and a cement 25 laboratory (17b) with a (e.g. subsea) hydraulic power unit (17a) including a pressurized sealing material (93a), a low-pressure tank (93c) for bleeding off control lines and a downhole pump (93b) for sealing control lines with sealant material (101) and a subsea pumping unit (16b) with a desired pumping capacity, which are being placed on a seabed by a crane (98) on the vessel (6). The vessel (6) can be further 30 equipped with a mid-ship derrick (25) to ease mounting of bottomhole assemblies (68).

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When the plug and abandonment operation starts, the well is closed in with a subsea Christmas tree, XMT, (94), wherein a horizontal Christmas tree (28) is presented on the drawing. A downhole safety valve (39a) is in a closed position with fluid in the production tubing (42). If the well has been temporary abandoned, a temporary or 5 cement plug (53) has been set with fluid (109) above.

This plug and abandonment method (shown on figure 2) is executed entirely from a light intervention vessel (6) through the subsea Christmas tree (94) and from inside the production tubing (42), using a coiled tubing string (12) with tools and downhole 10 assemblies (68).

Planning also consists of deciding how to operate the downhole valve (39a) and valves (34a-34c, 36, 37a-37c) on the subsea XMT (94) and how to seal off other downhole control lines (52).

Hydraulic pressure can be supplied from the hydraulic power unit (17a) placed on the seabed (49) and connected to a wellhead outlet port (29) and to the surface through an umbilical (15) running to a control cabin (10) on the vessel (6). All downhole control lines (52) must be tested and finally sealed off.

Coiled tubing with downhole communication (figures 10,16-23, 25-30) is preferably used to enable independent operation of more than one tool in the downhole assembly (68).

25 The at least one remote operated vehicle (19, 20) is connected to the remote vehicle control unit (18) on the vessel (6) and is further connected and operated by at least one umbilical (21, 22).

One of the at least one remote operated vehicle (19) can be used for removing a 30 debris cap (27) from the subsea horizontal Christmas tree (28), and the hydraulic power unit (17a), with a tool (93) for bleeding off and sealing off control lines, a pump (93b) with pressurized sealant material (93a) and a low-pressure tank (93c) for bleeding off pressure, is connected to the downhole safety valve (39a) through a

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control line (16a, 52). The subsea pumping unit (16b), with a Y-connection with functionality to select one or two sources (105), is connected to an annulus isolation valve (37a) through a hose (104) and to the vessel (6) through an umbilical (14) connected to a pit or separator (26) from the control cabin (10).

On figure 4, the remote operated vehicle (19), operated from the ROV control unit (18), has removed the debris cap (27) from the subsea (horizontal) Christmas tree (28, 94). A subsea coiled tubing injector stack (58a) is placed on top of the horizontal Christmas tree (28) using a Christmas tree adapter (82). The stack has choke and kill 10 valves (58b-58c), rams (58e, 58g) and multiple shear rams (58f) and a coiled tubing injector head (58d). The high-pressure unit (16b) with pumping capacity is connected to a choke valve (58c) on the injector stack (58a) and is also connected to the annulus isolation valve (37a) on the subsea tree (94). The purpose of the subsea pumping unit (16b) is pumping displaced fluid through a hose (14) to the pit or 15 separator (26) on the surface and providing for full circulation of barrier material (86) to the surface.

On the left side of the stack on figure 4, a choke line umbilical (55a) running to the surface to the pit or separator (26) via the control cabin (10), is connected to a choke 20 valve (58c), and a hose (108) is connected to the Y-connection, with functionality to select one or two sources (105), for example an annulus isolation valve (37a) (via the hose (104) and/or the choke line (58c) on the subsea pumping unit (16b). On the right side on figure 4 there is a kill-line umbilical (55b) connected to one or two valves (58b) running to the surface via the control cabin (10).

The vessel (6) is fully stacked with a selection of washing train components (61a-e, 65), barrier materials (85a-86), a mixer and stirrer (65, 66), solvents and anti-freeze (95b), a cement laboratory (17b), optionally a derrick (25), a coiled tubing equipment (8, 9, 10, 11, 12, 13, 69), including a coiled tubing pump unit (69) and a crane (98). 30

A coiled tubing string (12), prepared on the vessel, is used to run in hole by removing upper (30) and lower (31) crown plugs. The run-in-hole process is done with a coiled tubing string (12) equipped with centralizer(s) (106) and a stroker (107) to remove the 349001

upper crown plug (30). The coiled tubing string (12) connects to the upper crown plug (30), releases and pulls it out of hole. Then the coiled tubing string (12) is run in hole to remove the lower crown plug (31), to release and pull it out of hole. In this way any retrievable plug (64a) in the well (79) can be replaced or pulled to the surface.

The hydraulic power unit (17a) contains a tank (93c) for pressurized sealant material (93a), e.g. a mixture of glue and silicon (101), and a downhole pump (93b) to seal off the control lines after these have been bled off to the low-pressure tank (93c).

10 On figure 5, a high-pressure cap (38) is removed from a vertical Christmas tree (78) by one of the at least one remote operated vehicle (20). The subsea coiled tubing injector stack (58a) is placed on the vertical Christmas tree (78), and the coiled tubing string (12) is in the well (79). The production valves (34a-34c) are operated by one of the at least one remote operated vehicle (19), either through the wellhead port 15 arrangement (29) or through a manifold. The production valves (34a-34c) are being opened before the operation starts.

On the left side of the stack on figure 5, the choke line umbilical (55a) running to the surface is connected to the choke valve (58c), and the hose (108) is connected to the 20 Y-connection, with functionality to select a source (105) on the subsea pumping unit (16b). On the right side on figure 5, the kill-line umbilical (55b) is connected to one or two valves (58b) running to the surface.

Figure 6 shows the first run (#1) downhole with a washing train (56) and a cleaning 25 assembly (95a, 96), and a throughtubing well tractor (75a), which may be required.

On the way down a scraper (95a) with high-pressure nozzles and brushes of the cleaning assembly (95a, 96) is drifting and cleaning inside the production tubing (42), with solvents and anti-freeze agents (95b), focusing on the areas to be sealed off to secure adhesion of the barrier material. When entering a planned depth, the cleaning 30 assembly (95a, 96) and the throughtubing well tractor (75a) have the option of being dropped by ball drop release.

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When using the cleaning and scraper tool (95a, 96) with solvents and anti-freeze agents (95b), the throughtubing well tractor (75a) can be used to avoid buckling of the coiled tubing string (12) under each run-in-hole operation.

5 Figure 6 shows also the washing train (56) being lined up and ready to be pumped.

An example of the washing train (56) composition is constituted of: at least two spacers (61a, 61b), a washing pill (61c) arranged between the spacers (61a, 61b), and seawater (61d) or salt brine (100).

With full flow capacity in the coiled tubing string (12), displacing of heavy fluid (109) is started and cleaning fluid (95b) is used and pumped (69) down through the washing train (56), and the heavy fluid (109), separated by a spacer (61a), is forced up, through the coiled tubing subsea injector stack outlet valve (58c) and/or the annulus 15 valve (37a) on the subsea tree (94), to the pit or separator (26) on the vessel (6) assisted by the subsea pumping unit (16b) through the Y-connection (105).

The purpose is to displace the heavy fluid (109) and the used washing fluid (61c) with seawater (61d) or brine (100), depending on the well conditions (the well integrity), 20 and to secure adhesion for the barrier material (86) inside the production tubing (42).

Figure 7 shows a plug (63a), which is not set, inside the production tubing (42), with production and intermediate casing (44a, 45a) strings and associated cement (44b, 45b).

Figure 8 shows a plug (64a), which is now set, inside the production tubing (42), with the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b).

30 Figure 9 shows a cement plug (53), inside the production tubing (42), with the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b).

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Figure 10 shows a plug (63b), which is not set, but which is run, on a coiled tubing string (12) with perforation guns (62a) above, inside the production tubing (42), with the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b). A perforation gun (62a) and a plug release mechanism are being

5 operated through a control line (91b) connected to the control cabin (10) on the surface.

Figure 11 shows a plug (64a). The perforation gun (62a) is run on the coiled tubing string (12) above the plug (64a), inside the production tubing (42), with the production 10 and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b).

Figure 12 shows the plug (64a), wherein the perforation gun (62b) has been fired, above the plug (64a), inside the production tubing (42), with the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b), which 15 has been perforated (88) now.

Figure 13 shows the cement plug (53). The perforation gun (62b) has been fired above. The perforation gun (62b) is run on the coiled tubing string (12), and the perforations are made through the production tubing (42), the production and

20 intermediate casing (44a, 45a) strings and the associated cement (44b, 45b).

Figure 14 shows a plug (64a), which is set, with perforations through the production tubing (42), the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b).

Figure 15 shows a plug (63b), which is not set, but is connected below a well tractor (75), inside the production tubing (42), with the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b). The well tractor (75) is operated through the control line (91b) connected to the surface.

Figure 16 shows a plug with a release mechanism (63b) electronically operated, which is not set, but is connected to the perforation gun (62a) and the well tractor (75), inside the production tubing (42), with the production and intermediate casing

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(44a, 45a) strings and the associated cement (44b, 45b). The well tractor (75) and the plug release mechanism (63b) and the perforation gun (62a) are operated through the control line (91b) connected to the control cabin (10) on the surface.

5 Figure 17 shows a plug with a release mechanism (63b) electronically operated, which is not set, but is connected to two perforation guns (62a) and the well tractor (75), inside the production tubing (42), with the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b). The well tractor (75) and the plug release mechanism (63b) and the two perforation guns (62a) are operated 10 through the control line (91b) connected to the surface control cabin (10).

Figure 18 shows a plug with a release mechanism (63b) electronically operated, which is not set, but is connected to the perforation gun (62a) and two well tractors (75), inside the production tubing (42), with the production and intermediate casing 15 (44a, 45a) strings and the associated cement (44b, 45b). The well tractors (75) and the plug release mechanism (63b) and the perforation gun (62a) are operated through the control line (91b) connected to the surface control cabin (10).

Figure 19 shows a plug with a release mechanism (63b) electronically operated, 20 which is not set, but is connected to two perforation guns (62a) and two well tractors (75), inside the production tubing (42), with the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b). The well tractors (75) and the plug release mechanism (63b) and the perforation guns (62a) are operated through the control line (91b) connected to the surface control cabin (10).

Figure 20 shows a plug with a release mechanism (63b) electronically operated, which is not set, connected to two perforation guns (62a) and two well tractors (75), inside the production tubing (42), below the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b). The well tractors (75) and the 30 plug release mechanism (63b) and the perforation guns (62a) are operated through the control line (91b) connected to the surface.

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Figure 21 shows two perforation guns (62a) and two well tractors (75), inside the production tubing (42), below the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b).

5 Figure 22 shows a milling tool (102) at the end of the coiled tubing string (12) and/or the well tractor (75), with a short section of the production tubing (42) being milled (103), inside the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b).

10 Figure 23 shows the milling tool (102) at the end of the coiled tubing string (12) and/or the well tractor (75), with a short section of the production tubing (42) being milled (103), above a lower and previously milled section (103), inside the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b).

15 Figure 24 shows one perforation gun (62b, 88), which perforates the production tubing (42), the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b).

Figure 25 shows two perforation guns (62b, 88), which perforate the production 20 tubing (42), the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b).

Figure 26 shows three perforation guns (62b, 88), which perforate the production tubing (42), the production and intermediate casing (44a, 45a) strings and the 25 associated cement (44b, 45b).

Figure 27 shows a plug with a release mechanism (64a) electronically operated, which is set and is connected to the perforation gun (62b, 88), which perforates the production tubing (42), the production and intermediate casing (44a, 45a) strings and 30 the associated cement (44b, 45b). The perforation gun (62b, 88) and the plug (64a) are operated through the control line (91b) connected to the surface.

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Figure 28 shows a plug with a release mechanism (64a) electronically operated, which is set and is connected to two perforation guns (62b, 88), which perforate the production tubing string (42), the production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b). The perforation guns (62b, 88) and the 5 plug (64a) are operated through the control line (91b) connected to the surface.

Figure 29 shows a plug with a release mechanism (64a) electronically operated, which is set and is connected to three perforation guns (62a, 88, 89):

- an upper perforation gun (89) placed inside the production tubing (42), the 10 production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b),

- a middle perforation gun (88) placed inside the production tubing (42), the production casing string (44a) and the associated cement (44b), and

- a lower perforation gun (88) placed inside the production tubing (42).

15 The perforation guns (62a, 88, 89) and the plug (64a) are operated through the control line (91b) connected to the surface.

Figure 30 shows three perforation guns (62a, 88, 89):

- an upper perforation gun (89) placed inside the production tubing (42), the 20 production and intermediate casing (44a, 45a) strings and the associated cement (44b, 45b),

- a middle perforation gun (88) placed inside the production tubing (42), the production casing string (44a) and the associated cement (44b), and

- a lower perforation gun (88) placed inside the production tubing (42).

25 The perforation guns (62a, 88, 89) are operated through the control line (91b) connected to the surface.

Figure 31 shows the coiled tubing string (12) placed above the perforations (88), which is above a production packer (40) and a plug (64a, 71) placed adjacent. A 30 coiled tubing packer (60a) is being closed / set, and the plug (64a, 71) and the production packer (40) serve as a lower foundation for the barrier material (86). A certain amount of barrier material volume, according to some calculations, is being filled, then pull out of hole operation is executed with the coiled tubing string (12).

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Then we should wait a certain period of time for the barrier material to cure, and then a pressure test should be conducted from above to verify the integrity of the primary barrier.

5 Figure 32 shows the primary barrier being pressure tested from above, conducted from the surface through the coiled tubing string (12) using the subsea injector stack (58d) with closed pipe ram (58e), with built in pressure and temperature sensors (112) as barrier. The at least one remote operated vehicle (19) is placed above the subsea stack (58d) to observe any leakage.

Figure 33 shows the coiled tubing string (12), with the closed / set packer (60a), where barrier material (86) is being squeezed for providing a secondary barrier through perforations (88) into the production tubing (42), the a-annuli (89) and the formation (48). The plug (64a) and/or the primary barrier serve as a foundation to the 15 secondary barrier.

Figure 34 shows the primary and secondary barriers being pressure tested and verified.

20 Figure 35 shows the coiled tubing string (12), with the closed / set packer (60a), where the barrier material (86) is being filled for providing a primary barrier through the perforations (88) into the production tubing (42) and the a-annuli (89). The plug (64a, 71) serves as a foundation for the barrier within the production tubing (42). Perforations (88) through entire section are made above. The coiled tubing packer 25 (60a) is released, and the coiled tubing string (12) is lifted up to avoid being embedded in the barrier material (86).

Figure 36 shows the coiled tubing string (12), with the closed packer (60a), placed adjacent to the production packer (40), squeezing barrier material (86) to extend the 30 barrier after the lower section barrier material (86) has cured. The barrier material (86) for the primary barrier is filled through the perforations (88) into the production tubing (42), the a-annuli (89) and the formation (48). The closed volume below the production packer (40) and the coiled tubing string (12) with expanded / set packer

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(60a) and above the cured and pressure tested lower primary barrier (87a) and the production liner packer (41) allow pressure to be increased, forcing the barrier material (86) into all annuli (99) and the formation (48). The lower cured section serves as a foundation for the barrier within the production tubing (42).

Figure 37 shows the primary barrier (87b) below the production packer (40) cured, pressure tested and verified.

Figure 38 shows the coiled tubing string (12), with the set packer (60a), being placed 10 above deep perforations (88), inside the lower section surface casing (46a), squeezing barrier material (86) into all annuli (99). The plug (64a) and the production packer (40) serve as a foundation for the secondary barrier material (86).

Figure 39 shows the well with no deep set plugs, with a coiled tubing string (12), with 15 an unset packer (60b), placed above the reservoir (50), which has been perforated (90).

Figure 40 shows the coiled tubing string (12) with the set packer (60a) and a fluid train inside, from below consisting of:

20 - seawater (61d),

- a spacer (61a),

- barrier material #1 (85a), which can be colloidal silica dispersed in freshwater pill (85a1)

- a spacer (61a), and

25 - seawater (61d) or salt brine (100).

The purpose of using the barrier material #1 (85a), which can be colloidal silica dispersed in freshwater pill (85a1), is as explained below:

- The curing time of the barrier material (85a1) is being delayed by the freshwater.

30 - Natrium chloride is a curing agent for the barrier material (85a1).

- The grain size of the barrier material (85a1) is customized to match that of the reservoir and the formation, thus allowing it to penetrate micro-annuli. When

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the grain size in the receiving part matches the barrier material's grain size, this ensures proper binding, maximum surface contact and adhesion.

Moreover, the best suited barrier material (86) shall be used.

5 Figure 40 also shows the coiled tubing string (12) with the packer (60a) expanded or closed, placed above the perforated (90) reservoir (50), with the aim of squeezing (111) the barrier material (86) through the perforations (90) into the reservoir (50).

Figure 41 shows the coiled tubing string (12), with the unset packer (60b), being lifted 10 above the barrier material (86) to avoid being embedded. Then a pressure test is conducted across full cross section to verify the integrity of the primary barrier material (86) that is squeezed (111) into the reservoir (50) after curing of the lower primary barrier.

15 For wells (79) without lifting capacity the primary barrier can be placed through the perforations (90) directly into the reservoir (50, 111).

Figure 42 shows a pressure test across full cross section and a verified barrier into the reservoir (50). The coiled tubing string (12), with the unset packer (60b), being 20 placed above the deep perforations (88), through the production tubing (42) and the production casing and cement (44a, 44b), and the barrier material (86) being squeezed (111) into the reservoir (50), and a plug (64a) below the perforations (88) for the secondary barrier.

25 Figure 43, as described in figure 36, shows the coiled tubing string (12), with the set or expanded packer (60a), being placed above perforations (88), and a plug (64a) placed below the perforations (88). Then the barrier material (86) is being squeezed into the production tubing (42) and the production casing (44a) and the associated cement (44b) and into the formation (48) across full cross section. A liner hanger 30 packer (41) and a plug (64a) serve as a lower foundation for the barrier material (86).

The packer on the coiled tubing string (60a) and the production packer (40) serve as upper barriers and allow for pressure to be increased. The coiled tubing packer (60a) 349001

is released and pulled out of hole with the coiled tubing string (12) to avoid being embedded pending pressure test of secondary barrier.

Figure 44 shows the primary and secondary barriers are now tested and verified. On 5 the previous run the coiled tubing string (12), equipped with a plug (64a) and possibly a perforation gun, placed the plug (64a) inside the production tubing (42) adjacent to an intermediate cashing shoe (47), before perforating (88) the production tubing (42), the production casing (44a), the associated cement (44b), the intermediate casing (45a), the associated cement (45b) into the formation (48). The plug (64a) and the 10 production packer (40) serve as a lower foundation to the barrier material (86). The barrier material (86) is being squeezed into the formation (48) and the micro-annuli (99). When the barrier material (86) has been pumped and squeezed according to calculated volumes, the coiled tubing packer (60b) is released and pulled out of hole with the coiled tubing string (12) to avoid being embedded in the barrier material (86).

15 Then we have to wait for the barrier material (86) to cure and should prepare for the pressure test.

Figure 45 shows the primary barrier, across full cross section, given approved cement bond log of production liner cement, pressure tested and verified. A plug 20 (64a) is placed above the production packer (40). Above the intermediate casing shoe (47) deep perforations (88) have been shot, and perforations (89) into aannulus (92) are made 50-100 meters above the plug (64a) and above the deep perforations (88). The coiled tubing string (12), equipped with a control line (91b) and a tracer sensor (91a), is placed between the deep perforations (88) and the

25 perforations (89) into the a-annuli (92) with the aim of achieving circulation into aannulus. Circulation can be verified by use of barrier material with tracer (85f).

Figure 46 shows a circulation in the a-annuli possibly verified by a tracer, the coiled tubing string (12) with an expanded packer (60a) being placed in between the deep 30 (88) and shallow (89, 92) perforations. Circulation is achieved by pumping from above against the lower plug (64a) and the production packer (40). When pressure is applied, the barrier material (85f) will rise in the a-annuli (99) and will gradually fill up to the shallow perforations (92) and poor down inside the production tubing (42). If

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the barrier material (86) contains radioactive tracer material (85f), the circulation can be verified by a sensor (91a) placed above the coiled tubing packer (60a) and connected to a control line (91b). Then the coiled tubing packer (60b) is released and pulled out of hole with the coiled tubing string (12), waiting for barrier material (85f) to 5 be cured and pressure tested to verify the barrier integrity.

Figure 47 shows the primary barrier, across full cross section, pressure tested and verified. A plug (64a) is placed above the production packer (40). Above the intermediate casing shoe (47) deep perforations (88) have been shot, and a section 10 of the production tubing (42) has been milled (103), using a milling tool (102) on a coiled tubing string (12), 50-100 meters above the plug (64a) and above the deep perforations (88).

Figure 48 shows that the coiled tubing string (12) is placed just below the surface 15 casing shoe (47), pumping barrier material (86) with the plug (64a) and production packer (40) serving as a foundation. The barrier material (86) will fill through the deep perforations (88) and rise in the a-annuli (110b). The pressure and the viscosity of the barrier material (86) will contribute to forcing the fluid upwards in annuli providing for circulation, facilitated by the coiled tubing pump (69) and the Y-connection (105) 20 and the pump (16b) placed adjacent to the wellhead (51). Through continued pumping the circulation in the a-annuli can be verified on the surface.

Figure 49 shows the primary barrier, across full cross section, given approved cement bond log of the production liner cement, pressure tested and verified. A plug 25 (64a) is placed above the production packer (40). A section of the production tubing (42) above the plug (64a) is milled (103) or perforated (89) into a-annulus only.

Figures 50, 51 and 52 show the primary barrier, pressure tested and verified. A secondary plug (64a) is placed above the production packer (40). A section of the 30 production tubing (42) above the plug (64a) is milled (103) or perforated into the aannulus (89) only. The coiled tubing string (12) with the packer (60a, 60b) is placed above the milled (103) or perforated section (89), and pumping of the barrier material (86) is being performed. The plug (64a) and the production packer (40) serve as a

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foundation for the barrier material (86). As pressure is applied, the barrier material (86) will fill the a-annuli (110b) and rise up, and thus will enable circulation, particularly through the a-annuli (110b) to the surface, facilitated by the coiled tubing pump (69) and the Y-connection (105) and the pump (16b) placed adjacent to the 5 wellhead (51).

Figure 53 shows the cured, pressure tested and verified primary barrier (87b) in the production liner. A plug (64a) is placed adjacent to the production packer (40). A section of the production tubing (42) above the plug (64a) is milled (103) or

10 perforated (89). At least 50-100 meters above perforations are made into a-annuli (89), the coiled tubing string (12) with packer (60b) is placed between the milled section and the perforations, squeezing barrier material (86) and achieving circulation in a-annulus (99) possibly verified by tracer (85f). This P&A method is possible due to previously conducted and verified cement bond log.

Figures 54 and 55 show the coiled tubing string (12) with the expanded packer (60a), placed between the upper perforations (89) and the milled section (103), equipped with sensors for tracer, pressure and temperature (91a), and the communication link (91b) to the surface. Pumping of the barrier material (85f) through the coiled tubing 20 string (12) is being performed. The production packer (40) and the plug (64a) serve as a foundation for the barrier material (85f). As pressure is applied the barrier material (85f) will fill and rise up in the a-annuli (99). When a tracer (91a) on the coiled tubing string (12) detects the barrier material (85f), circulation is confirmed. When pumping of the barrier material (85f) is continued, circulation to the surface 25 (110) is enabled, through the a-annuli (99) and artificial annuli created between the coiled tubing string (12) and the inside of the production tubing (42), through the subsea tree (94), the annulus isolation valve (37a) and/or the subsea injection stack (58a), the choke line entry port valves (58c) and subsea pumping unit (16b) to the pit or separator (26) on the vessel (6), facilitated by the coiled tubing pump (69) and the 30 Y-connection (105) and the pump (16b) placed adjacent to the wellhead (51).

Figure 56 shows the light well intervention vessel (6) and the well (79) with the primary and secondary barriers, across the full cross section, pressure tested and

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verified (87b), the primary barrier material (86) has been squeezed (111) into the reservoir (50), and the secondary barrier being approved by cement (44b, 45b, 46b) logging verification. The upper (third) barrier is verified through circulation of the barrier material (86) to the surface (110). The circulation is achieved by pumping (69) 5 the barrier material (86) through the coiled tubing string (12) with the coiled tubing packers set (60a) to ensure downwards flow in the production tubing (42). Circulation in the a-annuli (99) and through the deep perforations into the formation (88) is enabled through previously made perforations (88, 92) and the milled (103) or perforated (88) section of the production tubing (42). Return is taken through the 10 artificially made annuli (99) outside the coiled tubing string (12) and through the aannuli (99) back to the vessel (6) through the choke valve (58c) and/or the annulus isolation valve (37a) and/or crossover valve (36), and/or the wellhead outlets ports (29), and the hoses (104, 108), to the Y-connection (105), and the subsea pumping unit (16b) is supporting the surface coiled tubing pump (69), to obtain circulation 15 through the annuli (99) and to the pit or separator (26). The figure shows also a closed slip ram (58e) against the coiled tubing string (12) to avoid filling the entire volume in the injection stack (58a), and to force return through choke line entry valves (58c). The reference sample of the barrier material (86) in the cement laboratory (17b) will indicate curing process. The coiled tubing string (12) is being 20 pulled out of hole to avoid being embedded.

Said one or two remote operated vehicles (19, 20), steered from the ROV control unit (18) through the respective umbilical (21, 22), are present in the sea.

25 The vessel (6) is fully stacked with a selection of washing train components (61a-e, 65), barrier materials (85a-86), a mixer and stirrer (65, 66), solvents and anti-freeze (95b), a cement laboratory (17b), optionally a derrick (25), a coiled tubing equipment (8, 9, 10, 11, 12, 13, 69), including a coiled tubing pump unit (69) and a crane (98).

30 Figure 57 shows a coiled tubing assembly placed on land (onshore). The primary and secondary barriers are now tested and verified (87b). The third barrier is set by pumping the barrier material (86) through the perforations (88, 92) and thus obtaining circulation to the surface. The figure also shows that circulation to the surface,

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particularly through the a-annuli (110b), and not through the artificially made annuli outside the coiled tubing string (12), which is sealed off by the coiled tubing packer (60a). The plug (64a) and the production packer (40) below the perforations (88) or milled slot (103) serve as a lower foundation for the third permanent barrier. The 5 circulation in the annuli (99) is enabled by the coiled tubing pump (69) and the surface pumping unit (69, 118), through the wellhead ports (116) on the surface wellhead (115).

Figure 58 shows a coiled tubing assembly placed on an offshore platform. The 10 primary and secondary barriers are now tested and verified (87b). The third barrier is set by pumping the barrier material (86) through the perforations (88, 92) and thus obtaining circulation to the surface. The circulation in the annuli (99) is enabled by the coiled tubing pump (69) and the surface pumping unit (118), through the wellhead ports (116) on the surface wellhead (115). The figure also shows that circulation to 15 the surface, particularly through the a-annuli (110b), and not through the artificially made annuli outside the coiled tubing string (12), which is sealed off by the coiled tubing packer (60a). The plug (64a) and the production packer (40) below the perforations (88) or milled slot (103) serve as a lower foundation for the third permanent barrier.

Figure 59 shows a permanently plugged (80) well (79) with the primary and secondary barriers, across the full cross section, pressure tested and verified (the secondary barrier being also approved by cement logging verification). The primary plug is achieved through injecting (111) the barrier material (86) through the

25 perforations (90) into the reservoir (50). The third permanent (environmental) plug verified through circulation to the surface.

The figure also shows all bores in the Christmas tree (94) filled with barrier material (86). The downhole safety valve (39a) has been closed. The control lines (16a), 30 including the downhole safety valve (39a, 39b), have all been bled off and filled with e.g. a mixture of glue and silicone (101) from the hydraulic power unit (17a), with the module (93) for bleeding off and sealing off the control lines, including the pressurized sealant material (93a), the pump (93b) and the low-pressure tank (93c)

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for bleeding off pressure, hence the control lines (16a) are permanently sealed off by the control line sealant material (101) being e.g. a mixture of glue and silicon.

Filling of all the bores in the Christmas tree (94) is likely when using the Y-connection 5 to assist in lifting through both the annulus valve (37a) and the choke valve (58c) on the injector stack (58a). When the Y-connection used with both valves (37a, 58c) is open, then the barrier material (86) will circulate in all main bores in the Christmas tree (94).

10 Figure 60 shows a permanently plugged (80) well (79) with three full cross section barriers being tested and verified.

After removing all temporary umbilicals, other hoses, lines and other subsea equipment, the remote operated vehicle (19) has been utilized to jet away and clear 15 the sediments surrounding the wellhead frame, with the aim of cleaning the ground around the metal structure for adhesion of the cement (85c).

A cement dome (117) is placed by pouring cement (85c) through the coiled tubing string (12) on top of the Christmas tree (94), allowing it to be sealed off and left on 20 the seabed (49) without compromising interest of fishing, shipping or other activities.

When using the riserless intervention vessel for performing the permanent abandonment operations, leaving the Christmas tree (94) and wellhead (51) in a cement dome on the seabed is the preferred solution, due to limited cutting and lifting 25 capacities.

Additional modifications, alterations and adaptations of the present invention will suggest themselves to those skilled in the art without departing from the scope of the invention as defined in the following patent claims.

1 Document library (data room)

2 Planning, preparations and training of multiskilled personnel

3 Drilling rig

4 Cost reduction

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5 Time reduction

6 Light well intervention vessel

7 Steering house

8 Coiled tubing reel

9 Coiled tubing power pack and accumulator unit

10 Control cabin

11 Spooler head

12 Coiled tubing string

13 Gooseneck

13b Surface injection stack

14 Umbilical vessel-subsea pumping unit

15 Umbilical vessel-subsea hydraulic power unit

16a Hydraulic control line from hydraulic power unit to wellhead port for downhole safety valve line

16b Subsea pumping unit

17a Hydraulic power unit

17b Cement laboratory

18 ROV control unit

19 primary ROV

20 secondary ROV

21 primary umbilical connected to the ROV

22 secondary umbilical connected to the ROV

23 Moonpool

24 Helicopter deck

25 Derrick

26 PIT or separator

27 Debris cap

28 Subsea horizontal Christmas tree

29 Wellhead outlet ports

30 Upper crown plug

31 Lower crown plug

32 Annulus bore

33 Production bore

34a Production upper master valve

34b Production isolation valve

34c Production swab valve

35 Christmas tree body

36 Crossover valve

37a Annulus isolation valve

37b Annulus master valve

37c Annulus swab valve

38 High pressure cap

39a Downhole safety valve (closed)

39b Downhole safety valve (open)

40 Production packer

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41 Liner hanger packer

42 Production tubing

43a Liner

43b Liner cement

44a Production casing

44b Production casing cement

45a Intermediate casing

45b Intermediate casing cement

46a Surface casing

46b Surface casing cement

47 Casing shoe

48 Formation

49 Seabed

50 Reservoir

51 Wellhead

52 Downhole control lines

53 Temporary plug or cement plug

54 Tubing fluid

55 Annulus fluid

55a Choke line umbilical-subsea injector stack

55b Kill line umbilical

56 Washing train

57 Tubing hanger

58a Coiled tubing subsea injector stack

58b Kill line entry port valves

58c Choke line entry port valves

58d Subsea injector

58e Pipe ram

58f Shear ram

58g Slip ram

59 Drifting, scraping and brushing tool

60a Coiled tubing packer, expanded

60b Coiled tubing packer, not expanded

61a Spacer #1, to separate fluids

61b Spacer #2, to separate fluids

61c Washing pill, between spacers

61d Seawater

61e Freshwater

62a Perforation gun, pre-firing

62b Perforation gun, post-firing

63a Plug, pre-set, mechanically operated setting mechanism 63b Plug, pre-set, electronically operated setting mechanism 64a Plug, set

65 Mixer

66 Stirrer

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67 Thru-tubing re-settable packer

68 Bottom hole assembly (BHA)

69 Pump, coiled tubing

70a Release mechanism, closed position

70b Release mechanism, open position

71 Temporary plug previously placed

72 Temporary cement plug previously placed

73 Plug (full throughflow), run in hole on coiled tubing

74 Plug (full throughflow), in closed position, ready for pumping barrier material 75 Well tractor

75a Throughtubing well tractor with release function

76 Mid sea level

77 Perforation gun on well tractor

78 Vertical Christmas tree

79 Well

80 Permanently plugged well

81 Temporary plugged well

82 Christmas tree adapter

83 Cap rock

84 Perforation gun on two off well tractor

85a Barrier material #1 - colloidal silica

85a1 Barrier material #1 - colloidal silica dispersed in freshwater pill

85b Barrier material #2 - micro cement

85c Barrier material #3 - cement

85d Barrier material #4 - expanding cement

85e Barrier material #5 - additives

85f Barrier material #6 - tracer, radioactive

86 Barrier material, best suited (example 85a-85f)

87a Barrier material, cured

87b Barrier material, cured, pressure tested and verified

88 Perforated tubing and casing

89 Perforated into a-annulus only

90 Perforations in reservoir

91a Sensor, well barrier material (tracer)

91b Control line for downhole tools, inside or outside coiled tubing string 92 Perforated for circulation from above

93 Module for bleeding off and sealing off control lines

93a Pressurized sealant material

93b Pump

93c Low pressure tank for bleeding off pressure

94 Christmas tree

95a Cleaning and scraper tool, with weak point for ball drop release

95b Solvents and anti-freeze agents

96 Brushing tool

97 Check valve

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98 Crane

99 Annuli

100 Salt brine / brine

101 Control line sealant material (e.g. a mixture of glue and silicon)

102 Milling tool

103 Milled production tubing section

104 Hose from annulus wing valve to subsea pumping unit (16b)

105 Y-connection, with functionality to select source

106 Centralizer for coiled tubing string

107 Stroker tool for coiled tubing string

108 Hose from subsea injector stack to subsea pumping unit

109 Heavy fluid

110 Circulation to surface

110b Circulation through a-annuli to surface

111 Squeezing barrier material (86) through perforations (90) into reservoir (50) 112 Pressure and temperature sensor

113 Surface BOP

114 Surface BOP kill and choke lines

115 Surface wellhead

116 Surface wellhead outlet valves

117 Cement dome

118 Pumping unit

Claims

CLAIMS

1. A method for riserless and rigless plug and abandonment of a wellbore, the method comprising, in a recommended order, the steps of:

5 a) placing a pumping unit (16b) in close proximity to a wellhead (51) of the wellbore;

b) placing a coiled tubing injector stack (58a) on top of the wellhead (51) or on top of a Christmas tree (94) on the wellhead (51);

c) connecting a source (105) on the pumping unit (16b), using a connection 10 comprising a first hose (108), to a choke valve (58c), arranged on the coiled tubing injector stack (58a), by using the first hose (108);

d) connecting the pumping unit (16b) to a pit or separator (26) via a first umbilical or hose (14);

e) removing any unnecessary plug (30, 31, 64a) on the way down for the coiled 15 tubing string (12) by means of a stroker (107) arranged at the operational end of the coiled tubing string (12);

dropping a cleaning assembly (95a, 96) and possibly a well tractor (75, 75a) into the wellbore;

f) scraping and washing a section of the wellbore to be plugged by means of a 20 scraper (95a) having high-pressure nozzles and brushes and using a washing fluid (61c) with solvents and anti-freeze agents (95b), dropping a cleaning assembly (95a, 96) and possibly a well tractor (75, 75a) into the wellbore, and displacing fluid (109) and particles from the wellbore to maintain well integrity;

g) running a coiled tubing string (12) into the wellbore, wherein the coiled tubing 25 string (12) is, for each run-in-hole operation, equipped, at an operational end thereof and depending on the operation to be performed, with at least one of: a stroker (107) configured for removing any unnecessary plug (30, 31, 64a), a passive packer (60a) being unset under run-in-hole operation and configured to expand or set when pressure is increased over a predetermined level and/or assemblies (68) comprising 30 at least one perforation gun (62a, 88, 89) and/or a milling tool (102), and a plug (64a), and possibly a well tractor (75, 75a);

h) milling and/or perforating the section of the wellbore to be plugged with its adjacent production tubing (42), other adjacent casing and/or adjacent formation by

means of the milling tool (102) and/or the at least one perforation gun (62a, 88, 89) respectively;

i) placing at least one packer and/or at least one plug (63a, 63b, 64a) above and/or below the section to be plugged, and/or using any existing packer (40, 41) 5 and/or plug (71) to isolate the section to be plugged;

j) pumping barrier materials (86) through the coiled tubing string (12) into the section to be plugged and through perforations (88, 89, 92) and/or milled sections (103) to create a first barrier, wherein the passive packer (60a, 60b) at the operational end of the coiled tubing string (12) is being activated and opened by the 10 increased pressure and isolates the annular space between the coiled tubing string (12) and the production tubing (42); and

k) pulling out the coiled tubing string (12) with the passive packer (60a).

2. The method for riserless and rigless plug and abandonment according to claim 15 1, wherein the connection is a Y-connection (105) further comprising a second hose (104), and the source on the pumping unit (16b) is being connected to an annulus valve (37a; 29, 116) arranged on the Christmas tree (94) or on the wellhead (51, 115) by using the second hose (104) to facilitate circulation to the surface (110, 110b).

20 3. The method for riserless and rigless plug and abandonment according to claim 1 or 2, further comprising the steps of:

- if a valve cannot be manually operated, placing a hydraulic power unit (17a) in close proximity to the wellhead (51);

- connecting the hydraulic power unit (17a), having at least one tank (93a, 93c) 25 for control line sealant barrier material (101), to a wellhead port (29) via an external control line (16a).

4. The method for riserless and rigless plug and abandonment according to any preceding claim, further comprising the steps of:

30 - curing the barrier material of the first barrier; and

- optionally pressure testing the first barrier.

5. The method for riserless and rigless plug and abandonment according to any preceding claim, further comprising the step of:

- creating at least one second barrier above the first barrier using all or some of the steps a) - k).

6. The method for riserless and rigless plug and abandonment according to claim 1 or 5, wherein under step j) the barrier material (86) is being circulated through the annuli (99), between the production tubing (42) and casing, to the surface (110) from the coiled tubing string (12) placed inside the production tubing (42) and through the 10 created perforations (88, 92) or milled slots (103) placed below the coiled tubing packer (60a).

7. The method for riserless and rigless plug and abandonment according to claim 5, further comprising the steps of:

15 - curing the barrier material of said at least one second barrier; and

- optionally pressure testing said at least one second barrier.

8. The method for riserless and rigless plug and abandonment according to any preceding claim, further comprising the step of:

20 - pressure testing, from above, each barrier placed across full cross section of the wellbore.

9. The method for riserless and rigless plug and abandonment according to claim 4 or 7, where the curing process is being delayed by placing colloidal silica dispersed 25 in a freshwater pill (85a, 85a1) prior to exposing the colloidal silica to seawater (61d) or salt brine (100) in the formation (48) and/or the reservoir (50).

10. The method for riserless and rigless plug and abandonment according to any preceding claim, further comprising the steps of:

30 - bleeding off all downhole control lines (52); and

- sealing off the downhole control lines (52).

11. The method for riserless and rigless plug and abandonment according to any preceding claim, further comprising the step of:

- pouring cement (85c) through the coiled tubing string (12) on top of the wellhead (51) and/or the Christmas tree (94) to create a cement dome (117) over 5 them.

12. The method for riserless and rigless plug and abandonment according to any preceding claim, the method being configured for plug and abandonment of a subsea well, wherein a light well intervention vessel (6) and at least one remote operated 10 vehicle, ROV, (19, 20), connected to the vessel (6) and operated by at least one umbilical (21, 22), are being used to perform some of the method steps.

13. The method for riserless and rigless plug and abandonment according to any one of claims 1-11, wherein the method is configured for plug and abandonment of a 15 surface or platform well.

14. The method for riserless and rigless plug and abandonment according to any preceding claim, wherein a tracer and/or a sensor (85f, 91a) is used to track and/or verify the circulation of the barrier material.

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P A T E N T K R A V

1. En fremgangsmåte for stigerørsløs og riggløs plugging og forlating av et brønnhull, idet fremgangsmåten omfatter, i en anbefalt rekkefølge, trinnene med:

5 a) å plassere en pumpeenhet (16b) i umiddelbar nærhet til et brønnhode (51) for brønnhullet;

b) å plassere en kveilrørinjektorstabel (58a) på toppen av brønnhodet (51) eller på toppen av et juletre (94) på brønnhodet (51);

c) å koble en kilde (105) på pumpeenheten (16b), ved å bruke en forbindelse

10 som omfatter en første slange (108), til en strupeventil (58c), anordnet på kveilrørinjektorstabelen (58a), ved å bruke den første slangen (108);

d) å koble pumpeenheten (16b) til en grop / sjakt eller separator (26) via en første navlestreng eller slange (14);

e) å fjerne enhver unødvendig plugg (30, 31, 64a) på vei ned for kveilrørstrengen

15 (12) ved hjelp av en slag- eller stempelenhet (107) som er anordnet ved den operative enden til kveilrørstrengen (12);

å slippe en rensesammenstilling (95a, 96) og muligens en brønntraktor (75, 75a) inn i brønnhullet;

f) å skrape og vaske en seksjon av brønnhullet som skal plugges ved hjelp av en

20 skrapeenhet (95a) som har høytrykksdyser og børster og bruker et vaskefluid (61c) med løsemidler og frostvæsker (95b), å slippe en rensesammenstilling (95a, 96) og muligens en brønntraktor (75, 75a) inn i brønnhullet, og å erstatte fluid (109) og partikler fra brønnhullet for å opprettholde brønnintegritet;

g) å kjøre en kveilrørstreng (12) inn i brønnhullet, hvor kveilrørstrengen (12) er,

25 for hver hullinnkjøringsoperasjon, utstyrt, ved en operativ ende derav og avhengig av operasjonen som skal utføres, med minst én av: en slag- eller stempelenhet (107) som er konfigurert til å fjerne enhver unødvendig plugg (30, 31, 64a), en passiv pakning (60a) som er deaktivert under hullinnkjøringsoperasjon og konfigurert til å ekspandere eller settes når trykket økes over et forhåndsbestemt nivå, og/eller

30 sammenstillinger (68) som omfatter minst én perforeringskanon (62a, 88, 89) og/eller et freseverktøy (102), og en plugg (64a), og muligens en brønntraktor (75, 75a); h) å frese og/eller perforere seksjonen av brønnhullet som skal plugges med dets tilstøtende produksjonsrør (42), annet tilstøtende fôringsrør og/eller tilstøtende

349001

formasjon ved hjelp av henholdsvis freseverktøyet (102) og/eller den minst ene perforeringskanonen (62a, 88, 89);

i) å plassere minst én pakning og/eller minst én plugg (63a, 63b, 64a) over og/eller under seksjonen som skal plugges, og/eller å bruke enhver eksisterende

5 pakning (40, 41) og/eller plugg (71) for å isolere seksjonen som skal plugges;

j) å pumpe barrierematerialer (86) gjennom kveilrørstrengen (12) inn i seksjonen som skal plugges, og gjennom perforeringer (88, 89, 92) og/eller utfreste seksjoner (103) for å danne en første barriere, hvor den passive pakningen (60a, 60b) ved den operative enden til kveilrørstrengen (12) blir aktivert og åpnet ved det økte trykket og

10 isolerer det ringformede rommet mellom kveilrørstrengen (12) og produksjonsrøret (42); og

k) å trekke ut kveilrørstrengen (12) med den passive pakningen (60a).

2. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge krav 1,

15 hvor forbindelsen er en Y-forbindelse (105) som videre omfatter en andre slange (104), og kilden på pumpeenheten (16b) blir koblet til en ringromsventil (37a; 29, 116) som er anordnet på juletreet (104) for å lette sirkulasjonen til overflaten (110, 110b).

20 3. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge krav 1 eller 2, videre omfattende trinnene med:

- hvis en ventil ikke kan betjenes manuelt, å plassere en hydraulisk kraftenhet (17a) i umiddelbar nærhet til brønnhodet (51);

- å koble den hydrauliske kraftenheten (17a) som har minst en tank (93a, 93c)

25 for kontroll- eller styrelinjetetningsmiddelbarrieremateriale (101), til en brønnhodeport (29) via en ekstern kontroll- eller styrelinje (16a).

4. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge et hvilket som helst av de foregående kravene, videre omfattende trinnene med:

30 - å herde barrierematerialet til den første barrieren; og

- eventuelt å trykkteste den første barrieren.

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5. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge et hvilket som helst av de foregående kravene, videre omfattende trinnet med:

- å danne minst én andre barriere over den første barrieren ved å bruke alle eller noen av trinnene a) - k).

6. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge krav 1 eller 5, hvor under trinn j) blir barrierematerialet (86) sirkulert gjennom ringrommene (99), mellom produksjonsrøret (42) og fôringsrøret, til overflaten (110) fra kveilrørstrengen (12) plassert innenfor produksjonsrøret (42) og gjennom de opprettede

10 perforeringene (88, 92) eller de utfreste slissene (103) som er plassert under kveilrørpakningen (60a).

7. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge krav 5, videre omfattende trinnene med:

15 - å herde barrierematerialet til den minst ene andre barrieren; og

- eventuelt å trykkteste den minst ene andre barrieren.

8. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge et hvilket som helst av de foregående kravene, videre omfattende trinnet med:

20 - å trykkteste, ovenfra, hver barriere som er plassert over hele tverrsnittet av brønnhullet.

9. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge krav 4 eller 7, hvor herdeprosessen blir forsinket ved å plassere kolloidalt silika dispergert i

25 en ferskvannspille (85a, 85a1) før den kolloidale silikaen blir eksponert for sjøvann (61d) eller saltlake (100) i formasjonen (48) og/eller reservoaret (50).

10. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge et hvilket som helst av de foregående kravene, videre omfattende trinnene med:

30 - å lede vekk alle nedihulls kontroll-linjer (52); og

- å tette / forsegle nevnte nedihulls kontroll-linjer (52).

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11. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge et hvilket som helst av de foregående kravene, videre omfattende trinnet med:

- å helle sement (85c) gjennom kveilrørstrengen (12) på toppen av brønnhodet (51) og/eller juletreet (94) for å danne en sementkuppel (117) over dem.

12. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge et hvilket som helst av de foregående kravene, hvor fremgangsmåten er konfigurert for plugging og forlating av en undervannsbrønn, hvor et lett brønnintervensjonsfartøy (6) og minst ett fjernstyrt fartøy, ROV, (19, 20) som er koblet til fartøyet (6) og operert

10 av minst én navlestreng (21, 22), blir brukt til å utføre noen av fremgangsmåtetrinnene.

13. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge et hvilket som helst av krav 1-11, hvor fremgangsmåten er konfigurert for plugging og

15 forlating av en overflate- eller plattformbrønn.

14. Fremgangsmåten for stigerørsløs og riggløs plugging og forlating ifølge et hvilket som helst av de foregående kravene, hvor et sporstoff og/eller en føler / sensor (85f, 91a) blir brukt til å spore og/eller verifisere sirkulasjonen av barriere-

20 materialet.

Drawings

Priority

No priority

Patent classes

IPC classes

E21B 33/13

E21B 33/035

E21B 33/076

E21B 21/00

CPC classes

E21B 33/13

E21B 33/035

E21B 33/076

E21B 21/001

Citations

US 9388653 B2 (B2)

WO 2017089000 A1 (A1)

Applicants, owners and inventors

Owners

REIN OFFSHORE AS

Christian Benneches vei 10

0286 OSLO

NO (OSLO Municipality, Oslo county)

Org. number: 933836754

Inventors

Helge Lone

Christian Benneches vei 10

0286 OSLO

NO (OSLO Municipality, Oslo county)

Asle Rein

Kittel-Nielsensvei 82 C

1163 OSLO

NO (OSLO Municipality, Oslo county)

Agent

BRYN AARFLOT AS

Stortingsgata 8

0161 OSLO

NO (OSLO Municipality, Oslo county)

Org. number: 979993269

Reference: 145800NO

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Only events from 2024.03.04 and onwards are shown.

Riserless and rigless permanent plug and abandonment of subsea, surface and platform wells

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