WELLHEAD SYSTEM AND METHOD FOR CARBON CAPTURE AND STORAGE

BACKGROUND
1. Field of Invention

This invention relates in general to equipment used in onshore or offshore oil and gas production, and in particular, to a wellhead system and method for carbon capture and storage in depleted hydrocarbon reservoirs or dedicated aquifers.

2. Description of the Prior Art

Onshore and offshore formations serve as depleted hydrocarbon reservoirs or dedicated aquifers. Such formations support oil and gas production of hydrocarbons but may be also recognized as contributing to carbon dioxide (CO₂) emissions. Such CO₂may be contained into the formation. However, depleted formations may continue to be treated as hydrocarbon-bearing while aquifers may need to be treated differently, and such formations may require different solutions.

SUMMARY

In at least one embodiment, a wellhead system for carbon capture and storage in a depleted hydrocarbon reservoir or dedicated aquifer is disclosed. The system includes a wellhead block to comprise or support therewith a barrier subsystem of one or more of at least one isolation gate valve or one or more plugs. The barrier subsystem is to allow access to a well that is associated with the depleted hydrocarbon reservoir or dedicated aquifer. The system includes one or more modulation valves to modulate an injection of a wellhead fluid comprising a carbon component into the wellhead block.

In at least one embodiment, a method for carbon capture and storage in a depleted hydrocarbon reservoir or dedicated aquifer is also disclosed. The method includes providing a wellhead block that comprises or supports therewith a barrier subsystem of one or more of at least one isolation gate valve or one or more plugs. The method also includes allowing, using the barrier subsystem, access to a well that is associated with the depleted hydrocarbon reservoir or dedicated aquifer. The method further includes modulating, using one or more modulation valves, an injection of a wellhead fluid comprising a carbon component into the wellhead block.

In at least one embodiment, a further system for carbon capture and storage in a depleted hydrocarbon reservoir or dedicated aquifer is disclosed with a different configuration. The system includes a wellhead block to comprise one or more modulation valves to modulate an injection of a wellhead fluid comprising a carbon component into the wellhead. The system includes a barrier subsystem comprising one or more subsea valves. The barrier subsystem is associated with the wellhead block to allow access to a well that is associated with the depleted hydrocarbon reservoir or dedicated aquifer.

BRIEF DESCRIPTION OF THE DRAWINGS

Various embodiments in accordance with the present disclosure will be described with reference to the drawings, in which:

FIG. 1 illustrates an example environment subject to at least one embodiment herein;

FIG. 2 illustrates a line diagram detailing a template structure of a wellhead block and a manifold module to work with the wellhead block, in at least one embodiment;

FIG. 3 illustrates a perspective view of a wellhead cap to sit above a wellhead block, in at least one embodiment;

FIGS. 4A and 4B illustrate different configurations of a wellhead block associated with a wellhead, in at least one embodiment;

FIGS. 5A and 5B illustrate further configurations of a wellhead block associated with a wellhead, in at least one embodiment;

FIG. 6 illustrates yet another configuration of a wellhead block associated with a wellhead, in at least one embodiment;

FIGS. 7-11 illustrate, in further detail, one or more of the configurations of FIGS. 4A to 6 of a wellhead block associated with a well, in at least one embodiment; and

FIG. 12 illustrates a method for carbon capture and storage in a depleted hydrocarbon reservoir or dedicated aquifer, according to at least one embodiment.

DETAILED DESCRIPTION

In the following description, various embodiments will be described. For purposes of explanation, specific configurations and details are set forth in order to provide a thorough understanding of the embodiments. However, it will also be apparent to one skilled in the art that the embodiments may be practiced without the specific details. Furthermore, well-known features may be omitted or simplified in order not to obscure the embodiment being described. Various other functions can be implemented within the various embodiments as well as discussed and suggested elsewhere herein. In at least an embodiment, the present disclosure is to a system and a method for a functional and compact arrangement that allows for injection of carbon compounds, such as CO₂, as part of wellhead fluids, while providing appropriate well barriers isolations for well integrity and intervention.

In at least one embodiment, a wellhead (also referred to as a wellhead system) may include structural security, along with access to storage formation and annulus space. Meanwhile, a tree system includes an Xmas Tree that may be located above a wellhead to provide access to downhole features of a well. In at least one embodiment, instead of a tree system, a wellhead block herein provides function, monitoring, isolation, and flow path, for injection, for a depleted formation or aquifer while providing well barrier and isolation needs. In at least one embodiment, such a feature replaces an Xmas Tree to provide a wellhead block that is able to support carbon storage applications. In doing so, cost savings through reduced complexity and functionality may be achieved to strengthen an economic case for CO₂storage projects.

In at least one embodiment, FIG. 1 illustrates an example environment 100 that is associated with improvements described herein. While aspects herein are applicable to onshore and offshore wells, a wellhead 102 may include a series of complex pipes or other safety components 104 affixed to a well casing 106 on a well (generally depicted as reference numeral 108). In at least one embodiment, such affixing may be performed at a bottom of the wellhead 102. The wellhead 102 may have an opening 110 at its top. Such a wellhead 102 is only exemplary and other types of wellheads and associated components may be subject to the improvements described herein.

In at least one embodiment, the wellhead 102 may include a wellhead cap 112 positioned over the wellhead opening 110. The wellhead cap 112 may be provided to protect the inside of the wellhead 102 from the ambient and harsh conditions that exist in the environment 100. For example, such a wellhead cap 112 can prevent seawater (if offshore) from filling a bore hole. The wellhead cap 112 may be generally sized to fit dimensions of a wellhead opening 110. Further, as wellhead adapters may be used to mate a wellhead cap 112 into a wellhead opening 110.

While techniques herein may be subject to modifications and alternative constructions, these variations are within spirit of present disclosure. As such, certain illustrated embodiments are shown in drawings and have been described above in detail, but these are not limiting disclosure to specific form or forms disclosed; and instead, cover all modifications, alternative constructions, and equivalents falling within spirit and scope of disclosure, as defined in appended claims.

Initially and throughout herein, abbreviations may be used to certain features of a system for carbon capture and storage in a depleted hydrocarbon reservoir or dedicated aquifer. These include, unless otherwise indicated, Annulus Isolation device (AID), Annulus Pressure Transducer (APT), Blow-Out Preventer (BOP), Downhole Pressure & Temperature gauges (DHPT), Downstream of Choke Pressure and Temperature transducers (DPT), Fibre Optic (FO), Horizontal Clamp Connection System (HCCS), Injection Master Valve (IMV), Integrated Template System (ITS), Multi-flowbase (MFB), Multi-Quick Connect (MQC), Non Return Valve (NRV), Riserless Light Well Intervention (RLWI), Side Pocket Mandrel (SPM), Single Phase Flow Meter (SPFM), Subsea Control Module (SCM), Subsea Valve (SSV), Surface Controlled Subsea Valve (SCSSV), Upstream of Choke Pressure and Temperature transducers (UPT), Vertical Clamp Connection System (VCCS), and Xmas Tree (XT).

FIG. 2 illustrates line diagram 200 detailing a template structure 210 of a wellhead block and a manifold module 212 to work with the wellhead block 202, in at least one embodiment. The template structure 210 may rest on a mudline in an offshore application or may be partly under a mudline hosting a wellhead 206. In at least one embodiment, the template structure 210 includes or supports the manifold module 212 and enables the wellhead block 202 to be installed and removed as one unit on a wellhead 206. FIG. 2 illustrates that a wellhead block includes or supports a bore-through hole 230 in a wellhead block body 204; different access ports (such as for a side flow path 226); at least one plug 212 for the bore-through hole 230 that allows vertical access when a wellhead cap 228 is removed; and side access paths 224 for different annulus access for venting, monitoring, intervening, and performing other operations.

While an Xmas tree (XT) arrangement may be used for production flow (also referred to as reservoir fluid) of hydrocarbons from a subsurface reservoir of a well, a system for carbon capture and storage in a depleted hydrocarbon reservoir or dedicated aquifer may be dedicated for injection carbon compounds, such as comprising CO₂, as part of wellhead fluid into either depleted hydrocarbon reservoirs or dedicated aquifers. The wellhead block 202 may be prepared with plugs and/or inline primary valves and may be devoid of a wing valve, such as illustrated in one or more of FIGS. 3-11 herein. The wellhead block 202 may be capped by a wellhead cap 228 that sits on top a wellhead block 202 but may not be capped in some embodiments, as detailed further with respect to one or more of FIGS. 3-11.

In at least one embodiment, injection of wellhead fluids, which is distinct from a reservoir fluid extracted, may comprise carbon components, such as CO₂that is to be captured. The injected wellhead fluids may be directed through a side flow path 226 of the wellhead block. For all intents and purposes, the side flow path for injection of wellhead fluids terminates at a top of a wellhead block but it curves to a side of the wellhead block and is devoid of a vertical flow path with respect to the wellhead block. For example, the side flow path may be devoid of a vertical length above a wellhead block that is more than a height of the wellhead block. A flow spool may be provided to support such injection, along with a choke valve, as detailed further with respect to one or more of FIGS. 3-11, that may be in a retrievable module 220 or may be in an appropriate part of the wellhead block 202. In at least one embodiment, the choke valve may include a replaceable or retrievable insert.

In at least one embodiment, the modulation valve may be a choke valve that is used to perform modulation functions. Further, for any future well intervention, the wellhead cap 228 may be removed or may support attachments for attaching other features, including a riserless light well intervention system. To support such aspect, therefore, in at least one embodiment, a wellhead block 202 may be capped or may include a main body (or wellhead block body) 204, one or more isolation gate valves, and a wellhead connector, as further depicted and detailed at least with respect to FIG. 3.

Systems and methods for carbon capture and storage herein provide a technical advantage of having a fit-for-function arrangement. In at least one embodiment, this arrangement enables a compact assembly while addressing issues of minimizing flow path requirements for the injection of media including carbon compounds via a side of a wellhead block and removes the need for a large bore injection wing valve.

In FIG. 2, a wellhead block (generally depicted as reference numeral 202) is able to support bore access using an annulus access port, a valve, and an access path 230. In at least one embodiment, therefore, a wellhead block 202 includes or supports a bore-through hole 230; a side flow or access path 226 for injected fluids; annulus access ports 224A; association with at least one valve 214; 222; and further access or flow paths 224B for annulus access. Further, the bore-through hole 230 is to allow access a bore for injection fluids from a side flow path 226 of the wellhead block 202, while also allowing vertical bore access from above, such as by removal of a plug 212 and a wellhead cap 228. Separately, distinct access paths 224B can allow access to the well annulus 232 from the further access or flow paths 224B of the wellhead block 202.

In at least one embodiment, the wellhead block 202 may be associated with an isolation gate valve 214 at the side flow path 226. The isolation gate valve 214 may be within the wellhead block 202 or supported therewith by the wellhead block 202 to provision the side flow or access path 226. A retrievable module 220 is provided for controls to be made to the injection fluid to be provided to the well, for instance. In at least one embodiment, such features simplify a wellhead block 202.

In at least one embodiment, the wellhead block 202 includes an internal profile to enable one or more plugs 212 to be set. As such, FIG. 2 also illustrates a barrier subsystem having one or more plugs 212 and at least one isolation gate valve 214. Furthermore, the wellhead block 202 can include exterior profile to enable a riserless light well intervention (RLWI) stack or a BOP stack to be coupled over the wellhead block 202. In at least one embodiment, further, valves may be provided for the access path 226 either in the vertical path of the bore-through hole 230 or the side flow path 226. These valves may be remotely-activated and may be normally open valves. Process valves (such as an actuated valve) 222 may be provided on the retrievable module 220. As also illustrated, annular regions 232 may be accessed, along with the main bore 234, through the side access paths 226, 224B, and the bore-through hole 230 of the wellhead block 202.

An isolation gate valve 214 may be associated with at least one side flow path 226. The isolation gate valve 214 can provide a barrier that keeps fluid and pressure limited to the wellhead block 202. The isolation gate valve 214 can also be used to provide a barrier for workovers and well interventions. In at least one embodiment, the isolation gate valve 214 may be ball valves, mechanically actuated valves, or hydraulic valves.

A downhole surface controlled subsurface safety valve (SCSSV) 208 may be provided in the bore as illustrated. An SCSSV 208 may be operated from surface facilities that interface via lines through the wellhead block 202. This is described in further detail with respect to FIGS. 7 to 11. The SCSSV 208 may be wireline-retrievable that can be run and retrieved on a wireline or may be tubing-retrievable that can be installed with a tubing string. The SCSSV 208 is configured in a fail-safe mode in which the SCSSV 208 may be held open by hydraulic control pressure applied to hold open a ball or flapper, but that closes when control or pressure is lost. In at least one embodiment, the SCSSV 208 may be shallow set, such as between the surface and 300 meters (m) below the surface; may be at medium depth, such as between 300 m and 600 m below the surface; or may be deep set, such as more than 600 m below the surface. There may be factors associated with geological stability, water depth, and/or reservoir location that may be used to determine a setting for the SCSSV 208.

One or more retrievable modules 220 may be provided, within the manifold module 212, for controls to be made to the injection fluid to be provided to the well, for instance. Each retrievable module 220 includes an actuated valve 222, a choke valve, and may also include a flow metering device. As such, a manifold module 212 may be used to coordinate controls for multiple wellhead blocks 202 for multiple wells. A manifold header 218 may support such coordinated controls. A subsea control module (SCM) 216 may be used when the well is an offshore well. The SCM 216 may perform a majority of the functions described for the system herein and an ROV may be deployed for controlling valves that are not controlled by the SCM 216.

FIG. 3 illustrates a perspective view of a wellhead cap system 300 of a wellhead cap 312 to sit on top of wellhead block, in at least one embodiment. As illustrated, the wellhead cap system 300 may include an ROV panel 302 and panel module 310 for communicating with valves or sensors therein or for communicating with an SCM 216 of a wellhead block if the wellhead cap 312 is installed over a wellhead block 202. Further, the wellhead cap system 300 includes a flow connection 308 that may be part of a gooseneck 304 and that may have a connector 306 for a further downstream connection. A lift shackle 304 may be provided to position, install, or remove the wellhead cap system 300 if it is used with a wellhead block 202 and may then allow access to a bore-through hole of the wellhead block 202 after removal of any other intervening component, such as crown plugs 212.

FIGS. 4A and 4B illustrate different configurations 400; 450 of a wellhead block 402; 452 associated with a wellhead 408; 458, in at least one embodiment. The wellhead block 402, in a first configuration illustrated in FIG. 4A, includes a choke wellhead block 406 and a gate wellhead block 404. Different from a configuration in FIG. 2, throughout FIGS. 4A and 4B, a choke valve and one or more gate valves are in wellhead blocks that may be a single wellhead block as a singular structure or that may be multiple wellhead blocks stacked together as a multiple-component structure to support a side flow path of the wellhead block 404.

In the configuration in FIG. 4A, a choke valve may be provided in the choke wellhead block 406 and two isolation gate valves may be provided in the gate wellhead block 404. The choke valve may be used to control a flow rate of a wellhead fluid to be injected through the wellhead block 402 from a side flow path associated with the wellhead block 402. Further, the choke valves may be used to regulate pressure in the flow connector line. The isolation gate valves provide on and off control for wellhead fluid flow.

FIG. 4B illustrates a second configuration of a wellhead block 452, provided as a singular structure rather than a two-component structure of a choke wellhead block and a gate wellhead bock, as illustrated in FIG. 4A and detailed further in FIG. 7. The configuration of the wellhead block 452 of FIG. 4B incorporates the isolation gate valves and the choke valve in a single structure. Further details of the wellhead block 452 configuration of FIG. 4B is illustrated in FIG. 8. In addition, FIG. 4A illustrates that further features, such as an APT 414, a DPHT 424, a SPFM 422, a DPT 420, and a UPT 426 may be provided in the system herein to perform or support one or more further functions associated with the system. Such features are not marked in one or more of the subsequent FIGS. 5A-11, but will be readily understood to a person of ordinary skill in reviewing the present disclosure, as to their locations and functions in each embodiment herein and the FIGS. 5A-11.

FIGS. 5A and 5B illustrate further configurations 500; 550 of a wellhead block 502; 552 associated with a wellhead 508; 558, in at least one embodiment. The wellhead block 502, in a third configuration illustrated in FIG. 5A, provides a singular structure to host at least isolation gate valves and access paths for various bore and annulus access, but also enables pass-through support for the choke valve, which is located external to the wellhead block 502. In at least one embodiment, the external location is to a side of the wellhead block 502. Further, provision exists on the wellhead block 502 to allow vertical access to the bore-through hole by at least removal of provided plugs 504 of the wellhead block 502.

A fourth configuration of a wellhead block 552 is illustrated in FIG. 5B. In this configuration, a singular structure of a wellhead block 552 may be provided in a similar manner as the third configuration but enables the isolation gate valves 554 to be optional because of at least the presence of the plugs, such as the plug 504 also applicable in the wellhead block 552. While this fourth configuration retains the pass-through support for a choke valve located external to the wellhead block 552, it provides additional subsurface valves 560 with control features through the wellhead block 552. This may be in addition to an SCSSV. Further details of the wellhead block 502; 552 configurations of FIGS. 5A and 5B are illustrated in FIGS. 9 and 10, respectively.

FIG. 6 illustrates yet another configuration 600 of a wellhead block 602 associated with a wellhead, in at least one embodiment. The wellhead block 602 is in a fifth configuration illustrated in FIG. 6 and provides a singular structure in a similar manner as the second to fourth configurations but enables isolation gate valves 608 to be in multiple optional locations (also detailed in FIG. 11) like the fourth configuration. Differently than the fourth configuration, however, the fifth configuration brings the choke valve 610 internal to the wellhead block 602. For intervention purposes and for access to a vertical bore-through hole, the choke insert of the choke valve 610 may be retrieved. This then enables the required access. The choke insert may be replaced after such access is complete. Further details of the wellhead block 602 configuration of FIG. 6 are illustrated in FIG. 11.

FIG. 6 also depicts subsurface valves 560 used in the manner of the fourth configuration in FIG. 5B. For barriers provided by such subsurface valves 560 in FIGS. 5B and 6, one or more non return valves (NRV) valves 604 may be used in the tubing string to allow injected wellhead fluid to flow in one direction 606 only. Such NRVs may include structures of a ball valve, a flapper valves, or other valves capable of downhole use and capable of performing non-return functions.

FIGS. 7-11 illustrate, in further detail, each one of the configurations of FIGS. 4A to 6 of a wellhead block associated with a well, in at least one embodiment. The configurations herein address issues of carbon capture and storage. For example, current subsea regulations may be linked to oil and gas production of hydrocarbons and may be considered to be excessive in its demand for containing CO₂. As previously noted, depleted formations continue to be treated as hydrocarbon bearing wells while aquifers may be treated differently.

In at least one embodiment, depending on the type of field development pipeline operation performed, modulating valves may be required for modulating flow which may be configured within the flow spool to the well. Such valves (one or more of the choke valves or the isolation gate valves) may be configured as retrievable individually or within a flow module, as described at least in FIG. 2. Further, such valves may be high cycle valves.

In the configurations of FIGS. 7-11, a Single-Phase Flow Meter (SPFM) 714 may be provided within a flow spool to act as a flow measurement device, such as to enable monitoring of individual well injection rates. In at least one embodiment, the SPFM 714 may be calibrated prior to installation to perform its monitoring function. In at least one embodiment, an alternative to an SPFM may be enabled by the use of virtual flow-metering. Virtual flow-metering may utilize pressure transducers arranged within the system herein to determine flow when used in conjunction with an algorithm aligned to a pressure drop detected during injection of the wellhead fluid that includes the carbon component. In at least one embodiment, the SPFM 714 may be housed in either the spool or in the retrievable flow module.

Further, an in-line high flow retrievable metering valve arrangement may be provided to manage the injection of wellhead fluid, in place of or to supplement an insert-retrievable choke valve 706, illustrated in FIG. 7. The insert-retrievable choke valve 706 is mounted on a tree cap and on top of a wellhead block 702 and able to access a bore using a bore-through hole of the wellhead block. For all intents and purposes, FIG. 7 illustrates in part a configuration of a choke valve 706 that is supported by the wellhead block 702 at least because of the bore-through hole enabled in the wellhead block 702. Further, the wellhead block 702 includes a hub and include two isolation gate valves (valves/actuators) 704.

Further, for all intents and purposes, the choke valve 706, even if above the wellhead block 702 is to support a side flow path associated with the wellhead block to inject wellhead fluid into the wellhead block. For example, as illustrated the side flow path for injection of wellhead fluids may terminate at a top of a wellhead block, but it curves to a side of the wellhead block 702 and is devoid of a vertical flow path with respect to the wellhead block 702. For example, the side flow path may be devoid of a vertical length above a wellhead block 702 that is more than a height of the wellhead block 702. In this manner the flow of injected wellhead fluid is through a side flow path into the wellhead block 702.

In at least one embodiment, access is provided to an “A” annulus via an annulus vent/injection line (forming an access path) 712 of the wellhead block 702, as illustrated. The access is also through a tubing hanger 708 and can be used for both, venting activities if so required and/or for performing annulus top-up with fluids if so required. In at least one embodiment, top-up with fluids for an annulus may be performed using Triethylene Glycol (TEG), Diethylene Glycol (DEG) and Monoethylene Glycol (MEG) or other fluids. This may be done when it is determined that, due to thermal cycling, a vacuum is created when annulus fluid cools during well injection.

In at least one embodiment, monitoring of an “A” annulus may be performed using an Annulus Pressure Transducer (APT) sensor 716 that is mounted on the wellhead 702 and/or using downhole gauges located within a completion string. In instances where there is “A” annulus pressure build up, such as when excess annulus fluid may expand as injection stops and when such excess annulus fluid goes back to geothermal temperature, it is possible that tubing integrity issues may occur. Features herein for side-pocket mandrels (SPM) 718 in a tubing string can provide automated venting of the annulus pressure into a tubing string at pre-set levels using an annulus vent/injection line of the wellhead block. Such SPMs or similar features are qualified as barriers when the venting feature is closed.

In instances where other annuli are required to be monitored, such monitoring can be performed using electronic signaling/proximity sensors that allow feedback through a tubing hanger via the Downhole Pressure & Temperature gauges (DHPT) cable and termination 720, as illustrated and which is another access path of the wellhead block.

Further, the wellhead block may be prepared with additional sensors, such as an Upstream of Choke Pressure and Temperature transducers (UPT) 722 and a Downstream of Choke Pressure and Temperature transducers (DPT) 720 to determine cavity pressures. Access between points of monitoring within a well and the sensors is enabled by one or more access paths of the wellhead block.

In at least one embodiment, well control can be performed through several available options on the wellhead block. The options include direct control from a host location; control using a Subsea Control Module (SCM) located within the wellhead block as discussed with respect to FIGS. 2 and 6A; control using an SCM that is specifically on a manifold (such as a manifold module) and that includes a flying lead 710 between the wellhead block and the well via MQC connection; and control using an SCM within a protection structure.

In at least one embodiment, other control configurations may be enabled using the wellhead block, including control using an SCM on a wellhead block or on a manifold being shared for the wellhead block 702 and for the well to enabled manifold control operations. Where an Integrated Template Solution (ITS)/Multi-flowbase (MFB) 210 is used with multiple wells that are configured adjacent to one another, the SCM may be placed to allow shared use between multiple wells as discussed with respect to the embodiment in FIG. 2.

In at least one embodiment, a hub (such as in FIG. 8) may be provided on the wellhead block. Such a hub may be a wellhead cap to allow for attachment of such items as choke hub connection and Riserless Light Well Intervention (RLWI) packages that share a common profile for attachment with the wellhead cap. In at least one embodiment, common to all configurations in FIGS. 2 and 4A-6 (also FIGS. 7-11) is that the wellhead blocks provided can be mated with a fishing protection system, if so required while being fixed to a wellhead. This feature protects a wellhead and protects the wellhead blocks provided for the wellhead.

In at least one embodiment, a simple landing ring may be landed over a low pressure wellhead housing (“LP Hsg”) 806 and supported by a high pressure wellhead housing (“LP Hsg”) 808 (such as marked in FIG. 8 but also available but not marked in FIG. 7) with an arm for a flowline connection support where there is no requirement for a fishing protection system that may be used in satellite well applications to assist in supporting a flowline connection. In addition to individual satellite well applications, the wellhead blocks may also be located in the ITS/MFB with a remote connection to tie in to one or more flow paths (or access paths).

In at least one embodiment, a tubing hanger may use an Annulus Isolation device (AID) for isolation of the annulus prior to installation of a wellhead block. The AID can also be operated using a Tubing Hanger Running tool that can enable the annulus to be accessed/displaced during completion installation activities.

In at least one embodiment, a tubing hanger may include a passage for hydraulic control lines capable of such functions as operating one or more of SCSSVs, SSVs, and other downhole hydraulic functions. Further, a Downhole Pressure & Temperature gauges (DHPT) or Fiber Optic (FO) signal may be provided through the wellhead blocks to monitor formation pressures/temperatures.

FIG. 7 illustrates, in further detail 700, the configuration of FIG. 4A of a wellhead block associated with a well, in at least one embodiment. For purposes of well intervention, a wellhead block 702 may be temporarily removed allowing well bore access using a RLWI attached to a hub of the wellhead block 702. The RLWI may be replaced after such intervention. This configuration uses a barrier subsystem of two isolation gate valves (valve with actuator 704) for well intervention. In at least one embodiment, therefore, if the wellhead block 702 is a two-component structure then only the hub may be temporarily removed and then replaced after intervention is completed.

In at least one embodiment, FIG. 7 also depicts a gate wellhead block forming the wellhead block component of the wellhead block 702. The gate wellhead block includes a connector bottom. The gate wellhead block may be a clamp and hub subsystem which supports a choke valve 706 and a side flow path for a flowline connection, as also illustrated. A concentric bore may be accessed via the wellhead block. The concentric bore may include two main barriers that are electrically and/or hydraulically operated for isolation purposes.

In at least one embodiment, the wellhead block 702 supports exit terminations for bore and supports access paths 712 for DPTs, APTs, DHPTs/FOs, Downstream PT (DPT) sensors to monitor line pressures, SCSSVs function line port with isolation, AID Function line port with isolation, injection treatment and vent points, annulus vent/injection port with isolation, and lines that are run to at least a mini MQC.

In at least one embodiment, a wellhead cap may include or be supported by a 720 monobore hub connection and one or more injection insert-retrievable choke valves adapted for electrical and/or hydraulic operation. In at least one embodiment, a Flow-Over operation may be enabled by the wellhead block 702. Further, a simple flow spool may be provided for the wellhead block 702 to import supply. This may be a diver flange or a remote vertical or horizontal connection.

Still further, an Upstream PT (UPT) sensor enables monitoring of line pressure in the access paths or in the well. The wellhead block 702 or its components may be run as one with a choke valve and a flow spool as illustrated by the features in FIG. 2. The flow spool can be with a flange or a VCCS support for ITS/MFB use. As illustrated in these figures, an option is provided for use of the SPFM in a flow spool. There are also options for using a Side Pocket Mandrel (SPM) in a tubing string for automated equalizing of the A-annulus.

FIG. 8 illustrates, in further detail 800, the configuration of FIG. 4B of a wellhead block associated with a well, in at least one embodiment. In this configuration, for the purpose of well intervention, the wellhead block 802 may be a single structure (including a 720 hub) without a separate gate wellhead block and a valve wellhead block. Components described in FIG. 7 may be used in FIG. 8, as readily understood to a skilled artisan upon reviewing the disclosure herein and so such components are not marked. Also, in this configuration in FIG. 8, a barrier subsystem of two isolation gate valves (valve with actuators 804) may be used for well intervention. An insert choke 810 may be temporarily removed from the wellhead block 802, which combination is the wellhead block 802 and which removal of at least the insert choke then allows well bore access using a RLWI attached to a top of the wellhead block 802. The choke insert may be replaced after such intervention.

In at least one embodiment, the wellhead block 802 includes a connector bottom, a clamp and hub subsystem top, and access paths for a concentric bore having two main barriers that may be electrically or hydraulicly operated for isolation purposes. Further, the wellhead block 802 may include access paths with exit terminations for one or more of: a bore DPT, an APT, a DHPT/FO, a Downstream PT (DPT) sensor to monitor line pressure of an annulus region, an SCSSV function line port with isolation, an AID Function line port with isolation, an injection treatment/vent point, an annulus vent/injection port with isolation, and for lines that run to at least a mini MQC. Further, the 720 hub of the wellhead block 802 may include a 720 monobore hub connection and an injection insert-retrievable choke valve (altogether referred to as the choke/insert retrievable with 720 hub or a wellhead block 802), along with support for electrical and/or hydraulic operation.

For a flow-over operation, a simple flow spool may be used to import supply. This may be a diver flange or remote vertical or horizontal connection. An Upstream PT (UPT) sensor may be associated with the wellhead block 802 to monitor line pressure. The wellhead block 802, along with the choke valve and the flow spool may be run as one unit. The flow spool can be used with a flange or VCCS for ITS/MFB application. In at least one embodiment, there is an option to use an SPFM in a flow spool. There is a further option of using a Side Pocket Mandrel (SPM) in a tubing string for automated equalizing of A-annulus.

FIG. 9 illustrates, in further detail 900, the configuration of FIG. 5A of a wellhead block associated with a well, in at least one embodiment. In this configuration, for the purpose of well intervention, instead of the wellhead block 902 being addressed, the choke insert can remain in place on a side and a top of a clamp and hub subsystem 908 (generally referred to by the wellhead block having a 720 hub top) may be addressed using an RLWI. Further, this configuration may use crown plugs 904 with a single isolation gate valve (valve with actuator 906) as a barrier subsystem to provide barriers. For bore access, the RLWI can be attached to the top of the clamp and hub subsystem of the wellhead block. This enables retrieval of the crown plugs for intervention purposes. In this configuration, a choke insert would only be recovered due to a failure in the choke, such as a wear-related failure.

In this configuration, the wellhead block 902 further includes a connector bottom, a clamp and hub subsystem top, and access paths for a concentric bore with two main barriers that may be electrically and/or hydraulicly operated for isolation purposes. The wellhead block 902 includes access paths and exit terminations for a bore DPT, an APT, a DHPT/FO, an SCSSV function line port with isolation, an AID Function line port with isolation, an injection treatment and/or vent point, an annulus vent/injection port with isolation, and lines that can be run to at least one mini MQC.

Still further, the wellhead block 902 includes or is associated with (and supported by) an injection insert-retrievable choke valve 910 capable of electrical and/or hydraulic operation. For flow-over operations, a simple flow spool is provided to import supply. This may be a diver flange or a remote vertical or horizontal connection. The wellhead block 902 may include an Upstream PT (UPT) and a Downstream PT (DPT) sensors to monitor line pressures. The flow spool may be a flange or VCCS for ITS/MFB use. This configuration may be provided with an option to use an SPFM in a flow spool and an option to use a Side Pocket Mandrel (SPM) in a tubing string for automated equalizing of an A-annulus.

FIG. 10 illustrates, in further detail 1000, the configuration of FIG. 5B of a wellhead block associated with a well, in at least one embodiment. In this configuration, for the purpose of well intervention, instead of the wellhead block 1002, a clamp and hub subsystem 1010 may be temporarily removed. This allows well bore access using an RLWI attached to an upper hub of the subsystem 1010. Replacement of the removed part may be performed, after such intervention is completed. This configuration may not use any isolation gate valves 1014 (or may use it as an option) and may instead use plugs 1008, which are supported further by upper and lower subsea valves 1004, 1006.

The wellhead block 1002 includes a connector bottom, a clamp and hub subsystem top, and access paths to a concentric bore with the sub-surface valves. The wellhead block 1002 may be associated with (and supported by) a choke 1012 in a combination that is placed within a master valve block (MVB). The wellhead block 1002 includes support for an injection insert-retrievable choke 1012 that may be electrically and/or hydraulically operated.

In at least one embodiment, a flow-over operation may be performed using a simple flow spool-to-import a connection. The wellhead block 1002 may include or be supported by an Upstream PT (UPT) and a Downstream PT (DPT) sensor to monitor line pressures. The wellhead block 1002 may include or be supported by exit terminations for a bore DPT, an APT, a DHPT/FO, an SCSSV function line port with isolation, an upper subsea valve function line port with isolation, a lower subsea valve function line port with isolation, an AID Function line port with isolation, an injection treatment/vent point, an annulus vent/injection port with isolation, and with lines that are run to at least one mini MQC.

In at least one embodiment, the simple flow spool can import supply. This may be using diver flange or remote a vertical or horizontal connection. The flow spool can be provided with a flange or VCCS for ITS/MFB use. In at least one embodiment, options are available in this configuration for an SPFM in a flow spool and for using a Side Pocket Mandrel (SPM) in a tubing string for automated equalizing of an A-annulus.

FIG. 11 illustrates, in further detail 1100, the configuration of FIG. 6 of a wellhead block 1102 associated with a well, in at least one embodiment. In this configuration, for the purpose of well intervention, the insert-retrievable choke valve 1104 is provided as illustrated in multiple optional locations and can be temporarily removed allowing well bore access using an RLWI attached to an upper hub and that can be replaced after such intervention. Like in FIG. 13, this configuration uses isolation gate valves 1106 in one of different locations as illustrated in FIG. 6 but may not use plugs. This configuration may be supported further by upper and lower subsea valves and may use an integral choke valve 1104 within the wellhead block 1102 that may include a 720 hub top.

The wellhead block 1102 may further include a connector bottom, a clamp and hub subsystem top, and access paths to a concentric bore having sub-surface valves. In this configuration, an integral choke valve 1104 may be provided with respect to the wellhead block 1102. For example, the integral choke valve 1104 may be located within the wellhead block 1102. Further, the choke valve 1104 may be an injection insert-retrievable choke valve supported by electrical and/or hydraulic operation.

In at least one embodiment, a flow-over operation is supported by a simple flow spool-to-import connection. Further, the wellhead block 1102 may include an Upstream PT (UPT) and a Downstream PT (DPT) sensor to monitor line pressure associated with the access paths. The wellhead block 1102 may include exit terminations for a bore DPT, an APT, a DHPT/FO, an SCSSV function line port with isolation, an upper subsea valve function line port with isolation, a lower subsea valve function line port with isolation, an AID Function line port with isolation, an injection treatment/vent point, an annulus vent/injection port with isolation, and lines to be run to at least one mini MQC.

In at least one embodiment, a simple flow spool-to-import supply, such as a diver flange or a remote vertical or horizontal connection may be used. The flow spool can be with used with a flange or a VCCS for ITS/MFB use. This configuration supports options for using an SPFM in the flow spool and for using a Side Pocket Mandrel (SPM) in the tubing string for automated equalizing of an A-annulus.

FIG. 12 illustrates a method 1200 for carbon capture and storage in a depleted hydrocarbon reservoir or dedicated aquifer, according to at least one embodiment. The method 1200 includes providing (1202A) a wellhead block to comprise or support a barrier subsystem having one or more of at least one isolation gate valve or one or more plugs. The method 1200 includes associating (1202B) the barrier subsystem with the wellhead block to allow access to a well that is associated with the depleted hydrocarbon reservoir or dedicated aquifer. In at least one embodiment, the steps 1202A and 1202B may be performed together, with the providing (1202A) step including the barrier system being associated with the wellhead block.

In at least one embodiment, the features of the wellhead block includes one or more modulation valves to modulate an injection of a wellhead fluid comprising a carbon component into a side of the well and includes one or more access paths. The method 1200 includes monitoring (1204), using at least one flow measurement device, individual well injection rates for the wellhead fluid into the depleted hydrocarbon reservoir or dedicated aquifer.

In at least one embodiment, the method 1200 includes verifying (1206) that a change is detected or that a change is to be applied to the individual well injection rates. Step 1204 may be repeated to continue monitoring. In at least one embodiment, the method 1200 includes modulating (1208), using one or more modulation valves, an injection of a wellhead fluid comprising a carbon component into the wellhead block. The modulating (1208) feature may be a change in the injection of the wellhead fluid based at least in part on the individual well injection rates.

Terms such as a, an, the, and similar referents, in context of describing disclosed embodiments (especially in context of following claims), are understood to cover both singular and plural, unless otherwise indicated herein or clearly contradicted by context, and not as a definition of a term. Including, having, including, and containing are understood to be open-ended terms (meaning a phrase such as, including, but not limited to) unless otherwise noted. Connected, when unmodified and referring to physical connections, may be understood as partly or wholly contained within, attached to, or joined, even if there is something intervening.

Recitation of ranges of values herein are merely intended to serve as a shorthand method of referring individually to each separate value falling within range, unless otherwise indicated herein and each separate value is incorporated into specification as if it were individually recited herein. In at least one embodiment, use of a term, such as a set (for a set of items) or subset unless otherwise noted or contradicted by context, is understood to be nonempty collection including one or more members. Further, unless otherwise noted or contradicted by context, term subset of a corresponding set does not necessarily denote a proper subset of corresponding set, but subset and corresponding set may be equal.

Conjunctive language, such as phrases of form, at least one of A, B, and C, or at least one of A, B and C, unless specifically stated otherwise or otherwise clearly contradicted by context, is otherwise understood with context as used in general to present that an item, term, etc., may be either A or B or C, or any nonempty subset of set of A and B and C. In at least one embodiment of a set having three members, conjunctive phrases, such as at least one of A, B, and C and at least one of A, B and C refer to any of following sets: {A}, {B}, {C}, {A, B}, {A, C}, {B, C}, {A, B, C}. Thus, such conjunctive language is not generally intended to imply that certain embodiments require at least one of A, at least one of B and at least one of C each to be present. In addition, unless otherwise noted or contradicted by context, terms such as plurality, indicates a state of being plural (such as, a plurality of items indicates multiple items). In at least one embodiment, a number of items in a plurality is at least two but can be more when so indicated either explicitly or by context. Further, unless stated otherwise or otherwise clear from context, phrases such as based on means based at least in part on and not based solely on.

Operations of methods in the Figures described herein can be performed in any suitable order unless otherwise indicated herein or otherwise clearly contradicted by context. In at least one embodiment, a method includes processes such as those processes described herein (or variations and/or combinations thereof) that may be performed under control of one or more computer systems configured with executable instructions and that may be implemented as code (e.g., executable instructions, one or more computer programs or one or more applications) executing collectively or exclusively on one or more processors, by hardware or combinations thereof.

In at least one embodiment, such code may be stored on a computer-readable storage medium. In at least one embodiment, such code may be a computer program having instructions executable by one or more processors. In at least one embodiment, a computer-readable storage medium is a non-transitory computer-readable storage medium that excludes transitory signals (such as a propagating transient electric or electromagnetic transmission) but includes non-transitory data storage circuitry (such as buffers, cache, and queues) within transceivers of transitory signals. In at least one embodiment, code (such as executable code or source code) is stored on a set of one or more non-transitory computer-readable storage media having stored thereon executable instructions (or other memory to store executable instructions) that, when executed (such as a result of being executed) by one or more processors of a computer system, cause computer system to perform operations described herein.

In at least one embodiment, a set of non-transitory computer-readable storage media includes multiple non-transitory computer-readable storage media and one or more of individual non-transitory storage media of multiple non-transitory computer-readable storage media lack all of code while multiple non-transitory computer-readable storage media collectively store all of code. In at least one embodiment, executable instructions are executed such that different instructions are executed by different processors—in at least one embodiment, a non-transitory computer-readable storage medium store instructions and a main central processing unit (CPU) executes some of instructions while other processing units execute other instructions. In at least one embodiment, different components of a computer system have separate processors and different processors execute different subsets of instructions.

In at least one embodiment, computer systems are configured to implement one or more services that singly or collectively perform operations of processes described herein and such computer systems are configured with applicable hardware and/or software that enable performance of operations. In at least one embodiment, a computer system that implements at least one embodiment of present disclosure is a single device or is a distributed computer system having multiple devices that operate differently such that distributed computer system performs operations described herein and such that a single device does not perform all operations.

In at least one embodiment, even though the above discussion provides at least one embodiment having implementations of described techniques, other architectures may be used to implement described functionality, and are intended to be within scope of this disclosure. In addition, although specific responsibilities may be distributed to components and processes, they are defined above for purposes of discussion, and various functions and responsibilities might be distributed and divided in different ways, depending on circumstances.

In at least one embodiment, although subject matter has been described in language specific to structures and/or methods or processes, it is to be understood that subject matter claimed in appended claims is not limited to specific structures or methods described. Instead, specific structures or methods are disclosed as example forms of how a claim may be implemented.

From all the above, a person of ordinary skill would readily understand that the tool of the present disclosure provides numerous technical and commercial advantages and can be used in a variety of applications. Various embodiments may be combined or modified based in part on the present disclosure, which is readily understood to support such combination and modifications to achieve the benefits described above.

WELLHEAD SYSTEM AND METHOD FOR CARBON CAPTURE AND STORAGE

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