U.S. Pat. No. 11,767,754, issued on Sep. 26, 2023 to Kalb et al., teaches a downhole fiberoptic transmission for real-time well monitoring and downhole equipment actuation. The subsea wellhead system includes a tubing hanger landed in a wellhead. The tubing hanger has a first fiberoptic cable. A tree is landed on the tubing hanger, and a transducer is disposed at a downhole location. The tree comprises a second fiberoptic cable. The first fiberoptic cable is communicatively coupled to the transducer and extends between the transducer and the seal sub. The seal sub is landed in the tubing hanger. The seal sub includes a first fiberoptic communications line that is communicatively coupled to the first fiberoptic cable and the second fiberoptic cable. The seal sub and the tubing hanger form an electrical connection regardless of an orientation of the tubing hanger relative to the tree.

U.S. Patent Application Publication No. 2004/0020653, published on Feb. 5, 2040 to D. R. Smith, provides a method and apparatus to monitor, control and log subsea oil and gas wells. This method allows logging tools, wire rope, optical fibers, electrical cables, monitoring and measuring instruments, and other items to be disposed into the well without interfering with the flow path through the production string. An instrument pod is moored or tethered over the subsea well. The instrument pod is designed to provide on-board data storage, data processing, data receiving and data transmission equipment, such that the data from the well can be transmitted back to a receiving network. The data can be stored and processed as useful information for reservoir operators.

U.S. Patent Application Publication No. 2008/0272931, published on Nov. 6, 2008 to Auzerais et al., provides a method and apparatus for measuring parameters within a well. This system includes a first apparatus having a first reel of a first wound fiberoptic line and at least one sensor able to measure the parameter of the well. The information on this parameter can be transmitted through the first optical fiber. A second apparatus includes a second reel of a wound optical fiber that is able to unwind from a second reel. An extremity of the second optical fiber is fixed to a reference point. A light transmitter or receiver device is linked to the reference point and is able to generate or detect a light pulse through the second optical fiber line. There is a means to exchange the light pulse between the first and second optical fibers.

U.S. Patent Application Publication No. 2021/0140310, published on May 13, 2021 to Kalb et al., discloses a system and method for real-time monitoring of well conditions and actuation of downhole equipment. The subsea wellhead system includes a tubing hanger landed on a wellhead. The tubing hanger includes a first fiberoptic cable, and a tree is landed on the tubing hanger. The tree has a second fiberoptic cable. A transducer is disposed at a downhole location. The first fiberoptic cable is communicatively coupled to the transducer and extends between the transducer and the seal sub. The seal sub is landed in the tubing hanger. The seal sub includes a first fiberoptic communications line that is communicatively coupled to the first fiberoptic cable and the second fiberoptic cable. The seal sub and the tubing hanger form an electrical connection regardless of an orientation of the tubing hanger relative to the tree.

SUMMARY OF THE INVENTION

It is an object of the present invention to provide a system and process for subsea fiberoptic logging which allows for the deployment and operation of a fiberoptic well logging tool in a subsea environment.

It is another object of the present invention to provide a system and process for the subsea fiberoptic logging which allows for real-time logging to a surface location.

It is another object of the present invention to provide a system and process for subsea fiberoptic logging which allows for data logging to be obtained subsea.

It is another object of the present invention to provide a system and process for subsea fiberoptic logging that facilitates subsea deployment and operation of a fiberoptic logging unit.

It is another object of the present invention to provide a system and process for subsea fiberoptic logging that provides the ability to conduct multiple deployments without recovering of the subsea structure to the surface.

It is another object of the present invention to provide a system and process for subsea fiberoptic logging which allows a subsea probe to be installed by a remotely-operated vehicle.

It is another object of the present invention to provide a system and process for subsea fiberoptic logging that provides the ability to change out the subsea probe in a quick, convenient, and easy manner.

It is a further object of the present invention to provide a system and process for subsea fiberoptic logging which allows for distributed pressure measurements sensing, distributed temperature sensing and distributed acoustic sensing within the well.

It is a further object of the present invention to provide a system and process for subsea fiberoptic logging which provides a rich well profile and a monitoring of changing conditions, irregularities, anomalies, or events.

It is still a further object of the present invention to provide a system and process for subsea fiberoptic logging which is adaptable to a subsea tree injection module mounted upon a wellhead or upon a subsea tree.

These and other objects and advantages of the present invention will become apparent from a reading of the attached specification and appended claims.

The present invention is a system for subsea fiberoptic logging of a well. The system includes a subsea structure having a central bore, an upper valve positioned on the central bore below an upper connector of the subsea structure, a lower valve positioned on the central bore below the upper valve, and a subsea probe releasably affixed to the upper connector of the subsea structure. The subsea structure has a lower connector at an end of the subsea structure opposite the upper connector. The subsea structure has at least one channel adapted to connect to a downline. The upper valve is movable between an open position and a closed position. The lower valve is also movable between an open position and a closed position. The channel opens to the central bore in an area between the upper valve and the lower valve. The subsea probe has a fiberoptic line connected thereto. This fiberoptic line is adapted to extend through a portion of the central bore of the subsea structure and into the well so as to sense parameters within the well.

The channel has an upper end positioned at or adjacent to a top of the subsea structure. The upper end of the channel is adapted to connect with the downline. The downline is, in particular, a length of coiled tubing. A passageway extends from the central bore or from the upper connector to the channel. The subsea probe has a housing receiving a portion of the fiberoptic line. The housing is separable from the subsea probe and is adapted to flow through the passageway to the channel. The housing and the fiberoptic line are extendable to the bottom of the well.

In the present invention, the subsea probe includes a connector releasably affixed to the upper connector of the subsea structure. A housing is releasably affixed to this connector and extends into a portion of the central bore of the subsea structure. The housing receives a portion of the fiberoptic line therein. The connector of the subsea probe has an interface at an outer surface thereof. The interface connects with the fiberoptic line. The interface is adapted to allow measurements from the fiberoptic line to be transmitted or transported to a surface location. The fiberoptic line has a probe tip positioned at or adjacent to a bottom of the housing. The probe tip is a single point sensor.

In one embodiment of the present invention, the subsea structure is a subsea tree injection module. A subsea tree has a connector at an upper end thereof. The lower connector of the subsea tree injection module is affixed to the connector of the subsea tree. Alternatively, there is a wellhead positioned on the surface location of a top of the well. The lower connector of the subsea structure is affixed to the wellhead. A subsea data acquisition unit is connected to or cooperative with the fiberoptic line. The subsea data acquisition unit is adapted to receive and process data received from the fiberoptic line.

The present invention is also a process for obtaining data from a fiberoptic line in a well. This process includes the steps of: (1) affixing the connector to a surface of the subsea structure such that the housing and the portion of the fiberoptic line extend into the central bore of the subsea structure; (2) releasing the housing from the connector such that the connector flows into the central bore of the subsea structure; (3) traveling the housing and the fiberoptic line from the central bore of the subsea structure and into the well; and (4) taking measurements from the fiberoptic line when the fiberoptic line is in the well.

The connector or the central bore has a passageway extending to the channel. A liquid flows into and through the channel and the lower valve is open such that the flowing liquid passes toward the well. The housing is released so as to flow through the passageway to the channel into the central bore in an area between the upper valve and the lower valve. The channel has a coiled tubing extending to a reservoir of liquid. A valve can be open to the channel so as to allow the liquid from the reservoir to flow into the central bore. The upper valve is opened while the lower valve is closed such that the liquid flows through the upper valve and into and through the passageway such that the housing and the portion of the fiberoptic line flows into the channel. The upper valve can be closed after the housing is released so as to stop fluid flow when the housing passes into the channel.

The lower valve is closed so as to shear the fiberoptic line such that the housing and the portion of the fiberoptic line remain at the bottom of the well. The connector is released from the subsea structure after the step of taking measurements. In particular, the upper valve is closed prior to the step of releasing the connector. The connector is actuated so as to separate the connector from a connector of the subsea structure. In the preferred embodiment of the present invention, the subsea structure is a subsea tree injection module that is adapted to connect to a subsea tree or to a wellhead.

This foregoing Section is intended to describe, with particularity, the preferred embodiments of the present invention. It is understood that modifications to this preferred embodiment can be made within the scope of the present claims. As such, this Section should not to be construed, in any way, as limiting of the broad scope of the present invention. The present invention should only be limited by the following claims and their legal equivalents.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is an upper perspective view showing a subsea injection module of the prior art.

FIG. 2 is a cross-sectional view of a fiberoptic probe of the prior art.

FIG. 3 is a cross-sectional view of a fiberoptic probe of the prior art as deployed within a well and connected to processing equipment.

FIG. 4 illustrates the fiberoptic probe of another embodiment of the prior art as installed within a wellbore.

FIG. 5 is a side elevational view, in partial cross-section, of the subsea tree injection module of FIG. 1 with modifications for the receipt of a fiberoptic probe of the present invention.

FIG. 6 is a schematic illustration of the components of the subsea tree injection module of the present invention as adapted for the receipt of the fiberoptic probe.

FIG. 7 is a side elevational view of the fiberoptic probe of the present invention.

FIG. 8 is a flow diagram showing, in particular, the flow of fluids within the subsea tree injection module and showing the deployment of the fiberoptic probe.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 5 shows a system 100 for subsea fiberoptic logging for a well. In particular, a subsea tree injection module 102 is particularly illustrated. This subsea tree injection module 102 is the “subsea structure” in accordance with the claims of the present invention. The subsea tree injection module 102 generally has the configuration of the subsea tree injection module 10 as illustrated in FIG. 1. However, there are variety of modifications to the subsea tree injection module 102 particularly adapted to the system 100 of the present invention. In particular, the subsea tree injection module 102 includes a central bore 104. Central bore 104 can be in the nature of a lubricator bore. The subsea tree injection module 102 includes an upper connector 106 and a lower connector 108. The subsea tree injection module 102 further includes a first channel 110 and a second channel 112. Channel 110 has an upper end 114 adapted to be connected to a downline (not shown). Similarly, the second channel 112 has an upper connector 116 adapted to be connected to a downline (not shown).

An upper valve 118 is positioned on the central bore 104 below the upper connector 106. This upper valve 118 is movable between an open position and a closed position. A lower valve 120 is positioned on the central bore 104 below the upper valve 118. The lower valve 120 is movable between an open position and a closed position. The channels 110 and 112 will open to the central bore 104 in an area 122 between the upper valve 118 and the lower valve 120.

A subsea probe (124; FIG. 7) is releasably affixed to the upper connector 106 of the subsea tree injection module 102. This subsea probe (124) will have the fiberoptic line connected thereto (as shown in the following drawings). This fiberoptic line is adapted to extend through a portion of the central bore 104 and into the well so as to sense parameters within the well. The connector 106 can be a TC2V inboard hub. The upper valve 118 and the lower valve 120 are ball valves.

The first channel 110 has an upper end positioned at or adjacent to the top 126 of the subsea tree injection module 102. The upper end of the first channel 110 is adapted to connect with a downline (not shown). This downline can be a length of coiled tubing.

As will be described hereinafter, a passageway (130; FIG. 6) extends from the central bore