Patent Application
20100059230
Not applicable.
The disclosed subject matter relates generally to field of subsea oil and gas production and, more particularly, to a coil tubing guide.
Offshore oil and gas wells may generally be divided into two groups—surface piercing wells and subsea wells. Surface piercing wells are wells that are located on an artificial surface above sea level that is supported by a fixed structure (e.g., a floating platform) or a floating structure (e.g., a spar, a semi-submersible, a tension leg platform, a vessel, a barge, etc.). Subsea wells reside on the sea floor, including their wellhead structure and valving control (subsea Christmas tree).
Often during the life of a well, intervention into the well bore may be required for a variety of reasons. For example, an intervention may be required to diagnose a problem, correct a problem, stimulate production, and/or repair equipment within the well bore. Performing intervention operations on surface piercing wells is very straightforward as surface piercing wells are easily accessed through the top of the Christmas tree (located on the artificial surface) using traditional means developed for land-based wells, e.g., a lubricator, pressure containment assembly (wireline rams), and one or more lifting devices. Such operations can be performed at a relatively low cost due to the ready accessibility to the top of the Christmas tree on such surface piercing wells and the equipment used in performing such interventions.
However, intervention on subsea wells is much more difficult and expensive. Intervention of a subsea well frequently requires the rental and use of a surface vessel, a completion/workover riser, both surface and subsea pressure containment assemblies (i.e., a surface tree that mimics a surface piercing Christmas tree—so that workover hardware can be attached), and a lower workover riser package. The lower workover riser package includes a lower riser package with actuated pressure containment rams and an emergency disconnect package for well control to allow surface access to the subsea Christmas tree. Equipment used in such subsea intervention projects may not be readily available and they are much more expensive than their land-based counterparts. Moreover, intervention on a subsea well is much more complex and involved as compared to intervention projects on surface piercing wells. Thus, intervention on subsea wells may be delayed or not performed at all, or the subsea wells may simply be allowed to operate inefficiently.
So-called light well intervention was initially introduced in the North Sea in an effort to increase accessibility and reduce the costs associated with intervention of a subsea well. Generally, lightweight well intervention involves the use of a relatively small work vessel with moderate lifting capacity to go to the offshore site and lower a lightweight intervention package (LIP) on guidelines down to a subsea tree that is coupled to a well at the sea floor. Then a simple “wireline” intervention via a subsea lubricator is used to enter the well. The subsea version is an adaptation of the traditional equipment used on surface piercing wells. However, lightweight wireline work only addresses 60-70% of the types of well intervention missions oil companies are interested in employing. For the remaining 30%, oil companies rely on coil tubing (CT) intervention.
Coil tubing operation is a unique intervention method because it introduces a continuous hollow tube as the intervention string which can provide fluids, pressure, and circulation capabilities that wireline intervention methods cannot. As a result, coil tubing operations require a circulation return line of some sort to complete the hydraulic circuit as fluids are sent down the coil tubing. Usually the return fluid is captured and transmitted via the completion workover riser made from alloy steel pipe (i.e., threaded or clamped together—much like drill pipe), or more exotically, via a concentric tube made from a composite or flexible pipe, or third, by placing the reel containing the coil tubing on the sea floor near the subsea well.
The weight of the completion workover riser and the weight of its concentric outer tube causes a technical issue for smaller vessels associated with light well intervention. These smaller ship-shaped vessels have minimal draft displacement to apply sufficient tension on the top of the riser tube to keep it structurally stable in the water column and limited deck capacity to accommodate the amount of riser tube necessary, along with the coil tubing reels and surface equipment. The tension and deck load problems are exacerbated as water depth increases and environments grow more severe.
Another issue with conventional coil tubing implementations using concentric risers arises due to movement of the coil tubing. As the coil tubing moves into or out of a concentric conduit (e.g., riser or concentric tube) it tends to carry the return fluid in the direction the coil tubing is moving (i.e., into or out of the well). This tends to build up a lower pressure in the return fluid at the top end of the riser and a higher pressure at the bottom or delivery end of the riser. The imbalanced pressures at either end increase as the velocity of the coil tubing movement increases. During rapid deployment or retrieval (i.e., to save trip time) the higher imbalanced pressure may cause seal degradation at the point where the coil tubing is snubbing into the well.
This section of this document is intended to introduce various aspects of art that may be related to various aspects of the disclosed subject matter described and/or claimed below. This section provides background information to facilitate a better understanding of the various aspects of the disclosed subject matter. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art. The disclosed subject matter is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.
The following presents a simplified summary of the disclosed subject matter in order to provide a basic understanding of some aspects of the disclosed subject matter. This summary is not an exhaustive overview of the disclosed subject matter. It is not intended to identify key or critical elements of the disclosed subject matter or to delineate the scope of the disclosed subject matter. Its sole purpose is to present some concepts in a simplified form as a prelude to the more detailed description that is discussed later.
One aspect of the disclosed subject matter is seen in a guide system. The guide system includes a flexible pipe and a plurality of bend restrictor members disposed along the flexible pipe. The bend restrictor members define a first channel and are operable to limit a degree of bending present in the first channel.
Another aspect of the disclosed subject matter is seen an apparatus for interfacing with a subsea well. The apparatus includes a flexible pipe extending from a surface vessel to the subsea well. A plurality of bend restrictor members is disposed along the flexible pipe and defines a first channel. The bend restrictor members are operable to limit a degree of bending present in the first channel. Coil tubing extends from the surface vessel to the subsea well through the first channel.
Yet another aspect of the disclosed subject matter is seen in a method for interfacing with a subsea well. The method includes providing a plurality of bend restrictor members disposed along a flexible pipe and defining a first channel. The bend restrictor members are operable to limit a degree of bending present in the first channel. The flexible pipe is attached to the subsea well. Coil tubing is inserted from a surface vessel to the subsea well through the first channel to interface with the subsea well.
The disclosed subject matter will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and:
While the disclosed subject matter is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the disclosed subject matter to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosed subject matter as defined by the appended claims.
One or more specific embodiments of the disclosed subject matter will be described below. It is specifically intended that the disclosed subject matter not be limited to the embodiments and illustrations contained herein, but include modified forms of those embodiments including portions of the embodiments and combinations of elements of different embodiments as come within the scope of the following claims. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. Nothing in this application is considered critical or essential to the disclosed subject matter unless explicitly indicated as being “critical” or “essential.”
The disclosed subject matter will now be described with reference to the attached figures. Various structures, systems and devices are schematically depicted in the drawings for purposes of explanation only and so as to not obscure the disclosed subject matter with details that are well known to those skilled in the art. Nevertheless, the attached drawings are included to describe and explain illustrative examples of the disclosed subject matter. The words and phrases used herein should be understood and interpreted to have a meaning consistent with the understanding of those words and phrases by those skilled in the relevant art. No special definition of a term or phrase, i.e., a definition that is different from the ordinary and customary meaning as understood by those skilled in the art, is intended to be implied by consistent usage of the term or phrase herein. To the extent that a term or phrase is intended to have a special meaning, i.e., a meaning other than that understood by skilled artisans, such a special definition will be expressly set forth in the specification in a definitional manner that directly and unequivocally provides the special definition for the term or phrase.
Referring now to the drawings wherein like reference numbers correspond to similar components throughout the several views and, specifically, referring to
In the illustrated embodiment, the LIP 125 includes a guide member 130, a snubbing injecting unit 135, and a lower riser package (LRP) 138. The LRP 138 may include interface equipment to allow interacting with the well 110 through a production access bore, such as wire cutting/sealing valves (or other sealing devices), crossover/circulation valves, recirculation valves, chemical injection valves, etc., as is known in the art. The subbing injecting unit 135 provides an interface by which coil tubing 140 may be connected for performing various well intervention activities. A work vessel 145 positioned on the sea surface proximate the well 110 employs a coil tubing guide system 150 coupled to the LRP 138 to allow the coil tubing 140 to be extended down to the well 110 and interface with the LIP 125 through the guide 130. A surface injector unit 152 may be provided to insert and/or withdraw the coli tubing 140 from the coil tubing guide system 150.
The subsea Christmas tree 120 and lightweight intervention package (LIP) 125 are intended to be representative in nature. That is, they are intended to encompass any of a variety of different structures that may be operatively coupled to the well 110. For example, the subsea Christmas tree 120 typically comprises a plurality of valves that are used in controlling the production from the well 110. The subsea Christmas tree 120 may be of any desired shape or configuration (e.g., horizontal, vertical, etc.). Similarly, the LIP 125 is intended to generically represent any type of equipment that may be operatively coupled to the well 110 during an intervention process. It should be understood that
The coil tubing guide system 150 includes a plurality of bend restrictor members 155 coupled to a return line 160. An upper guide member 165 is also provided to aid in aligning the coil tubing 140 with a channel (shown in
The coil tubing guide system 150 may be connected to the LIP 125 using various techniques. In one embodiment, a winch line (not shown), sheaved at the LRP 138 may be used to pull the coil tubing guide system 150 down to the subsea well 110. Using this arrangement, the coil tubing guide system 150 may be assembled to the appropriate length and towed behind the work vessel 145 to the site of the subsea well 110. The winching system may guide a connector on the LRP 138 into engagement with a corresponding connector on an end of the return line 160. Alternatively, a remotely operated vehicle (ROV) may be used to complete the engagement.
The assembly process for the coil tubing guide system 150 includes providing a return line of a length appropriate for reaching the well 110. In the illustrated embodiment, the return line 160 is a flexible pipe, such as COFLON flexible pipe offered by Technip headquartered in Paris, France, or a different flexible pipe that may meet the standards set forth in API 17 B and API 17 J issued by the American Petroleum Institute under the titles “Recommended Practice for Flexible Pipe” and “Specification for Unbonded Flexible Pipe”. The individual members 200, 205 that make up each bend restrictor member 155 are positioned along the length of the return line 160. The pins 225 may be placed within the pin recesses 220 to align the coil tubing channel 210. Generally, the maximum bend radius of the coil tubing guide system 150 may be controlled based on the length and diameter of the bend restrictor members 155, the dimensions of the channels 210, 215, and the spacing between adjacent bend restrictor members 155. The size of the bend restrictor members 155 and the relative sizes of the coil tubing channel 210 and return line channel 215 may be selected to accommodate any size return line 160 and or coil tubing 140. The bend restrictor dimensions, channel dimensions, and/or spacing may be varied along the length of the coil tubing guide system 150 to provide different shapes in the water column (i.e., different maximum bend radii at different places). The maximum bend radii is also selected to provide a geometry that prevents compressive buckling of the coil tubing 140 is it is inserted into the LIP 125, subsea Christmas tree 120, and subsea well 110. Hence, the maximum bend radius is typically less than a buckling radius of the coil tubing 140, which may vary depending factors such as the material, wall thickness, radius, etc., of the coil tubing 140.
Generally, the materials selected for the bend restrictor members 155 provide an overall density that is less than seawater (i.e., <64 lb/ft3). Due to this characteristic, bend restrictor members 155 provide sufficient buoyancy to fully support their weight and the weight of the return line 160 with some residual buoyancy to provide some hydrodynamic stability in the water column between the work vessel 145 and the subsea Christmas tree 120. The work vessel 145 and associated tension control equipment need only support the fluid column weight present in the return line 160.
In the illustrated embodiment, the return line channel 215 is sized such that it is slightly smaller than the outside diameter of the return line 160 to provide an interference fit. Ribs (not shown) may be provided in one or more positions along the return line channel 215 to enhance the fit. Alternatively, other retention techniques may be used to retain the bend restrictor members 155 in the proper position, such as clamps (not shown) positioned between bend restrictor members 155. In such an embodiment, the clamps (not shown) may also be adapted to perform the anti-rotational functions of the pins 225. In some embodiments, the return line channel 215 may also be sized and shaped to support other lines, such as strength members (e.g., rope), electrical, umbilical, or chemical injection lines bundled with the return line 160.
After the coil tubing guide system 150 has been assembled and installed beneath the vessel 145, the buoyancy helps keep the coil tubing guide system 150 upright and the alignment provides a simple pathway for the coil tubing 145 to travel the length of the water column down to the subsea well 110. Because the coil tubing 140 is structurally supported and enclosed by the bend restrictor members 155, the coil tubing 140 is protected from damaging environmental loads. The coil tubing 140 follows the coil tubing channels 210 of the bend restrictor members 155 to the guide member 130, which directs the coil tubing 140 to the snubbing injecting unit 135. Because the coil tubing guide system 150 is not pressure or fluid containing ram equipment is not required at the surface. As seen in
Referring to
The snubbing injecting unit 135 includes a snubber element 430 for sealing around the coil tubing 140 and an injecting unit 440 for applying motive force on the coil tubing to provide for inserting or ejecting the coil tubing 140. In general, the injecting unit 440 includes opposed endless belts that pass around rollers that are hydraulically or electromagnetically driven to move the coil tubing 140. The snubbing injecting unit 135 may also include a chemical injection recirculation valve 450 to allow various chemicals to be introduced into the well or for flushing the snubbing injecting unit 135.
Depending on the particular type of intervention, the equipment attached to the LRP 138 may be varied. For example, for a wireline intervention a lubricator may be coupled to the LRP 138 to allow a wireline tool to interface with the LRP 138. The LRP 138 may also be used to connect to a full completion workover riser. If the intervention type is changed, the LIP 125 may be readily configured to receive a different type of interface, such as the snubbing injecting unit 135.
The injecting unit 440 may be configured to operate in concert with the surface injecting unit 152 to maintain proper tension in the coil tubing 140. During an emergency disconnect event, cutting valves in the LRP 138 may shear the coil tubing, and the injecting unit 440 may eject the coil tubing 140 regardless of whether the coil tubing 140 is in compression or tension prior to the cutting to allow isolation valves in the LRP 138 to provide the pressure boundary for isolating the subsea well 110. An isolation valve may also be provided in the LRP 138 for isolating the return line port 420.
The coil tubing guide system 150 described herein provides numerous advantages. The bend restrictor members 155 provide lateral stability within the coil tubing channel 210 to keep the coil tubing 140 from buckling. The coil tubing channel 210 and its tapered ends 230 may be coated or sleeved with a lower friction, wear resistant material to augment of conveyance of the coil tubing 140 through the channel 210, 230 and lessen the possibility of damage to the bend restrictor members 155. Also, the bend ratio of the coil tubing guide system 150 may be varied depending on the size and placement of the bend restrictor members 155. The coil tubing guide system 150 eliminates the need for specialized high pressure containing piping seen in concentric risers. The elimination of the high pressure piping also eliminates the need for surface rams and/or snubbing units. The gaps in the coil tubing guide system 150 between the bend restrictor members 155 allow sea water surrounding the coil tubing to circulate and enter/leave the coil tubing channel 210 anywhere along the length of the coil tubing guide system 150, eliminating the phenomenon where circulated fluid coming back from the well 110 follows the movement of the coil tubing 140. The buoyancy of the coil tubing guide system 150 greatly reduces the weight supported by the work vessel 145. The modular nature of the bend restrictor members 155 and return line 160 provides for easy and cost-effective maintenance, as only broken or worn parts need to be replaced. Also, the coil tubing guide system 150 is separate from the coil tubing 140, allowing the appropriate size, strength, and pressure ratings for the coil tubing 140 to be varied for the particular intervention.
The particular embodiments disclosed above are illustrative only, as the disclosed subject matter may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the disclosed subject matter. Accordingly, the protection sought herein is as set forth in the claims below.
