US20130118757A1

US20130118757A1 - Control line protection

Info

Publication number: US20130118757A1
Application number: US13/261,503
Authority: US
Inventors: Mark Francis Barrilleaux; Daniel Ndzi Shirmboh; Jim W. Spearman
Original assignee: BP Exploration Operating Co Ltd
Current assignee: BP Exploration Operating Co Ltd
Priority date: 2010-05-04
Filing date: 2011-04-15
Publication date: 2013-05-16
Also published as: WO2011138574A3; GB201219659D0; GB2493663A; NO20121433A1; WO2011138574A2

Abstract

A control line protector for use with a tubing string, e.g. production tubing having at least one control line on an outer surface thereof is disclosed. The control line protector comprises a sleeve having a cylindrical rigid outer wall, the sleeve being locatable around the tubing string and the at least one control line, and a polymeric scaling element disposed, in use, between an inner surface of the outer wall of the sleeve and the tubing string, operable to substantially seal the space between the outer wall of the sleeve and the tubing string.

Description

The present invention relates to the protection of control lines, especially control lines for downhole equipment in oil and gas wells. The invention also relates to methods of safely opening a formation isolation valve in a well and to methods of safely removing tubing from a well.
In the oil and gas industry, it is known to provide control lines for downhole equipment along the outside of tubing. Typically, the control lines are clamped or strapped to the outside of the tubing. The control lines may be hydraulic or electrical or fibre optic. Typically, such control lines have diameters of from 0.25 inches (0.64 cm) to 0.5 inches (1.27 cm).
It is also known to group control lines into so-called flatpacks. A flatpack typically comprises a hard thermoplastic housing which encapsulates the control lines passing therethrough.
The more control lines that are incorporated within a flat-pack, the stiffer it becomes. Accordingly, there is a limit to the number of control lines that a flatpack may comprise before it becomes too stiff to be readily handled or manipulated, e.g. coiled and uncoiled with the tubing to which it is to be attached.
A typical flatpack comprises from 2 to 10, e.g. from 2 to 4, control lines. A three-line flatpack may comprise three 0.25 inch (0.64 cm) diameter control lines encapsulated together by a hard thermoplastic material.
The transverse cross section of the flatpack can be substantially rectangular, trapezoidal or crescent-shaped and may preferably be shaped to fit the curvature of the tubing to which it is attached. A flatpack having a rectangular cross section may have dimensions of 1.5 inches (3.81 cm) by 0.5 inches (1.27 cm).
Typically, different control lines extend to different depths in a well.
For a subsea well completion, there are typically from 5 to 10 control lines strapped to the outside of the production tubing. These control lines may be grouped into one, two or three flatpacks. For instance, one flatpack may contain control lines for control of downhole equipment, another may contain control lines for controlling chemical injection and another may contain control lines for a downhole safety valve. Downhole flow control and downhole safety valve control lines are sometimes combined into one flatpack.
When completing a hydrocarbon production well, tubing is run into the well and a formation isolation valve is opened, thereby providing fluid communication between the hydrocarbon-bearing formation and the surface via the tubing.
Typically, the tubing is adapted to open the formation isolation valve, as it is nm into the well. The tubing is also provided with a hanger which is adapted to be seated in a landing bowl and a sealing element which is adapted to be seated in a seal bore or packer wherein the landing bowl and seal bore or packer are located in the wellbore. The landing of the hanger in the landing bowl and the sealing element in the seal bore or packer occurs substantially simultaneously. Once the hanger and/or the sealing element have landed, the annulus around the tubing is sealed.
However, there is a time during a well completion operation when the formation isolation valve is open, but the hanger and sealing element have not yet landed. At this time, there may be an annular pathway around the outside of the tubing to the surface, up which expanding bubbles of gas can rise.
In order to prevent this gas reaching the surface, an annular blow-out preventer is actuated to close off the annular pathway. An annular blow-out preventer comprises a doughnut-shaped element expandable on actuation to close the annular gap between the tubing and the well casing. The blow-out preventer typically comprises metal elements for reinforcing the doughnut-shaped element.
Actuating the blow-out preventer can damage control lines or flatpacks attached to the outside of the tubing within a well. Actuation of the blow-out preventer would typically crush or deform plastics materials, e.g. a flatpack housing, against which it is brought to bear. The impact of the reinforcing elements on the control lines or flatpacks is a particular cause of damage.
Furthermore, if the blow-out preventer does not close the annular pathway sufficiently to at least reduce the flow of gas to manageable levels, then it will be necessary to actuate shear rams to seal off the well. Shear rams cut the tubing within the well. Subsequently, it is a complex, expensive and time consuming task to recover the tubing and associated equipment from the well.
It is known to stabilise a hydrocarbon production well during the well completion operation by employing an intermediate isolation assembly. While this allows the well completion to be carried out safely, it may add complexity and/or expense to the operation. The present invention solves or at least mitigates these problems.
A first aspect of the invention provides a control line protector for use with a tubing string having at least one control line extending in a longitudinal direction along at least part of an outer surface thereof, the control line protector comprising:

a sleeve that is locatable around the tubing string and the at least one control line, the sleeve comprising:
a cylindrical rigid outer wall; and
a polymeric sealing element disposed, in use, between an inner surface of the outer wall of the sleeve and the outer surface of the tubing string, operable to substantially seal the space between the outer wall of the sleeve and the tubing string.

The rigid outer wall of the sleeve provides a strong, substantially non-deformable surface for a blow-out preventer to bear against, should it be necessary for the blow-out preventer to be actuated. Thus, the blow-out preventer, when actuated, does not impact upon and potentially damage the at least one control line.
Moreover, because the outer wall may not deform appreciably when an actuated blow-out preventer bears against it, a good seal is formed between the blow-out preventer and the sleeve. Ideally, the rigid outer wall should have a smooth surface to enable reliable sealing with an actuated blow-out preventer.
Preferably, the rigid outer wall may be formed from metal. For instance, the outer wall of the sleeve may be made from steel; carbon steel or a low chrome steel may be especially preferred.
Preferably, a major portion of the cylindrical outer wall of the sleeve is of substantially uniform outer diameter. This is advantageous, because it enables a better seal to be formed with an annular blow-out preventer, which will expand radially inwardly against the outer wall of the sleeve, when actuated.
Preferably, the sleeve may be tapered at one or both of its ends. Such tapering may facilitate insertion of the control line protector into a well and/or removal of the control line protector from a well.
The sleeve may be provided with an end wall at one or both of its ends.
Preferably, a plurality of parts, e.g. two, three or four parts, may be securable together to form the sleeve. The parts may each comprise sub-lengths of the sleeve, e.g. annular segments, and/or segments of the perimeter of the sleeve, e.g. part-cylindrical segments. For instance, the parts may each comprise a substantially equal part-cylindrical segment, e.g. a half, a third or a quarter, of a cylinder. In a preferred embodiment, the sleeve may be formed from two substantially hemi-cylindrical parts.
The parts may be joined together, in use, by a plurality of fixing means such as bolts, which may be spaced at intervals around the circumference of the sleeve when joining together annular segments or along the length of the sleeve when joining together part-cylindrical segments.
For instance, fixing means for joining together part-cylindrical segments of the sleeve may be spaced, in use, at approximately 1 foot (30 cm) intervals along the joint (along the length of the sleeve).
Preferably, apertures for the fixing means, e.g. bolts, are provided, which are externally accessible, thereby easing installation of the protector around a tubing string.
A sealant, e.g. an elastomeric or a liquid curable sealant such as a resin, may be applied to the joints between parts of the assembled sleeve.
In embodiments where the sleeve comprises a plurality of parts, two or more of the parts may be connected to one another by a hinge. Accordingly, installation of the protector may be easier and the number of bolts required may be reduced.
The or each hinge may be a temporary hinge, whereby at least a portion of the hinge may be removable once the sleeve is in place around a tubing string without affecting the integrity of the sleeve. Embodiments utilising such a removable hinge may be preferred, because the continuous outer surface of the sleeve may be smoother after removal of the relevant portion of the hinge. As a result, better, more reliable sealing between an actuated blow-out preventer and the sleeve may be achieved, in use.
Typically, the sleeve may be from 20 feet to 100 feet (6 m to 30 m), preferably from 30 feet to 50 feet (9 m to 15 m), more preferably from 30 feet to 40 feet (9 m to 12 m) in length. The length chosen for the sleeve should take into account any inaccuracies in downhole depth measurements and “rig heave” in the event that an offshore subsea well is being serviced from a floating vessel e.g. a rig.
Typically, the tubing string around which the sleeve is locatable may have an outer diameter of up to 7 inches (18 cm), e.g. 5.5 inches (14 cm) or 7 inches (18 cm).
Accordingly, the outer wall of the sleeve may have an inner dimension, e.g. diameter, of up to 9 inches (23 cm), e.g. from 6 inches (15 cm) to 9 inches (23 cm), in order to accommodate, in use, the tubing string, the at least one control line and the polymeric sealing element.
Preferably, the rigid outer wall of the sleeve may have a radial thickness of up to 0.75 inches, e.g. from 0.25 to 0.75 inches. Typically, the outer wall of the sleeve is of substantially uniform thickness.
Preferably, the sleeve (outer wall and polymeric sealing element) has a radial thickness of up to 3.5 inches (8.9 cm), e.g. from 1 inch (2.5 cm) to 3 inches (7.6 cm).
The polymeric sealing element may be formed from an elastomer, e.g. a thermoplastic elastomer such as a polyurethane or an ethylene propylene diene monomer (EPDM) rubber crosslinked with polypropylene, e.g. Santoprene™.
The polymeric sealing element is preferably an annular polymeric body. Suitably, the outer diameter of the annular polymeric body is selected to be a tight fit with the inner surface of the rigid outer wall of the sleeve. Suitably, the inner diameter of the annular polymeric body is selected such that the annular polymeric body is a tight fit with the outer surface of the tubing string. Thus, the outer diameter of the annular polymeric body matches the inner diameter of the rigid outer wall of the sleeve while the inner diameter of the annular polymeric, sealing element matches the outer diameter of the tubing string. Preferably, the annular polymeric body is provided with at least one channel, recess or groove extending in a longitudinal direction along the inner surface thereof for accommodating, in use, the at least one control line. Typically, the at least one control line is tightly accommodated, in use, in the channel, recess, or groove.
The annular polymeric body may be bonded, e.g. adhered, to the inner surface of the rigid outer wall of the sleeve. Accordingly, where the sleeve is formed in parts, the annular polymeric body is also formed in parts each part being bonded to a corresponding or complementary section of the rigid outer wall of the sleeve. The annular polymeric body may be formed from two to eight parts, e.g., two, three or four parts.
Alternatively or additionally, the polymeric sealing element may comprise a resin. The resin, e.g. an epoxy resin or a silicone resin may be injected or otherwise delivered between the cylindrical outer wall of the sleeve and the tubing string and sets, hardens or cures in situ to augment or provide the sealing element.
The control line protector may further comprise one or more bulkheads, e.g. metallic bulkheads, locatable, in use, between the wall of the sleeve and the tubing string around which the control line protector is fitted. The one or more bulk heads are arranged transversely between the outer wall of the sleeve and the tubing string.
Optionally, the control line protector may be permanently fitted to, e.g. fabricated with, a section of the tubing string. In such an embodiment, the at least one control line will need to be provided with a connector member at each end of the sleeve to connect it to sections of corresponding control line situated above and below the control line protector.
A further aspect of the invention provides a string of tubing, e.g. production tubing, having at least one control line extending in a longitudinal direction along on an outer surface thereof, the tubing having fitted thereto at least one control line protector according to the present invention.
In use, the sleeve may be concentric with the tubing string. Alternatively, the longitudinal axis of the sleeve may be offset from that of the tubing string, i.e. the sleeve may be eccentric with the tubing string. It may be preferred for the sleeve to be eccentric with the tubing string, because a smaller polymeric sealing element may then be required, since typically the at least one control line may be arranged on one side of the tubing string. Thus, where the sealing element is a polymeric annular body, the bore through the annular body may be eccentric such that the sleeve is arranged eccentrically around the string of tubing and the at least one control line. Typically, the thicker portion of the polymeric annular body is arranged adjacent the at least one control line.
Moreover, space within a well is often limited, meaning that use of a concentric arrangement may not be practical. Accordingly, an eccentric embodiment may make more efficient use of available space within a wellbore.
Preferably, the string of tubing may extend from a tubing hanger such that, in use, the at least one control line protector is located below the tubing hanger.
The string of tubing may extend thousands of feet from the hanger.
Preferably, the at least one control line protector may be located relatively close to, e.g. less than 500 feet (152 m) from, preferably less than 300 feet (91 m) from, the tubing hanger.
In a preferred embodiment, the string of tubing may be fitted with two control line protectors. For example, a first control line protector may be located immediately below, e.g. less than 50 feet (15 in) from, the tubing hanger, while a second control line protector may be located several hundred feet, e.g. from 200 feet (61 m) to 500 feet (152 m), from the tubing hanger.
In embodiments in which the string of tubing has a plurality of control lines attached thereto, at least some of the control lines may be grouped together into one or more flatpacks.
Typically, the string or tubing may comprise jointed tubing.
The string of tubing may comprise at its lower end, i.e. the distal end from the or a tubing hanger, a portion known as a stinger.
Typically, the stinger may have a length of from 20 feet to 100 feet (6 m to 30 m), e.g. it may comprise from one to three joints of tubing.
The stinger may comprise means for opening a formation isolation valve, e.g. a collet.
Another aspect of the invention provides a method of opening a formation isolation valve located in a well using an opening means provided at the end of a tubing string and of sealing the annular space between the wall of the well and the tubing string using an annular blow-out preventer that is located within the well wherein:

(a) the tubing string extends from a hanger; and
(b) a control line protector is located around a portion of the tubing string having at least one control line extending in a longitudinal direction along the outer surface thereof; the method comprising:
(A) running the tubing string into the well so as to open the formation isolation valve; and
(B) immediately thereafter actuating the annular blow-out preventer;
wherein the control line protector comprises a sleeve having a cylindrical rigid outer wall and a polymeric sealing element disposed, in use, between an inner surface of the outer wall of the sleeve and the outer surface of the tubing string, the sealing element being operable to substantially seal the space between the outer wall of the sleeve and the tubing string and wherein the control line protector is arranged on the tubing string at a location below the hanger such that when the tubing string opens the formation isolation valve, the control line protector is located in the wellbore adjacent the annular blow-out preventer and the actuated annular blow-out preventer bears against the cylindrical rigid outer wall of the sleeve.

Suitably the well that contains the formation isolation valve is a hydrocarbon production well or a fluid injection well, in particular a water injection well, used for injecting a fluid into a hydrocarbon-bearing formation,
Typically, the formation isolation valve and the annular blow-out preventer may be at known or predetermined depths within the well. Further, the length of the tubing string that has been run into the well may be known. Accordingly, an operative may be able to select an appropriate position to fit the control line protector around the string such that when the tubing string has been run into the wellbore to a sufficient depth for the opening means at the end of the tubing string to open the formation isolation valve, the annular blow-out preventer is adjacent the portion of the tubing string that is fitted with the control line protector.
The method may comprise the subsequent step of stabilising the well, e.g. by circulating fluid down the tubing string.
After stabilising the well, the annular blow-out preventer may be de-actuated, thereby allowing the string to be run further into the well such that the hanger is landed in a landing bowl that is located in the well.
Another aspect of the invention provides a method of pulling a tubing string from a well containing a hanger landing bowl at a first depth, an annular blow-out preventer at a second depth and a formation isolation valve at a third depth, the first depth being less than the second depth and the second depth being less than the third depth, the tubing string extending downwardly from a hanger landed in the hanger landing bowl and passing through the formation isolation valve, thereby maintaining the formation isolation valve in an open position, wherein a control line extends in a longitudinal direction along at least a portion of the tubing string and wherein a control line protector is fitted to the tubing string the method comprising: withdrawing the tubing string from the well by an amount sufficient to lift the hanger from the hanger landing bowl whilst maintaining the formation isolation valve in the open position; and shortly thereafter actuating the annular blow-out preventer; wherein the control line protector comprises a sleeve having a cylindrical rigid outer wall and a polymeric sealing element disposed, in use, between an inner surface of the outer wall of the sleeve and the string, the sealing element being operable to substantially seal the space between the outer wall of the sleeve and the string and wherein the control line protector is fitted to the tubing string below the hanger such that when the hanger is lifted from the landing bowl and the formation isolation valve is in the open position, the control line protector is located in the well adjacent the annular blow-out preventer and the actuated annular blow-out preventer bears against the cylindrical rigid outer wall of the sleeve.
Prior to lifting the hanger from the hanger bowl, the control line protector is typically located in the well at a position between the blow-out preventer and the formation isolation valve, preferably, immediately below the blow-out preventer, such that when the hanger is lifted from the landing bowl and the formation isolation valve is in the open position, the control line protector is located in the well adjacent the annular blow out preventer.

In order that the invention may be more readily understood, certain embodiments will be described, by way of example only, with reference to the accompanying drawings, in which:

FIG. 1 shows a longitudinal cross section of a section of tubing to which is fitted a control line protector according to the invention;

FIG. 2 a is a transverse cross section along line A-A in FIG. 1;

FIG. 2 b is an alternative transverse cross section along line A-A in FIG. 1;

FIG. 3 a is a transverse cross section along line B-B in FIG. 1;

FIG. 3 b is an alternative transverse cross section along line B-B in FIG. 1;

FIG. 4 is a bolt;

FIGS. 5, 6 and 7 are a series of schematic drawings of a well illustrating a method according to the invention; and

FIG. 8 is a schematic drawing illustrating a method of pulling tubing from a well according to the invention.

In FIG. 1 there is shown a section of production tubing 1, which has attached to its outside and running along its length a flatpack 2.
The section of production tubing 1 comprises a joint 3. The joint 3 has a greater outer diameter than the tubing 1 either side of it.
A control line protector comprising a steel sleeve 4 is fitted around the tubing 1. The sleeve 4 is cylindrical with inwardly tapering portions at each end. The inwardly tapering portions form end walls. The sleeve 4 is around 50 feet (15 m) in length. Five steel annular bulkheads 5 are provided at regular intervals and are provided inside the sleeve 4 at pre-determined intervals along the length of the sleeve 4. Two of the bulkheads 5 are located either side of the joint 3.
The other spaces between the bulkheads 5 are substantially filled with elastomeric sealing inserts or bodies 6.
FIG. 2 a shows a transverse cross section along line A-A of FIG. 1.
The flatpack 2 attached to the production tubing 1 is trapezoidal in cross section.
FIG. 2 a shows that the sleeve 4 is made from two hemi- cylindrical parts 400 a, 400 b. The elastomeric sealing insert 6 is made up of first and second substantially hemi- cylindrical parts 600 a, 600 b. The first part 600 a comprises a groove which is shaped to fit snugly around the flatpack 2.
FIG. 2 a shows an embodiment in which the sleeve 4 is concentric with the tubing 1.
Alternatively, the sleeve may be eccentric with the tubing. Such an arrangement is shown in FIG. 2 b, an alternative transverse cross section along line A-A of FIG. 1.
In FIG. 2 b, a trapezoidal flatpack 2′ is attached to the outside of production tubing 1′. The sleeve of the control line protector is eccentric with the production tubing 1′. The sleeve is made up of first and second hemi-cylindrical parts 400 a′, 400 b′. The elastomeric sealing insert between the sleeve and the tubing 1′ comprises a major part 600 a′ and a minor part 600 b′. The major part 600 a′ comprises a groove which is shaped to fit snugly around the flatpack 2′. The minor part 600 b′ is generally thinner than the major part 600 a′, since the production tubing 1′ is offset towards the second hemi-cylindrical part 400 b′ of the sleeve.
FIG. 3 a is a transverse cross section along line B-B in FIG. 1, i.e. through one of the bulkheads 5.
The flatpack 2 attached to the production tubing 1 is trapezoidal in cross section.
FIG. 3 a shows that the sleeve 4 is made from two hemi- cylindrical parts 400 a, 400 b. The steel bulkhead 5 is made up of first and second substantially hemi- cylindrical parts 500 a, 500 b. The first part 500 a is shaped to accommodate flatpack 2.
The two parts 500 a, 500 b of the bulkhead are attached to the sleeve by four equally spaced steel screws 8, two in each of the substantially hemi- cylindrical parts 400 a, 400 b of the sleeve, which pass through apertures (not shown) in the sleeve.
FIG. 3 a also shows bolts 7 which fix the two parts 400 a, 400 b of the sleeve together. Parts of the bolts 7 pass through the bulkhead 5.
FIG. 3 a shows an embodiment in which the sleeve 4 is concentric with the tubing 1
Alternatively, the sleeve may be eccentric with the tubing. Such an arrangement is shown in FIG. 3 b, an alternative transverse cross section along B-B of FIG. 1.
In FIG. 3 b, a trapezoidal flatpack 2′ is attached to the outside of production tubing 1′. The sleeve of the control line protector is eccentric with the production tubing 1′. The sleeve is made up of first and second hemi-cylindrical parts 400 a′, 400 b′. The bulkhead 5 between the sleeve and the tubing 1′ comprises a major part 500 a′ and a minor part 500 b ′. The major part 500 a′ is shaped to accommodate the flatpack 2′. The minor part 600 b′ is generally thinner than the major part 600 a′, since the production tubing 1′ is offset towards the second hemi-cylindrical part 400 b′ of the sleeve. The remaining features of FIG. 3 b are substantially the same as described above in respect of FIG. 3 a, with like features being indicated by like reference numerals but with a prime in FIG. 3 b.
FIG. 4 shows a side elevation of a screw 8 for affixing the sleeve to the bulkhead. The screw 8 comprises a head and a shank. In use, e.g. as shown in FIGS. 3 a and 3 b, the head should not protrude from the outer surface of the sleeve, in order that the outer surface may be as smooth as possible. Therefore, the apertures for receiving the bolts may be countersunk.
The bulkheads may be affixed to the sleeve by any suitable method, e.g. welding.
The provision of bulkheads, e.g. metallic bulkheads, spaced along the inner surface of the sleeve serves a number of functions. First, the bulkheads may provide stops or barriers against in-service deformation, e.g. arising from extrusion or expansion of the polymeric sealing elements due to fluid ingress or high temperatures, which may occur in harsh downhole conditions. A related benefit is that the polymeric sealing elements may be provided as shorter moulded or extruded parts, which may be easier to manufacture and handle. Different numbers of such shorter parts could be used to provide sealing elements for use with sleeves of different lengths.
Further, the bulkheads either side of a joint may provide upper and lower mechanical stops against movement of the joint. Typically, the bulkheads may also be repositionable within the sleeve to accommodate uncertainty in the relative position of the control line protector and any joints in the tubing.
Also, e.g. as shown in FIGS. 3 a and 3 b, where the sleeve comprises a plurality of parts that are fixed together, e.g. with bolts, the bulkheads may provide additional material in which the bolts or other fixing means may gain purchase, thereby making the control line protector more robust.
FIG. 5 shows an offshore production well comprising a riser 41 extending downwardly from a rig floor 42. The riser 41 passes below the waterline 43 to a subsea wellhead comprising a hanger landing bowl 49 located on or close to the sea floor 45. A well bore lined with well casing 44 extends from the subsea well head down through the sea floor 45 to a hydrocarbon reservoir. Fluid communication from the hydrocarbon reservoir is provided by perforations 46 in the well casing 44.
A formation isolation valve 47 is located within the well casing 44 above the perforations 46. In FIG. 5, the formation isolation valve 47 is closed, thereby isolating the hydrocarbon reservoir from the section of the well above the formation isolation valve 47. A seal bore 48 is located within the well casing 44 above the formation isolation valve 47.
The subsea wellhead further comprises, above the hanger landing bowl 49, an annular blow-out preventer 50 and a choke line 51. The choke line 51 communicates with the internal volume of the riser 41 via an outlet located at a point between the hanger landing bowl 49 and the annular blow-out preventer 50. The choke line 51 provides a controlled fluid circulation path to the surface, e.g. to a gas separation facility (not shown).
The subsea wellhead further comprises shear rams (not shown) located between the outlet to the choke line 51 and the annular blow-out preventer 50. As is known in the art, the shear rams are operable in an emergency to seal the well. Actuating the shear rams will cut any tubing located within the well.
As shown in FIG. 5, a string of production tubing 52 has been run into the well. A tubing hanger 53 is connected to the production tubing 52. Attached to the outside of the tubing 52 by means of regularly spaced clamps (not shown) and extending down from the hanger 53 are two flatpacks 54 a, 54 b comprising control lines for downhole equipment. The flatpacks 54 a, 54 b extend along substantially the entire length of the tubing 52, but only a relatively short length is depicted for the sake of clarity.
About 30 to 40 feet (9 m to 12 m) below the tubing hanger 53, a control line protector 55 according to the invention is fixed to the tubing 52. The control line protector 55 is around 40 feet long and comprises a steel sleeve and a sealing element adhered to an inner surface thereto, the sealing element having channels therethrough which are shaped to accommodate and substantially seal around the flatpacks 54 a, 54 b.
The lowermost portion of the tubing 52 comprises a stinger 56. The stinger 56 is provided at its upper end with a seal assembly 57 and at its lower end with a collet 58 for actuating the formation isolation valve 47.
FIG. 5 illustrates the situation, in which the production tubing 52 is in the process of being run into the well, but the collet 58 has not yet actuated the formation isolation valve 47. Accordingly, the well is secure below the formation isolation valve 47.
In FIG. 6, the production tubing 52 has been run further into the well such that the collet 58 has passed through, and thereby opened, the formation isolation valve 47. However, the seal assembly 57 has not yet landed in the seal bore 48 and the tubing hanger 53 has not yet landed in the hanger landing bowl 49.
In this position, there is fluid communication between the rig and the hydrocarbon reservoir via the stinger 56 and the production tubing 52. There is also, however, an annular pathway up the well through the formation isolation valve 47 around the outside of the stinger 56 and the production tubing 52. Bubbles of gas 59 can rise up this annular pathway, expanding as they do so.
Therefore, in order to prevent large bubbles of gas reaching the rig in this way, the annular blow-out preventer 50 is actuated. As shown in FIG. 6 the actuated blow-out preventer 50 bears on the outer surface of the control line protector 55, which protects flatpacks 54 a, 54 b from being damaged by the blow-out preventer 50. It will be appreciated that the annular pathway is substantially sealed by the blow-out preventer 50 and the sealing element inside the sleeve of the control line protector 55. Any gas bubbles 59 rising up the annular pathway are diverted in a controlled fashion to the surface via choke line 51.
With the apparatus in the position shown in FIG. 6, a fluid is circulated down the inside of the tubing 52 to clear gas from below the formation isolation valve 47. Once a static column of fluid has been built up, the annular blow-out preventer 50 can be opened safely and the tubing 52 can be run further into the well.
Thus, as shown in FIG. 7, the tubing 52 is run into the well until the hanger 53 lands in the landing bowl 49 and the seal assembly 57 lands in the seal bore 48. Typically, the hanger 53 and the seal assembly 57 may be landed almost simultaneously. Accordingly, the well is secure and the only path for fluid from the reservoir to the rig is along the inside of tubing 52.
FIG. 8 shows an application of the invention when pulling a tubing string from a well, e.g. for a workover.
When a workover is required, it is necessary to pull the tubing 52 from the well. Hence, the hanger 53 is lifted from the landing bowl 49 and the seal assembly 57 is removed from the seal bore 48. As soon as this occurs, ideally before the tubing 52 has been lifted by any more than 50 feet (15 metres), the annular blow-out preventer 50 is actuated to prevent bubbles of gas 59 passing up the annulus between the riser 41 and the tubing 52 to the rig floor 42.
As shown in FIG. 8, the control line protector 55 is positioned such that it protects flatpacks 54 a, 54 b when the annular blow-out preventer 50 is actuated. In the position shown in FIG. 8, any bubbles of gas 59 rising up the annulus are safely diverted along choke line 51.
Fluid is then circulated down tubing 52 to stabilise the well. Once the well is stabilised, the tubing 52 may be pulled from the well with the formation isolation valve 47 closing after the collet 58 passes through it.
In FIGS. 5, 6, 7 and 8, a downhole expandable packer may be employed in place of the seal bore 48 with the packer being actuatable to seal around the seal assembly 57.
It is worth noting that the Figures are not to scale. In particular, FIGS. 5, 6, 7 and 8 are schematic for the sake of clarity, owing to the disparate distances involved. Typically, the distance from the rig floor 42 to the water line 43 may be of the order of a few tens of feet. The annular blow out preventer 50 may be located a few tens of feet above the seafloor 45, but several thousand feet below the water line 43. The seal bore 48 may be located several thousands of feet below the seafloor 45 and a few tens or hundreds of feet above the formation isolation valve 47.
The length of the control line protector is selected such that a tolerance of depth uncertainty is built in to the device, i.e. to allow for some margin for error in the location of the control line protector, as it will typically be run many thousands of feet into a well. By appropriately selecting the length of the control line protector and fitting it to the correct section of tubing, it is possible to ensure that, in use, the control line protector is in place to protect any control lines should it be necessary to actuate the blow-out preventer. In offshore wells, the length of the control line protector should be sufficient to accommodate movement due to the heave of the drilling ship or rig.
While the control line protector should minimise the flow of fluid therethrough, it need not be absolutely fluid-tight.
It will be appreciated that the present invention provides a number of benefits.
For example, use of the control line protector below a tubing hanger provides improved well control both immediately after opening the formation isolation valve during a well completion and/or immediately before pulling the tubing from a well for a workover.
In the case of a completion of a production well containing oil and gas, the present invention allows the well to be completed safely without having to employ an intermediate isolation assembly to stabilise the well. Therefore, the well completion operation may be quicker, less complicated and/or less expensive. Previously, the only times a well could be safely completed without employing an intermediate isolation assembly was when the operator could be sure that the well did not contain any gas below the formation isolation valve.
The apparatus and methods of the present invention may be used in onshore and offshore wells, production wells and injection wells.
The apparatus and methods of the present invention may be used in completion operations with a temporary workstring.
The apparatus and methods of the present invention may allow tubing with control lines or flatpacks attached to its outside to be used in gravel pack placement completion operations.

Claims

1-23. (canceled)

24. A control line protector for sealing between a blowout preventer and a tubing string having at least one control line extending in a longitudinal direction along at least part of an outer surface thereof, the control line protector comprising: a sleeve that is locatable around the tubing string and the at least one control line, the sleeve comprising (a) a cylindrical rigid outer wall; and (b) a polymeric sealing element disposed, in use, between an inner surface of the outer wall of the sleeve and the outer surface of the tubing string, operable to substantially seal the space between the outer wall of the sleeve and the tubing string, wherein the polymeric sealing element is annular in shape.

25. A control line protector according to claim 24, wherein the rigid outer wall is made from metal.

26. A control line protector according to claim 24, wherein the sleeve is made from steel.

27. A control line protector according to claim 24, wherein a major portion of the cylindrical sleeve is of substantially uniform outer diameter.

28. A control line protector according to claim 24, wherein the sleeve is formed from a plurality of parts.

29. A control line protector according to claim 28, wherein two or more of the parts are part-cylindrical and are hingedly connected to one another.

30. A control line protector according to claim 28, wherein the parts are joined together by a plurality of fixing means spaced at intervals along the joint between the parts.

31. A control line protector according to claim 24, wherein the sleeve is formed from two substantially hemi-cylindrical parts.

32. A control line protector according to claim 24, wherein the sleeve is from 20 feet to 100 feet (6 m to 30 m) in length.

33. A control line protector according to claim 24, wherein the polymeric sealing element comprises an elastomer or a resin.

34. A control line protector according to claim 33 wherein the resin is injected between the outer wall of the sleeve and the tubing string and sets in situ to augment or provide the polymeric sealing element.

35). A control line protector according to claim 24, wherein the inner wall of the polymeric sealing element is provided with a channel or groove in which the at least one control line may be tightly accommodated in use.

36. A control line protector according to claim 24, wherein the polymeric sealing element comprises an annular polymeric body bonded to an inner surface of the outer wall of the sleeve.

37. A control line protector according to claim 24, wherein the polymeric sealing element comprises a plurality of discrete bodies.

38. A string of tubing having at least one control line on an outer surface thereof, the tubing having fitted thereto at least one control line protector according to claim 24.

39. A string of tubing according to claim 38, wherein the control line protector is concentric or eccentric with the tubing.

40. A string of tubing according to claim 38 having at least one flatpack attached thereto that extends in a longitudinal direction along at least part of the outer surface of the string of tubing.

41. A string of tubing according to claim 38, wherein the string of tubing extends from a tubing hanger and the control line protector is positioned on the string of tubing, such that, in use, the at least one control line protector is located in a well adjacent an annular blow-out preventer.

42. A string of tubing according to claim 38, which is fitted with two control line protectors.

43. A method of opening a formation isolation valve located in a well using an opening means provided at the end of a tubing string and of sealing the annular space between the wall of the well and the tubing string using an annular blow-out preventer that is located within the well wherein:

(a) the tubing string extends from a hanger; and

(b) a control line protector is located around a portion of the tubing string having at least one control line extending in a longitudinal direction along the outer surface thereof;

the method comprising:

(A) running the tubing string into the well so as to open the formation isolation valve; and

(B) immediately thereafter actuating the annular blow-out preventer;

wherein the control line protector comprises a sleeve having a cylindrical rigid outer wall and a polymeric sealing element disposed, in use, between an inner surface of the outer wall of the sleeve and the outer surface of the tubing string, the sealing element being annular in shape and operable to substantially seal the space between the outer wall of the sleeve and the tubing string and wherein the control line protector is arranged on the tubing string at a location below the hanger such that when the tubing string opens the formation isolation valve, the control line protector is located in the well adjacent the annular blow-out preventer and the actuated annular blow-out preventer bears against the cylindrical rigid outer wall of the sleeve.

44. A method according to claim 43 comprising the subsequent step of stabilising the well and thereafter deactuating the annular blow-out preventer, thereby allowing the string of tubing to be run further into the well such that the hanger is landed in a landing bowl that is located within the well.

45. A method of pulling a string of tubing from a well containing a hanger landing bowl at a first depth, an annular blow-out preventer at a second depth and a formation isolation valve at a third depth, the first depth being less than the second depth and the second depth being less than the third depth, the string of tubing extending downwardly from a hanger landed in the hanger landing bowl and extending through the formation isolation valve, thereby maintaining the formation isolation valve in an open position, wherein a control line extends in a longitudinal direction along at least a portion of the string of tubing and wherein a control line protector is fitted to the string of tubing, the method comprising:

withdrawing the string of tubing from the well by an amount sufficient to lift the hanger from the hanger landing bowl whilst maintaining the formation isolation valve in the open position;

and immediately thereafter actuating the annular blow-out preventer;

wherein the control line protector comprises a sleeve having a cylindrical rigid outer wall and a polymeric sealing element disclosed, in use, between an inner surface of the outer wall of the sleeve and an outer surface of the string of tubing, the sealing element being annular in shape and operable to substantially seal the space between the outer wall of the sleeve and the string and wherein the control line protector is fitted to the string below the hanger such that when the hanger is lifted from the landing bowl and the formation isolation valve is in the open position, the control line protector is located in the well adjacent the annular blow-out preventer and the actuated annular blow-out preventer bears against the cylindrical rigid outer wail of the sleeve.

46. A method according to claim 45 comprising the subsequent step of stabilising the well and thereafter deactuating the annular blow-out preventer, thereby allowing the string to be pulled further from the well such that the formation isolation valve can close.