WO1997040255A2

WO1997040255A2 - Tubing injection systems for land and under water use

Info

Publication number: WO1997040255A2
Application number: PCT/US1997/007705
Authority: WO
Inventors: Philip Burge; Peter Fontana; Glenn Leroux; Friedhelm Makhol
Original assignee: Baker Hughes Incorporated
Priority date: 1996-04-19
Filing date: 1997-04-21
Publication date: 1997-10-30
Also published as: AU2934897A; EP0894182A2; CA2239096A1; NO982485D0; NO982485L; WO1997040255A3; CA2239096C; AU730344B2

Abstract

This invention provides a tubing injection system that contains an injector (200) with two movable injection blocks which are remotely operable to provide a desired opening. Each injection block contains a plurality of gripping members for holding a range of tubing sizes. The injection blocks automatically adjust to provide the required gripping force and tubing speed according to programmed instructions. A resilient tubing guidance system (40) is positioned above the injector head directs the tubing into the injector head. Sensors are provided to determine the radial force on the tubing exerted by the injector head, tubing speed, injector speed, compression of the tubing guidance member and the back tension on the reel. A control unit (170) continually maintains the tubing speed, tension and radial pressure on the tubing within predetermined limits. The control unit also maintains the back tension on the reel. This invention also provides a tubing handling system for moving a tubing from a vessel into a subsea wellbore. A main injector (200) of the type described above is permanently attached to the wellhead. A smaller injector (190) at the vessel moves the tubing from the vessel to the underwater injector. A riser (80) between the two injectors guide the tubing into the underwater injector. A control unit (170) controls the operation of the system.

Description

TITLE: TUBING INJECTION SYSTEMS FOR LAND AND UNDER-WATER USE

Field of the Invention

This invention relates generally to tubing injection systems for use in drilling and/or servicing wellbores and more particularly to a novel land tubing

injection and under-water tubing injection systems and a novel injector head which is remotely and automatically controllable for running different types of

tubings and bottomhole assemblies into the wellbores.

Background of the Art

Drilling rigs and workover rigs are utilized to run drill pipes, production pipes or casings into wellbores during the drilling or servicing operations. Such rigs are expensive and the drilling and service operations are time-consuming. To reduce or minimize the time and expense involved in using jointed pipes or

jointed tubing, operators often use coiled-tubing instead for performing drilling and/or workover operations.

During the early applications of coiled-tubings, relatively small coiled tubings (typically approximately one inch in outer diameter) were used. Use of

a small diameter coiled-tubing limits the amount of fluid that can be injected downhole, amount of compression force that can be transmitted through the coiled-tubing to the bottomhole assembly, amount of tension that can be placed

on the coiled-tubing, amount of torque that the tubing can withstand, type and weight of the tools that can be utilized to perform drilling or servicing operations, and the length of the tubing that can be used.

Due to improvements in the materials used for making the coiled-tubings

and improvements in the tubing-handling equipment, coiled-tubings of varying sizes are now commonly used to perform many functions previously performed by drill pipes or jointed-tubulars. Due to the low cost of operating coiled- tubings, the flexibility of its use and the continued increase in the drilling of

complex wellbores, such as multi-lateral wellbores, highly deviated wellbores and the more recent development of contoured wellbores, the use of coiled-

tubings has been steadily increasing.

However, the injectors and the equipment for handling tubings from reels

to injectors are still typically designed to run a specific tubing size. Most of the operations of the prior art injectors, tubing reels and wellhead equipment are

manually performed by operators who respond to visual gauges to operate a variety of control valves that direct hydraulic power to different elements of

such injectors, tubing reels and the wellhead equipment. The prior art injectors are not designed to allow for the passage of relatively large diameter bottom hole assemblies therethrough. Thus, in order to perform a drilling or workover operation with a relatively large diameter bottom hole assembly attached to the lower end of a relatively small outer diameter tubing, the bottomhole assembly

is either attached below the injector prior to placing the injector on the subsea

wellhead or it is attached below the tubing after the tubing has passed through the injector. Such a process is relatively cumbersome and can be unsafe.

For land operations, the injector head is typically placed on the wellhead

equipment. To attach a bottomhole assembly such as a drilling assembly, the

injector head is removed from the wellhead equipment to insert the bottomhole assembly into the wellhead equipment. Additionally, systems having vertically- movable injector head and gooseneck, which allow the operator to connect and

disconnect the bottomhole assembly to the tubing on a working platform have also been used.

For land operations, the prior art tubing injection systems still require moving the injector head from its operating position whenever a relatively larger

diameter bottomhole assembly is to be inserted into a wellbore through the wellhead equipment. These systems also do not provide an injector head that

allows the passage of both tubings and bottomhole assemblies of a variety of sizes to pass through the injector head when the bottomhole assembly is

already connected to the tubing. An additional drawback of the prior art injector heads is that they bite into the coiled tubing and frequently induce into the coiled tubing excessive stress resulting in reduced tubing life or damaged tubing. In some cases, the damage requires the operators to cease to replace the coiled tubing, which can be very expensive.

It is, therefore, desirable to have an injector head that allows the passage

of a wide range of bottomhole assemblies through the injector head and insert and remove coiled tubings of various sizes into and from the wellbore without the necessity of removing the injector head. It is further desirable to have an injector head which can securely grip the tubings without inducing undue radial

stress into the tubings or damaging the tubings. In the prior art systems, the tubing is typically unwound from a reel and passed over a gooseneck, which is a rigid structure of a relatively short radius. Such goosenecks impart great stress onto the tubing when the tubing is passed

from a tubing reel into the injector head. Also, the prior art systems utilize manual methods for controlling various operations of the tubing injection

systems. Such manual methods are imprecise, can induce excessive stress in the tubing and are labor intensive.

For offshore operations, floating vessels, such as ships and semi- submersible rigs, and fixed offshore platforms, such as jack-up rigs, are utilized for drilling, completing and servicing subsea wellbores and for performing workover and other post-drilling services. Most of the coiled-tubing injection systems are designed for use with land rigs. Relatively little progress has been made in developing coiled-tubing injection systems for subsea applications, especially from floating vessels or rigs. Coiled-tubing operations from floating

rigs pose unique problems because of the constant motion of the vessel. Additionally, injector heads are not permanently installed on subsea wellhead because prior art injectors require attaching the bottom hole assemblies, such as drilling assemblies, which typically have substantially greater outside

diameters compared to the tubing, after the tubing has passed through the injector head. Additionally, prior art systems do not provide methods for transporting a bottomhole assembly attached to a tubing end between the wellhead and the vessel. Prior art systems also do not provide under water

tubing injection systems that are automatically operated from the surface. Due to the corrosive nature of sea water, electrical sensors are typically not used in connection with under-water injection heads. Also, prior art under water injector systems are not efficient, do not allow for the automatic control of the

injectors, and typically require attaching the bottom hole assembly below the underwater injector prior to the placement of the injector on the wellhead.

United States Patent No. 5,002,130, issued to Laky, discloses an injector placed under water on the wellhead for injecting a tubing into the

wellbore. To place the injector on the wellhead, the coiled-tubing is securely held into the injector. The injector is then lowered from the offshore platform

into the sea by the coiled-tubing until it reaches the wellhead. The weight of the injector is used to lower it to the wellhead. To keep the injector from

coming in contact with the sea water, the injector is encased in an enclosure. Water in the enclosure is displaced by a gas. Gas injection means are provided for continuously injecting the gas into the enclosure to replace any gas that

may leak during operations. Such a system requires gas injection equipment and other control equipment for ensuring continued supply of gas into the enclosure during the entire length of the operation being performed, which can be expensive and requires installing unnecessary equipment under water. The

same results can be obtained by sealing selected elements of the injector, such as the bearings, drive mechanisms and motors, as provided by the present

invention.

In addition to the above-noted deficiencies of the prior art systems,

operations of the injector head and the wellhead equipment, such as the blowout preventor, are generally manually controlled by several operators.

These operators adjust a variety of hydraulic control valves to adjust various operating parameters, such as the gripping pressure applied by the injector head

on the tubing, the injector head speed, the back-tension on the tubing at the reel, and the operation of the BOP. Some systems require several operators who must be stationed at different locations at the rig to control the various operations of the injector head, reel and the wellhead equipment. Such

manually controlled operations are imprecise, labor intensive, relatively inefficient, and detrimental to the long life of the equipment, especially the

coiled tubing.

It is, therefore, highly desirable to have a tubing injection system wherein

certain operating parameters relating to the various equipment, such as the injector head, tubing reel and the wellhead equipment, are remotely and automatically controlled to provide a more efficient and safer rig operations.

It is further desirable to provide a safe working area away from the injector

head for the operator to connect and disconnect the bottomhole equipment to the tubing and to pass such equipment through the injector head without moving the injector head or the gooseneck.

It is also highly desirable to have a tubing handling system for subsea use

that includes permanently installed (for the duration of the work to be performed) injector at the subsea wellhead that can be opened to allow the passage of bottomhole assemblies therethrough and move the tubing through

the wellbore. It is further desirable to remotely control the operation of such subsea injector to provide a more efficient and safe operation, including

automatically adjusting the gripping force on the tubing to a desired value and shutting down the injection system and/or activating appropriate alarms if an unsafe condition, such a free falling tubing, is detected. The present invention addresses the above-noted deficiencies of prior art

land and subsea tubing handling systems and provides tubing injection systems, wherein a novel injector placed on the subsea wellhead or at the surface allows

for the passage of relatively large diameter bottomhole assemblies

therethrough. The tubing injection systems automatically control the operation

of the injector, whether installed at the surface or under water, and other

elements of the tubing injection system. The subsea system further includes

a secondary surface injector for transporting the bottomhole assemblies

attached to the tubing from the vessel to the subsea injector.

SUMMARY OF THE INVENTION

In one embodiment, the present invention provides a rig which includes

an electrically controllable injection system from a remote location. The

injection system contains at least two opposing injection blocks which are

movable relative to each other. Each such injection block contains a plurality

of gripping members. Each gripping member is designed to accommodate

removable Y-blocks that are designed for specific tubing size. The injector head

is placed on a platform above the wellhead equipment. A plurality of rams are

coupled to the injector head for adjusting the width of the opening between the

injection blocks and for providing a predetermined gripping force to the holding

blocks. The rams are preferably hydraulically operated. A tubing guidance

system is positioned above the injector head for directing a tubing into the injector head opening in a substantially vertical direction. The rig system contains a variety of sensors for determining values of various operating parameters. The system contains sensors for determining the radial force on

the tubing exerted by the injector head, tubing speed, injector head speed, weight on bit during the drilling operations, bulk weight of the drill string, compression of the tubing guidance member during operations and the back

tension on the tubing reel.

With respect to the operation of the injector head, during normal operation when the tubing is inserted into the wellbore, the control unit continually maintains the tubing speed, tension on chains in the injector head

and radial pressure on the tubing within predetermined limits provided to the control unit. Additionally, the control unit maintains the back tension on the reel and the position of the tubing guidance system within their respective predetermined limits. The control unit also controls the operation of the

wellhead equipment. During removal of the tubing from the wellbore, the control unit operates the reel and the injector head to remove the tubing from the wellbore. Thus, in one mode of operation, the system of the invention automatically performs the tubing injection or removal operations for the

specified tubing according to programmed instruction. The rig system of the present invention requires substantially less manpower to operate in contrast to comparable conventional rigs. The bottomhole assembly is safely connected from the tubing at a working platform prior to inserting the bottomhole assembly into the injector head and is then disconnected after the bottomhole assembly has been safely removed from the wellbore to the working platform above the injector head. This system does

not require removing or moving either the tubing guidance system or the injector head as required by the prior art systems. The injector head is fixed above the wellhead equipment, which is safer compared to the system which require moving the injector head. Substantially all of the operation is performed from the control unit which is conveniently located at a safe distance from the rig frame, thus providing a relatively safer working environment. The

operations are automated, thereby requiring substantially fewer persons to operate the rig system.

The present invention also provides a tubing injection system for moving a tubing through subsea wellbores. The system includes an electrically-

controllable under water injector near the seabed. The under water injector operates in the same manner as described above with reference to the land

system. A surface injector on the vessel moves the bottomhole assembly attached to the tubing end from the vessel to the subsea injector. A riser

placed between the vessel and the under water injector guides the tubing into

the subsea injector. After the tubing has passed through the under water injector, the secondary surface injector may be made inoperable. A relatively small third injector may be utilized to move the tubing from a reel to the secondary surface injector and to provide desired tubing tension between the

reel and the third injector.

A tubing guidance system at the vessel platform may also be utilized to guide the tubing from the reel through the secondary injector in substantially vertical direction. The under water injector is preferably electrically controlled

and hydraulically operated. Hydraulic power source is placed on the vessel, while electrically-controlled fluid valves associated with the underwater injector are preferably placed under water near the underwater injector. A variety of sensors associated with the tubing injection system provide information about

certain operating parameters relating to the tubing injection system. A control

unit at the surface controls the operation of the tubing injection system, including the tubing gripping force, tubing speed, injector speed, compression of the tubing guidance member and the back tension on the tubing reel. Any

drives, bearings and motors in the under water injector are selectively sealed

while the chain mechanism is left exposed to the sea water.

During operation, the control unit continually maintains the tubing speed, tension on the injector chains and radial pressure on the tubing within predetermined limits provided to the control unit. Additionally, the control unit maintains the back tension on the reel. The control unit also may control the

operation of the wellhead equipment. During removal of the tubing from the wellbore, the control unit operates the reel and the injector in the reverse

direction to remove the tubing and any bottom hole assembly attached to its bottom end from the wellbore. Substantially all of the operation is performed from the control unit, which is conveniently located at the surface. The operations are automated, thereby requiring substantially fewer persons to

operate the system compared to the prior art systems.

The present invention provides a method for moving a tubing through a subsea wellbore. The method comprises the steps: (a) placing a subsea injector adjacent the seabed; (b) placing a surface injector at the surface; (c) providing a riser between the subsea and the surface injectors for guiding the tubing to the first injector; (d) moving the tubing from a source to the subsea injector through the riser by the surface injector; and (e) moving the tubing through the

wellbore with the subsea injector.

Examples of the more important features of the invention have been

summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art

may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims

appended hereto. BRIEF DESCRIPTION OF THE DRAWINGS

For detailed understanding of the present invention, references should be

made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein:

FIG. 1 shows a schematic elevational view of a land drilling rig utilizing

the tubing injection system according to the present invention.

FIG. 2 shows a schematic elevational view of a tubing handling system for use in moving tubing through a subsea wellbore according to a preferred embodiment of the present invention.

FIG. 3 shows a schematic elevational view of an injector according to the

present invention for use with the subsea and land drilling systems shown in FIGS. 1 and 2. FIG. 4A shows a side view of a block having a resilient member for use in the injector head of FIG. 3.

FIG. 4B shows a side view of a gripping member for use in the block of FIG. 4A.

FIG. 5 shows a block functional diagram of a control system for controlling the operation of the tubing injection systems shown in FIGS. 1 and 2. DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

FIG. 1 shows a schematic elevational view of a land rig 10 utilizing a tubing handling system according to the present invention. The rig 10 includes

a substantially vertical frame 12 placed on a base or platform 14. A suitable wellhead equipment 17 containing a wellhead stack 16 and a blowout preventor stack 18 are placed as desired over the well casing (not shown) in the wellbore. A first platform or injector platform 20 is provided at a suitable

height above the wellhead equipment 17. An injector, generally denoted herein by numeral 200 and described in more detail later in reference to FIG. 3, is

fixedly attached to the injector platform 20 directly above the wellhead equipment 17. A control panel 122 for controlling the operation of the injector

head is preferably placed on the injector platform 20 near the injector 200. The control panel 122 contains a number of electrically-operated control valves 124 for controlling the various hydraulically-operated elements of the injector 200. The control valves 124 control the flow of a pressurized fluid from a common

hydraulic power system or unit 60 to the valves 124, as described in more detail below in reference to FIG. 3. An electrical control system or control unit 170, preferably placed at a remote location, controls the operation of the injector 200 and other elements of the rig 10 according to programmed

instructions or models provided to the control unit 170. The detailed description of the injector 200 and the operation of the rig 10 are described

below.

Still referring to FIG. 1 , the rig 10 further contains a working platform 30 that is attached to the frame 12 above the injector 200. Tubing 142 to be

used for performing the drilling, workover or other desired operations is coiled on a tubing reel 80. The reel 80 is preferably hydraulically operated and is controlled by the control unit 170. The control unit 170 controls a fluid control valve 62 placed in a fluid line 64 coupled between the reel 80 and the hydraulic

power unit 60. A speed sensor 65, preferably a wheel-type sensor known in

the art, is operatively coupled to the tubing near the reel 80. The output of the sensor 65 is passed to the control unit 170, which determines the speed of the tubing in either direction. A sensor 84 is coupled to the reel for providing the reel rotational speed. A tension sensor 86 is coupled to the reel 80 for determining the back tension on the tubing 142. The tubing 142 from the reel 80 passes over a tubing guidance system

40, which guides the tubing 142 from the reel 80 into the injector 200. The

tubing guidance system 40 is attached to the frame 12 above the working platform 30 at a height "h" which is sufficient to enable an operator to connect

and disconnect the required downhole equipment to the tubing 142 prior to inserting it into the injector 200. The tubing guidance system 40 preferably

contains a 180° guide arch 44 having a relatively large radius. A radius of about fifteen (15) feet has been determined to be suitable for coiled tubing

having outside diameter between one (1 ) inch and three and one half (3.5)

inches. A front end 44a of the guide arch 44 is preferably positioned directly above the reel 80 on which the tubing 142 is wound and the tail end 44b is

positioned above an opening 202 of the injector 200 so that the tubing 142 will enter vertically into an injector opening 201. The guide arch 44 is supported

by a rigid arch frame 46, which is placed on a horizontal support member 48 by a flexible connection system 50. The flexible connection system 50 contains a piston 52 that is connected between the guide arch 44 and the member 48. Members 54a and 54b are fixedly connected to the piston 52 and

pivotly connected to the horizontal member 48 at pivot points 48a and 48b, respectively. During operations, as the weight or tension on the guide arch 44

varies, the piston 52 enables the guide system 40 to move vertically. The large radius and the piston 52 make the guide system 40 resilient, thereby avoiding

excessive stress on the tubing 142. This system has been found to improve the life of the coiled tubing compared to the fixed gooseneck systems

commonly used in the oil industry. A position sensor 56 is coupled to the piston 52 to determine the position of the guide arch 44 relative to its original or non-operating position. During operations, the control unit 170 continually determines the position of the guide arch 44 from the sensor 56. The control

unit 170 is programmed to activate an alarm and/or shut down the operation if the guide arch 44 has moved downward beyond a predetermined position.

The position of the guide arch 44 correlates to the stress on the guide arch 44. All of the hydraulically operable elements of the wellhead equipment 17 are coupled to the hydraulic power unit 60, including the blowout preventor stack 18. For each such hydraulically operated element, an electrically operable

control valve, such as valve 19 or 124, is placed in an associated line, such as

line 21 connected between the element and the hydraulic power unit 60. Each such control valve is operatively coupled to the control unit 170, which controls the operation of the control valve 19 or 124 according to programmed instructions. In addition, the control unit 170 may be coupled to a variety of other sensors (not shown), such as pressure and temperature sensors for determining the pressure and temperature downhole and at the wellhead

equipment. The control unit 170 is programmed to operate such elements in a manner that will close the wellhead equipment 17 when an unsafe condition is detected by the control unit 170.

FIG. 2 shows a schematic elevational view of a tubing injection system

100 that moves tubing 142 from a reel 180 at a floating rig 101 (such as a ship or a semi-submersible rig, herein referred to as the "vessel") to a permanently installed injector 200 at a subsea wellhead 119 and through a subsea wellbore (not shown) according to the present invention. A template

120 on the sea bed 121 supports a frame 127 that in turn supports the wellhead equipment (described below) and connects tension lines 123 to the

vessel 101. FIG. 2 shows typical wellhead equipment used during the drilling

of offshore wellbores. The wellhead equipment includes a control valve 124 that allows the drilling fluid to circulate to the surface via a fluid line 128 and a blow-out-preventor stack 126 having a plurality of control valves 126a. A lubricator 130 with its associated flow control valves 130a is shown placed

over the blow-out-preventor stack 126. The flow control valves 130a associated with the lubricator 130 are utilized to control the discharge of any fluid from the lubricator 130 to the surface via a fluid flow line 132. A stuffing box 136, placed over the lubricator 130, provides a seal around the tubing 142

when it passes therethrough.

A first frame 138 is supported above the stuffing box 136 and a second

frame 140, having a substantially flat platform 144, is supported over the first frame 138. The two frames 138 and 140 have suitable openings above the

stuffing box 136, sufficient to allow passage of a desired sized bottomhole

assembly (not shown) to the stuffing box 136. Tension lines 123 connect the frames 127 and 138, while tension lines 141 are used to position the second platform 140 over the first platform 138. The tension lines 141 are moored to

the vessel 101. An injector, such as the injector 200 described earlier, is permanently

(i.e. for the duration of the work to be performed) placed on the platform 144 above the wellhead equipment. A stripper 178 may be placed over the injector

200 to cut the tubing 142, if required during operations. A control unit 170, such as described earlier with respect to FIG. 1 , placed on the vessel 101 , controls the operation of the tubing injection system 100, including the operation of the injector 200, the wellhead and various other elements

associated with the tubing injection system 100. The control unit 170

preferably includes a computer, associated memory, recorder, display unit and other peripheral devices (not shown). The computer computes the values of the various operating parameters from input or data received from the various sensors in the tubing injector system 100 and carries out data manipulation in response to programmed instructions provided to the control unit 170.

A hydraulic power unit 160 placed on the vessel platform 102 provides

the required pressurized fluid to the various hydraulically-operated devices in the tubing injection system 100. A valve control unit or panel 122 having a plurality of electrically-operated fluid control valves 124 is preferable placed on or near the injector 200. The valve control panel 122 may, however, be placed

at any other suitable location, including on the vessel platform 102. Individual control valves 124 control the flow of the pressurized fluid from the hydraulic power unit 160 to the various devices in the injector 200, thereby controlling the operation of such associated devices. Electrical power conductors to the

panel 122 and other subsea devices and two-way data communication links between the subsea devices and the control unit 170 are placed in a suitable conduit 111. Pressurized fluid from the hydraulic control unit 160 to the

control panel 122 is provided via a conduit 113. The operation of the system

100 is described below. Tubing 142 is coiled on the reel 180 placed on the vessel platform 102.

The reel 180 is preferably hydraulically-operated and controlled by the control unit 170. To control the operation of the reel 180, the control unit 170

operates a fluid control valve 162 placed in a fluid line 164 coupled between the reel 180 and the hydraulic power unit 160. A sensor 182, preferably a wheel-type sensor, is operatively coupled to the tubing near the reel 180. The output of the sensor 182 passes to the control unit 170, which determines the speed of the tubing 142 in either direction. A sensor 184, coupled to the reel

180, provides the rotational speed of the reel 180. A tension sensor 186 is coupled to the tubing 142 for determining the back tension on the tubing 142. In the preferred embodiment of the present invention, a relatively small injector 195 is positioned above the reel 180 for moving the tubing 142 from the reel 180 to a secondary surface injector 190 and for providing desired

tubing tension between the injector 195 and the reel 180. The injector 195 is preferably mounted on a support member 196 attached above the reel 180. The injector 195 provides and controls the line tension between the reel 180

and the injector 190. The injector 190 is preferably placed at a height "h-," above the vessel

platform 102 so as to provide adequate working space below the injector 190

to install borehole assemblies to an end of the tubing 142 received below the injector 190. If a movable injector is utilized as the injector 190, the height

"h-," can be adjusted to facilitate assembly and installation of the bottomhole

assembly to the tubing. For the purpose of this invention any suitable injector may be used such as injector 190 or injector 195.

In addition to or as an alternative to using the injector head 195, a tubing

guide or gooseneck 144 may be utilized to guide the tubing 142 from the reel 180 to the secondary surface injector 190. Any gooseneck may be utilized for the purpose of this invention. The tubing guide 144 preferably has a 180° guide arch which enables the tubing to move from the reel 180 substantially

vertically toward the vessel platform 102. The front end 144a of the gooseneck 144 is preferably positioned directly above the reel 180 and the tail end 144b is positioned above an opening 191 of the surface secondary injector 190 in a manner that will ensure that the tubing 142 will enter the secondary surface injector opening 191 vertically.

A riser 80, which may be a rigid-type riser or flexible-type riser, placed between the platform 102 and the injector 200, guides the bottomhole assembly 145 and the tubing 142 into a through opening 201 in the injector

200. The primary purpose of the injector 195 is to provide desired tension to the tubing 142 while the primary purpose of the surface injector 190 is to move the tubing 142 between the reel 180 on the vessel 101 and the injector

200. Therefore, once the bottom hole assembly 145 has passed through the

opening 201 of the subsea injector 200, the surface injector 190 may be fully opened so that the tubing 142 freely passes therethrough. For a majority of the applications, the secondary surface injector 190 need only be made strong

enough so that it can move the tubing 142 between the reel 180 and the subsea injector 200. However, for certain applications, such as relatively large diameter tubings, the surface injector 190 may be utilized to maintain a desired line pull (tension) between the reel 180 and the injectors 190 and 200. The secondary surface injector 190 may also be utilized to augment the subsea injector 200 in case of emergency, such as in the event the tubing 142 starts

to free fall into the wellbore.

Still referring to FIG. 2, all of the hydraulically-operable elements,

including each of the injectors 190, 195 and 200, control valves of the blowout preventor 26 and those of the lubricator 30, receive pressurized fluid from the hydraulic power unit 160 via their associated fluid lines. Typically, for each such hydraulically-operated element, an electrically-operated control valve, such

as valve 124, is placed in its associated line (not shown), which is connected between the element and the hydraulic power unit 160. Each such control valve is operatively coupled to the control unit 170, which controls its operation according to programmed instructions. In addition, the control unit

170 is coupled to a variety of other sensors, such as pressure and temperature sensors for determining the pressure and temperature at the wellhead. The control unit 170 is programmed to operate such elements in a manner that will

close the wellhead equipment when an unsafe condition is detected by the

control unit 170.

A typical procedure to move the bottomhole assembly 145 attached to the end of the tubing 142 from the vessel 101 into the wellbore is as follows. The subsea injector 200 is permanently (for the duration of the task to be

performed) mounted on the subsea wellhead in any suitable manner. An end

of the tubing 142 is moved through the surface injector 190 into the work area 191. The bottomhole assembly 145 is attached to the end of the tubing 142. The pressure between the stuffing box 136 and the lubricator 130 is equalized. This may be done by closing the lower valve 130a of the lubricator 130. The stuffing box 136 is opened and the subsea injector 200 is opened to its fully open position. The reel 180, injectors 190 and 195 (if installed) are then

operated to move the tubing 142 into the riser 80. The tubing 142 is moved by the injector 190 while the small injector 195 provides a desired line pull between the injector head 195 and the reel 180. The riser 80 guides the bottomhole assembly 145 from the vessel 101 through the opening 201 of the

injector 200 and into the stuffing box 136. After the bottomhole assembly 145 has passed into the stuffing box 136, the injector 200 is operated so that the gripping members of the chain

mechanism (described later) securely hold the tubing 142. The stuffing box 136 is closed around the tubing 142. The lubricator 130 is pressure tested using sea water provided by a control line 132 from the surface or via the tubing 142 and the bottomhole assembly 145. The pressure between the

lubricator 130 and the wellbore is then equalized by using any known method in the art. The wellhead valves 126a are then opened to allow the bottomhole assembly to pass therethrough and into the wellbore. The subsea injector 200 is operated at a desired speed to move the bottomhole assembly 145 into the

wellbore. During operation, the wellbore fluid is circulated through the tubing 142, the bottomhole assembly 145, and a return line 128 at the wellhead to the surface. The wellbore fluid is not circulated through the lubricator 130. The lubricator 130 is filled with the sea water to prevent collapse of the

lubricator 130.

The above procedure is reversed to retrieve the bottomhole assembly

145 to the vessel 101 It will be appreciated that in the present system, the subsea injector 200 is installed only once for the entire length of the operation. The bottomhole assembly :s moved into and out of the wellbore without removing the injector 200. The above procedure allows for attaching the

bottomhole assembly to the tubing 142 at the vessel 101 and passing it through the subsea injector 200 and then moving the bottomhole assembly and

the tubing 142 through the wellbore. This procedure is relatively simple and

is safer compared to the prior art methods. In the prior art methods, the bottomhole assembly 145 is attached to the tubing below the injector to be deployed under water prior to the deployment. Also, the injector is deployed

under water with the coiled-tubing securely holding the injector. To retrieve the bottomhole assembly to the vessel, the under water injector is moved to the

vessel.

The function and operation of the injector 200 will now be described while referring to FIGS. 3, 4A, and 4B. FIG. 3 shows a schematic elevational view of an embodiment of the injector 200 according to the present invention. The injector 200 contains two vertically placed opposing blocks 210a and 210b

that are movable with respect to each other in a substantially horizontal direction so as to provide a selective opening 272 of width "d" therebetween. The lower end of the block 210a is placed on a horizontal support member 212 supported by upper rollers 214a and a lower roller 216a. Similarly, the lower

end of the block 210b is placed on a horizontal support member 212 supported by upper rollers 214b and lower roller 216b. The blocks 210a and 210b are pivotly connected to each other at a pivot point 219 by pivot members 218 in a manner that enables the blocks to move horizontally, thereby creating a desired opening of width "d" between such blocks. A plurality of hydraulically- operated members (RAM) 230a-c are attached to the blocks 210a-b for adjusting the width "d" of the opening 272 to a desired amount. The RAMS

230a-c are operatively coupled via a control valve 124 placed in the control

panel 122 to the hydraulic power unit 160. The control unit 170 controls the RAM action. The RAMS 230a-c are all operated in unison so as to exert substantially uniform force on the blocks 210a and 210b.

Injector block 210a preferably contains an upper wheel 240a and a lower wheel 240a', which are rotated by a chain 211a connected to teeth 213a and 213b of the wheels 240a and 240b respectively. The upper wheel 240a contains a plurality of tubing holding blocks 242a attached around the circumference of the upper wheel 240a. Similarly, injector block 210b contains an upper wheel 240b and a lower wheel 240b', which are rotated by a chain

211b connected to the teeth of such wheels. The upper wheel 240b contains a plurality of tubing holding blocks 242b attached around the circumference of the upper wheel 240b. The wheels 240a and 240b are rotated in unison by a suitable variable speed motor (not shown) whose operation is controlled by the control unit 170. Each block 242a and 242b is adapted to receive a Y-block therein, which is designed for holding or gripping a specific tubing size or a

narrow range of tubing sizes. Additionally, a separate vertically operating RAM 260 is connected to each of the lower wheels for maintaining a desired tension on their associated chains. The RAMS 260 are preferably hydraulically- operated and electrically-controlled by the control unit 170.

Still referring to FIG. 3, for underwater use, members 240a and 240b,

motors (not shown) for operating the chain drives, rams 230a-230c, panel 122,

and any other electro-hydraulic interface and bearings of the injector 200 are selectively sealed, leaving the chain and the blocks 242 exposed to the water. Sealing selected items of the subsea injector 200 prevents such elements from rusting and avoids either completely sealing the subsea injector 200 or using gas to expel water from around the subsea injector 200 as taught by prior art

methods, which can be very expensive. FIG.4A shows a side view of an injection tubing holding block 242, such

as blocks 242a-b shown in FIG. 3. FIG. 4B shows a side view of a holding member 295 for use in the block 242. The block 242 is "Y-shaped" having outer surfaces 290a and 290b which respectively have therein receptacles 292a and 292b for receiving therein the tubing holding member 295. Each

surface of the Y-block 242 contains a resilient member, such as member 293b shown placed in the surface 292b. The outer surface of the holding member 295 may contain a rough surface or teeth for providing friction thereto for holding the tubing 142 (FIG. 2). A separate holding member 295 is placed in

each of the outer surfaces of the Y-block 242 over the resilient member. The Y-blocks 242 are fixedly attached to the upper wheels 240a-b around their respective circumferences as previously described. During operations, the Y- blocks are urged against the tubing 142, which causes the holding members

295 to somewhat bite into the tubing 142 to provide sufficient gripping action. As the wheels 240a-b rotate, the Y-blocks 242 grip the tubing 142 and move it in the direction of rotation of the wheels 240a-b. If the tubing has irregular

surfaces or relatively small joints, the resilient members provide sufficient

flexibility to the holding members to adjust to the changing contour of the

tubing without sacrificing the gripping action.

As shown in FIG 3, the injector 200 preferably includes a number of

sensors which are coupled to the control unit 170 (FIG. 2) for providing information about selected injector head operating parameter. The injector

head 200 preferably contains a speed sensor 270 for determining the rotational speed of the injector 200, which correlates to the speed at which the injector

head 200 should be moving the tubing 142 (FIG. 2). The control system 170 determines the actual tubing speed from the sensor 162 (FIGS. 1 and 2), which may be placed at any suitable place such as near the injector head as shown in FIG. 3. A sensor 273 is provided to determine the size "d" of the

opening between the injector head Y-blocks 242. Additional sensors are provided to determine the chain tension and the radial pressure or force applied to the tubing 142 by the Y-blocks 242. Now referring back to FIG. 1 , the control unit 170 is coupled to the

various sensors and control valves in the rig 10 and it controls the operation of the rig 10, including that of the injector head 200 and the blowout preventor

18 according to programmed instructions. Prior to operating the rig 10, an

operator enters information into the control unit 170 about various elements of the system, such as the size of the tubing and limits of certain parameters, such as the maximum tubing speed, the maximum difference allowed between the actual tubing speed obtained from the sensor 162 and the tubing speed

determined from the injector head speed sensor 270. The control unit 170 also continually determines the tension on the chains 211a and 211b, and the radial pressure on the tubing 142. Still referring to FIG. 1 , to operate the rig 10, an operator inputs to the

control unit 170 the maximum outside dimension of the bottomhole assembly 145, the size of the tubing 142 to be utilized, the limits or ranges for the radial

pressure that may be exerted on the tubing 142, the maximum difference between the actual tubing speed and the injector head speed and limits relating

to other parameters to be controlled. An end of the tubing 142 is passed over the guide arch 44 and held in place above the working platform 30. An

operator attaches the bottomhole assembly 145 of the desired downhole equipment to the tubing end. The RAMS 230a-c are then operated to provide an opening 202 in the injector head 200 that is sufficient to pass the bottomhole assembly therethrough. After inserting the bottomhole assembly

into the wellhead equipment 17, the control unit 170 can automatically operate the injector 200 based on the programmed instruction for the parameters as input by the operator. In one mode, the system 10 may be operated wherein

the control unit 170 inserts the tubing 142 at a predetermined speed and

maintains the radial pressure on the tubing 142 within predetermined limits.

If a slippage of the tubing 142 through the injector 200 is detected, such as when it is determined that the actual speed of the tubing 142 is greater than the speed of the injector 200, then the control unit 170 causes the RAMS 230a-c to exert additional pressure on the tubing to provide greater gripping

force to the blocks 242b. If the slippage continues even after the gripping force has reached the maximum limit defined for the tubing 142 and the back tension on the tubing is within a desired range, the control unit 170 may be programmed to activate an alarm (not shown) and/or to shut down the

operation until the problem is resolved.

Still referring to FIG. 1 , with respect to the operation of the injector 200, during normal operation when the tubing is inserted into the wellbore, the control unit 170 continually maintains the tubing speed, tension on the chains 211a-b and radial pressure on the tubing 142 within predetermined limits

provided to the control unit 170. Additionally, the control unit 170 maintains the back tension on the reel 180 and the position of the tubing guidance system 40 within their respective predetermined limits. The control unit 170 also controls the operation of the wellhead equipment 17. During removal of the tubing from the wellbore, the control unit 170 operates the reel 180 and the injector 200 to remove the tubing 142 from the wellbore. Thus, in one

mode of operation, the system 10 of the invention automatically performs the tubing injection and removal operations for the specified tubing used according

to programmed instruction.

The rig system 10 of the present invention requires substantially less

manpower to operate in contrast to comparable conventional rigs. The bottomhole assembly is safely connected to the tubing 145 at a working platform 30 prior to inserting the bottomhole assembly into the injector head

and disconnected after the bottomhole assembly has been safely removed from

the wellbore to the working platform 30 above the injector head without requiring human intervention to move either the tubing guidance system 40 or the injector 200 as required in the prior art systems. The injector 200 is fixed

above the wellhead equipment 18, which is safer compared to the systems

which require moving the injector. Substantially all of the operation is performed from the control unit 170 which is conveniently located at a safe distance from the rig frame 12, thus providing a relatively safer working

environment. The operations are automated, thereby requiring substantially fewer persons to operate the rig system.

Now referring to FIG. 2and 3, the tubing injection system 100 contains

a number of sensors. Such sensors are coupled to the control unit 170 which determines information about selected parameters of the tubing injection system 100. The subsea injector 200 preferably contains a speed sensor 270 for determining the rotational speed of the injector, which correlates to the speed at which the injector 200 should be moving the tubing 142. The control

unit 170 determines the actual tubing speed from the sensor 162 placed at the surface injector 190 or a sensor 162' placed at the subsea injector 200. A

sensor 273 is provided to determine the size "d" of the opening between the injector Y-blocks 242a-b. Additional sensors are provided to determine the tension on the chains 211a and 211b and the radial pressure or force applied to the tubing 142 by the Y-blocks 242a-b.

As shown in FIG. 2, the control unit 170 is coupled to the various sensors and control valves in the system 100 for determining the values of the various operating parameters of the system 100 including parameters relating to the injectors 190, 195 and 200, the tension on the tubing 142 and the

actual speed of the tubing 142. It also controls the operation of the system,

including that of the injector 200 according to programmed instructions. Any connections between the control unit 170 and the subsea sensors may be made by electrical wires run inside a sea worthy cable or conduit 113.

Prior to operating the system 100, an operator provides the control u t

170 with information about various elements of the system 100, such as the sizes of the tubing 142 and the bottomhole assembly 145 and limits of certain parameters, such as the maximum tubing speed, the maximum difference

permitted between the actual tubing speed obtained from the sensor 162 or

162' and the tubing speed determined from the injector speed sensor 270. Additionally, the maximum radial pressure that may be exerted on the tubing 142 and limits relating to other parameters to be controlled are also provided

to the control unit 170. To pass the bottomhole assembly 145 through the

injector opening 202, the control unit 170 operates the RAMS 230a-230c to provide an opening that is large enough to pass the bottomhole assembly 145 through the opening. After the bottomhole assembly 145 has passed through

the lubricator 30, the control unit 170 may be set to automatically operate the injector 200 based on the programmed instruction. In one mode, the system 100 may be operated wherein the control unit 170 inserts the tubing 142 at a

predetermined speed and maintains the radial pressure on the tubing 142 within predetermined limits. If a slippage of the tubing 142 through the subsea injector 200 is detected, i.e., when the actual speed of the tubing is greater than the speed of the injector, then the control unit 170 causes the RAMS to

exert additional pressure on the tubing 142 to provide greater gripping force to the blocks 242a-b. If the slippage continues even after the gripping force has reached the maximum limit defined for the tubing 145 and the back tension on the tubing is within a desired range, the control unit 170 is programmed to

activate an alarm and/or to shut down the operation until the problem is resolved.

Still referring to FIG. 2, with respect to the operation of the injector 200,

during normal operation when the tubing 142 is inserted into the wellbore, the

control unit 170 continually determines the tension on the chains 211a and 211b (FIG. 2), the radial pressure on the tubing., and the speed of the tubing 142, and operates the injector 200 so as to maintains the tubing speed, tension

on the chains 211a-b and radial pressure on the tubing within predetermined

limits provided to the control unit 170. The control unit 170 also controls the operation of the wellhead equipment 118. During removal of the tubing 142 from the wellbore, the control unit 170 operates the reel 180 and the injectors 190, 195 and 200 to remove the bottomhole assembly 145 and the tubing 142 from the wellbore.

FIG. 5 shows a generic block functional diagram of the interconnection

and operation of the various elements of tubing injection systems 10 and 100 respectively shown in FIGS. 1 and 2. The electrically-operated fluid control valves, generally shown by box 324, are coupled to the various surface and/or subsea hydraulically-operated devices. The surface hydraulically-operated devices may include the surface injectors 340 and 348, reel 342 and any other

devices, which are generally denoted herein by box 346. The subsea hydraulically-operated devices may include the subsea injector 352, pumps and other devices associated with the lubricator 354, the blow-out-preventor 356, and other subsea devices, generally denoted herein by box 358. The various sensors in the system, whether placed under water or at the surface, provide

signals directly or after pre-processing to the control unit 310. The surface sensors may include sensors for determining the tubing speed 334, reel tension

332, sensors placed in the tubing guidance system 336 and any other desired sensors. Other sensors are generally denoted herein as S^S,, and may include

sensors for determining the chain tension and the width of the opening of the injector, wellhead pressure and sensors for determining other operating parameters. The control unit 310 computes the values of the various operating

parameters of the systems 10 or 100 as the case may be in response to the information provided by the various sensors and programmed instructions. The control unit 310 controls the operation of the various devices in response to the computed parameters and instructions provided to the control unit 310. The

control unit 310 may be programmed to periodically or continually update

selected operating parameters of the systems 10 or 100 and cause the operation to shut down and/or activate one or more alarms when one or more of the operating conditions is unsafe or undesirable. The control unit 310 can operate the systems 10 and 100 to provide optimal handling of the tubing 142.

The system 10 and 100 of the present invention may be programmed to

automatically perform the tubing injection and removal operations for the specific tubing used for a given operation. In the present system, substantially all of the operation is performed from the control unit 170, which is conveniently located at a safe distance from the other tubing injection equipment, thus providing a relatively safer working environment. The tubing injection and retrieval operations are automated, thereby providing greater

control over the operations compared to the known prior art systems. The systems of the present invention also require fewer persons to operate the

systems compared to the prior art systems.

While the foregoing disclosure is directed to the preferred embodiments of the invention, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope and spirit of the appended

claims be embraced by the foregoing disclosure.

Claims

WHAT IS CLAIMED IS:

1 . Tubing injection apparatus for use in oilfield wellbore operations,

comprising: (a) an injector head for holding a tubular member in an opening of adjustable width in the head for moving the tubular member in a substantially vertical direction;

(b) a ram system coupled to the injector head for controlling the width of the opening and for providing a predetermined gripping force to the injector head for securely gripping the tubular member; and

(c) an electrical control system for controlling the ram system to adjust the opening and to provide the predetermined gripping force to the injector head.

2. The apparatus as specified in claim 1 , wherein the ram system is actuated by a pressurized fluid that is controlled by the electrical control system.

3. The apparatus as specified in claim 2, wherein the electrical control system includes an electrically-controlled valve coupled to the ram system for controlling flow of a pressurized fluid to the ram system.

4. The apparatus as specified in claim 1 , wherein the electrical control

system includes a sensor placed at the injector head for determining the speed

of the tubular member passing through the opening in the injector head.

5. The apparatus as specified in claim 1 , wherein the injector head includes

two continuously movable members positioned opposite each other and spaced

apart to define the opening in the injector head, each such movable member

having connected thereto a plurality of spaced holding blocks for gripping the

tubular member when the predetermined gripping force is applied to the

movable members.

6. The apparatus as specified in claim 5, wherein the electrical control

system further includes a sensor for determining the speed of the movable

members.

7. The apparatus as specified in claim 6, wherein the electrical control

system increases the gripping force on the movable members when the speed

of the tubular member is greater than the speed of the movable members.

8. The apparatus as specified in claim 5, wherein each holding block

includes a resilient member associated therewith for providing flexibility of movement of the holding block when engaging the tubular member.

9. The apparatus as specified in claim 8, wherein each of the movable members includes a motor-operated circular motion chain.

10. The apparatus as specified in claim 9, wherein the ram system contains at least one pressurized fluid actuated ram and wherein each of the movable members is movably mounted on a respective backing member, with the ram

controlling the opening between the movable members.

1 1 . A rig for use in wellbore operations, comprising: (a) an injector head placed on a first platform, the injector head

having: (i) at least two movable members having holding blocks for

gripping a tubular member in an opening of adjustable width between the holding blocks and for moving the tubular member in a substantially vertical direction, and (ii) a ram coupled to the injector head for adjusting the width

of the opening between the holding blocks and for providing a predetermined gripping force to the holding

blocks for securely gripping the tubular member, the ram

being operable upon the application of fluid under pressure, (b) a guide positioned above the injector head for directing a tubing

into the injector head opening in a substantially vertical direction; and (c) an electrical control system for controlling the ram to adjust the opening and to provide the predetermined gripping force to the

injector head.

12. The rig as specified in claim 1 1 , wherein the guide is movably mounted on a support structure attached to a second platform.

13. The rig as specified in claim 1 1 , wherein the guide is movably mounted on a support structure on the second platform for adjusting height of the guide above the second platform within a predetermined range.

14. The rig as specified in claim 13, wherein the electrical control system includes a sensor associated with the guide for detecting the vertical position

of the guide.

15. The rig as specified in claim 1 1 further including coiled tubing having a first end passing through the opening in the injector head and a second end

which is spooled on a reel.

16. The rig as specified in claim 11 , wherein the electrical control system includes a sensor for monitoring tension of the coiled tubing extending from the

reel.

17. The rig as specified in claim 1 1 , wherein the electrical control system includes a sensor placed at the injector head for determining the speed of the

tubular member passing through the opening in the injector head.

18. The rig as specified in claim 1 1 , wherein the electrical control system includes an electrically controlled valve for controlling flow of fluid to the ram.

19. The rig as specified in claim 18, wherein the control system controls the valves for controlling flow of fluid under pressure to control the operation of the ram.

20. The rig as specified in claim 1 1 , wherein the electrical control system includes a sensor placed at the injector head for determining the speed of the tubular member passing through the opening in the injector head.

21. The rig as specified in claim 20, wherein the electrical control system includes a sensor for determining the weight of the tubular member.

22. The rig as specified in claim 1 1 , wherein the injector head includes two continuously movable members positioned opposite each other and spaced apart to define the opening in the injector head, each such movable member

having connected thereto a plurality of holding blocks for gripping the tubular member and for applying the predetermined force on the movable members.

23. The rig as specified in claim 1 1 , wherein the electrical control system

includes a sensor for determining the speed of the movable members.

24. The rig as specified in claim 23, wherein the electrical control system increases the gripping force on the movable members when the speed of the

tubular member is greater than the speed of the movable members.

25. Apparatus for handling tubular members for use in an underwater

wellbore, comprising: (a) a first underwater injector adjacent to the seabed for moving a tubular member through the wellbore;

(b) a secondary surface injector for receiving the tubular member from

a source thereof and moving the tubular member between the

source and the first underwater injector; and

(c) a riser between the first underwater injector and the secondary

surface injector for guiding the tubular member to the first

underwater injector.

26 The apparatus according to claim 25, wherein the tubular member is

selected from a group consisting of a coiled-tubing and a jointed tubing.

27. The apparatus according to claim 25, wherein the first underwater

injector is placed on a wellhead at the sea bed.

28. The apparatus according to claim 27, wherein the wellhead comprises:

(i) a stuffing box below the first underwater injector, said stuffing

box providing a seal around the tubular member when the tubular member is passed therethrough; and

(ii) a lubricator between the wellbore and the stuffing box, said

lubricator having control valves that enable discharging fluids

accumulated in the lubricator.

29. The apparatus according to claim 25, wherein the first underwater

injector includes an endless chain mechanism having gripping members

attached thereto for securely holding and moving the tubular member through the first underwater injector.

30. The apparatus according to claim 29 further having a motor for moving

the endless chain mechanism and a ram to urge the gripping members against the tubular member.

31 . The apparatus according to claim 30, wherein the motor and the rams

are selectively sealed from its surroundings while the endless chain is exposed to the surroundings.

32. The apparatus according to claim 26 further comprising a plurality of

electrically- operated fluid control valves associated with the first underwater

injector for controlling the flow of a pressurized fluid to a plurality of devices

in the first injector that operate the first injector.

33. The apparatus according to claim 32, wherein the electrically-operated fluid control valves are placed under water near the first underwater injector.

34. The apparatus according to claim 32 further compπsing a hydraulic power unit at the surface for supplying pressurized fluid to the plurality of electrically operated fluid control valves associated with the first underwater injector for controlling the flow of a pressurized fluid to a plurality of devices

in the first injector that operate the first injector.

35. The apparatus according to claim 32 further comprising a control unit for

controlling the operation of the first underwater injector.

36. The apparatus according to claim 35, wherein the control unit controls

the operation of the electrically operated fluid control valves.

37. A method for moving a tubular member from a source thereof through a subsea wellbore, comprising: (a) providing a first underwater injector adjacent to the seabed for

moving the tubular member into the wellbore;

(b) providing a second surface injector at the surface for moving the tubular member between the source and the first underwater injector; and

(c) providing a riser between the first underwater injector and the second surface injector for guiding the tubular member into the first underwater injector.

38. The method of claim 37 further comprising: (i) moving the tubular member through the riser by the injector on the vessel; and

(ii) moving the tubular member through the wellbore by the first underwater injector.

39. The method of claim 38 further comprising removing the injector on the vessel when the tubular member has passed through the underwater injector.

40. The method of claim 38 further comprising providing a control unit

operatively coupled to the underwater injector for controlling the operation of the underwater injector.

41. A method for moving a tubular member from a source thereof through

a subsea wellbore, comprising:

(a) placing a first underwater injector on a subsea wellhead, said underwater injector having an opening of adjustable size between a predetermined range therethrough; (b) providing a second surface injector at the surface for moving the tubular member between the source and the first underwater injector; and (c) attaching a bottomhole assembly to an end of the tubular member, said bottomhole assembly having an outside dimension

that is greater than the outside dimension of the tubing; (c) opening the first underwater to a size that is larger than the outside dimension of the bottomhole assembly;

(d) passing the bottomhole assembly through the opening of the underwater injector by utilizing the surface injector; and (e) moving the tubular member by the underwater injector into the wellbore.