Patent Application
20110024103
1. Field of the Invention
Embodiments of the present invention generally relate to a method and apparatus for providing a conductor in a tubular.
1. Description of the Related Art
The use of coiled tubing in the oil industry is increasing in popularity for drilling, completion, and production operations in crude oil or natural gas wellbores. Historically, strings of drill pipe were used for drilling and conducting operations inside a wellbore, usually several hundred or thousand feet under the surface of the ground. However, joints of drill pipe must be threaded together and lowered into the wellbore over a long time period of many hours or days. Coiled tubing emerged as a solution by providing a relatively fast and reliable method of conducting operations downhole within a wellbore, without using heavy and cumbersome jointed drill pipe.
Coiled tubing is a continuous tubular strand traditionally made from steel possessing sufficient ductility to withstand flexing as the tubing is uncoiled from a reel for insertion into the wellbore or coiled back onto the reel for removal from the wellbore since the coiled tubing is plastically deformed onto the reel. Coiled tubing is traditionally manufactured by rolling flat strips cut from rolls of sheet steel into a tubular shape and fusion welding the seam. Recent advances include composite coiled tubing strings made from fibers embedded in a resin matrix fibers embedded in a resin matrix. The fibers, usually glass and carbon, are wound around an extruded thermoplastic tube and saturated with a resin, such as epoxy. Another recent advance is seamless steel coiled tubing which may be manufactured by extrusion.
Coiled tubing is deployed using a coiled tubing unit. The coiled tubing unit includes the reel, an injector, controls, and a power pack. The injector feeds the coiled tubing into the wellbore through a stripper mounted on the wellhead. Such a coiled tubing unit is discussed and illustrated in U.S. Pat. No. 5,828,003, which is herein incorporated by reference in its entirety.
Current coiled tubing applications include slim hole drilling, deployment of reeled completions, logging of deviated or highly deviated (i.e., horizontal) wellbores, and deploying treatment fluids downhole. The use of coiled tubing in highly deviated or horizontal wellbores is rapidly increasing at a rapid rate.
Many of these applications would benefit from the ability to transmit and receive data and/or or transmit power from the surface. This ability could be used to monitor the properties of the coiled tubing, detect pressure and temperature inside the wellbore at the distal end and/or along the coiled tubing, monitor and/or control the operation of downhole tools mounted upon the distal end of the coiled tubing, and/or detect an exact depth of the distal end of the coiled tubing.
Past attempts at transmitting data to the surface include wireless telemetry (i.e., mud pulse, electromagnetic, and acoustic). However, wireless telemetry suffers from low bandwidth (i.e., 10 bits/second), latent travel time (speed of sound for acoustic and mud pulse), and inability to transmit electricity. U.S. Pat. No. 6,717,501 to Hall discloses wired drill pipe. However, wired drill pipe suffers from the disadvantages of drill pipe, discussed above. U.S. Pat. No. 6,143,988 to Neuroth discloses a cable disposed in a coiled tubing string. However, Neuroth requires deforming the coiled tubing to support the weight of the cable and a jacket and armor to protect and support the cable. U.S. Pat. No. 5,828,003 to Thomeer discloses coiled tubing made from a composite laminate having conductive wires embedded therein. Thomeer's composite is extremely complicated to design and manufacture. U.S. Pat. No. Re. 36,833 to Moore discloses a continuous tubing having conductors enclosed by a metal strip welded to the tubing as the tubing is roll-formed and welded. U.S. Pat. No. 7,025,580 to Heagy discloses an inflatable liner bonded to a pipe with a resin and having a channel housing a cable conduit.
For some of these applications, it may be desirable to coat an inner surface of the coiled tubing wall to protect the surface from corrosion or plugging. Corrosion may be caused by pumping an acidic solution through the coiled tubing in a formation treatment operation. Plugging may be caused by pumping hydrocarbon fluid through the coiled tubing in a low temperature environment, such as subsea. Byproducts, such as paraffin may condense from the hydrocarbon fluid and adhere to the inner surface of the coiled tubing. Such a coating process is discussed in U.S. patent application Ser. No. 12/388,166 (Atty. Dock. No. TUBE/0003), filed Feb. 18, 2009, which is herein incorporated by reference in its entirety. The '166 application discusses a multi-cycle coating regimen including a degreasing cycle, a rinse cycle, a descaling cycle, a neutralization cycle, a drying cycle, an inhibitor cycle, and a coating cycle. The working fluid for each cycle may be applied using a pig or pigtrain. The protective coating may be a polymer, such as epoxy, polyurethane, or polytetrafluoroethylene (PTFE).
Embodiments of the present invention generally relate to a method and apparatus for providing a conductor in a tubular. In one embodiment, a coiled tubing string for use in a wellbore includes: a tubular; a conductor extending at least essentially a length of the tubular; and a tubular coating extending at least essentially the length of the tubular and bonding the conductor to an inner surface of the tubular.
In another embodiment, a tubing string for use in a wellbore includes: a tubular; a first tubular coating extending a length of the tubular and made from an electrically conductive material; and a second tubular coating extending the length of the tubular and made from an electrically insulating material. The first coating is disposed between the second coating and an inner surface of the tubular.
In another embodiment, a method for bonding a conductor to an inner surface of a tubular includes: pumping a volume of coating in front of a pig; and propelling the pig through the tubular, wherein the pig applies the coating to the inner surface having at least a portion of the conductor laid thereon.
In another embodiment, a method for forming a signal conductor along an inner surface of a tubular, includes: pumping a volume of coating in front of a pig; and propelling the pig through the tubular. The pig applies the coating to the inner surface and the coating is electrically conductive.
In another embodiment, a spool pig for use in a coiled tubing string, includes: a nose; a tail; a mandrel connected to the nose and tail; and a spool disposed on the mandrel and rotatable relative to the mandrel.
So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
In preparing the coiled tubing 50 for deployment of the spool pig 1, an inlet 55i and outlet 55o of the tubing 50 may be located at or near ground level to allow for easier access. A clamp (not shown) may be secured to each of the inlet 50i and outlet 50o. Each clamp may have a flange to receive corresponding flanges of a pig launcher (not shown) and a pig receiver (not shown). A suitable pig launcher and receiver are illustrated in FIGS. 1 and 9-11 of U.S. Pat. No. 5,230,842, which is herein incorporated by reference in its entirety. As discussed above and in the '166 application, an inner surface 50s of the coiled tubing 50 may be treated to remove manufacturing or other debris until a white-metal or near white-metal finish, such as NACE number one or two, is achieved.
To deploy the spool pig 1 into the coiled tubing 50, the spool pig may be loaded into the launcher. Alternatively, the spool pig 1 may be launched into the coiled tubing string without using a launcher and/or receiver. Propellant P may be injected into the launcher to drive the spool pig 1 through the coiled tubing 50. The propellant P may be a fluid, such as liquid or compressed gas, such as ambient air, dry air, or nitrogen. As the spool pig 1 travels through the coiled tubing 50, a conduit 100 may unwind from the spool pig 1. An end of the conduit distal from the spool pig 1 may be fastened to the inlet or the launcher. The spool pig 1 may exert tension T on the conduit 100 as the spool pig 1 travels through the coiled tubing, thereby retaining the coiled tubing along an inner curvature of the coil. When the spool pig 1 reaches the outlet 55o, the spool pig 1 may be caught by the receiver and removed from the coiled tubing string 50. A proximate end of the conduit 100 may be fastened to the receiver, outlet, or a tensioner (not shown). The conduit 100 may be made from a metal or alloy, such as steel or aluminum, or a polymer, such as polyvinyl chloride (PVC).
The guide 12 may be a roller mounted to the mandrel 7 or rear rim 16 for feeding the conduit 100 from the spool 15 to the coiled tubing inner surface 50s. The tail 5 may have a notch formed in an outer surface thereof for passage of the conduit 100. The conduit 100 may be wrapped along the sleeve 19 and retained by the rims 16, 18. The bearings 17 may each be disposed between the head 18 or tail 16 and the mandrel 7. Alternatively, the bearings 17 may be disposed between the sleeve 19 and the mandrel 7. The bearings 17 may longitudinally connect the spool 15 to the mandrel 7 while allowing relative rotation therebetween. The bearings 17 may be fastened to the mandrel 7 and the spool 15. The tensioner 14 may include one or more Beliville washers engaging the front rim 18 and the nose 10 to frictionally dampen rotation of the spool 15, thereby maintaining tension T in the conduit. The rims 16, 18 and sleeve 19 may be integrally formed or fastened together, such as by threaded connections.
Alternatively, instead of a spool pig 1, the spool of conduit 100 may be located externally of the coiled tubing 50 and a simple pig may be used to pull the distal end of the conduit through the coiled tubing 50.
The lead extruder pig 60a may include a cup 61, a seal 63, and one or more fasteners 64h,s, 65. The cup 61 may include a wiper 61b,s and a hub 61h. The wiper 61b,s may be molded to the hub 61h. The seal 63 may include a disc 63d and one or more hubs 63h. The disc 63d may be molded between the two hubs 63h. The wiper 61b,s, and disc 63d may each be made from a polymer, such as polyurethane, ploychloroprene, or polyisoprene and the hubs 61h, 63h may be made from a metal or alloy, such as steel. The hubs 61h, 63h may be connected by a longitudinally extending fastener, such as a bolt 64h,s and a nut 65 engaged with a threaded shank 64s of the bolt. A head 64h of the bolt may shoulder against a base 61b of the wiper 61b,s.
An outer portion of the disc 63d may be in sealing engagement with the coiled tubing inner surface 50s and be solid. The wiper 61b,s may have a flexible, cylindrical wall or skirt 61s, extending rearwardly from a base 61b connected or mounted to the bolt 64h,s. The flexible skirt 61s may be expandable outwardly in response to pressure differential during movement of the pig 60a through the coiled tubing 50 in coating operations. When so expanded outwardly, the skirt 61s may define an annular front reservoir Ra between the disc 63d and the skirt 61s. The skirt 61s and the outer portion of the disc 63d may be flexible enough to accommodate passage over the conduit 100. Alternatively, the skirt and the disc may each have a notch formed in an outer portion thereof and aligned with the conduit to accommodate the conduit. The annular reservoir Ra may be filled with a volume of the coating material 110 to be applied to the interior surface of the coiled tubing 50. The coating material 110 in reservoir Ra may be urged toward the coiled tubing inner surface under the force of the pressure moving the lead pig 60a through the tubing 50, and the flared skirt 61s may exert a wiping blade action about its outer periphery for this purpose. One or more feed ports 61p may be formed through the base 61b. The feed ports 61p may allow passage into the annular reservoir R of the coating material 110 from a main charge of coating material 110 transported between the pigs 60a,b.
The trail pig 60b may be similar to the lead pig 60a except that the disc 63d may have one or more passages or slots 63p formed through an outer portion thereof and the ports 61p may be omitted. The size and number of coating material slots 63p may be chosen to regulate the amount of coating material 110 which may pass rearwardly of the disc 63d into a rear reservoir Rb. One of the ports 63p may or may not be sized and aligned with the conduit 100 to accommodate the conduit 100. The rear reservoir Rb may receive a regulated volume of coating material 110 from the main charge through the slots 63p as the trail pig 60b moves through the coiled tubing 50. The skirt 61s of the trail pig 60b may be flexible outwardly to a position where an outer rim is spaced from the coiled tubing inner surface 50s to define a circumferential gap. As with the skirt 61s of the lead pig 60a, the skirt 61s of the trail pig 60b may be flexible enough to accommodate passage over the conduit 100 or may have a notch formed in an outer portion thereof in alignment with the conduit to accommodate the conduit. The amount of flexure of rear pig skirt 61s and thus the size of the gap may be governed by the propellant pressure selected for movement of the pigs 60a,b through the coiled tubing 50. The selected pressure, in conjunction with the regulated volume of coating material 110 in reservoir Rb, may be used to regulate the thickness of coating material 110 deposited on the coiled tubing inner surface 50s.
An initial volume of the main charge may be sufficient to coat a length of the coiled tubing inner surface 50s with a coating 110 of predetermined thickness. After the leading and trailing extruder pigs 60a,b have been driven through the coiled tubing 50 to the receiver, the coating layer 110 may be dried by passing a sufficient volume of dehydrated air through the tubing for a time sufficient to thoroughly dry the coating layer 110. Depending on the specific coating material selected, the coating layer may require an additional curing step after it has been completely dried. For instance, where PTFE is used as the coating material, the tubing may be heated by unwinding the coiled tubing from the reel, through an oven, and then back onto a second storage reel.
As discussed more below, it may be desirable to apply one or more additional layers of the coating, whether of the same or different coating material. After the first coating layer has been dried with dehydrated air, the extruder pigs 60a,b, together with another quantity of coating material therebetween, may be loaded in reverse order and position into the downstream tubing section along with a new mass or charge of coating material to apply a second layer of coating. Alternatively, the extruder pigs 60a,b may be removed and loaded in the same order and position at the upstream loading chamber in the manner described above. The drying and/or curing process may then be repeated. Alternatively, the lead extruder pig 60a may be omitted and only the trail pig 60b may be used to apply the coating 110.
In addition to bonding the conduit 100 to the inner surface 50s, the coating 110 may serve to protect the inner surface 50s from corrosion, erosion, and/or plugging. The coating 110 may be made from a polymer, such as epoxy, polyurethane, or PTFE or, as discussed below, a composite, such as a metal/alloy-filled polymer. The coating 110 may be electrically insulating or electrically conductive.
Once the conduit 100 is bonded to the coiled tubing inner surface 50s and the fiber/cable 120f,c is inserted through the conduit, the coiled tubing may be deployed into a wellbore, such as for a drilling operation. A BHA (not shown) including a drill bit, a mud motor, a bent sub, an orienter, and a sensor sub (i.e., MWD and/or LWD) may be connected to a distal end of the coiled tubing. The cable/conduit may be used to transmit data from the BHA to the surface, such as temperature, pressure, drill bit orientation, torque, and rotary speed of the bit. The data may be transmitted at high rates, such as one or more kilo-bits, mega-bits, or giga-bits per second. The data may also be transmitted in real time (no latency time). Additionally, the sensor sub may include logging sensors to detect formation characteristics while drilling. Communication may be bidirectional such that data is sent from the BHA to the surface and instructions may be sent from the surface to the BHA, such as to actuate the orienter. Additionally, optical power may be transmitted from the surface along the fiber/cable 120f,c to an additional generator sub of the BHA including one or more photovoltaic cells. The power and data may be multiplexed on a single cable/fiber or a second cable/fiber may be added for power. The generator may used to power one or more components of the BHA, such as the orienter and/or sensor sub.
Alternatively, a single jacketed wire may be used instead of the twisted pair. In this alternative, an earth return circuit may be use to conduct data signals or electricity between the surface and the BHA. Additionally, an optical cable/fiber may be bonded to the inner surface by the coating so that the twisted pair cable may be used to transmit electricity and the optical fiber/cable may be used to transmit data. The additional optical cable/fiber may be circumferentially spaced from the twisted pair/cable and bonded directly to the inner surface or be disposed in the conduit with the cable for the conduit alternative discussed above.
The conductive layer 410b may further be used to monitor the integrity of one or both of the insulating layers 410a,c. For example if the inner insulating layer 410c is compromised by fluid erosion, a short may form between the conductive layer 410b and fluid in the coiled tubing bore, thereby substantially altering resistance of the conductive layer. The failure may be detected and the coiled tubing 50 retrieved to the surface for repair or replacement.
The coiled tubing string 50 having any of the conductors 120,320,410b,d, 420 may be used to charge a battery of a downhole tool installed in the wellbore. A coupling may be connected to a distal end of the coiled tubing 50. The coiled tubing 50 may then be injected into the wellbore until the coupling engages or is proximate to the downhole tool. The coupling may be wired or wireless (i.e., inductive coupling). Electricity may be transmitted from the surface to the downhole tool, thereby charging the battery of the downhole tool. The coiled tubing may then be retrieved to surface. Any of the conductors 120, 320, 410b,d, 420 may be used to power any downhole tool, such as a sensor sub, an orienter, a motor, and/or a tool actuator, such as a valve actuator.
Alternatively, the coiled tubing 50 may be used as production tubing, and any of the conductors 120,320,410,420 may be used to transmit data and/or power between temperature and pressure sensors of a sensor sub connected to a distal end of the coiled tubing and the surface. Alternatively, the conductors 120,320,410,420 may be bonded to an inner surface of a production tubing string instead of a coiled tubing string.
Alternatively, any of the conductors 120,320,410,420 may be used to heat the coiled tubing 50, such as for melting/disassociating a paraffin or gas hydrates plug or preventing the formation thereof.
The diverter 503 may have a conical inner surface for transitioning flow from a bore of the coiled tubing to a bore 510 of the coupling 550m. A profile 501a may be formed in an end of the mandrel 501 for receiving the diverter 503. The profile 501a may include a shoulder and a lip. The shoulder may abut an end of the diverter and the lip may have an outer diameter slightly larger than an inner diameter of a corresponding profile of the diverter, thereby forming an interference fit and longitudinally and torsionally connecting the diverter 503 and the mandrel 501. Additionally or alternatively, an adhesive (not shown) may be used to bond the diverter 503 to the mandrel 501. Each of the diverter 503 and the mandrel 501 may have a hole 501h (only mandrel hole shown) formed therethrough for pressure equalization. A groove 503g may be formed in an outer surface of the diverter 503 for receiving an end of the coating 310. A port 503p may be formed in a wall of the diverter 503 and in communication with the groove 503g for passage of one of the conductors 320. A portion of the groove 503g adjacent the port may be enlarged for receiving one of the conductors 320.
An opening 501o may be formed in an outer surface of the profile 501a and a port 501p may be formed in a wall of the mandrel 501. The opening 501o may provide for passage of one of the conductors 320 and the port 501p may house a booted contact 504 and high pressure feed-thru 505. An end of the conductor 320 may be sealed within the booted contact 504 and the booted contact may provide electrical communication between the conductor 320 and the feed-thru 505 via connection with a first end of the feed-thru. A second end of the feed-thru may be in electrical communication with a lead 550 (
The mandrel 501 may have a socket 501s formed in an outer surface thereof and the coiled tubing end 55 may have a dimple protruding from an inner surface thereof received by the socket, thereby longitudinally and torsionally connecting the mandrel to the coiled tubing end. The connection may be reinforced in tension by a conical outer surface 501c of the mandrel 501 receiving a split wedge ring 506 and abutment of the wedge ring 506 with an inner surface of the coiled tubing end 55. The mandrel 501 may also have a threaded outer surface 501t engaging a threaded inner surface 502t of the pin 502, thereby longitudinally and torsionally coupling the pin and the mandrel. A nut 507 may be longitudinally connected to the pin 502 by a shoulder and a fastener, such as a snap ring 511. The nut 507 may rotate freely relative to the pin 502. The nut 507 may have a threaded outer surface 507t. The pin 502 may have splines 502s formed around an outer surface thereof and at a tip thereof. A tip of the coiled tubing end 55 and a shoulder of the pin 502 may each be beveled 55b, 502b so a smooth and flush aggregate outer surface is formed. Various interfaces of the coupling 500m may be sealed with seals (denoted by black filling), such as o-rings.
Additionally, the male 500m and female 500f couplings may include a second booted contact 504, feed-thru 505, and leads/contacts 550-559 so that a second conductor (i.e., twisted pair 320t, circumferentially spaced 320b, or coax 320t) may be used.
Once spooled on a reel of the coiled tubing unit, the coupling at the internal end 55i may be connected to a hydraulic or mud system and a data and/or power system using one or more swivels (not shown), such as an electrical and/or hydraulic swivel or an optical and/or hydraulic swivel. The electrical swivel may include slip rings or inductive couplings to transfer data and/or power.
Additionally, either of the couplings 500f,m may be used to connect the coiled tubing string 50 to a second coiled tubing sting (not shown) having either or both the couplings 500f,m to create a longer string, such as for insertion into deep wellbores.
While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
This application claims benefit of U.S. Provisional Application Ser. No. 61/229,010, filed Jul. 28, 2009, which is hereby incorporated by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 61229010 | Jul 2009 | US |
