Many existing wells include hydrocarbon pay zones which were bypassed during drilling and completion because such bypassed zones were not economical to complete and produce. Offshore drilling rigs cost approximately $40 million to build and may cost as much as $250,000 a day to lease. Such costs preclude the use of such expensive rigs to drill and complete these bypassed hydrocarbon pay zones. Presently, there is no cost effective methods of producing many bypassed zones. Thus, often only the larger oil and gas producing zones are completed and produced because those wells are sufficiently productive to justify the cost of drilling and completion using offshore rigs.
Many major oil and gas fields are now paying out and there is a need for a cost effective method of producing these previously bypassed hydrocarbon pay zones. The locations and size of these bypassed hydrocarbon zones are generally known, particularly in the more mature producing fields.
To economically drill and complete the bypassed pay zones in existing wells, it is necessary to eliminate the use of conventional rigs and conventional drilling equipment. One method of producing wells without rigs is the use of metal coiled tubing with a bottom hole assembly. See for example U.S. Pat. Nos. 5,215,151; 5,394,951 and 5,713,422, all incorporated herein by reference. The bottom hole assembly typically includes a downhole motor providing the power to rotate a bit for drilling the borehole. The bottom hole assembly operates only in the sliding mode since the metal coiled tubing is not rotated at the surface like that of steel drill pipe which is rotated by a rotary table on the rig. The bottom hole assembly may or may not include a tractor which propels the bottom hole assembly down the borehole. One such tractor is a thruster that pushes off the lower terminal end of the coiled tubing and does not rely upon contacting or gripping the inside wall of the borehole. The depth that can be drilled by such a bottom hole assembly is limited.
Coiled tubing, as currently deployed in the oilfield industry, generally includes small diameter cylindrical tubing having a relatively thin wall made of metal or composite material. Coiled tubing is typically much more flexible and of lighter weight than conventional drill pipe. These characteristics of coiled tubing have led to its use in various well operations. For example, coiled tubing is routinely utilized to inject gas or other fluids into the well bore, inflate or activate bridges and packers, transport well logging tools downhole, perform remedial cementing and clean-out operations in the well bore, and to deliver or retrieve drilling tools downhole. The flexible, lightweight nature of coiled tubing makes it particularly useful in deviated well bores.
Typically, coiled tubing is introduced into the oil or gas well bore through wellhead control equipment. A conventional handling system for coiled tubing can include a reel assembly, a gooseneck, and a tubing injector head. The reel assembly includes a rotating reel for storing coiled tubing, a cradle for supporting the reel, a drive motor, and a rotary coupling. During operation, the tubing injector head draws coiled tubing stored on the reel and injects the coiled tubing into a wellhead. The drive motor rotates the reel to pay out the coiled tubing and the gooseneck directs the coil tubing into the injector head. A rotary coupling provides an interface between the reel assembly and a fluid line from a pump. Fluids are often pumped through the coiled tubing during operations. Such arrangements and equipment for coiled tubing are well known in the art.
The use of metal coiled tubing has various deficiencies. Metal coiled tubing tends to buckle the deeper the bottom hole assembly penetrates the borehole. Buckling is particularly acute in deviated wells where gravity does not assist in pulling the tubing downhole. As the tubing buckles, the torque and drag created by the contact with the borehole becomes more difficult to overcome and often makes it impractical or impossible to use coiled tubing to reach distant bypassed hydrocarbon zones. Further, steel coiled tubing often fatigues from cyclic bending early in the drilling process and must be replaced. It has also been found that coiled tubing may be as expensive to use as a conventional drilling system using jointed steel pipe and a rig.
While prior art coiled tubing handling systems are satisfactory for coiled tubing made of metal such as steel, these systems do not accommodate the relatively long spans or drill string lengths achievable with coiled tubing made of composites. Such extended spans of composite coiled tubing strings are possible because composite coiled tubing is significantly lighter than steel coiled tubing. In fact, composite coiled tubing can be manufactured to have neutral buoyancy in drilling mud. With composite coiled tubing effectively floating in the drilling mud, downhole tools, such as tractors, need only overcome frictional forces in order to tow the composite coiled tubing through a well bore. This characteristic of composites markedly increases the operational reach of composite coiled tubing. Thus, composite coiled tubing may well allow well completions to depths of 20,000 feet or more, depths previously not easily achieved by other methods.
Moreover, composite coiled tubing is highly resistant to fatigue failure caused by “bending events,” a mode of failure that is often a concern with steel coiled tubing. At least three bending events may occur before newly manufactured coiled tubing enters a well bore: unbending when the coiled tubing is first unspooled from the reel, bending when travelling over a gooseneck, and unbending upon entry into an injector. Such accumulation of bending events can seriously undermine the integrity of steel coiled tubing and pose a threat to personnel and rig operations. Accordingly, steel coiled tubing is usually retired from service after only a few trips into a well bore. However, composite coiled tubing is largely unaffected by such bending events and can remain in service for a much longer period of time.
Hence, systems utilizing composite coiled tubing can be safely and cost-effectively used to drill and explore deeper and longer wells than previously possible with conventional drilling systems. Moreover, completed but unproductive wells may be reworked to improve hydrocarbon recovery. Thus, composite coiled tubing systems can allow drilling operations into formations that have been inaccessible in the past and thereby further maximize recovery of fossil fuels.
However, these dramatic improvements in drilling operations cannot be realized without handling systems that can efficiently and cost-effectively deploy extended lengths of composite coiled tubing. Prior art coiled tubing handling systems do not readily accommodate the reel change-outs needed when injecting thousands of feet of coiled tubing downhole. Prior art coiled tubing handling systems require a work stoppage to change out an empty reel for a full reel. Because such a procedure is inefficient, there is a need for a coiled tubing handling system that more efficiently changes out successive reels of coiled tubing.
Composite coiled tubing offers the potential to exceed the performance limitations of isotropic metals, thereby increasing the service life of the pipe and extending operational parameters. Composite coiled tubing is constructed as a continuous tube fabricated generally from non-metallic materials to provide high body strength and wear resistance. This tubing can be tailored to exhibit unique characteristics which optimally address burst and collapse pressures, pull and compression loads, as well as high strains imposed by bending. This enabling capability expands the performance parameters beyond the physical limitations of steel or alternative isotropic material tubulars. In addition, the fibers and resins used in composite coiled tubing construction make the tube impervious to corrosion and resistant to chemicals used in treatment of oil and gas wells.
High performance composite structures are generally constructed as a buildup of laminated layers with the fibers in each layer oriented in a particular direction or directions. These fibers are normally locked into a preferred orientation by a surrounding matrix material. The matrix material, normally much weaker than the fibers, serves the role of transferring load into the fibers. Fibers having a high potential for application in constructing composite pipe include glass, carbon, and aramid. Epoxy or thermoplastic resins are good candidates for the matrix material.
A composite umbilical or coiled tubing typically has an impermeable fluid liner, a plurality of load carrying layers, and a wear layer. A plurality of conductors may be embedded in the load carrying layers. These conductors may be metallic or fiber optic conductors such as electrical conductors and data transmission conductors. One or more of the data transmission conduits may include a plurality of sensors. It should be appreciated that the conductors may be passages extending the length of an umbilical for the transmission of pressure fluids.
Types of composite tubing are shown and described in U.S. Pat. Nos. 5,018,583; 5,097,870; 5,176,180; 5,285,008; 5,285,204; 5,330,807; 5,348,096; and 5,469,916, each of these patents is incorporated herein by reference. See also “Development of Composite Coiled Tubing for Oilfield Services,” by A. Sas-Jaworsky and J. G. Williams, SPE Paper 26536, 1993, incorporated herein by reference. U.S. Pat. Nos. 5,080,175; 5,172,765; 5,234,058; 5,437,899; and 5,540,870, each of these patents being incorporated herein by reference, disclose composite rods, electrical or optical conductors housed in a composite cable.
The impermeable fluid liner is often an inner tube preferably made of a polymer, such as polyvinyl chloride or polyethylene. The liner can also be made of a nylon, other special polymer, or elastomer. In selecting an appropriate material for a fluid liner, consideration is given to the chemicals in the drilling fluids to be used in drilling the sidetracked well and the temperatures to be encountered downhole. The primary purpose for an inner liner is as an impermeable fluid barrier since carbon fibers are not impervious to fluid migration particularly after they have been bent. The inner liner is impermeable to fluids and thereby isolates the load carrying layers from the drilling fluids passing through the flow bore of the liner. An inner liner also serves as a mandrel for the application of the load carrying layers during the manufacturing process for the composite umbilical.
The load carrying layers are preferably a resin fiber having a sufficient number of layers to sustain the required load of the work string suspended in fluid, including the weight of the composite umbilical and bottom hole assembly.
The fibers of load carrying layers are preferably wound into a thermal setting or curable resin. Carbon fibers are preferred because of their strength, and although glass fibers are not as strong, glass fibers are much less expensive than carbon fibers. Also, a hybrid of carbon and glass fibers may be used. Thus, the particular fibers for the load carrying layers will depend upon the well, particularly the depth of the well, such that an appropriate compromise of strength and cost may be achieved in the fiber selected. Typically an all carbon fiber is preferred because of its strength and its ability to withstand pressure.
Load carrying fibers provide the mechanical properties of the composite umbilical. The load carrying layers are wrapped and braided so as to provide the composite umbilical with various mechanical properties including tensile and compressive strength, burst strength, flexibility, resistance to caustic fluids, gas invasion, external hydrostatic pressure, internal fluid pressure, ability to be stripped into the borehole, density, i.e. flotation, fatigue resistance and other mechanical properties. Fibers are uniquely wrapped and braided to maximize the mechanical properties of composite umbilical including adding substantially to its strength.
The wear layer is preferably braided around the outermost load carrying layer. The wear layer may also be a sacrificial layer since it will engage the inner wall of the borehole and will wear as the composite umbilical is tripped into the well. A wear layer protects the underlying load carrying layers. One preferred wear layer is that of Kevlar™, which is a very strong material that is resistant to abrasion. There may be additional wear layers as required. One advantage of a distinct wear layer is that it can be of a different fiber and color, making it easy to determine the wear locations on a composite umbilical. An inner liner and wear layer are not critical to the use of a composite umbilical and may not be required in certain applications. A pressure layer may also be applied although not required.
During the braiding process, electrical conductors, data transmission conductors, sensors and other data links may be embedded between the load carrying layers in the wall of a composite umbilical. These are wound into the wall of the composite umbilical with the carbon, hybrid, or glass fibers of load carrying layers. It should be appreciated that any number of electrical conductors, data transmission conduits, and sensors may be embedded as desired in the wall of a composite umbilical.
The electrical conductors may include one or more copper wires such as wire, multi-conductor copper wires, braided wires, or coaxial woven conductors. These are connected to a power supply at the surface. A braided copper wire or coaxial cable is wound with the fibers integral to the load carrying layers. Although individual copper wires may be used, a braided copper wire provides a greater transmission capacity with reduced resistance along a composite umbilical. Electrical conductors allow the transmission of a large amount of electrical power from the surface to the bottom hole assembly through essentially a single conductor. With multiplexing, there may be two-way communication through a single conductor between the surface and bottom hole assembly. This single conductor may provide data transmission to the surface.
The principal copper conductor used for power transmission from the power supply at the surface to the bottom hole assembly is preferably braided copper wire. The braided cooper wire may be used to provide the power for a power section which rotates the bit. Braided copper wire may conduct a large voltage, such as 400 volts of electricity, from the surface, which will generate heat that must be dissipated. Braided copper wire is preferably disposed between the two outermost load carrying layers. By locating braided copper wire adjacent the outer diameter of a composite umbilical, the braided copper wire is disposed over a greater surface area of layers to maximize the dissipation of heat.
The data transmission conduit may be a plurality of fiber optic data strands or cables providing communication to the controls at the surface such that all data is transmitted in either direction fiber optically. Fiber optic cables provide a broad band width transmission and permit two-way communication between bottom hole assembly and the surface. As previously described, the fiber optic cable may be linear or spirally wound in the carbon, hybrid or glass fibers of load carrying layers.
A composite umbilical is coilable so that it may be spooled onto a drum. In the manufacturing of composite umbilical, the inner liner is spooled off a drum and passed linearly through a braiding machine. The carbon, hybrid, or glass fibers are then braided onto the inner liner as the liner passes through multiple braiding machines, each braiding a layer of fiber onto the inner liner. The finished composite umbilical is then spooled onto a drum.
During the braiding process, the electrical conductors, data transmission conductors, and sensors are applied to the composite umbilical between the braiding of load carrying layers. Conductors may be laid linearly, wound spirally or braided around the umbilical during the manufacturing process while braiding the fibers. Further, conductors may be wound at a particular angle so as to compensate for the expansion of the inner liner upon pressurization of composite umbilical. A composite umbilical may be made of various diameters. The size of umbilical, of course, will be determined by the particular application and well for which it is to be used.
Although it is possible that the composite umbilical may have any continuous length, such as up to 25,000 feet, it is preferred that the composite umbilical be manufactured in shorter lengths as, for example, in 1,000, 5,000, and 10,000 foot lengths. A typical shipping drum will hold approximately 12,000 feet of composite umbilical. However, it is typical to have additional back up drums available with additional composite umbilical. These drums, of course, may be used to add or shorten the length of the composite umbilical. With respect to the diameters and weight of the composite umbilical, there is no practical limitation as to its length.
The composite umbilical has all of the properties requisite to enable the drilling and completion of extended reach wells. In particular, the composite umbilical has great strength for its weight when suspended in fluid as compared to ferrous materials and has good longevity. Composite umbilical also is compatible with the drilling fluids used to drill the borehole and approaches buoyancy (dependent upon mud weight and density) upon passing drilling fluids down its flowbore and back up the annulus formed by the borehole. This reduces to acceptable limits drag and other friction factors previously encountered by metal pipe. Composite umbilical may be used in elevated temperatures particularly when a heat exchanger is placed on drilling platform to cool the drilling fluids circulating through the borehole.
In current practice coiled tubing is often used in conjunction with a bottom hole assembly connected to the end of the tubing string. The bottom hole assembly may include a variety of downhole tools and devices including sensors, orientation devices, motors, hydraulic rams, and steering tools. If the tubing is supporting a bottom hole assembly for drilling, the bottom hole assembly will include a drill bit and other drilling equipment. Sensors and monitoring equipment of other kinds may be located upstream of the drill bit. One consequence of the variety of equipment used in conjunction with coiled tubing string is the need for some means to conduct electrical power and signals from one end of the string to the other. In this way power and signals from the control/operating point on the surface can be sent to the bottom hole assembly at the opposite end of the string, and likewise signals from the bottom hole assembly can be transmitted to the surface. Thus composite coiled tubing may be manufactured with conductors embedded in the wall of the tubing itself. The conductors may be electrical wires, optical transmitting cables, or other forms of cabling that permit the transmission of energy or data. Electrical conductors within the coiled tubing can be connected to the bottom hole assembly at one end of the string; and at the opposite end of the string, the conductors can be connected to meters, gauges, control equipment, computers, and the like.
The transmission of signals through composite coiled tubing does present one problem, however. When two or more lengths of tubing must be joined to provide the required overall length for the particular well operation, a connector must be provided to pass the energy and/or data between adjoining lengths of coiled tubing. Such a connection must first provide a robust electrical contact between the two lengths of wire to be joined so that an uninterrupted signal may pass even in the presence of the shaking and jarring that occur during a well operation, particularly during a drilling operation. In addition the connection must provide insulation. The connected conductors must not only be insulated from the fluids and other matter in the surrounding well environment but in addition the connected conductors must be properly insulated from the other conductors within the composite tubing. Materials that are present in the well environment can be highly corrosive and destructive of electrical conductors. A common shortcoming of the existing methods for connecting composite coiled tubing is that they do not adequately meet the need for a robust and well insulated electrical connection of the electrical conductors in the joined sets of tubing.
Composite coiled tubing is subjected to bending stress both when on a reel and when being fed over the gooseneck into the injector. The injector also presents a diametrical restriction through which the composite coiled tubing must pass. Further, the connector must be spoolable with the connected lengths of composite coiled tubing onto a reel or spool requiring that the connector have a limited length. Therefore, a connector joining two consecutive strings of composite coiled tubing must be able to resist the bending forces on the tubing without creating areas of stress concentration that may cause premature failure of the string. The connector must also be able to fit through the injector head, which means that the diameter of the connector is essentially limited to the diameter of the tubing, and must be spoolable, which means that the length of the connector must be of a predetermined limited length dimension. These design constraints, coupled with the preferred threaded connector that can be engaged without rotating the tubing strings, creates the need in the art for a robust, compact composite coiled tubing connector.
Notwithstanding the foregoing described prior art, there remains a need for a coiled tubing connector that combines the features of a strong mechanical connection, sealing the fluids within the coiled tubing from the outside environment, and providing a robust electrical connection. These and other features and advantages are found in the present invention.