Patent Application
20130186619
Embodiments relate to methods and apparatus for moving a rod through a cylinder. Some embodiments relate to coiled tubing for oil field services and some embodiments relate to maintaining pipes containing hydrocarbons.
Helical buckling thwarts the efforts of many who aspire to resolve wellbore or pipe problems with mechanical equipment that utilizes a long, flexible rod or tube. Coiled tubing operations (CT) especially encounter helical buckling problems when the tubing is of extended length in deviated wellbores. This problem often limits the extent of reach in extended reach coiled tubing operations. Coiled tubing may experience helical buckling as the tubing travels through high friction regions of a wellbore or through horizontal regions of a wellbore. In conventional coiled tubing operations, the tubing is translated along the borehole either via gravity or via an injector pushing from the surface. For an extended reach horizontal wellbore, an axial compressive load will build up along the length of the coiled tubing due to frictional interactions between the coiled tubing and the borehole wall. A typical axial load as a function of measured depth is plotted in
If the horizontal section of the wellbore is sufficiently long, the axial compressive load will be large enough to cause the coiled tubing to buckle. The first buckling mode is referred to as “sinusoidal buckling”—in this mode, the coiled tubing snakes along the bottom of the borehole with curvature in alternating senses. This is a fairly benign buckling mode, in the sense that neither the internal stresses nor frictional loads increase significantly. As the axial compressive load continues to increase, the coiled tubing will buckle in a second buckling mode. This buckling mode is called “helical buckling”—this mode consists of the coiled tubing spiraling or wrapping along the borehole wall. This buckling mode can have quite severe consequences—once the coiled tubing begins to buckle helically, the normal force exerted by the borehole wall on the tubing increases very quickly. This causes a proportional increase in frictional loading, which in turn creates an increase in axial compressive load. Once helically buckling has initiated, the axial compressive load increases very quickly to a level such that the tubing can no longer be pushed into the whole. This condition is termed “lock-up.” A plot of axial load as a function of measured depth for a coiled tubing which is almost in a locked up state is shown in
Coiled tubing operations employ several techniques for maximizing the depth of penetration in extended reach wells. Vibrators are used in conjunction with CT to increase the depth of penetration in extended reach wells. These vibrators are made up to the bottomhole assembly (BHA) connected at the end of the CT string and are normally activated by pumping fluid through them. The oscillating action caused by the vibrator results in reduced drag forces on the pipe as it is pushed into the wellbore from surface. One of the more effective solutions uses a vibrator as part of the bottomhole assembly (BHA). The oscillations caused by the vibrator reduce the excessive drag on the CT string in high angle wellbore trajectories. This reduction in drag often delays the onset of helical buckling. Effectively, this drag reduction has been found to be equivalent to as much as 30% of the friction coefficient between the wellbore wall and the CT. Thus, drag force reduction increases the CT's ability to go further in an extended reach well. However, depending on the wellbore configuration and the CT string characteristics, as well as the vibrator's amplitude and frequency of the oscillations produced, the position of the vibrator at the terminal end of the BHA may not be effective to allow well total depth (or target depth) to be reached.
When a CT string goes into lockup mode, the entire string length is not completely helically-buckled. There are typically one or two locations in the wellbore where the CT is at a critical state, depending on several physical factors, including wellbore/completion design, CT string characteristics, etc. Lock-up developing in these one or two critical locations is sufficient to prevent the CT from advancing further into the wellbore. The location is typically either near surface below the wellhead for most high angle wells or near the heel of a long horizontal well or both. These locations can be identified prior to actual insertion of the CT into the well through analysis using a force modeling software such as CoilCADE™, a commercially available product available from Schlumberger Technology Corporation of Sugar Land, Tex.
Similarly, pipe used to connect the output of wellbores in oil fields including offshore operations may require maintenance to remove residue and/or improve flow. Such systems exercise flexible tubing equipment that experiences similar buckling along the length of the tubing when equipment is introduced to service the pipelines.
Embodiments relate to an apparatus and a method for delivering a rod in a cylinder including propagating a rod in a cylinder along the interior of the cylinder, and introducing a motion in an orientation of at least one of the followings (orthogonal, parallel to or rotational) to a length of the rod, wherein the motion comprises multiple motion sources along the length of the rod, and wherein the multiple motion sources comprise a control system that controls at least one of the motion sources. Embodiments relate to an apparatus and method for delivering a rod in a cylinder including a cylinder comprising a deviated portion, a rod comprising a length within the cylinder, multiple motion sources positioned along the length of the rod, and a control system in communication with at least one of the motion sources, wherein the control system controls the location and orientation of frictional contact between the rod and cylinder over time.
Embodiments are further explained in the detailed description that follows, in reference to the noted plurality of drawings by way of non-limiting examples of exemplary embodiments of the present invention. The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawing will be provided by the Office upon request and payment of the necessary fee.
Generally, coiled tubing is selected for its ability to coil on a reel for transport at the surface, to retain some rigidity and integrity as it travels through a pipe or wellbore, to convey material or information, and/or to perform a specialized service at the terminal end of the tubing. Further, coiled tubing is often used in harsh conditions where design parameters must also encompass transport, environmental stewardship, and sturdy, rugged construction specifications. The tubing may be selected for chemical, temperature, and physical constraints. The welds, connectors, surface and terminal components may also be tailored for similar integrity concerns.
Several methods are employed to move the tubing through a wellbore or pipe. Tractors may be used to provide axial motion. The tubing may have an outlet port that may be configured to vibrate as described above. The surface connection may include a component to intentionally vibrate the tubing. The fluid may be introduced to and controlled throughout the tubing to tailor at its flow and the resulting tubing vibration using valves, pumps, and other devices. Embodiments herein provide methods and apparatus to distribute additional vibration along the length of the coiled tubing and to control the various ways vibration may be introduced anywhere in the coiled tubing assembly.
To be explicit, a rod that may benefit from embodiments herein may be hollow and configured to deliver fluid such as coiled tubing. The rod may be solid with no voids in its cross section or it may have a narrow interior hollow void in comparison to its outer diameter. The void may be circular or ellipsoid or eccentric. A rod may be cylindrical in shape, that is, have a primary length and a circular cross section, but it also may feature a cross section that is ellipsoid, square, rectangular, curved, eccentric or indeterminate in nature. The rod may be metallic, ceramic, composite, polymer, a combination thereof, or some other material selected for its flexibility and resilience in harsh environments. A diameter of the rod may be consistent for the length of the rod. The diameter may vary over the length of the rod, for example, it may narrow along the length away from the surface. It may telescope along its length. Further, equipment along the length such as connectors, welds, or valves may also vary its inner and/or outer diameter along the length of the rod. In some embodiments, a rod may that may benefit from embodiments described herein include the deployment of sensors and/or downhole tools (for example, pressure and sampling tools). A rod may also encompass wireline tools including the tools that travel through horizontal regions of a wellbore.
Similarly, the rod may be introduced into a cylinder such as a wellbore. The wellbore may be vertical, deviated from vertical, horizontal, or some combination thereof. It may be cased or uncased, in transition between the two or some combination thereof. Also, the cylinder may be a pipe. The pipe may connect multiple wellbores such as in offshore operations. The cross section of the cylinder may be circular. It may also be irregular, ellipsoid, eccentric, or indeterminate along its length. The cross section may vary along the length of the cylinder with regions that are cased, regions that not cased, regions that are perforated and/or fractured or a combination thereof.
Embodiments described herein use single point or distributed (multi-point or continuous) vibration in order to extend the reach of a rod moving through a cylinder. That is, intentionally introducing motion orthogonal to, or parallel to, or rotationally about the forward direction of the tubing improves the likelihood that the tubing will travel through a wellbore instead of succumb to the buckling lock-up described above. The vibration is employed in order to delay or avoid the onset of helical buckling of the coiled tubing string and/or to allow progress into the wellbore in the presence of helically buckled tubing.
Several strategies have been used in order to delay or avoid lock-up. Several different types of vibration are possible. These include:
1) Axial vibration—vibration is induced along the axis of the coiled tubing/wellbore
2) Lateral vibration—vibration is induced orthogonal to the axis of the coiled tubing/wellbore
3) Torsional—rotational vibration is induced about the axis of the coiled tubing/wellbore
4) Lateral rotational—rotational vibration induced about an axis orthogonal to the axis of the coiled tubing/wellbore
The vibrations could be used individually or in combination with each other. The vibrations can be phased in order to optimize their effectiveness in extending reach. Further, vibration sources could be located in one or several locations along the length of the coiled tubing. Most straightforward would be locating the vibration source at the surface (e.g., at the injector head). The vibration source could be located at or near the end of the CT string (e.g., an element of the bottomhole assembly, tractor, etc.). The vibration source could be distributed along the length of the coiled tubing. This would either need to be assembled during the manufacturing process or discrete lengths of the coiled tubing could be joined by a “connector” element which would house the vibration source. In some embodiments, a self-contained module may include a power source (battery, turbine/alternator), electronics, actuator (rotary, linear, hammer drill, etc.). Also, the lengths of tubing between sources of vibration can be different, having different cross-sectional shapes as needed for optimization.
For a vibrator to be effective, the oscillations should be of sufficient amplitude and frequency to propagate to the critical locations within the wellbore where the likelihood of buckling is higher. In long, extended reach wells, locating the vibration source at an intermediate point mid-string of the CT (near the critical location) rather than at the end with other BHA components, would be advantageous. It will also be possible to configure multiple vibration sources in different locations on the CT string should it become necessary.
Methods to introduce vibration can be classified in 3 distinct locations, with different mechanical systems utilized:
1) From surface—this has the advantage of using continuous coiled tubing
a. Axial excitation by modulating the injector speed
b. Torsional excitation by rotating the injector unit back and forth about the axis of the CT
c. Lateral excitation by moving the injector unit from side to side
2) From downhole end of CT—also has advantage of using continuous coiled tubing
a. Mud motor to convert fluid power into vibration (motor configured to provide desired amplitude and frequency). The induced vibration can be lateral (such as introduced by the whirling of the rotor), axial (such as introduced by modulating a flow port as the rotor turns), torsional (such as introduced by modulating the pressure drop across the motor), or a combination of those.
b. Use of a series of pressure relief valves (controlled so as to open/close either totally or partially in a modulated/harmonic fashion) in axial or lateral orientation to pulse the fluid flow
c. Use of a cam or series of cams controlled by a downhole motor (similar to mud motor idea, would require downhole power and electronics but would allow better control)
d. Use of linear actuator (axial) controlled by a downhole motor or electro-magnets
e. Use of hammer-drill actuator
3) From distributed vibration module
a. Placing the vibration source(s) mid-string along the CT length, at an optimal location along the tubing for both length and vibration, maximizes the benefits of the oscillations and requires thoughtful design of the mechanical components. Vibration could be achieved through distributed flow induced vibration actuators.
Some embodiments require a means of connecting discrete lengths of CT to the module. This connection may be mechanical, electrical, or both. To facilitate locating the vibrator mid-string of the CT, some embodiments will use a jointed-spoolable connector. Some embodiments may also feature additional well control barriers to address safety risks.
For example, the shape of the module connecting the sections of coiled tubing could be as needed for specified contact with the wellbore. As an example embodiment of distributed vibration module, we include a figure of REELCONNECT™ connection system (commercially available from Schlumberger Technology Corporation of Sugar Land, Tex.), which is a spoolable connector to attach discrete lengths of coiled tubing in
A detailed example of a connector-based system is now provided. To enable connection of a vibrator mid-string of the CT, it will be necessary to use a flush, jointed connector (
a) Connect 2 (or more) lengths of CT using “spoolable” connector and store into a single work reel
b) Make-up conventional BHA to end of CT string
c) Run CT into well to locate “spoolable” connector above wellhead (below injector)
d) Bleed-off pressure in CT string (downhole checkvalve to hold wellbore pressure)
e) With BOP's closed, access “spoolable” connector and disconnect threaded connection between CT lengths
f) Make-up dual, full-bore ball valve assembly; then vibrator to lower CT length
g) Make-up upper CT length to vibrator
h) Re-install surface equipment to wellhead
i) Run complete assembly into well.
The threaded joint on the connector permits separation of the assembly into halves, with each half remaining connected to the CT string lengths. This threaded joint is non-rotating, allowing make-up to be accomplished without turning either the upper or lower CT string. The dual, full-bore ball valve is a redundancy to ensure proper well control during disassembly and equipment rigdown. It is likely that the integrity of the downhole check valve would be compromised upon completion of the intervention, i.e., may not hold back well pressure (
Distributed mechanisms could also include tractors or rotational devices such as mud motors. One possible embodiment of a mechanical system that could be included in the connection device is shown in
Another possible embodiment is to use the attachment method to deploy distributed tractors or rotation mechanisms such as mud motors.
Another component that could be selected as a connection device is a pressure pulse system (Such as POWERPULSE™ which is commercially available from Schlumberger Technology Corporation or other pulsed power fluid delivery systems) that periodically opens and closes the main flow to generate pressure pulse on the coiled tubing. A valve that is controlled for vibration generated by the pressure drop created by changes in fluid flow may be selected in some embodiments. To summarize, most downhole vibration devices can be modified to incorporate into the connection device to form a distributed system.
An additional application of the distributed rotation mechanisms, tractors, and/or vibration modules is deployment of completions (typically, lower completions) in deviated wellbores. Instead of vibration devices, other embodiments would include the use of distributed tractors or rotation mechanisms (e.g., mud motors). An additional application of the distributed mechanisms (vibration, tractor, or rotation) is deployment of completions in deviated wellbores. Currently, such deployments are not possible on coiled tubing, as the frictional loads required to push heavy completions (in addition to the frictional load of the tubing itself) into the wellbores are too large—the coiled tubing would lock-up. The distributed tractors, vibration modules, and/or rotation mechanisms would significantly reduce the axial friction, allowing coiled tubing to deploy these completions. During deployment, if rotation of a section of the completion is not desirable it can be achieved by placing a swivel joint above the section of the completion to prevent it from rotation. This will save significant time/cost as compared to deploying these completion strings on drillpipe. If the coiled tubing were still not able to push in the entire completion, it is possible that the completion could be deployed in stages, each stage short/light enough to be conveyed on CT. While this would require multiple sequences of running in and out of the hole, the speed of running in and out of the hole on CT (as compared to tripping in/out on drillpipe) may justify this deployment method.
Overall, tailoring relative motion of the rod with respect to the relatively rigid cylinder is desirable. Additional devices may be appropriate for some embodiments. A magnet based system using two sets of magnets that are made to rotate relative to each other and convert the rotation into a modulated axial force may be desirable for some embodiments as it minimizes the effect on the fluid flow. An agitator-based system with openings that are designed to open and close in a modulated fashion and are distributed across the circumference of the rod may be desirable for some embodiments. The surface of the rod may be modified to create a wave-like disturbance along the length of the tubing as the fluid goes through.
Control may be helpful, such as synchronization of or tailoring for vibration decay along the length of the tubing for multiple vibration modules. Appropriately synchronizing vibration may use sensing devices located along the length of the CT string (either in the vibration modules, in a fiber optic cable, or through other means) to sense the excitation state of the string. The distributed vibration modules may also include sensors to monitor wellbore conditions. The information from the various sensors could be communicated via fiber optic cable (iCoil), wirelessly, through an electrical cable, or other means. Based on the sensor information, downhole actuation of the vibration mechanisms can be adjusted to control the synchronization of the various vibration mechanisms (for example, by adjusting the flow into a vibration mechanism).
An additional embodiment includes sensors in these vibration modules in order to both extend reach through vibration and monitor conditions in the wellbore through the sensors. The sensors could include pressure, temperature, vibration such as accelerometers and gyros, tension/compression through strain gauges or other means, and/or fluid monitoring. Another embodiment includes the sensors without the vibration modules when reach extension is not required, for example. An embodiment with vibration/sensor modules is depicted in
In some embodiments, it is desirable for the vibration source to be “on/off” switchable, i.e., vibrations are only produced when pumping during the critical stages of the RIH process. This will ensure that it does not interfere with or is “invisible” to the intended objective of the intervention (e.g., pumping acid, wellbore cleanout, etc.) once the target depth is reached. Simply, the vibration effects are only required during conveyance. Essentially, the tool has two modes: vibration mode and normal operation mode. The function can be switched from vibration to operation mode by pumping at a certain threshold rate. If necessary, it can be shifted back to vibration from operation mode by the same means. The chart (
An additional control component includes acknowledging that the vibration tool will generate an oscillating axial force when pumping at a certain pump rate. This pump rate is predetermined per the job requirement, but it is adjustable at surface prior to running the tool into the wellbore. The magnitude and frequency of the oscillating force is adjustable as well, predetermined through modeling analysis before RIH. This ensures that the proper oscillations are developed for a given wellbore/CT configuration. The adjustability can be accomplished at surface prior to running the tool into the wellbore and need not necessarily be adjustable “on-demand” when the tool is in the wellbore.
In some of the embodiments explained above, the only component that would require a “spoolable” feature would be the connector itself. The rest of the assembly, such as a dual ball valve and vibrator, may be conventionally constructed as with other bottom hole assemblies. Furthermore, because these are assembled below the stripper (WHP packoff seal), an OD flushed with the CT diameter is not a requirement.
The advantages of some of the embodiments herein are numerous. Coiled tubing operations and pipe maintenance programs including clearing pipes generally could benefit from this. Long distance tubing may be a benefit for some embodiments. Using the tubing for operations that traditionally require more rigid pipe-like equipment is a benefit. Embodiments described herein could also enable deployment of stiff, heavy lower completions in deviated wellbores.
