Method and system for extending reach in deviated wellbores using selected injection speed

A method for extending reach of a coiled tubing string in a deviated wellbore includes vibrating the tubing string while the tubing string is injected into the wellbore at a first injection speed, finding the peak speed of lateral vibration of the tubing string, determining a second injection speed as a function of the obtained peak speed of lateral vibration, and adjusting the injection speed of the vibrating tubing string from the first injection speed to the determined second injection speed based on said function. A non-transitory computer-readable storage medium to execute the foregoing method is provided, along with a system for extending reach of a coiled tubing string in a deviated wellbore.

TECHNICAL FIELD

The subject disclosure relates to the hydrocarbon industry. More particularly, the subject disclosure relates to a method for extending reach in deviated wellbores.

BACKGROUND

Coiled tubing refers to metal piping, used for interventions in oil and gas wells and sometimes as production tubing in depleted gas wells. Coiled tubing operations typically involve at least three primary components. The coiled tubing itself is spooled on a large reel and is dispensed onto and off of the reel during an operation. The tubing extends from the reel to an injector. The injector moves the tubing into and out of the wellbore. Between the injector and the reel is a tubing guide or gooseneck. The gooseneck is typically attached or affixed to the injector and guides and supports the coiled tubing from the reel into the injector. Typically, the tubing guide is attached to the injector at the point where the tubing enters. As the tubing wraps and unwraps on the reel, it moves from one side of the reel to the other (side-to-side).

Residual bending is one of the technical challenges for coiled tubing operations. Residual bend exists in every coiled tubing string. During storage and transportation, a coiled-tubing string is plastically deformed (bent) as it is spooled on a reel. During operations, the tubing is unspooled (bent) from the reel and bent on the gooseneck before entering into the injector and the wellbore. Although the reel is manufactured in a diameter as large as possible to decrease the residual bending incurred on the coiled tubing, the maximum diameter of many reels is limited to several meters due to storage and transportation restrictions.

As the coiled tubing goes through the injector head, it passes through a straightener; but the tubing retains some residual bending strain. That strain can cause the tubing to wind axially along the wall of the wellbore like a long, stretched spring. In conventional coiled tubing operations, the tubing is translated along the borehole either via gravity or via an injector pushing from the surface. As a result, the end of the coiled tubing being translated into the borehole is load-free. 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. As the borehole “doglegs” away from the vertical direction, the axial load changes in a tensile direction. A typical axial load as a function of measured depth in a wellbore is plotted inFIG. 1where the wellbore has a 4000 foot vertical section; a 600 foot, 15 degree per 100 foot dogleg section from vertical to horizontal; and a horizontal section that extends to the end of the wellbore.

When a long length of coiled tubing is deployed in the horizontal portion of the well bore, frictional forces are exerted on the tubing string from the wellbore wall rubbing on the coiled tubing, increasing the axial compressive load. 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. A first buckling mode of the tubing string is referred to as “sinusoidal buckling”. In the first buckling 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.

A second buckling mode is termed “helical buckling”. The helical buckling mode is characterized by the coiled tubing spiraling or wrapping along the borehole wall. Helical buckling can have quite severe consequences. For example, once the coiled tubing begins to buckle helically, the normal force exerted by the borehole wall on the coiled tubing string increases very quickly. This causes a proportional increase in frictional loading, which consequently creates an increase in axial compressive load in the tubing string between the injector and the end of the helically buckled region. Once helical buckling has been initiated, further injection of the tubing causes that axial compressive load to increase sharply with injection to a level that indicates that the tubing string is in a condition termed “lock-up”. Visually, the lock-up condition can be noted at the top of the wellbore when the tubing string contacts the wall of the wellbore or well casing. 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 inFIG. 2. Such lock-up limits the use of coiled tubing as a conveyance member for logging tools in highly-deviated, horizontal, or up-hill sections of wellbores.

Various methods are available to avoid lock-up and extend the reach of coiled tubing. Some of these methods include tractors, tapered coiled tubing strings, alternate materials e.g. composite coiled tubing, straighteners, friction reducers, and injecting a light fluid inside the coiled tubing. These methods are aimed at delaying the onset of helical buckling, which, as described above, may lead to lock-up of the coiled tubing string.

SUMMARY

One strategy to delay or avoid lock-up of coiled tubing (hereinafter referred to as “tubing string”) that is being introduced into a wellbore is to induce vibration in the tubing string. Several different types of induced vibration are possible, which can be used separately or in combination with each other. These types 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; and4) Lateral rotational—rotational vibration is induced about an axis orthogonal to the axis of the coiled tubing/wellbore.

According to one aspect, a method is provided for extending reach of a coiled tubing string in a deviated wellbore. The method includes vibrating the tubing string while the tubing string is injected into the wellbore at a first injection speed, finding the peak speed of lateral vibration of the tubing string, determining a second injection speed as a function of the peak speed of lateral vibration, and adjusting the injection speed of the vibrating tubing string from the first injection speed to the determined second injection speed if the first injection speed is not equal to the second injection speed.

DETAILED DESCRIPTION

The particulars shown herein are by way of example and for purposes of illustrative discussion of the examples of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure. In this regard, no attempt is made to show details in more detail than is necessary, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice. Furthermore, like reference numbers and designations in the various drawings indicate like elements.

Helical buckling can limit the extent of reach in extended reach coiled tubing operations. One strategy to delay or avoid lock-up of coiled tubing (hereinafter referred to as “tubing string”) that is being introduced into a wellbore is to inject the tubing string at a rate that is based in part on the peak speed of the lateral vibration of the tubing string in the wellbore.

Vibration of a tubing string can be induced by vibration sources (e.g., apparatuses) that may be located in one or several locations along the length of the tubing string. For example, one location for a vibration source may be at the surface (e.g., at the injector head). Also, for example, a vibration source may be located at or near the free end of the tubing string (e.g., at an element of the bottom hole assembly, such as a tractor, etc.). Additionally, for example, one or more vibration sources may be distributed along the length of the tubing string between its free end in the wellbore and its constrained end at the injector at the surface. The latter example may be accomplished by assembling one or more vibration sources to the coiled tubing during its manufacture or assembling one or more vibration sources onto discrete lengths of the coiled tubing such as at joints of such sections (i.e., connectors joining the discrete lengths may house the vibration sources).

Helix initiation length is defined as the length of tubing between its free end and the position on the tubing where helical buckling is initiated. For example, the data shown inFIG. 2relates to a tubing string that is almost in a locked up state, and shows that the ultimate depth near lockup is about 9000 ft and the measured depth at the start of helical buckling is about 4500 ft, resulting in an approximate helix initiation length of about 4500 ft.

Normalized helix initiation is defined as the helix initiation length when the tubing string is vibrated divided by the helix initiation length of the tubing string without being vibrated. Thus, a normalized helix initiation that is greater than 1 indicates that the vibration of the tubing string results in reach extension of the tubing string (i.e., a longer ultimate length at lock-up) beyond what would be possible without vibration of the tubing string. Thus, the larger the normalized helix initiation, the greater the benefit of the vibration. With the foregoing in mind, it is possible to determine a tubing injection speed that will maximize the normalized helix initiation and, therefore, the reach extension of a tubing string.

Because lock-up occurs quickly after the onset of the helical buckling mode, it is possible to use helix initiation length as a proxy for determining the length of the tubing string at which lock-up will occur (lock-up length). That is, because helical initiation length and lock-up length are very highly correlated, the lock-up length can be approximated based on the helical initiation length. Consequently, if the onset of helical buckling can be delayed, lock-up can also be delayed.

In one embodiment coiled tubing that is subject to induced vibration is injected into a deviated wellbore at a speed (hereinafter referred to as vinj) that is less than the peak speed of the lateral vibration of the tubing string (hereinafter referred to as vpk). The peak speed of the lateral vibration of the tubing string may be obtained using data from an accelerometer mounted on the vibrating portion of the tubing string. Such accelerometer data can be converted into velocity by integrating the acceleration, as is known. When the tubing string is injected at a speed that is less than the peak speed of lateral vibration of the tubing string (i.e., a normalized injection speed vinj/vpkthat is less than 1), the induced vibration in the tubing string destabilizes the frictional interaction between the tubing string and the wellbore, allowing for the sinusoidally buckled region (e.g.,FIG. 2) to decay away.

FIG. 3illustrates a plot of normalized helical buckle initiation as a function of normalized injection speed (i.e., vinj/vpk) for a tubing string vibrated at three different vibration frequencies in a cylindrical constraint (e.g., a pipe or well bore). As seen inFIG. 3, as the normalized injection speed decreases the normalized helical initiation increases, indicating that reach extension increases substantially. Indeed, as the injection speed decreases toward zero, the high-friction sinusoidally buckled region has greater time to relax and decay away, allowing for relatively farther reach.

FIG. 4illustrates normalized helical buckle initiation data as a function of normalized injection speed for a simulation of a tubing string vibrated at three different vibration frequencies in a cylindrical constraint (e.g., a pipe or well bore). The simulation models, among other factors, the frictional forces between the tubing string and the wellbore that arise when the tubing string is pushed along the horizontal section of the deviated well bore. InFIG. 4, the simulated data is plotted for vibrations in the frequency range of 5 to 1000 Hz. In some cases, (the open square, the solid circle and the open triangle) the frequency and the injection speed were fixed and the peak acceleration was changed to obtain multiple points on the plot. In another case, (the X), the frequency and peak acceleration were fixed and the injection speed was changed to obtain multiple points on the plot. In other cases, (the open star and the closed star) the peak acceleration and the injection speed were fixed and the vibration frequency was changed in order to obtain multiple points on the plot. And, in another case (the open circle), the peak acceleration was fixed and the injection speed and vibration frequency were changed in order to obtain points on the plot. As shown inFIG. 3, as injection speed decreases, the helical buckling initiation length increases. Also,FIG. 4shows that for all of the frequencies, as the normalized injection speed approaches 4 (i.e., the injection speed is four times as large as the lateral velocity of the tubing string) there will be little reach extension when compared to tubing strings that are not vibrated.

The data inFIGS. 3 and 4show that for normalized injection speeds less than one, as the injection speed approaches 0, reach can increase more than two-fold. In one aspect, as is seen fromFIGS. 3 and 4, a normalized injection speed less than or equal to 1 is advantageous as the normalized helix initiation rises significantly as the normalized injection speed reduces below unity. In another aspect, normalized injection speeds of less than or equal to 0.8, 0.6, 0.5, 0.4, and 0.3 are useful in increasing reach. However, there are practical considerations of injecting the tubing string too slowly that militate against very low injection speeds (e.g., normalized injection speeds less than 0.25). For example, low injection speeds mean that the duration and cost of installing the tubing increase.

During an actual job, real-time actions can be taken to change the injection speed to achieve the maximum reach, taking into account the foregoing discussion.

FIG. 5shows a workflow to extend reach in a wellbore. At501the workflow starts with the coiled tubing string being arranged at the top of a wellbore and readied for injection into the wellbore. At503the tubing is injected into the wellbore while vibration is induced in the tubing string at a frequency. At505the peak lateral speed of the vibrating tubing string is measured. At507the normalized injection speed is determined and compared to a constant (e.g., a threshold value) that is less than 1 (e.g., 0.5) to determine whether the injection speed should be adjusted to achieve a desired reach extension associated with the constant (e.g., threshold value). For example, if it is determined at507that the normalized injection speed is not equal to the constant (e.g., 0.5) (NO at507), then the injection speed is adjusted at509to achieve the desired normalized injection speed. On the other hand, if the normalized injection speed is equal to the constant (e.g., minimum threshold) (YES at507), then the injection speed is not adjusted and the injection continues at that injection speed until either lock-up approaches or the tubing string reaches the end of the wellbore at511.

In one embodiment, as suggested by the loop between the output of507or509and the input to505inFIG. 5, the peak vibration speed may be monitored during injection, and changes in peak vibration speed may be used to change the injection speed.

In one embodiment, as the tubing string approaches lock-up, the injection speed may be modified (e.g., decreased) further in an attempt to obtain farther reach of the tubing string in the deviated wellbore.

The workflow described above may employ the use of sensors (downhole and/or at surface) to monitor the injection speed of the tubing and the velocity of the lateral movement of the tubing string, which would allow for feedback on the effect of adjusting the injection speed. This information could be processed and used downhole, or it could be transmitted to the surface (for example, via fiber optic cable, wirelessly, via electrical cable, or via other means). In this way, the information can be used to optimize the performance of the injection and vibration equipment to achieve maximum reach extension of the tubing string in the deviated wellbore.

In one aspect, some of the methods and processes described above, such as the workflow described with respect toFIG. 5, are performed by a processor. The term “processor” should not be construed to limit the embodiments disclosed herein to any particular device type or system. The processor may include a computer system. The computer system may also include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, or general purpose computer) for executing any of the methods and processes described above. The computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card), or other memory device.

Some of the methods and processes described above, can be implemented as computer program logic for use with the computer processor. The computer program logic may be embodied in various forms, including a source code form or a computer executable form. Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language, or a high-level language such as C, C++, or JAVA). Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor. The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).

Alternatively or additionally, the processor may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and/or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)). Any of the methods and processes described above can be implemented using such logic devices.

FIG. 6shows an example of a system600for extending reach of a coiled tubing string in a deviated wellbore. The system600includes a computer system or processor601, a vibration source603, a tubing string605which is vibrated by the vibration source603, one or more sensors (accelerometers)608coupled to or attached to the tubing string605, and an injector609coupled to the tubing string for injecting the tubing string into a wellbore620. In one embodiment, the processor601may include a system described above. In one embodiment, the computer system includes a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, or general purpose computer) for executing the workflow described herein, such as the workflow shown inFIG. 5. In one embodiment, the processor601is communicatively coupled to a vibration source603. In one embodiment, the processor601also communicates via a wired or wireless connection with the sensor608and with the injector609at the top of the wellbore620. The processor601determines an injection speed for injecting the tubing string605into the wellbore620and outputs an injection speed control signal based on the determined injection speed. The injector609is constructed to inject the tubing string605at the injection speed based on the injection speed control signal.

The vibration source603is constructed to vibrate the tubing string605. The vibration source603may be capable of inducing one or more different types of vibration. Also, the different types of induced vibration can be employed separately or in combination with each other. The types of vibration may include axial vibration where vibration is induced along the axis of the coiled tubing/wellbore, lateral vibration where vibration is induced orthogonal to the axis of the coiled tubing/wellbore, torsional-rotational vibration where vibration is induced about the axis of the coiled tubing/wellbore, and lateral rotational-rotational vibration where vibration is induced about an axis orthogonal to the axis of the coiled tubing/wellbore.

Vibration of a tubing string can be induced by one or more vibration sources603(e.g., apparatuses) that may be located in one or several locations along the length of the tubing string605. For example, one location for the vibration source603may be at the surface (e.g., at the injector head). Also, for example, the vibration source603may be located at or near the free end of the tubing string605(e.g., at an element of the bottom hole assembly, such as a tractor, etc.). Additionally, for example, one or more vibration sources603may be distributed along the length of the tubing string605between its free end in the wellbore620and its constrained end at the injector609at the surface. The latter example may be accomplished by assembling one or more vibration sources603to the coiled tubing605during its manufacture or assembling one or more vibration sources603onto discrete lengths of the coiled tubing605such as at joints of such sections (i.e., connectors joining the discrete lengths may house the vibration sources).