Selectively retrievable CT whipstock provides flexibility without losing production

Coiled tubing (CT) intervention services involving casing exits require use of a whipstock assembly, including a milling assembly, concave and anchor. The anchor secures the concave, keeping it from traveling downhole while performing the sidetrack. The self-orienting packer and latch system (Fig. 1) allows packer retrieval on the same trip as the concave and latch, or leave it in the well as a datum for a lateral or re-entry. The system also allows for torque transmittal from the milling assembly to the packer’s slips. The packer has an open bore that allows production to flow through it, when left in the well.

Fig. 1. Coiled tubing packer and latch system.

The retrievable whipstock packer and latch system is deployed on CT or wireline in normal or sour service applications, for wells that require the flexibility to retrieve the packer, or drill additional laterals or re-entries, using an adjustable, self-orienting whipstock.

The whipstock packer and latch have been used in several lab and function tests. This article describes the tests and results that this self-orienting, trip-saving system has completed successfully.

BACKGROUND

The whipstock packer and latch system’s selective retrievability provides the option of retrieving the packer on the same trip as the whipstock or leaving it downhole for additional laterals or re-entries. It shears out of the packer after the lateral has been drilled, immediately giving the operator the option to re-engage and retrieve the packer. By reducing the number of trips needed for total tool retrieval, the time needed to begin producing from the lateral, as well as the time required to employ a crew for such tasks, is reduced. The packer’s bore allows for the flow of oil and/or gas from existing lower zones to prevent loss of production. The latch’s 360° adjustability allows for a lateral in any direction.

Whipstock description. Whipstocks provide cost-effective redirecting of drilling. As opposed to section milling, whipstocks allow sidetracking with fewer cuttings, better directional control and more re-entry possibilities. Sidetracking can be accomplished either in open hole, or more commonly, through one or more strings of casing and/or tubing.

Whipstocks can be oriented to a specific direction, thereby allowing successful drilling of laterals. With the advent of whipstock “retrievability,” multiple casing exits forming multilateral wells are becoming commonplace. In these situations, many lateral wellbores can flow into the parent wellbore, greatly enhancing the well’s output and use of surface equipment. This production can take place during drilling, providing greater hole cleaning and valuable hydrocarbon recovery during the construction phase.

Historical perspective. When initially introduced to the industry, whipstocks were used primarily to sidetrack wellbore problems encountered during drilling, such as stuck pipe. This method proved more cost-effective than engaging in time-consuming fishing operations. Whipstocks of this type were simple in design and often cemented in open hole.

When problems were encountered inside casing, and fishing operations proved unsuccessful, special whipstocks were cemented inside the casing to allow sidetracking through the casing wall. This method was not always successful, nor was it always desirable to use cement to anchor the whipstock while milling the exit. Because of these undesirable factors, special anchor sections were designed. The special anchor sections were added to the bottoms of whipstocks to anchor them into the casing. These anchors were often patterned after conventional packer and liner-hanger type slip designs, and did not meet the demands of milling operations. Eventually, the anchor design was enhanced, and the reliability of whipstocks to stay anchored improved dramatically.

Packer-type whipstocks. The packer-type whipstock is one type of anchor system used in cased-hole applications, when exiting the casing is required. The packer-type whipstock, as its name implies, is anchored in the wellbore through the use of a specialized casing packer. A muleshoe stinger assembly is assembled to the bottom of the whipstock concave section. The packer-type whipstock, with the muleshoe stinger assembly, is latched in a matching casing packer that has been specifically set for the whipstock.

Once the packer is set, a survey tool is run downhole to determine the packer’s exact orientation. This survey tool can be part of the setting tool string or an independent operation. With this information, the muleshoe stinger assembly on the whipstock bottom is adjusted before lowering into the wellbore. As the whipstock is lowered into the packer assembly, it is oriented to the desired direction automatically and then latched into place. The packer can be used to isolate the new lateral from lower pressure zones.

This system allows for retrieval of the whipstock and stinger assemblies without removing the packer. The packer provides a datum for future re-entry work in the lateral while allowing for production from zones below it. The same packer can be used for multiple casing exits.

Benefits of coiled tubing. The benefits are simple, yet very subtle. The most obvious difference between CT and drill pipe (DP) is the lack of physical exertion required every 30, 60 or 90 ft with CT, as opposed to DP. The HSE benefits are equally significant. The continuous pipe string virtually ensures continuous well control, eliminating the chance of wellbore fluids entering the environment uncontrollably. Safety concerns, such as pinch points and slips, trips and falls, are also lowered, by not having to make and break connections, stab pipe, or any other tasks associated with the rig floor.

This deployment technique continues to gain acceptance across broader applications. The benefits of continuous pipe go beyond the HSE aspects and have produced the following enhancements:

• The ease of well control can yield improvements to the reservoir through the application of additional techniques, such as underbalanced drilling or controlled pressure drilling.
• Hydrocarbon recovery during the exit/drilling process provides economic benefits.
• Hole cleaning during tripping can be achieved, as circulation is maintained, as the coiled tubing is run into and pulled from the wellbore.
• Drilled sections with unstable shales can be managed more effectively; the risk of sticking, while adding or removing DP, is eliminated.
• Continuous wellbore pressure monitoring, whether in drilling or tripping mode, is another differentiator.
• Workovers or interventions can take place while production is occurring. This is accomplished through techniques, such as pressure deployment, where tool strings are placed into, or recovered from, the wellbore using specialized BOPs, as well as the ability to snub, overcome wellbore pressure, and work the string into the well.

A CT exit begins the same as a DP exit, with a gauge mill or simulated BHA run, to ensure that the wellbore is free of unknown restrictions. This drifting of the wellbore greatly improves success, regardless of the deployment technique.

The next step is also similar. Depending on well information and future plans, often the kickoff depth and orientation are critical. To ensure these data points are managed accurately, wireline is often employed to install the packer. Use of DP or CT along with MWD equipment is also an option. Once the packer is in place and oriented, it is on to the next step.

Running a standard CT whipstock versus a DP whipstock used to differ from this point forward. Most CT whipstocks required a run to place the tray or whipstock into the packer. This new development allows for the whipstock and milling assembly to be run the same as a DP operation. This improvement removes one trip from the operation, on par with the DP operation. Milling the window is also on par with the DP operation and can be completed in one event, leaving the wellbore with an exit suitable for most any drilling operation, completion tool or technique. After the lateral is drilled, the parent wellbore may be used for production. If so, the packer used for anchoring purposes can now be used as a production packer, or be removed completely. The process of removing the whipstock is similar with both CT and DP, but the enhancement to this system allows for either operation to take place during the same trip into the wellbore.

DESCRIPTION OF TECHNOLOGY

Packers typically consist of four main components: an inner component to connect the packer to the setting mechanism; a packing element to separate the upper and lower zones surrounding the packer; and slips used to centralize and stabilize the packing downhole. Also included is an outer sleeve to aid in the packoff of the packing element and retrieval of the packer. The packer can either be open-ended, to allow production from lower zones to produce through it after the whipstock has been run and pulled, or they can be closed-ended, to serve as a plug to seal off minimally producing or unprofitable zones. If a packer is open-ended with a through bore, it likely contains an inner sealing area to allow a latch or stinger to be inserted into it, with a whipstock attached to aid in creating an upper and lower zone above and beneath the packer, to isolate the pressures on each side.

A latch designed for a packer will likely consist of three main components. Seals are impressed inside the packer to help isolate the pressure above the packer from the pressure below it. A locking mechanism is used to hold the latch in place after initially engaging the packer. A shearing mechanism will be included, to allow the latch to release from the packer after use. The latch’s locking and shearing mechanisms hold it in place while the other whipstock components operate. When the latch is ready to be retrieved, the force required to actuate the shearing mechanism is applied, and the latch releases from the packer, retrievable from the hole.

OPERATIONS

Set anchor. Prior to being set in the well, the packer is first attached to a setting adapter kit that connects it to the hydraulically actuated setting (HST) tool. The HST is activated by producing pumping fluid into the tubing of the tool, until a predetermined, minimum differential pressure between the tubing pressure of the setting tool and the well’s annulus pressure has been reached.

Fig. 2. Packer set in hole. Fig. 3. Concave and latch orienting into desired position within packer. Fig. 4. Latch fully seated within the packer. Fig. 5. Shearing concave and latch out of packer Note: this step occurs after the casing exit is complete, and the lateral has been drilled. Fig. 6. Retrieval of concave and latch from packer. Fig. 7. Packer re-engaged and ready to be retrieved. Fig. 8. Packer retrieved from hole.

After having been assembled together, the setting assembly is stroked downhole until the desired depth has been reached. Once reached, a ball or other tubing isolation device is dropped down into the setting tool, and fluid is pumped into the tubing of the setting tool until the minimally required differential pressure is reached and the setting tool begins to actuate. The outer portion of the setting tool strokes the outer portion of the adapter kit downward, shifting the packer’s outer sleeve downward into the slip cones, forcing the slips outward into the casing. The gauge rings surrounding the packing element converge, compressing the element until it seals firmly against the inner casing wall. The pressure in the tubing will continue to build until reaching a predetermined shear value, releasing the adapter kit from the packer while the packer firmly sets inside the casing, Fig. 2.

Orienting into the packer. After the packer has been set, an orientation gyro is run into the well, to verify the packer’s setting depth and orientation. Once the packer orientation has been determined, the milling whipstock, with the latch attached, is prepared for running. Before the whipstock is tripped into the well, a compass card will be used to adjust the latch’s orientation, as needed, to ensure that the whipstock faces the desired direction downhole. This is accomplished by adjusting a positioning member on the latch, orienting the latch’s mandrel, and then retightening it together.

Once completed, the whipstock and latch are tripped into the well, until reaching the packer. After the whipstock reaches the packer, the latch will be stroked into the packer until it is fully seated. While in the process of being seated, the latch’s orientation mechanism engages the packer’s orienting mechanism to put the whipstock into the desired position. An example of the latch and concave being out of orientation, before going into the correct position, is in Figs. 3 and 4.

Engaging the packer. Once the whipstock is oriented, the centralizing sleeve centers the latch within the packer, to ensure that the latch and packer’s lower locking mechanisms are engaged. These mechanisms prevent the latch from prematurely stroking out of the packer, prior to milling the window. The latch will continue to stroke into the packer until an external stop on the latch mates against the packer’s internal stop. This stop prevents the latch from stroking too far into the packer. After the stop is reached, the tool is pulled upward, to ensure that the whipstock has fully engaged the packer, Fig. 4.

The window is milled. After a set force is pulled into the packer to verify that the whipstock is fully engaged, milling begins. After the window has been milled, the mills are retrieved, and the operator is free to begin sidetracking.

Retrieving the whipstock. After the sidetrack has been completed, and the drill bit has been removed, the whipstock can then be removed. The latch’s selective retrievability gives the operator the option of retrieving only the whipstock and latch, or re-engaging the packer to retrieve it from the well. To retrieve the whipstock from the packer, the operator will pull the necessary force on the whipstock until the shear device on the latch is sheared, and the latch releases from the packer, Fig. 5. At this point, the operator can continue stroking up until the whipstock has been pulled out, Fig. 6.

Retrieving BHA and the anchor. If the customer desires to remove the anchor immediately, the whipstock and latch can be stroked back into the packer, to engage the retrieving mechanism. After the initial shear to release the whipstock from the packer, the whipstock and latch are stroked back into the packer until the external stop is engaged. After stopping, the latch is pulled up to lock the latch’s retrieving mechanism into the packer’s retrieving mechanism, Fig. 7. Afterwards, sufficient force is pulled upward until the packer releases from the casing, and the slips retract into the slips’ cage. The packer is now free to be tripped, Fig. 8.

LABORATORY TESTING

The packer and latch described were tested to ISO V3 standards. After the packer was set inside the casing in the testing cell, the latch was inserted into the packer until the locking mechanisms were engaged, and testing began. Temperatures ranged from 175°F to 275°F. The system also was torque-tested to 2,500 ft-lb. The operating envelope of the packer and latch is shown in Fig. 9. Note: The whipstock packer and latch were designed in conjunction with a milling system. The full systems test of the selectively retrievable anchor and milling system was completed in April 2013 with an under-2-hour sidetrack and successful two-stage retrieval of the whipstock and anchor.

Fig. 9. Operating envelope of the coiled tubing packer and latch.

APPLICATIONS

Three wells drilled during the 2006 campaign were selected as references for this article. Case studies, such as that of wells D, E, and F from Hassi Messaoud field of the Cambrian reservoir in Algeria, are ideal for the selectively retrievable whipstock packer and latch in providing a datum for lateral wellbores to be drilled. The torque-holding capability of the packer and latch system, as well as the high-release mechanism, will ensure that the whipstock remains firmly in place during milling and drilling operations.^{1, 2, 3}

As mentioned previously, the differences between CT and DP are evident. Applications in which CT would be chosen over DP are often based on subtle differences referenced in this article. The use of this technology has existed for many years, and several long-term projects have been spawned from these successes. In Alaska, Prudhoe Bay field has used this technique, along with 3D and 4D seismic, to pinpoint and drain the reservoir. This technique has provided a reliable, cost-effective means to maximize drainage of this complex reservoir. Another long-term project has taken place at Hassi Messaoud. In this case, the client has used the benefits of re-entry, along with underbalanced drilling techniques, to revitalize wells that were shut in. In some instances, where topside production equipment could accommodate the flow while in drilling mode, and once the virgin zone was entered, hydrocarbon production would commence.

In this article’s introduction, we highlighted well control as one benefit of CT and CT-deployed operations. When operators re-enter a well that has H₂S present, continuous well control is beneficial. In most instances, when these reservoirs were drilled, they were done so in such a manner that all the hydrocarbons were intentionally held in place, often with the use of a thick, heavy drilling fluid. As the well’s life expires, the reservoir pressure decreases, and the use of these same drilling fluids for well control might seriously damage the formation and, therefore, further limit production rates. In Algeria for instance, the use of native crude oil and nitrogen ensures that the hydrostatic pressure is low enough, so that the reservoir has no extra pressure exerted upon it.

Depth control and drilling measurements are critical during any casing or tubing exit. When the formation target is vast, and the kickoff point is less critical with respect to the drilling program, it is still very important that the whipstock position is controlled in such a manner that no casing or tubing couplings are in the path of the milling BHA. This correlation of depth is normally done by comparing exiting wellbore logs that include casing or tubing couplings against the log data being observed. This will ensure that no couplings will obscure the milling path. Depth control is often based off of this same log comparison technique, if the existing log had been tied into gamma-ray or openhole logs.

If the existing casing and tubing log are not tied back to a known openhole formation log, then this additional information may need to be acquired. Another critical aspect that needs to be addressed, when placing the kickoff point, is the direction of the target formation or desired well path. This can be accomplished via several different ways, depending on the system being used. If the anchor point is placed in the well via wireline (a packer for instance), then the locating lug orientation is often determined through the use of a gyro survey tool. If CT is used to place the anchor point, then the drill measurements system can be used in the same manner mentioned above.

CONCLUSIONS

Selective retrievability ensures that operators reduce the number of trips required to retrieve packers. This same selective retrievability provides an operator with the flexibility to recover either part or all of the anchor and packer assembly. This decision can be made after installation and drilling are complete.

Based on the completion’s design, the packer can be left in the wellbore for future laterals. Multiple laterals drilled from a single packer means less time tripping in, and out, of wellbore to set packers. It also provides a datum for re-entry into the lateral for future operations.

The ISO standards to which this anchor and packer were tested ensure that there is integrity at the junction. Thorough testing with the required pressure reversals increases the confidence in this system to meet the demands of the challenging re-entries encountered. The high torque rating ensures that stronger motors can be used for milling. 

REFERENCES

1. Amor, B., A. Ferhat, and R. Messas, “Underbalanced coiled tubing drilling practices in horizontal, short-radius re-entry well applied in Hassi Messaoud, Algeria, SPE paper 106870, presented at the Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, Oct. 30−Nov. 1, 2007. http://dx.doi.org/10.2118/106870-MS.
2. Amor, B., A. Ferhat, and R. Messas, et al, 2007. “Successful application of underbalanced coiled tubing drilling in horizontal short-radius re-entry well in Hassi Messaoud, Algeria,” SPE paper 106907, presented at SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, March 20−21, 2007. http://dx.doi.org/10.2118/106907-MS.
3. Amor, B., A. Ferhat, and R. Messas, et al. 2007. Successful application of underbalanced coiled tubing drilling in horizontal short-radius re-entry well to enhance production in Hassi Messaoud field, Algeria,” SPE paper 107305, presented at the SPE/IADC Middle East Drilling and Technology Conference, Cairo, Egypt, Oct. 22−24, 2007. http://dx.doi.org/10.2118/107305-MS.