Patent Application
20160069173
1. Field of the Disclosure
The embodiments described herein relate to a system and methods of decreasing the coefficient of friction between a coiled tubing string and casing and/or tubing in a horizontal wellbore to permit the coiled tubing string to access farther into the horizontal wellbore.
2. Description of the Related Art
With more long laterals currently being drilled in wells throughout the world, multistage technologies are becoming more popular. In addition, the length of lateral or horizontal wellbore is increasing with plans for laterals to reach as far as 10,000 feet. Increasing the length of a horizontal wellbore may result in difficulty in reaching the end of the horizontal wellbore with tools conventional conveyed on coiled tubing. At a point along the length of the horizontal wellbore, the coefficient of friction between the coiled tubing and the casing of the horizontal wellbore increases to the point that the friction between the two prevents the further insertion of the tool on the coiled tubing string. Lubricants have been used to reduce the coefficient of friction in the wellbore between components. However, most commercially available lubricants exhibit limited capability of extending the reach along a lateral or horizontal wellbore at approximately 6,000 feet. Additionally, lubricant injection into a horizontal wellbore is often dissipated by subsequent treatment procedures conducted within the wellbore. It would be beneficial to provide a system and method of permitting farther reach capabilities into a horizontal wellbore with a coiled tubing string.
The present disclosure is directed to an extended reach method within a horizontal wellbore that overcomes some of the problems and disadvantages discussed above.
One embodiment is a method of treating a horizontal wellbore comprising positioning a bottom hole assembly within a horizontal wellbore adjacent a first production zone of the horizontal wellbore. The bottom hole assembly is connected to a coiled tubing string. The method comprises creating a flow path between the first production zone and an annulus between the coiled tubing string and a casing string of the horizontal wellbore and pumping a first pad fluid down the annulus to the first production zone. The method comprises pumping a treatment fluid down the annulus to the first production zone and pumping a first flushing fluid down the annulus beyond the first production zone. The method comprises reducing a coefficient of friction between the casing string and the coiled tubing string by pumping lubricant within the first flushing fluid.
Reducing the coefficient of friction may further comprise pumping fluid down an interior of the coiled tubing string to actuate a vibratory device connected to the coiled tubing string. The first treatment fluid may include sand and/or proppant. Pumping the first treatment fluid may fracture the first production zone. Pumping the first flushing fluid may move proppant and/or sand into the fractures of the first production zone and may substantially remove the proppant and/or sand from the horizontal wellbore adjacent the first production zone. The method may include modeling the reduction of the coefficient of friction between the casing string and the coiled tubing string between the first production zone and a second production zone. The amount of lubricant pumped within the first flushing fluid may be based on the modeling. The amount of lubricant pumped within the first flushing fluid may be a predict amount to cover the casing between the first production zone and the second production zone.
Based on the modeling, the method may include pumping fluid down the coiled tubing string to actuate a vibratory device connected to the coiled tubing string. The method may include positioning the bottom hole assembly adjacent the second production zone of the horizontal wellbore. Creating a flow path between the first production zone and the annulus may comprise moving a first sleeve to open a first port in the casing string. The method may comprise creating a flow path between the second production zone and the annulus. The method may include pumping a second pad fluid down the annulus to the second production zone and pumping a second treatment fluid down the annulus to the second production zone. The second pad fluid may be substantially comprised of the first flushing fluid. The method may comprise pumping a second flushing fluid down the annulus to beyond the second production zone and reducing the coefficient of friction between the casing string and the coiled tubing string by pumping lubricant within the second flushing fluid.
One embodiment is a system to treat a multizone horizontal wellbore. The system comprises a casing string and a coiled tubing string positioned within the casing string. The system comprises a vibratory tool connected to the coiled tubing string, the vibratory tool being actuated to vibrate upon fluid being pumped through the coiled tubing string. The vibration of the vibratory tool reduces a coefficient of friction between the coiled tubing string and the casing string. The system comprises a bottom hole assembly connected to the coiled tubing string below the vibratory tool, the bottom hole assembly configured to permit an individual treatment of multiple production zones of the horizontal wellbore via an annulus between the coiled tubing string and the casing string.
The vibratory tool may comprise a fluid hammer tool that is actuated to vibrate by fluid pumped through the coiled tubing string. The bottom hole assembly may include at least one packing element that may be actuated to create a seal within the annulus. The casing string may include at least one port and at least one sleeve for each production zone, wherein each sleeve may be moved to permit communication between the production zone and the annulus.
One embodiment is a method of treating a horizontal wellbore comprising positioning a bottom hole assembly within a casing string of a horizontal wellbore adjacent a first production zone of the horizontal wellbore. The bottom hole assembly is connected to a coiled tubing string. The method comprises treating the first production zone and reducing a coefficient of friction between the casing string and the coiled tubing string. The method comprises moving the bottom hole assembly adjacent a second production zone of the horizontal wellbore.
Treating the first production zone may comprise pumping fluid down an annulus between the coiled tubing string and the casing string to fracture the first production zone. Reducing the coefficient of friction may comprise actuating a vibratory tool. The vibratory tool may be a fluid hammer tool. Reducing the coefficient of friction may comprise pumping flushing fluid down the annulus between the coiled tubing string and the casing string, the flushing fluid including a lubricant. The method may comprise treating the second production zone and reducing the coefficient of friction between the casing string and the coiled tubing string after treating the second production zone.
While the disclosure is susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and will be described in detail herein. However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. Rather, the intention is to cover all modifications, equivalents and alternatives falling within the scope of the invention as defined by the appended claims.
As the lengths of horizontal laterals and horizontal wellbores continue to increase, it may become more difficult to position a coiled tubing conveyed tool to the end of the wellbore. As the coiled tubing string 7 travels along the horizontal wellbore 1 it may reach a point at which the friction between the casing 6 and the coiled tubing 7 and/or the BHA 50 prevents continued movement of the coiled tubing string 7 down the horizontal wellbore 1. As shown in
After the pad fluid 11 has been pumped down the annulus 4, a treatment fluid 12 may be pumped down the annulus 4 to treat the formation through the flow path to the formation 5, which happens to be port 9 shown in
As shown in
Once the BHA 50 is located at the next production zone, a flow path to the formation may be created, a pad fluid 11 may be pumped down the annulus 4, a treatment fluid 12 may then be pumped down the annulus 4, and a flush fluid 15 with lubricant 16 may then be pumped down the annulus 4. In some instances, the pad fluid 11 of a zone may comprise the flush fluid 15 pumped down the annulus of a previously treated production zone. The repeated pumping of lubricant 16 within flushing fluid 15 at individual production zones may ensure that adequate lubricant 16 is retained within the casing 6 to lower the coefficient of friction and permit the movement of the BHA 50 as opposed to pumping lubricant 16 into the casing 6 prior to treating multiple production zones. As discussed above, the repeated pumping of fluids down the annulus 4 may move the lubricant 16 out of the casing 1 and into the formation 5 if a lubricant 16 is pumped into the casing 6 prior to the treatment operations.
The method may include the optional step 160 of determining what steps may be necessary to reduce the coefficient of friction between the coiled tubing and the casing so that the BHA may be moved beyond the present production zone. Step 160 may be done using modeling software such as CIRCA, or the like, to determine the optimal steps required to reduce the coefficient of friction for various portions of a horizontal wellbore. The modeling software may be used to determine the requisite steps to reduce the coefficient of friction prior to the BHA entering the horizontal wellbore. Alternatively, the determining step 160 may be done as each new zone is reached with the BHA along progression along the length of a horizontal wellbore. The determining step 160 may indicate the amount, concentration, and/or type of lubricant needed to be added to the flush fluid to adequately reduce the coefficient of friction of a designated length of the horizontal wellbore. Step 160 may determine that lubricant should be pumped down the annulus with flush fluid to decrease the coefficient of friction in step 170. Step 160 may also determine that a vibratory device should be actuated to decrease the coefficient of friction. If so, fluid may be pumped down the coiled tubing to actuate the vibratory device in optional step 180. In step 190, the BHA is moved to the next production zone. The BHA may be moved while the vibratory tool is vibrating in optional step 180.
The method may include the optional step 260 of determining what steps may be necessary to reduce the coefficient of friction between the coiled tubing and the casing so that the BHA may be moved beyond the present production zone. Step 260 may determine that a vibratory device should be actuated to decrease the coefficient of friction. If so, fluid may be pumped down the coiled tubing to actuate the vibratory device in step 270. Step 260 may determine that lubricant should also be pumped down the annulus with the flush fluid to decrease the coefficient of friction in step 280. In step 290, the BHA is moved to the next production zone. The BHA may be moved while the vibratory tool is vibrating in step 270.
Although this disclosure has been described in terms of certain preferred embodiments, other embodiments that are apparent to those of ordinary skill in the art, including embodiments that do not provide all of the features and advantages set forth herein, are also within the scope of this disclosure. Accordingly, the scope of the present disclosure is defined only by reference to the appended claims and equivalents thereof.
